As filed with the Securities and Exchange Commission on
March 31, 2011
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
American Midstream Partners,
LP
(Exact Name of Registrant as
Specified in its Charter)
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Delaware
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4922
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27-0855785
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(Primary Standard Industrial
Classification Code Number)
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(I.R.S. Employer
Identification Number)
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1614 15th Street
Suite 300
Denver, Colorado 80202
(720) 457-6060
(Address, including Zip Code,
and Telephone Number, including Area Code, of Registrants
Principal Executive Offices)
Brian F. Bierbach
President and Chief Executive
Officer
1614 15th Street
Suite 300
Denver, Colorado 80202
(720) 457-6060
(Name, Address, including Zip
Code, and Telephone Number, including Area Code, of Agent for
Service)
Copies to:
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G. Michael OLeary
Timothy C. Langenkamp
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200
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William N. Finnegan IV
Brett E. Braden
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400
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Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement becomes effective.
If any of the securities being registered on this form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box. o
If this form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same
offering. o
If this form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
If this form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one)
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Large
accelerated
filer o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller reporting
company o
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(Do not check if a smaller
reporting company)
CALCULATION OF REGISTRATION
FEE
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Amount of
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Title of Each Class of
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Proposed Maximum Aggregate
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Registration
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Securities to be Registered
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Offering Price(1)(2)
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Fee
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Common units representing limited partner interests
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$
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75,000,000
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$
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8,708
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(1)
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Includes common units issuable upon exercise of the
underwriters option to purchase additional common units.
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(2)
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Estimated solely for the purpose of calculating the registration
fee pursuant to Rule 457(o).
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The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The
information in this preliminary prospectus is not complete and
may be changed. We may not sell these securities until the
registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell these securities and it is not soliciting an offer
to buy these securities in any jurisdiction where the offer or
sale is not permitted.
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SUBJECT TO COMPLETION, DATED
MARCH 31, 2011
PRELIMINARY PROSPECTUS
Common
Units
Representing Limited Partner
Interests
American Midstream Partners,
LP
$ per
common unit
This is the initial public offering of our common units. We are
selling common units in this
offering. We currently expect that the initial public offering
price will be between $ and
$ per common unit. Prior to this
offering, there has been no public market for our common units.
We have granted the underwriters an option to purchase up to an
additional common
units to cover over-allotments.
We intend to apply to list our common units on The NASDAQ Stock
Market under the symbol
.
Investing in our common units involves risks. Please read
Risk Factors beginning on page 13.
These risks include the following:
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We may not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to pay the minimum quarterly distribution or any distribution
to our unitholders.
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Because of the natural decline in production from existing wells
in our areas of operation, our success depends on our ability to
obtain new sources of natural gas, which is dependent on factors
beyond our control. Any decrease in the volumes of natural gas
that we gather, process or transport could adversely affect our
business and operating results.
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Natural gas, NGL and other commodity prices are volatile, and a
reduction in these prices in absolute terms, or an adverse
change in the prices of natural gas and NGLs relative to one
another, could adversely affect our gross margin and cash flow
and our ability to make distributions to our unitholders.
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We are a relatively small enterprise, and our management has
limited history with our assets and no experience in managing
our business as a publicly traded partnership. As a result,
operational, financial and other events in the ordinary course
of business could disproportionately affect us, and our ability
to grow our business could be significantly limited.
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If third-party pipelines or other midstream facilities
interconnected to our gathering or transportation systems become
partially or fully unavailable, or if the volumes we gather or
transport do not meet the natural gas quality requirements of
such pipelines or facilities, our revenue and cash available for
distribution could be adversely affected.
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AIM Midstream Holdings, LLC directly owns and controls American
Midstream GP, LLC, our general partner, which has sole
responsibility for conducting our business and managing our
operations, each of which have conflicts of interest with us and
limited fiduciary duties, and they may favor their own interests
to the detriment of us and our other unitholders.
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Holders of our common units have limited voting rights and are
not entitled to elect our general partner or its directors.
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Even if holders of our common units are dissatisfied, they
cannot initially remove our general partner without its consent.
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You will be required to pay taxes on your share of our income
even if you do not receive any cash distributions from us.
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Neither the Securities and Exchange Commission nor any other
regulatory body has approved or disapproved of these securities
or determined if this prospectus is truthful or complete. Any
representation to the contrary is a criminal offense.
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Per Common Unit
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Total
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Public Offering Price
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$
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$
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Underwriting Discount(1)
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$
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$
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Proceeds to American Midstream Partners, LP (before expenses)
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$
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$
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(1)
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Excludes an aggregate structuring
fee payable to Citigroup Global Markets Inc. and Merrill Lynch,
Pierce, Fenner & Smith Incorporated that is equal to
0.75% of the gross proceeds of this offering. Please see
Underwriting.
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The underwriters expect to deliver the common units to
purchasers on or
about ,
2011, through the book-entry facilities of The Depository
Trust Company.
Joint Book-Running Managers
,
2011
[Inside
Front Cover Art to Come]
Table of
Contents
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1
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F-1
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A-1
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B-1
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EX-3.1 |
EX-3.2 |
EX-3.4 |
EX-3.5 |
EX-21.1 |
EX-23.1 |
EX-23.2 |
iii
You should rely only on the information contained in this
prospectus or in any free writing prospectus we may authorize to
be delivered to you. Neither we nor the underwriters have
authorized anyone to provide you with additional or different
information. If anyone provides you with different or
inconsistent information, you should not rely on it. We are not,
and the underwriters are not, making an offer to sell these
securities in any jurisdiction where the offer or sale is not
permitted. You should not assume that the information contained
in this prospectus is accurate as of any date other than the
date on the front of this prospectus.
iv
SUMMARY
This summary provides a brief overview of information
contained elsewhere in this prospectus. Because it is
abbreviated, this summary does not contain all of the
information that you should consider before investing in our
common units. You should read the entire prospectus carefully,
including the historical consolidated financial statements and
related notes of American Midstream Partners, LP and the
historical combined financial statements and related notes of
American Midstream Partners Predecessor, which we refer to as
our Predecessor. The information presented in this prospectus
assumes (1) an initial public offering price of
$ per common unit (the mid-point
of the price range set forth on the cover page of this
prospectus), (2) unless otherwise indicated, that the
underwriters option to purchase additional common units is
not exercised, and (3) that the unit split referred to in
Recapitalization Transactions and Partnership
Structure has occurred. You should read Risk
Factors beginning on page 13 for more information
about important risks that you should consider carefully before
investing in our common units. We include a glossary of some of
the terms used in this prospectus as Appendix B.
Unless the context otherwise requires, references in this
prospectus to (i) American Midstream Partners,
LP, we, our, us or
like terms for periods from and after the acquisition of our
assets on November 1, 2009 refer to American Midstream
Partners, LP and its subsidiaries; (ii) American
Midstream Partners, LP, we, our,
us or like terms for periods prior to
November 1, 2009 refer to our Predecessor and its
subsidiaries; (iii) American Midstream GP or
our general partner refer to American Midstream GP,
LLC; (iv)AIM Midstream Holdings refers to AIM
Midstream Holdings, LLC and its subsidiaries and affiliates,
other than American Midstream Partners, LP and its subsidiaries
and American Midstream GP, as of the closing date of this
offering; and (v) AIM refers to American
Infrastructure MLP Fund, L.P. and its subsidiaries and
affiliates, other than American Midstream Partners, LP, American
Midstream GP, AIM Midstream Holdings and their respective
subsidiaries.
American
Midstream Partners, LP
Overview
We are a growth-oriented Delaware limited partnership that was
formed by AIM in August 2009 to own, operate, develop and
acquire a diversified portfolio of natural gas midstream energy
assets. We are engaged in the business of gathering, treating,
processing and transporting natural gas through our ownership
and operation of nine gathering systems, three processing
facilities, two interstate pipelines and six intrastate
pipelines. Our primary assets, which are strategically located
in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide
critical infrastructure that links producers and suppliers of
natural gas to diverse natural gas markets, including various
interstate and intrastate pipelines, as well as utility,
industrial and other commercial customers. We currently operate
approximately 1,400 miles of pipelines that gather and
transport over
500 MMcf/d
of natural gas. We acquired our existing portfolio of assets
from a subsidiary of Enbridge Energy Partners, L.P., or
Enbridge, in November 2009.
Our operations are organized into two segments:
(i) Gathering and Processing and (ii) Transmission. In
our Gathering and Processing segment, we receive fee-based and
fixed-margin compensation for gathering, transporting and
treating natural gas. Where we provide processing services at
the plants that we own, or obtain processing services for our
own account under our elective processing arrangements, we
typically retain and sell a percentage of the residue natural
gas and resulting natural gas liquids, or NGLs, under
percent-of-proceeds,
or POP, arrangements. We also receive fee-based and fixed-margin
compensation in our Transmission segment primarily related to
capacity reservation charges under our firm transportation
contracts and the transportation of natural gas pursuant to our
interruptible transportation and fixed-margin contracts.
For the year ended December 31, 2010, we generated
$38.1 million of gross margin, of which $24.6 million
was segment gross margin generated in our Gathering and
Processing segment and $13.5 million was segment gross
margin generated in our Transmission segment. For the year ended
December 31, 2010, $24.9 million, or 65.4%, of our
gross margin was generated from fee-based, fixed-margin and firm
and interruptible transportation contracts with respect to which
we have little or no direct commodity price exposure. For a
definition of gross margin and a reconciliation of gross margin
to its most directly comparable financial measure calculated in
accordance with GAAP, please read Selected Historical
Financial and Operating Data Non-GAAP Financial
Measures.
1
Business
Strategies
Our principal business objective is to increase the quarterly
cash distributions that we pay to our unitholders over time
while ensuring the ongoing stability of our business. We expect
to achieve this objective by executing the following strategies:
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Capitalize on Organic Growth Opportunities Associated with
Our Existing Assets. We continually seek to
identify and evaluate economically attractive organic expansion
and asset enhancement opportunities that leverage our existing
asset footprint and strategic relationships with our customers.
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Attract Additional Volumes to Our Systems. We
intend to attract new volumes of natural gas to our systems from
existing and new customers by continuing to provide superior
customer service and reestablishing relationships with customers
that were potentially underserved by the previous owner of our
assets.
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Pursue Strategic and Accretive
Acquisitions. We plan to pursue accretive
acquisitions of energy infrastructure assets that are
complementary to our existing asset base or that provide
attractive potential returns in new operating regions or
business lines.
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Manage Exposure to Commodity Price Risk. We
will manage our commodity price exposure by targeting a contract
portfolio that is weighted towards fee-based and fixed-margin
contracts while mitigating direct commodity price exposure by
employing a prudent hedging strategy.
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Maintain Financial Flexibility and Conservative
Leverage. We plan to pursue a disciplined
financial policy and seek to maintain a conservative capital
structure that we believe will allow us to consider attractive
growth projects and acquisitions even in periods of challenging
market environments.
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Continue Our Commitment to Safe and Environmentally Sound
Operations. The safety of our employees and the
communities in which we operate is one of our highest
priorities. We believe it is critical to handle natural gas and
NGLs for our customers safely, while striving to minimize the
environmental impact of our operations.
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Competitive
Strengths
We believe that we will be able to successfully execute our
business strategies because of the following competitive
strengths:
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Well Positioned to Pursue Opportunities Overlooked by Larger
Competitors. Our size and flexibility, in
conjunction with our geographically diverse asset base, position
us to pursue economically attractive growth projects and
acquisitions that may not be large enough to be attractive to
many of our larger competitors.
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Diversified Asset Base. Our assets are
diversified geographically and by business line, which
contributes to the stability of our cash flows and creates a
number of potential growth opportunities for our business.
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Strategically Located Assets. Our assets are
located in areas where we believe there will be opportunities to
access new natural gas supplies and to capture new customers
that are underserved by our competitors. We continue to see
drilling activity on and around our systems, and we believe that
our assets are strategically positioned to capitalize on such
activity.
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Focus on Delivering Excellent Customer
Service. We view our strong customer
relationships as one of our key assets and believe it is
critical to maintain operational excellence and ensure
best-in-class
customer service and reliability.
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Experienced and Incentivized Management and Operating
Teams. Our executive management team has an
average of over 25 years of experience in the midstream
energy industry. The team possesses a comprehensive skill set to
support our business and enhance unitholder value through asset
optimization, accretive development projects and acquisitions.
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2
Our
Sponsor
American Infrastructure MLP Fund, L.P., or AIM, is a private
investment firm specializing in investments in energy, natural
resources, infrastructure and real property. AIM, along with
certain of the funds that AIM advises, currently indirectly owns
84.4% of the ownership interests in AIM Midstream Holdings,
which owns 100% of our general partner. Robert B. Hellman,
Matthew P. Carbone and Edward O. Diffendal serve on the board of
directors of our general partner and are principals of and have
ownership interests in AIM. After the closing of this offering,
AIM Midstream Holdings will continue to hold 100% of the
ownership interests in our general partner and will
hold % of our common units
and % of our subordinated units, or
an aggregate of % of our total
limited partner interests.
Risk
Factors
An investment in our common units involves risks associated with
our business, regulatory and legal matters, our limited
partnership structure and the tax characteristics of our common
units. Please read carefully the risks under the caption
Risk Factors immediately following this Summary,
beginning on page 13.
Recapitalization
Transactions and Partnership Structure
We are a growth-oriented Delaware limited partnership that was
formed by AIM to own, operate, develop and acquire a diversified
portfolio of midstream energy assets.
Immediately prior to the closing of this offering, the following
transactions, which we refer to as the recapitalization
transactions, will occur:
|
|
|
|
|
each general partner unit held by our general partner will
automatically split
into general
partner units, resulting in the ownership by our general partner
of an aggregate
of
general partner units, representing a 2.0% general partner
interest in us;
|
|
|
|
each common unit held by participants in our Long-Term Incentive
Plan, or LTIP, will automatically split
into
common units, resulting in their ownership of an aggregate
of
common units, representing an
aggregate % limited partner
interest in us;
|
|
|
|
each outstanding phantom unit granted to participants in our
LTIP will automatically split
into
phantom units, resulting in their holding an aggregate
of phantom
units;
|
|
|
|
each common unit held by AIM Midstream Holdings will
automatically split
into common
units, resulting in the ownership by AIM Midstream Holdings of
an aggregate of common units,
representing an aggregate % limited
partner interest in us; and
|
|
|
|
the common units held by AIM Midstream Holdings will
automatically convert into common
units
and
subordinated units.
|
In connection with the closing of this offering, the following
transactions will occur:
|
|
|
|
|
we will
issue
common units to the public in this offering;
|
|
|
|
AIM Midstream Holdings will
contribute
common units to our general partner as a capital contribution;
|
|
|
|
our general partner will contribute the common units contributed
to it by AIM Midstream Holdings to us in exchange
for
general partner units in order to maintain its 2.0% general
partner interest in us;
|
|
|
|
we will use the net proceeds from this offering for the purposes
set forth in Use of Proceeds;
|
|
|
|
we will enter into a new credit facility; and
|
|
|
|
we will use the net proceeds from borrowings under our new
credit facility for the purposes set forth in Use of
Proceeds.
|
3
Ownership
of American Midstream Partners, LP
The diagram below illustrates our organization and ownership
after giving effect to this offering and the related
recapitalization transactions and assumes that the
underwriters option to purchase additional common units is
not exercised.
|
|
|
|
|
Public Common Units
|
|
|
|
%
|
AIM Midstream Holdings Units:
|
|
|
|
|
Common Units
|
|
|
|
%
|
Subordinated Units
|
|
|
|
%
|
LTIP Participants Common Units
|
|
|
|
%
|
General Partner Interest
|
|
|
2.0
|
%
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
|
|
|
4
Our
Management
We are managed and operated by the board of directors and
executive officers of our general partner, American Midstream
GP. Currently, and upon the closing of this offering, AIM
Midstream Holdings will own all of the ownership interests in
our general partner. Our unitholders will not be entitled to
elect our general partner or its directors or otherwise directly
participate in our management or operation. AIM holds an
aggregate 84.4% indirect interest in AIM Midstream Holdings.
Robert B. Hellman, Matthew P. Carbone and Edward O. Diffendal
serve on the board of directors of our general partner and are
principals of and have ownership interests in AIM. In addition,
the executive officers of our general partner and certain
members of our general partners board of directors hold an
aggregate 1.1% interest in AIM Midstream Holdings. After the
closing of this offering, AIM Midstream Holdings will continue
to hold 100% of the ownership interests in our general partner
and will hold % of our common units
and % of our subordinated units, or
an aggregate of % of our total
limited partner interests. For information about the executive
officers and directors of our general partner, please read
Management. Our general partner will be liable, as
general partner, for all of our debts (to the extent not paid
from our assets), except for indebtedness or other obligations
that are made specifically nonrecourse to it. Whenever possible,
our general partner intends to cause us to incur indebtedness or
other obligations that are nonrecourse to it.
In order to maintain operational flexibility, our operations
will be conducted through, and our operating assets will be
owned by, American Midstream, LLC and its subsidiaries. However,
we, American Midstream, LLC and its subsidiaries do not have any
employees. Although all of the employees that conduct our
business are employed by our general partner, we sometimes refer
to these individuals in this prospectus as our employees.
Following the closing of this offering, our general partner and
its affiliates will not receive any management fee or other
compensation in connection with our general partners
management of our business, but will be reimbursed for expenses
incurred on our behalf. These expenses include the costs of
employee and director compensation and benefits properly
allocable to us, and all other expenses necessary or appropriate
for the conduct of our business and allocable to us. Our
partnership agreement provides that our general partner will
determine in good faith the expenses that are allocable to us.
Our general partner
owns
general partner units representing a 2.0% general partner
interest in us, which entitles it to receive 2.0% of all the
distributions we make. Our general partner also owns all of our
incentive distribution rights, which will entitle it to
increasing percentages, up to a maximum of 48.0%, of the cash we
distribute in excess of $ per unit
per quarter, after the closing of our initial public offering.
Please read Certain Relationships and Related Party
Transactions.
Principal
Executive Offices and Internet Address
Our principal executive offices are located at 1614
15th Street, Suite 300, Denver, CO 80202, and our
telephone number is
(720) 457-6060.
Our website is located at
www. .com.
We expect to make available our periodic reports and other
information filed with or furnished to the Securities and
Exchange Commission, which we refer to as the SEC, free of
charge through our website, as soon as reasonably practicable
after those reports and other information are electronically
filed with or furnished to the SEC. Information on our website
or any other website is not incorporated by reference herein and
does not constitute a part of this prospectus.
Summary
of Conflicts of Interest and Fiduciary Duties
General
Our general partner has a legal duty to manage us in a manner
beneficial to the holders of our common and subordinated units.
This legal duty originates in statutes and judicial decisions
and is commonly referred to as a fiduciary duty.
However, the officers and directors of our general partner also
have a fiduciary duty to manage the business of our general
partner in a manner beneficial to its owner, AIM Midstream
Holdings. Certain of the officers and directors of our general
partner are also officers of AIM Midstream Holdings. As a result
of these relationships, conflicts of interest may arise in the
future between us and holders of our
5
common units, on the one hand, and AIM Midstream Holdings and
our general partner, on the other hand. For example, our general
partner will be entitled to make determinations that affect the
amount of cash distributions we make to the holders of common
units, which in turn has an effect on whether our general
partner receives incentive cash distributions as discussed above.
Partnership
Agreement Modifications to Fiduciary Duties
Our partnership agreement limits the liability of, and reduces
the fiduciary duties owed by, our general partner to holders of
our common and subordinated units. Our partnership agreement
also restricts the remedies available to holders of our common
and subordinated units for actions that might otherwise
constitute a breach of our general partners fiduciary
duties. By purchasing a common unit, the purchaser agrees to be
bound by the terms of our partnership agreement and, pursuant to
the terms of our partnership agreement, each holder of common
units consents to various actions and potential conflicts of
interest contemplated in the partnership agreement that might
otherwise be considered a breach of fiduciary or other duties
under applicable state law.
AIM
Midstream Holdings May Engage in Competition with
Us
Our partnership agreement does not prohibit AIM, AIM Midstream
Holdings or their respective affiliates other than our general
partner from owning assets or engaging in businesses that
compete directly or indirectly with us. In addition, AIM
Midstream Holdings may acquire, construct or dispose of
additional midstream or other assets in the future, without any
obligation to offer us the opportunity to acquire or construct
any of those assets.
For a more detailed description of the conflicts of interest and
the fiduciary duties of our general partner, please read
Conflicts of Interest and Fiduciary Duties.
6
The
Offering
|
|
|
Common units offered to the public |
|
common
units. |
|
|
|
common
units, if the underwriters exercise in full their option to
purchase additional common units. |
|
Units outstanding after this offering |
|
common
units
and subordinated
units, each representing a 49.0% limited partner interest in us.
Our general partner will
own general
partner units, representing a 2.0% general partner interest in
us. |
|
Use of proceeds |
|
We intend to use the net proceeds from this offering of
approximately $ million,
after deducting underwriting discounts, commissions and
structuring fees, but before paying offering expenses, to
(i) repay in full the outstanding balance under our
existing credit facility, (ii) pay offering expenses of
approximately $ million,
(iii) terminate, in exchange for a payment of approximately
$ , the advisory services agreement
between American Midstream, LLC and AIM, (iv) establish a
cash reserve of $2.2 million related to our non-recurring
deferred maintenance capital expenditures for the twelve months
ending June 30, 2012, and (v) distribute approximately
$ million to AIM Midstream
Holdings for reimbursement of capital expenditures funded by the
initial investment by AIM Midstream Holdings in us. |
|
|
|
We will use the proceeds from borrowings of approximately
$ million under our new
credit facility to (i) distribute approximately
$ million to AIM Midstream
Holdings and (ii) pay fees and expenses relating to our new
credit facility of approximately $
. |
|
|
|
If the underwriters exercise their option to purchase additional
common units, we will use the net proceeds from that exercise to
redeem from AIM Midstream Holdings a number of common units
equal to the number of common units issued upon such exercise,
at a price per common unit equal to the proceeds per common unit
in this offering before expenses but after deducting
underwriting discounts, commissions and structuring fees. |
|
|
|
Please read Use of Proceeds. |
|
Cash distributions |
|
We intend to pay a minimum quarterly distribution of
$ per unit
($ per unit on an annualized
basis) to the extent we have sufficient cash from operations
after establishment of cash reserves and payment of fees and
expenses, including payments to our general partner and its
affiliates. We refer to this cash as available cash.
Our ability to pay the minimum quarterly distribution is subject
to various restrictions and other factors described in more
detail under the caption Our Cash Distribution Policy and
Restrictions on Distributions. We will adjust the minimum
quarterly distribution payable for the period from the closing
of this offering
through ,
2011, based on the length of that period. |
7
|
|
|
|
|
Our partnership agreement requires that we distribute all of our
available cash each quarter in the following manner: |
|
|
|
first, 98.0% to the holders of common units
and 2.0% to our general partner, until each common unit has
received the minimum quarterly distribution of
$ plus any arrearages from prior
quarters;
|
|
|
|
second, 98.0% to the holders of subordinated
units and 2.0% to our general partner, until each subordinated
unit has received the minimum quarterly distribution of
$ ; and
|
|
|
|
third, 98.0% to all unitholders, pro rata,
and 2.0% to our general partner, until each unit has received a
distribution of $ .
|
|
|
|
If cash distributions to our unitholders exceed
$ per unit in any quarter, our
general partner will receive, in addition to distributions on
its 2.0% general partner interest, increasing percentages, up to
48.0%, of the cash we distribute in excess of that amount. We
refer to these distributions as incentive
distributions. Please read Provisions of Our
Partnership Agreement Relating to Cash Distributions. |
|
|
|
The amount of as adjusted cash available for distribution
generated during the year ended December 31, 2010 would
have been insufficient to allow us to pay the full minimum
quarterly distribution ($ per unit
per quarter, or $ on an annualized
basis) on all of our common and subordinated units, as well as
the corresponding distribution on our 2.0% general partner
interest, for such period. Please read Our Cash
Distribution Policy and Restrictions on Distributions. |
|
|
|
We believe that, based on the Statement of Estimated Adjusted
EBITDA included under the caption Our Cash Distribution
Policy and Restrictions on Distributions, we will have
sufficient cash available for distribution to pay the annualized
minimum quarterly distribution of
$ per unit on all common and
subordinated units, as well as the corresponding distribution on
our 2.0% general partner interest, for the twelve months ending
June 30, 2012. |
|
Subordinated units |
|
AIM Midstream Holdings will initially indirectly own all of our
subordinated units. The principal difference between our common
units and subordinated units is that in any quarter during the
subordination period, holders of the subordinated units are not
entitled to receive any distribution of available cash until the
common units have received the minimum quarterly distribution
plus any arrearages in the payment of the minimum quarterly
distribution from prior quarters. Subordinated units will not
accrue arrearages. |
|
Conversion of subordinated units |
|
The subordination period will end on the first business day
after we have earned and paid at least
(i) $ (the minimum quarterly
distribution on an annualized basis) on each outstanding common
and subordinated unit, as well as the corresponding distribution
on our 2.0% general partner interest, for each of three
consecutive, non-overlapping four-quarter periods ending on or
after September 30, 2014 or
(ii) $ (150% of the annualized |
8
|
|
|
|
|
minimum quarterly distribution) on each outstanding common and
subordinated unit, as well as the corresponding distribution on
our 2.0% general partner interest, in addition to any
distribution made in respect of the incentive distribution
rights, for any four consecutive quarter period ending on or
after September 30, 2012; provided that we have paid at
least the minimum quarterly distribution from operating surplus
on each outstanding common unit and subordinated unit, as well
as the corresponding distribution on our 2.0% general partner
interest, for each quarter in that four-quarter period. |
|
|
|
In addition, the subordination period will end upon the removal
of our general partner other than for cause if the units held by
our general partner and its affiliates are not voted in favor of
such removal. |
|
|
|
When the subordination period ends, all subordinated units will
convert into common units on a
one-for-one
basis, and all common units thereafter will no longer be
entitled to arrearages. |
|
Limited voting rights |
|
Our general partner will manage and operate us. Unlike the
holders of common stock in a corporation, you will have only
limited voting rights on matters affecting our business. You
will have no right to elect our general partner or its directors
on an annual or continuing basis. Our general partner may not be
removed except by a vote of the holders of at least
662/3%
of the outstanding limited partner units voting together as a
single class, including any limited partner units owned by our
general partner and its affiliates, including AIM Midstream
Holdings. Upon the closing of this offering, AIM Midstream
Holdings will own an aggregate of %
of our common and subordinated units. This will give AIM
Midstream Holdings the ability to prevent the involuntary
removal of our general partner. Please read The
Partnership Agreement Voting Rights. |
|
Limited call right |
|
If at any time our general partner and its affiliates own more
than 80.0% of the outstanding common units, our general partner
has the right, but not the obligation, to purchase all of the
remaining common units at a price that is not less than the
then-current market price of the common units. |
|
Eligible holders and redemption |
|
If our general partner determines that a holder of our common
units is not an Eligible Holder, it may elect not to make
distributions or allocate income or loss to such holder.
Eligible Holders are: |
|
|
|
U.S. individuals or entities subject to U.S. federal
income taxation on the income generated by us; or
|
|
|
|
U.S. entities not subject to U.S. federal income
taxation on the income generated by us, so long as all of the
entitys owners are domestic individuals or entities
subject to such taxation.
|
|
|
|
We have the right, which we may assign to any of our affiliates,
but not the obligation, to redeem all of the common units of any
holder that is not an Eligible Holder or that has failed to
certify or has falsely certified that such holder is an Eligible
Holder. The purchase price for such redemption would be equal to
the lesser of the |
9
|
|
|
|
|
holders purchase price and the then-current market price
of the common units. The redemption price will be paid in cash
or by delivery of a promissory note, as determined by our
general partner. |
|
|
|
Please read The Partnership Agreement
Non-Citizen
Assignees; Redemption and The Partnership
Agreement Non-Taxpaying Assignees; Redemption. |
|
Estimated ratio of taxable income to distributions |
|
We estimate that if you own the common units you purchase in
this offering through the record date for distributions for the
period
ending ,
you will be allocated, on a cumulative basis, an amount of
federal taxable income for that period that will
be % or less of the cash
distributed to you with respect to that period. For example, if
you receive an annual distribution of
$ per unit, we estimate that your
average allocable federal taxable income per year will be no
more than $ per unit. Please read
Material Federal Income Tax Consequences Tax
Consequences of Unit Ownership Ratio of Taxable
Income to Distributions and Material Federal Income
Tax Consequences Tax Consequences of Unit
Ownership Limitations on Deductibility of
Losses. |
|
Material federal income tax consequences |
|
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States, or
the U.S., please read Material Federal Income Tax
Consequences. |
|
Exchange listing |
|
We intend to apply to list our common units on The NASDAQ Stock
Market under the symbol
. |
10
Summary
Historical Financial and Operating Data
The following table presents our summary historical consolidated
financial and operating data, as well as the summary historical
combined financial and operating data of our Predecessor, which
was comprised of 12 indirectly wholly owned subsidiaries of
Enbridge, as of the dates and for the periods indicated.
The summary historical combined financial data presented as of
and for the year ended December 31, 2008, and as of and for
the 10 months ended October 31, 2009 are derived from
the audited historical combined financial statements of our
Predecessor that are included elsewhere in this prospectus. The
summary historical consolidated financial data presented as of
December 31, 2009, for the period from August 20, 2009
(date of inception) to December 31, 2009 and as of and for
the year ended December 31, 2010 are derived from our
audited historical consolidated financial statements included
elsewhere in this prospectus. We acquired our assets effective
November 1, 2009. During the period from our inception on
August 20, 2009 to October 31, 2009, we had no
operations although we incurred certain fees and expenses
associated with our formation and the acquisition of our assets
from Enbridge.
For a detailed discussion of the following table, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations. The following table
should also be read in conjunction with our historical audited
consolidated financial statements and related notes and our
Predecessors audited combined financial statements and
related notes included elsewhere in this prospectus. Among other
things, those historical financial statements include more
detailed information regarding the basis of presentation for the
information in the following table.
The following table presents the non-GAAP financial measures
adjusted EBITDA and gross margin that we use in our business and
view as important supplemental measures of our performance.
These measures are not calculated or presented in accordance
with GAAP. We explain these measures under Selected
Historical Financial and Operating Data
Non-GAAP Financial Measures and reconcile them to net
income (loss), their most directly comparable financial measure
calculated and presented in accordance with GAAP.
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
American Midstream Partners Predecessor
|
|
|
|
American Midstream Partners, LP and Subsidiaries
(Successor)
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
10 Months
|
|
|
|
August 20, 2009
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
Ended
|
|
|
|
(Inception Date)
|
|
|
|
Year Ended
|
|
|
|
|
December 31,
|
|
|
|
October 31,
|
|
|
|
to December 31,
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
|
2009
|
|
|
|
2009
|
|
|
|
2010
|
|
|
|
|
(in thousands, except per unit and operating data)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
$
|
366,348
|
|
|
|
$
|
143,132
|
|
|
|
$
|
32,833
|
|
|
|
$
|
211,940
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
|
323,205
|
|
|
|
|
113,227
|
|
|
|
|
26,593
|
|
|
|
|
173,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
|
43,143
|
|
|
|
|
29,905
|
|
|
|
|
6,240
|
|
|
|
|
38,119
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
|
13,423
|
|
|
|
|
10,331
|
|
|
|
|
1,594
|
|
|
|
|
12,187
|
|
Selling, general and administrative expenses(1)
|
|
|
|
8,618
|
|
|
|
|
8,577
|
|
|
|
|
1,346
|
|
|
|
|
8,854
|
|
One-time transaction costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,404
|
|
|
|
|
303
|
|
Depreciation expense
|
|
|
|
13,481
|
|
|
|
|
12,630
|
|
|
|
|
2,978
|
|
|
|
|
20,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
|
35,522
|
|
|
|
|
31,538
|
|
|
|
|
12,322
|
|
|
|
|
41,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
7,621
|
|
|
|
|
(1,633
|
)
|
|
|
|
(6,082
|
)
|
|
|
|
(3,238
|
)
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
5,747
|
|
|
|
|
3,728
|
|
|
|
|
910
|
|
|
|
|
5,406
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income) expenses
|
|
|
|
(854
|
)
|
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
2,728
|
|
|
|
$
|
(5,337
|
)
|
|
|
$
|
(6,992
|
)
|
|
|
$
|
(8,644
|
)
|
General partners interest in net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(140
|
)
|
|
|
|
(173
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,852
|
)
|
|
|
|
(8,471
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners net income (loss) per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1.52
|
)
|
|
|
$
|
(0.81
|
)
|
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
$
|
18,155
|
|
|
|
$
|
14,589
|
|
|
|
$
|
(6,531
|
)
|
|
|
$
|
13,791
|
|
Investing activities
|
|
|
|
(10,486
|
)
|
|
|
|
(853
|
)
|
|
|
|
(151,976
|
)
|
|
|
|
(10,268
|
)
|
Financing activities
|
|
|
|
(7,929
|
)
|
|
|
|
(14,008
|
)
|
|
|
|
159,656
|
|
|
|
|
(4,609
|
)
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
$
|
21,956
|
|
|
|
$
|
11,021
|
|
|
|
$
|
3,450
|
|
|
|
$
|
18,263
|
|
Segment gross margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing
|
|
|
|
27,354
|
|
|
|
|
20,024
|
|
|
|
|
3,698
|
|
|
|
|
24,595
|
|
Transmission
|
|
|
|
15,789
|
|
|
|
|
9,881
|
|
|
|
|
2,542
|
|
|
|
|
13,524
|
|
Balance Sheet Data (At Period End):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
421
|
|
|
|
$
|
149
|
|
|
|
$
|
1,149
|
|
|
|
$
|
63
|
|
Accounts receivable, net and unbilled revenue
|
|
|
|
9,532
|
|
|
|
|
8,756
|
|
|
|
|
19,776
|
|
|
|
|
22,850
|
|
Property, plant and equipment, net
|
|
|
|
216,903
|
|
|
|
|
205,126
|
|
|
|
|
149,266
|
|
|
|
|
146,808
|
|
Total assets
|
|
|
|
277,242
|
|
|
|
|
250,162
|
|
|
|
|
174,470
|
|
|
|
|
173,229
|
|
Total debt (current and long-term)(2)
|
|
|
|
60,000
|
|
|
|
|
|
|
|
|
|
61,000
|
|
|
|
|
56,370
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
179.2
|
|
|
|
|
211.8
|
|
|
|
|
169.7
|
|
|
|
|
175.6
|
|
Plant inlet volume
(MMcf/d)(3)
|
|
|
|
12.5
|
|
|
|
|
11.7
|
|
|
|
|
11.4
|
|
|
|
|
9.9
|
|
Gross NGL production (Mgal/d)(3)
|
|
|
|
40.2
|
|
|
|
|
39.3
|
|
|
|
|
38.2
|
|
|
|
|
34.1
|
|
Transmission segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
336.2
|
|
|
|
|
357.6
|
|
|
|
|
381.3
|
|
|
|
|
350.2
|
|
Firm transportation capacity reservation
(MMcf/d)
|
|
|
|
627.3
|
|
|
|
|
613.2
|
|
|
|
|
701.0
|
|
|
|
|
677.6
|
|
Interruptible transportation throughput
(MMcf/d)
|
|
|
|
141.6
|
|
|
|
|
121.0
|
|
|
|
|
118.0
|
|
|
|
|
80.9
|
|
|
|
|
(1) |
|
Includes LTIP expenses for the period from August 20, 2009
to December 31, 2009 and for the year ended
December 31, 2010 of $0.2 million and
$1.7 million, respectively. Of these amounts,
$0.2 million and $1.2 million, respectively, represent
non-cash expenses. |
|
(2) |
|
Excludes Predecessor Note payable to Enbridge Midcoast Limited
Holdings, L.L.C. of $39.3 million as of December 31,
2008. |
|
(3) |
|
Excludes volumes and gross production under our elective
processing arrangements. For a description of our elective
processing arrangements, please read Business
Gathering and Processing Segment Gloria System. |
12
RISK
FACTORS
Limited partner units are inherently different from capital
stock of a corporation, although many of the business risks to
which we are subject are similar to those that would be faced by
a corporation engaged in similar businesses. We urge you to
carefully consider the following risk factors together with all
of the other information included in this prospectus in
evaluating an investment in our common units.
If any of the following risks were to occur, our business,
financial condition or results of operations could be materially
adversely affected. In that case, we might not be able to pay
the minimum quarterly distribution on our common units, the
trading price of our common units could decline and you could
lose all or part of your investment in us.
Risks
Related to our Business
We may
not have sufficient cash from operations following the
establishment of cash reserves and payment of fees and expenses,
including cost reimbursements to our general partner, to enable
us to pay the minimum quarterly distribution to holders of our
common and subordinated units.
In order to pay the minimum quarterly distribution of
$ per unit per quarter, or
$ per unit on an annualized basis,
we will require available cash of approximately
$ million per quarter, or
$ million per year, based on
the number of common and subordinated units to be outstanding
immediately after completion of this offering. We may not have
sufficient available cash from operating surplus each quarter to
enable us to pay the minimum quarterly distribution. The amount
of cash we can distribute on our units principally depends upon
the amount of cash we generate from our operations, which will
fluctuate from quarter to quarter based on, among other things:
|
|
|
|
|
the volume of natural gas we gather, process and transport;
|
|
|
|
the level of production of oil and natural gas and the resultant
market prices of oil and natural gas and NGLs;
|
|
|
|
realized pricing impacts on our revenue and expenses that are
directly subject to commodity price exposure;
|
|
|
|
the market prices of natural gas and NGLs relative to one
another, which affects our processing margins;
|
|
|
|
capacity charges and volumetric fees associated with our
transportation services;
|
|
|
|
the level of competition from other midstream energy companies
in our geographic markets;
|
|
|
|
the level of our operating, maintenance and general and
administrative costs; and
|
|
|
|
regulatory action affecting the supply of, or demand for,
natural gas, the transportation rates we can charge on our
regulated pipelines, how we contract for services, our existing
contracts, our operating costs or our operating flexibility.
|
In addition, the actual amount of cash we will have available
for distribution will depend on other factors, including:
|
|
|
|
|
the level of capital expenditures we make;
|
|
|
|
the cost of acquisitions, if any;
|
|
|
|
our debt service requirements and other liabilities;
|
|
|
|
fluctuations in our working capital needs;
|
13
|
|
|
|
|
our ability to borrow funds and access capital markets;
|
|
|
|
restrictions contained in our debt agreements;
|
|
|
|
the amount of cash reserves established by our general
partner; and
|
|
|
|
other business risks affecting our cash levels.
|
For a description of additional restrictions and factors that
may affect our ability to make cash distributions, please read
Our Cash Distribution Policy and Restrictions on
Distributions.
On a
historical as adjusted basis we would not have had sufficient
cash available for distribution to pay the full minimum
quarterly distribution on all of our units for the year ended
December 31, 2010.
We must generate approximately
$ million of available cash
to pay the minimum quarterly distribution for four quarters on
all of our common and subordinated units that will be
outstanding immediately following this offering, as well as the
corresponding distribution on our 2.0% general partner interest.
The amount of historical as adjusted available cash generated
during the year ended December 31, 2010 would not have been
sufficient to allow us to pay the full minimum quarterly
distribution on our common and subordinated units as well as the
corresponding distribution on our 2.0% general partner interest,
during that period. Specifically, the amount of historical as
adjusted available cash generated during the year ended
December 31, 2010 would have been sufficient to pay the
minimum quarterly distribution on all of our common units, but
only % of the minimum quarterly
distribution on our subordinated units. For a calculation of our
ability to make cash distributions to our unitholders based on
our historical as adjusted results for 2010, please read
Our Cash Distribution Policy and Restrictions on
Distributions.
The
assumptions underlying the forecast of cash available for
distribution that we include in Our Cash Distribution
Policy and Restrictions on Distributions are inherently
uncertain and are subject to significant business, economic,
financial, regulatory and competitive risks and uncertainties
that could cause actual results to differ materially from those
forecasted.
The forecast of cash available for distribution set forth in
Our Cash Distribution Policy and Restrictions on
Distributions includes our forecasted results of
operations, adjusted EBITDA and cash available for distribution
for the twelve months ending June 30, 2012. The financial
forecast has been prepared by management, and we have not
received an opinion or report on it from our or any other
independent auditor. The assumptions underlying the forecast are
inherently uncertain and are subject to significant business,
economic, financial, regulatory and competitive risks, including
risks that expansion projects that do not result in an increase
in gathered and transported volumes, and uncertainties that
could cause actual results to differ materially from those
forecasted. If we do not achieve the forecasted results, we may
not be able to pay the full minimum quarterly distribution or
any amount on our common or subordinated units, in which event
the market price of our common units may decline materially.
Because
of the natural decline in production from existing wells in our
areas of operation, our success depends on our ability to obtain
new sources of natural gas, which is dependent on factors beyond
our control. Any decrease in the volumes of natural gas that we
gather, process or transport could adversely affect our business
and operating results.
The natural gas volumes that support our business are dependent
on the level of production from natural gas and oil wells
connected to our systems, the production of which will naturally
decline over time. As a result, our cash flows associated with
these wells will also decline over time. In order to maintain or
increase throughput levels on our systems, we must obtain new
sources of natural gas. The primary factors affecting our
ability to obtain non-dedicated sources of natural gas include
(i) the level of successful drilling activity in our areas
of operation and (ii) our ability to compete for volumes
from successful new wells.
We have no control over the level of drilling activity in our
areas of operation, the amount of reserves associated with wells
connected to our systems or the rate at which production from a
well declines. In
14
addition, we have no control over producers or their drilling or
production decisions, which are affected by, among other things:
|
|
|
|
|
the availability and cost of capital;
|
|
|
|
prevailing and projected oil and natural gas and NGL prices;
|
|
|
|
demand for oil, natural gas and NGLs;
|
|
|
|
levels of reserves;
|
|
|
|
geological considerations;
|
|
|
|
environmental or other governmental regulations, including the
availability of drilling permits; and
|
|
|
|
the availability of drilling rigs and other production and
development costs.
|
Fluctuations in energy prices can also greatly affect the
development of new oil and natural gas reserves. Further
declines in natural gas prices could have a negative impact on
exploration, development and production activity, and if
sustained, could lead to a material decrease in such activity.
Sustained reductions in exploration or production activity in
our areas of operation would lead to reduced utilization of our
assets.
Because of these and other factors, even if new natural gas
reserves are known to exist in areas served by our assets,
producers may choose not to develop those reserves. If
reductions in drilling activity result in our inability to
maintain the current levels of throughput on our systems, it
could reduce our revenue and cash flow and adversely affect our
ability to make cash distributions to our unitholders.
Natural
gas, NGL and other commodity prices are volatile, and a
reduction in these prices in absolute terms, or an adverse
change in the prices of natural gas and NGLs relative to one
another, could adversely affect our gross margin and cash flow
and our ability to make distributions to our
unitholders.
We are subject to risks due to frequent and often substantial
fluctuations in commodity prices. In the past, the prices of
natural gas and crude oil have been extremely volatile, and we
expect this volatility to continue. The NYMEX daily settlement
price for natural gas for the forward month contract in 2010
ranged from a high of $6.01 per MMBtu to a low of $3.29 per
MMBtu. Natural gas prices reached relatively high levels in 2005
and early 2006 and have exhibited significant volatility since
then, including a sustained decline beginning in 2008, with the
forward month gas futures contracts closing at a seven-year low
of $2.51 per MMBtu in September 2009. NGL prices are generally
positively correlated to the price of WTI crude oil, which has
also exhibited frequent and substantial fluctuations. The NYMEX
daily settlement price for WTI crude oil for the forward month
contract in 2010 ranged from a high of $91.51 per Bbl to a low
of $66.88 per Bbl. Crude oil prices reached historically high
levels in July 2008, hitting a peak of $145.63 per Bbl, and have
demonstrated substantial volatility since then, with the forward
month crude oil futures contracts ranging from $30.81 per Bbl in
December 2008 to above $100.00 per Bbl in March 2011.
The markets for and prices of natural gas, NGLs and other
hydrocarbon commodities depend on factors that are beyond our
control. These factors include the supply of and demand for
these commodities, which fluctuate with changes in market and
economic conditions and other factors, including:
|
|
|
|
|
worldwide economic conditions;
|
|
|
|
worldwide political events, including actions taken by foreign
oil and gas producing nations;
|
|
|
|
worldwide weather events and conditions, including natural
disasters and seasonal changes;
|
|
|
|
the levels of domestic production and consumer demand;
|
|
|
|
the availability of imported liquefied natural gas, or LNG;
|
|
|
|
the availability of transportation systems with adequate
capacity;
|
|
|
|
the volatility and uncertainty of regional pricing differentials;
|
15
|
|
|
|
|
the price and availability of alternative fuels;
|
|
|
|
the effect of energy conservation measures;
|
|
|
|
the nature and extent of governmental regulation and
taxation; and
|
|
|
|
the anticipated future prices of oil, natural gas, NGLs and
other commodities.
|
In our Gathering and Processing segment, we have exposure to
direct commodity price risk under
percent-of-proceeds
processing contracts as well as under our elective processing
arrangements. Under
percent-of-proceeds
arrangements, we generally purchase natural gas from producers
and retain an agreed percentage of the proceeds (in cash or
in-kind) from the sale at market prices of pipeline-quality
natural gas and NGLs resulting from our processing activities.
We also purchase natural gas at various receipt points, process
the gas at a third-party owned natural gas processing facility
and sell our portion of the residue gas and NGLs. Under
percent-of-proceeds
arrangements, our revenue and our cash flows increase or
decrease as the prices of natural gas and NGLs fluctuate. When
we process natural gas that we purchase for our own account, the
relationship between natural gas prices and NGL prices also
affects our profitability. When natural gas prices are low
relative to NGL prices, it is more profitable for us to process
the natural gas that we purchase and process for our own
account. When natural gas prices are high relative to NGL
prices, it is less profitable for us and our customers to
process natural gas both because of the higher value of natural
gas and because of the increased cost (principally that of
natural gas shrink that occurs during processing and use of
natural gas as a fuel) of separating the mixed NGLs from the
natural gas. As a result, we may experience periods in which
higher natural gas prices relative to NGL prices reduce our
processing margins or reduce the volume of natural gas processed
pursuant to our elective processing arrangements. For the year
ended December 31, 2010,
percent-of-proceeds
arrangements accounted for approximately 34.6% of our gross
margin, or 53.7% of the segment gross margin in our Gathering
and Processing segment. For a discussion of these arrangements,
please read Industry Overview Typical
Midstream Contractual Arrangements.
A
decrease in demand for natural gas, NGLs or condensate by the
petrochemical, refining or heating industries, could adversely
affect the profitability of our midstream
business.
A decrease in demand for natural gas, NGLs or condensate by the
petrochemical, refining or heating industries, could adversely
affect the profitability of our midstream business. Various
factors impact the demand for natural gas, NGLs and condensate,
including general economic conditions, extended periods of
ethane rejection, increased competition from petroleum-based
products due to pricing differences, adverse weather conditions,
availability of natural gas processing and transportation
capacity, government regulations affecting prices and production
levels of natural gas, NGLs and condensate.
Our
hedging activities may not be effective in reducing our direct
exposure to commodity price risk and the variability of our cash
flows and may, in certain circumstances, increase the
variability of our cash flows.
We have entered into derivative transactions related to only a
portion of the equity volumes of NGLs to which we take title. As
a result, we will continue to have direct commodity price risk
to the unhedged portion of our NGL equity volumes. We currently
have no hedges in place beyond July 2012. Our actual future
volumes may be significantly higher or lower than we estimated
at the time we entered into the derivative transactions for that
period. If the actual amount is higher than we estimated, we
will have greater commodity price risk than we intended. If the
actual amount is lower than the amount that is subject to our
derivative financial instruments, we might be forced to satisfy
all or a portion of our derivative transactions without the
benefit of the cash flow from our sale of the underlying
physical commodity, resulting in a reduction of our liquidity.
The derivative instruments we utilize for these hedges are based
on posted market prices, which may be lower than the actual NGL
prices that we realize in our operations. As a result of these
factors, our hedging activities may not be as effective as we
intend in reducing the variability of our cash flows, and in
certain circumstances may actually increase the variability of
our cash flows. To the extent we hedge our commodity price risk,
we may forego the benefits we would otherwise experience if
commodity prices were to change in our favor. We do not enter
into derivative transactions with respect to the volumes of
natural gas or condensate that we purchase and sell.
16
We may
not successfully balance our purchases and sales of natural gas,
which would increase our exposure to commodity price
risks.
We purchase from producers and other suppliers a substantial
amount of the natural gas that flows through our pipelines and
processing facilities for sale to third parties, including
natural gas marketers and other purchasers. We are exposed to
fluctuations in the price of natural gas through volumes sold
pursuant to
percent-of-proceeds
arrangements as well as through volumes sold pursuant to our
fixed-margin contracts.
In order to mitigate our direct commodity price exposure, we do
not enter into natural gas hedge contracts, but rather attempt
to balance our natural gas sales with our natural gas purchases
on an aggregate basis across all of our systems. We may not be
successful in balancing our purchases and sales, and as such may
become exposed to fluctuations in the price of natural gas. For
example, we are currently net purchasers of natural gas on
certain of our systems and net sellers of natural gas on certain
of our other systems. Our overall net position with respect to
natural gas can change over time and our exposure to
fluctuations in natural gas prices could materially increase,
which in turn could result in increased volatility in our
revenue, gross margin and cash flows.
Although we enter into
back-to-back
purchases and sales of natural gas in our fixed-margin contracts
in which we purchase natural gas from producers or suppliers at
receipt points on our systems and simultaneously sell an
identical volume of natural gas at delivery points on our
systems, we may still be exposed to commodity price risks. For
example, the volumes or timing of our purchases and sales may
not correspond. In addition, a producer or supplier could fail
to deliver contracted volumes or deliver in excess of contracted
volumes, or a purchaser could purchase less than contracted
volumes. Any of these actions could cause our purchases and
sales to become unbalanced. If our purchases and sales are
unbalanced, we will face increased exposure to commodity price
risks, which in turn could result in increased volatility in our
revenue, gross margin and cash flows.
We are
a relatively small enterprise, and our management has limited
history with our assets and no experience in managing our
business as a publicly traded partnership. As a result,
operational, financial and other events in the ordinary course
of business could disproportionately affect us, and our ability
to grow our business could be significantly
limited.
We will be smaller than many of the other companies in our
industry for the foreseeable future, not only in terms of market
capitalization but also in terms of managerial, operational and
financial resources. Consequently, an operational incident,
customer loss or other event that would not significantly impact
the business and operations of the larger companies in our
industry may have a material adverse impact on our business and
results of operations. In addition, our executive management
team is relatively small with no experience in managing our
business as a publicly traded partnership and has managed our
business and assets for less than two years. As a result, we may
not be able to anticipate or respond to material changes or
other events in our business as effectively as if our executive
management team had such experience and had managed our business
and assets for many years. Furthermore, acquisitions and other
growth projects may place a significant strain on our management
resources. As a result, our ability to execute our growth
strategy and to integrate acquisitions and expansion projects
successfully into our existing operations could be significantly
limited.
If we
fail to develop or maintain an effective system of internal
controls, we may not be able to report our financial results
timely and accurately or prevent fraud, which would likely have
a negative impact on the market price of our common
units.
Upon the completion of this offering, we will become subject to
the public reporting requirements of the Securities Exchange Act
of 1934, as amended, or the Exchange Act. Effective internal
controls are necessary for us to provide reliable and timely
financial reports, prevent fraud and to operate successfully as
a publicly traded partnership. We prepare our consolidated
financial statements in accordance with GAAP, but our internal
accounting controls may not meet all standards applicable to
companies with publicly traded securities. Our efforts to
develop and maintain our internal controls may not be
successful, and we may be
17
unable to maintain effective controls over our financial
processes and reporting in the future or to comply with our
obligations under Section 404 of the Sarbanes-Oxley Act of
2002, which we refer to as Section 404. For example,
Section 404 will require us, among other things, to
annually review and report on, and our independent registered
public accounting firm to attest to, the effectiveness of our
internal controls over financial reporting. We must comply with
Section 404 for our fiscal year ending December 31,
2012. Any failure to develop, implement or maintain effective
internal controls or to improve our internal controls could harm
our operating results or cause us to fail to meet our reporting
obligations.
Prior to this offering, we have been a private company and have
not been required to file reports with the SEC. We currently
have limited accounting personnel, and while we have begun the
process of evaluating the adequacy of our accounting personnel
staffing level and other matters related to our internal
controls over financial reporting, we cannot predict the outcome
of our review at this time.
Given the difficulties inherent in the design and operation of
internal controls over financial reporting, in addition to our
limited accounting personnel and management resources, we can
provide no assurance as to our, or our independent registered
public accounting firms, future conclusions about the
effectiveness of our internal controls, and we may incur
significant costs in our efforts to comply with
Section 404. Any failure to implement and maintain
effective internal controls over financial reporting will
subject us to regulatory scrutiny and a loss of confidence in
our reported financial information, which could have an adverse
effect on our business and would likely have a negative effect
on the trading price of our common units.
We
depend on a relatively small number of customers for a
significant portion of our gross margin. The loss of any one or
more of these customers could adversely affect our ability to
make distributions to you.
A significant percentage of the gross margin in each of our
segments is attributable to a relatively small number of
customers. Additionally, a number of customers upon which our
business depends are small companies that may in the future have
limited access to capital or that may, as a result of
operational incidents or other events, be disproportionately
affected as a compared to larger, better capitalized companies.
In our Gathering and Processing segment, Contango Operators Inc.
and Venture Oil & Gas Co. accounted for approximately
16% and 17%, respectively, of our segment gross margin for the
year ended December 31, 2010. In our Transmission segment,
Calpine Corporation accounted for approximately 38% of our
segment gross margin for the year ended December 31, 2010.
Although we have gathering, processing or transmission contracts
with each of these customers of varying duration and commercial
terms, if one or more of these customers were to default on
their contract or if we were unable to renew our contract with
one or more of these customers on favorable terms, we may not be
able to replace any of these customers in a timely fashion, on
favorable terms or at all. In any of these situations, our gross
margin and cash flows and our ability to make cash distributions
to our unitholders may be adversely affected. We expect our
exposure to concentrated risk of non-payment or non-performance
to continue as long as we remain substantially dependent on a
relatively small number of customers for a substantial portion
of our gross margin.
If
third-party pipelines or other midstream facilities
interconnected to our gathering or transportation systems become
partially or fully unavailable, or if the volumes we gather or
transport do not meet the natural gas quality requirements of
such pipelines or facilities, our revenue and cash available for
distribution could be adversely affected.
Our natural gas gathering and processing and transportation
systems connect to other pipelines or facilities, the majority
of which, such as the Southern Natural Gas Company, or Sonat,
pipeline, the Toca plant, oil gathering lines on Quivira and the
Burns Point processing plant, as well as the Destin, Tennessee
Gas and Transco pipelines, are owned and operated by third
parties. For example, our elective processing arrangements are
entirely dependent on the Toca plant for processing services and
the Sonat pipeline for natural gas takeaway capacity and are
substantially dependent on the Tennessee Gas Pipeline, or TGP,
for natural gas supply volumes. The continuing operation of such
third-party pipelines and other midstream facilities is not
within our control. These pipelines and other midstream
facilities may become unavailable
18
because of testing, turnarounds, line repair, reduced operating
pressure, lack of operating capacity, regulatory requirements,
curtailments of receipt or deliveries due to insufficient
capacity or because of damage from hurricanes or other
operational hazards. If any of these pipelines or other
midstream facilities becomes unable to receive or transport
natural gas, or if the volumes we gather or transport do not
meet the natural gas quality requirements of such pipelines or
facilities, our revenue and cash available for distribution
could be adversely affected.
We are
exposed to the credit risks of our key customers, and any
material nonpayment or nonperformance by our key customers or
purchasers could have a material adverse effect on our revenue,
gross margin and cash flows.
We are subject to risks of loss resulting from nonpayment or
nonperformance by our customers to which we provide services and
sell commodities. Our three largest purchasers of natural gas in
our Gathering and Processing segment are ConocoPhillips,
Enbridge Marketing (U.S.) L.P., or EMUS, and Dow Hydrocarbons
and Resources, which accounted for approximately 41%, 29% and
10%, respectively, of our segment revenue for the year ended
December 31, 2010. Additionally, ExxonMobil and Calpine
Corporation are the two largest purchasers of natural gas and
transmission capacity, respectively, in our Transmission segment
and accounted for approximately 43% and 10%, respectively, of
our segment revenue for the year ended December 31, 2010.
Some of our customers may be highly leveraged or
under-capitalized and subject to their own operating and
regulatory risks, which could increase the risk that they may
default on their obligations to us. In addition, some of our
customers, such as Calpine Corporation, which emerged from
bankruptcy in 2008, may have a history of bankruptcy or other
material financial and liquidity issues. Any material nonpayment
or nonperformance by any of our key customers could have a
material adverse effect on our revenue, gross margin and cash
flows and our ability to make cash distributions to our
unitholders.
Our
gathering, processing and transportation contracts subject us to
renewal risks.
We gather, purchase, process, transport and sell most of the
natural gas and NGLs on our systems under contracts with terms
of various durations. As these contracts expire, we may have to
negotiate extensions or renewals with existing suppliers and
customers or enter into new contracts with other suppliers and
customers. We may be unable to obtain new contracts on favorable
commercial terms, if at all. We also may be unable to maintain
the economic structure of a particular contract with an existing
customer or the overall mix of our contract portfolio. For
example, depending on prevailing market conditions at the time
of a contract renewal, gathering and processing customers with
percent-of-proceeds
contracts may choose to switch to fee-based gathering and
transportation contracts, or a producer with whom we have a
natural gas purchase contract may choose to enter into a
transportation contract with us and retain title to its natural
gas. To the extent we are unable to renew our existing contracts
on terms that are favorable to us or successfully manage our
overall contract mix over time, our revenue, gross margin and
cash flows could decline and our ability to make distributions
to our unitholders could be materially and adversely affected.
Our
elective processing arrangements are
month-to-month,
and the loss of these arrangements would materially and
adversely affect our revenue and gross margin in our Gathering
and Processing segment.
A substantial portion of our revenue and gross margin in our
Gathering and Processing segment are generated by processing
natural gas under our
percent-of-proceeds
arrangements with Enterprise Products Partners L.P. at its Toca
plant. We refer to these arrangements as our elective processing
arrangements. During the year ended December 31, 2010, 7%
and 18% of our revenue and segment gross margin, respectively,
in our Gathering and Processing segment were generated under our
elective processing arrangements. Our elective processing
arrangements are currently renewing on a
month-to-month
basis. Our revenue, segment gross margin and cash flows could be
materially and adversely affected if we were unable to negotiate
an extension of the elective processing arrangements or if
Enterprise were to demand commercial terms that are less
favorable to us.
19
Our
industry is highly competitive, and increased competitive
pressure could adversely affect our business and operating
results.
We compete with other midstream companies in our areas of
operation. In addition, some of our competitors are large
companies that have greater financial, managerial and other
resources than we do. Our competitors may expand or construct
gathering, compression, treating, processing or transportation
systems that would create additional competition for the
services we provide to our customers. In addition, our customers
may develop their own gathering, compression, treating,
processing or transportation systems in lieu of using ours. Our
ability to renew or replace existing contracts with our
customers at rates sufficient to maintain current revenue and
cash flow could be adversely affected by the activities of our
competitors and our customers. All of these competitive
pressures could have a material adverse effect on our business,
results of operations, financial condition and ability to make
cash distributions to our unitholders.
Significant
portions of our pipeline systems have been in service for
several decades and we have a limited ownership history with
respect to all of our assets. There could be unknown events or
conditions or increased maintenance or repair expenses and
downtime associated with our pipelines that could have a
material adverse effect on our business and results of
operations.
We purchased our assets from Enbridge in November 2009.
Significant portions of the pipeline systems that we purchased
have been in service for many decades. In addition, our
executive management team was hired shortly before that purchase
and, consequently, has a limited history of operating our
assets. There may be historical occurrences or latent issues
regarding our pipeline systems that our executive management may
be unaware of and that may have a material adverse effect on our
business and results of operations. The age and condition of our
pipeline systems could also result in increased maintenance or
repair expenditures, and any downtime associated with increased
maintenance and repair activities could materially reduce our
revenue. Any significant increase in maintenance and repair
expenditures or loss of revenue due to the age or condition of
our pipeline systems could adversely affect our business and
results of operations and our ability to make cash distributions
to our unitholders.
We may
incur significant costs and liabilities as a result of pipeline
integrity management program testing and related
repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as
reauthorized and amended by the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006, the U.S. Department of
Transportation, or DOT, has adopted regulations requiring
pipeline operators to develop integrity management programs for
transmission pipelines located where a leak or rupture could
harm high consequence areas, including high
population areas, areas that are sources of drinking water,
ecological resource areas that are unusually sensitive to
environmental damage from a pipeline release and commercially
navigable waterways, unless the operator effectively
demonstrates by risk assessment that the pipeline could not
affect the area. The regulations require operators, including
us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
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maintain processes for data collection, integration and analysis;
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repair and remediate pipelines as necessary; and
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implement preventive and mitigating actions.
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Upon reviewing the integrity maintenance plan we inherited, we
determined that we have an additional sixteen high consequence
areas that we identified after we acquired our assets.
In addition, many states have adopted regulations similar to
existing DOT regulations for intrastate gathering and
transmission lines. Although many of our natural gas facilities
fall within a class that is not subject to these requirements,
we may incur significant costs and liabilities associated with
repair, remediation, preventative or mitigation measures
associated with our non-exempt pipelines, particularly our
AlaTenn and
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Midla pipelines. We currently estimate that we will incur future
costs of approximately $2.1 million during 2012 to complete
the testing required by existing DOT regulations. This estimate
does not include the costs, if any, for repair, remediation,
preventative or mitigating actions that may be determined to be
necessary as a result of the testing program, which could be
substantial. Such costs and liabilities might relate to repair,
remediation, preventative or mitigating actions that may be
determined to be necessary as a result of the testing program,
as well as lost cash flows resulting from shutting down our
pipelines during the pendency of such repairs. Additionally,
should we fail to comply with DOT regulations, we could be
subject to penalties and fines.
If we
are unable to make acquisitions on economically acceptable terms
from third parties, our future growth will be limited, and the
acquisitions we do make may reduce, rather than increase, our
cash generated from operations on a per unit
basis.
Our ability to grow depends, in part, on our ability to make
acquisitions that increase our cash generated from operations on
a per unit basis. The acquisition component of our strategy is
based, in large part, on our expectation of ongoing divestitures
of midstream energy assets by industry participants. A material
decrease in such divestitures would limit our opportunities for
future acquisitions and could adversely affect our ability to
grow our operations and increase our distributions to our
unitholders.
If we are unable to make accretive acquisitions from third
parties, whether because we are (i) unable to identify
attractive acquisition candidates or negotiate acceptable
purchase contracts, (ii) unable to obtain financing for
these acquisitions on economically acceptable terms or
(iii) outbid by competitors or for any other reason, then
our future growth and ability to increase distributions will be
limited. Furthermore, even if we do make acquisitions that we
believe will be accretive, these acquisitions may nevertheless
result in a decrease in the cash generated from operations on a
per unit basis.
Any acquisition involves potential risks, including, among other
things:
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mistaken assumptions about volumes, revenue and costs, including
synergies;
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an inability to secure adequate customer commitments to use the
acquired systems or facilities;
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an inability to integrate successfully the assets or businesses
we acquire, particularly given the relatively small size of our
management team and its limited history with our assets;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business concerns;
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unforeseen difficulties operating in new geographic areas and
business lines; and
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customer or key employee losses at the acquired businesses.
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If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and our
unitholders will not have the opportunity to evaluate the
economic, financial and other relevant information that we will
consider in determining the application of these funds and other
resources.
Our
construction of new assets may not result in revenue increases
and will be subject to regulatory, environmental, political,
legal and economic risks, which could adversely affect our
results of operations and financial condition.
One of the ways we intend to grow our business is through
organic growth projects. The construction of additions or
modifications to our existing systems and the construction of
new midstream assets involve numerous regulatory, environmental,
political, legal and economic uncertainties that are beyond our
control. Such expansion projects may also require the
expenditure of significant amounts of capital, and financing may
not be available on economically acceptable terms or at all. If
we undertake these projects, they may not be
21
completed on schedule, at the budgeted cost, or at all.
Moreover, our revenue may not increase immediately upon the
expenditure of funds on a particular project.
For instance, if we expand a pipeline, the construction may
occur over an extended period of time, yet we will not receive
any material increases in revenue until the project is completed
and placed into service. Moreover, we could construct facilities
to capture anticipated future growth in production in a region
in which such growth does not materialize or only materializes
over a period materially longer than expected. Since we are not
engaged in the exploration for and development of natural gas
and oil reserves, we often do not have access to third-party
estimates of potential reserves in an area prior to constructing
facilities in that area. To the extent we rely on estimates of
future production in our decision to construct additions to our
systems, such estimates may prove to be inaccurate as a result
of the numerous uncertainties inherent in estimating quantities
of future production. As a result, new facilities may not
attract enough throughput to achieve our expected investment
return, which could adversely affect our results of operations
and financial condition.
In addition, the construction of additions to our existing
gathering and transportation assets may require us to obtain new
rights-of-way.
We may be unable to obtain such
rights-of-way
and may, therefore, be unable to connect new natural gas volumes
to our systems or capitalize on other attractive expansion
opportunities. Additionally, it may become more expensive for us
to obtain new
rights-of-way
or to renew existing
rights-of-way.
If the cost of renewing or obtaining new
rights-of-way
increases materially, our cash flows could be adversely affected.
We do
not intend to obtain independent evaluations of natural gas
reserves connected to our gathering and transportation systems
on a regular or ongoing basis; therefore, in the future, volumes
of natural gas on our systems could be less than we
anticipate.
We do not intend to obtain independent evaluations of natural
gas reserves connected to our systems on a regular or ongoing
basis. Accordingly, we may not have independent estimates of
total reserves dedicated to some or all of our systems or the
anticipated life of such reserves. If the total reserves or
estimated life of the reserves connected to our gathering and
transportation systems are less than we anticipate and we are
unable to secure additional sources of natural gas, it could
have a material adverse effect on our business, results of
operations, financial condition and our ability to make cash
distributions to our unitholders.
Recent
incidents and their aftermath could lead to additional
governmental regulation of the offshore exploration and
production industry, which may result in substantial cost
increases or delays in offshore drilling as well as our offshore
natural gas gathering activities.
In April 2010, a deepwater exploration well located in the Gulf
of Mexico, owned and operated by companies unrelated to us,
sustained a blowout and subsequent explosion leading to the
leaking of hydrocarbons. In response to this event, certain
federal agencies and governmental officials ordered additional
inspections of deepwater operations in the Gulf of Mexico. On
May 28, 2010, a six-month federal moratorium was
implemented on all offshore deepwater drilling projects. On
October 12, 2010, the Department of the Interior announced
it was lifting the deepwater drilling moratorium. Despite the
fact that the drilling moratorium was lifted, this spill and its
aftermath has led to additional governmental regulation of the
offshore exploration and production industry and delays in the
issuance of drilling permits, which may result in volume
impacts, cost increases or delays in our offshore natural gas
gathering activities, which could materially impact our
business, financial condition and results of operations.
Although none of our offshore gathering systems currently depend
on deepwater production, we cannot predict with any certainty
what form any additional regulation or limitations would take or
what impact they may have on offshore drilling activity in
general or the producers to which we provide offshore gathering
services.
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Our
business involves many hazards and operational risks, some of
which may not be fully covered by insurance. If a significant
accident or event occurs for which we are not adequately
insured, our operations and financial results could be adversely
affected.
Our operations are subject to all of the risks and hazards
inherent in the gathering, compressing, treating, processing and
transportation of natural gas, including:
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damage to pipelines and plants, related equipment and
surrounding properties caused by hurricanes, tornadoes, floods,
fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction, vehicles, farm and utility
equipment;
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leaks of natural gas and other hydrocarbons or losses of natural
gas as a result of the malfunction of equipment or facilities;
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ruptures, fires and explosions; and
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other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.
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For example, in April 2010, there was a rupture in our Bazor
Ridge gathering pipeline which gathers natural gas high in
hydrogen sulfide content which resulted in an extended shut-down
of a significant portion of that system until the pipeline could
be inspected and repaired. The affected portion of the line is
the one that gathers the most significant volumes of gas on this
system and delivers it to our Bazor Ridge plant, and we were
required to curtail a portion of this flow volume until we built
a new bypass pipeline, the Winchester Lateral, connecting this
production, as well as potential new production, to the Bazor
Ridge plant. The affected section of line was fully shut down
for approximately 25 days and, until our Winchester Lateral
was completed approximately 177 days later, we were able to
gather only approximately 70% of pre-rupture flow volume. The
Winchester Lateral cost $3.9 million to construct and the
repairs to, and testing of, the affected sections of pipe cost
approximately $0.5 million.
These risks could result in substantial losses due to personal
injury
and/or loss
of life, severe damage to and destruction of property and
equipment and pollution or other environmental damage. These
risks may also result in curtailment or suspension of our
operations. A natural disaster or other hazard affecting the
areas in which we operate could have a material adverse effect
on our operations. We are not fully insured against all risks
inherent in our business. For example, we do not have any
casualty insurance on our underground pipeline systems that
would cover damage to the pipelines. Additionally, we do not
have business interruption/loss of income insurance that would
provide coverage in the event of damage to any of our
underground facilities. In addition, although we are insured for
environmental pollution resulting from environmental accidents
that occur on a sudden and accidental basis, we may not be
insured against all environmental accidents that might occur,
some of which may result in toxic tort claims. If a significant
accident or event occurs for which we are not fully insured, it
could adversely affect our operations and financial condition.
Furthermore, we may not be able to maintain or obtain insurance
of the type and amount we desire at reasonable rates. As a
result of market conditions, premiums and deductibles for
certain of our insurance policies may substantially increase. In
some instances, certain insurance could become unavailable or
available only for reduced amounts of coverage. Additionally, we
may be unable to recover from prior owners of our assets,
pursuant to our indemnification rights, for potential
environmental liabilities.
Our
interstate natural gas pipelines are subject to regulation by
the FERC, which could adversely affect our ability to make
distributions to our unitholders.
Our AlaTenn and Midla interstate natural gas transportation
systems are subject to regulation by the Federal Energy
Regulatory Commission, or FERC, under the Natural Gas Act of
1938, or the NGA. Under the NGA, the rates for and terms of
conditions of service on these interstate facilities must be
just and reasonable and not unduly discriminatory. The rates and
terms and conditions for our interstate pipeline services are
set forth in tariffs that must be filed with and approved by the
FERC. Pursuant to FERCs jurisdiction over rates, existing
rates may be challenged by complaint and proposed rate increases
may be challenged by protest. Any
23
successful complaint or protest against our rates could have an
adverse impact on our revenue associated with providing
transportation service.
Under the NGA, the FERC has the authority to regulate companies
that provide natural gas pipeline transportation services in
interstate commerce. The FERCs authority over such
companies includes such matters as:
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rates and terms and conditions of service;
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the types of services interstate pipelines may offer to their
customers;
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the certification and construction of new facilities;
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the acquisition, extension, disposition or abandonment of
facilities;
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the maintenance of accounts and records;
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relationships between affiliated companies involved in certain
aspects of the natural gas business;
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the initiation and discontinuation of services;
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market manipulation in connection with interstate sales,
purchases or transportation of natural gas and NGLs; and
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participation by interstate pipelines in cash management
arrangements.
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The Energy Policy Act of 2005 amended the NGA to add an
anti-manipulation provision. Pursuant to the amended NGA, the
FERC established rules prohibiting energy market manipulation.
Also, the FERCs rules require interstate pipelines and
their affiliates to adhere to Standards of Conduct that, among
other things, require that transportation employees function
independently of marketing employees. The FERC also requires
interstate pipelines to adhere to its rules regarding the filing
and approval of transportation agreements that include
provisions which differ from the transportation agreements
included in their FERC gas tariff. We are conducting a review of
the transportation agreements entered into by our predecessor to
determine whether, and to what extent, any of our transportation
agreements include such provisions. We are subject to audit by
the FERC of our compliance in general, including adherence to
all its rules and regulations. A violation of these rules, or
any other rules, regulations or orders issued or administered by
the FERC, may subject us to civil penalties, disgorgement of
unjust profits, or appropriate non-monetary remedies imposed by
the FERC. In addition, the Energy Policy Act of 2005 amended the
NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase
civil and criminal penalties for any violation of the NGA, NGPA
and any rules, regulations or orders of the FERC up to
$1.0 million per day per violation.
Additionally, existing rates may not reflect our current costs
of operations, which may have risen since the last time our
rates were approved by the FERC. Because proposed rate increases
are procedurally complicated, we may have a significant period
of time during which our gross margin from such FERC-regulated
systems may be materially less than we have historically
obtained.
The
application of certain FERC policy statements could affect the
rate of return on our equity we are allowed to recover through
rates and the amount of any allowance (if any) our interstate
systems can include for income taxes in establishing their rates
for service, which would in turn impact our revenue and/or
equity earnings.
In setting authorized rates of return for interstate natural gas
pipelines, the FERC uses a discounted cash flow model that
incorporates the use of proxy groups to develop a range of
reasonable returns earned on equity interests in companies with
corresponding risks. The FERC then assigns a rate of return on
equity within that range to reflect specific risks of that
pipeline when compared to the proxy group companies. The FERC
allows master limited partnerships, or MLPs, to be included in
the proxy group to determine return on equity. However, as to
such MLPs, the FERC will generally adjust the long-term growth
rate used to calculate the equity cost of capital. The FERC
stated that the long-term growth projection for natural gas
pipeline MLPs will be equal to fifty percent of gross domestic
product (GDP), as compared to the unadjusted GDP used for
corporations. Therefore, to the extent
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that MLPs are included in a proxy group, the FERCs policy
lowers the return on equity that might otherwise be allowed if
there were no adjustment to the MLP growth projection used for
the discounted cash flow model. This could lower the return on
equity that we would otherwise be able to obtain.
The FERC currently allows partnerships, including MLPs, to
include in their
cost-of-service
an income tax allowance if the partnerships owners have
actual or potential income tax liability, a matter that will be
reviewed by FERC on a
case-by-case
basis. Any changes to the FERCs treatment of income tax
allowances in
cost-of-service
rates or an adverse determination with respect to the inclusion
of an income tax allowance in our interstate pipelines
rates could result in an adjustment in a future rate case of our
interstate pipelines respective equity rates of return
that underlie their recourse rates and may cause their recourse
rates to be set at a level that is different, and in some
instances lower, than the level otherwise in effect.
A
change in the jurisdictional characterization or regulation of
our assets by federal, state or local regulatory agencies or a
change in policy by those agencies could result in increased
regulation of our assets which could materially and adversely
affect our financial condition, results of operations and cash
flows.
Intrastate transportation facilities that do not provide
interstate transmission services are exempt from the
jurisdiction of the FERC under the NGA. Although the FERC has
not made any formal determinations with respect to any of our
facilities, we believe that our intrastate natural gas pipelines
and related facilities that are not engaged in providing
interstate transmission services are engaged in exempt gathering
and intrastate transportation and, therefore, are not subject to
FERC jurisdiction. We believe that our natural gas gathering
pipelines meet the traditional tests that the FERC has used to
determine if a pipeline is a gathering pipeline and is therefore
not subject to the FERCs jurisdiction. The distinction
between FERC-regulated transmission services and federally
unregulated gathering services is the subject of substantial
ongoing litigation and, over time, the FERCs policy for
determining which facilities it regulates has changed. In
addition, the distinction between FERC-regulated transmission
facilities, on the one hand, and intrastate transportation and
gathering facilities, on the other, is a fact-based
determination made by the FERC on a case by case basis. If the
FERC were to consider the status of an individual facility and
determine that the facility
and/or
services provided by it are not exempt from FERC regulation
under the NGA, the rates for, and terms and conditions of,
services provided by such facility would be subject to
regulation by the FERC under the NGA. Such regulation could
decrease revenue, increase operating costs, and, depending upon
the facility in question, could adversely affect our results of
operations and cash flows. In addition, if any of our facilities
were found to have provided services or otherwise operated in
violation of the NGA or NGPA, this could result in the
imposition of civil penalties as well as a requirement to
disgorge charges collected for such service in excess of the
cost-based rate established by the FERC.
Moreover, FERC regulation affects our gathering, transportation
and compression business generally. FERCs policies and
practices across the range of its natural gas regulatory
activities, including, for example, its policies on open access
transportation, market manipulation, ratemaking, capacity
release and market transparency and market center promotion,
directly and indirectly affect our gathering business. In
addition, the classification and regulation of our gathering and
intrastate transportation facilities also are subject to change
based on future determinations by the FERC, the courts or
Congress.
State regulation of gathering facilities generally includes
various safety, environmental and, in some circumstances,
nondiscriminatory take requirements and complaint-based rate
regulation. In recent years, the FERC has taken a more
light-handed approach to regulation of the gathering activities
of interstate pipeline transmission companies, which has
resulted in a number of these companies transferring gathering
facilities to federally unregulated affiliates. As a result of
these activities, natural gas gathering may begin to receive
greater regulatory scrutiny at both the state and federal levels.
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We are
subject to stringent environmental laws and regulations that may
expose us to significant costs and liabilities.
Our natural gas gathering, compression, treating and
transportation operations are subject to stringent and complex
federal, state and local environmental laws and regulations that
govern the discharge of materials into the environment or
otherwise relate to environmental protection. Examples of these
laws include:
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the federal Clean Air Act and analogous state laws that impose
obligations related to air emissions;
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the federal Comprehensive Environmental Response, Compensation
and Liability Act, also known as CERCLA or the Superfund law,
and analogous state laws that regulate the cleanup of hazardous
substances that may be or have been released at properties
currently or previously owned or operated by us or at locations
to which our wastes are or have been transported for disposal;
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the federal Water Pollution Control Act, also known as the Clean
Water Act, and analogous state laws that regulate discharges
from our facilities into state and federal waters, including
wetlands;
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the federal Oil Pollution Act, also known as OPA, and analogous
state laws that establish strict liability for releases of oil
into waters of the United States;
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the federal Resource Conservation and Recovery Act, also known
as RCRA, and analogous state laws that impose requirements for
the storage, treatment and disposal of solid and hazardous waste
from our facilities;
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the Endangered Species Act, also known as the ESA; and
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the Toxic Substances Control Act, also known as TSCA, and
analogous state laws that impose requirements on the use,
storage and disposal of various chemicals and chemical
substances at our facilities.
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These laws and regulations may impose numerous obligations that
are applicable to our operations, including the acquisition of
permits to conduct regulated activities, the incurrence of
capital or operating expenditures to limit or prevent releases
of materials from our pipelines and facilities, and the
imposition of substantial liabilities and remedial obligations
for pollution resulting from our operations. Numerous
governmental authorities, such as the U.S. Environmental
Protection Agency, or the EPA, and analogous state agencies,
have the power to enforce compliance with these laws and
regulations and the permits issued under them, oftentimes
requiring difficult and costly corrective actions. Failure to
comply with these laws, regulations and permits may result in
the assessment of administrative, civil and criminal penalties,
the imposition of remedial obligations and the issuance of
injunctions limiting or preventing some or all of our
operations. In addition, we may experience a delay in obtaining
or be unable to obtain required permits, which may cause us to
lose potential and current customers, interrupt our operations
and limit our growth and revenue.
There is a risk that we may incur significant environmental
costs and liabilities in connection with our operations due to
historical industry operations and waste disposal practices, our
handling of hydrocarbon wastes and potential emissions and
discharges related to our operations. Joint and several, strict
liability may be incurred, without regard to fault, under
certain of these environmental laws and regulations in
connection with discharges or releases of hydrocarbon wastes on,
under or from our properties and facilities, many of which have
been used for midstream activities for a number of years,
oftentimes by third parties not under our control. Private
parties, including the owners of the properties through which
our gathering or transportation systems pass and facilities
where our wastes are taken for reclamation or disposal, may also
have the right to pursue legal actions to enforce compliance as
well as to seek damages for non-compliance with environmental
laws and regulations or for personal injury or property damage.
For example, an accidental release from one of our pipelines
could subject us to substantial liabilities arising from
environmental cleanup and restoration costs, claims made by
neighboring landowners and other third parties for personal
injury and property damage and fines or penalties for related
violations of environmental laws or regulations. In addition,
changes in environmental laws occur frequently, and any such
changes that result in more stringent and costly waste handling,
storage, transport, disposal or remediation requirements could
have a material adverse effect on our operations or financial
position. We may not be able to recover all or any of these
costs from insurance. Please read Business
Environmental Matters for more information.
26
Our
operations may impact the environment or cause environmental
contamination, which could result in material liabilities to
us.
Our operations use hazardous materials, generate limited
quantities of hazardous wastes and may affect runoff or drainage
water. In the event of environmental contamination or a release
of hazardous materials, we could become subject to claims for
toxic torts, natural resource damages and other damages and for
the investigation and clean up of soil, surface water,
groundwater, and other media. Such claims may arise out of
conditions at sites that we currently own or operate, as well as
at sites that we previously owned or operated, or may acquire.
Our liability for such claims may be joint and several, so that
we may be held responsible for more than our share of the
contamination or other damages, or even for the entire share.
These and other impacts that our operations may have on the
environment, as well as exposures to hazardous substances or
wastes associated with our operations, could result in costs and
liabilities that could have a material adverse effect on us.
Please read Business Environmental
Matters.
Climate
change legislation, regulatory initiatives and litigation could
result in increased operating costs and reduced demand for the
natural gas services we provide.
In recent years, the U.S. Congress has been considering
legislation to restrict or regulate emissions of greenhouse
gases, such as carbon dioxide and methane, that are understood
to contribute to global warming. The American Clean Energy and
Security Act of 2009, passed by the House of Representatives,
would, if enacted by the full Congress, have required greenhouse
gas, or GHG, emissions reductions by covered sources of as much
as 17% from 2005 levels by 2020 and by as much as 83% by 2050.
It presently appears unlikely that comprehensive climate
legislation will be passed by either house of Congress in the
near future, although energy legislation and other initiatives
are expected to be proposed that may be relevant to GHG
emissions issues. In addition, almost half of the states, either
individually or through multi-state regional initiatives, have
begun to address GHG emissions, primarily through the planned
development of emission inventories or regional GHG cap and
trade programs. Most of these cap and trade programs work by
requiring either major sources of emissions, such as electric
power plants, or major producers of fuels, such as refineries
and gas processing plants, to acquire and surrender emission
allowances. The number of allowances available for purchase is
reduced each year until the overall GHG emission reduction goal
is achieved. Depending on the scope of a particular program, we
could be required to purchase and surrender allowances for GHG
emissions resulting from our operations (e.g., at compressor
stations). Although most of the state-level initiatives have to
date been focused on large sources of GHG emissions, such as
electric power plants, it is possible that smaller sources such
as our gas-fired compressors could become subject to GHG-related
regulation. Depending on the particular program, we could be
required to control emissions or to purchase and surrender
allowances for GHG emissions resulting from our operations.
Independent of Congress, the EPA is beginning to adopt
regulations controlling GHG emissions under its existing Clean
Air Act authority. For example, on December 15, 2009, the
EPA officially published its findings that emissions of carbon
dioxide, methane and other GHGs present an endangerment to human
health and the environment because emissions of such gases are,
according to the EPA, contributing to warming of the
earths atmosphere and other climatic changes. These
findings by the EPA allow the agency to proceed with the
adoption and implementation of regulations that would restrict
emissions of greenhouse gases under existing provisions of the
federal Clean Air Act. In 2009, the EPA adopted rules regarding
regulation of GHG emissions from motor vehicles. In addition, on
September 22, 2009, the EPA issued a final rule requiring
the reporting of greenhouse gas emissions from specified large
greenhouse gas emission sources in the U.S. beginning in
2011 for emissions occurring in 2010. Our Bazor Ridge facility
is currently required to report under this rule beginning in
2011. On November 30, 2010, the EPA published a final rule
expanding its existing GHG emissions reporting rule for
petroleum and natural gas facilities, including natural gas
transmission compression facilities that emit 25,000 metric tons
or more of carbon dioxide equivalent per year. The rule, which
went into effect on December 30, 2010, requires reporting
of greenhouse gas emissions by regulated facilities to EPA by
March 2012 for emissions during 2011 and annually thereafter.
Three of our onshore compression facilities will likely be
required to report under this rule, with the first report due to
the EPA on March 31, 2012. In 2010, EPA also issued a final
rule, known as the Tailoring Rule, that makes
certain large stationary sources and modification projects
subject to permitting requirements for greenhouse
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gas emissions under the Clean Air Act. Several of EPAs
greenhouse gas rules are being challenged in pending court
proceedings and, depending on the outcome of such proceedings,
such rules may be modified or rescinded or the EPA could develop
new rules.
Although it is not possible at this time to accurately estimate
how potential future laws or regulations addressing greenhouse
gas emissions would impact our business, any future federal laws
or implementing regulations that may be adopted to address
greenhouse gas emissions could require us to incur increased
operating costs and could adversely affect demand for the
natural gas we gather, treat or otherwise handle in connection
with our services. The potential increase in the costs of our
operations resulting from any legislation or regulation to
restrict emissions of greenhouse gases could include new or
increased costs to operate and maintain our facilities, install
new emission controls on our facilities, acquire allowances to
authorize our greenhouse gas emissions, pay any taxes related to
our greenhouse gas emissions and administer and manage a
greenhouse gas emissions program. While we may be able to
include some or all of such increased costs in the rates charged
by our pipelines or other facilities, such recovery of costs is
uncertain. Moreover, incentives to conserve energy or use
alternative energy sources could reduce demand for natural gas,
resulting in a decrease in demand for our services. We cannot
predict with any certainty at this time how these possibilities
may affect our operations.
Increased
regulation of hydraulic fracturing could result in reductions or
delays in natural gas production by our customers, which could
adversely impact our revenue.
A portion of our customers oil and gas production is
developed from unconventional sources, such as coalbed methane
plays, that require hydraulic fracturing as part of the
completion process. Hydraulic fracturing involves the injection
of water, sand and chemicals under pressure into the formation
to stimulate gas production. Legislation to amend the Safe
Drinking Water Act to repeal the exemption for hydraulic
fracturing from definition of underground injection
and require federal permitting and regulatory control of
hydraulic fracturing, as well as legislative proposals to
require disclosure of the chemical constituents of the fluids
used in the fracturing process, were proposed in recent sessions
of Congress. The U.S. Congress continues to consider
legislation to amend the Safe Drinking Water Act. Scrutiny of
hydraulic fracturing activities continues in other ways, with
the EPA having commenced a multi-year study of the potential
environmental impacts of hydraulic fracturing, the results of
which are anticipated to be available by 2012. Several states
have also proposed or adopted legislative or regulatory
restrictions on hydraulic fracturing. We cannot predict whether
any such legislation will ever be enacted and if so, what its
provisions would be. If additional levels of regulation and
permits were required through the adoption of new laws and
regulations at the federal or state level, that could lead to
delays, increased operating costs and process prohibitions that
could reduce the volumes of natural gas that move through our
gathering systems which would materially adversely affect our
revenue and results of operations.
Our
pipelines may be subject to more stringent safety
regulation.
Proposed pipeline safety legislation requiring more stringent
spill reporting and disclosure obligations was introduced in the
U.S. Congress and passed by the U.S. House of
Representatives in 2010, but was not voted on in the
U.S. Senate. Similar legislation is likely to be considered
in the current session of Congress, either independently or in
conjunction with the reauthorization of the Pipeline Safety Act.
The Department of Transportation has also recently proposed
legislation providing for more stringent oversight of pipelines
and increased penalties for violations of safety rules, which is
in addition to the Pipeline and Hazardous Materials Safety
Administrations announced intention to strengthen its
rules. Such legislative and regulatory changes could have a
material effect on our operations through more stringent and
comprehensive safety regulations and higher penalties for the
violation of those regulations.
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The
adoption and implementation of new statutory and regulatory
requirements for swap transactions could have an adverse impact
on our ability to hedge risks associated with our business and
increase the working capital requirements to conduct these
activities.
In July 2010 federal legislation known as the Dodd-Frank Wall
Street Reform and Consumer Protection Act, or the Dodd-Frank
Act, was enacted. The Dodd-Frank Act provides new statutory
requirements for swap transactions, including oil and gas
hedging transactions. These statutory requirements must be
implemented through, regulation primarily through rules to be
adopted by the Commodities Futures Trading Commission, or the
CFTC. The Dodd-Frank Act provisions are intended to change
fundamentally the way swap transactions are entered into,
transforming an
over-the-counter
market in which parties negotiate directly with each other into
a regulated market in which most swaps are to be executed on
registered exchanges or swap execution facilities and cleared
through central counterparties. Many market participants will be
newly regulated as swap dealers or major swap participants, with
new regulatory capital requirements and other regulations that
may impose business conduct rules and mandate how they hold
collateral or margin for swap transactions. All market
participants will be subject to new reporting and recordkeeping
requirements.
The impact of the Dodd-Frank Act on our hedging activities is
uncertain at this time, and the CFTC has not yet promulgated
final regulations implementing the key provisions. Although we
do not believe we will need to register as a swap dealer or
major swap participant, and do not believe we will be subject to
the new requirements to trade on an exchange or swap execution
facility or to clear swaps through a central counterparty, we
may have new regulatory burdens. Moreover, the changes to the
swap market as a result of Dodd-Frank implementation could
significantly increase the cost of entering into new swaps or
maintaining existing swaps, materially alter the terms of new or
existing swap transactions
and/or
reduce the availability of new or existing swaps.
Depending on the rules and definitions adopted by the CFTC, we
might in the future be required to provide cash collateral for
our commodities hedging transactions under circumstances in
which we do not currently post cash collateral. Posting of such
additional cash collateral could impact liquidity and reduce our
cash available for capital expenditures or other partnership
purposes. A requirement to post cash collateral could therefore
reduce our willingness or ability to execute hedges to reduce
commodity price uncertainty and thus protect cash flows. If we
reduce our use of swaps as a result of the Dodd-Frank Act and
regulations, our results of operations may become more volatile
and our cash flows may be less predictable.
We do
not own all of the land on which our pipelines and facilities
are located, which could result in disruptions to our
operations.
We do not own all of the land on which our pipelines and
facilities have been constructed, and we are, therefore, subject
to the possibility of more onerous terms
and/or
increased costs to retain necessary land use if we do not have
valid
rights-of-way
or if such
rights-of-way
lapse or terminate. We obtain the rights to construct and
operate our pipelines on land owned by third parties and
governmental agencies for a specific period of time. Our loss of
these rights, through our inability to renew
right-of-way
contracts or otherwise, could have a material adverse effect on
our business, results of operations, financial condition and
ability to make cash distributions to our unitholders.
Restrictions
in our new credit facility could adversely affect our business,
financial condition, results of operations, ability to make
distributions to unitholders and value of our common
units.
We expect to enter into a new credit facility concurrently with
the closing of the offering. Our new credit facility is likely
to limit our ability to, among other things:
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incur additional debt;
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make distributions on or redeem or repurchase units;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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transfer or otherwise dispose of assets.
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Our new credit facility also will likely contain covenants
requiring us to maintain certain financial ratios.
The provisions of our new credit facility may affect our ability
to obtain future financing and pursue attractive business
opportunities and our flexibility in planning for, and reacting
to, changes in business conditions. In addition, a failure to
comply with the provisions of our new credit facility could
result in a default or an event of default that could enable our
lenders to declare the outstanding principal of that debt,
together with accrued and unpaid interest, to be immediately due
and payable. If the payment of our debt is accelerated, our
assets may be insufficient to repay such debt in full, and our
unitholders could experience a partial or total loss of their
investment.
Debt
we incur in the future may limit our flexibility to obtain
financing and to pursue other business
opportunities.
Our future level of debt could have important consequences to
us, including the following:
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our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
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our funds available for operations, future business
opportunities and distributions to unitholders will be reduced
by that portion of our cash flow required to make interest
payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn
in our business or the economy generally; and
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our flexibility in responding to changing business and economic
conditions may be limited.
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Our ability to service our debt will depend upon, among other
things, our future financial and operating performance, which
will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, some of which
are beyond our control. If our operating results are not
sufficient to service any future indebtedness, we will be forced
to take actions such as reducing distributions, reducing or
delaying our business activities, acquisitions, investments or
capital expenditures, selling assets or seeking additional
equity capital. We may not be able to effect any of these
actions on satisfactory terms or at all.
Increases
in interest rates could adversely impact our unit price, our
ability to issue equity or incur debt for acquisitions or other
purposes and our ability to make cash distributions at our
intended levels.
Interest rates may increase in the future. As a result, interest
rates on future credit facilities and debt offerings could be
higher than current levels, causing our financing costs to
increase accordingly. As with other yield-oriented securities,
our unit price is impacted by our level of our cash
distributions and implied distribution yield. The distribution
yield is often used by investors to compare and rank
yield-oriented securities for investment decision-making
purposes. Therefore, changes in interest rates, either positive
or negative, may affect the yield requirements of investors who
invest in our units, and a rising interest rate environment
could have an adverse impact on our unit price, our ability to
issue equity or incur debt for acquisitions or other purposes
and our ability to make cash distributions at our intended
levels.
Our
ability to operate our business effectively could be impaired if
we fail to attract and retain key management
personnel.
Our ability to operate our business and implement our strategies
depends on the continued contributions of certain executive
officers and key employees of our general partner. The loss of
any of our senior executives could have a material adverse
effect on our business. In addition, we believe that our future
success will depend on our continued ability to attract and
retain highly skilled management personnel with midstream
natural gas
30
industry experience and competition for these persons in the
midstream natural gas industry is intense. Given our small size,
we may be at a disadvantage, relative to our larger competitors,
in the competition for these personnel. We may not be able to
continue to employ our senior executives and key personnel or
attract and retain qualified personnel in the future, and our
failure to retain or attract our senior executives and key
personnel could have a material adverse effect on our ability to
effectively operate our business.
A
shortage of skilled labor in the midstream natural gas industry
could reduce labor productivity and increase costs, which could
have a material adverse effect on our business and results of
operations.
The gathering, treating, processing and transporting of natural
gas requires skilled laborers in multiple disciplines such as
equipment operators, mechanics and engineers, among others. We
have from time to time encountered shortages for these types of
skilled labor. If we experience shortages of skilled labor in
the future, our labor and overall productivity or costs could be
materially and adversely affected. If our labor prices increase
or if we experience materially increased health and benefit
costs with respect to our general partners employees, our
results of operations could be materially and adversely affected.
Our
work force could become unionized in the future, which could
adversely affect the stability of our production and materially
reduce our profitability.
All of our systems are operated by non-union employees of our
general partner. Our employees have the right at any time under
the National Labor Relations Act to form or affiliate with a
union. If our employees choose to form or affiliate with a union
and the terms of a union collective bargaining agreement are
significantly different from our current compensation and job
assignment arrangements with our employees, these arrangements
could adversely affect the stability of our operations and
materially reduce our profitability.
The
amount of cash we have available for distribution to holders of
our common and subordinated units depends primarily on our cash
flow rather than on our profitability, which may prevent us from
making distributions, even during periods in which we record net
income.
The amount of cash we have available for distribution depends
primarily upon our cash flow and not solely on profitability,
which will be affected by non-cash items. As a result, we may
make cash distributions during periods when we record losses for
financial accounting purposes and may not make cash
distributions during periods when we record net earnings for
financial accounting purposes.
Terrorist
attacks and threats, escalation of military activity in response
to these attacks or acts of war could have a material adverse
effect on our business, financial condition or results of
operations.
Terrorist attacks and threats, escalation of military activity
or acts of war may have significant effects on general economic
conditions, fluctuations in consumer confidence and spending and
market liquidity, each of which could materially and adversely
affect our business. Future terrorist attacks, rumors or threats
of war, actual conflicts involving the United States or its
allies, or military or trade disruptions affecting our customers
may significantly affect our operations and those of our
customers. Strategic targets, such as energy-related assets and
transportation assets, may be at greater risk of future
terrorist attacks than other targets in the United States.
Disruption or significant increases in energy prices could
result in government-imposed price controls. It is possible that
any of these occurrences, or a combination of them, could have a
material adverse effect on our business, financial condition and
results of operations.
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Risks
Inherent in an Investment in Us
AIM
Midstream Holdings directly owns and controls our general
partner, which has sole responsibility for conducting our
business and managing our operations. AIM Midstream Holdings and
our general partner have conflicts of interest with us and
limited fiduciary duties, and they may favor AIM Midstream
Holdings interests to the detriment of us and our
unitholders.
Following this offering, AIM Midstream Holdings will own and
control our general partner, as well as appoint all of the
officers and directors of our general partner, some of whom will
also be officers of AIM Midstream Holdings. Although our general
partner has a fiduciary duty to manage us in a manner that is
beneficial to us and our unitholders, the directors and officers
of our general partner have a fiduciary duty to manage our
general partner in a manner that is beneficial to its owner, AIM
Midstream Holdings. Conflicts of interest may arise between AIM
Midstream Holdings and our general partner, on the one hand, and
us and our unitholders, on the other hand. In resolving these
conflicts of interest, our general partner may favor its own
interests and the interests of AIM Midstream Holdings over our
interests and the interests of our unitholders. These conflicts
include the following situations, among others:
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Neither our partnership agreement nor any other agreement
requires AIM Midstream Holdings to pursue a business strategy
that favors us.
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Our general partner is allowed to take into account the
interests of parties other than us, such as AIM Midstream
Holdings, in resolving conflicts of interest.
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Our partnership agreement limits the liability of and reduces
the fiduciary duties owed by our general partner, and also
restricts the remedies available to our unitholders for actions
that, without the limitations, might constitute breaches of
fiduciary duty.
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Except in limited circumstances, our general partner has the
power and authority to conduct our business without unitholder
approval.
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Our general partner determines the amount and timing of asset
purchases and sales, borrowings, issuance of additional
partnership securities and the creation, reduction or increase
of reserves, each of which can affect the amount of cash that is
distributed to our unitholders.
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Our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is
classified as a maintenance capital expenditure, which reduces
operating surplus, or an expansion capital expenditure, which
does not reduce operating surplus. This determination can affect
the amount of cash that is distributed to our unitholders and to
our general partner and the ability of the subordinated units to
convert to common units.
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Our general partner determines which costs incurred by it are
reimbursable by us.
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Our general partner may cause us to borrow funds in order to
permit the payment of 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.
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Our partnership agreement permits us to classify up to
$ million as operating
surplus, even if it is generated from asset sales, non-working
capital borrowings or other sources that would otherwise
constitute capital surplus. This cash may be used to fund
distributions on our subordinated units or to our general
partner in respect of the general partner interest or the
incentive distribution rights.
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Our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf.
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Our general partner intends to limit its liability regarding our
contractual and other obligations.
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Our general partner may exercise its right to call and purchase
all of the common units not owned by it and its affiliates if
they own more than 80% of the common units.
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Our general partner controls the enforcement of the obligations
that it and its affiliates owe to us.
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Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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Our general partner may elect to cause us to issue common units
to it in connection with a resetting of the target distribution
levels related to our general partners incentive
distribution rights without the approval of the conflicts
committee of the board of directors of our general partner or
our unitholders. This election may result in lower distributions
to our common unitholders in certain situations.
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Please read Conflicts of Interest and Fiduciary
Duties.
AIM
Midstream Holdings is not limited in its ability to compete with
us and is not obligated to offer us the opportunity to acquire
additional assets or businesses, which could limit our ability
to grow and could adversely affect our results of operations and
cash available for distribution to our
unitholders.
AIM Midstream Holdings is not prohibited from owning assets or
engaging in businesses that compete directly or indirectly with
us. In addition, in the future, AIM Midstream Holdings may
acquire, construct or dispose of additional midstream or other
assets and may be presented with new business opportunities,
without any obligation to offer us the opportunity to purchase
or construct such assets or to engage in such business
opportunities. Moreover, while AIM Midstream Holdings may offer
us the opportunity to buy additional assets from it, it is under
no contractual obligation to do so and we are unable to predict
whether or when such acquisitions might be completed.
There
is no existing market for our common units, and a trading market
that will provide you with adequate liquidity may not develop.
The price of our common units may fluctuate significantly, and
you could lose all or part of your investment.
Prior to this offering, there has been no public market for our
common units. After this offering, there will be
only
publicly traded common units, assuming no exercise of the
underwriters option to purchase additional common units.
In addition, AIM Midstream Holdings will
own
common
and
subordinated units, representing an
aggregate % limited partner
interest in us. We do not know the extent to which investor
interest will lead to the development of a trading market or how
liquid that market might be. Furthermore, this offering is
smaller than initial public offerings for midstream companies in
recent years, which may lead to an even greater lack of
liquidity than normal. You may not be able to resell your common
units at or above the initial public offering price.
Additionally, the lack of liquidity may result in wide bid-ask
spreads, contribute to significant fluctuations in the market
price of the common units and limit the number of investors who
are able to buy the common units.
The initial public offering price for the common units will be
determined by negotiations between us and the representatives of
the underwriters and may not be indicative of the market price
of the common units that will prevail in the trading market. The
market price of our common units may decline below the initial
public offering price. The market price of our common units may
also be influenced by many factors, some of which are beyond our
control, including:
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our quarterly distributions;
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our quarterly or annual earnings or those of other companies in
our industry;
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the loss of a large customer;
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announcements by us or our competitors of significant contracts
or acquisitions;
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changes in accounting standards, policies, guidance,
interpretations or principles;
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general economic conditions;
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the failure of securities analysts to cover our common units
after this offering or changes in financial estimates by
analysts;
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future sales of our common units; and
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other factors described in these Risk Factors.
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If you
are not an Eligible Holder, you may not receive distributions or
allocations of income or loss on your common units and your
common units will be subject to redemption.
We have adopted certain requirements regarding those investors
who may own our common and subordinated units. Eligible Holders
are U.S. individuals or entities subject to
U.S. federal income taxation on the income generated by us
or entities not subject to U.S. federal income taxation on
the income generated by us, so long as all of the entitys
owners are U.S. individuals or entities subject to such
taxation. If you are not an Eligible Holder, our general partner
may elect not to make distributions or allocate income or loss
on your units, and you run the risk of having your units
redeemed by us at the lower of your purchase price cost and the
then-current market price. The redemption price may be paid in
cash or by delivery of a promissory note, as determined by our
general partner. Please read The Partnership
Agreement
Non-Citizen
Assignees; Redemption.
Common
units held by persons who are non-taxpaying assignees will be
subject to the possibility of redemption.
Our partnership agreement gives our general partner the power to
amend the agreement to avoid any adverse effect on the maximum
applicable rates chargeable to customers by us under FERC
regulations, or in order to reverse an adverse determination
that has occurred regarding such maximum rate. If our general
partner determines that our not being treated as an association
taxable as a corporation or otherwise taxable as an entity for
U.S. federal income tax purposes, coupled with the tax
status (or lack of proof thereof) of one or more of our limited
partners, has, or is reasonably likely to have, a material
adverse effect on the maximum applicable rates chargeable to
customers by us, then our general partner may adopt such
amendments to our partnership agreement as it determines are
necessary or advisable to obtain proof of the U.S. federal
income tax status of our limited partners (and their owners, to
the extent relevant) and permit us to redeem the units held by
any person whose tax status has or is reasonably likely to have
a material adverse effect on the maximum applicable rates or who
fails to comply with the procedures instituted by our general
partner to obtain proof of the U.S. federal income tax
status. Please read The Partnership Agreement
Non-Taxpaying Assignees; Redemption.
Our
general partner intends to limit its liability regarding our
obligations.
Our general partner intends to limit its liability under
contractual arrangements so that the counterparties to such
arrangements have recourse only against our assets, and not
against our general partner or its assets. Our general partner
may therefore cause us to incur indebtedness or other
obligations that are nonrecourse to our general partner. Our
partnership agreement provides that any action taken by our
general partner to limit its liability is not a breach of our
general partners fiduciary duties, even if we could have
obtained more favorable terms without the limitation on
liability. In addition, we are obligated to reimburse or
indemnify our general partner to the extent that it incurs
obligations on our behalf. Any such reimbursement or
indemnification payments would reduce the amount of cash
otherwise available for distribution to our unitholders.
Our
partnership agreement requires that we distribute all of our
available cash, which could limit our ability to grow and make
acquisitions.
We expect that we will distribute all of our available cash to
our unitholders and will rely primarily upon external financing
sources, including commercial bank borrowings and the issuance
of debt and equity securities, to fund our acquisitions and
expansion capital expenditures. As a result, to the extent we
are unable to finance growth externally, our cash distribution
policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, we
may not grow as quickly as businesses that reinvest their
available cash to expand ongoing operations. To the extent we
issue additional units in
34
connection with any acquisitions or expansion capital
expenditures, the payment of distributions on those additional
units may increase the risk that we will be unable to maintain
or increase our per unit distribution level. There are no
limitations in our partnership agreement, and we do not
anticipate there being limitation in our new credit facility, on
our ability to issue additional units, including units ranking
senior to the common units. The incurrence of additional
commercial borrowings or other debt to finance our growth
strategy would result in increased interest expense, which, in
turn, may impact the available cash that we have to distribute
to our unitholders.
Our
partnership agreement limits our general partners
fiduciary duties to holders of our common and subordinated
units.
Our partnership agreement contains provisions that modify and
reduce the fiduciary standards to which our general partner
would otherwise be held by state fiduciary duty law. For
example, our partnership agreement permits our general partner
to make a number of decisions in its individual capacity, as
opposed to in its capacity as our general partner or otherwise,
free of fiduciary duties to us and our unitholders. This
entitles our general partner to consider only the interests and
factors that it desires and relieves it of any duty or
obligation to give any consideration to any interest of, or
factors affecting, us, our affiliates or our limited partners.
Examples of decisions that our general partner may make in its
individual capacity include:
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how to allocate corporate opportunities among us and its
affiliates;
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whether to exercise its limited call right;
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how to exercise its voting rights with respect to the units it
owns;
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whether to elect to reset target distribution levels; and
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whether or not to consent to any merger or consolidation of the
partnership or amendment to the partnership agreement.
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By purchasing a common unit, a common unitholder agrees to
become bound by the provisions in the partnership agreement,
including the provisions discussed above. Please read
Conflicts of Interest and Fiduciary Duties
Fiduciary Duties.
Our
partnership agreement restricts the remedies available to
holders of our common and subordinated units for actions taken
by our general partner that might otherwise constitute breaches
of fiduciary duty.
Our partnership agreement contains provisions that restrict the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty under state fiduciary duty law. For example, our
partnership agreement:
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provides that whenever our general partner makes a determination
or takes, or declines to take, any other action in its capacity
as our general partner, our general partner is required to make
such determination, or take or decline to take such other
action, in good faith, and will not be subject to any other or
different standard imposed by our partnership agreement,
Delaware law, or any other law, rule or regulation, or at equity;
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as such decisions are made in good
faith, meaning that it believed that the decision was in, or not
opposed to, the best interest of our partnership;
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provides that our general partner and its officers and directors
will not be liable for monetary damages to us, our limited
partners or their assignees resulting from any act or omission
unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that
our general partner or its officers and directors, as the case
may be, acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal matter, acted with
knowledge that the conduct was criminal; and
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provides that our general partner will not be in breach of its
obligations under the partnership agreement or its fiduciary
duties to us or our unitholders if a transaction with an
affiliate or the resolution of a conflict of interest is:
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(a) approved by the conflicts committee of the board of
directors of our general partner, although our general partner
is not obligated to seek such approval;
(b) approved by the vote of a majority of the outstanding
common units, excluding any common units owned by our general
partner and its affiliates;
(c) on terms no less favorable to us than those generally
being provided to or available from unrelated third
parties; or
(d) fair and reasonable to us, taking into account the
totality of the relationships among the parties involved,
including other transactions that may be particularly favorable
or advantageous to us.
In connection with a situation involving a transaction with an
affiliate or a conflict of interest, any determination by our
general partner must be made in good faith. If an affiliate
transaction or the resolution of a conflict of interest is not
approved by our common unitholders or the conflicts committee
and the board of directors of our general partner determines
that the resolution or course of action taken with respect to
the affiliate transaction or conflict of interest satisfies
either of the standards set forth in subclauses (c) and
(d) above, then it will be presumed that, in making its
decision, the board of directors acted in good faith, and in any
proceeding brought by or on behalf of any limited partner or the
partnership, the person bringing or prosecuting such proceeding
will have the burden of overcoming such presumption.
Our
general partner may elect to cause us to issue common units to
it in connection with a resetting of the target distribution
levels related to our general partners incentive
distribution rights without the approval of the conflicts
committee of our general partners board or our
unitholders. This election may result in lower distributions to
our common unitholders in certain situations.
Our general partner has the right, at any time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled
(48.0%) for each of the prior four consecutive fiscal quarters,
to reset the initial target distribution levels at higher levels
based on our cash distribution at the time of the exercise of
the reset election. Following a reset election by our general
partner, the minimum quarterly distribution will be reset to an
amount equal to the average cash distribution per unit for the
two fiscal quarters immediately preceding the reset election
(such amount is referred to as the reset minimum quarterly
distribution), and the target distribution levels will be
reset to correspondingly higher levels based on percentage
increases above the reset minimum quarterly distribution.
We anticipate that our general partner would exercise this reset
right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion; however,
it is possible that our general partner could exercise this
reset election at a time when we are experiencing declines in
our aggregate cash distributions or at a time when our general
partner expects that we will experience declines in our
aggregate cash distributions in the foreseeable future. In such
situations, our general partner may be experiencing, or may
expect to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued common units, which are entitled
to specified priorities with respect to our distributions and
which therefore may be more advantageous for the general partner
to own in lieu of the right to receive incentive distribution
payments based on target distribution levels that are less
certain to be achieved in the then current business environment.
As a result, a reset election may cause our common unitholders
to experience dilution in the amount of cash distributions that
they would have otherwise received had we not issued common
units to our general partner in connection with resetting the
target distribution levels related to our general partners
incentive distribution rights. Please read Provisions of
Our Partnership Agreement Relating to Cash
Distributions General Partners Right to Reset
Incentive Distribution Levels.
36
Holders
of our common units have limited voting rights and are not
entitled to elect our general partner or its
directors.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will have no right on an annual or ongoing basis to elect our
general partner or its board of directors. The board of
directors of our general partner will be chosen by AIM Midstream
Holdings. Furthermore, if the unitholders are dissatisfied with
the performance of our general partner, they will have little
ability to remove our general partner. As a result of these
limitations, the price at which the common units will trade
could be diminished because of the absence or reduction of a
takeover premium in the trading price. Our partnership agreement
also contains provisions limiting the ability of unitholders to
call meetings or to acquire information about our operations, as
well as other provisions limiting the unitholders ability
to influence the manner or direction of management.
Even
if holders of our common units are dissatisfied, they cannot
initially remove our general partner without its
consent.
The unitholders initially will be unable to remove our general
partner without its consent because our general partner and its
affiliates will own sufficient units upon the closing of this
offering to be able to prevent its removal. The vote of the
holders of at least
662/3%
of all outstanding limited partner units voting together as a
single class is required to remove our general partner.
Following the closing of this offering, AIM Midstream Holdings
will own % of our outstanding
common and subordinated units. Also, if our general partner is
removed without cause during the subordination period and units
held by our general partner and its affiliates are not voted in
favor of that removal, all remaining subordinated units will
automatically convert into common units and any existing
arrearages on our common units will be extinguished. A removal
of our general partner under these circumstances would adversely
affect our common units by prematurely eliminating their
distribution and liquidation preference over our subordinated
units, which would otherwise have continued until we had met
certain distribution and performance tests. Cause is narrowly
defined to mean that a court of competent jurisdiction has
entered a final, non-appealable judgment finding our general
partner liable for actual fraud or willful or wanton misconduct
in its capacity as our general partner. Cause does not include
most cases of charges of poor management of the business, so the
removal of our general partner because of the unitholders
dissatisfaction with our general partners performance in
managing our partnership will most likely result in the
termination of the subordination period and conversion of all
subordinated units to common units.
Our
partnership agreement restricts the voting rights of unitholders
owning 20% or more of our common units.
Unitholders voting rights are further restricted by a
provision of our partnership agreement providing that any units
held by a person that owns 20% or more of any class of units
then outstanding, other than our general partner, its
affiliates, their transferees and persons who acquired such
units with the prior approval of the board of directors of our
general partner, cannot vote on any matter.
Our
general partner interest or the control of our general partner
may be transferred to a third party without unitholder
consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of AIM Midstream Holdings to transfer all or a portion
of its ownership interest in our general partner to a third
party. The new owner of our general partner would then be in a
position to replace the board of directors and officers of our
general partner with its own designees and thereby exert
significant control over the decisions made by the board of
directors and officers.
You
will experience immediate and substantial dilution in net
tangible book value of $ per
common unit.
The estimated initial public offering price of
$ per common unit (the midpoint of
the range set forth on the cover of this prospectus) exceeds our
net tangible book value of $ per
unit. Based on the estimated
37
initial public offering price of $
per common unit, you will incur immediate and substantial
dilution of $ per common unit.
This dilution results primarily because the assets contributed
by our general partner and its affiliates are recorded in
accordance with GAAP at their historical cost, and not their
fair value. Please read Dilution.
We may
issue additional units without your approval, which would dilute
your existing ownership interests.
Our partnership agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of our unitholders. The issuance by us
of additional common units or other equity securities of equal
or senior rank will have the following effects:
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our existing unitholders proportionate ownership interest
in us will decrease;
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the amount of cash available for distribution on each unit may
decrease;
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because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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AIM
Midstream Holdings may sell units in the public or private
markets, and such sales could have an adverse impact on the
trading price of the common units.
After the sale of the common units offered by this prospectus,
assuming that the underwriters do not exercise their option to
purchase additional common units, AIM Midstream Holdings will
hold an aggregate
of
common units
and
subordinated units. All of the subordinated units will convert
into common units at the end of the subordination period and may
convert earlier under certain circumstances. The sale of these
units in the public or private markets could have an adverse
impact on the price of the common units or on any trading market
that may develop.
Our
general partner has a limited call right that may require you to
sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, which it may assign to any of its affiliates or to us,
but not the obligation, to acquire all, but not less than all,
of the common units held by unaffiliated persons at a price that
is not less than their then-current market price, as calculated
pursuant to the terms of our partnership agreement. As a result,
you may be required to sell your common units at an undesirable
time or price and may not receive any return on your investment.
You may also incur a tax liability upon a sale of your units. At
the closing of this offering, and assuming no exercise of the
underwriters option to purchase additional common units,
AIM Midstream Holdings will own
approximately % of our outstanding
common units. At the end of the subordination period, assuming
no additional issuances of common units (other than upon the
conversion of the subordinated units), AIM Midstream Holdings
will own approximately % of our
outstanding common units. For additional information about this
right, please read The Partnership Agreement
Limited Call Right.
Your
liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law, and we conduct
business in a number of other states. The limitations on the
liability of holders of limited partner interests for the
obligations of a limited partnership
38
have not been clearly established in some of the other states in
which we do business. You could be liable for any and all of our
obligations as if you were a general partner if a court or
government agency were to determine that:
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we were conducting business in a state but had not complied with
that particular states partnership statute; or
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your right to act with other unitholders to remove or replace
our general partner, to approve some amendments to our
partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
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For a discussion of the implications of the limitations of
liability on a unitholder, please read The Partnership
Agreement Limited Liability.
Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets. Delaware
law provides that for a period of three years from the date of
an impermissible distribution, limited partners who received the
distribution and who knew at the time of the distribution that
it violated Delaware law will be liable to the limited
partnership for the distribution amount. Substituted limited
partners are liable both for the obligations of the assignor to
make contributions to the partnership that were known to the
substituted limited partner at the time it became a limited
partner and for those obligations that were unknown if the
liabilities could have been determined from the partnership
agreement. Neither liabilities to partners on account of their
partnership interest nor liabilities that are non-recourse to
the partnership are counted for purposes of determining whether
a distribution is permitted.
We
will incur increased costs as a result of being a publicly
traded partnership.
We have no history operating as a publicly traded partnership.
As a publicly traded partnership, we will incur significant
legal, accounting and other expenses. In addition, the
Sarbanes-Oxley Act of 2002 and related rules subsequently
implemented by the SEC and The NASDAQ Stock Market LLC, or the
NASDAQ, have required changes in the corporate governance
practices of publicly traded companies. We expect these rules
and regulations to increase our legal and financial compliance
costs and to make activities more time-consuming and costly. For
example, as a result of becoming a publicly traded partnership,
we are required to have at least three independent directors,
create an audit committee and adopt policies regarding internal
controls and disclosure controls and procedures, including the
preparation of reports on internal controls over financial
reporting. In addition, we will incur additional costs
associated with our publicly traded partnership reporting
requirements. We also expect these new rules and regulations to
make it more difficult and more expensive for our general
partner to obtain director and officer liability insurance and
to possibly result in our general partner having to accept
reduced policy limits and coverage. As a result, it may be more
difficult for our general partner to attract and retain
qualified persons to serve on its board of directors or as
executive officers. We have included $2.3 million of
estimated annual incremental costs associated with being a
publicly traded partnership in our financial forecast included
elsewhere in this prospectus. However, it is possible that our
actual incremental costs of being a publicly traded partnership
will be higher than we currently estimate.
If we
are deemed to be an investment company under the
Investment Company Act of 1940, it would adversely affect the
price of our common units and could have a material adverse
effect on our business.
Our initial assets will consist of our ownership interests in
our operating subsidiaries. If a sufficient amount of our other
assets are deemed to be investment securities,
within the meaning of the Investment Company Act of 1940, or the
Investment Company Act, we would either have to register as an
investment company under the Investment Company Act, obtain
exemptive relief from the SEC or modify our organizational
structure or contract rights so as to fall outside of the
definition of investment company. Registering as an investment
company could, among other things, materially limit our ability
to engage in transactions with affiliates, including the
purchase and sale of certain securities or other property from
or to our affiliates, restrict our ability
39
to borrow funds or engage in other transactions involving
leverage and require us to add additional directors who are
independent of us or our affiliates. The occurrence of some or
all of these events would adversely affect the price of our
common units and could have a material adverse effect on our
business.
Moreover, treatment of us as an investment company would prevent
our qualification as a partnership for federal income tax
purposes, in which case we would be treated as a corporation for
federal income tax purposes. As a result, we would pay federal
income tax on our taxable income at the corporate tax rate,
distributions to you would generally be taxed again as corporate
distributions and none of our income, gains, losses or
deductions would flow through to you. If we were taxed as a
corporation, our cash available for distribution to you would be
substantially reduced. Therefore, treatment of us as an
investment company would result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders,
likely causing a substantial reduction in the value of our
common units. For a discussion of the federal income tax
implications that would result from our treatment as a
corporation in any taxable year, please read Material
Federal Income Tax Consequences Partnership
Status.
Tax Risks
to Common Unitholders
In addition to reading the following risk factors, you should
read Material Federal Income Tax Consequences for a
more complete discussion of the expected material federal income
tax consequences of owning and disposing of common units.
Our
tax treatment depends on our status as a partnership for federal
income tax purposes. If the IRS were to treat us as a
corporation for federal income tax purposes, which would subject
us to entity-level taxation, then our cash available for
distribution to our unitholders would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the
Internal Revenue Service, or IRS, on this or any other tax
matter affecting us.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. A change in our business or a
change in current law could cause us to be treated as a
corporation for federal income tax purposes or otherwise subject
us to taxation as an entity.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of
35.0%, and would likely pay state and local income tax at
varying rates. Distributions would generally be taxed again as
corporate distributions (to the extent of our current and
accumulated earnings and profits), and no income, gains, losses,
deductions, or credits would flow through to you. Because a tax
would be imposed upon us as a corporation, our cash available
for distribution to you would be substantially reduced.
Therefore, if we were treated as a corporation for federal
income tax purposes there would be material reduction in the
anticipated cash flow and after-tax return to our unitholders,
likely causing a substantial reduction in the value of our
common units.
Our partnership agreement provides that, if a law is enacted or
existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects
us to entity-level taxation for federal, state or local income
tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the
impact of that law on us.
If we
were subjected to a material amount of additional entity-level
taxation by individual states, it would reduce our cash
available for distribution to our unitholders.
Changes in current state law may subject us to additional
entity-level taxation by individual states. Because of
widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. Imposition of such a tax
on us by Texas, and if applicable by any other state, will
reduce the cash available for distribution to you. Our
partnership agreement provides that, if a law is enacted or
existing law is
40
modified or interpreted in a manner that subjects us to
entity-level taxation, the minimum quarterly distribution amount
and the target distribution amounts may be adjusted to reflect
the impact of that law on us.
The
tax treatment of publicly traded partnerships or an investment
in our common units could be subject to potential legislative,
judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded
partnerships, including us, or an investment in our common units
may be modified by administrative, legislative or judicial
interpretation at any time. Recently, members of the
U.S. Congress have considered substantive changes to the
existing federal income tax laws that affect certain publicly
traded partnerships, which, if enacted, may or may not be
applied retroactively. Although we are unable to predict whether
any of these changes or any other proposals will ultimately be
enacted, any such changes could negatively impact the value of
an investment in our common units.
Our
unitholders share of our income will be taxable to them
for U.S. federal income tax purposes even if they do not receive
any cash distributions from us.
Because a unitholder will be treated as a partner to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, a unitholders allocable share
of our taxable income will be taxable to it, which may require
the payment of federal income taxes and, in some cases, state
and local income taxes on its share of our taxable income even
if it receives no cash distributions from us. Our unitholders
may not receive cash distributions from us equal to their share
of our taxable income or even equal to the actual tax liability
that results from that income.
If the
IRS contests the federal income tax positions we take, the
market for our common units may be adversely impacted and the
cost of any IRS contest will reduce our cash available for
distribution to our unitholders.
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 the conclusions of our counsel expressed in this
prospectus or from the positions we take, and the IRSs
positions may ultimately be sustained. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take
and such positions may not ultimately be sustained. A court may
not agree with some or all of our counsels conclusions or
the positions we take. Any contest with the IRS, and the outcome
of any IRS contest, may have a materially adverse impact on the
market for our common units and the price at which they trade.
In addition, our costs of any contest with the IRS will be borne
indirectly by our unitholders and our general partner because
the costs will reduce our cash available for distribution.
Tax
gain or loss on the disposition of our common units could be
more or less than expected.
If you sell your common units, you will recognize a gain or loss
for federal income tax purposes equal to the difference between
the amount realized and your tax basis in those common units.
Because distributions in excess of your allocable share of our
net taxable income decrease your tax basis in your common units,
the amount, if any, of such prior excess distributions with
respect to the common units you sell will, in effect, become
taxable income to you if you sell such common units at a price
greater than your tax basis in those common units, even if the
price you receive is less than your original cost. Furthermore,
a substantial portion of the amount realized on any sale of your
common units, whether or not representing gain, may be taxed as
ordinary income due to potential recapture items, including
depreciation recapture. In addition, because the amount realized
includes a unitholders share of our nonrecourse
liabilities, if you sell your common units, you may incur a tax
liability in excess of the amount of cash you receive from the
sale. Please read Material Federal Income Tax
Consequences Disposition of Common Units
Recognition of Gain or Loss for a further discussion of
the foregoing.
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Tax-exempt
entities and
non-U.S.
persons face unique tax issues from owning our common units that
may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as
employee benefit plans and 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 that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file U.S. federal income tax returns
and pay tax on their share of our taxable income. If you are a
tax-exempt entity or a
non-U.S. person,
you should consult a tax advisor before investing in our common
units.
We
will treat each purchaser of common units as having the same tax
benefits without regard to the actual common units purchased.
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 will adopt depreciation
and amortization positions that may not conform to all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to you. Our counsel is unable to opine as to
the validity of such filing positions. It also could affect the
timing of these tax benefits or the amount of gain from your
sale of common units and could have a negative impact on the
value of our common units or result in audit adjustments to your
tax returns. Please read Material Federal Income Tax
Consequences Tax Consequences of Unit
Ownership Section 754 Election for a
further discussion of the effect of the depreciation and
amortization positions we will adopt.
We
prorate our items of income, gain, loss and deduction for U.S.
federal income tax purposes between transferors and transferees
of our units each month based upon the ownership of our units on
the first day of each month, instead of on the basis of the date
a particular unit is transferred. The IRS may challenge this
treatment, which could change the allocation of items of income,
gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction
for U.S. federal income tax purposes between transferors
and transferees of our units each month based upon the ownership
of our units on the first day of each month, instead of on the
basis of the date a particular unit is transferred. The use of
this proration method may not be permitted under existing
Treasury Regulations. Recently, however, the U.S. Treasury
Department issued proposed Treasury Regulations that provide a
safe harbor pursuant to which publicly traded partnerships may
use a similar monthly simplifying convention to allocate tax
items among transferor and transferee unitholders. Nonetheless,
the proposed regulations do not specifically authorize the use
of the proration method we have adopted. If the IRS were to
challenge this method or new Treasury regulations were issued,
we may be required to change the allocation of items of income,
gain, loss and deduction among our unitholders. Andrews Kurth
LLP has not rendered an opinion with respect to whether our
monthly convention for allocating taxable income and losses is
permitted by existing Treasury Regulations. Please read
Material Federal Income Tax Consequences
Disposition of Common Units Allocations Between
Transferors and Transferees.
A
unitholder whose common units are loaned to a short
seller to cover a short sale of common units may be
considered as having disposed of those common units. If so, he
would no longer be treated for federal income tax purposes as a
partner with respect to those common units during the period of
the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose common units are loaned to a
short seller to cover a short sale of common units
may be considered as having disposed of the loaned common units,
he may no longer be treated for federal income tax purposes as a
partner with respect to those common units during the period of
the loan to the short seller and the unitholder may recognize
gain or loss from such disposition. Moreover, during the period
of the loan to the short seller, any of our income, gain, loss
or deduction with respect to those common units may not be
reportable by the unitholder and any cash distributions received
by the unitholder as to those
42
common units could be fully taxable as ordinary income. Our
counsel has not rendered an opinion regarding the treatment of a
unitholder where common units are loaned to a short seller to
cover a short sale of common units; therefore, our unitholders
desiring to assure their status as partners and avoid the risk
of gain recognition from a loan to a short seller are urged to
consult a tax advisor to discuss whether it is advisable to
modify any applicable brokerage account agreements to prohibit
their brokers from loaning their common units.
We
will adopt certain valuation methodologies and monthly
conventions for U.S. federal income tax purposes that may result
in a shift of income, gain, loss and deduction between our
general partner and our unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common
units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
our general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our valuation methods,
or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of taxable income, gain, loss and deduction between
our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
taxable gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have technically terminated our
partnership for federal income tax purposes if there is a sale
or exchange of 50% or more of the total interests in our capital
and profits within a twelve-month period. For purposes of
determining whether the 50% threshold has been met, multiple
sales of the same interest will be counted only once. Our
technical termination would, among other things, result in the
closing of our taxable year for all unitholders, which would
result in us filing two tax returns (and our unitholders could
receive two Schedules K-1 if relief was not available, as
described below) for one fiscal year and could result in a
deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a
taxable year other than a fiscal year ending December 31,
the closing of our taxable year may also result in more than
twelve months of our taxable income or loss being includable in
his taxable income for the year of termination. Our termination
currently would not affect our classification as a partnership
for federal income tax purposes, but instead we would be treated
as a new partnership for tax purposes. If treated as a new
partnership, we must make new tax elections and could be subject
to penalties if we are unable to determine that a termination
occurred. The IRS has recently announced a publicly traded
partnership technical termination relief program whereby, if a
publicly traded partnership that technically terminated requests
publicly traded partnership technical termination relief and
such relief is granted by the IRS, among other things, the
partnership will only have to provide one
Schedule K-1
to unitholders for the year notwithstanding two partnership tax
years. Please read Material Federal Income Tax
Consequences Disposition of Common Units
Constructive Termination for a discussion of the
consequences of our termination for federal income tax purposes.
As a
result of investing in our common units, you may become subject
to state and local taxes and return filing requirements in
jurisdictions where we operate or own or acquire
properties.
In addition to federal income taxes, our unitholders will likely
be subject to other taxes, including state and local taxes,
unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by
43
the various jurisdictions in which we conduct business or own
property now or in the future, even if they do not live in any
of those jurisdictions. Our unitholders will likely be required
to file state and local income tax returns and pay state and
local income taxes in some or all of these various
jurisdictions. Further, our unitholders may be subject to
penalties for failure to comply with those requirements. We will
initially own property or conduct business in a number of
states, most of which currently impose a personal income tax on
individuals. Most of these states also impose an income tax on
corporations and other entities. As we make acquisitions or
expand our business, we may own property or conduct business in
additional states that impose a personal income tax. It is your
responsibility to file all U.S. federal, state and local
tax returns. Our counsel has not rendered an opinion on the
state or local tax consequences of an investment in our common
units.
Compliance
with and changes in tax laws could adversely affect our
performance.
We are subject to extensive tax laws and regulations, including
federal, state and foreign income taxes and transactional taxes
such as excise, sales/use, payroll, franchise and ad valorem
taxes. New tax laws and regulations and changes in existing tax
laws and regulations are continuously being enacted that could
result in increased tax expenditures in the future. Many of
these tax liabilities are subject to audits by the respective
taxing authority. These audits may result in additional taxes as
well as interest and penalties.
44
USE OF
PROCEEDS
We expect to receive net proceeds of approximately
$ million (based upon the
mid-point of the price range set forth on the cover page of this
prospectus), after deducting underwriting discounts, commissions
and structuring fees, but before paying offering expenses, from
the issuance and sale of common units offered by this
prospectus. We will use the net proceeds from this offering to:
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repay in full the outstanding balance under our existing credit
facility;
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pay offering expenses of approximately
$ million;
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terminate, in exchange for a payment of approximately
$ , the advisory services
agreement between American Midstream, LLC and AIM;
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establish a cash reserve of $2.2 million related to
non-recurring deferred maintenance capital expenditures for the
twelve months ending June 30, 2012; and
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distribute approximately
$ million to AIM Midstream
Holdings for reimbursement of capital expenditures funded by the
initial investment by AIM Midstream Holdings in us.
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Immediately following the repayment of the outstanding balance
under our existing credit facility with the net proceeds of this
offering, we will terminate our existing credit facility and
enter into a new credit facility and borrow approximately
$ under that credit facility. We
will use the proceeds from that borrowing to (i) fund a
distribution of approximately $ to
AIM Midstream Holdings and (ii) pay fees and expenses of
approximately $ relating to our
new credit facility.
A portion of the amounts to be repaid under our existing credit
facility with the net proceeds of this offering were used to
finance our acquisition of our assets in November 2009. As of
March 29, 2011, we had approximately $56.3 million of
indebtedness outstanding under our existing credit facility.
This indebtedness had a weighted average interest rate of 7.41%
as of March 29, 2011. At December 31, 2010, we had
$56.4 million of borrowings outstanding under our existing
credit facility. Our existing credit facility matures in
November 2012.
Our estimates assume an initial public offering price of
$ per common unit (based upon the
mid-point of the price range set forth on the cover page of this
prospectus) and no exercise of the underwriters option to
purchase additional common units. An increase or decrease in the
initial public offering price of $1.00 per common unit would
cause the net proceeds from the offering, after deducting
underwriting discounts, to increase or decrease by
$ million. Any increase or
decrease in the initial public offering price will result in a
corresponding adjustment to the distribution to AIM Midstream
Holdings from the net proceeds of this offering.
If the underwriters exercise their option to purchase additional
common units, we will use the net proceeds from that exercise to
redeem from AIM Midstream Holdings a number of common units
equal to the number of common units issued upon such exercise,
at a price per common unit equal to the proceeds per common unit
in this offering before expenses but after deducting
underwriting discounts, commissions and structuring fees.
The underwriters may, from time to time, engage in transactions
with and perform services for us and our affiliates in the
ordinary course of business. Please read
Underwriting.
45
CAPITALIZATION
The following table shows:
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our historical capitalization, as of December 31,
2010; and
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our pro forma as adjusted capitalization, as of
December 31, 2010, giving effect to:
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our receipt and use of net proceeds of
$ million from the issuance
and sale
of
common units to the public at an assumed initial offering price
of $ (based upon the mid-point of
the price range set forth on the cover page of this prospectus)
in the manner described in Use of Proceeds,
including the repayment of all outstanding indebtedness under
our existing credit facility;
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the entry into and borrowings of
$
under the new credit facility; and
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the other transactions described in Summary
Recapitalization Transactions and Partnership Structure.
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We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, our
historical consolidated financial statements and the
accompanying notes included elsewhere in this prospectus. You
should also read this table in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations. This table assumes
that the underwriters option to purchase additional common
units is not exercised.
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As of December 31, 2010
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Pro Forma,
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Historical
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As Adjusted
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(in thousands)
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Cash and cash equivalents(1)
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$
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63
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$
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Long-Term Debt:
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Existing credit facility(2)
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$
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56,370
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$
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New credit facility(3)(4)
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Total long-term debt (including current maturities)
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$
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56,370
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$
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Partners Capital:
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Limited partners
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Common unitholders public
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$
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$
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Common unitholders LTIP participants
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836
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Common unitholders AIM Midstream Holdings
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82,788
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Subordinated unitholders AIM Midstream Holdings
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General partner
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2,124
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Total partners capital(5)
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$
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85,748
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$
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Total capitalization
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$
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142,118
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$
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(1) |
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The pro forma, as adjusted amount includes $2.2 million of
cash reserved for our non-recurring deferred maintenance capital
expenditures. |
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(2) |
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As of March 29, 2011, we had $56.3 million of
borrowings outstanding under our existing credit facility. This
amount does not include $0.6 million of letters of credit
that were outstanding under our existing credit facility as of
that date. |
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(3) |
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Does not include $0.6 million in currently outstanding
letters of credit that will be issued under our new credit
facility. |
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(4) |
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We expect the initial interest rate under our new credit
facility to be %. |
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(5) |
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Total partners capital does not include $0.1 million
of accumulated other comprehensive income. |
46
DILUTION
Dilution is the amount by which the offering price paid by the
purchasers of common units sold in this offering will exceed the
pro forma net tangible book value per unit after the offering.
On a pro forma basis as of December 31, 2010, after giving
effect to the offering of common units and the application of
the related net proceeds, and assuming the underwriters
option to purchase additional common units is not exercised, our
net tangible book value was
$ million, or
$ per unit. Net tangible book
value excludes $ million of
net intangible assets. Purchasers of common units in this
offering will experience substantial and immediate dilution in
net tangible book value per common unit for financial accounting
purposes, as illustrated in the following table:
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Assumed initial public offering price per common unit
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$
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Net tangible book value per unit before the offering(1)
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$
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Increase in net tangible book value per unit attributable to
purchasers in the offering
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Less: Pro forma net tangible book value per unit after the
offering(2)
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Immediate dilution in tangible net book value per common unit to
purchasers in the offering(3)
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$
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(1) |
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Determined by dividing the number of units
( common
units, subordinated
units
and
general partner units) held by our general partner and its
affiliates, including AIM Midstream Holdings, into the net
tangible book value of our assets. |
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(2) |
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Determined by dividing the total number of units to be
outstanding after this offering
( common
units, subordinated
units
and
general partner units) into our pro forma net tangible book
value, after giving effect to the application of the expected
net proceeds of this offering. |
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(3) |
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If the initial public offering price were to increase or
decrease by $1.00 per common unit, then dilution in net tangible
book value per common unit would equal
$ and
$ , respectively. |
The following table sets forth the number of units that we will
issue and the total consideration contributed to us by our
general partner and its affiliates and by the purchasers of
common units in this offering upon the closing of the
transactions contemplated by this prospectus:
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Units Acquired
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Total Consideration
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Number
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Percent
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Amount
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Percent
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(in thousands)
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General partner and affiliates(1)(2)
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%
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$
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%
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Purchasers in the offering
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Total
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100.0
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%
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$
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100.0
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%
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(1) |
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The units acquired by our general partner and its affiliates,
including AIM Midstream Holdings, consist
of
common
units, subordinated
units
and
general partner units. |
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(2) |
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Assumes the underwriters option to purchase additional
common units is not exercised. |
47
OUR CASH
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash
distribution policy in conjunction with the factors and
assumptions upon which our cash distribution policy is based,
which are included under the heading
Assumptions and Considerations below. In
addition, please read Forward-Looking Statements and
Risk Factors for information regarding statements
that do not relate strictly to historical or current facts and
certain risks inherent in our business. For additional
information regarding our historical operating results, you
should refer to our historical consolidated financial statements
and related notes and our Predecessors historical combined
financial statements and related notes included elsewhere in
this prospectus.
General
Rationale
for Our Cash Distribution Policy
Our partnership agreement requires us to distribute all of our
available cash quarterly. Our cash distribution policy reflects
our belief that our unitholders will be better served if we
distribute rather than retain our available cash. Generally, our
available cash is the sum of our (i) cash on hand at the
end of a quarter after the payment of our expenses and the
establishment of cash reserves and (ii) cash on hand
resulting from working capital borrowings made after the end of
the quarter. Because we are not subject to an entity-level
federal income tax, we have more cash to distribute to our
unitholders than would be the case were we subject to federal
income tax.
Limitations
on Cash Distributions and Our Ability to Change Our Cash
Distribution Policy
There is no guarantee that our unitholders will receive
quarterly distributions from us. We do not have a legal
obligation to pay the minimum quarterly distribution or any
other distribution except as provided in our partnership
agreement. Our cash distribution policy may be changed at any
time and is subject to certain restrictions, including the
following:
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Our general partner will have the authority to establish
reserves for the prudent conduct of our business and for future
cash distributions to our unitholders, and the establishment or
increase of those reserves could result in a reduction in cash
distributions to our unitholders from the levels we currently
anticipate pursuant to our stated cash distribution policy. Any
determination to establish cash reserves made by our general
partner in good faith will be binding on our unitholders. Our
partnership agreement provides that in order for a determination
by our general partner to be considered to have been made in
good faith, our general partner must believe that the
determination is in, or not opposed to, our best interests.
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While our partnership agreement requires us to distribute all of
our available cash, our partnership agreement, including the
provisions requiring us to make cash distributions contained
therein, may be amended. Our partnership agreement generally may
not be amended during the subordination period without the
approval of our public common unitholders other than in certain
limited circumstances where no unitholder approval is required.
However, our partnership agreement can be amended with the
consent of our general partner and the approval of a majority of
the outstanding common units (including common units held by AIM
Midstream Holdings) after the subordination period has ended. At
the closing of this offering, assuming no exercise of the
underwriters option to purchase additional common units,
AIM Midstream Holdings will own our general partner and
approximately % of our outstanding
common units and all of our outstanding subordinated units,
or % of our limited partner
interests.
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Even if our cash distribution policy is not modified or revoked,
the amount of cash that we distribute and the decision to make
any distribution is determined by our general partner, taking
into consideration the terms of our partnership agreement.
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Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets.
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We may lack sufficient cash to pay distributions to our
unitholders for a number of reasons, including as a result of
increases in our operating or general and administrative
expenses, principal and interest payments on our debt, tax
expenses, working capital requirements and anticipated cash
needs.
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Our
Ability to Grow is Dependent on Our Ability to Access External
Expansion Capital
Because we will distribute all of our available cash to our
unitholders, we expect that we will rely primarily upon external
financing sources, including commercial bank borrowings and the
issuance of debt and equity securities, to fund our acquisitions
and expansion capital expenditures. As a result, to the extent
we are unable to finance growth externally, our cash
distribution policy will significantly impair our ability to
grow. In addition, because we intend to distribute all of our
available cash, our growth may not be as fast as that of
businesses that reinvest their available cash to expand ongoing
operations. To the extent we issue additional units in
connection with any acquisitions or expansion capital
expenditures, the payment of distributions on those additional
units may increase the risk that we will be unable to maintain
or increase our per unit distribution level. There are no
limitations in our partnership agreement, and we do not
anticipate there being limitations in our new credit facility,
on our ability to issue additional units, including units
ranking senior to the common units. The incurrence of additional
commercial borrowings or other debt to finance our growth
strategy would result in increased interest expense, which in
turn may impact the available cash that we have to distribute to
our unitholders.
Our
Minimum Quarterly Distribution
Upon the closing of this offering, the board of directors of our
general partner intends to adopt an initial distribution rate of
$ per unit per quarter, or
$ per unit on an annualized basis,
to be paid no later than 45 days after the end of each
fiscal quarter beginning with the quarter
ending ,
2011. This equates to an aggregate cash distribution of
$ million per quarter, or
$ million on an annualized
basis, based on the number of common and subordinated units
anticipated to be outstanding immediately after the closing of
this offering, as well as our 2.0% general partner interest. We
refer to our initial quarterly distribution rate as our minimum
quarterly distribution. We will adjust our first distribution
for the period from the closing of this offering
through ,
2011 based on the length of that period.
To the extent the underwriters exercise their option to purchase
additional common units, we will use the net proceeds from that
exercise to redeem from AIM Midstream Holdings a number of
common units equal to the number of common units issued upon
such exercise, at a price per common unit equal to the proceeds
per common unit before expenses but after deducting underwriting
discounts, commissions and structuring fees. Accordingly, the
exercise of the underwriters option will not affect the
total number of common units or subordinated units outstanding
or the amount of cash needed to pay the minimum quarterly
distribution on all units. Please read Use of
Proceeds.
Initially, our general partner will be entitled to 2.0% of all
distributions that we make prior to our liquidation. In the
future, our general partners initial 2.0% interest in
these distributions may be reduced if we issue additional units
and our general partner does not contribute a proportionate
amount of capital to us to maintain its initial 2.0% general
partner interest.
49
The table below sets forth the number of common, subordinated
and general partner units that we anticipate will be outstanding
immediately following the closing of this offering, assuming the
underwriters do not exercise their option to purchase additional
common units and the aggregate distribution amounts payable on
those units during the year following the closing of this
offering at our minimum quarterly distribution rate of
$ per unit per quarter
($ per unit on an annualized
basis).
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Number of
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Units
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Minimum Quarterly Distributions
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One Quarter
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Annualized
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Public Common Units
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$
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$
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AIM Midstream Holdings Units:
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|
|
|
|
|
|
|
|
|
Common Units
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated Units
|
|
|
|
|
|
|
|
|
|
|
|
|
LTIP Participants Common Units
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner Interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The subordination period generally will end and all of the
subordinated units will convert into an equal number of common
units if we have earned and paid at least
$ on each outstanding common and
subordinated unit and the corresponding distribution on our
general partners 2.0% interest for each of three
consecutive, non-overlapping four-quarter periods ending on or
after September 30, 2014. The subordination period will
automatically terminate and all of the subordinated units will
convert into an equal number of common units if we have earned
and paid at least
$
(150% of the annualized minimum quarterly distribution) on each
outstanding common and subordinated unit and the corresponding
distributions on our general partners 2.0% interest and
incentive distribution rights for any four consecutive quarter
period ending on or after September 30, 2012; provided that
we have paid at least the minimum quarterly distribution from
operating surplus on each outstanding common unit and
subordinated unit for each quarter in that four-quarter period
and the corresponding distribution on our general partners
2.0% interest. Please read the Provisions of Our
Partnership Agreement Relating to Cash Distributions
Subordination Period.
If we do not pay the minimum quarterly distribution on our
common units, our common unitholders will not be entitled to
receive such payments in the future except in some circumstances
during the subordination period. To the extent we have available
cash in any future quarter during the subordination period in
excess of the amount necessary to pay the minimum quarterly
distribution to holders of our common units and the
corresponding distributions on our general partners 2.0%
interest, we will use this excess available cash to pay any
distribution arrearages on the common units related to prior
quarters before any cash distribution is made to holders of the
subordinated units. Please read Provisions of Our
Partnership Agreement Relating to Cash Distributions
Subordination Period.
Our cash distribution policy, as expressed in our partnership
agreement, may not be modified or repealed without amending our
partnership agreement. The actual amount of our cash
distributions for any quarter is subject to fluctuations based
on the amount of cash we generate from our business and the
amount of reserves our general partner establishes in accordance
with our partnership agreement as described above. We will pay
our distributions on or about the 15th of each of February,
May, August and November to holders of record on or about the
1st of each such month. If the distribution date does not
fall on a business day, we will make the distribution on the
business day immediately preceding the indicated distribution
date.
In the sections that follow, we present in detail the basis for
our belief that we will be able to fully fund our annualized
minimum quarterly distribution of
$ per unit for the twelve months
ending June 30, 2012. In those sections, we present two
tables, consisting of:
|
|
|
|
|
Unaudited Historical As Adjusted Available Cash, in
which we present the amount of cash we would have had available
for distribution on a historical as adjusted basis for our
fiscal year ended December 31, 2010, derived from our
audited historical consolidated financial statements that are
included in this prospectus, as adjusted to give effect to the
incremental general and administrative expenses associated with
being a publicly traded partnership; and
|
50
|
|
|
|
|
Statement of Estimated Adjusted EBITDA, which
supports our belief that we will be able to generate the
sufficient estimated adjusted EBITDA to pay the minimum
quarterly distribution on all units for the twelve months ending
June 30, 2012.
|
Unaudited
Historical As Adjusted Available Cash for the Year Ended
December 31, 2010
If we had completed this offering on January 1, 2010, our
historical as adjusted available cash generated for the year
ended December 31, 2010 would have been approximately
$10.0 million. This amount would have been insufficient to
pay the minimum quarterly distribution on all of our common and
subordinated units for such period.
Our unaudited historical as adjusted available cash for the year
ended December 31, 2010 includes $2.3 million of
incremental general and administrative expenses that we expect
to incur as a result of becoming a publicly traded partnership.
This amount is an estimate, and our general partner will
ultimately determine the actual amount of these incremental
general and administrative expenses to be reimbursed by us in
accordance with our partnership agreement. Incremental general
and administrative expenses related to being a publicly traded
partnership include expenses associated with annual and
quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on NASDAQ;
independent auditor fees; legal fees; investor relations
expenses; registrar and transfer agent fees and director and
officer insurance expenses. These expenses are not reflected in
our or our Predecessors historical financial statements.
Our estimate of incremental general and administrative expenses
is based upon currently available information. The adjusted
amounts below do not purport to present our results of
operations had this offering been completed as of the date
indicated. In addition, cash available to pay distributions is
primarily a cash accounting concept, while our historical
consolidated financial statements have been prepared on an
accrual basis. As a result, you should view the amount of
historical as adjusted available cash only as a general
indication of the amount of cash available to pay distributions
that we might have generated had we completed this offering on
January 1, 2010.
51
The following table illustrates, on a historical as adjusted
basis, for the year ended December 31, 2010, the amount of
cash that would have been available for distribution to our
unitholders, assuming that this offering had been completed at
the beginning of such period. Each of the adjustments reflected
or presented below is explained in the footnotes to such
adjustments.
Unaudited
Historical As Adjusted Available Cash
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2010
|
|
|
|
(in thousands,
|
|
|
|
except per unit
|
|
|
|
data)
|
|
|
Net Loss
|
|
$
|
(8,644
|
)
|
Adjustments to reconcile net loss to adjusted EBITDA:
|
|
|
|
|
Add:
|
|
|
|
|
Other non-cash items(1)
|
|
|
1,488
|
|
Depreciation expense
|
|
|
20,013
|
|
Interest expense
|
|
|
5,406
|
|
|
|
|
|
|
Adjusted EBITDA(2)
|
|
$
|
18,263
|
|
Adjustments to reconcile adjusted EBITDA to Historical as
Adjusted Available Cash:
|
|
|
|
|
Less:
|
|
|
|
|
Incremental general and administrative expenses of being a
publicly traded partnership(3)
|
|
|
2,250
|
|
Net cash interest expense
|
|
|
4,523
|
|
Maintenance capital expenditures(4)
|
|
|
1,464
|
|
Expansion capital expenditures(4)
|
|
|
8,804
|
|
Add:
|
|
|
|
|
Capital contributed to fund expansion capital expenditures(5)
|
|
|
8,804
|
|
|
|
|
|
|
Historical as Adjusted Available Cash
|
|
$
|
10,026
|
|
|
|
|
|
|
Cash Distributions
|
|
|
|
|
Distributions per unit(6)
|
|
|
|
|
Distributions to public common unitholders(6)
|
|
|
|
|
Distributions to AIM Midstream Holdings, our general partner and
LTIP participants(6)
|
|
|
|
|
|
|
|
|
|
Total Distributions
|
|
$
|
|
|
|
|
|
|
|
Excess (Shortfall)
|
|
$
|
|
|
|
|
|
|
|
Percent of minimum quarterly distributions payable to common
unitholders
|
|
|
|
%
|
Percent of minimum quarterly distributions payable to
subordinated unitholders
|
|
|
|
%
|
|
|
|
(1) |
|
Includes non-cash compensation expense related to our LTIP and
certain transaction expenses related to our formation, entry
into our new credit facility and acquisition of assets. |
|
(2) |
|
For a definition of adjusted EBITDA and a reconciliation to its
most directly comparable financial measure calculated and
presented in accordance with GAAP, please read Selected
Historical Financial and Operating Data
Non-GAAP Financial Measures. |
|
(3) |
|
Represents estimated cash expenses associated with being a
publicly traded partnership, such as expenses associated with
annual and quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on NASDAQ;
independent auditor fees; legal fees; investor relations
expenses; registrar and transfer agent fees and director and
officer insurance expenses. |
|
(4) |
|
For the year ended December 31, 2010, our capital
expenditures totaled $10.3 million. For this period,
capital expenditures included maintenance capital expenditures
and expansion capital expenditures. We estimate that 14.3% of
our capital expenditures, or $1.5 million, were maintenance
capital expenditures and that 85.7% of our capital expenditures,
or $8.8 million, were expansion capital expenditures.
Although we |
52
|
|
|
|
|
classified our capital expenditures as maintenance capital
expenditures and expansion capital expenditures, we believe
those classifications approximate, but do not necessarily
correspond to, the definitions of estimated maintenance capital
expenditures and expansion capital expenditures under our
partnership agreement. While we expect that in the future
expansion capital expenditures will primarily be funded through
borrowings or the sale of debt or equity securities, we funded
our expansion capital expenditures during the year ended
December 31, 2010 through a capital contribution made to us
by AIM Midstream Holdings and our general partner. |
|
(5) |
|
Consists of an aggregate of $8.8 million in capital
contributed to us by AIM Midstream Holdings and our general
partner in September and November of 2010 that was used to fund
our expansion capital expenditures. |
|
(6) |
|
The table above is based on the following assumptions: (i) the
unit split and the transactions related to the maintenance of
our general partners 2% general partner interest in us
have been consummated, (ii) we have
issued
common units in this offering, and (iii) the
underwriters option to purchase additional common units
has not been exercised. Please read Summary
Recapitalization Transactions and Partnership Structure.
The table reflects the number of common and subordinated units
that we anticipate will be outstanding immediately following the
closing of this offering, as well as our 2.0% general partner
interest, and the aggregate distribution amounts payable on
those units during the year following the closing of this
offering at our minimum quarterly distribution rate of
$ per unit per quarter
($ per unit on an annualized
basis), as well as the corresponding distribution on our 2.0%
general partner interest. |
Estimated
Adjusted EBITDA for the Twelve Months Ending June 30,
2012
Set forth below is a Statement of Estimated Adjusted EBITDA that
supports our belief that we will be able to generate sufficient
cash available for distribution to pay the annualized minimum
quarterly distribution on all of our outstanding units for the
twelve months ending June 30, 2012. The financial forecast
presents, to the best of our knowledge and belief, the expected
results of operations, adjusted EBITDA and cash available for
distribution for the forecast period. We define adjusted EBITDA
as net income, plus interest expense, income tax expense,
depreciation expense, certain non-cash charges such as non-cash
equity compensation, unrealized losses on commodity derivative
contracts and selected charges that are unusual or
non-recurring, less interest income, income tax benefit,
unrealized gains on commodity derivative contracts and selected
gains that are unusual or non-recurring.
For a reconciliation of adjusted EBITDA to its most directly
comparable financial measure calculated and presented in
accordance with GAAP, please read Selected Historical
Financial and Operating Data Non-GAAP Financial
Measures.
Our Statement of Estimated Adjusted EBITDA reflects our
judgment, as of the date of this prospectus, of conditions we
expect to exist and the course of action we expect to take in
order to be able to pay the annualized minimum quarterly
distribution on all of our outstanding units and the
corresponding distributions on our general partners 2.0%
interest for the twelve months ending June 30, 2012. The
assumptions discussed below under Assumptions
and Considerations are those that we believe are
significant to our ability to generate our estimated adjusted
EBITDA. We believe our actual results of operations and cash
flows will be sufficient to generate the minimum adjusted EBITDA
necessary to pay the annualized minimum quarterly distribution
on all of our outstanding common and subordinated units, as well
as the corresponding distribution on our 2.0% general partner
interest, for the twelve months ending June 30, 2012;
however, we can give you no assurance that we will generate this
amount. There will likely be differences between our estimated
adjusted EBITDA and our actual results and those differences
could be material. If we fail to generate our estimated adjusted
EBITDA, we may not be able to pay the annualized minimum
quarterly distribution on all of our outstanding limited partner
units and the corresponding distribution on our 2.0% general
partner interest. In order to fund distributions on all of our
outstanding common, subordinated and general partner units at
our initial rate of $ per unit on
an annualized basis, as well as the corresponding distribution
on our 2.0% general partner interest, for the twelve months
ending June 30, 2012, our adjusted EBITDA for the twelve
months ending June 30, 2012 must be at least
$ million.
We do not, as a matter of course, make public projections as to
future operations, earnings or other results. However,
management has prepared the Statement of Estimated Adjusted
EBITDA and related
53
assumptions and considerations set forth below to substantiate
our belief that we will have sufficient available cash to pay
the annualized minimum quarterly distribution to all our
unitholders for the twelve months ending June 30, 2012.
This forecast is a forward-looking statement and should be read
together with our historical consolidated financial statements
and the accompanying notes, and our Predecessors
historical combined financial statements and the accompanying
notes included elsewhere in this prospectus, as well as
Managements Discussion and Analysis of Financial
Condition and Results of Operations. The accompanying
prospective financial information was not prepared with a view
toward complying with the guidelines established by the American
Institute of Certified Public Accountants with respect to
prospective financial information, but, in the view of our
management, is substantially consistent with those guidelines
and was prepared on a reasonable basis, reflects the best
currently available estimates and judgments, and presents, to
the best of managements knowledge and belief, the
assumptions on which we base our belief that we can generate the
minimum adjusted EBITDA necessary for us to have sufficient cash
available for distribution to pay the aggregate annualized
minimum quarterly distribution on all of our outstanding common
and subordinated units, as well as the corresponding
distribution on our 2.0% general partner interest, for the
twelve months ending June 30, 2012. However, this
information is not fact and should not be relied upon as being
necessarily indicative of future results, and readers of this
prospectus are cautioned not to place undue reliance on the
prospective financial information.
The prospective financial information included in this
prospectus has been prepared by, and is the responsibility of,
our management. PricewaterhouseCoopers LLP has not examined,
compiled or performed any procedures with respect to the
accompanying prospective financial information and, accordingly,
PricewaterhouseCoopers LLP does not express an opinion or any
other form of assurance with respect thereto. The reports of
PricewaterhouseCoopers LLP included in this prospectus relate to
our and our Predecessors historical financial information.
It does not extend to the prospective financial information and
should not be read to do so.
When considering our financial forecast, you should keep in mind
the risk factors and other cautionary statements under
Risk Factors. Any of the risks discussed in this
prospectus, to the extent they are realized, could cause our
actual results of operations to vary significantly from those
that would enable us to generate the minimum adjusted EBITDA
necessary to pay the annualized minimum quarterly distribution
on all of our outstanding common and subordinated units, as well
as the corresponding distribution on our 2.0% general partner
interest, for the twelve months ending June 30, 2012.
We are providing the Statement of Estimated Adjusted EBITDA to
supplement our historical consolidated financial statements and
our Predecessors historical combined financial statements
in support of our belief that we will have sufficient available
cash to pay the annualized minimum quarterly distribution on all
of our outstanding common and subordinated units, as well as the
corresponding distribution on our 2.0% general partner interest,
for the twelve months ending June 30, 2012. Please read
below under Assumptions and
Considerations for further information as to the
assumptions we have made for the financial forecast.
We do not undertake any obligation to release publicly the
results of any future revisions we may make to the financial
forecast or to update this financial forecast to reflect events
or circumstances after the date of this prospectus. Therefore,
you are cautioned not to place undue reliance on this
information.
54
Statement
of Estimated Adjusted EBITDA
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Ending
|
|
|
|
June 30, 2012
|
|
|
|
(in thousands, except
|
|
|
|
per unit data)
|
|
|
Total Revenue
|
|
$
|
295,469
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
251,083
|
|
|
|
|
|
|
Gross margin(1)
|
|
|
44,386
|
|
Operating expenses:
|
|
|
|
|
Direct operating expenses
|
|
|
14,404
|
|
Selling, general and administrative expenses(2)
|
|
|
10,837
|
|
Depreciation expense
|
|
|
20,247
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
45,488
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(1,102
|
)
|
Interest expense
|
|
|
1,526
|
|
Net income (loss)
|
|
$
|
(2,628
|
)
|
|
|
|
|
|
Adjustments to reconcile net income to estimated adjusted EBITDA:
|
|
|
|
|
Add:
|
|
|
|
|
Interest expense
|
|
|
1,526
|
|
Non-cash compensation expense related to our LTIP
|
|
|
1,600
|
|
Depreciation expense
|
|
|
20,247
|
|
|
|
|
|
|
Estimated adjusted EBITDA(1)
|
|
$
|
20,745
|
|
Adjustments to reconcile estimated adjusted EBITDA to estimated
cash available for distribution:
|
|
|
|
|
Less:
|
|
|
|
|
Cash interest expense
|
|
|
979
|
|
Estimated maintenance capital expenditures
|
|
|
3,000
|
|
Non-recurring deferred maintenance capital expenditures during
forecast period
|
|
|
2,200
|
|
Expansion capital expenditures
|
|
|
4,955
|
|
Add:
|
|
|
|
|
Non-cash items(3)
|
|
|
5
|
|
Borrowings to fund expansion capital expenditures
|
|
|
4,955
|
|
Cash from offering proceeds reserved to fund non-recurring
deferred maintenance capital expenditures
|
|
|
2,200
|
|
|
|
|
|
|
Estimated Cash Available for Distribution
|
|
$
|
16,771
|
|
|
|
|
|
|
Estimated Annual Cash Distributions
|
|
|
|
|
Distributions per unit(4)
|
|
|
|
|
Distributions on public common units(4)
|
|
|
|
|
Distributions on common units held by AIM Midstream Holdings(4)
|
|
|
|
|
Distributions on subordinated units held by AIM Midstream
Holdings(4)
|
|
|
|
|
Distributions to our general partner(4)
|
|
|
|
|
Distributions on common units held by LTIP participants(4)
|
|
|
|
|
Total Estimated Annual Distributions
|
|
$
|
|
|
|
|
|
|
|
Excess Cash Available for Distributions
|
|
$
|
|
|
|
|
|
|
|
Minimum Estimated Adjusted EBITDA
|
|
$
|
|
|
|
|
|
|
|
Percent of minimum quarterly distributions payable to common
unitholders
|
|
|
|
%
|
Percent of minimum quarterly distributions payable to
subordinated unitholders
|
|
|
|
%
|
|
|
|
(1) |
|
For definitions of adjusted EBITDA and gross margin, please read
Selected Historical Financial and Operating
Data Non-GAAP Financial Measures. |
55
|
|
|
(2) |
|
Includes $2.3 million of estimated cash expenses associated
with being a publicly traded partnership, such as expenses
associated with annual and quarterly reporting, tax return and
Schedule K-1 preparation and distribution, Sarbanes-Oxley
compliance, expenses associated with listing on NASDAQ,
independent auditor fees, legal fees, investor relations
expenses, registrar and transfer agent fees and director and
officer insurance expenses. |
|
(3) |
|
Represents estimated non-cash costs associated with our
commodity price hedging program and non-cash revenue from our
construction, operating and maintenance agreements. |
|
(4) |
|
The table above is based on the assumption that the
underwriters option to purchase additional common units
has not been exercised and reflects the number of common and
subordinated units that we anticipate will be outstanding
immediately following the closing of this offering, as well as
our 2.0% general partner interest, and the aggregate
distribution amounts payable on those units during the forecast
period at our minimum quarterly distribution rate of
$ per unit on an annualized basis,
as well as the corresponding distribution on our 2.0% general
partner interest. |
56
Assumptions
and Considerations
Set forth below are the material assumptions that we have made
in order to demonstrate our ability to generate our estimated
adjusted EBITDA for the twelve months ending June 30, 2012.
General
Considerations and Sensitivity Analysis
|
|
|
|
|
Revenue and operating expenses are net of intercompany
transactions.
|
|
|
|
We estimate that the price of natural gas, NGLs and condensate
for the twelve months ending June 30, 2012 will average
$4.87 per Mcf, $1.34 per gallon and $2.39 per gallon,
respectively. These estimates for the price of natural gas, NGLs
and condensate were prepared using forward NYMEX natural gas,
OPIS NGL and NYMEX crude oil strip prices, respectively, as of
February 2, 2011. The prices we expect to realize reflect
various discounts or premiums to these NYMEX- and OPIS-based
prices due to transportation, quality and regional price
adjustments as well as the effect of the hedging program
described below.
|
|
|
|
Our estimated revenue, gross margin and adjusted EBITDA include
the effect of our commodity price hedging program under which we
have hedged a portion of the commodity price risk related to our
expected NGL sales with swaps and puts, primarily on individual
NGL components. Our hedging program for the twelve months ending
June 30, 2012 covers approximately 88% of our expected NGL
equity volumes for that period. Please see
Managements Discussion and Analysis of Financial
Condition and Results of Operations Quantitative and
Qualitative Disclosures about Market Risk.
|
|
|
|
System throughput volumes and realized natural gas and NGL
prices are the key factors that will influence whether the
amount of cash available for distribution for the twelve months
ending June 30, 2012 is above or below our forecast. For
example, if all other assumptions are held constant, a 5.0%
increase or decrease in volumes across all of our assets above
or below forecasted levels would result in a $1.5 million
increase or decrease, respectively, in cash available for
distribution. A 5.0% increase or decrease in the price of
natural gas above or below forecasted levels would result in a
$0.2 million decrease or increase, respectively, in cash
available for distribution. A 5.0% decrease in the price of NGLs
below forecasted levels, including the effect of our existing
hedges, would result in a $0.2 million decrease in cash
available for distribution. A 5.0% increase in the price of NGLs
above forecasted levels, including the effect of our existing
hedges, would result in a $0.3 million increase in cash
available for distribution. A decrease in forecasted cash flow
of greater than $ million
would result in our generating less than the minimum cash
required to pay distributions during the forecast period.
|
Total
Revenue
We estimate that we will generate total revenue of
$295.5 million for the twelve months ending June 30,
2012, compared to $211.9 million for the year ended
December 31, 2010. This increase primarily relates to
higher expected volumes and higher NGL and condensate prices on
our systems as described below. Please read
Gross Margin.
Purchases
of Natural Gas, NGLs and Condensate
We estimate that total purchases of natural gas, NGLs and
condensate for the twelve months ending June 30, 2012 will
be $251.1 million, compared to $173.8 million for the
year ended December 31, 2010. The expected increase in
purchases of natural gas, NGLs and condensate for the twelve
months ending June 30, 2012 compared to the year ended
December 31, 2010 is primarily due to expected higher
volumes on our systems and higher NGL and condensate prices, as
further described below. We purchase natural gas and NGLs at
market prices adjusted for transportation, quality and regional
price differentials. As further discussed below,
$165.0 million of our estimated purchases of natural gas
relate to fixed-margin contracts in our two segments.
57
Gathering
and Processing Segment Gross Margin
We estimate that we will generate segment gross margin for our
Gathering and Processing segment of $30.8 million for the
twelve months ending June 30, 2012, as compared to
$24.6 million for the year ended December 31, 2010.
The table below outlines the composition of our estimated and
actual segment gross margin for our Gathering and Processing
segment for the twelve months ending June 30, 2012 and the
year ended December 31, 2010, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Year Ended
|
|
|
Ending
|
|
|
|
December 31, 2010
|
|
|
June 30, 2012
|
|
|
|
($ in millions)
|
|
|
Gathering and Processing Segment Gross Margin:
|
|
|
|
|
|
|
|
|
Fee-based
|
|
$
|
6.5
|
|
|
$
|
9.5
|
|
Fixed-margin
|
|
|
4.9
|
|
|
|
3.9
|
|
Percent-of-proceeds
fee-based
|
|
|
0.9
|
|
|
|
3.2
|
|
Percent-of-proceeds
equity
|
|
|
12.3
|
|
|
|
14.2
|
(1)
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
24.6
|
|
|
$
|
30.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes a net effect of $(1.1) million due to our hedging
program. |
With respect to the fee-based and fixed-margin portions of our
estimated segment gross margin, the increase is primarily
attributable to higher estimated volumes on our systems, as
further described below. The increase in segment gross margin
related to the sale of our equity volumes under our
percent-of-proceeds
arrangements is attributable to increased estimated volumes on
our Gloria and Bazor Ridge systems as well as increased
estimated NGL prices.
Throughput and Processing Volumes. We
estimate that we will transport an average of
252.8 MMcf/d
of natural gas and process an average of
54.4 MMcf/d
of natural gas for the twelve months ending June 30, 2012,
compared to an average of approximately
175.6 MMcf/d
and
42.3 MMcf/d,
respectively, for the year ended December 31, 2010. The
table below outlines the composition of our estimated and actual
volumes for our Gathering and Processing segment for the twelve
months ending June 30, 2012 and the year ended
December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Year Ended
|
|
|
Ending
|
|
|
|
December 31, 2010
|
|
|
June 30, 2012
|
|
|
Throughput Volumes
(MMcf/d):
|
|
|
|
|
|
|
|
|
Fee-based
|
|
|
100.2
|
|
|
|
155.6
|
|
Fixed-margin
|
|
|
63.7
|
|
|
|
51.9
|
|
Percent-of-proceeds
owned plants
|
|
|
9.9
|
|
|
|
17.2
|
|
Incremental interconnect volumes(1)
|
|
|
1.8
|
|
|
|
28.1
|
|
|
|
|
|
|
|
|
|
|
Total throughput volumes
|
|
|
175.6
|
|
|
|
252.8
|
|
|
|
|
|
|
|
|
|
|
Processing Plant Inlet Volumes
(MMcf/d):
|
|
|
|
|
|
|
|
|
Owned plants
|
|
|
9.9
|
|
|
|
17.2
|
|
Elective processing arrangements(2)
|
|
|
32.4
|
|
|
|
37.2
|
|
|
|
|
|
|
|
|
|
|
Total processing inlet volumes
|
|
|
42.3
|
|
|
|
54.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents volumes of natural gas that we purchase at
market-based prices at the Lafitte/TGP interconnect to be
processed under our elective processing arrangements. We do not
receive a gathering or treating fee for such volumes. |
58
|
|
|
(2) |
|
Volumes processed pursuant to our elective processing
arrangements include certain volumes that are also gathered on
our systems pursuant to fixed-margin arrangements. The amount of
volumes gathered and processed in this manner is estimated to be
9.2 MMcf/d
for the twelve months ending June 30, 2012 and was
30.6 MMcf/d
for the year ended December 31, 2010. This decrease was
primarily the result of the conversion of two contracts from
fixed-margin to
fee-based. |
The increased throughput volumes estimated for the twelve months
ending June 30, 2012 are primarily due to increased
estimated shipments on the Gloria and Bazor Ridge systems as a
result of the completion of an interconnect between TGP and our
Lafitte system and the Winchester lateral, respectively, as well
as new production on the Quivira system resulting from wells
that were connected in late 2010. The increased processing
volumes estimated for the twelve months ending June 30,
2012 are primarily due to the full-year impact of the
Lafitte/TGP interconnect, the full-year impact of the Winchester
lateral that relieved pipeline constraints on our Bazor Ridge
system, new production connected to our Bazor Ridge system and
planned growth projects.
Gathering Fees. For the twelve months
ending June 30, 2012, we estimate that we will realize an
average gathering fee of $0.17/Mcf and $0.21/Mcf for our
fee-based and fixed-margin gathering activities, respectively,
and an average fee of $0.50/Mcf related to the fee-based portion
of our
percent-of-proceeds
arrangements at our owned plants (we do not receive a gathering
or treating fee with respect to our incremental interconnect
volumes). This compares to $0.18/Mcf, $0.21/Mcf and $0.26/Mcf,
respectively, for the year ended December 31, 2010. Our
estimated gathering and fixed-margin fees are generally
consistent with those realized on a historical basis. Our
estimated fees under the fee-based portion of our
percent-of-proceeds
arrangements are expected to increase primarily due to an
additional fee we collect on volumes associated with the
Winchester lateral.
Gathering and Processing Product Sales and
Purchases. The table below outlines the
amount and composition of our estimated natural gas, NGL and
condensate sales volumes, revenue and associated product
purchase costs for the twelve months ending June 30, 2012
without giving effect to our hedging program.
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|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Volume
|
|
|
Revenue
|
|
|
Purchase Cost
|
|
|
|
|
|
|
(in millions)
|
|
|
Gathering and Processing Product Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas fixed-margin
(MMcf/d)
|
|
|
51.9
|
|
|
$
|
97.9
|
|
|
$
|
94.0
|
|
Percent-of-proceeds
arrangements at owned plants(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(MMcf/d)
|
|
|
7.1
|
|
|
|
12.4
|
|
|
|
9.7
|
|
NGLs (Mgal/d)
|
|
|
56.4
|
|
|
|
24.5
|
|
|
|
18.7
|
|
Condensate (Mgal/d)
|
|
|
6.5
|
|
|
|
5.5
|
|
|
|
4.3
|
|
Elective processing arrangements(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(MMcf/d, net)
|
|
|
24.5
|
|
|
|
46.4
|
|
|
|
53.4
|
|
NGLs (Mgal/d, net)
|
|
|
26.5
|
|
|
|
12.0
|
|
|
|
|
|
Condensate (Mgal/d, net)
|
|
|
0.7
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
(1) |
|
Represents gross sales volumes, for which we are entitled to
retain a percentage of the sales proceeds and remit back the
remainder to the producer. |
|
(2) |
|
Represents net equity sales volumes pursuant to our elective
processing arrangements. |
For the year ended December 31, 2010, we sold an average of
71.4 MMcf/d
of natural gas at an average realized price of $4.68/Mcf, an
average of 62.2 Mgal/d of NGLs at an average realized price of
$1.08/gal and an average of 5.9 Mgal/d of condensate at an
average realized price of $1.82/gal. Additionally, total
purchases of natural gas, NGLs and condensate in our Gathering
and Processing segment were $133.9 million for the year
ended December 31, 2010.
59
Transmission
Segment Gross Margin
We estimate that we will generate segment gross margin for our
Transmission segment of $13.6 million for the twelve months
ending June 30, 2012, as compared to $13.5 million for
the year ended December 31, 2010. The table below outlines
the composition of our estimated and actual segment gross margin
for our Transmission segment for the twelve months ending
June 30, 2012 and the year ended December 31, 2010,
respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Year Ended
|
|
|
Ending
|
|
|
|
December 31, 2010
|
|
|
June 30, 2012
|
|
|
|
(in millions)
|
|
|
Transmission Segment Gross Margin:
|
|
|
|
|
|
|
|
|
Firm transportation contracts
|
|
$
|
10.8
|
|
|
$
|
11.0
|
|
Interruptible transportation contracts
|
|
|
2.0
|
|
|
|
2.1
|
|
Fixed-margin
|
|
|
0.7
|
|
|
|
0.5
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
13.5
|
|
|
$
|
13.6
|
|
|
|
|
|
|
|
|
|
|
Transportation Volumes. We estimate
that we will transport
351.5 MMcf/d
of natural gas for the twelve months ending June 30, 2012,
compared to an average of approximately
350.2 MMcf/d
for the year ended December 31, 2010. Additionally, we
estimate that we will have
702.7 MMcf/d
of reserved capacity pursuant to firm transportation contracts
during the twelve months ending June 30, 2012, compared to
approximately
677.6 MMcf/d
for the year ended December 31, 2010. We estimate that
transportation volumes will consist of
251.8 MMcf/d
and
61.1 MMcf/d
of volumes pursuant to firm and interruptible transportation
contracts, respectively, and
38.7 MMcf/d
of volumes pursuant to fixed-margin contracts during the twelve
months ending June 30, 2012, compared to
269.3 MMcf/d,
53.5 MMcf/d
and
27.4 MMcf/d,
respectively, for the year ended December 31, 2010.
Transportation Fees. We estimate that
we will realize an aggregate average fee of $0.04/Mcf for
capacity reservation and variable use fees pursuant to firm
transportation contracts, an average fee of $0.09/Mcf for
transportation pursuant to interruptible contracts and an
average fee of $0.04/Mcf for transportation pursuant
fixed-margin activities for the twelve months ending
June 30, 2012, compared to an average of $0.04/Mcf,
$0.10/Mcf and $0.08/Mcf, respectively, for the year ended
December 31, 2010 due primarily to the full-year impact of
a new fixed-margin contract with a lower transportation fee that
we entered into in June 2010.
Transmission Product Sales and
Purchases. We estimate that our fixed-margin
activities will generate $71.5 million of revenue related
to natural gas sales and $71.0 million of expense related
to natural gas product purchases for the forecast period.
Direct
Operating Expense
We estimate that direct operating expense for the twelve months
ending June 30, 2012 will be $14.4 million compared to
$12.2 million for the year ended December 31, 2010.
Direct operating expense is comprised primarily of direct labor
costs, insurance costs, ad valorem and property taxes, repair
and maintenance costs, integrity management costs, utilities,
lost and unaccounted for gas and contract services. The expected
$2.2 million increase is primarily due to $1.5 million
in costs associated with our integrity management program during
the forecast period that were not required to be incurred in
2010 pursuant to the program.
Selling,
General and Administrative Expense
We estimate that SG&A expense for the twelve months ending
June 30, 2012 will be $10.8 million, compared to
$8.9 million for the year ended December 31, 2010.
These amounts include $1.6 million and $1.7 million of
cash and non-cash expenses, respectively, associated with grants
pursuant to our LTIP program. This increase is attributable to
the estimated $2.3 million of incremental SG&A expense
that we expect to incur as a result of being a publicly traded
partnership.
60
Depreciation
Expense
We estimate that depreciation expense for the twelve months
ending June 30, 2012 will be $20.2 million compared to
$20.0 million for the year ended December 31, 2010.
Estimated depreciation expense reflects managements
estimates, which are based on consistent average depreciable
asset lives and depreciation methodologies. The increase in
depreciation expense is primarily attributable to additional
depreciation associated with capital projects that we expect to
be placed in service during the forecast period.
Capital
Expenditures
We estimate that total capital expenditures for the twelve
months ending June 30, 2012 will be $10.2 million
compared to $10.3 million for the year ended
December 31, 2010. Total capital expenditures for the
twelve months ending June 30, 2012 includes
$2.2 million of estimated non-recurring deferred
maintenance capital expenditures for which we have reserved
$2.2 million of net proceeds from this offering. Our
estimate is based on the following assumptions:
|
|
|
|
|
We estimate that maintenance capital expenditures for the twelve
months ending June 30, 2012 will total $5.2 million.
These expenditures include planned maintenance on our systems.
This compares to $1.5 million for the year ended
December 31, 2010. The $5.2 million in estimated
maintenance capital expenditures includes the $3.0 million
in average estimated annual maintenance capital expenditures
that we expect to be required to maintain our assets over the
long-term. In addition, we have included $2.2 million of
estimated maintenance capital expenditures required for deferred
maintenance items on certain of our assets that we identified
based upon a thorough review and evaluation of our assets
following the closing of our November 2009 acquisition from
Enbridge. In order to fund the $2.2 million of incremental
costs, we intend to establish at the closing of this offering a
cash reserve with a portion of the net proceeds from this
offering.
|
|
|
|
We estimate that expansion capital expenditures for the twelve
months ending June 30, 2012 will be $5.0 million.
These expenditures are comprised of four expansion capital
projects that we believe we will pursue during the forecast
period. We expect that these projects will add over
$2.0 million in gross margin, which is reflected in this
forecast. Our expansion capital expenditures were
$8.8 million for the year ended December 31, 2010. The
capital projects that we expect to undertake in our forecast
period include:
|
|
|
|
|
|
a cylinder upgrade on the existing Gloria compressor that we
expect will increase throughput capacity on the Gloria system by
approximately
7 MMcf/d
and that we expect to be completed in the third quarter of 2011
at a cost of approximately $0.2 million;
|
|
|
|
the construction of an interconnect and the installation of a
skid-mounted treating facility along Midla, which is expected to
cost approximately $0.3 million and be completed in the
third quarter of 2011;
|
|
|
|
the construction of a new skid-mounted processing plant on the
Alabama Processing system in order to serve additional new
production at a cost of approximately $1.3 million in the
third quarter of 2011; and
|
|
|
|
the addition of field compression capacity to the Bazor Ridge
gathering system, which would provide us with the opportunity to
treat new natural gas production, at an expected cost of
approximately $3.2 million that we expect to complete in
the first quarter of 2012.
|
Financing
We forecast interest expense of approximately $1.5 million
for the twelve months ending June 30, 2012, compared to
approximately $5.4 million for the year ended
December 31, 2010. Our interest expense for the forecast
period is based on the following assumptions:
|
|
|
|
|
We will repay in full the outstanding borrowings of
$ million under our existing
credit facility with a portion of the proceeds from this
offering.
|
|
|
|
We will have debt outstanding as of the closing of this offering
of $21.5 million.
|
61
|
|
|
|
|
We will have average outstanding borrowings of
$25.7 million, including borrowings to finance our
estimated expansion capital expenditures of $5.0 million,
with an assumed weighted average interest rate of 3.5% under our
new credit facility, which is lower than the weighted average
interest rate of 7.5% for the year ended December 31, 2010
under our existing credit facility.
|
|
|
|
We will maintain a low cash balance and therefore do not
forecast any interest income.
|
Regulatory,
Industry and Economic Factors
Our forecast for the twelve months ending June 30, 2012 is
based on the following significant assumptions related to
regulatory, industry and economic factors:
|
|
|
|
|
There will not be any new federal, state or local regulation of
the midstream energy sector, or any new interpretation of
existing regulations, that will be materially adverse to our
business.
|
|
|
|
There will not be any major adverse change in the midstream
energy sector, commodity prices, capital or insurance markets or
general economic conditions.
|
62
PROVISIONS
OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH
DISTRIBUTIONS
Set forth below is a summary of the significant provisions of
our partnership agreement that relate to cash distributions.
Distributions
of Available Cash
General
Our partnership agreement requires that, within 45 days
after the end of each quarter, beginning with the quarter ending
December 31, 2009, we distribute all of our available cash
to unitholders of record on the applicable record date. We will
adjust the minimum quarterly distribution for the period from
the closing of the offering through September 30, 2011
based on the actual length of the period.
Definition
of Available Cash
Available cash generally means, for any quarter, all cash on
hand at the end of that quarter:
|
|
|
|
|
less the amount of cash reserves established by our general
partner at the date of determination of available cash for that
quarter to:
|
|
|
|
|
|
provide for the proper conduct of our business (including
reserves for our future capital expenditures, anticipated future
credit needs and refunds of collected rates reasonably likely to
be refunded as a result of a settlement or hearing related to
FERC rate proceedings or rate proceedings under applicable law
subsequent to that quarter);
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; and
|
|
|
|
provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters
(provided that our general partner may not establish cash
reserves for common and subordinated units unless it determines
that the establishment of reserves will not prevent us from
distributing the minimum quarterly distribution on all common
units and any cumulative arrearages on such common units for the
current quarter and the next four quarters);
|
|
|
|
|
|
plus, if our general partner so determines, all or any portion
of the cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made subsequent to the end of such quarter.
|
The purpose and effect of the last bullet point above is to
allow our general partner, if it so decides, to use cash from
working capital borrowings made after the end of the quarter but
on or before the date of determination of available cash for
that quarter to pay distributions to unitholders. Under our
partnership agreement, working capital borrowings are generally
borrowings that are made under a credit facility, commercial
paper facility or similar financing arrangement, and in all
cases are used solely for working capital purposes or to pay
distributions to partners, and with the intent of the borrower
to repay such borrowings within 12 months with funds other
than from additional working capital borrowings. The proceeds of
working capital borrowings increase operating surplus and
repayments of working capital borrowings are generally operating
expenditures (as described below) and thus reduce operating
surplus when repayments are made. However, if working capital
borrowings, which increase operating surplus, are not repaid
during the
12-month
period following the borrowing, they will be deemed repaid at
the end of such period, thus decreasing operating surplus at
such time. When such working capital borrowings are in fact
repaid, they will not be treated as a further reduction in
operating surplus because operating surplus will have been
previously reduced by the deemed repayment.
Intent
to Distribute the Minimum Quarterly Distribution
We intend to make a minimum quarterly distribution to the
holders of our common units and subordinated units of
$ per unit, or
$ on an annualized basis, to the
extent we have sufficient cash from our operations after the
establishment of cash reserves and the payment of costs and
expenses, including
63
reimbursements of expenses to our general partner. However,
there is no guarantee that we will pay the minimum quarterly
distribution on our units in any quarter. Even if our cash
distribution policy is not modified or revoked, the amount of
distributions paid under our policy and the decision to make any
distribution is determined by our general partner, taking into
consideration the terms of our partnership agreement. Please
read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Liquidity and Capital Resources Our Credit
Facility for a discussion of the restrictions to be
included in our new credit facility that may restrict our
ability to make distributions.
Operating
Surplus and Capital Surplus
General
All cash distributed to unitholders will be characterized as
either being paid from operating surplus or
capital surplus. We treat distributions of available
cash from operating surplus differently than distributions of
available cash from capital surplus.
Operating
Surplus
We define operating surplus as:
|
|
|
|
|
$ million (as described
below); plus
|
|
|
|
all of our cash receipts after the closing of this offering,
excluding cash from interim capital transactions (as defined
below); plus
|
|
|
|
working capital borrowings made after the end of a quarter but
on or before the date of determination of operating surplus for
that quarter; plus
|
|
|
|
cash distributions paid on equity issued to finance all or a
portion of the construction, acquisition, development or
improvement of a capital improvement or replacement of a capital
asset (such as equipment or facilities) in respect of the period
beginning on the date that we enter into a binding obligation to
commence the construction, acquisition, development or
improvement of a capital improvement or replacement of a capital
asset and ending on the earlier to occur of the date the capital
improvement or capital asset commences commercial service and
the date that it is abandoned or disposed of; plus
|
|
|
|
cash distributions paid on equity issued to pay the
construction-period interest on debt incurred, or to pay
construction-period distributions on equity issued, to finance
the capital improvements or capital assets referred to above;
less
|
|
|
|
all of our operating expenditures (as defined below) after the
closing of this offering; less
|
|
|
|
the amount of cash reserves established by our general partner
to provide funds for future operating expenditures; less
|
|
|
|
all working capital borrowings not repaid within 12 months
after having been incurred, or repaid within such
12-month
period with the proceeds of additional working capital
borrowings; less
|
|
|
|
any cash loss realized on disposition of an investment capital
expenditure.
|
As described above, operating surplus does not reflect actual
cash on hand that is available for distribution to our
unitholders and is not limited to cash generated by operations.
For example, it includes a provision that will enable us, if we
choose, to distribute as operating surplus up to
$ million of cash we receive
in the future from non-operating sources such as asset sales,
issuances of securities and long-term borrowings that would
otherwise be distributed as capital surplus.
We define interim capital transactions as (i) borrowings,
refinancings or refundings of indebtedness (other than working
capital borrowings and items purchased on open account in the
ordinary course of business) and sales of debt securities,
(ii) sales of equity securities, (iii) sales or other
dispositions of assets, other than sales or other dispositions
of inventory, accounts receivable and other assets in the
ordinary course of business and
64
sales or other dispositions of assets as part of ordinary course
asset retirements or replacements, (iv) the termination of
commodity hedge contracts or interest rate hedge contracts prior
to the termination date specified therein (provided that cash
receipts from any such termination will be included in operating
surplus in equal quarterly installments over the remaining
scheduled life of the contract), (v) capital contributions
received and (vi) corporate reorganizations or
restructurings.
We define operating expenditures as all of our cash
expenditures, including, but not limited to, taxes,
reimbursements of expenses to our general partner, interest
payments, payments made in the ordinary course of business under
interest rate hedge contracts and commodity hedge contracts
(provided that payments made in connection with the termination
of any interest rate hedge contract or commodity hedge contract
prior to the expiration of its stipulated settlement or
termination date will be included in operating expenditures in
equal quarterly installments over the remaining scheduled life
of such interest rate hedge contract or commodity hedge
contract), estimated maintenance capital expenditures (as
discussed in further detail below), director and officer
compensation, repayment of working capital borrowings and
non-pro rata repurchases of our units; provided,
however, that operating expenditures will not include:
|
|
|
|
|
repayments of working capital borrowings where such borrowings
have previously been deemed to have been repaid (as described
above);
|
|
|
|
payments (including prepayments and prepayment penalties) of
principal of and premium on indebtedness other than working
capital borrowings;
|
|
|
|
expansion capital expenditures;
|
|
|
|
actual maintenance capital expenditures;
|
|
|
|
investment capital expenditures;
|
|
|
|
payment of transaction expenses (including, but not limited to,
taxes) relating to interim capital transactions;
|
|
|
|
distributions to our partners; or
|
|
|
|
non-pro rata purchases of any class of our units made with the
proceeds of an interim capital transaction.
|
Capital
Surplus
Capital surplus is defined in our partnership agreement as any
distribution of available cash in excess of our cumulative
operating surplus. Accordingly, except as described above,
capital surplus would generally be generated by:
|
|
|
|
|
borrowings other than working capital borrowings;
|
|
|
|
sales of our equity and debt securities; and
|
|
|
|
sales or other dispositions of assets, other than inventory,
accounts receivable and other assets sold in the ordinary course
of business or as part of ordinary course retirement or
replacement of assets.
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Characterization
of Cash Distributions
Our partnership agreement requires that we treat all available
cash distributed as coming from operating surplus until the sum
of all available cash distributed since the closing of this
offering equals the operating surplus from the closing of this
offering through the end of the quarter immediately preceding
that distribution. Our partnership agreement requires that we
treat any amount distributed in excess of operating surplus,
regardless of its source, as capital surplus. We do not
anticipate that we will make any distributions from capital
surplus.
65
Capital
Expenditures
Maintenance capital expenditures are cash expenditures
(including expenditures for the addition or improvement to, or
the replacement of, our capital assets or for the acquisition of
existing, or the construction or development of new, capital
assets) made to maintain our long-term operating income or
operating capacity. We expect that a primary component of
maintenance capital expenditures will include expenditures for
routine equipment and pipeline maintenance or replacement due to
obsolescence. Maintenance capital expenditures will also include
interest (and related fees) on debt incurred and distributions
on equity issued (including incremental distributions on
incentive distribution rights) to finance all or any portion of
the construction or development of a replacement asset that is
paid in respect of the period that begins when we enter into a
binding obligation to commence constructing or developing a
replacement asset and ending on the earlier to occur of the date
that any such replacement asset commences commercial service and
the date that it is abandoned or disposed of.
Because our maintenance capital expenditures can be irregular,
the amount of our actual maintenance capital expenditures may
differ substantially from period to period, which could cause
similar fluctuations in the amounts of operating surplus,
adjusted operating surplus and cash available for distribution
to our unitholders if we subtracted actual maintenance capital
expenditures from operating surplus.
Our partnership agreement requires that an estimate of the
average quarterly maintenance capital expenditures be subtracted
from operating surplus each quarter as opposed to the actual
amounts spent. The amount of estimated maintenance capital
expenditures deducted from operating surplus for those periods
will be determined by the board of directors of our general
partner at least once a year, subject to approval by the
Conflicts Committee. The estimate will be made annually and
whenever an event occurs that is likely to result in a material
adjustment to the amount of our maintenance capital expenditures
on a long-term basis. For purposes of calculating operating
surplus, any adjustment to this estimate will be prospective
only. For a discussion of the amounts we have allocated toward
estimated maintenance capital expenditures and other maintenance
capital expenditures for the forecast period ending
June 30, 2012, please read Our Cash Distribution
Policy and Restrictions on Distributions.
The use of estimated maintenance capital expenditures in
calculating operating surplus will have the following effects:
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it will reduce the risk that maintenance capital expenditures in
any one quarter will be large enough to render operating surplus
less than the minimum quarterly distribution to be paid on all
the units for the quarter and subsequent quarters;
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it will increase our ability to distribute as operating surplus
cash we receive from non-operating sources;
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it will be more difficult for us to raise our distribution above
the minimum quarterly distribution and pay incentive
distributions on the incentive distribution rights held by our
general partner; and
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it will reduce the likelihood that a large actual maintenance
capital expenditure in a period will prevent our general
partners affiliates from being able to convert some or all
of their subordinated units into common units since the effect
of an estimate is to spread the expected expense over several
periods, thereby mitigating the effect of the actual payment of
the expenditure on any single period.
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Estimated maintenance capital expenditures reduce operating
surplus, but expansion capital expenditures, investment capital
expenditures and actual maintenance capital expenditures do not.
Expansion capital expenditures are cash expenditures incurred
for acquisitions or capital improvements that we expect will
increase our operating income or operating capacity over the
long term. Expansion capital expenditures include interest
payments (and related fees) on debt incurred and distributions
on equity issued to finance the construction, acquisition or
development of an improvement to our capital assets and paid in
respect of the period beginning on the date that we enter into a
binding obligation to commence construction, acquisition or
development of the capital improvement and ending on the earlier
to occur of the date that such capital improvement commences
commercial service and the date that such capital improvement is
abandoned or
66
disposed of. Examples of expansion capital expenditures include
the acquisition of equipment, or the construction, development
or acquisition of additional pipeline or treating capacity or
new compression capacity.
Capital expenditures that are made in part for expansion capital
purposes and in part for other purposes will be allocated
between expansion capital expenditures and expenditures for
other purposes by our general partner (with the concurrence of
the Conflicts Committee).
Investment capital expenditures are those capital expenditures
that are neither maintenance capital expenditures nor expansion
capital expenditures. Investment capital expenditures largely
will consist of capital expenditures made for investment
purposes. Examples of investment capital expenditures include
traditional capital expenditures for investment purposes, such
as purchases of securities, as well as other capital
expenditures that might be made in lieu of such traditional
investment capital expenditures, such as the acquisition of a
capital asset for investment purposes or development of
facilities that are in excess of the maintenance of our existing
operating capacity or operating income, but that are not
expected to expand, for more than the short term, our operating
capacity or operating income.
Subordination
Period
General
Our partnership agreement provides that, during the
subordination period (which we define below), the common units
will have the right to receive distributions of available cash
from operating surplus each quarter in an amount equal to
$ per common unit, which amount is
defined in our partnership agreement as the minimum quarterly
distribution, plus any arrearages in the payment of the minimum
quarterly distribution on the common units from prior quarters,
before any distributions of available cash from operating
surplus may be made on the subordinated units. These units are
deemed subordinated because for a period of time,
referred to as the subordination period, the subordinated units
will not be entitled to receive any distributions until the
common units have received the minimum quarterly distribution
plus any arrearages from prior quarters. Furthermore, no
arrearages will be paid on the subordinated units. The practical
effect of the subordinated units is to increase the likelihood
that during the subordination period there will be available
cash to be distributed on the common units.
Subordination
Period
Except as described below, the subordination period will begin
on the closing date of this offering and will extend until the
first business day of any quarter beginning after
September 30, 2014, that each of the following tests are
met:
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distributions of available cash from operating surplus on each
of the outstanding common and subordinated units equaled or
exceeded $ (the annualized minimum
quarterly distribution) for each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that
date;
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the adjusted operating surplus (as defined below) generated
during each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date equaled or
exceeded (i) the sum of
$ (the annualized minimum
quarterly distribution) on all of the outstanding common and
subordinated units during those periods on a fully diluted basis
and (ii) the corresponding distribution on our 2.0% general
partner interest; and
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there are no arrearages in payment of the minimum quarterly
distribution on the common units.
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For purposes of determining whether sufficient adjusted
operating surplus has been generated under the above conversion
test, the Conflicts Committee may adjust operating surplus
upwards or downwards if it determines in good faith that the
amount of estimated maintenance capital expenditures used in the
determination of adjusted operating surplus was materially
incorrect, based on the circumstances prevailing at the time of
the original estimate, for any one or more of the preceding two
four-quarter periods.
67
Early
Termination of Subordination Period
Notwithstanding the foregoing, the subordination period will
automatically terminate on the first business day of any quarter
beginning after September 30, 2012, that each of the
following tests are met:
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distributions of available cash from operating surplus on each
of the outstanding common units and subordinated units equaled
or exceeded $ (150.0% of the
annualized minimum quarterly distribution) for the four-quarter
period immediately preceding that date;
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the adjusted operating surplus (as defined below) generated
during the four-quarter period immediately preceding that date
equaled or exceeded the sum of
(i) $ (150.0% of the
annualized minimum quarterly distribution) on all of the
outstanding common units and subordinated units during that
period on a fully diluted basis and (ii) the distributions
made on our 2.0% general partner interest and the incentive
distribution rights;
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distributions of available cash from operating surplus on each
of the outstanding common units and subordinated units equaled
or exceeded the minimum quarterly distribution of $ per unit
and we made the corresponding distribution on our 2.0% general
partner interest for each quarter during the four-quarter period
immediately preceding that date; and
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there are no arrearages in payment of the minimum quarterly
distributions on the common units.
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Expiration
of the Subordination Period
When the subordination period ends, each outstanding
subordinated unit will convert into one common unit and will
thereafter participate pro rata with the other common units in
distributions of available cash. In addition, if the unitholders
remove our general partner other than for cause and no units
held by our general partner and its affiliates are voted in
favor of such removal:
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the subordination period will end and each subordinated unit
will immediately and automatically convert into one common unit;
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests.
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Adjusted
Operating Surplus
Adjusted operating surplus is intended to reflect the cash
generated from operations during a particular period and
therefore excludes net drawdowns of reserves of cash established
in prior periods. Adjusted operating surplus for a period
consists of:
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operating surplus generated with respect to that period
(excluding any amounts attributable to the item described in the
first bullet point under the caption Operating
Surplus and Capital Surplus Operating Surplus
above); less
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any net increase in working capital borrowings with respect to
that period; less
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any net decrease in cash reserves for operating expenditures
with respect to that period not relating to an operating
expenditure made with respect to that period; plus
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any net decrease in working capital borrowings with respect to
that period; plus
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any net decrease made in subsequent periods to cash reserves for
operating expenditures initially established with respect to
that period to the extent such decrease results in a reduction
in adjusted operating surplus in subsequent periods; plus
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any net increase in cash reserves for operating expenditures
with respect to that period required by any debt instrument for
the repayment of principal, interest or premium.
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68
Distributions
of Available Cash from Operating Surplus during the
Subordination Period
We will make distributions of available cash from operating
surplus for any quarter during the subordination period in the
following manner:
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first, 98.0% to the common unitholders, pro rata, and
2.0% to our general partner, until we distribute for each
outstanding common unit an amount equal to the minimum quarterly
distribution for that quarter;
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second, 98.0% to the common unitholders, pro rata, and
2.0% to our general partner, until we distribute for each
outstanding common unit an amount equal to any arrearages in
payment of the minimum quarterly distribution on the common
units for any prior quarters during the subordination period;
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third, 98.0% to the subordinated unitholders, pro rata,
and 2.0% to our general partner, until we distribute for each
outstanding subordinated unit an amount equal to the minimum
quarterly distribution for that quarter; and
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thereafter, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
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The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
Distributions
of Available Cash from Operating Surplus after the Subordination
Period
We will make distributions of available cash from operating
surplus for any quarter after the subordination period in the
following manner:
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first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until we distribute for each outstanding
unit an amount equal to the minimum quarterly distribution for
that quarter; and
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thereafter, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
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The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
General
Partner Interest and Incentive Distribution Rights
Our partnership agreement provides that our general partner
initially will be entitled to 2.0% of all distributions that we
make prior to our liquidation. Our general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us in order to maintain its 2.0% general
partner interest if we issue additional units. Our general
partners 2.0% interest, and the percentage of our cash
distributions to which it is entitled from such 2.0% interest,
will be proportionately reduced if we issue additional units in
the future and our general partner does not contribute a
proportionate amount of capital to us in order to maintain its
2.0% general partner interest. Our partnership agreement does
not require that our general partner fund its capital
contribution with cash. It may instead fund its capital
contribution by the contribution to us of common units or other
property.
Incentive distribution rights represent the right to receive an
increasing percentage (13.0%, 23.0% and 48.0%) of quarterly
distributions of available cash from operating surplus after the
minimum quarterly distribution and the target distribution
levels have been achieved. Our general partner currently holds
the incentive distribution rights, but may transfer these rights
separately from its general partner interest, subject to
restrictions in our partnership agreement.
The following discussion assumes that our general partner
maintains its 2.0% general partner interest, that there are no
arrearages on common units and that our general partner
continues to own the incentive distribution rights.
If for any quarter:
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we have distributed available cash from operating surplus to the
common and subordinated unitholders in an amount equal to the
minimum quarterly distribution; and
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69
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we have distributed available cash from operating surplus on
outstanding common units in an amount necessary to eliminate any
cumulative arrearages in payment of the minimum quarterly
distribution;
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then, we will distribute any additional available cash from
operating surplus for that quarter among the unitholders and our
general partner in the following manner:
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first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives a total of
$ per unit for that quarter (the
first target distribution);
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second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives a total of
$ per unit for that quarter (the
second target distribution);
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third, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives a total of
$ per unit for that quarter (the
third target distribution); and
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thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
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Percentage
Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of
available cash from operating surplus between the unitholders
and our general partner based on the specified target
distribution levels. The amounts set forth under Marginal
Percentage Interest in Distributions are the percentage
interests of our general partner and the unitholders in any
available cash from operating surplus we distribute up to and
including the corresponding amount
in the column Total Quarterly Distribution Per Unit Target
Amount. The percentage interests shown for our unitholders
and our general partner for the minimum quarterly distribution
are also applicable to quarterly distribution amounts that are
less than the minimum quarterly distribution. The percentage
interests set forth below for our general partner include its
2.0% general partner interest and assume that our general
partner has contributed any additional capital necessary to
maintain its 2.0% general partner interest, our general partner
has not transferred its incentive distribution rights and that
there are no arrearages on common units.
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Marginal Percentage Interest
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in Distributions
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Total Quarterly Distribution
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General
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per Unit Target Amount
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Unitholders
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Partner
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Minimum Quarterly Distribution
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$
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98.0
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%
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2.0
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%
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First Target Distribution
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up to $
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98.0
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%
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2.0
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%
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Second Target Distribution
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above $
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up to $
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85.0
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%
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15.0
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%
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Third Target Distribution
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above $
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up to $
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75.0
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%
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25.0
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%
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Thereafter
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above $
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50.0
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%
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50.0
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%
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General
Partners Right to Reset Incentive Distribution
Levels
Our general partner, as the initial holder of our incentive
distribution rights, has the right under our partnership
agreement to elect to relinquish the right to receive incentive
distribution payments based on the initial target distribution
levels and to reset, at higher levels, the minimum quarterly
distribution amount and target distribution levels upon which
the incentive distribution payments to our general partner would
be set. If our general partner transfers all or a portion of our
incentive distribution rights in the future, then the holder or
holders of a majority of our incentive distribution rights will
be entitled to exercise this right. The following discussion
assumes that our general partner holds all of the incentive
distribution rights at the time that a reset election is made.
Our general partners right to reset the minimum quarterly
distribution amount and the target distribution levels upon
which the incentive distributions payable to our general partner
are based may be exercised, without approval of our unitholders
or the Conflicts Committee, at any time when there are no
subordinated units outstanding and we have made cash
distributions to the holders of the incentive distribution
rights at the highest level of incentive distribution for each
of the four consecutive fiscal quarters immediately preceding
such time. If our general partner and its affiliates are not the
holders of a majority of the incentive distribution rights at
the time an election is made to reset the minimum quarterly
distribution amount and the
70
target distribution levels, then the proposed reset will be
subject to the prior written concurrence of the general partner
that the conditions described above have been satisfied. The
reset minimum quarterly distribution amount and target
distribution levels will be higher than the minimum quarterly
distribution amount and the target distribution levels prior to
the reset such that our general partner will not receive any
incentive distributions under the reset target distribution
levels until cash distributions per unit following this event
increase as described below. We anticipate that our general
partner would exercise this reset right in order to facilitate
acquisitions or internal growth projects that would otherwise
not be sufficiently accretive to cash distributions per common
unit, taking into account the existing levels of incentive
distribution payments being made to our general partner.
In connection with the resetting of the minimum quarterly
distribution amount and the target distribution levels and the
corresponding relinquishment by our general partner of incentive
distribution payments based on the target distributions prior to
the reset, our general partner will be entitled to receive a
number of newly issued common units and general partner units
based on a predetermined formula described below that takes into
account the cash parity value of the average cash
distributions related to the incentive distribution rights
received by our general partner for the two quarters immediately
preceding the reset event as compared to the average cash
distributions per common unit during that two-quarter period.
Our general partner will be issued the number of general partner
units necessary to maintain our general partners interest
in us immediately prior to the reset election.
The number of common units that our general partner would be
entitled to receive from us in connection with a resetting of
the minimum quarterly distribution amount and the target
distribution levels then in effect would be equal to the
quotient determined by dividing (x) the average aggregate
amount of cash distributions received by our general partner in
respect of its incentive distribution rights during the two
consecutive fiscal quarters ended immediately prior to the date
of such reset election by (y) the average of the amount of
cash distributed per common unit during each of these two
quarters.
Following a reset election, the minimum quarterly distribution
amount will be reset to an amount equal to the average cash
distribution amount per unit for the two fiscal quarters
immediately preceding the reset election (which amount we refer
to as the reset minimum quarterly distribution) and
the target distribution levels will be reset to be
correspondingly higher such that we would distribute all of our
available cash from operating surplus for each quarter
thereafter as follows:
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first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives an amount
equal to 115.0% of the reset minimum quarterly distribution for
that quarter;
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second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives an amount
per unit equal to 125.0% of the reset minimum quarterly
distribution for the quarter;
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third, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives an amount
per unit equal to 150.0% of the reset minimum quarterly
distribution for the quarter; and
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thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
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71
The following table illustrates the percentage allocation of
available cash from operating surplus between the unitholders
and our general partner at various cash distribution levels
(i) pursuant to the cash distribution provisions of our
partnership agreement in effect at the closing of this offering,
as well as (ii) following a hypothetical reset of the
minimum quarterly distribution and target distribution levels
based on the assumption that the average quarterly cash
distribution amount per common unit during the two fiscal
quarters immediately preceding the reset election was
$ .
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Marginal Percentage
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Interest in Distributions
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2.0%
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Quarterly
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General
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Incentive
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Distributions
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Quarterly Distribution
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Partner
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Distribution
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per Unit Following
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per Unit Prior to Reset
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Unitholders
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Interest
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Rights
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Hypothetical Reset
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Minimum Quarterly Distribution
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$
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98.0
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%
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2.0
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%
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First Target Distribution
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up to $
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98.0
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%
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2.0
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%
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Second Target Distribution
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above $
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up to $
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85.0
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%
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2.0
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%
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13.0
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%
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Third Target Distribution
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above $
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up to $
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75.0
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%
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2.0
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%
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23.0
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%
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Thereafter
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above $
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50.0
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%
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2.0
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%
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48.0
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%
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(1) |
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This amount is 115.0% of the hypothetical reset minimum
quarterly distribution. |
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(2) |
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This amount is 125.0% of the hypothetical reset minimum
quarterly distribution. |
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(3) |
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This amount is 150.0% of the hypothetical reset minimum
quarterly distribution. |
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
incentive distribution rights, based on an average of the
amounts distributed each quarter for the two quarters
immediately prior to the reset. The table assumes that
immediately prior to the reset there would
be
common units outstanding, our general partner has maintained its
2.0% general partner interest and the average distribution to
each common unit would be $ for
the two quarters prior to the reset.
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Cash
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Cash Distribution to General Partner Prior to Reset
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Distributions to
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2.0%
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Quarterly
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Common
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General
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Incentive
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Distribution per
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Unitholders
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Partner
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Distribution
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Total
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Unit Prior to Reset
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Prior to Reset
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Interest
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Rights
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Total
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|
Distributions
|
|
|
Minimum Quarterly Distribution
|
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|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
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|
First Target Distribution
|
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|
up to $
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|
Second Target Distribution
|
|
above $
|
|
|
|
up to $
|
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|
|
|
|
|
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|
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|
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|
|
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Third Target Distribution
|
|
above $
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|
up to $
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Thereafter
|
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|
above $
|
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|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
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|
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|
72
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
incentive distribution rights, with respect to the quarter in
which the reset occurs. The table reflects that, as a result of
the reset, there would be common units outstanding, our general
partners 2.0% interest has been maintained, and the
average distribution to each common unit would be
$ . The number of common units to
be issued to our general partner upon the reset was calculated
by dividing (i) the average of the amounts received by our
general partner in respect of its incentive distribution rights
for the two quarters prior to the reset as shown in the table
above, or $ , by (ii) the
average available cash distributed on each common unit for the
two quarters prior to the reset as shown in the table above, or
$ .
|
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Cash Distribution to General Partner
|
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|
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Cash
|
|
|
After Reset
|
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|
|
|
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|
Distributions to
|
|
|
2.0%
|
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|
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|
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|
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|
|
Quarterly
|
|
|
Common
|
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|
General
|
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|
Incentive
|
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|
|
|
|
|
|
|
|
Distribution per
|
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|
Unitholders
|
|
|
Partner
|
|
|
Distribution
|
|
|
|
|
|
Total
|
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|
Unit After Reset
|
|
|
After Reset
|
|
|
Interest
|
|
|
Rights
|
|
|
Total
|
|
|
Distributions
|
|
|
Minimum Quarterly Distribution
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
First Target Distribution
|
|
|
|
|
|
up to $
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
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|
Second Target Distribution
|
|
above $
|
|
|
|
up to $
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Target Distribution
|
|
above $
|
|
|
|
up to $
|
|
|
|
|
|
|
|
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Thereafter
|
|
|
|
|
|
above $
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
|
|
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|
Our general partner will be entitled to cause the minimum
quarterly distribution amount and the target distribution levels
to be reset on more than one occasion, provided that it may not
make a reset election except at a time when it has received
incentive distributions for the immediately preceding four
consecutive fiscal quarters based on the highest level of
incentive distributions that it is entitled to receive under our
partnership agreement.
Distributions
from Capital Surplus
How
Distributions from Capital Surplus Will Be Made
We will make distributions of available cash from capital
surplus, if any, in the following manner:
|
|
|
|
|
first, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until we distribute for each common unit
that was issued in this offering, an amount of available cash
from capital surplus equal to the initial public offering price
in this offering;
|
|
|
|
second, 98.0% to the common unitholders, pro rata, and
2.0% to our general partner, until we distribute for each
outstanding common unit, an amount of available cash from
capital surplus equal to any unpaid arrearages in payment of the
minimum quarterly distribution on the common units; and
|
|
|
|
thereafter, as if they were from operating surplus.
|
The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
Effect
of a Distribution from Capital Surplus
Our partnership agreement treats a distribution of capital
surplus as the repayment of the initial unit price from this
initial public offering, which is a return of capital. The
initial public offering price less any distributions of capital
surplus per unit is referred to as the unrecovered initial
unit price. Each time a distribution of capital surplus is
made, the minimum quarterly distribution and the target
distribution levels will be reduced in the same proportion as
the corresponding reduction in the unrecovered initial unit
price. Because distributions of capital surplus will reduce the
minimum quarterly distribution after any of these distributions
are made, it may be easier for our general partner to receive
incentive distributions and for the subordinated units to
convert into common units. However, any distribution of capital
surplus before the unrecovered initial unit price is reduced to
zero cannot be applied to the payment of the minimum quarterly
distribution or any arrearages.
73
Once we distribute capital surplus on a unit issued in this
offering in an amount equal to the initial unit price, we will
reduce the minimum quarterly distribution and the target
distribution levels to zero. We will then make all future
distributions from operating surplus, with 50.0% being paid to
the unitholders, pro rata, and 50.0% to our general partner. The
percentage interests shown for our general partner include its
2.0% general partner interest and assume that our general
partner has not transferred the incentive distribution rights.
Adjustment
to the Minimum Quarterly Distribution and Target Distribution
Levels
In addition to adjusting the minimum quarterly distribution and
target distribution levels to reflect a distribution of capital
surplus, if we combine our units into fewer units or subdivide
our units into a greater number of units, we will
proportionately adjust:
|
|
|
|
|
the minimum quarterly distribution;
|
|
|
|
the number of common units into which a subordinated unit is
convertible;
|
|
|
|
target distribution levels;
|
|
|
|
the unrecovered initial unit price; and
|
|
|
|
the number of general partner units comprising the general
partner interest.
|
For example, if a
two-for-one
split of the common units should occur, the minimum quarterly
distribution, the target distribution levels and the unrecovered
initial unit price would each be reduced to 50% of its initial
level, and each subordinated unit would be convertible into two
common units. We will not make any adjustment by reason of the
issuance of additional units for cash or property.
In addition, if legislation is enacted or if existing law is
modified or interpreted by a governmental authority, so that we
become taxable as a corporation or otherwise subject to taxation
as an entity for federal, state or local income tax purposes,
our partnership agreement specifies that the minimum quarterly
distribution and the target distribution levels for each quarter
may be reduced by multiplying each distribution level by a
fraction, the numerator of which is available cash for that
quarter and the denominator of which is the sum of available
cash for that quarter plus our general partners estimate
of our aggregate liability for the quarter for such income taxes
payable by reason of such legislation or interpretation. To the
extent that the actual tax liability differs from the estimated
tax liability for any quarter, the difference will be accounted
for in subsequent quarters.
Distributions
of Cash Upon Liquidation
General
If we dissolve in accordance with our partnership agreement, we
will sell or otherwise dispose of our assets in a process called
liquidation. We will first apply the proceeds of liquidation to
the payment of our creditors. We will distribute any remaining
proceeds to the unitholders and our general partner, in
accordance with their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of
our assets in liquidation.
The allocations of gain and loss upon liquidation are intended,
to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding
subordinated units upon our liquidation, to the extent required
to permit common unitholders to receive their unrecovered
initial unit price plus the minimum quarterly distribution for
the quarter during which liquidation occurs plus any unpaid
arrearages in payment of the minimum quarterly distribution on
the common units. However, there may not be sufficient gain upon
our liquidation to enable the holders of common units to fully
recover all of these amounts, even though there may be cash
available for distribution to the holders of subordinated units.
Any further net gain recognized upon liquidation will be
allocated in a manner that takes into account the incentive
distribution rights of our general partner.
74
Manner
of Adjustments for Gain
The manner of the adjustment for gain is set forth in our
partnership agreement. If our liquidation occurs before the end
of the subordination period, we will allocate any gain to our
partners in the following manner:
|
|
|
|
|
first, to our general partner and the holders of units
who have negative balances in their capital accounts to the
extent of and in proportion to those negative balances;
|
|
|
|
second, 98.0% to the common unitholders, pro rata, and
2.0% to our general partner, until the capital account for each
common unit is equal to the sum of: (1) the unrecovered
initial unit price; (2) the amount of the minimum quarterly
distribution for the quarter during which our liquidation
occurs; and (3) any unpaid arrearages in payment of the
minimum quarterly distribution;
|
|
|
|
third, 98.0% to the subordinated unitholders, pro rata,
and 2.0% to our general partner, until the capital account for
each subordinated unit is equal to the sum of: (1) the
unrecovered initial unit price; and (2) the amount of the
minimum quarterly distribution for the quarter during which our
liquidation occurs;
|
|
|
|
fourth, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to: (1) the sum of the excess of the
first target distribution per unit over the minimum quarterly
distribution per unit for each quarter of our existence; less
(2) the cumulative amount per unit of any distributions
of available cash from operating surplus in excess of the
minimum quarterly distribution per unit that we distributed
98.0% to the unitholders, pro rata, and 2.0% to our general
partner, for each quarter of our existence;
|
|
|
|
fifth, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to: (1) the sum of the excess of the
second target distribution per unit over the first target
distribution per unit for each quarter of our existence; less
(2) the cumulative amount per unit of any distributions
of available cash from operating surplus in excess of the first
target distribution per unit that we distributed 85.0% to the
unitholders, pro rata, and 15.0% to our general partner for each
quarter of our existence;
|
|
|
|
sixth, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to: (1) the sum of the excess of the
third target distribution per unit over the second target
distribution per unit for each quarter of our existence; less
(2) the cumulative amount per unit of any distributions
of available cash from operating surplus in excess of the second
target distribution per unit that we distributed 75.0% to the
unitholders, pro rata, and 25.0% to our general partner for each
quarter of our existence;
|
|
|
|
thereafter, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
|
The percentages set forth above are based on the assumption that
our general partner has not transferred its incentive
distribution rights and that we do not issue additional classes
of equity securities.
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that clause (3) of the second
bullet point above and all of the fourth bullet point above will
no longer be applicable.
Manner
of Adjustments for Losses
If our liquidation occurs before the end of the subordination
period, after making allocations of loss to the general partner
and the unitholders in a manner intended to offset in reverse
order the allocations of gains that have previously been
allocated, we will generally allocate any loss to our general
partner and unitholders in the following manner:
|
|
|
|
|
first, 98.0% to the holders of subordinated units in
proportion to the positive balances in their capital accounts
and 2.0% to our general partner, until the capital accounts of
the subordinated unitholders have been reduced to zero;
|
75
|
|
|
|
|
second, 98.0% to the holders of common units in
proportion to the positive balances in their capital accounts
and 2.0% to our general partner, until the capital accounts of
the common unitholders have been reduced to zero; and
|
|
|
|
thereafter, 100.0% to our general partner.
|
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that all of the first bullet point
above will no longer be applicable.
Adjustments
to Capital Accounts
Our partnership agreement requires that we make adjustments to
capital accounts upon the issuance of additional units. In this
regard, our partnership agreement specifies that we allocate any
unrealized and, for tax purposes, unrecognized gain resulting
from the adjustments to the unitholders and the general partner
in the same manner as we allocate gain upon liquidation. In the
event that we make positive adjustments to the capital accounts
upon the issuance of additional units, our partnership agreement
requires that we generally allocate any later negative
adjustments to the capital accounts resulting from the issuance
of additional units or upon our liquidation in a manner which
results, to the extent possible, in the partners capital
account balances equaling the amount which they would have been
if no earlier positive adjustments to the capital accounts had
been made. In contrast to the allocations of gain, and except as
provided above, we generally will allocate any unrealized and
unrecognized loss resulting from the adjustments to capital
accounts upon the issuance of additional units to the
unitholders and our general partner based on their respective
percentage ownership of us. In this manner, prior to the end of
the subordination period, we generally will allocate any such
loss equally with respect to our common and subordinated units.
If we make negative adjustments to the capital accounts as a
result of such loss, future positive adjustments resulting from
the issuance of additional units will be allocated in a manner
designed to reverse the prior negative adjustments, and special
allocations will be made upon liquidation in a manner that
results, to the extent possible, in our unitholders
capital account balances equaling the amounts they would have
been if no earlier adjustments for loss had been made.
76
SELECTED
HISTORICAL FINANCIAL AND OPERATING DATA
The following table presents our selected historical
consolidated financial and operating data, as well as the
selected historical combined financial and operating data of our
Predecessor, which was comprised of 12 indirectly wholly owned
subsidiaries of Enbridge, as of the dates and for the periods
indicated.
The selected financial data as of and for the year ended
December 31, 2006 are derived from the unaudited historical
combined financial data of our Predecessor that are not included
in this prospectus. The selected historical combined financial
data presented as of and for the year ended December 31,
2007 are derived from the audited historical combined financial
statements of our Predecessor that are not included in this
prospectus. The selected historical combined financial data
presented as of and for the year ended December 31, 2008,
and as of and for the 10 months ended October 31, 2009
are derived from the audited historical combined financial
statements of our Predecessor that are included elsewhere in
this prospectus. The selected historical consolidated financial
data presented as of December 31, 2009, for the period from
August 20, 2009 (date of inception) to December 31,
2009 and as of and for the year ended December 31, 2010 are
derived from our audited historical consolidated financial
statements included elsewhere in this prospectus. We acquired
our assets effective November 1, 2009. During the period
from our inception, on August 20, 2009, to October 31,
2009, we had no operations although we incurred certain fees and
expenses of approximately $6.4 million associated with our
formation and the acquisition of our assets from Enbridge, which
are reflected in the One-time transaction costs line
item of our consolidated financial data for the period from
August 20, 2009 through December 31, 2009.
For a detailed discussion of the following table, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations. The following table
should also be read in conjunction with the historical audited
consolidated financial statements of American Midstream
Partners, LP and related notes and our Predecessors
audited combined financial statements and related notes included
elsewhere in this prospectus. Among other things, those
historical financial statements include more detailed
information regarding the basis of presentation for the
information in the following table.
77
The following table presents the non-GAAP financial measures
adjusted EBITDA and gross margin that we use in our business and
view as important supplemental measures of our performance. For
a definition of these measures and a reconciliation of them to
their most directly comparable financial measures calculated and
presented in accordance with GAAP, please read
Non-GAAP Financial Measures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
American Midstream
|
|
|
|
|
|
|
|
|
Partners, LP
|
|
|
|
|
American Midstream Partners Predecessor
|
|
|
|
and Subsidiaries (Successor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
August 20,
|
|
|
|
|
|
|
|
|
Year
|
|
|
|
Year
|
|
|
|
Year
|
|
|
|
10 Months
|
|
|
|
2009 (Inception
|
|
|
|
Year
|
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
Date) to
|
|
|
|
Ended
|
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
October 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
|
2007
|
|
|
|
2008
|
|
|
|
2009
|
|
|
|
2009
|
|
|
|
2010
|
|
|
|
|
(in thousands, except per unit and operating data)
|
|
|
|
|
|
|
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
$
|
314,278
|
|
|
|
$
|
290,777
|
|
|
|
$
|
366,348
|
|
|
|
$
|
143,132
|
|
|
|
$
|
32,833
|
|
|
|
$
|
211,940
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
|
278,590
|
|
|
|
|
251,959
|
|
|
|
|
323,205
|
|
|
|
|
113,227
|
|
|
|
|
26,593
|
|
|
|
|
173,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
|
35,688
|
|
|
|
|
38,818
|
|
|
|
|
43,143
|
|
|
|
|
29,905
|
|
|
|
|
6,240
|
|
|
|
|
38,119
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
|
14,295
|
|
|
|
|
15,334
|
|
|
|
|
13,423
|
|
|
|
|
10,331
|
|
|
|
|
1,594
|
|
|
|
|
12,187
|
|
Selling, general and administrative expenses(1)
|
|
|
|
7,407
|
|
|
|
|
10,294
|
|
|
|
|
8,618
|
|
|
|
|
8,577
|
|
|
|
|
1,346
|
|
|
|
|
8,854
|
|
One-time transaction costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,404
|
|
|
|
|
303
|
|
Depreciation expense
|
|
|
|
9,917
|
|
|
|
|
12,500
|
|
|
|
|
13,481
|
|
|
|
|
12,630
|
|
|
|
|
2,978
|
|
|
|
|
20,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
|
31,619
|
|
|
|
|
38,128
|
|
|
|
|
35,522
|
|
|
|
|
31,538
|
|
|
|
|
12,322
|
|
|
|
|
41,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
4,069
|
|
|
|
|
690
|
|
|
|
|
7,621
|
|
|
|
|
(1,633
|
)
|
|
|
|
(6,082
|
)
|
|
|
|
(3,238
|
)
|
Other (income) expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
8,469
|
|
|
|
|
8,527
|
|
|
|
|
5,747
|
|
|
|
|
3,728
|
|
|
|
|
910
|
|
|
|
|
5,406
|
|
Income tax expense
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income) expenses
|
|
|
|
(996
|
)
|
|
|
|
1,209
|
|
|
|
|
(854
|
)
|
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
(3,506
|
)
|
|
|
$
|
(9,046
|
)
|
|
|
$
|
2,728
|
|
|
|
$
|
(5,337
|
)
|
|
|
$
|
(6,992
|
)
|
|
|
$
|
(8,644
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(140
|
)
|
|
|
|
(173
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,852
|
)
|
|
|
|
(8,471
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners net income (loss) per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1.52
|
)
|
|
|
$
|
(0.81
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
$
|
2,486
|
|
|
|
$
|
(447
|
)
|
|
|
$
|
18,155
|
|
|
|
$
|
14,589
|
|
|
|
$
|
(6,531
|
)
|
|
|
$
|
13,791
|
|
Investing activities
|
|
|
|
(7,587
|
)
|
|
|
|
745
|
|
|
|
|
(10,486
|
)
|
|
|
|
(853
|
)
|
|
|
|
(151,976
|
)
|
|
|
|
(10,268
|
)
|
Financing activities
|
|
|
|
5,132
|
|
|
|
|
322
|
|
|
|
|
(7,929
|
)
|
|
|
|
(14,088
|
)
|
|
|
|
159,656
|
|
|
|
|
(4,609
|
)
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
$
|
14,880
|
|
|
|
$
|
11,981
|
|
|
|
$
|
21,956
|
|
|
|
$
|
11,021
|
|
|
|
$
|
3,450
|
|
|
|
$
|
18,263
|
|
Segment gross margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing
|
|
|
|
19,215
|
|
|
|
|
22,108
|
|
|
|
|
27,354
|
|
|
|
|
20,024
|
|
|
|
|
3,698
|
|
|
|
|
24,595
|
|
Transmission
|
|
|
|
16,476
|
|
|
|
|
16,710
|
|
|
|
|
15,789
|
|
|
|
|
9,881
|
|
|
|
|
2,542
|
|
|
|
|
13,524
|
|
Balance Sheet Data (At Period End):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
61
|
|
|
|
$
|
681
|
|
|
|
$
|
421
|
|
|
|
$
|
149
|
|
|
|
$
|
1,149
|
|
|
|
$
|
63
|
|
Accounts receivable, net and unbilled revenue
|
|
|
|
16,357
|
|
|
|
|
13,643
|
|
|
|
|
9,532
|
|
|
|
|
8,756
|
|
|
|
|
19,776
|
|
|
|
|
22,850
|
|
Property, plant and equipment, net
|
|
|
|
233,143
|
|
|
|
|
219,898
|
|
|
|
|
216,903
|
|
|
|
|
205,126
|
|
|
|
|
149,226
|
|
|
|
|
146,808
|
|
Total assets
|
|
|
|
298,161
|
|
|
|
|
287,290
|
|
|
|
|
277,242
|
|
|
|
|
250,162
|
|
|
|
|
174,470
|
|
|
|
|
173,229
|
|
Total debt (current and long-term)(2)
|
|
|
|
65,000
|
|
|
|
|
60,000
|
|
|
|
|
60,000
|
|
|
|
|
|
|
|
|
|
61,000
|
|
|
|
|
56,370
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
179.2
|
|
|
|
|
211.8
|
|
|
|
|
169.7
|
|
|
|
|
175.6
|
|
Plant inlet volume
(MMcf/d)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.5
|
|
|
|
|
11.7
|
|
|
|
|
11.4
|
|
|
|
|
9.9
|
|
Gross NGL production (Mgal/d)(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40.2
|
|
|
|
|
39.3
|
|
|
|
|
38.2
|
|
|
|
|
34.1
|
|
Transmission segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
336.2
|
|
|
|
|
357.6
|
|
|
|
|
381.3
|
|
|
|
|
350.2
|
|
Firm transportation capacity reservation
(MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
627.3
|
|
|
|
|
613.2
|
|
|
|
|
701.0
|
|
|
|
|
677.6
|
|
Interruptible transportation throughput
(MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
141.6
|
|
|
|
|
121.0
|
|
|
|
|
118.0
|
|
|
|
|
80.9
|
|
|
|
|
(1) |
|
Includes LTIP expenses for the period from August 20, 2009
to December 31, 2009 and the year ended December 31,
2010 of $0.2 million and $1.7 million, respectively.
Of these amounts, $0.2 million and $1.2 million,
respectively, represent non-cash expenses. |
|
(2) |
|
Excludes Predecessor Note payable to Enbridge Midcoast Limited
Holdings, L.L.C. of $39.3 million as of December 31,
2008. |
78
|
|
|
(3) |
|
Excludes volumes and gross production under our elective
processing arrangements. For a description of our elective
processing arrangements, please read Business
Gathering and Processing Segment Gloria System. |
Non-GAAP Financial
Measures
We include in this prospectus the non-GAAP financial measures of
adjusted EBITDA and gross margin. We provide reconciliations of
these non-GAAP financial measures to their most directly
comparable financial measures as calculated and presented in
accordance with GAAP.
Adjusted
EBITDA
We define adjusted EBITDA as net income:
|
|
|
|
|
Interest expense;
|
|
|
|
Income tax expense;
|
|
|
|
Depreciation expense;
|
|
|
|
Certain non-cash charges such as non-cash equity compensation;
|
|
|
|
Unrealized losses on commodity derivative contracts; and
|
|
|
|
Selected charges that are unusual or non-recurring.
|
|
|
|
|
|
Interest income;
|
|
|
|
Income tax benefit;
|
|
|
|
Unrealized gains on commodity derivative contracts; and
|
|
|
|
Selected gains that are unusual or non-recurring.
|
Adjusted EBITDA is used as a supplemental financial measure by
management and by external users of our financial statements,
such as investors and lenders, to assess:
|
|
|
|
|
the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
|
|
|
|
the ability of our assets to generate cash sufficient to support
our indebtedness and make cash distributions to our unitholders
and general partner;
|
|
|
|
our operating performance and return on capital as compared to
those of other companies in the midstream energy sector, without
regard to financing or capital structure; and
|
|
|
|
the attractiveness of capital projects and acquisitions and the
overall rates of return on alternative investment opportunities.
|
The economic rationale behind managements use of adjusted
EBITDA is to measure the ability of our assets to generate cash
sufficient to pay interest costs, support our indebtedness and
make distributions to our investors.
The GAAP measure most directly comparable to adjusted EBITDA is
net income. Our non-GAAP financial measure of adjusted EBITDA
should not be considered as an alternative to net income.
Adjusted EBITDA is not a presentation made in accordance with
GAAP and has important limitations as an analytical tool. You
should not consider adjusted EBITDA in isolation or as a
substitute for analysis of our results as reported under GAAP.
Because adjusted EBITDA excludes some, but not all, items that
affect net income and is defined differently by different
companies in our industry, our definition of adjusted EBITDA may
not be comparable to similarly titled measures of other
companies.
79
Management compensates for the limitations of adjusted EBITDA as
an analytical tool by reviewing the comparable GAAP measures,
understanding the differences between the measures and
incorporating these data points into managements
decision-making process.
The following table presents a reconciliation of adjusted EBITDA
to net income (loss) attributable to our unitholders for each of
the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
American Midstream
|
|
|
|
|
|
|
|
|
Partners, LP
|
|
|
|
|
|
|
|
|
and Subsidiaries
|
|
|
|
|
American Midstream Partners Predecessor
|
|
|
|
(Successor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
August 20,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
Year
|
|
|
|
Year
|
|
|
|
Year
|
|
|
|
10 Months
|
|
|
|
(Inception
|
|
|
|
Year
|
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
Date) to
|
|
|
|
Ended
|
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
October 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
|
2006
|
|
|
|
2007
|
|
|
|
2008
|
|
|
|
2009
|
|
|
|
2009
|
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to Net Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
(3,506
|
)
|
|
|
$
|
(9,046
|
)
|
|
|
$
|
2,728
|
|
|
|
$
|
(5,337
|
)
|
|
|
$
|
(6,992
|
)
|
|
|
$
|
(8,644
|
)
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense
|
|
|
|
9,917
|
|
|
|
|
12,500
|
|
|
|
|
13,481
|
|
|
|
|
12,630
|
|
|
|
|
2,978
|
|
|
|
|
20,013
|
|
Interest expense
|
|
|
|
8,469
|
|
|
|
|
8,527
|
|
|
|
|
5,747
|
|
|
|
|
3,728
|
|
|
|
|
910
|
|
|
|
|
5,406
|
|
Non-cash equity compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150
|
|
|
|
|
1,185
|
|
One-time transaction costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,404
|
|
|
|
|
303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
$
|
14,880
|
|
|
|
$
|
11,981
|
|
|
|
$
|
21,956
|
|
|
|
$
|
11,021
|
|
|
|
$
|
3,450
|
|
|
|
$
|
18,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Gross
Margin
We define gross margin as the sum of segment gross margin in our
Gathering and Processing segment and segment gross margin in our
Transmission segment. We define segment gross margin in our
Gathering and Processing segment as revenue generated from
gathering and processing operations less the cost of natural
gas, NGLs and condensate purchased. We define segment gross
margin in our Transmission segment as revenue generated from
firm and interruptible transportation agreements and
fixed-margin arrangements, plus other related fees, less the
cost of natural gas purchased in connection with fixed-margin
arrangements. Gross margin is included as a supplemental
disclosure because it is a primary performance measure used by
our management as it represents the results of service fee
revenue and cost of sales, which are key components of our
operations. As an indicator of our operating performance, gross
margin should not be considered an alternative to, or more
meaningful than, net income as determined in accordance with
GAAP. Our gross margin may not be comparable to a similarly
titled measure of another company because other entities may not
calculate gross margin in the same manner. For a reconciliation
of gross margin to net income, its most directly comparable
financial measure calculated and presented in accordance with
GAAP, please read Note 18 to our consolidated financial
statements included elsewhere in this prospectus.
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MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
You should read the following discussion of the financial
condition and results of operations of American Midstream
Partners, LP and its subsidiaries in conjunction with the
historical consolidated financial statements and related notes
of American Midstream Partners, LP and the historical combined
financial statements and related notes of our Predecessor
included elsewhere in this prospectus. Among other things, those
financial statements and the related notes include more detailed
information regarding the basis of presentation for the
following information.
Overview
We are a growth-oriented Delaware limited partnership that was
formed by AIM in August 2009 to own, operate, develop and
acquire a diversified portfolio of natural gas midstream energy
assets. We are engaged in the business of gathering, treating,
processing and transporting natural gas through our ownership
and operation of nine gathering systems, three processing
facilities, two interstate pipelines and six intrastate
pipelines. Our primary assets, which are strategically located
in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide
critical infrastructure that links producers and suppliers of
natural gas to diverse natural gas markets, including various
interstate and intrastate pipelines, as well as utility,
industrial and other commercial customers. We currently operate
approximately 1,400 miles of pipelines that gather and
transport over
500 MMcf/d
of natural gas. We acquired our existing portfolio of assets
from a subsidiary of Enbridge Energy Partners, L.P., or
Enbridge, in November 2009.
Our operations are organized into two segments:
(i) Gathering and Processing and (ii) Transmission. In
our Gathering and Processing segment, we receive fee-based and
fixed-margin compensation for gathering, transporting and
treating natural gas. Where we provide processing services at
the plants that we own, or obtain processing services for our
own account under our elective processing arrangements, we
typically retain and sell a percentage of the residue natural
gas and resulting natural gas liquids, or NGLs, under
percent-of-proceeds,
or POP, arrangements. We own three processing facilities that
produced an average of approximately 34.1 Mgal/d of gross NGLs
for the year ended December 31, 2010. In addition, under
our elective processing arrangements, we contract for processing
capacity at a third-party plant where we have the option to
process natural gas that we purchase. Under these arrangements,
we sold an average of approximately 28.1 Mgal/d of net equity
NGL volumes for the year ended December 31, 2010. We also
receive fee-based and fixed-margin compensation in our
Transmission segment primarily related to capacity reservation
charges under our firm transportation contracts and the
transportation of natural gas pursuant to our interruptible
transportation and fixed-margin contracts.
Our
Operations
We manage our business and analyze and report our results of
operations through two business segments:
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Gathering and Processing. Our Gathering
and Processing segment provides wellhead to market
services for natural gas to producers of natural gas and oil,
which include transporting raw natural gas from various receipt
points through gathering systems, treating the raw natural gas,
processing raw natural gas to separate the NGLs and selling or
delivering pipeline quality natural gas as well as NGLs to
various markets and pipeline systems.
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Transmission. Our Transmission segment
transports and delivers natural gas from producing wells,
receipt points or pipeline interconnects for shippers and other
customers, which include local distribution companies, or LDCs,
utilities and industrial, commercial and power generation
customers.
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Gathering
and Processing Segment
Results of operations from our Gathering and Processing segment
are determined primarily by the volumes of natural gas we gather
and process, the commercial terms in our current contract
portfolio and
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natural gas, NGL and condensate prices. We gather and process
natural gas primarily pursuant to the following arrangements:
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Fee-Based Arrangements. Under these
arrangements, we generally are paid a fixed cash fee for
gathering and transporting natural gas.
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Fixed-Margin Arrangements. Under these
arrangements, we purchase natural gas from producers or
suppliers at receipt points on our systems at an index price
less a fixed transportation fee and simultaneously sell an
identical volume of natural gas at delivery points on our
systems at the same, undiscounted index price. By entering into
back-to-back
purchases and sales of natural gas, we are able to lock in a
fixed-margin on these transactions. We view the segment gross
margin earned under our fixed-margin arrangements to be
economically equivalent to the fee earned in our fee-based
arrangements.
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Percent-of-Proceeds
Arrangements. Under these arrangements, we
generally gather raw natural gas from producers at the wellhead
or other supply points, transport it through our gathering
system, process it and sell the residue natural gas and NGLs at
market prices. Where we provide processing services at the
processing plants that we own or obtain processing services for
our own account under our elective processing arrangements, such
as our Toca contracts, we generally retain and sell a percentage
of the residue natural gas and resulting NGLs. Please read
Business Gathering and Processing
Segment Gloria System.
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Gross margin earned under fee-based and fixed-margin
arrangements is directly related to the volume of natural gas
that flows through our systems and is not directly dependent on
commodity prices. However, a sustained decline in commodity
prices could result in a decline in volumes and, thus, a
decrease in our fee-based and fixed-margin gross margin. These
arrangements provide stable cash flows, but minimal, if any,
upside in higher commodity price environments. Under our typical
percent-of-proceeds
arrangement, our gross margin is directly impacted by the
commodity prices we realize on our share of natural gas and NGLs
received as compensation for processing raw natural gas.
However, our
percent-of-proceeds
arrangements also often contain a fee-based component, which
helps to mitigate the degree of commodity-price volatility we
could experience under these arrangements. We further seek to
mitigate our exposure to commodity price risk through our
hedging program. Please read Quantitative and
Qualitative Disclosures about Market Risk Commodity
Price Risk.
Transmission
Segment
Results of operations from our Transmission segment are
determined primarily by capacity reservation fees from firm
transportation contracts and, to a lesser extent, the volumes of
natural gas transported on the interstate and intrastate
pipelines we own pursuant to interruptible transportation or
fixed-margin contracts. Our transportation arrangements are
further described below:
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Firm Transportation Arrangements. Our
obligation to provide firm transportation service means that we
are obligated to transport natural gas nominated by the shipper
up to the maximum daily quantity specified in the contract. In
exchange for that obligation on our part, the shipper pays a
specified reservation charge, whether or not it utilizes the
capacity. In most cases, the shipper also pays a variable use
charge with respect to quantities actually transported by us.
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Interruptible Transportation. Our
obligation to provide interruptible transportation service means
that we are only obligated to transport natural gas nominated by
the shipper to the extent that we have available capacity. For
this service the shipper pays no reservation charge but pays a
variable use charge for quantities actually shipped.
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Fixed-Margin Arrangements. Under these
arrangements, we purchase natural gas from producers or
suppliers at receipt points on our systems at an index price
less a fixed transportation fee and simultaneously sell an
identical volume of natural gas at delivery points on our
systems at the same, undiscounted index price. We view
fixed-margin arrangements to be economically equivalent to our
interruptible transportation arrangements.
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The gross margin we earn from our transportation activities is
directly related to the capacity reservation on, and actual
volume of natural gas that flows through, our systems, neither
of which is directly dependent on commodity prices. However, a
sustained decline in market demand could result in a decline in
volumes and, thus, a decrease in our commodity-based gross
margin under firm transportation contracts or gross margin under
our interruptible transportation and fixed-margin contracts.
Contract
Mix
Set forth below is a table summarizing our average contract mix
for the twelve months ended December 31, 2010:
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Segment
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Percent of
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Gross
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Segment
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Margin
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Gross Margin
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(in millions)
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Gathering and Processing
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Fee-based
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$
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6.5
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26.4
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%
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Fixed-margin
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4.9
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19.9
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Percent-of-proceeds
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13.2
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53.7
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Total
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$
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24.6
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100
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%
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Transmission
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Firm transportation
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$
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10.8
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80.0
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%
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Interruptible transportation
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2.0
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14.8
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Fixed-margin
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0.7
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5.2
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Total
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$
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13.5
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100
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%
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How We
Evaluate Our Operations
Our management uses a variety of financial and operational
metrics to analyze our performance. We view these metrics as
important factors in evaluating our profitability and review
these measurements on at least a monthly basis for consistency
and trend analysis. These metrics include throughput volumes,
gross margin and direct operating expenses on a segment basis,
and adjusted EBITDA and distributable cash flow on a
company-wide basis.
Throughput
Volumes
In our Gathering and Processing segment, we must continually
obtain new supplies of natural gas to maintain or increase
throughput volumes on our systems. Our ability to maintain or
increase existing volumes of natural gas and obtain new supplies
is impacted by (i) the level of workovers or recompletions
of existing connected wells and successful drilling activity in
areas currently dedicated to or near our gathering systems,
(ii) our ability to compete for volumes from successful new
wells in the areas in which we operate, (iii) our ability
to obtain natural gas that has been released from other
commitments and (iv) the volume of natural gas that we
purchase from connected systems. We actively monitor producer
activity in the areas served by our gathering and processing
systems to pursue new supply opportunities.
In our Transmission segment, the majority of our segment gross
margin is generated by firm capacity reservation fees, as
opposed to the actual throughput volumes, on our interstate and
intrastate pipelines. Substantially all of this segment gross
margin is generated under contracts with shippers, including
producers, industrial companies, LDCs and marketers, for firm
and interruptible natural gas transportation on our pipelines.
We routinely monitor natural gas market activities in the areas
served by our transmission systems to pursue new shipper
opportunities.
Gross
Margin and Segment Gross Margin
Gross margin and segment gross margin are the primary metrics
that we use to evaluate our performance. See Selected
Historical Financial and Operating Data
Non-GAAP Financial Measures. We define segment
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gross margin in our Gathering and Processing segment as revenue
generated from gathering and processing operations less the cost
of natural gas, NGLs and condensate purchased. Revenue includes
revenue generated from fixed fees associated with the gathering
and treating of natural gas and from the sale of natural gas,
NGLs and condensate resulting from gathering and processing
activities under fixed-margin and
percent-of-proceeds
arrangements. The cost of natural gas, NGLs and condensate
includes volumes of natural gas, NGLs and condensate remitted
back to producers pursuant to
percent-of-proceeds
arrangements and the cost of natural gas purchased for our own
account, including pursuant to fixed-margin arrangements.
We define segment gross margin in our Transmission segment as
revenue generated from firm and interruptible transportation
agreements and fixed-margin arrangements, plus other related
fees, less the cost of natural gas purchased in connection with
fixed-margin arrangements. Substantially all of our gross margin
in this segment is fee-based or fixed-margin, with little to no
direct commodity price risk.
Direct
Operating Expenses
Our management seeks to maximize the profitability of our
operations in part by minimizing direct operating expenses.
Direct labor costs, insurance costs, ad valorem and property
taxes, repair and non-capitalized maintenance costs, integrity
management costs, utilities, lost and unaccounted for gas and
contract services comprise the most significant portion of our
operating expenses. These expenses are relatively stable and
largely independent of throughput volumes through our systems,
but may fluctuate depending on the activities performed during a
specific period.
Adjusted
EBITDA and Distributable Cash Flow
We define adjusted EBITDA as net income, plus interest expense,
income tax expense, depreciation expense, certain non-cash
charges such as non-cash equity compensation, unrealized losses
on commodity derivative contracts and selected charges that are
unusual or non-recurring, less interest income, income tax
benefit, unrealized gains on commodity derivative contracts and
selected gains that are unusual or non-recurring. See
Selected Historical Financial and Operating
Data Non-GAAP Financial Measures.
Although we have not quantified distributable cash flow on a
historical basis, after the closing of this offering we intend
to use distributable cash flow, which we define as adjusted
EBITDA plus interest income, less cash paid for interest expense
and maintenance capital expenditures, to analyze our
performance. Distributable cash flow will not reflect changes in
working capital balances. Adjusted EBITDA and distributable cash
flow are used as supplemental measures by our management and by
external users of our financial statements such as investors,
commercial banks, research analysts and others, to assess:
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the financial performance of our assets without regard to
financing methods, capital structure or historical cost basis;
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the ability of our assets to generate cash sufficient to support
our indebtedness and make cash distributions to our unitholders
and general partner;
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our operating performance and return on capital as compared to
those of other companies in the midstream energy sector, without
regard to financing or capital structure; and
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the attractiveness of capital projects and acquisitions and the
overall rates of return on alternative investment opportunities.
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Note
About Non-GAAP Financial Measures
Gross margin, adjusted EBITDA and distributable cash flow are
not financial measures presented in accordance with GAAP. We
believe that the presentation of these non-GAAP financial
measures will provide useful information to investors in
assessing our financial condition and results of operations. Net
income is the GAAP measure most directly comparable to each of
gross margin and adjusted EBITDA. The GAAP measure most directly
comparable to distributable cash flow is net cash provided by
operating activities. Our non-
84
GAAP financial measures should not be considered as alternatives
to the most directly comparable GAAP financial measure. Each of
these non-GAAP financial measures has important limitations as
an analytical tool because it excludes some but not all items
that affect the most directly comparable GAAP financial measure.
You should not consider any of gross margin, adjusted EBITDA or
distributable cash flow in isolation or as a substitute for
analysis of our results as reported under GAAP. Because gross
margin, adjusted EBITDA and distributable cash flow may be
defined differently by other companies in our industry, our
definitions of these non-GAAP financial measures may not be
comparable to similarly titled measures of other companies,
thereby diminishing their utility.
Items Affecting
the Comparability of Our Financial Results
Our historical results of operations for the periods presented
and those of our Predecessor may not be comparable, either to
each other or to our future results of operations, for the
reasons described below:
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Since we acquired our assets from Enbridge effective
November 1, 2009, the financial and operational data for
2009 that is discussed below is generally bifurcated between the
period that our Predecessor owned those assets and the period
from our acquisition through the end of the year. Moreover,
there is some overlap between these two periods resulting from
the fact that we were formed on August 20, 2009, which was
prior to the acquisition on November 1, 2009. As a result,
the 2009 period that our Predecessor owned and operated the
assets is the ten months ended October 31, 2009, while the
successor 2009 period begins with our inception on
August 20, 2009 and ends on December 31, 2009.
Although we incurred costs associated with our formation and the
acquisition of our assets from Enbridge of $6.4 million, we
had no material operations until November 1, 2009.
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The historical combined financial statements and related notes
of our Predecessor:
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are presented on a combined rather than a consolidated basis.
The principal difference between consolidated and combined
financial statements is that consolidated financial statements
do not reflect transactions and investments between consolidated
subsidiaries or between those subsidiaries and the parent
entity, showing instead a view of the parent entity and its
consolidated subsidiaries as a whole; and
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reflect the operation of our assets with different business
strategies and as part of a larger business rather than the
stand-alone fashion in which we operate them. Please read
Business Business Strategies.
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SG&A expenses of our Predecessor during periods in which we
did not own or operate our assets were allocated expenses from a
much larger parent entity and may not represent SG&A
expenses required to actually operate our assets as we intend.
In addition, we adopted an LTIP in connection with our formation
in 2009, and our SG&A expenses for the year ended
December 31, 2010 included $1.7 million of cash and
non-cash expenses associated with grants pursuant to our LTIP.
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Initially, we anticipate incurring approximately
$2.3 million of annual incremental general and
administrative expenses attributable to operating as a publicly
traded partnership, such as expenses associated with annual and
quarterly SEC reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on the NASDAQ;
independent auditor fees; legal fees; investor relations
expenses; registrar and transfer agent fees; director and
officer liability insurance costs; and director compensation.
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In connection with our formation and the acquisition of our
assets from Enbridge, we incurred transaction expenses of
approximately $6.4 million. These transaction expenses are
included in our historical consolidated financial statements for
the period from August 20, 2009 to December 31, 2009.
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In connection with the acquisition of our assets from Enbridge,
effective November 1, 2009:
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we put in place stand-alone insurance policies customary for
midstream partnerships, which had the effect of increasing our
direct operating expenses;
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we initiated a comprehensive review of the integrity management
program that we inherited when we acquired our assets. Following
this review, we concluded that there were sixteen high
consequence areas that required further testing pursuant to DOT
regulations;
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one of our subsidiaries entered into an advisory services
agreement with certain affiliates of AIM Midstream Holdings,
which resulted in higher SG&A expenses during the periods
after that acquisition. Please read Certain Relationships
and Related Party Transactions Agreements with
Affiliates. At the closing of this offering, we will pay
$ to those affiliates to terminate
this agreement; and
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we recorded our assets at fair value, which was less than our
Predecessors book value of those assets, and their useful
lives were also decreased, which had the net effect of
increasing the depreciation expense associated with our assets
after the acquisition date.
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Interest expense of our Predecessor was an allocated expense
from our Predecessors publicly traded parent entity. In
addition, we incurred indebtedness to finance our acquisition of
our assets from Enbridge, which increased our interest expense
after the acquisition date.
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After our acquisition of our assets from Enbridge, we initiated
a hedging program comprised of NGL puts and swaps, as well as
interest rate caps, that we account for using
mark-to-market
accounting. These amounts are included in our historical
consolidated financial statements and related notes as
unrealized/realized gain (loss) from risk management activities.
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In December 2010, we completed an interconnect between our
Lafitte pipeline and a pipeline on the TGP interstate system.
This interconnect enables us to purchase natural gas from
producers on the TGP system and deliver it to the Alliance
Refinery and the Toca processing plant, which will enable us to
process substantially more natural gas under our elective
processing arrangements.
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General
Trends and Outlook
We expect our business to continue to be affected by the key
trends discussed below. Our expectations are based on
assumptions made by us and information currently available to
us. To the extent our underlying assumptions about, or
interpretations of, available information prove to be incorrect,
our actual results may vary materially from our expected results.
Outlook
Beginning in the second half of 2008, the United States and
other industrialized countries experienced a significant
economic downturn that led to a decline in worldwide energy
demand. During this same period, North American oil and natural
gas supply was increasing as a result of the rise in domestic
unconventional production. The combination of lower energy
demand due to the economic downturn and higher North American
oil and natural gas supply resulted in significant declines in
oil, NGL and natural gas prices. While oil and NGL prices began
to increase steadily in the second quarter of 2009, natural gas
prices remained depressed and volatile throughout 2009 and 2010
in comparison to much of 2007 and 2008 due to a continued
increase in natural gas supply despite weaker offsetting demand
growth. The outlook for a worldwide economic recovery in 2011
remains uncertain, and the timing of a recovery in worldwide
demand for energy is difficult to predict. As a result, we
expect natural gas prices to remain relatively low in the near
term.
Notwithstanding the ongoing volatility in commodity prices,
there has been a recent resurgence in the level of acquisition
and divestiture activity in the midstream energy industry and we
expect that trend to continue. In particular, we believe that
opportunities to acquire midstream energy assets from third
parties that fulfill our strategic objectives will continue to
arise in the foreseeable future.
Supply
and Demand Outlook for Natural Gas and Oil
Natural gas and oil continue to be critical components of energy
consumption in the United States. According to the
U.S. Energy Information Administration, or EIA, annual
consumption of natural gas in the
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U.S. was approximately 24.1 trillion cubic feet, or Tcf, in
2010, compared to approximately 22.8 Tcf in 2009, representing
an increase of approximately 5.7%. Domestic production of
natural gas grew from approximately 21.6 Tcf in 2009 to
approximately 22.6 Tcf in 2010, or a 4.4% increase. The
industrial and electricity generation sectors currently account
for the largest usage of natural gas in the United States,
representing approximately 58% of the total natural gas consumed
in the United States during 2010. In particular, based on a
report by the EIA, industrial natural gas demand is expected to
grow from 7.3 Tcf in 2009 to 9.4 Tcf in 2020 as a result of an
expected recovery in industrial production.
According to the EIA, domestic crude oil production was
approximately 5.5 million barrels per day, or MMBbl/d, in
2010, compared to approximately 5.4 MMBbl/d in 2009,
representing an increase of approximately 2.8%. Domestic crude
oil production is expected to continue to increase over time
primarily due to improvements in technology that have enabled
U.S. onshore producers to economically extract sources of
supply, such as secondary and tertiary oil reserves and
unconventional oil reserves, that were previously unavailable or
uneconomic.
We believe that current oil and natural gas prices and the
existing demand for oil and natural gas will continue to result
in ongoing oil- and natural gas-related drilling in the United
States as producers seek to increase their production levels. In
particular, we believe that drilling activity targeting natural
gas with modest to high NGL content, such as on our Gloria
system, and targeting oil with associated natural gas, such as
on our Bazor Ridge system, will remain active. Although we
anticipate continued exploration and production activity in the
areas in which we operate, fluctuations in energy prices can
affect natural gas production levels over time as well as the
timing and level of investment activity by third parties in the
exploration for and development of new oil and natural gas
reserves. We have no control over the level of oil and natural
gas exploration and development activity in the areas of our
operations.
Impact
of Interest Rates
The credit markets recently have experienced near-record lows in
interest rates. As the overall economy strengthens, it is likely
that monetary policy will tighten, resulting in higher interest
rates to counter possible inflation. If this occurs, interest
rates on floating rate credit facilities and future offerings in
the debt capital markets could be higher than current levels,
causing our financing costs to increase accordingly. As with
other yield-oriented securities, our unit price will be impacted
by the level of our cash distributions and implied distribution
yield. The distribution yield is often used by investors to
compare and rank related yield-oriented securities for
investment decision-making purposes. Therefore, changes in
interest rates, either positive or negative, may affect the
yield requirements of investors who invest in our common units,
and a rising interest rate environment could have an adverse
impact on our unit price and our ability to issue additional
equity to make acquisitions, reduce debt or for other purposes.
Results
of Operations Combined Overview
The following table and discussion presents certain of our
historical consolidated financial data and the historical
combined financial data of our Predecessor for the periods
indicated.
We refer to the results of our Predecessors operations for
the period from January 1, 2009 to October 31, 2009 as
the 2009 Predecessor Period and to our operating results for the
period from August 20, 2009 to December 31, 2009 as
the 2009 Successor Period.
We acquired our assets effective November 1, 2009. During
the period from our inception, on August 20, 2009, to
October 31, 2009, we had no operations, but we incurred
certain fees and expenses totaling $6.4 million associated
with our formation and acquisition of our assets from Enbridge.
The financial data for the 2009 Predecessor Period and the year
ended December 31, 2008 represent periods of time prior to
our acquisition of our assets. During these periods, our
Predecessor owned and operated our operating assets. As such,
the results of operations for these periods do not necessarily
represent the results of operations that would have been
achieved during the period had we owned and operated our assets.
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The results of operations by segment are discussed in further
detail following this combined overview.
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American Midstream
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American Midstream Partners
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Partners, LP and Subsidiaries
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Predecessor
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(Successor)
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Period from
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August 20,
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Year
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10 Months
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2009
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Year
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Ended
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Ended
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(Inception Date) to
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Ended
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December 31,
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|
|
October 31,
|
|
|
|
December 31,
|
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|
|
December 31,
|
|
|
|
|
2008
|
|
|
|
2009
|
|
|
|
2009
|
|
|
|
2010
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
$
|
366,348
|
|
|
|
$
|
143,132
|
|
|
|
$
|
32,833
|
|
|
|
$
|
211,940
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
|
323,205
|
|
|
|
|
113,227
|
|
|
|
|
26,593
|
|
|
|
|
173,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin(1)
|
|
|
$
|
43,143
|
|
|
|
$
|
29,905
|
|
|
|
$
|
6,240
|
|
|
|
$
|
38,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
|
13,423
|
|
|
|
|
10,331
|
|
|
|
|
1,594
|
|
|
|
|
12,187
|
|
Selling, general and administrative expenses(2)
|
|
|
|
8,618
|
|
|
|
|
8,577
|
|
|
|
|
1,346
|
|
|
|
|
8,854
|
|
One-time transaction costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,404
|
|
|
|
|
303
|
|
Depreciation expense
|
|
|
|
13,481
|
|
|
|
|
12,630
|
|
|
|
|
2,978
|
|
|
|
|
20,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
|
35,522
|
|
|
|
|
31,538
|
|
|
|
|
12,322
|
|
|
|
|
41,357
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
|
7,621
|
|
|
|
|
(1,633
|
)
|
|
|
|
(6,082
|
)
|
|
|
|
(3,238
|
)
|
Interest expense
|
|
|
|
5,747
|
|
|
|
|
3,728
|
|
|
|
|
910
|
|
|
|
|
5,406
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income) expenses
|
|
|
|
(854
|
)
|
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
2,728
|
|
|
|
$
|
(5,337
|
)
|
|
|
$
|
(6,992
|
)
|
|
|
$
|
(8,644
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Other Financial Data:
|
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|
|
|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(3)
|
|
|
$
|
21,956
|
|
|
|
$
|
11,021
|
|
|
|
$
|
3,450
|
|
|
|
$
|
18,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
(1) |
|
For a definition of gross margin and a reconciliation to its
most directly comparable financial measure calculated and
presented in accordance with GAAP, please read Selected
Historical Financial and Operating Data
Non-GAAP Financial Measures, and for a discussion of
how we use gross margin to evaluate our operating performance,
please read How We Evaluate Our
Operations. |
|
(2) |
|
Includes LTIP expenses for the period from August 20, 2009
to December 31, 2009 and the year ended December 31,
2010 of $0.2 million and $1.7 million, respectively.
Of these amounts, $0.2 million and $1.2 million,
respectively, represent non-cash expenses. |
|
(3) |
|
For a definition of adjusted EBITDA and a reconciliation to its
most directly comparable financial measure calculated and
presented in accordance with GAAP, please read Selected
Historical Financial and Operating Data Non-GAAP
Financial Measures, and for a discussion of how we use
adjusted EBITDA to evaluate our operating performance, please
read How We Evaluate Our Operations. |
Year
Ended December 31, 2010 Compared to the 2009 Successor
Period and the 2009 Predecessor Period
Revenue. Our total revenue in 2010 was
$211.9 million compared to $32.8 million and
$143.1 million in the 2009 Successor Period and the 2009
Predecessor Period, respectively. This increase was primarily
due to higher realized NGL prices in our Gathering and
Processing segment and a new fixed-margin contract in our
Transmission segment. Under our fixed-margin contracts, we
purchase natural gas from producers or suppliers at receipt
points on our systems at an index price less a fixed
transportation fee and simultaneously sell an identical quantity
of natural gas at delivery points on our systems at the same
undiscounted index price. This increase was partially offset by
lower throughput and processing volumes in our Gathering and
Processing segment and lower NGL production.
Purchases of Natural Gas, NGLs and
Condensate. Our purchases of natural gas,
NGLs and condensate for 2010 were $173.8 million compared
to $26.6 million and $113.2 million in the 2009
Successor Period and
88
the 2009 Predecessor Period, respectively. This increase was
primarily the result of a new fixed-margin contract in our
Transmission segment and higher realized NGL prices in our
Gathering and Processing segment, and was partially offset by
lower throughput and processing volumes in our Gathering and
Processing segment.
Gross Margin. Gross margin in 2010 was
$38.1 million, compared to $6.2 million and
$29.9 million in the 2009 Successor Period and the 2009
Predecessor Period, respectively. This increase was primarily
due to higher realized NGL prices in our Gathering and
Processing segment, which positively impacted the segment gross
margin associated with our
percent-of-proceeds
arrangements, and was partially offset by lower throughput and
processing volumes in our Gathering and Processing segment. In
addition, segment gross margin in our Transmission segment was
higher in 2010 due to increased throughput volumes on our
regulated pipelines as a result of colder weather. The increases
in revenue and purchases of natural gas, NGLs and condensate
that were driven by higher realized commodity prices and the new
fixed-margin contract in our Transmission segment had minimal
impact on gross margin.
Direct Operating Expenses. Direct
operating expenses in 2010 were $12.2 million, compared to
$1.6 million and $10.3 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. This
increase was primarily due to higher fixed costs, such as
insurance and higher maintenance expenses that we incurred
following our acquisition of our assets in our Transmission
segment, partially offset by lower outside services costs in our
Gathering and Processing segment.
Selling, General and Administrative
Expenses. SG&A expenses in 2010 were
$8.9 million, compared to $1.3 million and
$8.6 million in the 2009 Successor Period and the 2009
Predecessor Period, respectively. SG&A expenses include
LTIP expenses of $1.7 million and $0.2 million in 2010
and the 2009 Successor Period, respectively. Because we adopted
the LTIP in November 2009, there were no LTIP expenses in the
2009 Predecessor Period. The decrease in SG&A expenses was
a result of our incurrence of actual SG&A expenses compared
to the historical allocation of SG&A expenses by the owner
of our Predecessor, but was offset in part by increases in LTIP
expenses due to an increase in the number of phantom units
granted in 2010.
One-Time Transaction Expenses. We
incurred approximately $6.4 million of one-time expenses,
including legal, consulting and accounting fees in the 2009
Successor Period in connection with our acquisition of our
assets. An additional $0.3 million was recorded in 2010
primarily related to Predecessor audit fees and remaining asset
valuation costs.
Depreciation Expense. Depreciation
expense was $20.0 million in 2010 compared to
$3.0 million and $12.6 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. We
recorded our assets at fair value, which was less than our
Predecessors book value of those assets, and their useful
lives were also decreased, which had the net effect of
increasing the depreciation expense associated with our assets
after the acquisition date. The increase in depreciation expense
from 2009 to 2010 is attributable to those adjustments.
The
2009 Successor Period and the 2009 Predecessor Period Compared
to Year Ended December 31, 2008
Revenue. Our total revenue was
$32.8 million and $143.1 million for the 2009
Successor Period and the 2009 Predecessor Period, respectively,
compared to $366.3 million for 2008. This decrease was
primarily due to lower realized natural gas, NGL and condensate
prices as well as lower plant inlet volumes and NGL production
in our Gathering and Processing segment, although this decrease
was partially offset by an increase in volumes gathered pursuant
to fee-based and fixed-margin arrangements.
Purchases of Natural Gas, NGLs and
Condensate. Our total purchases of natural
gas, NGLs and condensate were $26.6 million and
$113.2 million for the 2009 Successor Period and the 2009
Predecessor Period, respectively, compared to
$323.2 million for 2008. This decrease was primarily due to
lower throughput and processing volumes on our Bazor Ridge and
Alabama Processing systems, as well as lower realized natural
gas, NGL and condensate prices in our Gathering and Processing
segment.
Gross Margin. Gross margin was
$6.2 million and $29.9 million for the 2009 Successor
Period and the 2009 Predecessor Period, respectively, compared
to $43.1 million for 2008. This decrease was primarily due
to lower realized natural gas and NGL prices, which negatively
impacted the segment gross margin associated
89
with our
percent-of-proceeds
arrangements in the Gathering and Processing segment, but was
partially offset by higher throughput volumes on the Quivira
system. In addition, segment gross margin was lower in the
Transmission segment primarily as a result of the full-year
impact of the change in the terms of a contract on our Midla
system to more accurately reflect market rates between our
Predecessor and an affiliate of our Predecessor.
Direct Operating Expenses. Direct
operating expenses were $1.6 million and $10.3 million
for the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to $13.4 million for 2008. This
decrease was mainly due to the timing of our Predecessors
2008 expenditures in connection with a multi-year integrity
management program.
Selling, General and Administrative
Expenses. SG&A expenses were
$1.3 million and $8.6 million for the 2009 Successor
Period and the 2009 Predecessor Period, respectively, compared
to $8.6 million for 2008. This increase in SG&A
expenses was primarily due to additional costs allocated to our
Predecessor during the 2009 Predecessor Period. Moreover,
SG&A expenses include $0.2 million of LTIP expenses
for the 2009 Successor Period. We adopted the LTIP in November
2009 and, as a result, there were no LTIP expenses for the 2009
Predecessor Period or any period prior to our formation.
One-Time Transaction Expenses. We
incurred approximately $6.4 million of one-time expenses,
including legal, consulting and accounting fees in the 2009
Successor Period, in connection with our formation and
acquisition of our assets.
Depreciation Expense. Depreciation
expense was $3.0 million and $12.6 million for the
2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to $13.5 million for 2008. We
recorded our assets at fair value, which was less than our
Predecessors book value of those assets, and their useful
lives were also decreased, which had the net effect of
increasing the depreciation expense associated with our assets
after the acquisition date. This increase in depreciation
expense was primarily due to those adjustments.
90
Segment
Results
The table below contains key segment performance indicators
related to our discussion of the results of operations of our
segments.
|
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|
|
|
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|
|
American Midstream
|
|
|
|
|
American Midstream Partners
|
|
|
|
Partners, LP and Subsidiaries
|
|
|
|
|
Predecessor
|
|
|
|
(Successor)
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
August 20,
|
|
|
|
|
|
|
|
|
Year
|
|
|
|
10 Months
|
|
|
|
2009
|
|
|
|
Year
|
|
|
|
|
Ended
|
|
|
|
Ended
|
|
|
|
(Inception Date) to
|
|
|
|
Ended
|
|
|
|
|
December 31,
|
|
|
|
October 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
|
2008
|
|
|
|
2009
|
|
|
|
2009
|
|
|
|
2010
|
|
|
|
|
(in thousands, except operating data)
|
|
|
|
|
Segment Financial and Operating Data:
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
$
|
349,861
|
|
|
|
$
|
132,957
|
|
|
|
$
|
27,857
|
|
|
|
$
|
158,455
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
|
322,507
|
|
|
|
|
112,933
|
|
|
|
|
24,159
|
|
|
|
|
133,860
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin
|
|
|
$
|
27,354
|
|
|
|
$
|
20,024
|
|
|
|
$
|
3,698
|
|
|
|
$
|
24,595
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
$
|
8,186
|
|
|
|
$
|
7,134
|
|
|
|
$
|
956
|
|
|
|
$
|
7,721
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
179.2
|
|
|
|
|
211.8
|
|
|
|
|
169.7
|
|
|
|
|
175.6
|
|
Plant inlet volume
(MMcf/d)(1)
|
|
|
|
12.5
|
|
|
|
|
11.7
|
|
|
|
|
11.4
|
|
|
|
|
9.9
|
|
Gross NGL production (Mgal/d)(1)
|
|
|
|
40.2
|
|
|
|
|
39.3
|
|
|
|
|
38.2
|
|
|
|
|
34.1
|
|
Transmission segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
$
|
16,487
|
|
|
|
$
|
10,175
|
|
|
|
$
|
4,976
|
|
|
|
$
|
53,485
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
|
698
|
|
|
|
|
294
|
|
|
|
|
2,434
|
|
|
|
|
39,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment gross margin
|
|
|
$
|
15,789
|
|
|
|
$
|
9,881
|
|
|
|
$
|
2,542
|
|
|
|
$
|
13,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
$
|
5,237
|
|
|
|
$
|
3,197
|
|
|
|
$
|
638
|
|
|
|
$
|
4,466
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
336.2
|
|
|
|
|
357.6
|
|
|
|
|
381.3
|
|
|
|
|
350.2
|
|
Firm transportation
capacity reservation
(MMcf/d)
|
|
|
|
627.3
|
|
|
|
|
613.2
|
|
|
|
|
701.0
|
|
|
|
|
677.6
|
|
Interruptible transportation
throughput
(MMcf/d)
|
|
|
|
141.6
|
|
|
|
|
121.0
|
|
|
|
|
118.0
|
|
|
|
|
80.9
|
|
|
|
|
(1) |
|
Excludes volumes and gross production under our elective
processing arrangements. |
Year
Ended December 31, 2010 Compared to the 2009 Successor
Period and the 2009 Predecessor Period
Gathering
and Processing Segment
Revenue. Segment revenue for 2010 was
$158.5 million compared to $27.9 million and
$133.0 million in the 2009 Successor Period and the 2009
Predecessor Period, respectively. The following factors
contributed to this change in revenue:
|
|
|
|
|
Total natural gas throughput volumes on our Gathering and
Processing segment were
175.6 MMcf/d
in 2010 compared to
169.7 MMcf/d
and
211.8 MMcf/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively. Natural gas inlet volumes at our owned processing
plants were
9.9 MMcf/d
in 2010 compared to
11.4 MMcf/d
and
11.7 MMcf/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively. Gross NGL production volumes from our owned
processing plants
|
91
|
|
|
|
|
were 34.1 Mgal/d in 2010 compared to 38.2 Mgal/d and 39.3 Mgal/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively. The decrease in revenue in our Gathering and
Processing segment was mainly due to decreased throughput and
processing volumes of natural gas across certain of our systems
due to low drilling activity driven by a reduced commodity price
environment and natural declines of connected wells, as well as
decreased throughput and processing volumes on our Bazor Ridge
system due to unplanned downtime caused by the pipeline rupture
that occurred in April 2010. Please see Risk
Factors Risks Related to Our Business
Our business involves many hazards and operational risks, some
of which may not be fully covered by insurance. If a significant
accident or event occurs for which we are not adequately
insured, our operations and financial results could be adversely
affected for more information regarding the Bazor Ridge
pipeline rupture. This decrease in revenue was partially offset
by higher realized NGL prices across this segment.
|
|
|
|
|
|
The average NYMEX daily settlement price of natural gas in 2010
was $4.39/MMBtu, compared to $5.02/MMBtu and $3.99/MMBtu for the
2009 Successor Period and the 2009 Predecessor Period,
respectively. The average NYMEX daily settlement price in 2010
of WTI crude oil, to which NGL prices are generally positively
correlated, was $79.52/Bbl, compared to $76.30/Bbl and
$58.94/Bbl for the 2009 Successor Period and the 2009
Predecessor Period, respectively.
|
|
|
|
Our hedges had no effect on our revenue for the year ended
December 31, 2010. We and our Predecessor had no hedges
during the 2009 Successor Period and 2009 Predecessor Period,
respectively.
|
Purchases of Natural Gas, NGLs and
Condensate. Purchases of natural gas, NGLs
and condensate for 2010 were $133.9 million compared to
$24.2 million and $112.9 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. This
decrease in purchases of natural gas, NGLs and condensate was
primarily driven by lower throughput and processing volumes on
our Bazor Ridge system and lower fixed-margin volumes on our
Lafitte system, partially offset by higher realized NGL prices
across the segment.
Segment Gross Margin. Segment gross
margin for 2010 was $24.6 million compared to
$3.7 million and $20.0 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. This
increase was largely due to higher realized NGL prices that had
a positive impact on segment gross margin associated with
percent-of-proceeds
contracts on our Bazor Ridge and Gloria systems. In addition,
natural gas prices were lower in 2010, which had a net positive
impact on natural gas we processed under our elective processing
arrangements. We also received additional segment gross margin
associated with the construction of our Atmore processing plant
that commenced operation in June 2010. This increase was
partially offset by lower throughput volumes across most of our
gathering systems due to well declines and reduced drilling
activity due to lower natural gas prices as well as lower
volumes on our Bazor Ridge system largely resulting from a
pipeline rupture. Segment gross margin for the Gathering and
Processing segment represented 64.5% of our gross margin for
2010, compared to 59.3% and 67.0%, respectively, for the 2009
Successor Period and the 2009 Predecessor Period.
Direct Operating Expenses. Direct
operating expenses for 2010 were $7.7 million compared to
$1.0 million and $7.1 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. This
decrease in direct operating expenses was primarily due to lower
outside services costs.
Transmission
Segment
Revenue. Segment revenue for 2010 was
$53.5 million compared to $5.0 million and
$10.2 million in the 2009 Successor Period and the 2009
Predecessor Period, respectively. Total natural gas throughput
on our Transmission systems for 2010 was
350.2 MMcf/d
compared to
381.3 MMcf/d
and
357.6 MMcf/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively. This increase in revenue was primarily due to the
new fixed-margin contract in our Transmission segment under
which we purchase and simultaneously sell the natural gas that
we transport, as opposed to typical contracts in this segment in
which we receive a fixed fee for transporting natural gas. This
increase in revenue was partially offset by a decrease in
volumes transported pursuant to fee-based and fixed-margin
arrangements. Our hedges had no effect on our revenue for the
year
92
ended December 31, 2010. We and our Predecessor had no
hedges during the 2009 Successor Period and 2009 Predecessor
Period, respectively.
Purchases of Natural Gas, NGLs and
Condensate. Purchases of natural gas, NGLs
and condensate for 2010 were $40.0 million compared to
$2.4 million and $0.3 million in the 2009 Successor
Period and 2009 Predecessor Period, respectively. As part of our
fixed-margin arrangements, we purchase natural gas, but not NGLs
or condensate, in our Transmission segment. This increase was
primarily due to the new fixed-margin arrangement on our MLGT
system.
Segment Gross Margin. Segment gross
margin for 2010 was $13.5 million compared to
$2.5 million and $9.9 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. This
increase was primarily due to an increase in seasonally-adjusted
rates and reservation volumes as a result of colder weather in
markets served by our AlaTenn and Midla systems. During periods
of unseasonably cold weather, some shippers exceeded their
maximum contract quantities and had to secure higher priced
transport capacity to meet demand, thereby increasing our
segment gross margin. Segment gross margin in our Transmission
segment represented 35.5% of our gross margin for 2010, compared
to 40.7% and 33.0% for the 2009 Successor Period and the 2009
Predecessor Period, respectively.
Direct Operating Expenses. Direct
operating expenses for 2010 were $4.5 million compared to
$0.6 million and $3.2 million in the 2009 Successor
Period and the 2009 Predecessor Period, respectively. This
increase was primarily due to incremental insurance costs that
we had to incur and allocate to our assets.
The
2009 Successor Period and the 2009 Predecessor Period Compared
to Year Ended December 31, 2008
Gathering
and Processing Segment
Revenue. Segment revenue was
$27.9 million and $133.0 million for the 2009
Successor Period and the 2009 Predecessor Period, respectively,
compared to $349.9 million for 2008. The following factors
contributed to this change in revenue:
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Total natural gas throughput volumes on our Gathering and
Processing segment were
169.7 MMcf/d
and
211.8 MMcf/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to
179.2 MMcf/d
in 2008. Natural gas inlet volumes at our owned processing
plants were
11.4 MMcf/d
and
11.7 MMcf/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to
12.5 MMcf/d
in 2008. Gross NGL production volumes at our owned processing
plants were 38.2 Mgal/d and 39.3 Mgal/d in the 2009 Successor
Period and the 2009 Predecessor Period, respectively, compared
to 40.2 Mgal/d in 2008. The decline in plant inlet volumes and
NGL production was mainly due to lower throughput on our Bazor
Ridge and Alabama Processing systems, resulting from reductions
in drilling activity and demand as a result of the low commodity
price environment. This decline was partially offset by an
increase in natural gas throughput volumes on the Quivira system.
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The average NYMEX daily settlement price of natural gas was
$5.02/MMBtu and $3.99/MMBtu for the 2009 Successor Period and
the 2009 Predecessor Period, respectively, compared to
$8.90/MMBtu in 2008. The average NYMEX daily settlement price of
WTI crude oil, to which NGL prices are generally positively
correlated, was $76.30/Bbl and $58.94/Bbl for the 2009 Successor
Period and the 2009 Predecessor Period, respectively, compared
to $99.65/Bbl in 2008. This significant decrease in commodity
prices was responsible for the majority of the decrease in
revenue.
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Purchases of Natural Gas, NGLs and
Condensate. Purchases of natural gas, NGLs
and condensate were $24.2 million and $112.9 million
for the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to $322.5 million for 2008. This
decrease in purchases of natural gas, NGLs and condensate was
primarily driven by lower processing volumes as well as lower
realized natural gas, NGL and condensate prices.
Segment Gross Margin. Segment gross
margin was $3.7 million and $20.0 million for the 2009
Successor Period and the 2009 Predecessor Period, respectively,
compared to $27.4 million for 2008. This decrease was
mainly due to lower realized NGL and natural gas prices on our
Gloria and Bazor Ridge systems, partially offset by increased
throughput volumes on the Lafitte and Quivira systems due to an
93
increase in drilling activity during the high commodity price
environment in 2008. Segment gross margin for the Gathering and
Processing segment represented 59.3% and 67.0% of our gross
margin for the 2009 Successor Period and the 2009 Predecessor
Period, respectively, compared to 63.4% for 2008.
Transmission
Segment
Revenue. Segment revenue was
$5.0 million and $10.2 million for the 2009 Successor
Period and the 2009 Predecessor Period, respectively, compared
to $16.5 million for 2008. Total natural gas throughput on
our Transmission system was
381.3 MMcf/d
and
357.6 MMcf/d
in the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to
336.2 MMcf/d
in 2008. Despite the increase in throughput, our segment revenue
declined due to a reduction in firm and interruptible
transportation revenue across the segment, specifically caused
by the full-year impact of the change in the terms of a contract
on our Midla system to more accurately reflect market rates
between our Predecessor and an affiliate of our Predecessor.
Purchases of Natural Gas, NGLs and
Condensate. Purchases of natural gas, NGLs
and condensate were $2.4 million and $0.3 million in
the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to $0.7 million for 2008. As part of
our fixed-margin arrangements, we purchase natural gas, but not
NGLs or condensate, in our Transmission segment. This increase
was primarily driven by a new fixed-margin arrangement.
Segment Gross Margin. Segment gross
margin was $2.5 million and $9.9 million for the 2009
Successor Period and the 2009 Predecessor Period, respectively,
compared to $15.8 million for 2008. The decrease was
primarily a result of the full-year impact of the change in the
terms of a contract on our Midla system to more accurately
reflect market rates between our Predecessor and an affiliate of
our Predecessor. This decrease was partially offset by an
increase in transportation volumes due to weather-related demand
in markets served by the AlaTenn and Midla systems. Segment
gross margin for the Transmission segment represented 40.7% and
33.0% of our gross margin for the 2009 Successor Period and the
2009 Predecessor Period, respectively, compared to 36.6% for
2008.
Direct Operating Expenses. Direct
operating expenses were $0.6 million and $3.2 million
for the 2009 Successor Period and the 2009 Predecessor Period,
respectively, compared to $5.2 million for 2008. This
reduction in direct operating expenses was primarily due to the
timing of expenditures in connection with a multi-year integrity
management program undertaken by our Predecessor.
Liquidity
and Capital Resources
Since the acquisition of our assets in November 2009, our
sources of liquidity have included cash generated from
operations, equity investments by AIM Midstream Holdings and our
general partner and borrowings under our credit facility.
Following the closing of this offering, we expect our sources of
liquidity to include:
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cash generated from operations;
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borrowings under our new credit facility; and
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issuances of debt and equity securities.
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We believe that the cash generated from these sources will be
sufficient to allow us to distribute (i) the minimum quarterly
distribution on all of our outstanding common and subordinated
units and (ii) the corresponding distribution on our 2.0%
general partner interest and meet our requirements for working
capital and capital expenditures for the foreseeable future.
Working
Capital
Working capital is the amount by which current assets exceed
current liabilities and is a measure of our ability to pay our
liabilities as they become due. Our working capital was
($4.5) million at December 31, 2010
94
compared to ($2.4) million at December 31, 2009,
$28.6 million at October 31, 2009 and ($3.1) million
at December 31, 2008.
The $2.1 million decrease in working capital from
December 31, 2009 to December 31, 2010 was primarily a
result of the following factors:
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an increase in the current portion of long-term debt associated
with an increased amortization payment of $6.0 million due
during 2011 compared to $5.0 million due during
2010; and
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an increase in accrued expenses and other liabilities of
approximately $0.4 million, which was primarily the result
of accrued bonus payments and unfavorable contract obligations
acquired in connection with our acquisition of our assets.
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The $31.7 million net decrease in working capital from
December 31, 2008 to October 31, 2009 was primarily
the result of the elimination of affiliate obligations in
connection with our acquisition of our assets in 2009.
Cash
Flows
The following table reflects cash flows for the applicable
periods:
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American Midstream Partners, LP and
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American Midstream Partners Predecessor
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Subsidiaries (Successor)
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Period from
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August 20, 2009
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Year Ended
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10 Months Ended
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(Inception Date) to
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Year Ended
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December 31,
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October 31,
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December 31,
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December 31,
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2008
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2009
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2009
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2010
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(in thousands)
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Net cash provided by (used in):
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Operating activities
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$
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18,155
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$
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14,589
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$
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(6,531
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)
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$
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13,791
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Investing activities
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(10,486
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)
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(853
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)
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(151,976
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)
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(10,268
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)
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Financing activities
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(7,929
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)
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(14,008
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)
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159,656
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(4,609
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)
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Operating Activities. Net cash provided
by (used in) operating activities was $13.8 million for the
year ended December 31, 2010 compared to
($6.5) million and $14.6 million for the 2009
Successor Period and 2009 Predecessor Period, respectively. The
change in cash provided by (used in) operating activities was
primarily a result of the combined effects of a net loss, net of
non-cash charges, in addition to net positive changes in
operating assets and liabilities.
Net cash provided by (used in) operating activities was
($6.5) million and $14.6 million for the 2009
Successor Period and 2009 Predecessor Period, respectively,
compared to $18.2 million for the year ended
December 31, 2008. The change in cash provided by (used in)
operating activities was primarily a result of the combined
effects of a net loss, net of non-cash charges, in addition to
net negative changes in operating assets and liabilities.
Investing Activities. Net cash provided
by (used in) investing activities was ($10.3) million for
the year ended December 31, 2010 compared to
($152.0) million and ($0.9) million for the 2009
Successor Period and 2009 Predecessor Period, respectively. The
change in cash used in investing activities was primarily a
result of our acquisition of our assets in November 2009 for
cash consideration of $150.8 million and the construction
of the Winchester lateral in November 2010.
Net cash provided by (used in) investing activities was
($152.0) million and ($0.9) million for the 2009
Successor Period and 2009 Predecessor Period, respectively,
compared to ($10.5) million for the year ended
December 31, 2008. The change in cash used in investing
activities was primarily a result of our acquisition of our
assets in November 2009 for cash consideration of
$150.8 million.
Financing Activities. Net cash provided
by (used in) financing activities was ($4.6) million for
the year ended December 31, 2010 compared to
$159.7 million and ($14.0) million for the 2009
Successor Period and 2009 Predecessor Period, respectively. The
change in cash provided by (used in) financing activities was
primarily a result of net borrowings under our credit facility
of $61.0 million and a capital contribution of
$100.0 million by
95
AIM Midstream Holdings in connection with our acquisition of our
assets and funding our initial working capital requirements in
November 2009. During the year ended December 31, 2010, AIM
Midstream Holdings contributed an additional $12.0 million
to us, we made approximately $5.0 million of amortization
payments under the term loan portion of our existing credit
facility and we made distributions of $11.8 million to our
unitholders.
Net cash provided by (used in) financing activities was
$159.7 million and ($14.0) million for the 2009
Successor Period and 2009 Predecessor Period, respectively,
compared to ($7.9) million for the year ended
December 31, 2008. The change in net cash provided by (used
in) financing activities was primarily a result of net
borrowings under our credit facility of $61.0 million and a
capital contribution of $100.0 million by AIM Midstream
Holdings in connection with our acquisition of our assets and
funding our initial working capital requirements in November
2009.
Off-Balance
Sheet Arrangements
We do not have any off-balance sheet arrangements.
Capital
Requirements
The midstream energy business can be capital intensive,
requiring significant investment for the maintenance of existing
assets or acquisition or development of new systems and
facilities. We categorize our capital expenditures as either:
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maintenance capital expenditures, which are cash expenditures
(including expenditures for the addition or improvement to, or
the replacement of, our capital assets or for the acquisition of
existing, or the construction or development of new, capital
assets) made to maintain our long-term operating income or
operating capacity; or
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expansion capital expenditures, which are cash expenditures
incurred for acquisitions or capital improvements that we expect
will increase our operating income or operating capacity over
the long term.
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Historically, our maintenance capital expenditures have not
included all capital expenditures required to maintain volumes
on our systems. It is customary in the regions in which we
operate for producers to bear the cost of well connections, but
we cannot be assured that this will be the case in the future.
For the year ended December 31, 2010, our capital
expenditures totaled $10.3 million. For this period,
capital expenditures included maintenance capital expenditures
and expansion capital expenditures. We estimate that 14.3% of
our capital expenditures, or $1.5 million, were maintenance
capital expenditures and that 85.7% of our capital expenditures,
or $8.8 million, were expansion capital expenditures.
Although we classified our capital expenditures as maintenance
capital expenditures and expansion capital expenditures, we
believe those classifications approximate, but do not
necessarily correspond to, the definitions of estimated
maintenance capital expenditures and expansion capital
expenditures under our partnership agreement. While we expect
that in the future expansion capital expenditures will primarily
be funded through borrowings or the sale of debt or equity
securities, we funded our expansion capital expenditures during
the year ended December 31, 2010 through a capital
contribution made to us by AIM Midstream Holdings and our
general partner.
We have budgeted $3.2 million in capital expenditures for
the year ending December 31, 2011, of which
$0.2 million represents expansion capital expenditures and
$3.0 million represents maintenance capital expenditures.
At December 31, 2010, we had no budgeted expansion capital
expenditures for 2011. However, in February 2011, our general
partners board of directors approved a $0.2 million
upgrade on our existing Gloria compressor that we expect to
increase throughput capacity on the Gloria system and be
completed in 2011.
Our 2010 expansion capital expenditures were $8.8 million
and our maintenance capital expenditures were $1.5 million.
Our expansion capital expenditures during 2010 included:
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the construction of the Winchester lateral on our Bazor Ridge
system for $3.9 million, effectively upgrading the system
and increasing the effective operating capacity of that system;
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96
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the construction of a strategic interconnect between our Lafitte
system and TGP for $1.4 million, which allows us to move
gas from TGP onto our Lafitte and Gloria systems for processing
and delivery to customers downstream;
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the movement and recommissioning of the Atmore processing
facility to serve a producer customer for
$0.8 million; and
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$2.7 million of expansion capital expenditures comprised of
approximately 25 small capital projects.
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In addition to our budgeted capital projects, we intend to use a
portion of the net proceeds from this offering to establish a
cash reserve of $2.2 million related to non-recurring
deferred maintenance capital expenditures for the
twelve months ending June 30, 2012.
We anticipate that we will continue to make significant
expansion capital expenditures in the future. Consequently, our
ability to develop and maintain sources of funds to meet our
capital requirements is critical to our ability to meet our
growth objectives. We expect that our future expansion capital
expenditures will be funded by borrowings under our new credit
facility and the issuance of debt and equity securities.
Integrity
Management
When we acquired our operating assets from Enbridge, we
inherited an ongoing integrity management program required under
regulations of the U.S. Department of Transportation, or
DOT. These regulations require transportation pipeline operators
to implement continuous integrity management programs over a
seven-year cycle. Our current program will be completed in 2012.
In connection with the acquisition of our assets from Enbridge
we initiated a comprehensive review of the program and concluded
that there were sixteen high consequence areas, or HCAs, in
addition to those identified by our Predecessor that required
further testing pursuant to DOT regulations. We expect to incur
$2.1 million in integrity management expenses in 2012
associated with these HCAs to complete the current integrity
management program.
Beginning in 2013 we will begin a new integrity management
program during which we expect to incur an average of
$1.5 million in integrity management expenses per year over
the course of the seven-year cycle. Because DOT regulations
require integrity management activities for each HCA to be
performed within seven years from when they were last performed,
we expect to incur the following expenses:
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Year
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Integrity Management Expense
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(in thousands)
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2013
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$
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2,000
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2014
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5,015
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2015
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839
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2016
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675
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2017
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0
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2018
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0
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2019
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2,080
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Total
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$
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10,609
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In conjunction with the commencement of our next seven-year
integrity management program cycle in 2013, we plan to request
the DOTs consent to a modification of the timing of our
integrity management expenses so that we spend approximately
$1.5 million each year.
Distributions
We intend to pay a quarterly distribution at an initial rate of
$ per unit, which equates to an
aggregate distribution of
$ million per quarter, or
$ million on an annualized
basis, based on the number of common and subordinated units
anticipated to be outstanding immediately after the closing of
this offering, as well as our 2.0% general partner interest. We
do not have a legal obligation to make distributions except as
provided in our partnership agreement.
97
Our
Credit Facility
On November 4, 2009, we entered into our current
$85.0 million secured credit facility with a syndicate of
lending institutions. The credit facility is composed of a
$50.0 million term loan facility and a $35.0 million
revolving credit facility, which includes a
sub-limit of
up to $5.0 million for
same-day
swing line advances and a
sub-limit of
up to $10.0 million for letters of credit. Borrowings under
our revolving or term loan facility bear interest at a variable
rate per annum equal to the Base Rate or Eurodollar-based Rate,
as the case may be, plus the Applicable Margin. Base Rate,
Eurodollar-based Rate, Applicable Margin, Total Debt, and
Consolidated EBITDA are each defined in the credit agreement
that evidences our current facility. Our obligations under our
current credit facility are secured by a lien on and a security
interest in all of our personal property and our real property
with an aggregate value equal to at least eighty percent (80%)
of the total value of all of our real property. The terms of our
credit facility contain customary covenants, including those
that restrict our ability to make certain payments,
distributions, acquisitions, loans, or investments, incur
certain indebtednesses or create certain liens on our assets,
consolidate or enter into mergers, dispose of certain of our
assets, engage in certain types of transactions with our
affiliates, enter into certain sale/leaseback transactions and
modify certain material agreements. The remaining principal
balance of loans and any accrued and unpaid interest will be due
and payable in full on the maturity date in November 2012. As of
December 31, 2010, we were in compliance with the covenants
in our credit facility.
The events that constitute default under our current credit
facility include, among other things, the failure to pay
principal and interest on the indebtedness under our current
facility when due, failure to comply with certain covenants or
breach representations and warranties made under our current
credit facility, certain bankruptcy, dissolution, liquidation or
other insolvency events, or a change of control. In addition,
our current certain facility includes cross default provisions
with respect to indebtedness for borrowed money (other than is
borrowed under our current facility) that is in excess of
$1.0 million, individually, or in the aggregate.
In connection with our initial public offering, we plan to pay
off our existing credit facility and enter into a new
$ million revolving credit
facility. The new credit facility will mature
in ,
and borrowings will bear interest, at a variable rate per annum
equal to the lesser of LIBOR or the Base Rate, as the case may
be, plus the Applicable Margin (LIBOR, Base Rate and Applicable
Margin will each be defined in the credit agreement that
evidences our new credit facility). Under our new credit
facility, in addition to the uses described in Use of
Proceeds, we expect that borrowings may be used for
(i) the refinancing and repayment of certain existing
indebtedness, (ii) working capital and other general
partnership purposes and (iii) future capital expenditures.
Borrowings under our new credit facility will be secured by a
first-priority lien on and security interest in substantially
all of our assets. We expect the credit agreement that evidences
our new credit facility to contain customary covenants,
including restrictions on our ability to incur additional
indebtedness, make certain investments, loans or advances, make
distributions to our unitholders, make dispositions or enter
into sales and leasebacks, or enter into a merger or sale of our
property or assets, including the sale or transfer of interests
in our subsidiaries.
The events that constitute an Event of Default under our new
credit agreement are expected to be customary for loans of this
size and type.
Credit
Risk
We are subject to risks of loss resulting from nonpayment or
nonperformance by our customers to which we provide services and
sell commodities. Our three largest purchasers of natural gas in
our Gathering and Processing segment are ConocoPhillips,
Enbridge Marketing (U.S.) L.P. and Dow Hydrocarbons and
Resources and accounted for approximately 41%, 29% and 10%,
respectively, of our segment revenue for the year ended
December 31, 2010. Additionally, ExxonMobil and Calpine
Corporation are the two largest purchasers of natural gas and
transmission capacity, respectively, in our Transmission segment
and accounted for approximately 43% and 10%, respectively, of
our segment revenue for the year ended December 31, 2010.
We examine the creditworthiness of third-party customers to whom
we extend credit and manage our exposure to credit risk through
credit analysis, credit approval, credit limits and monitoring
procedures, and for certain transactions, we may request letters
of credit, prepayments or guarantees.
98
Customer
Concentration
A significant percentage of the gross margin in each of our
segments is attributable to a relatively small number of
customers. In our Gathering and Processing segment, Contango
Operators Inc. and Venture Oil & Gas Co. accounted for
approximately 16% and 17%, respectively, of our segment gross
margin for the year ended December 31, 2010. In our
Transmission segment, Calpine Corporation accounted for
approximately 38% of our segment gross margin for the year ended
December 31, 2010. Although we have gathering, processing
or transmission contracts with each of these customers of
varying duration, if one or more of these customers were to
default on their contract or if we were unable to renew our
contract with one or more of these customers on favorable terms,
we may not be able to replace any of these customers in a timely
fashion, on favorable terms or at all. In any of these
situations, our gross margin and cash flows and our ability to
make cash distributions to our unitholders may be adversely
affected. We expect our exposure to concentrated risk of
non-payment or non-performance to continue as long as we remain
substantially dependent on a relatively small number of
customers for a substantial portion of our gross margin.
Contractual
Obligations
The table below summarizes our contractual obligations and other
commitments as of December 31, 2010:
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Less Than
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1-3
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More Than
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Contractual Obligation
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Total
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1 Year
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Years
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3-5 Years
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5 Years
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(in thousands)
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|
|
|
|
|
|
Long-term debt(1)
|
|
$
|
56,370
|
|
|
$
|
6,000
|
|
|
$
|
50,370
|
|
|
$
|
|
|
|
$
|
|
|
Rights-of-way and operating leases
|
|
|
2,057
|
|
|
|
580
|
|
|
|
747
|
|
|
|
700
|
|
|
|
30
|
|
Asset retirement obligations
|
|
|
8,340
|
|
|
|
914
|
|
|
|
|
|
|
|
|
|
|
|
7,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
66,767
|
|
|
$
|
7,494
|
|
|
$
|
51,117
|
|
|
$
|
700
|
|
|
$
|
7,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Upon the closing of this offering, we expect to incur long-term
debt under our new credit facility of
$ million, which will be
used, together with the net proceeds of this offering, to make a
distribution to AIM Midstream Holdings as described in Use
of Proceeds. We expect the initial interest rate under our
new credit facility to be %.
|
Quantitative
and Qualitative Disclosures about Market Risk
Commodity
Price Risk
We are exposed to the impact of market fluctuations in the
prices of natural gas, NGLs and condensate in our Gathering and
Processing segment. Both our profitability and our cash flow are
affected by volatility in the prices of these commodities.
Natural gas and NGL prices are impacted by changes in the supply
and demand for natural gas and NGLs, as well as market
uncertainty. For a discussion of the volatility of natural gas
and NGL prices, please read Risk Factors. Adverse
effects on our cash flow from reductions in natural gas and NGL
product prices could adversely affect our ability to make
distributions to unitholders. We manage this commodity price
exposure through an integrated strategy that includes management
of our contract portfolio, optimization of our assets, and the
use of derivative contracts. Our overall direct exposure to
movements in natural gas prices is minimal as a result of
natural hedges inherent in our current contract portfolio.
Natural gas prices, however, can also affect our profitability
indirectly by influencing the level of drilling activity in our
areas of operation. We are a net seller of NGLs, and as such our
financial results are exposed to fluctuations in NGLs pricing.
In January 2011, we implemented a hedging program by entering
into a number of financial hedges to protect our expected NGL
production through mid 2012. Through our 2011 hedge
transactions, we executed swap and put contracts settled against
ethane, propane, butane and natural gasoline market prices.
Pursuant to our 2011 hedge transactions, we have hedged
approximately 86% of our expected exposure to NGL prices in
2011, and approximately 49% in 2012.
99
In June 2010, prior to our entry into our 2011 hedge
transactions, we executed a series of put contracts settled
against a basket of NGLs. Under these put contracts, we receive
a fixed floor price of $1.03 per gallon on 13,212 gal/d of a
negotiated NGL and liquids basket, which included ethane,
propane, iso-butane, normal butane, natural gasoline and WTI
crude oil. The relative weightings of the price of each
component of the basket are calculated via an arithmetic
formula. Based on the current commodity price environment, these
hedges are currently out of the money.
The table below sets forth certain information regarding our NGL
fixed swaps as of December 31, 2010 and March 18, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Average Price
|
|
Fair Market Value
|
|
|
|
|
|
Volumes
|
|
|
($/gal)
|
|
December 31,
|
|
|
March 18,
|
|
Commodity
|
|
Period
|
|
(gal/d)
|
|
|
We Receive
|
|
|
We Pay
|
|
2010
|
|
|
2011
|
|
|
Ethane
|
|
Feb 2011-Jul 2012
|
|
|
7,300
|
|
|
$
|
0.47
|
|
|
OPIS avg
|
|
|
N/A
|
|
|
$
|
(254,182
|
)
|
Propane
|
|
Feb 2011-Jul 2012
|
|
|
7,050
|
|
|
$
|
1.17
|
|
|
OPIS avg
|
|
|
N/A
|
|
|
$
|
(655,573
|
)
|
Iso-Butane
|
|
Feb 2011-Jul 2012
|
|
|
2,510
|
|
|
$
|
1.57
|
|
|
OPIS avg
|
|
|
N/A
|
|
|
$
|
(315,692
|
)
|
Normal Butane
|
|
Feb 2011-Jul 2012
|
|
|
3,000
|
|
|
$
|
1.59
|
|
|
OPIS avg
|
|
|
N/A
|
|
|
$
|
(343,988
|
)
|
Natural Gasoline
|
|
Feb 2011-Jul 2012
|
|
|
5,500
|
|
|
$
|
2.08
|
|
|
OPIS avg
|
|
|
N/A
|
|
|
$
|
(895,552
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
25,360
|
|
|
$
|
1.26
|
|
|
|
|
|
N/A
|
|
|
$
|
(2,464,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table below sets forth certain information regarding our NGL
puts as of December 31, 2010 and March 18, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Floor Strike
|
|
|
Fair Market Value
|
|
|
|
|
|
Volumes
|
|
|
Price
|
|
|
December 31,
|
|
|
March 18,
|
|
Commodity
|
|
Period
|
|
(gal/d)
|
|
|
($/gal)
|
|
|
2010
|
|
|
2011
|
|
|
NGL basket(1)
|
|
Feb 2011-Jul 2012
|
|
|
9,800
|
|
|
$
|
1.29
|
|
|
|
N/A
|
|
|
$
|
230,997
|
|
NGL basket(2)
|
|
Jun 2010-Jun 2011
|
|
|
13,212
|
|
|
$
|
1.03
|
|
|
$
|
|
|
|
$
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
23,012
|
|
|
$
|
1.14
|
|
|
$
|
|
|
|
$
|
231,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In January 2011, we entered into a put arrangement under which
we receive a fixed floor price of $1.29 per gallon on 9,800
gal/d of a negotiated NGL basket, which includes ethane,
propane, iso-butane, normal butane and natural gasoline. The
relative weightings of the price of each component of the basket
are calculated via an arithmetic formula. |
|
(2) |
|
In June 2010, we entered into a put arrangement under which we
receive a fixed floor price of $1.03 per gallon on 13,212 gal/d
of a negotiated NGL and liquids basket, which includes ethane,
propane, iso-butane, normal butane, natural gasoline and WTI
crude oil. The relative weightings of the price of each
component of the basket are calculated via an arithmetic formula. |
Interest
Rate Risk
We have exposure to changes in interest rates on our
indebtedness associated with our credit facility. In December
2009, we entered into an interest rate cap with participating
lenders with a $26.5 million notional amount at
December 31, 2010 that effectively caps our
Eurodollar-based rate exposure on that portion of our debt at a
maximum of 4.0%. We anticipate that, in conjunction with our
entry into a new credit facility contemporaneous with the
closing of this offering, we would implement similar swap or cap
structures to mitigate our exposure to interest rate risk.
The credit markets have recently experienced historical lows in
interest rates. As the overall economy strengthens, it is
possible that monetary policy will continue to tighten further,
resulting in higher interest rates to counter possible
inflation. Interest rates on floating rate credit facilities and
future debt offerings could be higher than current levels,
causing our financing costs to increase accordingly.
A hypothetical increase or decrease in interest rates by 1.0%
would have changed our interest expense by $0.6 million for
the year ended December 31, 2010.
100
Impact
of Seasonality
Results of operations in our Transmission segment are directly
affected by seasonality due to higher demand for natural gas
during the winter months, primarily driven by our LDC customers.
On our AlaTenn system, we offer some customers
seasonally-adjusted firm transportation rates that require
customers to reserve capacity at rates that are higher in the
period from October to March compared to other times of the
year. On our Midla system, we offer customers
seasonally-adjusted firm transportation reservation volumes that
allow customers to reserve more capacity during the period from
October to March compared to other times of the year. The
combination of seasonally-adjusted rates and reservation
volumes, as well as higher volumes overall, result in higher
revenue and segment gross margin in our Transmission segment
during the period from October to March compared to other times
of the year. We generally do not experience seasonality in our
Gathering and Processing segment.
Critical
Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP
requires our and our Predecessors management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenue and expenses during the period.
Actual results could differ from these estimates. The policies
and estimates discussed below are considered by our and
Predecessors management to be critical to an understanding
of the financial statements because their application requires
the most significant judgments from management in estimating
matters for financial reporting that are inherently uncertain.
See the description of our accounting policies in the notes to
the financial statements for additional information about our
critical accounting policies and estimates.
Use of Estimates. The preparation of financial
statements in accordance with accounting principles generally
accepted in the United States of America requires management to
make estimates and judgments that affect our reported financial
positions and results of operations. We review significant
estimates and judgments affecting our consolidated financial
statements on a recurring basis and record the effect of any
necessary adjustments prior to their publication. Estimates and
judgments are based on information available at the time such
estimates and judgments are made. Adjustments made with respect
to the use of these estimates and judgments often relate to
information not previously available. Uncertainties with respect
to such estimates and judgments are inherent in the preparation
of financial statements. Estimates and judgments are used in,
among other things, (1) estimating unbilled revenue and
operating and general and administrative costs,
(2) developing fair value assumptions, including estimates
of future cash flows and discount rates, (3) analyzing
tangible and intangible assets for possible impairment,
(4) estimating the useful lives of our assets and
(5) determining amounts to accrue for contingencies,
guarantees and indemnifications. Actual results could differ
materially from our estimates.
Property, Plant and Equipment. In general,
depreciation is the systematic and rational allocation of an
assets cost, less its residual value (if any), to the
period it benefits. Our property, plant and equipment is
depreciated using the straight-line method over the estimated
useful lives of the assets. The costs of renewals and
betterments which extend the useful life of property, plant and
equipment are also capitalized. The costs of repairs,
replacements and maintenance projects are expensed as incurred.
Our estimate of depreciation incorporates assumptions regarding
the useful economic lives and residual values of our assets. As
circumstances warrant, depreciation estimates are reviewed to
determine if any changes are needed. Such changes could involve
an increase or decrease in estimated useful lives or salvage
values which would impact future depreciation expense.
Impairment of Long-Lived Assets. We assess our
long-lived assets for impairment on authoritative guidance. A
long-lived asset is tested for impairment whenever events or
changes in circumstances indicate its carrying amount may exceed
its fair value. Fair values are based on the sum of the
undiscounted future cash flows expected to result from the use
and eventual disposition of the assets.
101
Examples of long-lived asset impairment indicators include:
|
|
|
|
|
a significant decrease in the market price of a long-lived asset
or asset group;
|
|
|
|
a significant adverse change in the extent or manner in which a
long-lived asset or asset group is being used or in its physical
condition;
|
|
|
|
a significant adverse change in legal factors or in the business
climate could affect the value of a long-lived asset or asset
group, including an adverse action or assessment by a regulator
which would exclude allowable costs from the rate-making process;
|
|
|
|
as accumulation of costs significantly in excess of the amount
originally expected for the for the acquisition or construction
of the long-lived asset or asset group;
|
|
|
|
a current-period operating cash flow loss combined with a
history of operating cash flow losses or a projection or
forecast that demonstrates continuing losses associated with the
use of a long-lived asset or asset group; and
|
|
|
|
a current expectation that, more likely than not, a long-lived
asset or asset group will be sold or otherwise disposed of
significantly before the end of its previously estimated useful
life.
|
We incurred no impairment charges during the year ended
December 31, 2010.
Environmental Remediation. Current accounting
guidelines require us to recognize a liability and expense
associated with environmental remediation if (i) government
agencies mandate such activities, (ii) the existence of a
liability is probable and (iii) the amount can be
reasonably estimated. As of December 31, 2010 we have
recorded no liability for remediation expenditures. If
governmental regulations change, we could be required to incur
remediation costs which may have a material impact on our
profitability.
Asset Retirement Obligations. As of
December 31, 2010, we have recorded liabilities of
$7.2 million for future asset retirement obligations
associated with our pipeline assets. Related accretion expense
has been recorded in interest expense as discussed in
Note 1 in our consolidated financial statements. The
recognition of an asset retirement obligation requires that
management make numerous estimates, assumptions and judgments
regarding such factors as costs of remediation, timing of
settlement to changes in the estimate of the costs of
remediation. Any such changes that result in upward or downward
revisions in the estimated obligation will result in an
adjustment to the related capitalized asset or corresponding
liability on a prospective basis and an adjustment in our
depreciation expense in future periods.
Revenue Recognition. We recognize revenue when
all of the following criteria are met: (1) persuasive
evidence of an exchange arrangement exists, (2) delivery
has occurred or services have been rendered, (3) the price
is fixed or determinable and (4) collectability is
reasonably assured. We record revenue and cost of product sold
on the gross basis for those transactions where we act as the
principal and take title to natural gas, NGLs or condensates
that is purchased for resale. When our customers pay us a fee
for providing a service such as gathering, treating or
transportation we record those fees separately in revenue. Under
keep-whole contracts, we keep the NGLs extracted and return the
processed natural gas or value of the natural gas to the
producer.
Natural Gas Imbalance Accounting. Quantities
of natural gas over-delivered or under-delivered related to
operational balancing agreements are recorded monthly as
inventory or as a payable using weighted average prices at the
time the imbalance was created. Monthly, gas imbalances
over-delivered are valued at the lower of cost or market; gas
imbalances under-delivered are valued at replacement cost. These
imbalances are typically settled in the following month with
deliveries of natural gas. Under the contracts, imbalance
cash-outs are recorded as a sale or purchase of natural gas, as
appropriate.
Price Risk Management Activities. We have
structured our hedging activities in order to minimize our
commodity pricing and interest rate risks and to help maintain
compliance with certain financial covenants in our credit
facility. These hedging activities rely upon forecasts of our
expected operations and financial structure through July 2012.
If our operations or financial structure are significantly
different from these forecasts, we could be subject to adverse
financial results as a result of these hedging activities. We
mitigate
102
this potential exposure by retaining an operational cushion
between our forecasted transactions and the level of hedging
activity executed.
From the inception of our hedging program in December 2009, we
used
mark-to-market
accounting for our commodity hedges and interest rate caps. We
record monthly realized gains and losses on hedge instruments
based upon cash settlements information. The settlement amounts
vary due to the volatility in the commodity market prices
throughout each month. We also record unrealized gains and
losses quarterly based upon the future value on
mark-to-market
hedges through their expiration dates. The expiration dates vary
but are currently no later than October 2012 for our interest
rate hedge and July 2012 for our commodity hedges. Costs
incurred to purchase interest rate and NGL puts are amortized
during the contract period through the unrealized risk
management instruments in total revenue. We monitor and review
hedging positions regularly.
103
INDUSTRY
OVERVIEW
General
The midstream natural gas industry provides the link between the
exploration and production of raw natural gas and the delivery
of that natural gas and its by-products to industrial,
commercial and residential end users. The principal components
of the business consist of gathering, compressing, treating,
dehydrating, processing, fractionating, transporting and
marketing natural gas and natural gas liquids, or NGLs. The
midstream industry is generally characterized by regional
competition based on the proximity of gathering systems and
processing and treating plants to natural gas producing wells.
Companies within this industry provide services at various
stages along the natural gas value chain by gathering natural
gas from producers at the wellhead, separating the hydrocarbons
into dry gas (primarily methane) and NGLs, and then routing the
separated dry gas and NGL streams to the next intermediate stage
of the value chain or to transportation pipelines for delivery
to end-markets. Transportation consists of moving
pipeline-quality natural gas from these gathering systems and
plants for delivery to customers.
The following diagram illustrates the various components of the
natural gas value chain:
Midstream
Services
The range of services provided by midstream natural gas service
providers are generally divided into the following six
categories:
Gathering. At the initial stages of the
midstream value chain, a network of typically small diameter
pipelines known as gathering systems directly connect to
wellheads in the production area. These gathering systems
transport natural gas from the wellhead to a central location
for treating and processing. A large gathering system may
involve thousands of miles of gathering lines connected to
thousands of wells. Gathering systems are typically designed to
be highly flexible to allow gathering of natural gas at
different pressures and scalable to allow for additional
production and well connections without significant incremental
capital expenditures.
Compression. Gathering systems are
operated at design pressures that maximize the total throughput
from all connected wells. Through a mechanical process known as
compression, volumes of natural gas at a given pressure are
compressed to a sufficiently higher pressure, thereby allowing
those volumes to be delivered into a higher pressure downstream
pipeline to be brought to market. Since wells produce at
progressively lower field pressures as they age, it becomes
necessary to add additional compression over time near the
wellhead to maintain throughput across the gathering system.
Treating and Dehydration. Another
process in the midstream value chain is treating and
dehydration, a step that involves the removal of impurities such
as water, carbon dioxide, nitrogen and hydrogen sulfide that may
be present when natural gas is produced at the wellhead. These
impurities must be removed for the natural gas to meet the
specifications for transportation on long-haul intrastate and
interstate pipelines. Moreover, end users will not purchase
natural gas with a high level of these impurities. To meet
downstream pipeline and end-user natural gas quality standards,
the natural gas is
104
dehydrated to remove the saturated water and is chemically
treated to separate the impurities from the gas stream.
Processing. The principal components of
natural gas are methane and ethane, but most natural gas also
contains varying amounts of other NGLs, which are heavier
hydrocarbons that are found in some natural gas streams. Even
after treating and dehydration, most natural gas is not suitable
for long-haul intrastate and interstate pipeline transportation
or commercial use because it contains NGLs. This natural gas,
referred to as rich or wet natural gas, must be processed to
remove these heavier hydrocarbon components, as well as natural
gas condensate. NGLs not only interfere with pipeline
transportation, but are also valuable commodities once removed
from the natural gas stream. The removal and separation of NGLs
usually takes place in a processing plant using industrial
processes that exploit differences in the weights, boiling
points, vapor pressures and other physical characteristics of
NGL components.
Fractionation. The mixture of NGLs that
results from natural gas processing is generally comprised of
the following five components: ethane, propane, normal butane,
iso-butane and natural gasoline. This mixture is often referred
to as y-grade or raw make NGL. Fractionation is the process by
which this mixture is separated into the NGL components prior to
their sale to various petrochemical and industrial end users.
Transmission. Once the raw natural gas
has been treated and processed, the remaining natural gas, or
residue natural gas, and NGL components are transported and
marketed to end users. The transmission of natural gas involves
the movement of pipeline-quality natural gas from gathering
systems and processing facilities to wholesalers and end users,
including industrial plants and LDCs. LDCs purchase natural gas
from transmission companies and market that natural gas to
commercial, industrial and residential end users. Transmission
pipelines generally span considerable distances and consist of
large-diameter pipelines that operate at higher pressures than
gathering pipelines to facilitate the transportation of greater
quantities of natural gas. The concentration of natural gas
production in a few regions of the U.S. generally requires
transmission pipelines to cross state borders to meet national
demand. These pipelines are referred to as interstate pipelines
and are primarily regulated by federal agencies or commissions,
including the FERC. Pipelines that transport natural gas
produced and consumed wholly within one state are generally
referred to as intrastate pipelines. Intrastate pipelines are
primarily regulated by state agencies or commissions.
Typical
Midstream Contractual Arrangements
The midstream services described above, with the exception of
transmission, are typically provided under contracts that vary
in the amount of commodity price risk they carry. The following
four contractual arrangements are the most common in the
midstream industry:
|
|
|
|
|
Fee-Based. In exchange for its
gathering, compression and treating services, the midstream
service provider receives a fee per unit of natural gas that is
gathered at the wellhead, compressed and treated. Depending on
the fee structure, producer customers may pay a single bundled
fee for gathering, treating and compressing, or those services
may be unbundled. Under fee-based arrangements, the midstream
service provider bears no direct commodity price risk, although
a sustained decline in natural gas prices may result in a
decline in volumes of natural gas for which these services are
needed.
|
|
|
|
Fixed-Margin. Under these arrangements,
the midstream service provider purchases natural gas from
producers or suppliers at receipt points on its systems at an
index price less a fixed transportation fee and simultaneously
sells an identical volume of natural gas at delivery points on
its systems at the same, undiscounted index price. By entering
into
back-to-back
purchases and sales of natural gas, the midstream service
provider is able to lock in a fixed-margin on these
transactions. These contracts are sometimes referred to as
wellhead purchase agreements.
|
|
|
|
Percent-of-Proceeds,
or POP. In exchange for its processing
services, the midstream service provider remits to a producer
customer a percentage of the proceeds from sales of residue
natural gas
and/or NGLs
that result from its processing, or in some cases, a percentage
of the physical residue natural gas
|
105
|
|
|
|
|
and/or NGLs
at the tailgate of the processing plant, retaining the balance
of the proceeds or physical commodity for its own account. These
types of arrangements expose the midstream service provider to
direct commodity price risk because the revenue from these
contracts directly correlates with the fluctuating price of
natural gas
and/or NGLs.
Moreover, the midstream service provider using a
percent-of-proceeds
arrangement will bear indirect commodity price risk in that a
sustained decline in natural gas or NGL prices may result in a
decline in volumes of natural gas for which processing services
are needed.
|
|
|
|
|
|
Keep-Whole. Keep-whole arrangements may
be used for processing services. Under these arrangements, the
midstream service provider keeps 100% of the NGLs produced, and
the processed natural gas, or value of the natural gas, is
returned to the producer customer. Since some of the natural gas
is used and removed during processing, the midstream service
provider compensates the producer customer for the amount used
and removed in processing by supplying additional natural gas or
by paying an
agreed-upon
value for the natural gas utilized. These arrangements have the
highest direct commodity price exposure for the midstream
service provider because its costs are dependent on the price of
natural gas and its revenue is based on the price of NGLs, each
of which fluctuate independently.
|
There are three primary forms of contracts utilized in the
transmission of natural gas, firm transportation contracts and
interruptible transportation contracts.
|
|
|
|
|
Firm Transportation. Firm
transportation contracts require a shipper customer to pay a
monthly reservation charge, which is a fixed charge owed
regardless of the actual pipeline capacity used by that
customer. When a shipper customer uses the capacity it has
reserved under these contracts, the midstream service provider
also collects a usage charge based on the volume of natural gas
actually transported. Usage charges generally enable the
midstream service provider to recover the variable costs of
operating the transmission system. Usage charges are typically a
small percentage of the total revenue received under firm
transportation contracts.
|
|
|
|
Interruptible
Transportation. Interruptible transportation
contracts require a shipper customer to pay fees based on its
actual use of the transmission system and related services.
Shipper customers with interruptible transportation contracts
are not assured capacity or service on the transmission
pipeline. To the extent that the transmission pipeline has
physical capacity resulting from firm transportation contracts
that are not being fully utilized, the system uses that capacity
for interruptible service.
|
|
|
|
Fixed-Margin Transportation. Under
these arrangements, the midstream service provider purchases
natural gas from producers or suppliers at receipt points on its
systems at an index price less a fixed transportation fee and
simultaneously sells an identical volume of natural gas at
delivery points on its systems at the same, undiscounted index
price. These contracts are sometimes referred to as wellhead
purchase agreements.
|
U.S.
Natural Gas Fundamentals
Natural gas is a critical component of energy consumption in the
United States. According to the EIA, annual consumption of
natural gas in the United States increased from approximately
22.8 Tcf in 2009 to approximately 24.1 Tcf in 2010, an increase
of approximately 5.7%. Total annual domestic natural gas
consumption is expected to rise from 24.1 Tcf in 2010 to 26.5
Tcf in 2035.
In order to maintain current levels of U.S. natural gas
supply and to meet the projected increase in demand, new sources
of domestic natural gas must continue to be developed to offset
the decline rates of existing production. Over the past several
years, a fundamental shift in U.S. natural gas production
has emerged with the contribution of natural gas from
unconventional resources, defined by the EIA as natural gas
produced from shale formations and coalbeds. The primary factors
driving this shift are the emergence of unconventional natural
gas plays and advances in technology that have allowed producers
to cost-effectively extract significant volumes of natural gas
from these plays. The development of these unconventional
sources
106
offsets declines in other U.S. natural gas supply, meeting
growing consumption and lowering the need for imported natural
gas.
According to the EIA:
|
|
|
|
|
The industrial and electricity generation sectors are the
largest users of natural gas in the United States, accounting
for approximately 58% of the total natural gas consumed in the
United States during 2010;
|
|
|
|
Annual industrial natural gas demand is expected to grow sharply
in the near term, from 7.3 Tcf in 2009 to 9.4 Tcf in 2020 as a
result of an expected recovery in industrial production;
|
|
|
|
In 2010, the end-user commercial and residential sectors
accounted for approximately 34% of the total natural gas
consumed in the United States; and
|
|
|
|
During the last five years ending December 31, 2010, the
United States has on average consumed approximately 23.0 Tcf per
year, with average annual domestic production of approximately
20.0 Tcf during the same period.
|
The graph below represents projected U.S. natural gas
production versus U.S. natural gas consumption through the
year 2035.
Source: Energy Information Administration.
107
BUSINESS
Overview
We are a growth-oriented Delaware limited partnership that was
formed by AIM in August 2009 to own, operate, develop and
acquire a diversified portfolio of natural gas midstream energy
assets. We are engaged in the business of gathering, treating,
processing and transporting natural gas through our ownership
and operation of nine gathering systems, three processing
facilities, two interstate pipelines and six intrastate
pipelines. Our primary assets, which are strategically located
in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide
critical infrastructure that links producers and suppliers of
natural gas to diverse natural gas markets, including various
interstate and intrastate pipelines, as well as utility,
industrial and other commercial customers. We currently operate
approximately 1,400 miles of pipelines that gather and
transport over
500 MMcf/d
of natural gas. We acquired our existing portfolio of assets
from Enbridge in November 2009.
Our operations are organized into two segments:
(i) Gathering and Processing and (ii) Transmission. In
our Gathering and Processing segment, we receive fee-based and
fixed-margin compensation for gathering, transporting and
treating natural gas. Where we provide processing services at
the plants that we own, or obtain processing services for our
own account under our elective processing arrangements, we
typically retain and sell a percentage of the residue natural
gas and resulting NGLs under POP arrangements. We own three
processing facilities that produced an average of approximately
34.1 Mgal/d of gross NGLs for the year ended December 31,
2010. In addition, under our elective processing arrangements,
we contract for processing capacity at a third-party plant where
we have the option to process natural gas that we purchase.
Under these arrangements, we sold an average of approximately
28.1 Mgal/d of net equity NGL volumes for the year
108
ended December 31, 2010. We also receive fee-based and
fixed-margin compensation in our Transmission segment primarily
related to capacity reservation charges under our firm
transportation contracts and the transportation of natural gas
pursuant to our interruptible transportation and fixed-margin
contracts.
For the year ended December 31, 2010, we generated
$38.1 million of gross margin, of which $24.6 million
was segment gross margin generated in our Gathering and
Processing segment and $13.5 million was segment gross
margin generated in our Transmission segment. For the year ended
December 31, 2010, $24.9 million, or 65.4%, of our
gross margin was generated from fee-based, fixed-margin and firm
and interruptible transportation contracts with respect to which
we have little or no direct commodity price exposure. For a
definition of gross margin and a reconciliation of gross margin
to its most directly comparable financial measure calculated in
accordance with GAAP, please read Selected Historical
Financial and Operating Data Non-GAAP Financial
Measures.
Business
Strategies
Our principal business objective is to increase the quarterly
cash distributions that we pay to our unitholders over time
while ensuring the ongoing stability of our business. We expect
to achieve this objective by executing the following strategies:
|
|
|
|
|
Capitalize on Organic Growth Opportunities Associated with
Our Existing Assets. We continually seek to
identify and evaluate economically attractive organic expansion
and asset enhancement opportunities that leverage our existing
asset footprint and strategic relationships with our customers.
We expect to have opportunities to expand our systems into new
markets and sources of supply, which we believe will make our
services more attractive to our customers. We intend to focus on
projects that can be completed at a relatively low cost and have
potential for attractive returns. Projects that we expect to
undertake in our forecast period include:
|
|
|
|
|
|
a cylinder upgrade on the existing Gloria compressor that we
expect will increase throughput capacity on the Gloria system by
approximately
7 MMcf/d
and that we expect to be completed in the third quarter of 2011
at a cost of approximately $0.2 million;
|
|
|
|
the construction of an interconnect and the installation of a
skid-mounted treating facility along Midla, which is expected to
cost approximately $0.3 million and be completed in the
third quarter of 2011;
|
|
|
|
the construction of a new skid-mounted processing plant on the
Alabama Processing system in order to serve additional new
production at a cost of approximately $1.3 million in the
third quarter of 2011; and
|
|
|
|
the addition of field compression capacity to the Bazor Ridge
gathering system, which would provide us with the opportunity to
treat new natural gas production, at an expected cost of
approximately $3.2 million that we expect to complete in
the first quarter of 2012.
|
|
|
|
|
|
Attract Additional Volumes to Our
Systems. We intend to attract new volumes of
natural gas to our systems from existing and new customers by
continuing to provide superior customer service and aggressively
marketing our services to additional customers in our areas of
operation. In addition, we intend to rebuild or reestablish
relationships with customers that were potentially underserved
by the previous owner of our assets. For example, in 2010 we
were able to contract with a customer on our Gloria system for
volumes of natural gas that it had decided to have gathered and
processed by alternative means prior to our acquisition of the
system. We have available capacity on a majority of our systems,
and as a result, we can accommodate additional volumes at a
minimal incremental cost.
|
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|
|
Pursue Strategic and Accretive
Acquisitions. We plan to pursue accretive
acquisitions of energy infrastructure assets that are
complementary to our existing asset base or that provide
attractive returns in new operating regions or business lines.
We will pursue acquisitions in our areas of operation that we
believe will allow us to realize operational efficiencies by
capitalizing on our existing infrastructure, personnel and
customer relationships. We will also seek acquisitions in new
geographic areas or new
|
109
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|
|
|
|
but related business lines to the extent that we believe we can
utilize our operational expertise to enhance our business with
these acquisitions.
|
|
|
|
|
|
Manage Exposure to Commodity Price
Risk. We will manage our commodity price
exposure by targeting a contract portfolio that is weighted
towards firm transportation, fee-based and fixed-margin
contracts while mitigating direct commodity price exposure by
employing a prudent hedging strategy. For the year ended
December 31, 2010, approximately 65.4% of our gross margin
was generated from firm transportation, fee-based and
fixed-margin contracts that, together with our
percent-of-proceeds
contracts and hedging activities, generated relatively stable
cash flows. For the years ending December 31, 2011 and
2012, we have hedged 86% and 49%, respectively, of our expected
net equity NGL volumes with a combination of swaps and puts for
the specific NGL components to which we are exposed. With
respect to our exposure to natural gas prices, we are currently
long natural gas on certain of our systems and short natural gas
on certain of our other systems, which effectively creates a
natural hedge against our exposure to fluctuations in the price
of natural gas.
|
|
|
|
Maintain Financial Flexibility and Conservative
Leverage. We plan to pursue a disciplined
financial policy and seek to maintain a conservative capital
structure that we believe will allow us to consider attractive
growth projects and acquisitions even in challenging commodity
price or capital markets environments. At the closing of this
offering, we anticipate entering into a new credit facility with
sufficient capacity to fund acquisitions, expansions and working
capital for our operations.
|
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|
|
Continue our Commitment to Safe and Environmentally Sound
Operations. The safety of our employees and
the communities in which we operate is one of our highest
priorities. We believe it is critical to handle natural gas and
NGLs for our customers safely, while striving to minimize the
environmental impact of our operations. To this end, we
implemented a safety performance program, including an integrity
management program, upon our formation in 2009 and implemented
planned maintenance programs to increase the safety, reliability
and efficiency of our operations.
|
Competitive
Strengths
We believe that we will be able to successfully execute our
business strategies because of the following competitive
strengths:
|
|
|
|
|
Well Positioned to Pursue Opportunities Overlooked by
Larger Competitors. Our size and flexibility,
in conjunction with our geographically diverse asset base,
positions us to pursue economically attractive growth projects
and acquisitions that may not be large enough to be attractive
to many of our larger competitors. Given the current size of our
business, these opportunities may have a larger impact on us
than they would have on our competitors and may provide us with
material growth opportunities. In addition, as a result of our
focus on customer service, we believe that we have unique
insights into our customers needs and are well situated to
take advantage of organic growth opportunities that arise from
those needs. For example, in 2010 we identified and executed an
opportunity to construct a major interconnection on our Lafitte
system with a third-party interstate pipeline offshore Louisiana
that provides additional volumes to a customers refinery
while also substantially increasing the utilization of both our
Gloria and Lafitte systems.
|
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|
|
Diversified Asset Base. Our assets are
diversified geographically and by business line, which
contributes to the stability of our cash flows and creates a
number of potential growth avenues for our business. We
primarily operate in five states, have access to multiple
sources of natural gas supply and service various interstate and
intrastate pipelines as well as utility, industrial and other
commercial customers. We believe this diversification provides
us with a variety of growth opportunities and mitigates our
exposure to reduced activity in any one area.
|
|
|
|
Strategically Located Assets. Our
assets are located in areas where we believe there will be
opportunities to access new natural gas supplies and to capture
new customers that are underserved by our competitors. We
continue to see drilling activity on and around our systems, and
we believe that our assets are strategically positioned to
capitalize on the resurgent drilling activity, increased demand
|
110
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|
|
|
|
for midstream services and growing commodity consumption in the
Gulf Coast and Southeast U.S. regions. Additionally, our
gathering and transmission pipelines have access to a variety of
markets, as well as intrastate and interstate pipelines. We
believe that our presence in the regions where we operate,
together with the available capacity of our assets, provide us
with a competitive advantage in capturing new customers and
supplies of natural gas.
|
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|
|
|
|
Focus on Delivering Excellent Customer
Service. We view our strong customer
relationships as one of our key assets and believe it is
critical to maintain operational excellence and ensure
best-in-class
customer service and reliability. Furthermore, we believe our
entrepreneurial culture and smaller size relative to our peers
enables us to offer more customized and creative solutions for
our customers and to be more responsive to their needs. We
believe our customer focus will enable us to capture new
opportunities and expand into new markets.
|
|
|
|
Experienced and Incentivized Management and Operating
Teams. Our executive management team has an
average of over 25 years of experience in the midstream
energy industry. The team possesses a comprehensive skill set to
support our business and enhance unitholder value through asset
optimization, accretive development projects and acquisitions.
In addition, our field supervisory team has operated our assets
for an average of over 20 years. We believe that our field
operating teams knowledge of the assets will further
contribute to our ability to execute our business strategies.
Furthermore, the interests of our executive management and
operating teams are strongly aligned with those of common
unitholders, including through their ownership of common units
and our Long-Term Incentive Plan.
|
Our
Sponsor
AIM is a private investment firm specializing in investments in
energy, natural resources, infrastructure and real property.
AIM, along with certain of the funds that AIM advises, currently
indirectly owns 84.4% of the ownership interests in AIM
Midstream Holdings, which owns 100% of our general partner.
Robert B. Hellman, Matthew P. Carbone and Edward O. Diffendal
serve on the board of directors of our general partner and are
principals of and have ownership interests in AIM. After the
closing of this offering, AIM Midstream Holdings will continue
to hold 100% of the ownership interests in our general partner
and will hold % of our common units
and % of our subordinated units, or
an aggregate of % of our total
limited partner interests.
111
Our
Assets
We own and operate all of our assets, which consist of nine
gathering systems, three processing facilities, two interstate
pipelines and six intrastate pipelines. Our assets are primarily
located in Alabama, Louisiana, Mississippi, Tennessee and Texas.
We organize our operations into two business segments:
(i) Gathering and Processing; and (ii) Transmission.
The following table provides information regarding our segments
and assets as of and for the year ended December 31, 2010.
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Approximate
|
|
|
|
|
|
Throughput
(MMcf/d)
|
|
|
|
|
|
|
|
|
Number
|
|
|
|
Approximate
|
|
Year
|
|
Quarter
|
|
|
|
|
|
|
|
|
of Connected
|
|
|
|
Design
|
|
Ended
|
|
Ended
|
|
|
|
|
Contract
|
|
|
|
Wells/Receipt
|
|
Compression
|
|
Capacity
|
|
December 31,
|
|
December 31,
|
|
|
System Type
|
|
Type(1)
|
|
Miles
|
|
Points
|
|
(Horsepower)
|
|
(MMcf/d)
|
|
2010
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & Processing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gloria
|
|
Gathering,
|
|
Fee(5), POP
|
|
|
110
|
|
|
|
57
|
|
|
|
1,877
|
|
|
|
60
|
|
|
|
36.6
|
|
|
|
38.8
|
|
|
|
Processing(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lafitte
|
|
Gathering
|
|
Fee(5)
|
|
|
40
|
|
|
|
44
|
|
|
|
|
|
|
|
71
|
|
|
|
12.0
|
|
|
|
11.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bazor Ridge
|
|
Gathering,
|
|
Fee, POP
|
|
|
160
|
|
|
|
40
|
|
|
|
6,287
|
|
|
|
22
|
|
|
|
9.2
|
|
|
|
11.7
|
|
|
|
Processing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quivira
|
|
Gathering
|
|
Fee
|
|
|
34
|
|
|
|
16
|
|
|
|
|
|
|
|
140
|
|
|
|
77.4
|
|
|
|
97.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Offshore Texas
|
|
Gathering
|
|
Fee(5)
|
|
|
56
|
|
|
|
22
|
|
|
|
|
|
|
|
100
|
|
|
|
15.3
|
|
|
|
16.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other(3)
|
|
Gathering,
|
|
Fee(5), POP
|
|
|
189
|
|
|
|
445
|
|
|
|
5,156
|
|
|
|
153
|
|
|
|
25.1
|
|
|
|
25.1
|
|
|
|
Processing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & Processing total
|
|
|
|
|
|
|
589
|
|
|
|
624
|
|
|
|
13,320
|
|
|
|
546
|
|
|
|
175.6
|
|
|
|
200.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bamagas
|
|
Intrastate
|
|
FT
|
|
|
52
|
|
|
|
2
|
|
|
|
|
|
|
|
450
|
|
|
|
151.5
|
|
|
|
170.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AlaTenn
|
|
Interstate
|
|
FT, IT
|
|
|
295
|
|
|
|
4
|
|
|
|
3,665
|
|
|
|
200
|
|
|
|
48.0
|
|
|
|
56.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midla
|
|
Interstate
|
|
FT, IT
|
|
|
370
|
|
|
|
9
|
|
|
|
3,600
|
|
|
|
198
|
|
|
|
87.2
|
|
|
|
95.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MLGT
|
|
Intrastate
|
|
FT, IT(5)
|
|
|
54
|
|
|
|
7
|
|
|
|
|
|
|
|
170
|
|
|
|
50.5
|
|
|
|
60.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other(4)
|
|
Intrastate
|
|
FT, IT
|
|
|
82
|
|
|
|
6
|
|
|
|
|
|
|
|
336
|
|
|
|
13.0
|
|
|
|
15.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission total
|
|
|
|
|
|
|
853
|
|
|
|
28
|
|
|
|
7,265
|
|
|
|
1,354
|
|
|
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350.2
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397.3
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(1) |
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In this table, fee refers to fee-based contracts, POP refers to
percent-of-proceeds contracts, FT refers to firm transportation
contracts and IT refers to interruptible transportation
contracts. For a general description of these types of
contracts, please see Industry Overview
Typical Midstream Contractual Arrangements. |
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(2) |
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Although the Gloria system is comprised solely of gathering
pipelines, we generate a substantial portion of our Gloria
revenue by processing natural gas for our own account at the
Toca processing plant through our elective processing
arrangements. We do not own the Toca processing plant, but we
have the contractual ability to process the natural gas for our
own account and retain the majority of the proceeds derived from
the sale of the residue natural gas and resulting NGLs. Please
see Gathering and Processing
Segment Gloria System. |
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(3) |
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Includes our Alabama Processing, Fayette, Magnolia, Stringer and
Heidelberg systems. |
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(4) |
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Includes our Trigas, Owens Corning and Chalmette systems. |
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(5) |
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Because we view the segment gross margin earned under our
fixed-margin arrangements to be economically equivalent to the
fee earned in our fee-based arrangements in our Gathering and
Processing segment and the fee earned in our interruptible
transportation arrangements in our Transmission segment, we have
included the fixed-margin arrangements in those categories. |
112
Gathering
and Processing Segment
General
Our Gathering and Processing segment is an integrated midstream
natural gas system that provides the following services to our
customers:
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gathering;
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compression;
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treating;
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processing;
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transportation; and
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sales of natural gas, NGLs and condensate.
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For a description of these services, please read Industry
Overview Midstream Services.
We own one processing plant on our Bazor Ridge system, two on
our Alabama Processing system and have the right to contract for
processing services for our own account at another, the Toca
plant, that is connected to our Gloria system. The Toca plant is
owned and operated by Enterprise. Our Bazor Ridge processing
plant and the Toca plant are both cryogenic processing plants.
These types of processing plants represent the latest generation
of processing techniques, using extremely low temperatures and
high pressures to optimize the extraction of NGLs from the raw
natural gas stream.
We generally derive revenue in our Gathering and Processing
segment from fee-based, fixed-margin and POP arrangements,
whether for our producer and supplier customers or our own
account. We have no keep-whole arrangements with our customers.
On our Gloria, Lafitte and Offshore Texas systems, we purchase
natural gas from producers or suppliers at receipt points on our
systems at an index price less a fixed transportation fee and
subsequently transport that natural gas to delivery points on
our systems at which we sell the natural gas at the same
undiscounted index price thereby earning a fixed margin on each
transaction. We regard the segment gross margin we earn with
respect to those purchases and sales a fixed-margin
and as the economic equivalent of a fee for our transportation
service, and as such, we include these transactions in the
category of fee-based contractual arrangements. In order to
minimize commodity price risk we face in these transactions, we
match sales with purchases at the index price on the date of
settlement. For the twelve months ended December 31, 2010,
our fee-based and fixed-margin arrangements and our POP
arrangements accounted for approximately 46.3% and 53.7%,
respectively, of our segment gross margin for this segment.
We continually seek new sources of raw natural gas supply to
maintain and increase the throughput volume on our gathering
systems and through our processing plants. As a result, we
connected eleven new supply sources in 2010 to systems in our
Gathering and Processing segment, including connections of
individual wells, as well as central delivery points and
interstate and intrastate pipelines that have multiple wells
behind them.
Our Gathering and Processing assets are located in Alabama,
Louisiana and Mississippi and in shallow state and federal
waters in the Gulf of Mexico off the coasts of Louisiana and
Texas.
Gloria
System
The Gloria gathering system provides gathering and compression
services through our assets, as well as processing services
through an elective processing arrangement we have at the Toca
plant. The Gloria system is located in Lafourche, Jefferson,
Plaquemines, St. Charles and St. Bernard parishes of Louisiana
and consists of approximately 110 miles of pipeline with
diameters ranging from three to 16 inches and three
compressors with a combined capacity of 1,877 horsepower. The
Gloria system has a design capacity of approximately
90 MMcf/d,
but is currently limited by compression horsepower at the Gloria
Compressor Station to approximately
60 MMcf/d.
Average throughput on the Gloria system for the year ended
December 31, 2010 was
36.6 MMcf/d
from approximately 57 connected wells and an interconnect with
our Lafitte system.
113
Average throughput on the Gloria system increased to
approximately
49.7 MMcf/d
for the month of December 2010 due to excess volumes from our
Lafitte system, primarily resulting from the completion of a new
interconnect between the Lafitte system and TGP, an interstate
pipeline owned by El Paso Corporation. For more information
about the excess natural gas from our Lafitte system, please
read Lafitte System.
The Gloria system gathers natural gas from onshore oil and
natural gas wells producing from the Gulf Coast region of
Louisiana. Production is derived from a variety of reservoirs
and ranges from dry natural gas to rich associated natural gas.
Well decline rates are variable in this area, but it is common
practice for producers to mitigate declines in production with
workovers and re-completions of existing wells. An average of
four wells per year were connected to the Gloria system over the
last three years, with four wells connected during the year
ended December 31, 2010. Producers generally bear the cost
of connecting their wells to our Gloria system.
Toca Plant and Our Elective Processing
Arrangements. The Toca plant is a cryogenic
processing plant with a design capacity of approximately
1.1 Bcf/d that is located in St. Bernard Parish in
Louisiana and operated by Enterprise. In conjunction with the
acquisition of the Gloria system in November 2009, we assumed a
POP processing contract with Enterprise that allows us to
process raw natural gas through the Toca plant, whether for our
customers or our own account. This contract renews on a
month-to-month
basis and specifies that Enterprise retains a percentage of the
NGLs produced by the Toca plant as payment for processing
services. In connection with the completion of the Lafitte/TGP
interconnect in November 2010, we entered into an additional
contract with Enterprise for processing natural gas we purchase
at the Lafitte/TGP interconnect. We refer to these Toca
contracts with Enterprise as our elective processing
arrangements. Please read Risk Factors
Risks Related to Our Business Our elective
processing arrangements are
month-to-month,
and the loss of these arrangements would materially and
adversely affect our revenue and
114
gross margin in our Gathering and Processing segment.
Natural gas that is processed at the Toca plant is transported
to end users via the Sonat pipeline directly and through various
interconnects downstream of the Toca plant. Sonat is the primary
pipeline into which Toca volumes are delivered.
We have the flexibility to decide whether to process natural gas
through the Toca plant and capture processing margins for our
own account or deliver the natural gas into the interstate
pipeline market at the inlet to the Toca plant, and we make this
decision based on the relative prices of natural gas and NGLs on
a monthly basis. Due to currently strong processing margins, we
currently process 100% of the natural gas purchased on the
Gloria system, as well as any excess natural gas purchased via
the Lafitte/TGP interconnect in excess of the needs of
ConocoPhillips at the Alliance Refinery. Based on publicly
available information, we believe that the Toca plant has
sufficient capacity available to accommodate additional volumes
from the Gloria system.
Lafitte
System
The Lafitte gathering system consists of approximately
40 miles of gathering pipeline, with diameters ranging from
four to 12 inches and a design capacity of approximately
71 MMcf/d.
The Lafitte system originates onshore in southern Louisiana and
terminates in Plaquemines Parish, Louisiana at the Alliance
Refinery owned by ConocoPhillips Corporation, or ConocoPhillips.
Average throughput on the Lafitte system for the year ended
December 31, 2010 was
12.0 MMcf/d
from approximately 44 connected wells and an interconnect with
TGP that was completed in December 2010. We are the sole
supplier of natural gas to the Alliance Refinery through our
Lafitte and Gloria systems. We supply natural gas to the
Alliance Refinery pursuant to a long-term contract that expires
in 2023. Any natural gas not used by ConocoPhillips at the
Alliance Refinery is delivered to our Gloria system.
Like our nearby Gloria system, the Lafitte system gathers
natural gas from onshore oil and natural gas wells producing
from the Gulf Coast region of Louisiana. An average of three
wells per year were connected to the Lafitte system over the
last three years, with no wells connected during the year ended
December 31, 2010. Producers generally bear the cost of
connecting their wells to our Lafitte system.
TGP Interconnect. In December 2010, we
completed an interconnect between our Lafitte pipeline and a
pipeline on the TGP interstate system. This interconnect
provides a redundant source of natural gas supply for the
ConocoPhillips Alliance Refinery to the extent that the Lafitte
native production is insufficient to supply the needs of the
refinery and provides us with increased operational flexibility
on our Gloria and Lafitte systems. To the extent that there is
excess supply that the refinery does not consume, we purchase
those volumes to be sold into Sonat pursuant to a fixed-margin
arrangement or to be processed at the Toca processing facility
pursuant to elective processing arrangements.
Bazor
Ridge System
The Bazor Ridge gathering and processing system consists of
approximately 160 miles of pipeline with diameters ranging
from three to eight inches and three compressor stations with a
combined compression capacity of 1,069 horsepower. Our Bazor
Ridge system is located in Jasper, Clarke, Wayne and Greene
Counties of Mississippi. The Bazor Ridge system also contains a
cryogenic sour natural gas treating and processing plant located
in Wayne County, Mississippi with a design capacity of
approximately
22 MMcf/d
and four inlet and one discharge compressor with approximately
5,218 of combined horsepower. We upgraded the turbo expander at
the Bazor Ridge processing plant in June 2010, which resulted in
a significant improvement in the plants NGL recoveries and
provided us with greater operating flexibility during changing
commodity price environments. We have POP arrangements with each
of our customers on the Bazor Ridge system that generally also
include a fee-based element for gathering and treating services.
After processing, the residue natural gas is sold and delivered
into the Destin Pipeline system, an interstate pipeline operated
by Destin Pipeline Company, L.L.C., which has connections with a
number of other interstate pipeline systems. We sell the NGLs we
recover at the truck rack at the tailgate of the Bazor Ridge
processing plant to Dufour Petroleum LP, an affiliate of
Enbridge, pursuant to a
month-to-month
contract. The NGLs are sold on a Mt. Belvieu index-based
price. Average throughput on the Bazor Ridge plant for the year
ended December 31, 2010 was approximately
9.2 MMcf/d
from 40 connected wells. Average throughput increased to
approximately
115
13.5 MMcf/d
for the month of December 2010 as a result of the completion of
the Winchester lateral, which we describe below, in November
2010.
In 2010, we built a new eight-inch diameter pipeline consisting
of approximately nine miles of pipe, called the Winchester
lateral, to serve the natural gas wells located in Wayne County,
Mississippi owned by Venture Oil & Gas, Inc., or
Venture, and other producers. The Winchester lateral allowed us
to increase the effective throughput capacity of the Bazor Ridge
gathering system by approximately 200% to approximately
25 MMcf/d.
In conjunction with the construction of the Winchester lateral,
we negotiated a five-year acreage dedication from Venture.
The natural gas supply for our Bazor Ridge system is derived
primarily from rich associated natural gas produced from oil
wells targeting the mature Upper Smackover formation. Production
from the wells drilled in this area is generally stable with
relatively modest decline rates. An average of one well per year
was connected to our Bazor Ridge gathering system over the last
three years, with no wells connected during the year ended
December 31, 2010. Despite the low number of new wells
connected, the generally stable production and relatively modest
decline rates from this formation allow us to maintain steady
throughput on our Bazor Ridge system. Given the recent and
current commodity price environment for crude oil, we expect
increasing drilling activity and resulting production in this
area during 2011.
Quivira
System
The Quivira gathering system consists of approximately
34 miles of pipeline, with a
12-inch
diameter mainline and several laterals ranging in diameter from
six to eight inches. The system originates offshore of Iberia
and St. Mary Parishes of Louisiana in Eugene Island
Block 24 and terminates onshore in St. Mary Parish,
Louisiana at a connection with the Burns Point processing plant,
a cryogenic processing plant with a
116
design capacity of 160 MMcf/d that is owned and operated by
Enterprise. The Quivira system has a design capacity of
approximately
140 MMcf/d.
This system also includes an onshore condensate handling
facility at Bayou Sale, Louisiana that is upstream of the Burns
Point processing plant. Residue natural gas is sold into TGP or
the Gulf South Pipeline system, an interstate pipeline owned by
Boardwalk Pipeline Partners, LP.
The Quivira system is fully subscribed under a firm
transportation arrangement through 2012, although a substantial
proportion of the revenue is derived from volumetric and
fee-based charges. Existing production in our gathering area
above our current system capacity is transported on other
systems that we believe offer producers less attractive economic
alternatives to our customers. Average throughput on the Quivira
system for the year ended December 31, 2010 was
approximately
77.4 MMcf/d
from 16 connected wells. Average throughput increased to
approximately
115 MMcf/d
for the month of December 2010 as a result of additional
production added to the system from a new interconnect to a
gathering system owned and operated by Contango Oil &
Gas Company. We expect that the Quivira system will be operating
at capacity for the remainder of 2011 and through 2012.
The Quivira system provides gathering services for natural gas
wells and associated natural gas produced from crude oil wells
operated by major and independent producers targeting multiple
conventional production zones in the shallow waters of the Gulf
of Mexico. Wells in this area have historically exhibited
relatively low rates of decline throughout the life of the
wells. The natural gas produced from these wells is typically
natural gas with condensate. An average of three wells per year
were connected to the Quivira system over the last three years,
with three wells connected during the year ended
December 31, 2010. Producers generally bear the cost of
connecting their wells to our Quivira system.
117
Offshore
Texas System
The Offshore Texas system consists of the GIGS and Brazos
systems, two parallel gathering systems that share common
geography and operating characteristics. The Offshore Texas
system provides gathering and dehydration services to natural
gas producers in the shallow waters of the Gulf of Mexico region
offshore Texas.
The Offshore Texas system consists of approximately
56 miles of pipeline with diameters ranging from six to
16 inches and a design capacity of approximately
100 MMcf/d.
Additionally, the Offshore Texas system has two onshore
separation and dehydration units, each with a capacity of
approximately
40 MMcf/d,
that remove water and other impurities from the gathered natural
gas before delivering it to our customers. The GIGS system
originates offshore of Brazoria County, Texas in Galveston
Island Block 343 and connects onshore to the Houston
Pipeline system, an intrastate pipeline owned by Energy Transfer
Partners, L.P. The Brazos system originates offshore of Brazoria
County, Texas in Brazos Block 366 and connects onshore to
the Dow Pipeline system, an interstate pipeline owned by Dow
Chemical Company. Substantially all of the natural gas gathered
on the Brazos system is delivered to Dow Chemical for use in its
chemical plant located in Freeport, Texas pursuant to a
month-to-month
contract. Dow consumes significantly more natural gas than is
provided by the Brazos system and we believe Dow may purchase
additional volumes from the Brazos system.
Average throughput on the Offshore Texas system for the year
ended December 31, 2010 was
15.3 MMcf/d
from approximately 22 connected wells. Average throughput
increased to approximately
19.7 MMcf/d
for the month of December 2010 as a result of recent
recompletion activity on wells connected to the system.
All of the wells in this area are natural gas wells producing
from the Gulf of Mexico shelf offshore Texas. An average of
three wells per year were connected to the Offshore Texas system
over the last three
118
years, with no new wells connected during the year ended
December 31, 2010. Producers generally bear the cost of
connecting their wells to our Texas Offshore system.
Other
Gathering and Processing Assets
Alabama Processing. The Alabama Processing
system consists of two small skid-mounted treating and
processing plants that we refer to, individually, as Atmore and
Wildfork. These treating and processing plants are located in
Escambia and Monroe Counties of Alabama, respectively, and have
design capacities of
3 MMcf/d
and
7 MMcf/d,
respectively. The Atmore and Wildfork plants processed an
average of
0.4 MMcf/d
and
0.3 MMcf/d
of natural gas, respectively, during the year ended
December 31, 2010.
Magnolia System. The Magnolia gathering system
is a Section 311 intrastate pipeline that gathers coalbed
methane in Tuscaloosa, Greene, Bibb, Chilton and Hale counties
of Alabama and delivers this natural gas to an interconnect with
the Transco Pipeline system, an interstate pipeline owned by The
Williams Companies, Inc. The Magnolia system consists of
approximately 116 miles of pipeline with small-diameter
gathering lines and trunklines ranging from six to
24 inches in diameter and one compressor station with 3,328
horsepower. The Magnolia system has a design capacity of
approximately
120 MMcf/d.
Average throughput on the Magnolia system for the year ended
December 31, 2010 was approximately
17.4 MMcf/d.
The Magnolia system is also strategically located in the Floyd
shale formation, a currently underdeveloped play that may have
significant production potential in a higher natural gas price
environment.
Our other gathering and processing systems include the Fayette
and Heidelberg gathering systems, located in Fayette County,
Alabama and Jasper County, Mississippi, respectively. The design
capacities for these systems are approximately
5 MMcf/d
and approximately
18 MMcf/d,
respectively. For the year ended December 31, 2010, average
throughput for these systems was approximately
0.5 MMcf/d
and approximately
6.5 MMcf/d,
respectively. We also own a small Joule Thompson processing
skid, called Stringer, that we lease to a producer in Wayne
County, Mississippi.
Growth
Opportunities
In our Gathering and Processing segment, we continually seek new
sources of raw natural gas supply to increase the throughput
volume on our gathering systems and through our processing
plants. In addition, we seek to identify and evaluate
economically attractive organic expansion and asset acquisition
opportunities that leverage our existing asset footprint and
strategic relationships with our customers. We also plan to
opportunistically pursue strategic and accretive acquisitions
within the midstream energy industry that are complementary to
our existing asset base or that provide attractive potential
returns in new operating regions or business lines. In addition
to the projects that we expect to undertake in our forecast
period, we are evaluating the following growth opportunities:
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the addition of compression to the Gloria system to accommodate
expected new production from existing customers or increase the
volumes purchased via the Lafitte/TGP interconnect, which we
expect to increase the current capacity of the Gloria system by
approximately 50%, to approximately
90 MMcf/d;
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the reconnection of our stranded Montegut lateral to the Gloria
system to provide access to areas of existing production that we
currently do not serve and potential access to a third-party
processing plant, which would allow us to connect new wells that
would increase the volume of natural gas that we gather on the
Gloria system;
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the addition of pipeline capacity on the Quivira system through
the pursuit of near-system acquisitions and the installation of
additional pipe or additional compression capacity; and
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the addition of compression capacity to the Wildfork plant on
the Alabama Processing system in order to increase plant
throughput.
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119
Customers
Substantially all of the natural gas produced on our Lafitte
system is sold to ConocoPhillips for use at its Alliance
Refinery in Plaquemines Parish, Louisiana under a contract that
expires in 2023. On our Bazor Ridge system, we have a POP
arrangement with Venture Oil & Gas Co. that contains
an acreage dedication under a contract that expires in 2015. We
have a weighted-average remaining life of approximately two
years on our fee-based contracts in this segment. The
weighted-average remaining life on our POP contracts in this
segment is approximately three years. For the year ended
December 31, 2010, our Gathering and Processing segment
derived 41%, 29% and 10% of its revenue from ConocoPhillips,
EMUS and Dow Hydrocarbons and Resources, respectively, and 16%
and 17% of its segment gross margin from arrangements with
Contango Operators Inc. and Venture Oil & Gas Co.,
respectively.
Transmission
Segment
General
Our Transmission segment is comprised of interstate and
intrastate pipelines that transport natural gas from
interconnection points on other large pipelines to customers
such as LDCs, electric utilities or direct-served industrial
complexes, or to interconnects on other pipelines. Certain of
our pipelines are subject to regulation by FERC and by state
regulators. In this segment, we generally enter into firm
transportation contracts with our shipper customers to transport
natural gas sourced from large interstate or intrastate
pipelines. Our Transmission segment assets are located in
multiple parishes in Louisiana and multiple counties in
Mississippi, Alabama and Tennessee.
In our Transmission segment, we contract with customers to
provide firm and interruptible transportation services. In
addition, we have a fixed-margin arrangement on our MLGT system
whereby we purchase and sell the natural gas that we transport
under this arrangement. For a description of the types of
contracts that we enter into with the customers in our
Transmission segment, please read Industry
Overview Typical Midstream Contractual
Arrangements.
For our Midla and AlaTenn systems, which are interstate natural
gas pipelines, the maximum and minimum rates for services are
governed by each individual systems FERC-approved tariff.
In some cases, we agree to discount services or in certain cases
we enter into negotiated rate agreements that, with FERC
approval, can have rates or other terms that are different than
those provided for in the FERC tariff. For our Bamagas and MLGT
systems, which are intrastate pipelines providing interstate
services under the Hinshaw exemption of the NGA, we negotiate
service rates with each of our shipper customers.
The table below sets forth certain information regarding the
assets, contracts and revenue for each of the major systems
comprising our Transmission segment, as of and for the year
ended December 31, 2010:
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Percent of
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Tariff Revenue Composition
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Design Capacity
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Weighted
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Firm Transportation Contracts
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Subscribed
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Average
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Capacity
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Interruptible
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Under Firm
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Remaining
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Reservation
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Variable Use
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Transportation
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Transportation
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Contract Life
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Asset
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Charges
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Charges
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Contracts
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Contracts
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(in Years)
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Bamagas
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100
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%
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%
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%
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44
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%
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9
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AlaTenn
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78
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%
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2
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%
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20
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%
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25
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%
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2
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Midla
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83
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%
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3
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%
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14
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%
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100
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%(1)
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1
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MLGT(2)
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%
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%
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100
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%
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15
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%
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1
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(1) |
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Represents volumes subscribed under firm transportation
contracts and design capacity on the mainline of our Midla
system. |
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(2) |
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Includes
fixed-margin
arrangements. |
120
Bamagas
System
Our Bamagas system is a Hinshaw intrastate natural gas pipeline
that travels west to east from an interconnection point with TGP
in Colbert County, Alabama to two power plants owned by Calpine
Corporation, or Calpine, in Morgan County, Alabama. The Bamagas
system consists of 52 miles of high pressure,
30-inch
pipeline with a design capacity of approximately
450 MMcf/d.
Average throughput on the Bamagas system for the year ended
December 31, 2010 was approximately
151.5 MMcf/d.
Currently, 100% of the throughput on this system is contracted
under long-term firm transportation agreements. Calpine
Corporation is the sole customer on the Bamagas system, with two
firm transportation contracts providing for a total of
200 MMcf/d
of firm transportation capacity. These contracts, which expire
in 2020, ensure steady natural gas supply for the Morgan and
Decatur Energy Centers in Morgan County, Alabama. These two
natural gas-fired power plants were built in 2002 and 2003 and
have a combined capacity of 1,502 megawatts. These generating
facilities supply the Tennessee Valley Authority, or the TVA,
with electricity under long-term contractual arrangements
between Calpine Corporation and the TVA.
AlaTenn
System
The AlaTenn system is an interstate natural gas pipeline that
interconnects with TGP and travels west to east delivering
natural gas to industrial customers in northwestern Alabama, as
well as the city gates of Decatur and Huntsville, Alabama. Our
AlaTenn system has a design capacity of approximately
200 MMcf/d
and is comprised of approximately 295 miles of pipeline
with diameters ranging from three to 16 inches and includes
two compressor stations with combined capacity of 3,665
horsepower. The AlaTenn system is connected to four receipt and
61 delivery points, including the Tetco Pipeline system, an
interstate pipeline owned by Duke Energy Corporation, and the
Columbia Gulf Pipeline system, an interstate pipeline owned by
NiSource Gas Transmission and Storage. Average throughput on the
AlaTenn system for the year ended December 31, 2010 was
approximately
48.0 MMcf/d.
121
Midla
System
Our Midla system is an interstate natural gas pipeline with
approximately 370 miles of pipeline linking the Monroe
Natural Gas Field in Northern Louisiana and interconnections
with the Transco Pipeline system and Gulf South Pipeline system
to customers near Baton Rouge, Louisiana. Our Midla system also
has interconnects to Centerpoint, TGP and Sonat along a
high-pressure lateral at the north end of the system, called the
T-32 lateral.
Our Midla system is strategically located near the Perryville
Hub, which is a major hub for natural gas produced in the
Louisiana and broader Gulf Coast region, including natural gas
from the Haynesville shale, Barnett shale, Fayetteville shale,
Woodford shale and Deep Bossier formations of Northern
Louisiana, Central Texas, Northern Arkansas, Eastern Oklahoma
and East Texas, respectively. The Midla system is connected to
nine receipt and 19 delivery points. Due to the numerous
interstate pipeline connections and growing supply and demand
dynamics in the surrounding regions, we believe that our
location near the Perryville Hub provides us a strategic
advantage in securing supplies of natural gas.
Natural gas generally flows from north to south on the Midla
mainline from interconnections with other interstate pipelines
to customers and end users. The Midla system consists of the
following components:
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the northern portion of the system, including the T-32 lateral;
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the mainline; and
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the southern portion of the system, including interconnections
with the MLGT system and other associated laterals.
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The northern portion of the system, including the T-32 lateral,
consists of approximately four miles of high pressure,
12-inch
diameter pipeline. Natural gas on the northern end of the Midla
system is delivered to two power plants operated by Entergy by
way of the T-32 lateral and the CLECO Sterlington plant by way
of the Sterlington lateral. These power plants are peak-load
generating facilities that consumed an aggregate
122
average of approximately
23.6 MMcf/d
of natural gas for the year ended December 31, 2010. The
T-32 lateral is fully subscribed, with approximately
296 MMcf/d
of firm transportation capacity under contracts with an average
remaining term of 0.5 years that automatically renew on a
year-to-year basis.
The mainline of the system has a design capacity of
approximately
198 MMcf/d
and consists of approximately 170 miles of low pressure,
22-inch
diameter pipeline with laterals ranging in diameter from two to
16 inches. This section of the Midla system primarily
serves small LDCs under firm transportation contracts that
automatically renew on a
year-to-year
basis. Substantially all of these contracts are at maximum rates
allowed under Midlas FERC tariff. Average throughput on
the Midla mainline for the year ended December 31, 2010 was
approximately
61.6 MMcf/d.
The southern portion of the system, including interconnections
with the MLGT system and other associated laterals, consists of
approximately two miles of high and low pressure,
12-inch
diameter pipeline. This section of the system primarily serves
industrial and LDC customers in the Baton Rouge market through
contracts with several large marketing companies. In addition,
this section includes two small offshore gathering lines, the
T-33 lateral in Grand Bay and the T-51 lateral in Eugene Island
28, each of which are approximately five miles in length.
Natural gas delivered on the southern end of the system is sold
under both firm and interruptible transportation contracts with
average remaining terms of two years.
MLGT
System
The MLGT system is an intrastate transmission system that
sources natural gas from interconnects with the FGT Pipeline
system, an interstate pipeline owned by Florida Gas Transmission
Company, the Tetco Pipeline system, the Transco Pipeline system
and our Midla system to a Baton Rouge, Louisiana refinery owned
and operated by ExxonMobil and five other industrial customers.
Our MLGT system has a design capacity of approximately
170 MMcf/d
and is comprised of approximately 54 miles of pipeline with
diameters ranging from three to 14 inches. The MLGT system
is connected to seven receipt and 16 delivery points. Average
throughput on the MLGT system for the year ended
December 31, 2010 was approximately
50.5 MMcf/d.
Other
Systems
Our other transmission systems include the Chalmette system,
located in St. Bernard Parish, Louisiana, and the Trigas system,
located in three counties in northwestern Alabama. The
approximate design capacities for the Chalmette and Trigas
systems are
125 MMcf/d
and
60 MMcf/d,
respectively. For the year ended December 31, 2010, the
approximate average throughput for these systems was
6.0 MMcf/d
and
5.9 MMcf/d,
respectively. We also have an interconnect in Albany County, New
York with an Owens Corning Delmar Facility in respect of which
we receive a small monthly payment. Finally, we also own a
number of miscellaneous interconnects and small laterals that
are collectively referred to as the SIGCO assets.
Growth
Opportunities
In our Transmission segment, we continually seek to increase the
throughput volume on our pipelines. We also seek to identify and
evaluate economically attractive organic expansion and asset
opportunities that leverage our existing asset footprint and
strategic relationships with our customers. In addition to the
projects that we expect to undertake in our forecast period, we
are evaluating the following growth opportunities:
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the addition of delivery points to the AlaTenn system, which we
believe will improve overall system flexibility and allow us to
capitalize on possible incremental natural gas demand from
various electric utilities on our system who are either in the
process of, or are evaluating, switching fuel sources from coal
to natural gas; and
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the addition of LDC and industrial customers on the AlaTenn
system who were commercially underserved by our Predecessor.
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Customers
In our Transmission segment, we contract with LDCs, electric
utilities, or direct-served industrial complexes, or to
interconnections on other large pipelines, to provide firm and
interruptible transportation services. Among all of our
customers in this segment, the weighted-average remaining life
of our firm and interruptible transportation contracts are
approximately five years and less than one year, respectively.
For the year ended December 31, 2010, our Transmission
segment derived 43% and 10% of its revenue from arrangements
with ExxonMobil and Calpine Corporation, respectively. In
addition, our Transmission segment derived 38% of its gross
margin from arrangements with Calpine Corporation for the year
ended December 31, 2010.
Competition
The natural gas gathering, compression, treating and
transportation business is very competitive. Our competitors in
our Gathering and Processing segment include other midstream
companies, producers, intrastate and interstate pipelines.
Competition for natural gas volumes is primarily based on
reputation, commercial terms, reliability, service levels,
location, available capacity, capital expenditures and fuel
efficiencies. Our major competitors in this segment include TGP
and Gulf South.
In our Transmission segment, we compete with other pipelines
that service regional markets, specifically in our Baton Rouge
market. An increase in competition could result from new
pipeline installations or expansions by existing pipelines.
Competitive factors include the commercial terms, available
capacity, fuel efficiencies, the interconnected pipelines and
gas quality issues. Our major competitors for this segment are
Southern Natural Gas Company, a subsidiary of El Paso
Corporation and Louisiana Intrastate Gas, owned by Crosstex
Energy, L.P.
Safety
and Maintenance
We are subject to regulation by the Pipeline and Hazardous
Materials Safety Administration, or PHMSA, of the Department of
Transportation, or the DOT, pursuant to the Natural Gas Pipeline
Safety Act of 1968, or the NGPSA, and the Pipeline Safety
Improvement Act of 2002, or the PSIA, which was recently
reauthorized and amended by the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006. The NGPSA regulates safety
requirements in the design, construction, operation and
maintenance of gas pipeline facilities, while the PSIA
establishes mandatory inspections for all U.S. oil and
natural gas transportation pipelines and some gathering lines in
high-consequence areas. The PHMSA has developed regulations
implementing the PSIA that require transportation pipeline
operators to implement integrity management programs, including
more frequent inspections and other measures to ensure pipeline
safety in high consequence areas, such as high
population areas, areas unusually sensitive to environmental
damage and commercially navigable waterways. New pipeline safety
legislation requiring more stringent spill reporting and
disclosure obligations has been introduced in the
U.S. Congress and was passed by the U.S. House of
Representatives in 2010, but was not voted on in the
U.S. Senate. Similar legislation is likely to be considered
in the current session of Congress, either independently or in
conjunction with the reauthorization of the Pipeline Safety Act.
In part as a result of the PG&E gas line explosion in
California last year, the Department of Transportation has also
recently proposed legislation providing for more stringent
oversight of pipelines and increased penalties for violations of
safety rules, which is in addition to the PHMSAs announced
intention to strengthen its rules.
We regularly inspect our pipelines and third parties assist us
in interpreting the results of the inspections.
States are largely preempted by federal law from regulating
pipeline safety for interstate lines but most are certified by
the DOT to assume responsibility for enforcing federal
intrastate pipeline regulations and inspection of intrastate
pipelines. In practice, because states can adopt stricter
standards for intrastate pipelines than those imposed by the
federal government for interstate lines, states vary
considerably in their authority and capacity to address pipeline
safety. These state oil and gas standards may include
requirements for facility design and management in addition to
requirements for pipelines. We do not anticipate any significant
difficulty in complying with applicable state laws and
regulations. Our natural gas pipelines have continuous
inspection and compliance programs designed to keep the
facilities in compliance with pipeline safety and pollution
control requirements.
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In addition, we are subject to a number of federal and state
laws and regulations, including the federal Occupational Safety
and Health Act, or OSHA, and comparable state statutes, the
purposes of which are to protect the health and safety of
workers, both generally and within the pipeline industry. In
addition, the OSHA hazard communication standard, the
Environmental Protection Agency, or EPA, community
right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in our operations and that such
information be provided to employees, state and local government
authorities and citizens. We and the entities in which we own an
interest are also subject to OSHA Process Safety Management
regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive,
flammable or explosive chemicals. These regulations apply to any
process which involves a chemical at or above the specified
thresholds or any process which involves flammable liquid or
gas, pressurized tanks, caverns and wells in excess of 10,000
pounds at various locations. Flammable liquids stored in
atmospheric tanks below their normal boiling points without the
benefit of chilling or refrigeration are exempt. We have an
internal program of inspection designed to monitor and enforce
compliance with worker safety requirements. We believe that we
are in material compliance with all applicable laws and
regulations relating to worker health and safety.
We and the entities in which we own an interest are also subject
to:
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EPA Chemical Accident Prevention Provisions, also known as the
Risk Management Plan requirements, which are designed to prevent
the accidental release of toxic, reactive, flammable or
explosive materials;
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OSHA Process Safety Management Regulations, which are designed
to prevent or minimize the consequences of catastrophic releases
of toxic, reactive, flammable or explosive materials; and
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Department of Homeland Security Chemical Facility Anti-Terrorism
Standards, which are designed to regulate the security of
high-risk chemical facilities.
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Regulation
of Operations
Regulation of pipeline gathering and transportation services,
natural gas sales and transportation of NGLs may affect certain
aspects of our business and the market for our products and
services.
Interstate
Natural Gas Pipeline Regulation
Our interstate natural gas transportation systems are subject to
the jurisdiction of the FERC under the Natural Gas Act of 1938,
or the NGA. Under the NGA, FERC has authority to regulate
natural gas companies that provide natural gas pipeline
transportation services in interstate commerce. Federal
regulation of our interstate pipelines extends to such matters
as:
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rates, services, and terms and conditions of service;
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the types of services offered to customers;
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the certification and construction of new facilities;
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the acquisition, extension, disposition or abandonment of
facilities;
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the maintenance of accounts and records;
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relationships between affiliated companies involved in certain
aspects of the natural gas business;
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the initiation and discontinuation of services;
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market manipulation in connection with interstate sales,
purchases or transportation of natural gas and NGLs; and
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participation by interstate pipelines in cash management
arrangements.
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Under the NGA, the rates for service on these interstate
facilities must be just and reasonable and not unduly
discriminatory.
The rates and terms and conditions for our interstate pipeline
services are set forth in FERC-approved tariffs. Pursuant to
FERCs jurisdiction over rates, existing rates may be
challenged by complaint and proposed rate increases may be
challenged by protest. Any successful complaint or protest
against our rates could have an adverse impact on our revenue
associated with providing transportation service.
In 2008, FERC issued Order No. 717, a final rule that
implements standards of conduct that include three primary
rules: (1) the independent functioning rule,
which requires transmission function and marketing function
employees to operate independently of each other; (2) the
no-conduit rule, which prohibits passing
transmission function information to marketing function
employees; and (3) the transparency rule, which
imposes posting requirements to help detect any instances of
undue preference. The FERC has since issued three rehearing
orders which generally reaffirmed the determinations in Order
No. 717 and also clarified certain provisions of the
Standards of Conduct. A single rehearing request related to
elective issues is currently pending before the FERC.
In 2005, the FERC issued a policy statement permitting the
inclusion of an income tax allowance in the cost of
service-based rates of a pipeline organized as a tax pass
through partnership entity to reflect actual or potential income
tax liability on public utility income, if the pipeline proves
that the ultimate owner of its interests has an actual or
potential income tax liability on such income. The policy
statement provided that whether a pipelines owners have
such actual or potential income tax liability will be reviewed
by the FERC on a
case-by-case
basis. In August 2005, FERC dismissed requests for rehearing of
its new policy statement. In December 2005, the FERC issued its
first significant case-specific review of the income tax
allowance issue in another pipeline partnerships rate
case. The FERC reaffirmed its income tax allowance policy and
directed the subject pipeline to provide certain evidence
necessary for the pipeline to determine its income tax
allowance. The tax allowance policy and the December 2005 order
were appealed to the United States Court of Appeals for the
District of Columbia Circuit, or D.C. Circuit. The D.C. Circuit
denied these appeals in May 2007 in ExxonMobil Oil
Corporation v. FERC and fully upheld the FERCs
new tax allowance policy and the application of that policy in
the December 2005 order. In 2007, the D.C. Circuit denied
rehearing of its ExxonMobil decision. The ExxonMobil
decision, its applicability and the issue of the inclusion
of an income tax allowance have been the subject of extensive
litigation before the FERC. Whether a pipelines owners
have actual or potential income tax liability continues to be
reviewed by FERC on a
case-by-case
basis. How the FERC applies ExxonMobil and the policy to
pipelines owned by publicly traded partnerships could impose
limits on a pipelines ability to include a full income tax
allowance in its cost of service.
In April 2008, the FERC issued a Policy Statement regarding the
composition of proxy groups for determining the appropriate
return on equity for natural gas and oil pipelines using
FERCs Discounted Cash Flow, or DCF, model for
setting
cost-of-service
or recourse rates. The FERC denied rehearing and no petitions
for review of the Policy Statement were filed. In the policy
statement, FERC concluded, among other matters that MLPs should
be included in the proxy group used to determine return on
equity for both oil and natural gas pipelines, but the long-term
growth component of the DCF model should be limited to fifty
percent of long-term gross domestic product. The adjustment to
the long-term growth component, and all other things being
equal, results in lower returns on equity than would be
calculated without the adjustment. However, the actual return on
equity for our interstate pipelines will depend on the specific
companies included in the proxy group and the specific
conditions at the time of the future rate case proceeding.
FERCs policy determinations applicable to MLPs are subject
to further modification.
Section 311
Pipelines
Intrastate transportation of natural gas is largely regulated by
the state in which such transportation takes place. To the
extent that our intrastate natural gas transportation systems
transport natural gas in interstate commerce without an
exemption under the NGA, the rates, terms and conditions of such
services are subject to FERC jurisdiction under Section 311
of the Natural Gas Policy Act, or NGPA, and Part 284 of the
FERCs regulations. Pipelines providing transportation
service under Section 311 are required to provide services
on an
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open and nondiscriminatory basis. The NGPA regulates, among
other things, the provision of transportation services by an
intrastate natural gas pipeline on behalf of a local
distribution company or an interstate natural gas pipeline. The
rates, terms and conditions of some transportation services
provided on our Section 311 pipeline systems are subject to
FERC regulation pursuant to Section 311 of the NGPA. Under
Section 311, rates charged for intrastate transportation
must be fair and equitable, and amounts collected in excess of
fair and equitable rates are subject to refund with interest.
The terms and conditions of service set forth in the intrastate
facilitys statement of operating conditions are also
subject to the FERC review and approval. Should the FERC
determine not to authorize rates equal to or greater than our
currently approved Section 311 rates, our business may be
adversely affected. Failure to observe the service limitations
applicable to transportation and storage services under
Section 311, failure to comply with the rates approved by
the FERC for Section 311 service, and failure to comply
with the terms and conditions of service established in the
pipelines FERC-approved statement of operating conditions
could result in alteration of jurisdictional status,
and/or the
imposition of administrative, civil and criminal remedies.
Hinshaw
Pipelines
Intrastate natural gas pipelines are defined as pipelines that
operate entirely within a single state, and generally are not
subject to FERCs jurisdiction under the NGA. Hinshaw
pipelines, by definition, also operate within a single state,
but can receive gas from outside their state without becoming
subject to FERCs NGA jurisdiction. Specifically,
Section 1(c) of the NGA exempts from the FERCs NGA
jurisdiction those pipelines which transport gas in interstate
commerce if (1) they receive natural gas at or within the
boundary of a state, (2) all the gas is consumed within
that state and (3) the pipeline is regulated by a state
commission. Following the enactment of the NGPA, the FERC issued
Order No. 63 authorizing Hinshaw pipelines to apply for
authorization to transport natural gas in interstate commerce in
the same manner as intrastate pipelines operating pursuant to
Section 311 of the NGPA. Hinshaw pipelines frequently
operate pursuant to blanket certificates to provide
transportation and sales service under the FERCs
regulations.
Historically, FERC did not require intrastate and Hinshaw
pipelines to meet the same rigorous transactional reporting
guidelines as interstate pipelines. However, as discussed below,
last year the FERC issued a new rule, Order No. 735, which
increases FERC regulation of certain intrastate and Hinshaw
pipelines. See Market Behavior Rules; Posting
and Reporting Requirements.
Gathering
Pipeline Regulation
Section 1(b) of the NGA exempts natural gas gathering
facilities from the jurisdiction of FERC. However, some of our
natural gas gathering activity is subject to Internet posting
requirements imposed by FERC as a result of FERCs market
transparency initiatives. We believe that our natural gas
pipelines meet the traditional tests that FERC has used to
determine that a pipeline is a gathering pipeline and is,
therefore, not subject to FERC jurisdiction. The distinction
between FERC-regulated transmission services and federally
unregulated gathering services, however, is the subject of
substantial, on-going litigation, so the classification and
regulation of our gathering facilities are subject to change
based on future determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes
various safety, environmental and, in some circumstances,
nondiscriminatory take requirements and complaint-based rate
regulation. In recent years, FERC has taken a more light-handed
approach to regulation of the gathering activities of interstate
pipeline transmission companies, which has resulted in a number
of such companies transferring gathering facilities to
unregulated affiliates. As a result of these activities, natural
gas gathering may begin to receive greater regulatory scrutiny
at both the state and federal levels. Our natural gas gathering
operations could be adversely affected should they be subject to
more stringent application of state or federal regulation of
rates and services. Our natural gas gathering operations also
may be or become subject to additional safety and operational
regulations relating to the design, installation, testing,
construction, operation, replacement and management of gathering
facilities. Additional rules and legislation pertaining to these
matters are considered or adopted from time to time. We cannot
predict what effect, if any, such changes might have on our
operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on
future legislative and regulatory changes.
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Our natural gas gathering operations are subject to ratable take
and common purchaser statutes in most of the states in which we
operate. These statutes generally require our gathering
pipelines to take natural gas without undue discrimination as to
source of supply or producer. These statutes are designed to
prohibit discrimination in favor of one producer over another
producer or one source of supply over another source of supply.
The regulations under these statutes can have the effect of
imposing some restrictions on our ability as an owner of
gathering facilities to decide with whom we contract to gather
natural gas. The states in which we operate have adopted a
complaint-based regulation of natural gas gathering activities,
which allows natural gas producers and shippers to file
complaints with state regulators in an effort to resolve
grievances relating to gathering access and rate discrimination.
We cannot predict whether such a complaint will be filed against
us in the future. Failure to comply with state regulations can
result in the imposition of administrative, civil and criminal
remedies. To date, there has been no adverse effect to our
system due to these regulations.
Market
Behavior Rules; Posting and Reporting Requirements
On August 8, 2005, Congress enacted the Energy Policy Act
of 2005, or the EPAct 2005. Among other matters, the EPAct 2005
amended the NGA to add an anti-manipulation provision which
makes it unlawful for any entity to engage in prohibited
behavior in contravention of rules and regulations to be
prescribed by FERC and, furthermore, provides FERC with
additional civil penalty authority. On January 19, 2006,
FERC issued Order No. 670, a rule implementing the
anti-manipulation provision of the EPAct 2005, and subsequently
denied rehearing. The rules make it unlawful for any entity,
directly or indirectly in connection with the purchase or sale
of natural gas subject to the jurisdiction of FERC or the
purchase or sale of transportation services subject to the
jurisdiction of FERC to (1) use or employ any device,
scheme or artifice to defraud; (2) to make any untrue
statement of material fact or omit to make any such statement
necessary to make the statements made not misleading; or
(3) to engage in any act or practice that operates as a
fraud or deceit upon any person. The new anti-manipulation rules
apply to interstate gas pipelines and storage companies and
intrastate gas pipelines and storage companies that provide
interstate services, such as Section 311 service, as well
as otherwise non-jurisdictional entities to the extent the
activities are conducted in connection with gas
sales, purchases or transportation subject to FERC jurisdiction.
The new anti-manipulation rules do not apply to activities that
relate only to intrastate or other non-jurisdictional sales or
gathering, but only to the extent such transactions do not have
a nexus to jurisdictional transactions. The EPAct
2005 also amends the NGA and the NGPA to give FERC authority to
impose civil penalties for violations of these statutes, up to
$1,000,000 per day per violation for violations occurring after
August 8, 2005. In connection with this enhanced civil
penalty authority, FERC issued a policy statement on enforcement
to provide guidance regarding the enforcement of the statutes,
orders, rules and regulations it administers, including factors
to be considered in determining the appropriate enforcement
action to be taken. Should we fail to comply with all applicable
FERC-administered statutes, rule, regulations and orders, we
could be subject to substantial penalties and fines.
The EPAct of 2005 also added a section 23 to the NGA
authorizing the FERC to facilitate price transparency in markets
for the sale or transportation of physical natural gas in
interstate commerce. In 2007, FERC took steps to enhance its
market oversight and monitoring of the natural gas industry by
issuing several rulemaking orders designed to promote gas price
transparency and to prevent market manipulation. In December
2007, FERC issued a final rule on the annual natural gas
transaction reporting requirements, as amended by subsequent
orders on rehearing, or Order No. 704. Order No. 704
requires buyers and sellers of annual quantities of natural gas
of 2,200,000 MMBtu or more, including entities not
otherwise subject to FERC jurisdiction, to submit on May 1 of
each year an annual report to FERC describing their aggregate
volumes of natural gas purchased or sold at wholesale in the
prior calendar year to the extent such transactions utilize,
contribute to or may contribute to the formation of price
indices. Order No. 704 also requires market participants to
indicate whether they report prices to any index publishers and,
if so, whether their reporting complies with FERCs policy
statement on price reporting. In June 2010, the FERC issued the
last of its three orders on rehearing and clarification further
clarifying its requirements.
In 2008, the FERC issued Order No. 720 which increases the
Internet posting obligations of interstate pipelines, and also
requires major non-interstate pipelines (defined as
pipelines that are not natural gas
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companies under the NGA that deliver more than 50 million
MMBtu annually) to post on the Internet the daily volumes
scheduled for each receipt and delivery point on their systems
with a design capacity of 15,000 MMBtu per day or greater.
Numerous parties requested modification or reconsideration of
this rule. An order on rehearing, Order
No. 720-A,
was issued on January 21, 2010. In that order the FERC
reaffirmed its holding that it has jurisdiction over major
non-interstate pipelines for the purpose of requiring public
disclosure of information to enhance market transparency. Order
No. 720-A
also granted clarification regarding application of the rule.
Two parties have filed appeals of Order Nos. 720 and
720-A to the
Fifth Circuit. The parties have filed briefs but no decision has
been issued.
In May 2010, the FERC issued Order No. 735, which requires
intrastate pipelines providing transportation services under
Section 311 of the NGPA and Hinshaw pipelines operating
under Section 1(c) of the NGA to report on a quarterly
basis more detailed transportation and storage transaction
information, including: rates charged by the pipeline under each
contract; receipt and delivery points and zones or segments
covered by each contract; the quantity of natural gas the
shipper is entitled to transport, store, or deliver; the
duration of the contract; and whether there is an affiliate
relationship between the pipeline and the shipper. Order
No. 735 further requires that such information must be
supplied through a new electronic reporting system and will be
posted on FERCs website, and that such quarterly reports
may not contain information redacted as privileged. The FERC
promulgated this rule after determining that such transactional
information would help shippers make more informed purchasing
decisions and would improve the ability of both shippers and the
FERC to monitor actual transactions for evidence of market power
or undue discrimination. Order No. 735 also extends the
Commissions periodic review of the rates charged by the
subject pipelines from three years to five years. Order
No. 735 becomes effective on April 1, 2011. In
December 2010, the Commission issued Order
No. 735-A.
In Order
No. 735-A,
the Commission generally reaffirmed Order No. 735 requiring
section 311 and Hinshaw pipelines to report on
a quarterly basis storage and transportation transactions
containing specific information for each transaction, aggregated
by contract.
In July 2010, for the first time the FERC issued an order
finding that the prohibition against buy/sell arrangements
applies to interstate open access services provided by
Section 311 and Hinshaw pipelines. The FERC denied numerous
requests for rehearing and motions for late interventions that
were filed in response to the July order. However, in October
2010, the FERC issued a Notice of Inquiry seeking public comment
on the issue of whether and how parties that hold firm capacity
on some intrastate pipelines can allow others to use their
capacity, including to what extent buy/sell transactions should
permitted and whether the FERC should consider requiring such
pipelines to offer capacity release programs. In the Notice of
Inquiry, the FERC granted a blanket waiver regarding such
transactions while the FERC is considering these policy issues.
The comment period has ended but the FERC has not yet issued an
order.
Offshore
Natural Gas Pipelines
Our offshore natural gas gathering pipelines are subject to
federal regulation under the Outer Continental Shelf Lands Act,
which requires that all pipelines operating on or across the
outer continental shelf provide open and nondiscriminatory
access to shippers. From 1982 until 2010, the Minerals
Management Service, or MMS, of the U.S. Department of the
Interior, or DOI, was the federal agency that managed the
nations oil, natural gas, and other mineral resources on
the outer continental shelf, which is all submerged lands lying
seaward of state coastal waters which are under
U.S. jurisdiction, and collected, accounted for, and
disbursed revenues from federal offshore mineral leases. On
June 18, 2010, the Minerals Management Service was renamed
the Bureau of Ocean Energy Management, Regulation and
Enforcement, or BOEMRE. The BOEMRE currently regulates offshore
operations, including engineering and construction
specifications for production facilities, safety procedures,
plugging and abandonment of wells on the outer continental
shelf, and removal of facilities. On January 19, 2011, the
U.S. Department of the Interior announced the structures
and responsibilities of the two remaining agencies, with the
reorganization of BOEMRE into these agencies to be completed by
October 1, 2011. Once the reorganization is complete, the
BOEMRE will cease to exist. At this time, we cannot predict the
impact that this reorganization, or future regulations or
enforcement actions taken by the new agencies, may have on our
operations.
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Sales
of Natural Gas and NGLs
Historically, the transportation and sale for resale of natural
gas in interstate commerce has been regulated by the FERC under
the NGA, the NGPA, and regulations issued under those statutes.
In the past, the federal government has regulated the prices at
which natural gas could be sold. While sales by producers of
natural gas can currently be made at market prices, Congress
could reenact price controls in the future. Deregulation of
wellhead natural gas sales began with the enactment of the NGPA
and culminated in adoption of the Natural Gas Wellhead Decontrol
Act which removed all price controls affecting wellhead sales of
natural gas effective January 1, 1993.
The price at which we sell natural gas is not currently subject
to federal rate regulation and, for the most part, is not
subject to state regulation. However, with regard to our
physical sales of these energy commodities, we are required to
observe anti-market manipulation laws and related regulations
enforced by the FERC
and/or the
Commodity Futures Trading Commission, or the CFTC, and the
Federal Trade Commission, or FTC. Should we violate the
anti-market manipulation laws and regulations, we could also be
subject to related third-party damage claims by, among others,
sellers, royalty owners and taxing authorities.
Sales of NGLs are not currently regulated and are made at
negotiated prices. Nevertheless, Congress could enact price
controls in the future.
As discussed above, the price and terms of access to pipeline
transportation are subject to extensive federal and state
regulation. The FERC is continually proposing and implementing
new rules and regulations affecting interstate natural gas
pipelines and those initiatives may also affect the intrastate
transportation of natural gas both directly and indirectly.
Environmental
Matters
General
Our operation of pipelines, plants and other facilities for the
gathering, compressing, treating and transporting of natural gas
and other products is subject to stringent and complex federal,
state and local laws and regulations relating to the protection
of the environment. As an owner or operator of these facilities,
we must comply with these laws and regulations at the federal,
state and local levels. These laws and regulations can restrict
or impact our business activities in many ways, such as:
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requiring the installation of pollution-control equipment or
otherwise restricting the way we operate;
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limiting or prohibiting construction activities in sensitive
areas, such as wetlands, coastal regions or areas inhabited by
endangered or threatened species;
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delaying system modification or upgrades during permit reviews;
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requiring investigatory and remedial actions to mitigate
pollution conditions caused by our operations or attributable to
former operations; and
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enjoining the operations of facilities deemed to be in
non-compliance with permits issued pursuant to such
environmental laws and regulations.
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Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties.
Certain environmental statutes impose strict joint and several
liability for costs required to clean up and restore sites where
substances, hydrocarbons or wastes have been disposed or
otherwise released. Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances, hydrocarbons or other waste products into
the environment.
The trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, there can be no assurance as to the
amount or timing of future expenditures for environmental
compliance or remediation and actual future expenditures may be
different from the
130
amounts we currently anticipate. We try to anticipate future
regulatory requirements that might be imposed and plan
accordingly to remain in compliance with changing environmental
laws and regulations and to minimize the costs of such
compliance. We also actively participate in industry groups that
help formulate recommendations for addressing existing or future
regulations.
We do not believe that compliance with federal, state or local
environmental laws and regulations will have a material adverse
effect on our business, financial position or results of
operations or cash flows. In addition, we believe that the
various environmental activities in which we are presently
engaged are not expected to materially interrupt or diminish our
operational ability to gather, compress, treat and transport
natural gas. We cannot assure you, however, that future events,
such as changes in existing laws or enforcement policies, the
promulgation of new laws or regulations or the development or
discovery of new facts or conditions will not cause us to incur
significant costs. Below is a discussion of the material
environmental laws and regulations that relate to our business.
We believe that we are in substantial compliance with all of
these environmental laws and regulations.
Hazardous
Substances and Waste
Our operations are subject to environmental laws and regulations
relating to the management and release of hazardous substances,
solid and hazardous wastes and petroleum hydrocarbons. These
laws generally regulate the generation, storage, treatment,
transportation and disposal of solid and hazardous waste and may
impose strict joint and several liability for the investigation
and remediation of affected areas where hazardous substances may
have been released or disposed. For instance, the Comprehensive
Environmental Response, Compensation, and Liability Act,
referred to as CERCLA or the Superfund law, and comparable state
laws impose liability, without regard to fault or the legality
of the original conduct, on certain classes of persons that
contributed to the release of a hazardous substance into the
environment. We may handle hazardous substances within the
meaning of CERCLA, or similar state statutes, in the course of
our ordinary operations and, as a result, may be jointly and
severally liable under CERCLA for all or part of the costs
required to clean up sites at which these hazardous substances
have been released into the environment.
We also generate industrial wastes that are subject to the
requirements of the Resource Conservation and Recovery Act,
referred to as RCRA, and comparable state statutes. While RCRA
regulates both solid and hazardous wastes, it imposes strict
requirements on the generation, storage, treatment,
transportation and disposal of hazardous wastes. We generate
little hazardous waste; however, it is possible that these
wastes, which could include wastes currently generated during
our operations, will in the future be designated as
hazardous wastes and, therefore, be subject to more
rigorous and costly disposal requirements. Any such changes in
the laws and regulations could have a material adverse effect on
our maintenance capital expenditures and operating expenses.
We currently own or lease, and our Predecessor has in the past
owned or leased, properties where hydrocarbons are being or have
been handled for many years. Although previous operators have
utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have
been disposed of or released on or under the properties owned or
leased by us or on or under the other locations where these
hydrocarbons and wastes have been transported for treatment or
disposal. These properties and the wastes disposed thereon may
be subject to CERCLA, RCRA and analogous state laws. Under these
laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by
prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial
operations to prevent future contamination. We are not currently
aware of any facts, events or conditions relating to such
requirements that could materially impact our operations or
financial condition.
Oil
Pollution Act
In January of 1974, the EPA adopted regulations under the OPA.
These oil pollution prevention regulations require the
preparation of a Spill Prevention Control and Countermeasure
Plan or SPCC for facilities engaged in drilling, producing,
gathering, storing, processing, refining, transferring,
distributing, using, or consuming oil and oil products, and
which due to their location, could reasonably be expected to
131
discharge oil in harmful quantities into or upon the navigable
waters of the United States. The owner or operator of an
SPCC-regulated facility is required to prepare a written,
site-specific spill prevention plan, which details how a
facilitys operations comply with the requirements. To be
in compliance, the facilitys SPCC plan must satisfy all of
the applicable requirements for drainage, bulk storage tanks,
tank car and truck loading and unloading, transfer operations
(intrafacility piping), inspections and records, security, and
training. Most importantly, the facility must fully implement
the SPCC plan and train personnel in its execution. We believe
that our facilities will not be materially adversely affected by
such requirements, and the requirements are not expected to be
any more burdensome to us than to any other similarly situated
companies.
Air
Emissions
Our operations are subject to the federal Clean Air Act and
comparable state and local laws and regulations. These laws and
regulations regulate emissions of air pollutants from various
industrial sources, including our compressor stations and
processing plants, and also impose various monitoring and
reporting requirements. Such laws and regulations may require
that we obtain pre-approval for the construction or modification
of certain projects or facilities expected to produce or
significantly increase air emissions, obtain and strictly comply
with air permits containing various emissions and operational
limitations and utilize specific emission control technologies
to limit emissions. Our failure to comply with these
requirements could subject us to monetary penalties,
injunctions, conditions or restrictions on operations and,
potentially, criminal enforcement actions. We believe that we
are in substantial compliance with these requirements. We may be
required to incur certain capital expenditures in the future for
air pollution control equipment in connection with obtaining and
maintaining operating permits and approvals for air emissions.
We believe, however, that our operations will not be materially
adversely affected by such requirements, and the requirements
are not expected to be any more burdensome to us than to any
other similarly situated companies.
Water
Discharges
The Federal Water Pollution Control Act, or the Clean Water Act,
and analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into state waters as well
as waters of the U.S. and to conduct construction
activities in waters and wetlands. Certain state regulations and
the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of
pollutants and chemicals. Spill prevention, control and
countermeasure requirements of federal laws require appropriate
containment berms and similar structures to help prevent the
contamination of regulated waters in the event of a hydrocarbon
tank spill, rupture or leak. In addition, the Clean Water Act
and analogous state laws require individual permits or coverage
under general permits for discharges of storm water runoff from
certain types of facilities. These permits may require us to
monitor and sample the storm water runoff from certain of our
facilities. Some states also maintain groundwater protection
programs that require permits for discharges or operations that
may impact groundwater conditions. Federal and state regulatory
agencies can impose administrative, civil and criminal penalties
for non-compliance with discharge permits or other requirements
of the Clean Water Act and analogous state laws and regulations.
We believe that compliance with existing permits and compliance
with foreseeable new permit requirements will not have a
material adverse effect on our financial condition, results of
operations or cash flow.
Safe
Drinking Water Act
The underground injection of oil and natural gas wastes are
regulated by the Underground Injection Control program
authorized by the Safe Drinking Water Act. The primary objective
of injection well operating requirements is to ensure the
mechanical integrity of the injection apparatus and to prevent
migration of fluids from the injection zone into underground
sources of drinking water. We own and operate an acid gas
disposal well in Wayne County, Mississippi as part of our Bazor
Ridge gas treating facilities. This well takes a combination of
hydrogen sulfide and carbon dioxide recovered from the raw field
natural gas feeding the Bazor Ridge Gas plant and injects it
into an underground formation permitted for this purpose. The
well received an Underground Injection Control (UIC)
Class 2 permit through the Mississippi state oil and gas
board in 1999. As part of our permit requirements, we perform
regular inspection, maintenance and reporting
132
to the state on the condition and operations of this well which
is adjacent to our processing plant. We believe that our
facilities will not be materially adversely affected by such
requirements.
Endangered
Species
The Endangered Species Act, or ESA, restricts activities that
may affect endangered or threatened species or their habitats.
While some of our pipelines may be located in areas that are
designated as habitats for endangered or threatened species, we
believe that we are in substantial compliance with the ESA.
However, the designation of previously unidentified endangered
or threatened species could cause us to incur additional costs
or become subject to operating restrictions or bans in the
affected states.
National
Environmental Policy Act
The National Environmental Policy Act, or NEPA, establishes a
national environmental policy and goals for the protection,
maintenance, and enhancement of the environment and provides a
process for implementing these goals within federal agencies. A
major federal agency action having the potential to
significantly impact the environment requires review under NEPA
and, as a result, many activities requiring FERC approval must
undergo NEPA review. Many of our activities are covered under
categorical exclusions which results in a shorter NEPA review
process. The Council on Environmental Quality has announced an
intention to reinvigorate NEPA reviews which may result in
longer review processes that could lead to delays and increased
costs that could materially adversely affect our revenues and
results of operations.
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 Earths atmosphere. In
response to the scientific studies, international negotiations
to address climate change have occurred. The United Nations
Framework Convention on Climate Change, also known as the
Kyoto Protocol, became effective on
February 16, 2005 as a result of these negotiations, but
the United States did not ratify the Kyoto Protocol. At the end
of 2009, an international conference to develop a successor to
the Kyoto Protocol issued a document known as the Copenhagen
Accord. Pursuant to the Copenhagen Accord, the United States
submitted a greenhouse gas emission reduction target of
17 percent compared to 2005 levels. We continue to monitor
the international efforts to address climate change. Their
effect on our operations cannot be determined with any certainty
at this time.
In the U.S., legislative and regulatory initiatives are underway
to limit GHG emissions. The U.S. Congress has considered
legislation that would control GHG emissions through a cap
and trade program and several states have already
implemented programs to reduce GHG emissions. The
U.S. Supreme Court determined that GHG emissions fall
within the federal Clean Air Act, or the CAA, definition of an
air pollutant, and in response the EPA promulgated
an endangerment finding paving the way for regulation of GHG
emissions under the CAA. In 2010, the EPA issued a final rule,
known as the Tailoring Rule, that makes certain
large stationary sources and modification projects subject to
permitting requirements for greenhouse gas emissions under the
Clean Air Act.
In addition, on September 2009, the EPA issued a final rule
requiring the reporting of GHGs from specified large GHG
emission sources in the U.S. beginning in 2011 for
emissions in 2010. Our Bazor Ridge facility is currently
required to report under this rule beginning in 2011. On
November 30, 2010, the EPA published a final rule expanding
its existing GHG emissions reporting to include onshore and
offshore oil and natural gas systems beginning in 2012. Three of
our onshore compression facilities will likely be required to
report under this rule, with the first report due to the EPA on
March 31, 2012.
Because regulation of GHG emissions is relatively new, further
regulatory, legislative and judicial developments are likely to
occur. Such developments may affect how these GHG initiatives
will impact us. In addition to these regulatory developments,
recent judicial decisions have allowed certain tort claims
alleging property damage to proceed against GHG emissions
sources may increase our litigation risk for such claims. Due to
the uncertainties surrounding the regulation of and other risks
associated with GHG emissions, we cannot predict the financial
impact of related developments on us.
133
Legislation or regulations that may be adopted to address
climate change could also affect the markets for our products by
making our products more or less desirable than competing
sources of energy. To the extent that our products are competing
with higher greenhouse gas emitting energy sources such as coal,
our products would become more desirable in the market with more
stringent limitations on greenhouse gas emissions. To the extent
that our products are competing with lower greenhouse gas
emitting energy sources such as solar and wind, our products
would become less desirable in the market with more stringent
limitations on greenhouse gas emissions. We cannot predict with
any certainty at this time how these possibilities may affect
our operations.
The majority of scientific studies on climate change suggest
that stronger storms may occur in the future in the areas where
we operate, although the scientific studies are not unanimous.
Due to their location, our operations along the Gulf Coast are
vulnerable to operational and structural damages resulting from
hurricanes and other severe weather systems and our insurance
may not cover all associated losses. We are taking steps to
mitigate physical risks from storms, but no assurance can be
given that future storms will not have a material adverse effect
on our business.
Anti-terrorism
Measures
The Department of Homeland Security Appropriation Act of 2007
requires the Department of Homeland Security, or DHS, to issue
regulations establishing risk-based performance standards for
the security of chemical and industrial facilities, including
oil and gas facilities that are deemed to present high
levels of security risk. The DHS issued an interim final
rule in April 2007 regarding risk-based performance standards to
be attained pursuant to this act and, on November 20, 2007,
further issued an Appendix A to the interim rules that
establish chemicals of interest and their respective threshold
quantities that will trigger compliance with these interim
rules. Covered facilities that are determined by DHS to pose a
high level of security risk will be required to prepare and
submit Security Vulnerability Assessments and Site Security
Plans as well as comply with other regulatory requirements,
including those regarding inspections, audits, recordkeeping,
and protection of chemical-terrorism vulnerability information.
Three of our facilities have more than the threshold quantity of
listed chemicals; therefore, a Top Screen evaluation
was submitted to the DHS. The DHS reviewed this information and
made the determination that none of the facilities are
considered high-risk chemical facilities.
Title to
Properties and
Rights-of-Way
Our real property falls into two categories: (1) parcels
that we own in fee and (2) parcels in which our interest
derives from leases, easements,
rights-of-way,
permits or licenses from landowners or governmental authorities,
permitting the use of such land for our operations. Portions of
the land on which our plants and other major facilities are
located are owned by us in fee title, and we believe that we
have satisfactory title to these lands. The remainder of the
land on which our plant sites and major facilities are located
are held by us pursuant to surface leases between us, as lessee,
and the fee owner of the lands, as lessors. Our Predecessors
leased or owned these lands for many years without any material
challenge known to us relating to the title to the land upon
which the assets are located, and we believe that we have
satisfactory leasehold estates or fee ownership in such lands.
We have no knowledge of any challenge to the underlying fee
title of any material lease, easement,
right-of-way,
permit or license held by us or to our title to any material
lease, easement,
right-of-way,
permit or lease, and we believe that we have satisfactory title
to all of our material leases, easements,
rights-of-way,
permits and licenses.
Employees
We do not have any employees. The officers of our general
partner will manage our operations and activities. As of
December 31, 2010, our general partner employed
approximately 76 people who will provide direct, full-time
support to our operations. All of the employees required to
conduct and support our operations will be employed by our
general partner. None of these employees are covered by
collective bargaining agreements, and our general partner
considers its employee relations to be good.
134
Legal
Proceedings
We are not a party to any legal proceeding other than legal
proceedings arising in the ordinary course of our business. We
are a party to various administrative and regulatory proceedings
that have arisen in the ordinary course of our business. Please
read Regulation of Operations
Interstate Transportation Pipeline Regulation and
Environmental Matters.
135
MANAGEMENT
We are managed by the directors and executive officers of our
general partner, American Midstream GP. Our general partner is
not elected by our unitholders and will not be subject to
re-election in the future. AIM Midstream Holdings owns all of
the membership interests in our general partner. Our general
partner has a board of directors, and our unitholders are not
entitled to elect the directors or directly or indirectly
participate in our management or operations. AIM, Eagle River
Ventures, LLC, Stockwell Fund II, L.P. and certain of our
executive officers own all of the membership interests in AIM
Midstream Holdings. In addition, Messrs. Hellman, Carbone
and Diffendal serve on the board of directors of our general
partner and are principals of and have ownership interests in
AIM. Our general partner owes certain fiduciary duties to our
unitholders. Our general partner will be liable, as general
partner, for all of our debts (to the extent not paid from our
assets), except for indebtedness or other obligations that are
made specifically nonrecourse to it. Whenever possible, we
intend to incur indebtedness that is nonrecourse to our general
partner.
Our partnership agreement provides for the conflicts committee
of the board of directors of our general partner, or the
Conflicts Committee, as delegated by the board of directors of
our general partner as circumstances warrant, to review
conflicts of interest between us and our general partner or
between us and affiliates of our general partner. If a matter is
submitted to the Conflicts Committee, which will consist solely
of independent directors, for their review and approval, the
Conflicts Committee will determine if the resolution of a
conflict of interest that has been presented to it by the board
of directors of our general partner is fair and reasonable to
us. The members of the Conflicts Committee may not be executive
officers or employees of our general partner or directors,
executive officers or employees of its affiliates. In addition,
the members of the Conflicts Committee must meet the
independence and experience standards established by the NASDAQ
and the Exchange Act for service on an audit committee of a
board of directors. Any matters approved by the Conflicts
Committee will be conclusively deemed to be fair and reasonable
to us, approved by all of our partners and not a breach by our
general partner of any duties it may owe us or our unitholders.
In addition, the board of directors of our general partner will
have an audit committee, or the Audit Committee, that complies
with the NASDAQ requirements, and a compensation committee of
the board of directors, or the Compensation Committee.
Even though most companies listed on the NASDAQ are required to
have a majority of independent directors serving on the board of
directors of the listed company, the NASDAQ does not require a
listed limited partnership like us to have a majority of
independent directors on the board of directors of its general
partner.
L. Kent Moore, Matthew P. Carbone, David L. Page and Edward O.
Diffendal will serve as the initial members of the Audit
Committee. L. Kent Moore serves as the chairman of the Audit
Committee. In compliance with the rules of the NASDAQ, the
members of the board of directors will appoint one additional
independent member to the board of directors within twelve
months of this offering, and that director will replace Edward
O. Diffendal as a member of the Audit Committee upon
appointment. Thereafter, our general partner is generally
required to have at least three independent directors serving on
its board at all times.
Robert B. Hellman and L. Kent Moore serve as the members of the
Compensation Committee. Robert B. Hellman serves as the chairman
of the Compensation Committee.
Robert B. Hellman and Matthew P. Carbone serve as the members of
the Compliance Committee. Robert B. Hellman serves as the
chairman of the Compliance Committee.
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Directors are appointed for a term of one year and hold office
until their successors have been elected or qualified or until
the earlier of their death, resignation, removal or
disqualification. Officers serve at the discretion of the board.
The following table shows information for the directors and
executive officers of our general partner.
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Name
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Age
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Position with American Midstream GP, LLC
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Robert B. Hellman
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53
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Chairman of the Board
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Brian F. Bierbach
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53
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Director, President and Chief Executive Officer
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Sandra M. Flower
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51
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Vice President of Finance
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John J. Connor II
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54
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Senior Vice President of Operations and Engineering
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Marty W. Patterson
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52
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Senior Vice President of Commercial Services
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William B. Mathews
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59
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Secretary, General Counsel and Vice President of Legal Affairs
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Matthew P. Carbone
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45
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Director
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Edward O. Diffendal
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41
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Director
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David L. Page
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76
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Director
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L. Kent Moore
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55
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Director
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Robert B. Hellman was elected Chairman of the
board of directors of our general partner in November 2009.
Mr. Hellman has been a Managing Director of AIM since he
co-founded AIM in July of 2006. Prior to co-founding AIM,
Mr. Hellman was a Managing Director of McCown De
Leeuw & Co., a private equity firm based in Foster
City, California since 1986. Mr. Hellman is also chairman
of the Board of Directors of Stonemor Partners L.P.
Mr. Hellman received an MBA from Harvard University, an
M.A. in Economics from the London School of Economics and a B.A.
in Economics from Stanford University.
Brian F. Bierbach was appointed President and
Chief Executive Officer, and elected as a member of the board of
directors of our general partner in November 2009. Prior to our
formation, Mr. Bierbach served as President and as a member
of the board of directors of Foothills Energy Ventures, LLC, a
private midstream natural gas asset development and operating
company, from 2006 to 2009. Mr. Bierbach has also served as
President of Cinergy Canada, Inc. from 2003 to 2005 and
President of Bear Paw Energy, LLC, a subsidiary of Northern
Border Partners, L.P., from 2000 to 2002. He also held various
positions with Enron Corporation, The Williams Companies, Inc.,
Apache Corporation and ConocoPhillips. He received a B.S. in
Civil Engineering from the University of Arizona.
Sandra M. Flower has served as Vice President of
Finance of our general partner since November 2009.
Ms. Flower also served as our Controller from November 2009
until March 2011. Prior to our formation, Ms. Flower served
as Group Controller at TransMontaigne, Inc. and as Director of
Internal Audit for TransMontaigne Partners, LP from 2005 to
2009. While at TransMontaigne, she was responsible for trading
support, credit, accounting and consolidation activities of
TransMontaigne Inc., as well as supervising the design and
implementation of all internal audit activities including
Sarbanes-Oxley compliance procedures. Ms. Flower began her
career at Touche Ross & Co. She received a B.S.B.A. from
the University of Rhode Island and is a CPA.
John J. Connor II has served as Senior Vice
President of Operations and Engineering of our general partner
since November 2009. Prior to our formation, Mr. Connor
served as Vice President of Development at Foothills Energy
Ventures, LLC. Prior to Foothills, he was Director of Midstream
Operations at Black Hills Midstream, LLC from 2006 to 2007 and
held various Director and General Manager positions at
El Paso Corporation from 1980 to 2004. Mr. Connor
received his B.S. in Civil Engineering from Colorado State
University and is a licensed professional engineer.
Marty W. Patterson has served as Senior Vice
President of Commercial Services of our general partner since
November 2009. Prior to our formation, he served as Vice
President of Commercial Operations at Foothills Energy Ventures,
LLC from 2006 to 2009. Prior to joining Foothills,
Mr. Patterson was the Director of Commercial Operations
with Cinergy Corp. from 2004 to 2006. Before that, he was the
Senior VP Energy Services, IDACORP Energy, L.P. from 1997 to
2003, and held various other positions, focused on operations.
137
Mr. Patterson received his degree in Petroleum Technology
from Kilgore College and is currently a board member of the
North American Energy Standards Board.
William B. Mathews has served as Secretary and
Vice President of Legal Affairs of our general partner since
November 2009 and General Counsel of our general partner since
March 2011. Prior to our formation, he served as Vice President,
General Counsel and Secretary of Foothills Energy Ventures, LLC
from December 2006 to November 2009, as well as a director from
August 2009 to November 2009. Prior to Foothills,
Mr. Mathews served as Assistant General Counsel for ONEOK
Partners, L.P., Northern Border Partners, L.P. and Bear Paw
Energy, LLC from July 2001 to December 2006 and, previous to
that, as Vice President and General Counsel of Duke Energy Field
Services (now DCP Midstream, LLC) until 2000, having joined a
predecessor company in 1985. He received a J.D. from the
University of Denver and a B.S. in Civil Engineering from the
University of Colorado.
Matthew P. Carbone was elected as a member of the
board of directors of our general partner in November 2009.
Mr. Carbone has been a Managing Director of AIM since he
co-founded AIM in July 2006. Prior to co-founding AIM, from
January 2005 until July 2006, Mr. Carbone was a Managing
Director of McCown De Leeuw & Co., or MDC.
Mr. Carbone has spent nearly 20 years in private
equity and investment banking. Prior to MDC he led Wit Capital
Groups West Coast operations and worked in the investment
banking divisions of Morgan Stanley, First Boston Corporation
and Smith Barney. Mr. Carbone is also a member of the board
of directors of the general partner of Oxford Resource Partners
L.P. He received an MBA from Harvard Business School and a B.A.
in Neuroscience from Amherst College.
Edward O. Diffendal was elected as a member of the
board of directors of our general partner in November 2009.
Mr. Diffendal has been a Principal with AIM since September
2007. Prior to joining AIM he served as a management consultant
from 2005 to 2007, held various operating positions at Veritas
Software Corp. from 2003 to 2005, was a Vice President at
Broadview Capital Partners, L.P. from 2000 to 2003 and was a
consultant at Monitor Company from 1991 to 1998.
Mr. Diffendal received an MBA from Dartmouth College and
M.A. and B.A. degrees in Economics from Stanford University.
David L. Page was elected as a member of the board
of directors of our general partner in February 2010.
Mr. Page also serves as Chairman of the Executive Committee
and a member of the Audit Committee of our General Partner.
Mr. Page has served as a management consultant since
February 2002. Prior to working as a management consultant,
Mr. Page served as Chairman and Chief Executive Officer of
Distribution Dynamics, Inc. from January 2000 until February
2002. His earlier career included a variety of management roles
at McCown De Leeuw & Co. from 1994 through 2000. Prior
to joining McCown De Leeuw & Co., Mr. Page was
President and Chief Executive Officer of Page Packaging
Corporation from 1987 through 1993, and Vice President and
General Manager of Boise Cascade Corporation from 1959 through
1987. Mr. Page received a B.A. in Business Administration
and Economics from Whitman College and completed the Executive
Program at Stanford University.
L. Kent Moore was elected as a member of the board
of directors of our general partner in November 2009.
Mr. Moore owns Eagle River Ventures, LLC, which holds
mostly oil and gas investments and a 0.5% interest in AIM
Midstream Holdings. Mr. Moore is currently a director of
Foothills Energy Ventures, LLC. From 2006 through 2009,
Mr. Moore also served as chairman of the board of
Foothills. He also serves as chairman of the board of trustees
for the Old Mutual Funds I and II, and also a trustee of the
TS&W/Claymore Long Short Fund. He has also served as a
portfolio manager and vice-president at Janus Capital, and as
analyst/portfolio manager for Marsico Capital Management,
focusing on technology and energy stocks. Before working in the
mutual fund industry, Mr. Moore was a vice-president with
Exeter Drilling Company and also co-founded and was President of
Caza Drilling Company. Mr. Moore received B.S. in
Industrial Management from Purdue University.
Compensation
Discussion and Analysis
Our general partner, under the direction of its board of
directors, or the Board, is responsible for managing our
operations and employs all of the employees that operate our
business. The compensation
138
payable to the officers of our general partner is paid by our
general partner and such payments are reimbursed by us on a
dollar-for-dollar
basis. See The Partnership Agreement
Reimbursement of Expenses.
The following is a discussion of the compensation policies and
decisions of the Compensation Committee of the Board, with
respect to the following individuals, who are executive officers
of our general partner and referred to as the named
executive officers for the fiscal year ended
December 31, 2010:
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Brian F. Bierbach, President and Chief Executive Officer;
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Sandra M. Flower, Vice President of Finance;
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John J. Connor, Senior Vice President of Operations and
Engineering;
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Marty W. Patterson, Senior Vice President of Commercial
Services; and
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William B. Mathews, Secretary, General Counsel and Vice
President of Legal Affairs.
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Our compensation program is designed to recruit and retain as
executive officers individuals with the highest capacity to
develop, grow and manage our business, and to align their
compensation with our short-term and long-term goals. To do
this, our compensation program for executive officers is made up
of the following main components: (i) base salary, designed
to compensate our executive officers for work performed during
the fiscal year; (ii) short-term incentive programs,
designed to reward our executive officers for our yearly
performance and for their individual performances during the
fiscal year; and (iii) equity-based awards, meant to align
our executive officers interests with our long-term
performance. Going forward, we expect that the Compensation
Committee will continue to focus on these same components,
although the Compensation Committee may consider whether changes
to the types of compensation provided may be appropriate in
order to more accurately reflect a compensation program
appropriate for a publicly-traded entity.
This section should be read together with the compensation
tables that follow, which disclose the compensation awarded to,
earned by or paid to the named executive officers with respect
to the year ended December 31, 2010.
Role
of the Board, the Compensation Committee and
Management
The Board has appointed the Compensation Committee to assist the
Board in discharging its responsibilities relating to
compensation matters, including matters relating to compensation
programs for directors and executive officers of the general
partner. The Compensation Committee has overall responsibility
for evaluating and approving our compensation plans, policies
and programs, setting the compensation and benefits of executive
officers, and granting awards under and administering our equity
compensation plans. The Compensation Committee is charged with,
among other things, establishing compensation practices and
programs that are (i) designed to attract, retain and
motivate exceptional leaders, (ii) structured to align
compensation with our overall performance and growth in
distributions to unitholders, (iii) implemented to promote
achievement of short-term and long-term business objectives
consistent with our strategic plans, and (iv) applied to
reward performance.
As described in further detail below under
Elements of the Compensation Programs,
the compensation programs for our executive officers consist of
base salaries, annual incentive bonuses and awards under the
American Midstream GP, LLC Long-Term Incentive Plan, which we
refer to as our LTIP, currently in the form of equity-based
phantom units, as well as other customary employment benefits
such as a 401(k) plan and health and welfare benefits. We expect
that, following the completion of this offering, total
compensation of our executive officers and the components and
allocation among components of their annual compensation will be
reviewed on at least an annual basis by the Compensation
Committee.
During 2010 and 2011, the Compensation Committee discussed
executive compensation issues at several meetings, and the
Compensation Committee expects to hold additional executive
compensation-related meetings in 2011 and in future years.
Topics discussed and to be discussed at these meetings included
and will include, among other things, (i) assessing the
performance of the Chief Executive Officer, or the CEO, and
other executive officers with respect to our results for the
prior year, (ii) reviewing and assessing the personal
performance of the executive officers for the preceding year and
(iii) determining the amount of the bonus
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pool to be paid to our executive officers for a given year after
taking into account the target bonus amounts established for
those executive officers at the outset of the year. In addition,
at these meetings, and after taking into account the
recommendations of our CEO only with respect to executive
officers other than our CEO, base salary levels and target bonus
amounts (representing the bonus that may be awarded expressed as
a dollar amount or as a percentage of base salary for the year)
for all of our executive officers will be established by the
Compensation Committee. In addition, the Compensation Committee
will make its decisions with respect to any awards under the
LTIP. We expect that our CEO will provide periodic
recommendations to the Compensation Committee regarding the
performance and compensation of the other named executive
officers.
Compensation
Objectives and Methodology
The principal objective of our executive compensation program is
to attract and retain individuals of demonstrated competence,
experience and leadership who share our business aspirations,
values, ethics and culture. A further objective is to provide
incentives to and reward our executive officers and other key
employees for positive contributions to our business and
operations, and to align their interests with our
unitholders interests.
In setting our compensation programs, we consider the following
objectives:
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to create unitholder value through sustainable earnings and cash
available for distribution;
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to provide a significant percentage of total compensation that
is at-risk or variable;
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to encourage significant equity holdings to align the interests
of executive officers and other key employees with those of
unitholders;
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to provide competitive, performance-based compensation programs
that allow us to attract and retain superior talent; and
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to develop a strong linkage between business performance,
safety, environmental stewardship, cooperation and executive
compensation.
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Taking account of the foregoing objectives, we structure total
compensation for our executives to provide a guaranteed amount
of cash compensation in the form of competitive base salaries,
while also providing a meaningful amount of annual cash
compensation that is at risk and dependent on our performance
and individual performances of the executives, in the form of
discretionary annual bonuses. We also seek to provide a portion
of total compensation in the form of equity-based awards under
our LTIP, in order to align the interests of executives and
other key employees with those of our unitholders and for
retention purposes. Historically, we have not made regular
annual grants of awards under our LTIP. To date, the only awards
under our LTIP were made in connection with our formation,
although certain of these grants were made in 2010. Going
forward, we expect that equity-based awards will be made more
regularly and that equity-based awards will become more
prominent in our annual compensation decision-making process.
Compensation decisions for individual executive officers are the
result of the subjective analysis of a number of factors,
including the individual executive officers experience,
skills or tenure with us and changes to the individual executive
officers position. In evaluating the contributions of
executive officers and our performance, although no
pre-determined numerical goals were established, a variety of
financial measures have been generally considered, including
non-GAAP financial measures used by management to assess our
financial performance, such as adjusted EBITDA and cash
available for distribution. For a definition of adjusted EBITDA,
please read Selected Historical Consolidated Financial and
Operating Data. For a discussion of the general concept of
cash available for distribution, please read
Our Cash Distribution Policy and Restrictions on
Distributions. In addition, a variety of factors related
to the individual performance of the executive officer were
taken into consideration.
In making individual compensation decisions, the Compensation
Committee historically has not relied on pre-determined
performance goals or targets. Instead, determinations regarding
compensation have been the result of the exercise of judgment
based on all reasonably available information and, to that
extent, were discretionary. Each executive officers
current and prior compensation is considered in setting future
140
compensation. The amount of each executive officers
current compensation will be considered as a base against which
determinations are made as to whether increases are appropriate
to retain the executive officer in light of competition or in
order to provide continuing performance incentives. Subject to
the provisions contained in the executive officers
employment agreement, if any, the Compensation Committee has
discretion to adjust any of the components of compensation to
achieve our goal of recruiting, promoting and retaining as
executive officers, individuals with the skills necessary to
execute our business strategy and develop, grow and manage our
business.
To date, we have not reviewed executive compensation against a
specific group of comparable companies or publicly traded
partnerships. Rather, the Compensation Committee has
historically relied upon the judgment and industry experience of
its members in making decisions with respect to total
compensation and with respect to the allocation of total
compensation among our three main components of compensation.
Going forward, we expect that the Compensation Committee will
make compensation decisions taking into account trends occurring
within our industry, including from a peer group of companies,
which we expect will include the following similar publicly
traded partnerships: Boardwalk Pipeline Partners, LP, Regency
Energy Partners LP, Targa Resources Partners LP, MarkWest Energy
Partners LP, Copano Energy LLC, Crosstex Energy LP, and Atlas
Pipeline Partners LP. Additionally, we expect that the
Compensation Committee will take into account trends occurring
within a group of publicly traded energy companies with market
capitalizations in the same range as our own, including from a
peer group of companies, which we expect will include the
following similar publicly-traded energy companies: Contango
Oil & Gas Co., Goodrich Petroleum Corp., Kodiak
Oil & Gas Corp., Magnum Hunter Resources Corp., Penn
Virginia Corp., Resolute Energy Corporation, Approach Resources,
Inc., PetroQuest Energy Inc. and Rex Energy Corporation. To
date, the Compensation Committee has not retained the services
of any compensation consultants.
Elements
of the Compensation Programs
Overall, the executive officer compensation programs are
designed to be consistent with the philosophy and objectives set
forth above. The principal elements of our executive officer
compensation programs are summarized in the table below,
followed by a more detailed discussion of each compensation
element.
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Element
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Characteristics
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Purpose
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Base Salaries
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Fixed annual cash compensation. Executive officers are eligible
for periodic increases in base salaries. Increases may be based
on performance or such other factors as the Compensation
Committee may determine.
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Keep our annual compensation competitive with the defined market
for skills and experience necessary to execute our business
strategy.
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Annual Incentive Bonuses
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Performance-related annual cash incentives earned based on our
objectives and individual performance of the executive officers.
We expect that trends for our peer group will be taken into
account in setting future annual cash incentive awards for our
executive officers.
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Align performance to our objectives that drive our business and
reward executive officers for our yearly performance and for
their individual performances during the fiscal year.
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Element
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Characteristics
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Purpose
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Equity-Based Awards
(Phantom-units
and Distribution Equivalent Rights)
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Performance-related, equity-based awards granted at the
discretion of the Compensation Committee. Awards are based on
our performance and we expect that, going forward, will take
into account competitive practices at peer companies. Grants
typically consist of phantom units that vest ratably over four
years and may be settled upon vesting with either a net cash
payment or an issuance of common units, at the discretion of the
Board. Historically, the Board has issued common units upon
vesting of phantom units. Distribution Equivalent Rights, or
DERs, which have been granted in conjunction with such phantom
unit awards, entitle the grantee to receive cash distributions
on unvested LTIP awards to the same extent generally as
unitholders receive cash distributions on our common units.
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Align interests of executive officers with unitholders and
motivate and reward executive officers to increase unitholder
value over the long term. Ratable vesting over a four-year
period is designed to facilitate retention of executive
officers. Issuance of common units upon vesting encourages
equity ownership in order to align interests of executive
officers with those of unitholders. DERs provide a clear,
objective link between growing distributions to unitholders and
executive compensation. (1)
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Retirement Plan
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Qualified retirement plan benefits are available for our
executive officers and all other regular full-time employees.
At our formation, we adopted and are maintaining a tax-deferred
or after-tax 401(k) plan in which all eligible employees can
elect to defer compensation for retirement up to IRS imposed
limits. The 401(k) plan permits us to make annual discretionary
matching contributions to the plan. For 2010, we matched
employee contributions to 401(k) plan accounts up to a maximum
employer contribution of 6% of the employees eligible
compensation.
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Provide our executive officers and other employees with the
opportunity to save for their future retirement.
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Health and Welfare Benefits
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Health and welfare benefits (medical, dental, vision, disability
insurance and life insurance) are available for our executive
officers and all other regular full-time employees.
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Provide benefits to meet the health and wellness needs of our
executive officers and other employees and their families.
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(1) |
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While we have made grants of DERs in the past, we expect to
modify those grants to remove, prior to the closing of this
offering, the DERs previously granted. In addition, we do not
expect to use grants of DERs as an element of our compensation
programs in the future. |
Base
Salaries
Base salaries for our executive officers will be determined
annually by an assessment of our overall financial and operating
performance, each executive officers performance
evaluation and changes in executive officer responsibilities.
While many aspects of performance can be measured in financial
terms, senior management will also be evaluated in areas of
performance that are more subjective. These areas include the
development and execution of strategic plans, the exercise of
leadership in the development of management and other employees,
innovation and improvement in our business activities and each
executive officers involvement in industry groups and in
the communities that we serve. We seek to compensate executive
officers for their performance throughout the year with annual
base salaries that are fair and competitive within our
marketplace. We believe that executive officer base salaries
should be competitive with salaries for executive officers in
similar positions and with similar responsibilities in our
marketplace and adjusted for financial and operating performance
and each executive officers performance evaluation, length
of service with us and previous work experience. Individual
salaries have historically been established by the
142
Compensation Committee based on the general industry knowledge
and experience of its members, in alignment with these
considerations, to ensure the attraction, development and
retention of superior talent. Going forward, we expect that
determinations will continue to focus on the above
considerations and will also take into account relevant market
data, including data from our peer group.
We expect that base salaries will be reviewed annually to ensure
continuing consistency with market levels and our level of
financial performance during the previous year. Future
adjustments to base salaries and salary ranges will reflect
movement in the competitive market as well as individual
performance. Annual base salary adjustments, if any, for the CEO
will be determined by the Compensation Committee. Annual base
salary adjustments, if any, for the other executive officers
will be determined by the Compensation Committee, taking into
account input from the CEO.
Annual
Incentive Bonuses
As one way of accomplishing compensation objectives, executive
officers are rewarded for their contribution to our financial
and operational success through the award of discretionary
annual cash incentive bonuses. Annual cash incentive awards, if
any, for the CEO are determined by the Compensation Committee.
Annual cash incentive awards, if any, for the other executive
officers are determined by the Compensation Committee taking
into account input from the CEO.
We expect to review annual cash bonus awards for the named
executive officers annually to determine award payments for the
prior fiscal year, as well as to establish target bonus amounts
for the current fiscal year. At the beginning of each year, the
Compensation Committee meets with the CEO to discuss partnership
and individual goals for the year and what each executive is
expected to contribute in order to help the partnership achieve
those goals. However, the amounts of the annual bonuses have
been determined in the discretion of the Compensation Committee.
While target bonuses for our executive officers who have entered
into employment agreements have been initially set at dollar
amounts that are 25% to 100% of their base salaries, the
Compensation Committee has had broad discretion to retain,
reduce or increase the award amounts when making its final bonus
determinations. Target bonus amounts for 2010 for
Messrs. Bierbach, Patterson and Connor, which are specified
in their employment agreements, are set forth in the table
below. Please refer to Employment Agreements
with Named Executive Officers below for a description of
these employment agreements. Ms. Flower and
Mr. Mathews did not have specific target bonus amounts
established for 2010. Further, bonuses (similar to other
elements of the compensation provided to executive officers)
historically have not been solely based on a prescribed formula
or pre-determined goals or specified performance targets but
rather have been determined on a discretionary basis and
generally have been based on a subjective evaluation of
individual, company-wide and industry performances.
The Board and the Compensation Committee believed that this
approach to assessing performance resulted in a more
comprehensive evaluation for compensation decisions. In 2010,
the Compensation Committee recognized the following factors in
making discretionary annual bonus recommendations and
determinations:
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a subjective performance evaluation based on company-wide
financial and individual qualitative performance, as determined
in the Compensation Committees discretion; and
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the scope, level of expertise and experience required for the
executive officers position.
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These factors were selected as the most appropriate measures
upon which to base the annual incentive cash bonus decisions
because our Compensation Committee believed that they help to
align individual compensation with performance and contribution.
With respect to its evaluation of company-wide financial
performance, although no pre-determined numerical goals are
established, the Compensation Committee generally reviewed our
results with respect to adjusted EBITDA and cash available for
distribution in making annual bonus determinations.
143
Following its performance assessment, and based on our financial
performance with respect to these criteria and the Compensation
Committees qualitative assessment of individual
performance, the Compensation Committee determined to award the
incentive bonus amounts set forth in the table below to our
named executive officers for performance in 2010.
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2010 Target
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2010 Bonus
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Name
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Bonus
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Awarded
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Brian F. Bierbach
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$ 65,000
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$
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65,000
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Sandra M. Flower
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N/A
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$
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35,000
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Marty W. Patterson
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$ 35,000
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$
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35,000
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John J. Connor
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$ 40,000
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$
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50,000
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William B. Mathews
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N/A
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$
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35,000
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Beginning in 2011, the Compensation Committee expects that it
will base annual incentive compensation award recommendations on
additional company-wide criteria as well as industry criteria,
recognizing the following factors as part of its determination
of annual incentive bonuses (without assigning any particular
weighting to any factor):
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financial performance for the prior fiscal year, including
adjusted EBITDA and cash available for distribution;
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distribution performance for the prior fiscal year compared to
the peer group;
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unitholder total return for the prior fiscal year compared to
the peer group; and
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competitive compensation data of executive officers in the peer
group.
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These factors were selected as the most appropriate measures
upon which to base the annual cash incentive bonus decisions
going forward because the Compensation Committee believes that
they will most directly correlate to increases in long-term
value for our unitholders.
Equity-Based
Awards
Design. The LTIP was adopted in 2009 in
connection with our formation. In adopting the LTIP, the Board
recognized that it needed a source of equity to attract new
members to and retain members of the management team, as well as
to provide an equity incentive to other key employees and
non-employee directors. We believe the LTIP promotes a long-term
focus on results and aligns executive and unitholder interests.
Historically, we have granted phantom units with associated DERs
to provide long-term incentives to our named executive officers.
DERs enable the recipients of phantom unit awards to receive
cash distributions on our phantom units to the same extent
generally as unitholders receive cash distributions on our
common units.
The LTIP is designed to encourage responsible and profitable
growth while taking into account non-routine factors that may be
integral to our success. Long-term incentive compensation in the
form of equity grants are used to provide incentives for
performance that leads to enhanced unitholder value, encourage
retention and closely align the executive officers
interests with unitholders interests. Equity grants
provide a vital link between the long-term results achieved for
our unitholders and the rewards provided to executive officers
and other key employees.
Phantom Units. The only awards made
under the LTIP since its adoption have been phantom units. A
phantom unit is a notional unit granted under the LTIP that
entitles the holder to receive an amount of cash equal to the
fair market value of one common unit upon vesting of the phantom
unit, unless the Board elects to pay such vested phantom unit
with a common unit in lieu of cash. Historically, our Board has
always issued common units instead of cash. Unless an individual
award agreement provides otherwise, the LTIP provides that
unvested phantom units are forfeited at the time the holder
terminates employment or board membership, as applicable. The
terms of the award agreements of our named executive officers
provide that a termination due to death or disability results in
full acceleration of vesting. In general, phantom units awarded
under our LTIP vest as to 25% of the award on each of the first
four anniversaries of the date of grant. A grant of
144
phantom units may include accompanying DERs, which entitle the
grantee to receive a cash payment with respect to each phantom
unit equal to the cash distribution made by the partnership on
each common unit. Under the terms of the award agreements, the
phantom units granted to the named executive officers include
DERs that are paid to the executive within 10 business days
after the date of the associated cash distribution made by the
partnership with respect to its common units.
Equity-Based Award Policies. Prior to
2011, equity-based awards were granted by the Compensation
Committee in connection with our formation. Going forward, we
expect that equity-based awards will be awarded by the
Compensation Committee on an annual basis as part of the ongoing
total annual compensation package for executive officers. On
March 2, 2010, Ms. Flower and Mr. Mathews
received awards of 51,579 phantom units and 25,789 phantom
units, respectively, including accompanying DERs, in connection
with our formation. No other named executive officers received
any awards under the LTIP in 2010.
Deferred
Compensation
Tax-qualified retirement plans are a common way that companies
assist employees in preparing for retirement. We provide our
eligible executive officers and other employees with an
opportunity to save for their retirement by participating in our
401(k) savings plan. The 401(k) plan allows executive officers
and other employees to defer compensation (up to IRS imposed
limits) for retirement and permits us to make annual
discretionary matching contributions to the plan. For 2010, we
matched employee contributions to 401(k) plan accounts up to a
maximum employer contribution of 6% of the employees
eligible compensation. Decisions regarding this element of
compensation do not impact any other element of compensation.
Other
Benefits
Each of the named executive officers is eligible to participate
in our employee benefit plans which provide for medical, dental,
vision, disability insurance and life insurance benefits, which
are provided on the same terms as available generally to all
salaried employees. In 2010, no perquisites were provided to the
named executive officers.
Recoupment
Policy
We currently do not have a recoupment policy applicable to
annual incentive bonuses or equity awards. The Compensation
Committee expects to continue to evaluate the need to adopt such
a policy, in light of current legislative policies as well as
economic and market conditions.
Employment
and Severance Arrangements
The Board and the Compensation Committee consider the
maintenance of a sound management team to be essential to
protecting and enhancing our best interests. To that end, we
recognize that the uncertainty that may exist among management
with respect to their at-will employment with our
general partner may result in the departure or distraction of
management personnel to our detriment. Accordingly, our general
partner previously entered into employment agreements with each
of Messrs. Bierbach, Patterson and Connor, which employment
agreements contain severance arrangements that we believed were
appropriate to encourage the continued attention and dedication
of members of our management. These employment agreements are
described more fully below under Employment
Agreements with Named Executive Officers.
Summary
Compensation Table for 2010
The following table sets forth certain information with respect
to the compensation paid to the named executive officers for the
year ended December 31, 2010.
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All Other
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Name and Principal Position
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Salary
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Bonus
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Unit Awards(1)
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Compensation(2)
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Total
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Brian F. Bierbach
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$
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235,000
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$
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65,000
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$
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183,016
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$
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483,016
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President and Chief Executive Officer
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Sandra M. Flower
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$
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140,000
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$
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35,000
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$
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643,691
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$
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7,437
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$
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826,128
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Vice President of Finance
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145
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All Other
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Name and Principal Position
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Salary
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Bonus
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Unit Awards(1)
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Compensation(2)
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Total
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Marty W. Patterson
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$
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190,000
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$
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35,000
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$
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$
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91,733
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$
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316,733
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Senior Vice President of Commercial Services
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John J. Connor
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$
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185,000
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$
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50,000
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$
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$
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91,717
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$
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326,717
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Senior Vice President of Operations and Engineering
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William B. Mathews
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$
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185,000
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$
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35,000
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$
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321,839
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$
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9,872
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$
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581,711
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Vice President Legal Affairs, General Counsel and Secretary
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(1) |
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Amounts shown in this column do not reflect dollar amounts
actually received by our named executive officers. Instead,
these amounts reflect the aggregate grant date fair value of
each phantom unit award granted in the year ended
December 31, 2010 computed in accordance with the
provisions of Financial Accounting Standards Board Accounting
Standards Codification Topic 718, Compensation Stock
Compensation (FASB ASC Topic 718). Assumptions used
in the calculation of these amounts are included in Note 13
to our consolidated financial statements included in this
prospectus. |
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(2) |
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Amounts shown in this column include employer contributions to
the named executive officers 401(k) plan accounts and life
insurance premiums paid by the employer. In addition, the
amounts shown for Messrs. Bierbach, Patterson and Connor
include the dollar value of any distributions paid on their
phantom unit awards pursuant to the DERs in 2010 in the amounts
of $182,283, $91,140 and $91,140, respectively. The amounts of
such distributions pursuant to DERs are not included in the
amounts shown for Ms. Flower and Mr. Mathews because
the grant date fair value of their awards reported in the
Unit Awards column factors in the value of such
distributions pursuant to the DERs. |
Grants of
Plan-Based Awards for 2010
The following table provides information regarding grants of
plan-based awards received by Sandra Flower and William Mathews
in 2010. Such awards consisted of phantom units and accompanying
DERs granted under the LTIP. No other named executive officers
received grants of plan-based awards during the year ended
December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other Unit
|
|
Grant Date Fair
|
|
|
|
|
Awards: Number of
|
|
Value of Phantom
|
Name
|
|
Grant Date
|
|
Phantom Units(1)
|
|
Unit Awards(2)
|
|
Sandra M. Flower
|
|
March 2, 2010
|
|
|
51,579
|
(3)
|
|
$
|
643,691
|
|
William B. Mathews
|
|
March 2, 2010
|
|
|
25,789
|
(3)
|
|
$
|
321,839
|
|
|
|
|
(1) |
|
Each phantom unit award was accompanied by a DER. |
|
(2) |
|
The grant date fair value of each phantom unit award is computed
in accordance with FASB ASC Topic 718, and factors in the value
of the DERs accompanying such awards. Assumptions used in the
calculation of these amounts are included in Note 13 to our
consolidated financial statements included in this prospectus. |
|
(3) |
|
Vests as to 25% of the award on each of first four anniversaries
of the date of grant. |
Employment
Agreements with Named Executive Officers
Our general partner has entered into employment agreements dated
November 2, 2009 and effective as of November 4, 2009,
with each of Brian F. Bierbach, Marty W. Patterson and John J.
Connor. Each of the employment agreements has an initial term of
two years. These employment agreements are each automatically
extended for successive one-year periods unless and until either
party elects to terminate the agreement by giving at least
90 days written notice prior to the commencement of the
next succeeding one-year period. These employment agreements
will terminate if either party gives such required notice, in
which case employment may continue on an at-will
basis, but the non-compete, non-solicitation and certain other
provisions of the agreements would terminate. The base salary
and target bonus amounts set forth in such employment agreements
are shown in the table below. The employment agreements provide
that the base
146
salary may be increased but not decreased (except for a decrease
that is consistent with reductions taken generally by other
executives of the general partner) and that the executive is
eligible to receive an annual cash bonus as approved from time
to time by the Compensation Committee based on criteria
established by the Compensation Committee. The employment
agreements also provide that the executive is eligible to
receive awards under the LTIP as determined by the Compensation
Committee.
|
|
|
|
|
|
|
|
|
|
|
2010 Base
|
|
|
2010 Target
|
|
Name
|
|
Salary
|
|
|
Bonus
|
|
|
Brian F. Bierbach
|
|
$
|
235,000
|
|
|
$
|
65,000
|
|
Marty W. Patterson
|
|
$
|
190,000
|
|
|
$
|
35,000
|
|
John J. Connor
|
|
$
|
185,000
|
|
|
$
|
40,000
|
|
Each employment agreement also contains certain confidentiality
covenants prohibiting each executive officer from, among other
things, disclosing confidential information relating to our
general partner or any of its affiliates including us. The
employment agreements also contain non-competition and
non-solicitation restrictions, which apply during the term of
the executives employment with our general partner and
continue for a period of 12 months following termination of
employment for any reason if such termination occurs during the
term of the employment agreement and not in connection with the
expiration of the employment agreement.
These employment agreements also provide for, among other
things, the payment of severance benefits under certain
circumstances. Please refer to Potential
Payment Upon Termination or Change in Control
Employment Agreements with Named Executive Officers below
for a description of these benefits under the employment
agreements.
Outstanding
Equity-Based Awards at December 31, 2010
The following table provides information regarding outstanding
equity-based awards held by the named executive officers as of
December 31, 2010. All such equity-based awards consist of
phantom units and accompanying DERs granted under the LTIP.
|
|
|
|
|
|
|
|
|
|
|
Units Awards
|
|
|
Number of Phantom
|
|
Market Value of
|
|
|
Units That Have Not
|
|
Phantom Units That
|
Name
|
|
Vested(1)
|
|
Have Not Vested(2)
|
|
Brian F. Bierbach
|
|
|
116,053
|
|
|
$
|
|
|
Sandra M. Flower
|
|
|
51,579
|
|
|
$
|
|
|
Marty W. Patterson
|
|
|
58,026
|
|
|
$
|
|
|
John J. Connor
|
|
|
58,026
|
|
|
$
|
|
|
William B. Mathews
|
|
|
25,789
|
|
|
$
|
|
|
|
|
|
(1) |
|
The awards to Messrs. Bierbach, Patterson and Connor were
granted on November 2, 2009. The awards to Ms. Flower
and Mr. Mathews were awarded on March 2, 2010. Each of
the awards vests as to 25% of the award on each of the first
four anniversaries of the date of grant. |
|
(2) |
|
The market value of phantom units that had not vested as of
December 31, 2010 is calculated based on the fair market
value of our common units as of December 31, 2010, which we
assumed was $ , the mid-point of
the range of the initial public offering price set forth on the
cover page of this prospectus, multiplied by the number of
unvested phantom units. |
147
Units
Vested in 2010
The following table shows the phantom unit awards that vested
during 2010.
|
|
|
|
|
|
|
|
|
|
|
Number of Units
|
|
|
Value Realized on
|
|
Name
|
|
Acquired on Vesting
|
|
|
Vesting(1)
|
|
|
Brian F. Bierbach
|
|
|
38,684
|
|
|
$
|
|
|
Marty W. Patterson
|
|
|
19,342
|
|
|
$
|
|
|
John J. Connor
|
|
|
19,342
|
|
|
$
|
|
|
|
|
|
(1) |
|
The value realized upon vesting of phantom units is calculated
based on the fair market value of our common units as of the
applicable vesting date, which we have assumed was $ , the
mid-point of the range of the initial public offering price set
forth on the cover page of this prospectus, multiplied by the
number of phantom units that vested. |
Long-Term
Incentive Plan
The Board has adopted our LTIP for employees, consultants and
directors of our general partner and affiliates who perform
services for us. The plan provides for the issuance of options,
unit appreciation rights, restricted units, phantom units, other
unit-based awards, unit awards or replacement awards, as well as
tandem DERs granted with respect to an award. To date, only
phantom units and related DERs have been issued under the LTIP.
As of March 29, 2011, 424,157 unvested phantom units are
outstanding under our LTIP. A phantom unit is a notional unit
granted under the LTIP that entitles the holder to receive an
amount of cash equal to the fair market value of one common unit
upon vesting of the phantom unit, unless the Board elects to pay
such vested phantom unit with a common unit in lieu of cash.
Historically, our Board has always issued common units in lieu
of cash upon vesting of a phantom unit. DERs may be granted in
tandem with phantom units. Except as otherwise provided in an
award agreement, DERs that are not subject to a restricted
period are currently paid to the participant at the time a
distribution is made to the unitholders, and DERs that are
subject to a restricted period are paid to the participant in a
single lump sum no later than the 15th day of the third
calendar month following the date on which the restricted period
ends.
The number of units that may be delivered with respect to awards
under the LTIP may not exceed 625,532 units, subject to
specified anti-dilution adjustments. However, if any award is
terminated, cancelled, forfeited or expires for any reason
without the actual delivery of units covered by such award or
units are withheld from an award to satisfy the exercise price
or the employers tax withholding obligation with respect
to such award, such units will again be available for issuance
pursuant to other awards granted under the LTIP. In addition,
any units allocated to an award will, to the extent such award
is paid in cash, be again available for delivery under the LTIP
with respect to other awards. There is no limitation on the
number of awards that may be granted under the LTIP and paid in
cash. The LTIP provides that it is to be administered by the
Board, provided that the Board may delegate authority to
administer the LTIP to a committee of non-employee directors.
The LTIP may be terminated or amended at any time, including
increasing the number of units that may be granted, subject to
unitholder approval as required by the securities exchange on
which the common units are listed at that time. However, no
change in any outstanding grant may be made that would
materially reduce the benefits of the participant without the
consent of the participant. The plan will terminate on the
earliest of (i) its termination by the Board or the
Compensation Committee, (ii) the tenth anniversary of the
date the LTIP was adopted or (iii) when units are no longer
available for delivery pursuant to awards under the LTIP. Unless
expressly provided for in the plan or an applicable award
agreement, any award granted prior to the termination of the
plan, and the authority of the Board or the Compensation
Committee to amend, adjust or terminate such award or to waive
any conditions or rights under such award, will extend beyond
the termination date.
148
Potential
Payments Upon Termination or Change in Control
Employment
Agreements with Named Executive Officers
The employment agreements with Messrs. Bierbach, Patterson
and Connor provide for, among other things, the payment of
severance benefits following certain terminations of employment
by our general partner or the termination of employment for
Good Reason (as defined in each of the employment
agreements) by the executive officer. Under these agreements, if
the executives employment is terminated by the general
partner other than for Cause (as defined in the
employment agreements) or other than upon the executives
death or disability, or if the executive resigns for Good
Reason, in each case, during the term of the agreement, the
executive will have the right to a lump sum cash payment by our
general partner equal to the executives annual base salary
at the rate in effect on the date of such termination, which
will be subject to reimbursement by us to our general partner.
The foregoing severance benefit is conditioned on the executive
executing a release of claims in favor of our general partner
and its affiliates, including us.
Cause is defined in each employment
agreement as the executive having (i) engaged in gross
negligence, gross incompetence or willful misconduct in the
performance of the duties required of him under the employment
agreement, (ii) refused without proper reason to perform
the duties and responsibilities required of him under the
employment agreement, (iii) willfully engaged in conduct
that is materially injurious to our general partner or its
affiliates including us (monetarily or otherwise),
(iv) committed an act of fraud, embezzlement or willful
breach of fiduciary duty to our general partner or an affiliate
including us (including the unauthorized disclosure of
confidential or proprietary material information of our general
partner or an affiliate including us) or (v) been convicted
of (or pleaded no contest to) a crime involving fraud,
dishonesty or moral turpitude or any felony. Good
Reason is defined in each employment agreement as a
termination by the executive in connection with or based upon
(i) a material diminution in the executives
responsibilities, duties or authority, (ii) a material
diminution in the executives base compensation,
(iii) assignment of the executive to a principal office
located beyond a
50-mile
radius of the executives then current work place, or
(iv) a material breach by us of any material provision of
the employment agreement.
Each employment agreement also contains certain confidentiality
covenants prohibiting each executive officer from, among other
things, disclosing confidential information relating to our
general partner or any of its affiliates including us. The
employment agreements also contain non-competition and
non-solicitation restrictions, which apply during the term of
the executives employment with our general partner and
continue for a period of 12 months following termination of
employment for any reason if such termination occurs during the
term of the employment agreement and not in connection with the
expiration of the employment agreement.
Phantom
Unit Award Agreements
Each of our named executive officers has received an award of
phantom units under the LTIP. The terms of the phantom unit
award agreements of our named executive officers provide that a
termination due to death or disability results in full
acceleration of vesting of any outstanding phantom units.
149
The following table shows the value of the severance benefits
and other benefits (1) under the employment agreements for
the named executive officers who have employment agreements and
(2) under the phantom unit award agreements, assuming in
each case that such named executive officer had terminated
employment on December 31, 2010. The named executive
officers are not entitled to receive any severance or other
benefits upon a change of control under such agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Death or
|
|
|
Termination
|
|
|
Resignation for
|
|
Name
|
|
Benefit Type
|
|
Disability(1)
|
|
|
Without Cause
|
|
|
Good Reason
|
|
|
Brian F. Bierbach
|
|
Lump sum payment per employment agreement
|
|
|
None
|
|
|
$
|
235,000
|
|
|
$
|
235,000
|
|
|
|
Accelerated vesting of phantom units per award agreement
|
|
$
|
|
|
|
|
None
|
|
|
|
None
|
|
Sandra M. Flower
|
|
Accelerated vesting of phantom
|
|
$
|
|
|
|
|
None
|
|
|
|
None
|
|
|
|
units per award agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
Marty W. Patterson
|
|
Lump sum payment per employment agreement
|
|
|
None
|
|
|
$
|
190,000
|
|
|
$
|
190,000
|
|
|
|
Accelerated vesting of phantom units per award agreement
|
|
$
|
|
|
|
|
None
|
|
|
|
None
|
|
John J. Connor
|
|
Lump sum payment per employment agreement
|
|
|
None
|
|
|
$
|
185,000
|
|
|
$
|
185,000
|
|
|
|
Accelerated vesting of phantom units per award agreement
|
|
$
|
|
|
|
|
None
|
|
|
|
None
|
|
William B. Mathews
|
|
Accelerated vesting of phantom units per award agreement
|
|
$
|
|
|
|
|
None
|
|
|
|
None
|
|
|
|
|
(1) |
|
The amounts shown in this column are calculated based on the
fair market value of our common units as of December 31,
2010, which we have assumed was $
, the mid-point of the range of the initial public offering
price set forth on the cover page of this prospectus, multiplied
by the number of phantom units that would have vested. |
Compensation
of Directors
In 2010, one of our directors, Kent Moore, received a retainer
paid quarterly in cash for his service on the Board. None of our
other directors received any fees paid in cash for service on
the Board. Following the closing of our initial public offering,
we anticipate that each director who is not an officer or
employee of our general partner will receive compensation for
attending meetings of the Board, as well as committee meetings,
which amounts have not yet been determined.
Each non-employee director listed in the table below has
received grants of phantom units and accompanying DERs under our
LTIP. Each non-employee director is also reimbursed for
out-of-pocket
expenses in connection with attending meetings of the Board or
its committees. Each director will be fully indemnified by us
for actions associated with being a director of our general
partner to the extent permitted under Delaware law.
Director
Compensation Table for 2010
The following table sets forth the compensation paid to our
non-employee directors for the year ended December 31,
2010, as described above. The compensation paid in 2010 to
Mr. Bierbach as an executive
150
officer is set forth in the Summary Compensation Table above.
Mr. Bierbach did not receive any additional compensation
related to his service as a director.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned or
|
|
|
|
All Other
|
|
|
Name and Principal Position
|
|
Paid in Cash
|
|
Unit Awards(1)
|
|
Compensation(2)
|
|
Total
|
|
L. Kent Moore
|
|
$
|
25,000
|
|
|
|
|
|
|
$
|
60,760
|
|
|
$
|
85,760
|
|
David L. Page
|
|
|
|
|
|
$
|
623,991
|
(3)
|
|
|
|
|
|
$
|
623,991
|
|
|
|
|
(1) |
|
The amount reported in this column represents the aggregate
grant date fair value of the phantom unit award granted to
Mr. Page as computed in accordance with FASB ASC Topic 718,
which factors in the value of the accompanying DERs. Assumptions
used in the calculation of these amounts are included in
Note 13 to our consolidated financial statements included
in this prospectus. |
|
(2) |
|
The amount reported in this column represents the dollar value
of distributions paid in 2010 pursuant to DERs granted in
connection with outstanding phantom unit awards held by
Mr. Moore. No such amounts are reported with respect to
Mr. Page due to the fact that the aggregate grant date fair
value of his unit award reported in the above table factors in
the value of the accompanying DERs. |
|
(3) |
|
On March 2, 2010, Mr. Page received a grant of 50,000
phantom units, with 25% of such units vesting on each of the
first through fourth anniversaries of the grant date. As of
December 31, 2010, Mr. Page held an aggregate of
50,000 unvested phantom units. |
On November 2, 2009, Mr. Moore received a grant of
51,579 phantom units, with 25% of such units vesting on each of
the first through fourth anniversaries of the grant date. As of
December 31, 2010, Mr. Moore held an aggregate of
38,684 unvested phantom units. Such phantom units will vest in
full upon a change of control.
Compensation
Practices as They Relate to Risk Management
We do not believe that our compensation policies and practices
create risks that are reasonably likely to have a material
adverse effect on the partnership. We believe our compensation
programs do not encourage excessive and unnecessary risk taking
by executive officers (or other employees). Short-term annual
incentives are generally paid pursuant to discretionary bonuses
enabling the Compensation Committee to assess the actual
behavior of our employees as it relates to risk taking in
awarding a bonus. Our use of equity based long-term compensation
serves our compensation programs goal of aligning the
interests of executives and unitholders, thereby reducing the
incentives to unnecessary risk taking.
151
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the
beneficial ownership of units following the closing of this
offering and the related transactions by:
|
|
|
|
|
each person who is known to us to beneficially own 5% or more of
such units to be outstanding;
|
|
|
|
our general partner;
|
|
|
|
each of the directors and named executive officers of our
general partner; and
|
|
|
|
all of the directors and executive officers of our general
partner as a group.
|
All information with respect to beneficial ownership has been
furnished by the respective directors, officers or 5% or more
unitholders as the case may be.
Our general partner is owned 100.0% by AIM Midstream Holdings.
AIM holds an aggregate 84.4% indirect interest in AIM Midstream
Holdings. Robert B. Hellman, Matthew P. Carbone and Edward O.
Diffendal serve on the board of directors of our general partner
and are principals of and have ownership interests in AIM. In
addition, Brian F. Bierbach, the President and Chief Executive
Officer of our general partner and a member of the board of
directors of our general partner, Marty W. Patterson, the Vice
President of Commercial Affairs of our general partner, John J.
Connor II, the Vice President of Operations of our general
partner, Sandra M. Flower, the Vice President of Finance of our
general partner, and William B. Mathews, the Secretary, General
Counsel and Vice President of Legal Affairs of our general
partner, have an aggregate 1.1% interest in AIM Midstream
Holdings.
The amounts and percentage of units beneficially owned are
reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the
rules of the SEC, a person is deemed to be a beneficial
owner of a security if that person has or shares
voting power, which includes the power to vote or to
direct the voting of such security, or investment
power, which includes the power to dispose of or to direct
the disposition of such security. In computing the number of
common units beneficially owned by a person and the percentage
ownership of that person, common units subject to options or
warrants held by that person that are currently exercisable or
exercisable within 60 days
of ,
2011, if any, are deemed outstanding, but are not deemed
outstanding for computing the percentage ownership of any other
person. Except as indicated by footnote, the persons named in
the table below have sole voting and investment power with
respect to all units shown as beneficially owned by them,
subject to community property laws where applicable.
152
The percentage of units beneficially owned is based on a total
of
common units and subordinated units outstanding immediately
following this offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
Percentage of
|
|
|
|
Percentage of
|
|
Common and
|
|
|
Common Units
|
|
Common Units
|
|
Subordinated
|
|
Subordinated Units
|
|
Subordinated
|
|
|
to be
|
|
to be
|
|
Units to be
|
|
to be
|
|
Units to be
|
|
|
Beneficially
|
|
Beneficially
|
|
Beneficially
|
|
Beneficially
|
|
Beneficially
|
Name of Beneficial Owner
|
|
Owned
|
|
Owned
|
|
Owned
|
|
Owned
|
|
Owned
|
|
AIM Universal Holdings, LLC(1)(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
AIM Midstream Holdings, LLC(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Robert B. Hellman(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Brian F. Bierbach(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Matthew P. Carbone(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Edward O. Diffendal(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
David L. Page(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
L. Kent Moore(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Sandra M. Flower(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
John J. Connor II(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Marty W. Patterson(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
William B. Mathews(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
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%
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%
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All directors and executive officers as a group (consisting of
10 persons)
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%
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%
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%
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* |
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An asterisk indicates that the person or entity owns less than
one percent. |
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(1) |
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AIM Universal Holdings, LLC, a Delaware limited liability
company, is the sole manager of AIM Midstream Holdings and may
therefore be deemed to beneficially own
the
common units
and subordinated
units held by AIM Midstream Holdings. AIM Universal Holdings,
LLCs members consist of Robert B. Hellman and Matthew P.
Carbone, both directors of our general partner, and George E.
McCown. |
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(2) |
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The address for this person or entity is 950 Tower Lane,
Suite 800, Foster City, California 94404. |
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(3) |
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The address for this person or entity is 1614 15th Street,
Suite 300, Denver, Colorado 80202. |
153
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Immediately following the closing of this offering, AIM
Midstream Holdings will
own common
units
and
subordinated units, representing a
combined % limited partner interest
in us
(or
common units
and
subordinated units, representing a
combined % limited partner interest
in us, if the underwriters exercise their option to purchase
additional common units in full). In addition, AIM Midstream
Holdings will own and control our general partner, which will
own a 2.0% general partner interest in us and all of our
incentive distribution rights.
Distributions
and Payments to our General Partner and its Affiliates
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with our formation, ongoing operation and any
liquidation of American Midstream Partners, LP. These
distributions and payments were determined by and among
affiliated entities and, consequently, are not the result of
arms-length negotiations.
Pre-IPO
Stage
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The consideration received by our general partner and its
affiliates prior to or in connection with this offering
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common
units;
subordinated
units;
all of our
incentive distribution rights; and
2.0%
general partner interest.
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Post-IPO
Stage
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Distributions of available cash to our general partner and its
affiliates |
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We will initially make cash distributions 98.0% to our
unitholders pro rata, including AIM Midstream Holdings, as the
holder of an aggregate
of
common units
and subordinated
units, and 2.0% to our general partner, assuming it makes any
capital contributions necessary to maintain its 2.0% general
partner interest in us. In addition, if distributions exceed the
minimum quarterly distribution and target distribution levels,
the incentive distribution rights held by our general partner
will entitle our general partner to increasing percentages of
the distributions, up to 48.0% of the distributions above the
highest target distribution level. |
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Assuming we have sufficient available cash to pay the full
minimum quarterly distribution on all of our outstanding units
for four quarters, our general partner and its affiliates would
receive an annual distribution of approximately
$ million on its 2.0% general
partner interest and AIM Midstream Holdings would receive an
annual distribution of approximately
$ million on its common units
and subordinated units. |
|
Payments to our general partner and its affiliates |
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Our general partner will not receive a management fee or other
compensation for its management of us. However, we will
reimburse our general partner and its affiliates for all
expenses incurred on our behalf. Our partnership agreement
provides that our general partner will determine the amount of
these reimbursed expenses. |
|
Withdrawal or removal of our general partner |
|
If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, |
154
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in each case for an amount equal to the fair market value of
those interests. Please read The Partnership
Agreement Withdrawal or Removal of Our General
Partner. |
Liquidation
Stage
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Liquidation |
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Upon our liquidation, our partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances. |
Ownership
Interests of Certain Executive Officers and Directors of Our
General Partner
Upon the closing of this offering, AIM Midstream Holdings will
continue to own 100.0% of our general partner. AIM, Eagle River
Ventures, LLC, Stockwell Fund II, L.P. and certain of our
executive officers own all of the equity interests in AIM
Midstream Holdings. In addition, Robert B. Hellman, Matthew P.
Carbone and Edward O. Diffendal serve on the board of directors
of our general partner and are principals of AIM.
In addition to the 2.0% general partner interest in us, our
general partner owns the incentive distribution rights, which
entitle the holder to increasing percentages, up to a maximum of
48.0%, of the cash we distribute in excess of
$ per quarter, after the closing
of our initial public offering. Upon the closing of this
offering, AIM Midstream Holdings will
own common
units
and
subordinated units.
Agreements
with Affiliates
We and other parties have or will enter into the various
documents and agreements with certain of our affiliates, as
described in more detail below. These agreements will affect the
offering transactions, including the vesting of assets in, and
the assumptions of liabilities by, us and our subsidiaries, and
the application of the proceeds of this offering. These
agreements have been negotiated among affiliated parties and,
consequently, are not the result of arms-length
negotiations.
Advisory
Services Agreement
In October 2009, our subsidiary, American Midstream, LLC entered
into an advisory services agreement with American Infrastructure
MLP Management, L.L.C., American Infrastructure MLP PE
Management, L.L.C., and American Infrastructure MLP Associates
Management, L.L.C., as the advisors. Under this agreement, the
advisors perform certain financial and advisory services for
American Midstream, LLC. No fees or reimbursements were paid to
the advisors during 2009 in respect of this agreement. During
2010, American Midstream, LLC paid the advisors $250,000 for
such services and reimbursed the advisors $77,606 for the
advisors actual and direct
out-of-pocket
expenses incurred in the performance of their services. For the
calendar year 2011 and each calendar year thereafter, the
advisors are entitled to annual compensation in the amount of
$250,000, plus a fee determined by a formula that takes into
account the increase in gross revenue of American Midstream, LLC
over the prior year. American Midstream, LLC is also obligated
to reimburse the advisors for their actual and direct
out-of-pocket
expenses. In connection with the closing of this offering, the
advisory services agreement will be terminated in exchange for
an aggregate payment of
$
from us to the advisors.
Contribution
Agreements
In October 2009, a contribution and sale agreement was entered
into by AIM Midstream Holdings and AIM Midstream, LLC, American
Infrastructure MLP Fund, L.P., American Infrastructure MLP
Private Equity Fund, L.P., American Infrastructure MLP
Associates Fund, L.P., Brian F. Bierbach, Marty W. Patterson,
John J. Connor II, Eagle River Ventures, LLC, and Stockwell
Fund II, L.P., as investors, and AIM Universal Holdings,
LLC. Pursuant to this agreement, the investors contributed an
aggregate of $100 million to AIM Midstream Holdings in
exchange for membership interests in AIM Midstream Holdings.
155
In November 2009, we entered into a contribution, conveyance and
assumption agreement with AIM Midstream Holdings, American
Midstream GP, American Midstream, LLC, and American Midstream
Marketing, LLC. Pursuant to this Agreement, AIM Midstream
Holdings contributed $2 million to American Midstream GP in
exchange for all of the outstanding membership interests in
American Midstream GP. American Midstream GP, in turn,
contributed such $2 million to us in exchange for 200,000
general partner units representing a 2% general partner interest
in us, and all of our incentive distribution rights. AIM
Midstream Holdings also contributed $98 million to us in
exchange for 9,800,000 common units representing a 98% limited
partner interest in us. We then contributed the
$100 million that we received from American Midstream GP
and AIM Midstream Holdings to American Midstream, LLC in
exchange for the continuation of our 100% member interest in
American Midstream, LLC.
In September 2010, a contribution and sale agreement was entered
into by AIM Midstream Holdings and AIM Midstream, LLC, American
Infrastructure MLP Fund, L.P., American Midstream MLP Associates
Fund, L.P., American Infrastructure MLP Private Equity Fund,
L.P., Eagle River Ventures, LLC, Stockwell Fund II, L.P.,
John J. Connor II, William B. Mathews, and Sandra M. Flower, as
investors. Pursuant to this agreement, the investors contributed
an aggregate of $12 million to AIM Midstream Holdings in
exchange for membership interests in AIM Midstream Holdings.
In September 2010, we entered into a contribution agreement with
AIM Midstream Holdings, our general partner, and American
Midstream, LLC. Pursuant to this Agreement, AIM Midstream
Holdings contributed $240,000, or 2% of the $12 million
contributed by the investors to AIM Midstream Holdings pursuant
to the contribution and sale agreement described in the
preceding paragraph, to our general partner. Our general
partner, in turn, contributed such $240,000 to us in exchange
for 24,000 general partner units. AIM Midstream Holdings also
contributed $11,760,000, or 98% of the $12 million
contributed by the investors to AIM Midstream Holdings pursuant
to the contribution and sale agreement described in the
preceding paragraph, to us in exchange for 1,176,000 common
units. We then contributed the $12 million that we received
from American Midstream GP and AIM Midstream Holdings to
American Midstream, LLC in furtherance of our existing limited
liability company interest American Midstream, LLC.
Investors
Rights Agreement
On October 30, 2009, AIM Midstream Holdings, AIM Midstream,
LLC, American Infrastructure MLP Fund, L.P., American
Infrastructure MLP Private Equity Fund, L.P. and American
Infrastructure MLP Associates Fund, L.P., or the AIM Parties,
and Stockwell Fund II, L.P., or Stockwell, entered into an
investors rights agreement pursuant to which Stockwell
received tag-along rights to sell its limited liability company
interests in AIM Midstream Holdings in the event the AIM Parties
desire to sell, contract to sell, pledge, transfer, exchange or
otherwise dispose of an aggregate of more than 50% of their
limited liability company interests in AIM Midstream Holdings to
a non-affiliated third party.
In addition, the investors rights agreement gives
Stockwell a limited preemptive right to acquire limited
liability company interests in AIM Midstream Holdings at any
time AIM Midstream Holdings offers to sell such interests to any
AIM Party. In such event, AIM Midstream Holdings is required to
offer to sell to Stockwell a prescribed number of limited
liability company interests prior to any issuance to the AIM
Parties, and Stockwell is entitled to purchase such interests on
the same terms and conditions as they are offered to the AIM
Party.
The rights described above will terminate upon the closing of
this offering.
Procedures
for Review, Approval and Ratification of Related-Person
Transactions
The board of directors of our general partner will adopt a code
of business conduct and ethics in connection with the closing of
this offering that will provide that the board of directors of
our general partner or its authorized committee will
periodically review all related-person transactions that are
required to be disclosed under SEC rules and, when appropriate,
initially authorize or ratify all such transactions. In the
event that the board of directors of our general partner or its
authorized committee considers ratification of a related-person
transaction and determines not to so ratify, the code of
business conduct and ethics will provide that our management
will make all reasonable efforts to cancel or annul the
transaction.
156
The code of business conduct and ethics will provide that, in
determining whether to recommend the initial approval or
ratification of a related-person transaction, the board of
directors of our general partner or its authorized committee
should consider all of the relevant facts and circumstances
available, including (if applicable) but not limited to:
(i) whether there is an appropriate business justification
for the transaction; (ii) the benefits that accrue to us as
a result of the transaction; (iii) the terms available to
unrelated third parties entering into similar transactions;
(iv) the impact of the transaction on director independence
(in the event the related person is a director, an immediate
family member of a director or an entity in which a director or
an immediately family member of a director is a partner,
shareholder, member or executive officer); (v) the
availability of other sources for comparable products or
services; (vi) whether it is a single transaction or a
series of ongoing, related transactions; and (vii) whether
entering into the transaction would be consistent with the code
of business conduct and ethics.
The code of business conduct and ethics described above will be
adopted in connection with the closing of this offering, and as
a result the transactions described above were not reviewed
under such policy.
157
CONFLICTS
OF INTEREST AND FIDUCIARY DUTIES
Conflicts
of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner and its
affiliates (including AIM Midstream Holdings), on the one hand,
and us and our unaffiliated limited partners, on the other hand.
The directors and executive officers of our general partner have
fiduciary duties to manage our general partner in a manner
beneficial to its owners. At the same time, our general partner
has a fiduciary duty to manage us in a manner beneficial to us
and our unitholders.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us and our limited partners, on
the other hand, our general partner will resolve that conflict.
Our partnership agreement contains provisions that modify and
limit our general partners fiduciary duties to our
unitholders. Our partnership agreement also restricts the
remedies available to unitholders for actions taken by our
general partner that, without those limitations, might
constitute breaches of its fiduciary duty.
Our general partner will not be in breach of its obligations
under the partnership agreement or its fiduciary duties to us or
our unitholders if the resolution of the conflict is:
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approved by the Conflicts Committee, although our general
partner is not obligated to seek such approval;
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approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
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on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of
the relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
|
Our general partner may, but is not required to, seek the
approval of such resolution from the Conflicts Committee. In
connection with a situation involving a conflict of interest,
any determination by our general partner involving the
resolution of the conflict of interest must be made in good
faith, provided that, if our general partner does not
seek approval from the Conflicts Committee and its board of
directors determines that the resolution or course of action
taken with respect to the conflict of interest satisfies either
of the standards set forth in the third and fourth bullet points
above, then it will be presumed that, in making its decision,
the board of directors acted in good faith, and in any
proceeding brought by or on behalf of any limited partner or the
Partnership, the person bringing or prosecuting such proceeding
will have the burden of overcoming such presumption. Unless the
resolution of a conflict is specifically provided for in our
partnership agreement, our general partner or the Conflicts
Committee may consider any factors it determines in good faith
to consider when resolving a conflict. When our partnership
agreement requires someone to act in good faith, it requires
that person to have an honest belief that he is acting in, or
not opposed to, the best interests of the partnership.
Conflicts of interest could arise in the situations described
below, among others.
AIM
Midstream Holdings and other affiliates of our general partner
may compete with us.
Our partnership agreement provides that our general partner will
be restricted from engaging in any business activities other
than acting as our general partner (or as general partner of
another company of which we are a partner or member) or those
activities incidental to its ownership of interests in us.
However, certain affiliates of our general partner, including
AIM Midstream Holdings, are not prohibited from engaging in
other businesses or activities, including those that might be in
direct competition with us. Additionally, AIM, through its
investment funds and managed accounts, makes investments and
purchases entities in various areas of the energy sector,
including the midstream natural gas industry. These investments
and acquisitions may include entities or assets that we would
have been interested in acquiring.
158
Pursuant to the terms of our partnership agreement, the doctrine
of corporate opportunity, or any analogous doctrine, will not
apply to our general partner or any of its affiliates, including
its executive officers, directors and AIM Midstream Holdings.
Any such person or entity that becomes aware of a potential
transaction, agreement, arrangement or other matter that may be
an opportunity for us will not have any duty to communicate or
offer such opportunity to us. Any such person or entity will not
be liable to us or to any limited partner for breach of any
fiduciary duty or other duty by reason of the fact that such
person or entity pursues or acquires such opportunity for
itself, directs such opportunity to another person or entity or
does not communicate such opportunity or information to us.
Therefore, AIM Midstream Holdings may compete with us for
investment opportunities and may own an interest in entities
that compete with us.
Our
general partner is allowed to take into account the interests of
parties other than us, such as AIM Midstream Holdings, in
resolving conflicts.
Our partnership agreement contains provisions that reduce the
fiduciary standards to which our general partner would otherwise
be held by state fiduciary duty law. For example, our
partnership agreement permits our general partner to make a
number of decisions in its individual capacity, as opposed to in
its capacity as our general partner. This entitles our general
partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include the exercise
of our general partners limited call right, its voting
rights with respect to the units it owns, its registration
rights and its determination whether or not to consent to any
merger or consolidation of the partnership.
Our
partnership agreement limits the liability and reduces the
fiduciary duties owed by our general partner, and also restricts
the remedies available to our unitholders for actions that,
without those limitations, might constitute breaches of its
fiduciary duty.
In addition to the provisions described above, our partnership
agreement contains provisions that restrict the remedies
available to our unitholders for actions that might otherwise
constitute breaches of our general partners fiduciary
duty. For example, our partnership agreement:
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provides that our general partner shall not have any liability
to us or our unitholders for decisions made in its capacity as
general partner so long as such decisions are made in good
faith, which means the honest belief that the decision is in our
best interest;
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provides generally that affiliated transactions and resolutions
of conflicts of interest not approved by the Conflicts Committee
and not involving a vote of unitholders must either be
(1) on terms no less favorable to us than those generally
being provided to or available from unrelated third parties or
(2) fair and reasonable to us, as determined by
our general partner in good faith, provided that, in
determining whether a transaction or resolution is fair
and reasonable, our general partner may consider the
totality of the relationships between the parties involved,
including other transactions that may be particularly
advantageous or beneficial to us; and
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provides that our general partner and its executive officers and
directors will not be liable for monetary damages to us or our
limited partners resulting from any act or omission unless there
has been a final and non-appealable judgment entered by a court
of competent jurisdiction determining that our general partner
or its executive officers or directors acted in bad faith or
engaged in fraud or willful misconduct or, in the case of a
criminal matter, acted with knowledge that their conduct was
criminal.
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Except
in limited circumstances, our general partner has the power and
authority to conduct our business without unitholder
approval.
Under our partnership agreement, our general partner has full
power and authority to do all things, other than those items
that require unitholder approval or with respect to which our
general partner has sought
159
Conflicts Committee approval, on such terms as it determines to
be necessary or appropriate to conduct our business including,
but not limited to, the following:
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the making of any expenditures, the lending or borrowing of
money, the assumption or guarantee of or other contracting for,
indebtedness and other liabilities, the issuance of evidences of
indebtedness, including indebtedness that is convertible into
our securities, and the incurring of any other obligations;
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the purchase, sale or other acquisition or disposition of our
securities, or the issuance of additional options, rights,
warrants and appreciation rights relating to our securities;
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the mortgage, pledge, encumbrance, hypothecation or exchange of
any or all of our assets;
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the negotiation, execution and performance of any contracts,
conveyances or other instruments;
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the distribution of our cash;
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the selection and dismissal of employees and agents, outside
attorneys, accountants, consultants and contractors and the
determination of their compensation and other terms of
employment or hiring;
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the maintenance of insurance for our benefit and the benefit of
our partners;
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the formation of, or acquisition of an interest in, the
contribution of property to, and the making of loans to, any
limited or general partnership, joint venture, corporation,
limited liability company or other entity;
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the control of any matters affecting our rights and obligations,
including the bringing and defending of actions at law or in
equity, otherwise engaging in the conduct of litigation,
arbitration or mediation and the incurring of legal expense, the
settlement of claims and litigation;
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the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
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the making of tax, regulatory and other filings, or the
rendering of periodic or other reports to governmental or other
agencies having jurisdiction over our business or
assets; and
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the entering into of agreements with any of its affiliates to
render services to us or to itself in the discharge of its
duties as our general partner.
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Our partnership agreement provides that our general partner must
act in good faith when making decisions on our
behalf, and our partnership agreement further provides that in
order for a determination to be made in good faith,
our general partner must have an honest belief that the
determination is in our best interests. Please read The
Partnership Agreement Voting Rights for
information regarding matters that require unitholder approval.
Actions
taken by our general partner may affect the amount of cash
available for distribution to unitholders or accelerate the
right to convert subordinated units.
The amount of cash that is available for distribution to
unitholders is affected by decisions of our general partner
regarding such matters as:
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the amount and timing of asset purchases and sales;
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cash expenditures and the amount of estimated reserve
replacement expenditures;
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borrowings;
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the issuance of additional units; and
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the creation, reduction or increase of reserves in any quarter.
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Our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is
classified as a maintenance capital expenditure, which reduces
operating surplus, or an expansion capital expenditure, which
does not reduce operating surplus. This determination can affect
the
160
amount of cash that is distributed to our unitholders and to our
general partner and the ability of the subordinated units to
convert into common units.
In addition, our general partner may use an amount, initially
equal to $ million, which
would not otherwise constitute available cash from operating
surplus, in order to permit the payment of cash distributions on
its units and incentive distribution rights. All of these
actions may affect the amount of cash distributed to our
unitholders and our general partner and may facilitate the
conversion of subordinated units into common units. Please read
Provisions of Our Partnership Agreement Relating to Cash
Distributions.
In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owed by our general partner to
our unitholders, including borrowings that have the purpose or
effect of:
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enabling our general partner or its affiliates to receive
distributions on any subordinated units held by them or the
incentive distribution rights; or
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hastening the expiration of the subordination period.
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For example, in the event we have not generated sufficient cash
from our operations to pay the minimum quarterly distribution on
our common units and our subordinated units, our partnership
agreement permits us to borrow funds, which would enable us to
make this distribution on all outstanding units. Please read
Provisions of Our Partnership Agreement Relating to Cash
Distributions Subordination Period.
Our partnership agreement provides that we and our subsidiaries
may borrow funds from our general partner and its affiliates.
Our general partner and its affiliates may not borrow funds from
us, or our operating company and its operating subsidiaries.
We
will reimburse our general partner and its affiliates for
expenses.
We will reimburse our general partner and its affiliates for
costs incurred in managing and operating us. Our partnership
agreement provides that our general partner will determine the
expenses that are allocable to us in good faith, and it will
charge on a fully allocated cost basis for services provided to
us. The fully allocated basis charged by our general partner
does not include a profit component. Please read Certain
Relationships and Related Party Transactions.
Contracts
between us, on the one hand, and our general partner and its
affiliates, on the other, will not be the result of
arms-length negotiations.
Our partnership agreement allows our general partner to
determine, in good faith, any amounts to pay itself or its
affiliates for any services rendered to us. Our general partner
may also enter into additional contractual arrangements with any
of its affiliates on our behalf. Neither our partnership
agreement nor any of the other agreements, contracts, and
arrangements between us and our general partner and its
affiliates are or will be the result of arms-length
negotiations. Similarly, agreements, contracts or arrangements
between us and our general partner and its affiliates that are
entered into following the closing of this offering will not be
required to be negotiated on an arms-length basis,
although, in some circumstances, our general partner may
determine that the Conflicts Committee may make a determination
on our behalf with respect to such arrangements.
Our general partner will determine, in good faith, the terms of
any of these transactions entered into after the close of this
offering.
Our general partner and its affiliates will have no obligation
to permit us to use any facilities or assets of our general
partner and its affiliates, except as may be provided in
contracts entered into specifically for such use. There is no
obligation of our general partner and its affiliates to enter
into any contracts of this kind.
Our
general partner intends to limit its liability regarding our
obligations.
Our general partner intends to limit its liability under
contractual arrangements so that counterparties to such
agreements have recourse only against our assets and not against
our general partner or its assets or any
161
affiliate of our general partner or its assets. Our partnership
agreement provides that any action taken by our general partner
to limit its liability is not a breach of our general
partners fiduciary duties, even if we could have obtained
terms that are more favorable without the limitation on
liability.
Common
units are subject to our general partners limited call
right.
Our general partner may exercise its right to call and purchase
common units, as provided in our partnership agreement, or may
assign this right to one of its affiliates or to us. Our general
partner may use its own discretion, free of fiduciary duty
restrictions, in determining whether to exercise this right. As
a result, a common unitholder may have to sell his common units
at an undesirable time or price. Please read The
Partnership Agreement Limited Call Right.
Common
unitholders will have no right to enforce obligations of our
general partner and its affiliates under agreements with
us.
Any agreements between us, on the one hand, and our general
partner and its affiliates, on the other, will not grant to the
unitholders, separate and apart from us, the right to enforce
the obligations of our general partner and its affiliates in our
favor.
Our
general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
The attorneys, independent accountants and others who perform
services for us have been retained by our general partner.
Attorneys, independent accountants and others who perform
services for us are selected by our general partner or the
Conflicts Committee and may perform services for our general
partner and its affiliates. We may retain separate counsel for
ourselves or the holders of common units in the event of a
conflict of interest between our general partner and its
affiliates, on the one hand, and us or the holders of common
units, on the other, depending on the nature of the conflict. We
do not intend to do so in most cases.
Our
general partner may elect to cause us to issue common units to
it in connection with a resetting of the target distribution
levels related to our general partners incentive
distribution rights without the approval of the Conflicts
Committee or our unitholders. This election may result in lower
distributions to our public common unitholders in certain
situations.
Our general partner has the right, at any time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled
(48.0%) for each of the prior four consecutive fiscal quarters,
to reset the initial target distribution levels at higher levels
based on our cash distribution at the time of the exercise of
the reset election. Following a reset election by our general
partner, the minimum quarterly distribution will be reset to an
amount equal to the average cash distribution per unit for the
two fiscal quarters immediately preceding the reset election
(such amount is referred to as the reset minimum quarterly
distribution), and the target distribution levels will be
reset to correspondingly higher levels based on percentage
increases above the reset minimum quarterly distribution.
We anticipate that our general partner would exercise this reset
right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion; however,
it is possible that our general partner could exercise this
reset election at a time when we are experiencing declines in
our aggregate cash distributions or at a time when our general
partner expects that we will experience declines in our
aggregate cash distributions in the foreseeable future. In such
situations, our general partner may be experiencing, or may
expect to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued common units, which are entitled
to specified priorities with respect to our distributions and
which therefore may be more advantageous for the general partner
to own in lieu of the right to receive incentive distribution
payments based on target distribution levels that are less
certain to be achieved in the then current business environment.
As a result, a reset election may cause our common unitholders
to experience dilution in the amount of cash distributions that
they would have otherwise received had we not issued common
units to our general partner in connection with resetting the
target distribution levels related to our general partners
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incentive distribution rights. Please read Provisions of
Our Partnership Agreement Relating to Cash
Distributions Distributions of Available
Cash General Partner Interest and Incentive
Distribution Rights.
Fiduciary
Duties
Our general partner is accountable to us and our unitholders as
a fiduciary. Fiduciary duties owed to unitholders by our general
partner are prescribed by law and the partnership agreement. The
Delaware Act provides that Delaware limited partnerships may, in
their partnership agreements, modify or eliminate, except for
the contractual covenant of good faith and fair dealing, the
fiduciary duties owed by the general partner to limited partners
and the partnership.
Our partnership agreement contains various provisions
restricting the fiduciary duties that might otherwise be owed by
our general partner. We have adopted these provisions to allow
our general partner or its affiliates to engage in transactions
with us that would otherwise be prohibited by state-law
fiduciary standards and to take into account the interests of
other parties in addition to our interests when resolving
conflicts of interest. Without such modifications, such
transactions could result in violations of our general
partners state-law fiduciary duty standards. We believe
this is appropriate and necessary because the board of directors
of our general partner has fiduciary duties to manage our
general partner in a manner beneficial both to its owners, as
well as to our unitholders. Without these modifications, our
general partners ability to make decisions involving
conflicts of interest would be restricted. The modifications to
the fiduciary standards enable our general partner to take into
consideration the interests of all parties involved, so long as
the resolution is fair and reasonable to us. These modifications
also enable our general partner to attract and retain
experienced and capable directors. These modifications
disadvantage the common unitholders because they restrict the
rights and remedies that would otherwise be available to
unitholders for actions that, without those limitations, might
constitute breaches of fiduciary duty, as described below, and
permit our general partner to take into account the interests of
third parties in addition to our interests when resolving
conflicts of interest. The following is a summary of the
material restrictions of the fiduciary duties owed by our
general partner to the limited partners:
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State law fiduciary duty standards |
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Fiduciary duties are generally considered to include an
obligation to act in good faith and with due care and loyalty.
The duty of care, in the absence of a provision in a partnership
agreement providing otherwise, would generally require a general
partner to act for the partnership in the same manner as a
prudent person would act on his own behalf. The duty of loyalty,
in the absence of a provision in a partnership agreement
providing otherwise, would generally prohibit a general partner
of a Delaware limited partnership from taking any action or
engaging in any transaction where a conflict of interest is
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Partnership agreement modified standards |
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Our partnership agreement contains provisions that waive or
consent to conduct by our general partner and its affiliates
that might otherwise raise issues as to compliance with
fiduciary duties or applicable law. For example, our partnership
agreement provides that when our general partner is acting in
its capacity as our general partner, as opposed to in its
individual capacity, it must act in good faith and
will not be subject to any other standard under applicable law.
In addition, when our general partner is acting in its
individual capacity, as opposed to in its capacity as our
general partner, it may act without any fiduciary obligation to
us or our limited partners whatsoever. These standards reduce
the obligations to which our general partner would otherwise be
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Our partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not
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vote of unitholders or that are not approved by the Conflicts
Committee must be: |
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on terms no less favorable to us than those
generally being provided to or available from unrelated third
parties; or
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fair and reasonable to us, taking into
account the totality of the relationships between the parties
involved (including other transactions that may be particularly
favorable or advantageous to us).
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If our general partner does not seek approval from the Conflicts
Committee and its board of directors determines that the
resolution or course of action taken with respect to the
conflict of interest satisfies either of the standards set forth
in the bullet points above, then it will be presumed that, in
making its decision, the board of directors, which may include
board members affected by the conflict of interest, acted in
good faith, and in any proceeding brought by or on behalf of any
limited partner or the partnership, the person bringing or
prosecuting such proceeding will have the burden of overcoming
such presumption. These standards reduce the obligations to
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In addition to the other more specific provisions limiting the
obligations of our general partner, our partnership agreement
further provides that our general partner and its officers and
directors will not be liable for monetary damages to us or our
limited partners for errors of judgment or for any acts or
omissions unless there has been a final and non-appealable
judgment by a court of competent jurisdiction determining that
our general partner or its officers and directors acted in bad
faith or engaged in fraud or willful misconduct or, in the case
of a criminal matter, acted with knowledge that the conduct was
unlawful. |
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Rights and remedies of unitholders |
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The Delaware Act generally provides that a limited partner may
institute legal action on behalf of the partnership to recover
damages from a third party where a general partner has refused
to institute the action or where an effort to cause a general
partner to do so is not likely to succeed. These actions include
actions against a general partner for breach of its fiduciary
duties or of the partnership agreement. In addition, the
statutory or case law of some jurisdictions may permit a limited
partner to institute legal action on behalf of himself and all
other similarly situated limited partners to recover damages
from a general partner for violations of its fiduciary duties to
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By purchasing our common units, each common unitholder
automatically agrees to be bound by the provisions in our
partnership agreement, including the provisions discussed above.
This is in accordance with the policy of the Delaware Act
favoring the principle of freedom of contract and the
enforceability of partnership agreements. The failure of a
limited partner to sign a partnership agreement does not render
the partnership agreement unenforceable against that person.
Under our partnership agreement, we must indemnify our general
partner and its officers, directors and managers, to the fullest
extent permitted by law, against liabilities, costs and expenses
incurred by our general partner or these other persons. We must
provide this indemnification unless there has been a final and
non-appealable judgment by a court of competent jurisdiction
determining that these persons acted in bad faith or
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engaged in fraud or willful misconduct or, in the case of a
criminal matter, acted with knowledge that the conduct was
unlawful. We also must provide this indemnification for criminal
proceedings when our general partner or these other persons
acted with no knowledge that their conduct was unlawful. Thus,
our general partner could be indemnified for its negligent acts
if it met the requirements set forth above. To the extent that
these provisions purport to include indemnification for
liabilities arising under the Securities Act of 1933, or the
Securities Act, in the opinion of the SEC, such indemnification
is contrary to public policy and therefore unenforceable. Please
read The Partnership Agreement
Indemnification.
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DESCRIPTION
OF THE COMMON UNITS
The
Units
The common units represent limited partner interests in us. The
holders of common units, along with the holders of subordinated
units, are entitled to participate in partnership distributions
and are entitled to exercise the rights and privileges available
to limited partners under our partnership agreement. For a
description of the relative rights and preferences of holders of
common units and subordinated units in and to partnership
distributions, please read this section and Our Cash
Distribution Policy and Restrictions on Distributions. For
a description of the rights and privileges of limited partners
under our partnership agreement, including voting rights, please
read The Partnership Agreement.
Transfer
Agent and Registrar
Duties
will serve as the registrar and transfer agent for the common
units. We will pay all fees charged by the transfer agent for
transfers of common units except the following that must be paid
by our unitholders:
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surety bond premiums to replace lost or stolen certificates, or
to cover taxes and other governmental charges in connection
therewith;
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special charges for services requested by a holder of a common
unit; and
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other similar fees or charges.
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There will be no charge to our unitholders for disbursements of
our cash distributions. We will indemnify the transfer agent,
its agents and each of their respective stockholders, directors,
officers and employees against all claims and losses that may
arise out of acts performed or omitted for its activities in
that capacity, except for any liability due to any gross
negligence or intentional misconduct of the indemnified person
or entity.
Resignation
or Removal
The transfer agent may resign, by notice to us, or be removed by
us. The resignation or removal of the transfer agent will become
effective upon our appointment of a successor transfer agent and
registrar and its acceptance of the appointment. If no successor
has been appointed and has accepted the appointment within
30 days after notice of the resignation or removal, our
general partner may act as the transfer agent and registrar
until a successor is appointed.
Transfer
of Common Units
By transfer of common units in accordance with our partnership
agreement, each transferee of common units shall be admitted as
a limited partner with respect to the common units transferred
when such transfer and admission are reflected in our books and
records. Each transferee:
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automatically agrees to be bound by the terms and conditions of,
and is deemed to have executed, our partnership agreement;
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represents and warrants that the transferee has the right,
power, authority and capacity to enter into our partnership
agreement; and
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gives the consents, waivers and approvals contained in our
partnership agreement, such as the approval of all transactions
and agreements that we are entering into in connection with this
offering.
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Our general partner will cause any transfers to be recorded on
our books and records no less frequently than quarterly.
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We may, at our discretion, treat the nominee holder of a common
unit as the absolute owner. In that case, the beneficial
holders rights are limited solely to those that it has
against the nominee holder as a result of any agreement between
the beneficial owner and the nominee holder.
Common units are securities and are transferable according to
the laws governing the transfer of securities. In addition to
other rights acquired upon transfer, the transferor gives the
transferee the right to become a substituted limited partner in
our partnership for the transferred common units.
Until a common unit has been transferred on our books, we and
the transfer agent may treat the record holder of the common
unit as the absolute owner for all purposes, except as otherwise
required by law or stock exchange regulations.
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THE
PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
partnership agreement. The form of our partnership agreement is
included in this prospectus as Appendix A. We will provide
prospective investors with a copy of our partnership agreement
upon request at no charge.
We summarize the following provisions of our partnership
agreement elsewhere in this prospectus:
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with regard to distributions of available cash, please read
Provisions of Our Partnership Agreement Relating to Cash
Distributions;
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with regard to the fiduciary duties of our general partner,
please read Conflicts of Interest and Fiduciary
Duties;
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with regard to the transfer of common units, please read
Description of the Common Units Transfer of
Common Units; and
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with regard to allocations of taxable income and taxable loss,
please read Material Federal Income Tax Consequences.
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Organization
and Duration
We were organized in August 2009 and have a perpetual existence.
Purpose
Our purpose under our partnership agreement is limited to any
business activities that are approved by our general partner and
in any event that lawfully may be conducted by a limited
partnership organized under Delaware law; provided that
our general partner may not cause us to engage, directly or
indirectly, in any business activity that our general partner
determines would cause us to be treated as an association
taxable as a corporation or otherwise taxable as an entity for
federal income tax purposes.
Although our general partner has the power to cause us, our
operating company and its subsidiaries to engage in activities
other than the business of gathering, compressing, treating and
transporting natural gas, our general partner has no current
plans to do so and may decline to do so free of any fiduciary
duty or obligation whatsoever to us or the limited partners,
including any duty to act in good faith or in the best interests
of us or the limited partners. Our general partner is generally
authorized to perform all acts it determines to be necessary or
appropriate to carry out our purposes and to conduct our
business.
Cash
Distributions
Our partnership agreement specifies the manner in which we will
make cash distributions to holders of our common units and other
partnership securities as well as to our general partner in
respect of its general partner interest and its incentive
distribution rights. For a description of these cash
distribution provisions, please read Provisions of Our
Partnership Agreement Relating to Cash Distributions.
Capital
Contributions
Unitholders are not obligated to make additional capital
contributions, except as described below under
Limited Liability.
For a discussion of our general partners right to
contribute capital to maintain its 2.0% general partner interest
if we issue additional units, please read
Issuance of Additional Securities.
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Voting
Rights
The following is a summary of the unitholder vote required for
approval of the matters specified below. Matters that require
the approval of a unit majority require:
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during the subordination period, the approval of a majority of
the outstanding common units, excluding those common units held
by our general partner and its affiliates, and a majority of the
outstanding subordinated units, voting as separate
classes; and
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after the subordination period, the approval of a majority of
the outstanding common units.
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By virtue of the exclusion of those common units held by our
general partner and its affiliates from the required vote, and
by their ownership of all of the subordinated units, during the
subordination period our general partner and its affiliates do
not have the ability to ensure passage of, but do have the
ability to ensure defeat of, any amendment that requires a unit
majority.
In voting their common and subordinated units, our general
partner and its affiliates will have no fiduciary duty or
obligation whatsoever to us or our limited partners, including
any duty to act in good faith or in the best interests of us and
our limited partners.
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Issuance of additional units
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No approval right.
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Amendment of our partnership agreement
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Certain amendments may be made by our general partner without
the approval of the unitholders. Other amendments generally
require the approval of a unit majority. Please read
Amendment of Our Partnership Agreement.
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Merger of our partnership or the sale of all or substantially
all of our assets
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Unit majority in certain circumstances. Please read
Merger, Sale or Other Disposition of
Assets.
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Dissolution of our partnership
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Unit majority. Please read Termination and
Dissolution.
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Continuation of our business upon dissolution
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Unit majority. Please read Termination and
Dissolution.
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Withdrawal of our general partner
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Under most circumstances, the approval of a majority of the
common units, excluding common units held by our general partner
and its affiliates, is required for the withdrawal of our
general partner prior to November 4, 2019 in a manner that would
cause a dissolution of our partnership. Please read
Withdrawal or Removal of Our General
Partner.
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Removal of our general partner
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Not less than
662/3%
of the outstanding units, voting as a single class, including
units held by our general partner and its affiliates. Please
read Withdrawal or Removal of Our General
Partner.
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Transfer of our general partner interest
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Our general partner may transfer all, but not less than all, of
its general partner interest in us without a vote of our
unitholders to an affiliate or another person in connection with
its merger or consolidation with or into, or sale of all or
substantially all of its assets to, such person. The approval of
a majority of the outstanding common units, excluding common
units held by our general partner and its affiliates, is
required in other circumstances for a transfer of the general
partner interest to a third party prior to June 30, 2020. Please
read Transfer of General Partner
Interest.
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Transfer of incentive distribution rights
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Except for transfers to an affiliate or to another person as
part of our general partners merger or consolidation, sale
of all or substantially all of its assets or the sale of all of
the ownership interests in such holder, the approval of a
majority of the outstanding common units, excluding common units
held by our general partner and its affiliates, is required in
most circumstances for a transfer of the incentive distribution
rights to a third party prior to June 30, 2021. Please read
Transfer of Incentive Distribution
Rights.
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Transfer of ownership interests in our general partner
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No approval required at any time. Please read
Transfer of Ownership Interests in Our General
Partner.
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Limited
Liability
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware Act
and that it otherwise acts in conformity with the provisions of
our partnership agreement, its liability under the Delaware Act
will be limited, subject to possible exceptions, to the amount
of capital it is obligated to contribute to us for its common
units plus its share of any undistributed profits and assets. If
it were determined, however, that the right of, or exercise of
the right by, the limited partners as a group:
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to remove or replace our general partner;
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to approve some amendments to our partnership agreement; or
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to take other action under our partnership agreement;
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constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could be held personally liable for our obligations
under the laws of Delaware, to the same extent as our general
partner. This liability would extend to persons who transact
business with us who reasonably believe that a limited partner
is a general partner. Neither our partnership agreement nor the
Delaware Act specifically provides for legal recourse against
our general partner if a limited partner were to lose limited
liability through any fault of our general partner. While this
does not mean that a limited partner could not seek legal
recourse, we know of no precedent for such a claim in Delaware
case law.
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if, after the distribution, all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of the partnership, would exceed the fair
value of the assets of the limited partnership. For the purpose
of determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, a substituted limited partner of a
limited partnership is liable for the obligations of its
assignor to make contributions to the partnership, except that
such person is not obligated for liabilities unknown to it at
the time it became a limited partner and that could not be
ascertained from the partnership agreement.
Our subsidiaries conduct business primarily in five states and
we may have subsidiaries that conduct business in other states
in the future. Maintenance of our limited liability as a member
of our operating company may require compliance with legal
requirements in the jurisdictions in which our operating company
conducts business, including qualifying our subsidiaries to do
business there.
Limitations on the liability of members or limited partners for
the obligations of a limited liability company or limited
partnership have not been clearly established in many
jurisdictions. If, by virtue of our
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ownership interest in our operating company or otherwise, it
were determined that we were conducting business in any state
without compliance with the applicable limited partnership or
limited liability company statute, or that the right or exercise
of the right by the limited partners as a group to remove or
replace our general partner, to approve some amendments to our
partnership agreement, or to take other action under our
partnership agreement constituted participation in the
control of our business for purposes of the statutes of
any relevant jurisdiction, then the limited partners could be
held personally liable for our obligations under the law of that
jurisdiction to the same extent as our general partner under the
circumstances. We will operate in a manner that our general
partner considers reasonable and necessary or appropriate to
preserve the limited liability of the limited partners.
Issuance
of Additional Securities
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities for the
consideration and on the terms and conditions determined by our
general partner without the approval of our limited partners.
It is possible that we will fund acquisitions through the
issuance of additional common units, subordinated units or other
partnership securities. Holders of any additional common units
we issue will be entitled to share equally with the
then-existing holders of common units in our distributions of
available cash. In addition, the issuance of additional common
units or other partnership securities may dilute the value of
the interests of the then-existing holders of common units in
our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, as determined by our general partner, may have
rights to distributions or special voting rights to which the
common units are not entitled. In addition, our partnership
agreement does not prohibit our subsidiaries from issuing equity
securities, which may effectively rank senior to the common
units.
Upon issuance of additional partnership securities, our general
partner will be entitled, but not required, to make additional
capital contributions to the extent necessary to maintain its
2.0% general partner interest in us. Our general partners
2.0% interest in us will be reduced if we issue additional units
in the future and our general partner does not contribute a
proportionate amount of capital to us to maintain its 2.0%
general partner interest. Moreover, our general partner will
have the right, which it may from time to time assign in whole
or in part to any of its affiliates, to purchase common units,
subordinated units or other partnership securities whenever, and
on the same terms that, we issue those securities to persons
other than our general partner and its affiliates, to the extent
necessary to maintain the percentage interest of the general
partner and its affiliates, including such interest represented
by common and subordinated units, that existed immediately prior
to each issuance. The holders of common units will not have
preemptive rights under our partnership agreement to acquire
additional common units or other partnership securities.
Amendment
of Our Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by
our general partner. However, our general partner will have no
duty or obligation to propose any amendment and may decline to
do so free of any fiduciary duty or obligation whatsoever to us
or our limited partners, including any duty to act in good faith
or in the best interests of us or our limited partners. In order
to adopt a proposed amendment, other than the amendments
discussed below, our general partner must seek written approval
of the holders of the number of units required to approve the
amendment or call a meeting of the limited partners to consider
and vote upon the proposed amendment. Except as described below,
an amendment must be approved by a unit majority.
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Prohibited
Amendments
No amendment may be made that would:
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enlarge the obligations of any limited partner without its
consent, unless approved by at least a majority of the type or
class of limited partner interests so affected; or
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enlarge the obligations of, restrict in any way any action by or
rights of, or reduce in any way the amounts distributable,
reimbursable or otherwise payable by us to our general partner
or any of its affiliates without the consent of our general
partner, which consent may be given or withheld at its option.
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The provision of our partnership agreement preventing the
amendments having the effects described in the clauses above can
be amended upon the approval of the holders of at least 90.0% of
the outstanding units, voting as a single class (including units
owned by our general partner and its affiliates). Upon the
closing of this offering, affiliates of our general partner will
own approximately % of the
outstanding common and subordinated units.
No
Unitholder Approval
Our general partner may generally make amendments to our
partnership agreement without the approval of any limited
partner to reflect:
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a change in our name, the location of our principal place of
business, our registered agent or our registered office;
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the admission, substitution, withdrawal or removal of partners
in accordance with our partnership agreement;
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a change that our general partner determines to be necessary or
appropriate for us to qualify or to continue our qualification
as a limited partnership or a partnership in which the limited
partners have limited liability under the laws of any state or
to ensure that neither we, our operating company, nor its
subsidiaries will be treated as an association taxable as a
corporation or otherwise taxed as an entity for federal income
tax purposes;
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a change in our fiscal year or taxable year and related changes;
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an amendment that is necessary, in the opinion of our counsel,
to prevent us or our general partner or its directors, officers,
agents, or trustees from in any manner being subjected to the
provisions of the Investment Company Act of 1940, the Investment
Advisors Act of 1940 or plan asset regulations
adopted under the Employee Retirement Income Security Act of
1974, or ERISA, whether or not substantially similar to plan
asset regulations currently applied or proposed;
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an amendment that our general partner determines to be necessary
or appropriate in connection with the authorization of issuance
of additional partnership securities or rights to acquire
partnership securities;
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any amendment expressly permitted in our partnership agreement
to be made by our general partner acting alone;
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an amendment effected, necessitated, or contemplated by a merger
agreement that has been approved under the terms of our
partnership agreement;
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any amendment that our general partner determines to be
necessary or appropriate for the formation by us of, or our
investment in, any corporation, partnership, joint venture,
limited liability company or other entity, as otherwise
permitted by our partnership agreement;
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mergers with, conveyances to or conversions into another limited
liability entity that is newly formed and has no assets,
liabilities or operations at the time of the merger, conveyance
or conversion other than those it receives by way of the merger,
conveyance or conversion; or
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any other amendments substantially similar to any of the matters
described above.
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In addition, our general partner may make amendments to our
partnership agreement without the approval of any limited
partner if our general partner determines that those amendments:
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do not adversely affect in any material respect the limited
partners considered as a whole or any particular class of
partnership interests as compared to other classes of
partnership interests;
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are necessary or appropriate to satisfy any requirements,
conditions, or guidelines contained in any opinion, directive,
order, ruling, or regulation of any federal or state agency or
judicial authority or contained in any federal or state statute;
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are necessary or appropriate to facilitate the trading of units
or to comply with any rule, regulation, guideline, or
requirement of any securities exchange on which the units are or
will be listed for trading;
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are necessary or appropriate for any action taken by our general
partner relating to splits or combinations of units under the
provisions of our partnership agreement; or
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are required to effect the intent expressed in this prospectus
or the intent of the provisions of our partnership agreement or
are otherwise contemplated by our partnership agreement.
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Opinion
of Counsel and Limited Partner Approval
Our general partner will not be required to obtain an opinion of
counsel that an amendment will not result in a loss of limited
liability to the limited partners or result in our being treated
as an entity for federal income tax purposes in connection with
any of the amendments described above under No
Unitholder Approval. No other amendments to our
partnership agreement will become effective without the approval
of holders of at least 90.0% of the outstanding units voting as
a single class unless we first obtain an opinion of counsel to
the effect that the amendment will not affect the limited
liability under applicable law of any of our limited partners.
In addition to the above restrictions, any amendment that would
have a material adverse effect on the rights or preferences of
any type or class of outstanding units in relation to other
classes of units will require the approval of at least a
majority of the type or class of units so affected. Any
amendment that reduces the voting percentage required to take
any action must be approved by the affirmative vote of limited
partners whose aggregate outstanding units constitute not less
than the voting requirement sought to be reduced.
Merger,
Sale or Other Disposition of Assets
A merger or consolidation of us requires the prior consent of
our general partner. However, our general partner will have no
duty or obligation to consent to any merger or consolidation and
may decline to do so free of any fiduciary duty or obligation
whatsoever to us or the limited partners, including any duty to
act in good faith or in the best interest of us or our limited
partners.
In addition, our partnership agreement generally prohibits our
general partner, without the prior approval of the holders of a
unit majority, from causing us to, among other things, sell,
exchange or otherwise dispose of all or substantially all of our
and our subsidiaries assets in a single transaction or a
series of related transactions, including by way of merger,
consolidation, other combination or sale of ownership interests
of our subsidiaries. Our general partner may, however, mortgage,
pledge, hypothecate, or grant a security interest in all or
substantially all of our and our subsidiaries assets
without that approval. Our general partner may also sell all or
substantially all of our and our subsidiaries assets under
a foreclosure or other realization upon those encumbrances
without that approval. Finally, our general partner may
consummate any merger without the prior approval of our
unitholders if we are the surviving entity in the transaction,
our general partner has received an opinion of counsel regarding
limited liability and tax matters, the transaction would not
result in a material amendment to the partnership agreement
(other than an amendment that the general partner could adopt
without the consent of the limited partners), each of our units
will be an identical unit of our partnership following the
transaction and the partnership securities to be issued do not
exceed 20.0% of our outstanding partnership securities
immediately prior to the transaction.
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If the conditions specified in our partnership agreement are
satisfied, our general partner may convert us or any of our
subsidiaries into a new limited liability entity or merge us or
any of our subsidiaries into, or convey all of our assets to, a
newly formed limited liability entity, if the sole purpose of
that conversion, merger or conveyance is to effect a mere change
in our legal form into another limited liability entity, our
general partner has received an opinion of counsel regarding
limited liability and tax matters and the governing instruments
of the new entity provide the limited partners and our general
partner with the same rights and obligations as contained in our
partnership agreement. Our unitholders are not entitled to
dissenters rights of appraisal under our partnership
agreement or applicable Delaware law in the event of a
conversion, merger or consolidation, a sale of substantially all
of our assets or any other similar transaction or event.
Termination
and Dissolution
We will continue as a limited partnership until dissolved under
our partnership agreement. We will dissolve upon:
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the withdrawal or removal of our general partner or any other
event that results in its ceasing to be our general partner
other than by reason of a transfer of its general partner
interest in accordance with our partnership agreement or
withdrawal or removal following the approval and admission of a
successor general partner;
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the election of our general partner to dissolve us, if approved
by the holders of units representing a unit majority;
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the entry of a decree of judicial dissolution of our
partnership; or
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there being no limited partners, unless we are continued without
dissolution in accordance with the Delaware Act.
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Upon a dissolution under the first clause above, the holders of
a unit majority may also elect, within specific time
limitations, to continue our business on the same terms and
conditions described in our partnership agreement and appoint as
a successor general partner an entity approved by the holders of
units representing a unit majority, subject to our receipt of an
opinion of counsel to the effect that:
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the action would not result in the loss of limited liability of
any limited partner; and
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neither we nor any of our subsidiaries would be treated as an
association taxable as a corporation or otherwise be taxable as
an entity for federal income tax purposes upon the exercise of
that right to continue (to the extent not already so treated or
taxed).
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Liquidation
and Distribution of Proceeds
Upon our dissolution, unless we are continued as a limited
partnership, the liquidator authorized to wind up our affairs
will, acting with all of the powers of our general partner that
are necessary or appropriate, liquidate our assets and apply the
proceeds of the liquidation as described in Provisions of
Our Partnership Agreement Relating to Cash
Distributions Distributions of Cash Upon
Liquidation. The liquidator may defer liquidation or
distribution of our assets for a reasonable period of time if it
determines that an immediate sale or distribution would be
impractical or would cause undue loss to our partners. The
liquidator may distribute our assets, in whole or in part, in
kind if it determines that a sale would be impractical or would
cause undue loss to the partners.
Withdrawal
or Removal of Our General Partner
Except as described below, our general partner has agreed not to
withdraw voluntarily as our general partner prior to
November 4, 2019 without obtaining the approval of the
holders of at least a majority of the outstanding common units,
excluding common units held by the general partner and its
affiliates, and furnishing an opinion of counsel regarding
limited liability and tax matters. On or after November 4,
2019, our general partner may withdraw as general partner
without first obtaining approval of any unitholder by giving at
least 90 days advance notice, and that withdrawal
will not constitute a violation of our partnership
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agreement. Notwithstanding the information above, our general
partner may withdraw without unitholder approval upon
90 days notice to the limited partners if at least
50.0% of the outstanding common units are held or controlled by
one person and its affiliates, other than our general partner
and its affiliates. In addition, our partnership agreement
permits our general partner in some instances to sell or
otherwise transfer all of its general partner interest and
incentive distribution rights in us without the approval of the
unitholders. Please read Transfer of General
Partner Interest and Transfer of
Incentive Distribution Rights.
Upon withdrawal of our general partner under any circumstances,
other than as a result of a transfer by our general partner of
all or a part of its general partner interest in us, the holders
of a unit majority may select a successor to that withdrawing
general partner. If a successor is not elected, or is elected
but an opinion of counsel regarding limited liability and tax
matters cannot be obtained, we will be dissolved, wound up and
liquidated, unless within a specified period of time after that
withdrawal, the holders of a unit majority agree in writing to
continue our business and to appoint a successor general
partner. Please read Termination and
Dissolution.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than
662/3%
of all outstanding units, voting together as a single class,
including units held by our general partner and its affiliates,
and we receive an opinion of counsel regarding limited liability
and tax matters. Any removal of our general partner is also
subject to the approval of a successor general partner by the
vote of the holders of a majority of the outstanding common
units, and a majority of the outstanding subordinated units,
voting as a single class. The ownership of more than
332/3%
of the outstanding units by our general partner and its
affiliates gives them the ability to prevent our general
partners removal. At the closing of this offering,
affiliates of our general partner will
own % of the outstanding common and
subordinated units.
Our partnership agreement also provides that if our general
partner is removed as our general partner under circumstances
where cause does not exist and units held by our general partner
and its affiliates are not voted in favor of that removal:
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the subordination period will end and all outstanding
subordinated units will immediately and automatically convert
into common units on a
one-for-one
basis;
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests
based on the fair market value of the interests at the time.
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In the event of removal of our general partner under
circumstances where cause exists or withdrawal of our general
partner where that withdrawal violates our partnership
agreement, a successor general partner will have the option to
purchase the general partner interest and incentive distribution
rights of the departing general partner for a cash payment equal
to the fair market value of those interests. Under all other
circumstances where our general partner withdraws or is removed
by the limited partners, the departing general partner will have
the option to require the successor general partner to purchase
the general partner interest of the departing general partner
and its incentive distribution rights for their fair market
value. In each case, this fair market value will be determined
by agreement between the departing general partner and the
successor general partner. If no agreement is reached, an
independent investment banking firm or other independent expert
selected by the departing general partner and the successor
general partner will determine the fair market value. Or, if the
departing general partner and the successor general partner
cannot agree upon an expert, then an expert chosen by agreement
of the experts selected by each of them will determine the fair
market value.
If the option described above is not exercised by either the
departing general partner or the successor general partner, the
departing general partners general partner interest and
its incentive distribution rights will automatically convert
into common units equal to the fair market value of those
interests as determined by an investment banking firm or other
independent expert selected in the manner described in the
preceding paragraph.
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In addition, we will be required to reimburse the departing
general partner for all amounts due to it, including, without
limitation, all employee-related liabilities, including
severance liabilities, incurred in connection with the
termination of any employees employed by the departing general
partner or its affiliates for our benefit.
Transfer
of General Partner Interest
Except for transfer by our general partner of all, but not less
than all, of its general partner interest to:
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an affiliate of our general partner (other than an
individual); or
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another entity as part of the merger or consolidation of our
general partner with or into another entity or the transfer by
our general partner of all or substantially all of its assets to
another entity, our general partner may not transfer all or any
of its general partner interest to another person prior to
June 30, 2021 without the approval of the holders of at
least a majority of the outstanding common units, excluding
common units held by our general partner and its affiliates. As
a condition of this transfer, the transferee must, among other
things, assume the rights and duties of our general partner,
agree to be bound by the provisions of our partnership agreement
and furnish an opinion of counsel regarding limited liability
and tax matters.
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Our general partner and its affiliates may, at any time,
transfer units to one or more persons, without unitholder
approval, except that they may not transfer subordinated units
to us.
Transfer
of Ownership Interests in Our General Partner
At any time, the owners of our general partner may sell or
transfer all or part of their ownership interests in our general
partner to an affiliate or a third party without the approval of
our unitholders.
Transfer
of Incentive Distribution Rights
Our general partner or its affiliates or a subsequent holder may
transfer its incentive distribution rights to an affiliate of
the holder (other than an individual) or another entity as part
of the merger or consolidation of such holder with or into
another entity, the sale of all of the ownership interest in the
holder or the sale of all or substantially all of the
holders assets to that entity without the prior approval
of the unitholders. Prior to June 30, 2021, other transfers
of incentive distribution rights will require the affirmative
vote of holders of a majority of the outstanding common units,
excluding common units held by our general partner and its
affiliates. On or after June 30, 2021, the incentive
distribution rights will be freely transferable.
Change of
Management Provisions
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove our general partner or otherwise change our management.
If any person or group, other than our general partner and its
affiliates, acquires beneficial ownership of 20.0% or more of
any class of units, that person or group loses voting rights on
all of its units. This loss of voting rights does not apply to
any person or group that acquires the units directly from our
general partner or its affiliates or any transferee of that
person or group that is approved by our general partner or to
any person or group who acquires the units with the prior
approval of the board of directors of our general partner.
Our partnership agreement also provides that if our general
partner is removed as our general partner under circumstances
where cause does not exist and units held by our general partner
and its affiliates are not voted in favor of that removal:
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the subordination period will end and all outstanding
subordinated units will immediately and automatically convert
into common units on a
one-for-one
basis;
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests
based on the fair market value of the interests at the time.
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Limited
Call Right
If at any time our general partner and its affiliates own more
than 80.0% of the then-issued and outstanding limited partner
interests of any class, our general partner will have the right,
which it may assign in whole or in part to any of its affiliates
or to us, to acquire all, but not less than all, of the
remaining limited partner interests of the class held by
unaffiliated persons as of a record date to be selected by our
general partner, on at least 10, but not more than 60, days
notice. The purchase price in the event of this purchase is the
greater of:
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the highest price paid by our general partner or any of its
affiliates for any limited partner interests of the class
purchased within the 90 days preceding the date on which
our general partner first mails notice of its election to
purchase those limited partner interests; and
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the average of the daily closing prices of the partnership
securities of such class for the 20 consecutive trading days
preceding the date three days before the date the notice is
mailed.
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As a result of our general partners right to purchase
outstanding limited partner interests, a holder of limited
partner interests may have his limited partner interests
purchased at an undesirable time or price. The tax consequences
to a unitholder of the exercise of this call right are the same
as a sale by that unitholder of his common units in the market.
Please read Material Federal Income Tax
Consequences Disposition of Common Units.
Meetings;
Voting
Except as described below regarding a person or group owning
20.0% or more of any class of units then outstanding,
unitholders who are record holders of units on the record date
will be entitled to notice of, and to vote at, meetings of our
limited partners and to act upon matters for which approvals may
be solicited.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting if consents in writing describing the action so taken
are signed by holders of the number of units necessary to
authorize or take that action at a meeting. Meetings of the
unitholders may be called by our general partner or by
unitholders owning at least 20.0% of the outstanding units of
the class for which a meeting is proposed. Unitholders may vote
either in person or by proxy at meetings. The holders of a
majority of the outstanding units of the class or classes for
which a meeting has been called, represented in person or by
proxy, will constitute a quorum unless any action by the
unitholders requires approval by holders of a greater percentage
of the units, in which case the quorum will be the greater
percentage. The units representing the general partner interest
are units for distribution and allocation purposes, but do not
entitle our general partner to any vote other than its rights as
general partner under our partnership agreement, will not be
entitled to vote on any action required or permitted to be taken
by the unitholders and will not count toward or be considered
outstanding when calculating required votes, determining the
presence of a quorum, or for similar purposes.
Each record holder of a unit has a vote according to its
percentage interest in us, although additional limited partner
interests having special voting rights could be issued. Please
read Issuance of Additional Securities.
However, if at any time any person or group, other than our
general partner and its affiliates, or a direct or subsequently
approved transferee of our general partner or its affiliates,
acquires, in the aggregate, beneficial ownership of 20.0% or
more of any class of units then outstanding, that person or
group will lose voting rights on all of its units and the units
may not be voted on any matter and will not be considered to be
outstanding when sending notices of a meeting of unitholders,
calculating required votes, determining the presence of a
quorum, or for other similar purposes. Common units held in
nominee or street name account will be voted by the broker or
other nominee in accordance with the instruction of the
beneficial owner unless
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the arrangement between the beneficial owner and its nominee
provides otherwise. Except as our partnership agreement
otherwise provides, subordinated units will vote together with
common units as a single class.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
Status as
Limited Partner
By transfer of common units in accordance with our partnership
agreement, each transferee of common units will be admitted as a
limited partner with respect to the common units transferred
when such transfer and admission are reflected in our books and
records. Except as described above under
Limited Liability, the common units will
be fully paid, and unitholders will not be required to make
additional contributions.
Non-Citizen
Assignees; Redemption
If we are or become subject to federal, state, or local laws or
regulations that, in the determination of our general partner,
create a substantial risk of cancellation or forfeiture of any
property in which we have an interest based on the nationality,
citizenship or other related status of any limited partner or
assignee, our general partner may request any limited partner or
assignee to furnish to the general partner an executed
citizenship certification or such other information about his
nationality, citizenship or related status. If a limited partner
fails to furnish such citizenship certification or other
requested information about his nationality, citizenship or
other related status within 30 days after a request for
such citizenship certification or other requested information or
our general partner determines after receipt of the information
that the limited partner is not an eligible citizen, the limited
partner may be treated as a non-citizen assignee. A non-citizen
assignee does not have the right to direct the voting of his
units and may not receive distributions in kind upon our
liquidation.
Furthermore, we have the right to redeem all of the common and
subordinated units of any holder that our general partner
concludes is not an eligible citizen or fails to furnish the
information requested by our general partner. The redemption
price in the event of such redemption for each unit held by such
unitholder will be the lesser of (i) the current market
price (the date of determination of which shall be the date
fixed for redemption) and (ii) the price paid for each such
unit by the unitholder. The redemption price will be paid, as
determined by our general partner, in cash or by delivery of a
promissory note. Any such promissory note will bear interest at
the rate of 5% annually and be payable in three equal annual
installments of principal and accrued interest, commencing one
year after the redemption date.
Non-Taxpaying
Assignees; Redemption
In the event any rates that we charge our customers become
regulated by the Federal Energy Regulatory Commission, to avoid
any adverse effect on the maximum applicable rates chargeable to
customers by us, or in order to reverse an adverse determination
that has occurred regarding such maximum rate, our partnership
agreement provides our general partner the power to amend the
agreement. If our general partner, with the advice of counsel,
determines that our not being treated as an association taxable
as a corporation or otherwise taxable as an entity for
U.S. federal income tax purposes, coupled with the tax
status (or lack of proof thereof) of one or more of our limited
partners, has, or is reasonably likely to have, a material
adverse effect on the maximum applicable rates chargeable to
customers by us, then our general partner may adopt such
amendments to our partnership agreement as it determines
necessary or advisable to:
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obtain proof of the U.S. federal income tax status of our
member (and their owners, to the extent relevant); and
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permit us to redeem the units held by any person whose tax
status has or is reasonably likely to have a material adverse
effect on the maximum applicable rates or who fails to comply
with the procedures instituted by our general partner to obtain
proof of the U.S. federal income tax status. The redemption
price in the case of such a redemption will be the average of
the daily closing prices per unit for the 20 consecutive trading
days immediately prior to the date set for redemption.
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Indemnification
Under our partnership agreement, we will indemnify the following
persons, in most circumstances, to the fullest extent permitted
by law, from and against all losses, claims, damages or similar
events:
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our general partner;
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any departing general partner;
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any person who is or was an affiliate of our general partner or
any departing general partner;
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any person who is or was a member, manager, partner, director,
officer, fiduciary or trustee of our partnership, our
subsidiaries, our general partner, any departing general partner
or any of their affiliates;
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any person who is or was serving at the request of the general
partner or any departing general partner as an officer,
director, member, manager, partner, fiduciary or trustee of
another person; and
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any person designated by our general partner.
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Any indemnification under these provisions will only be out of
our assets. Unless it otherwise agrees, our general partner will
not be personally liable for, or have any obligation to
contribute or loan funds or assets to us to enable us to
effectuate, indemnification. We may purchase insurance against
liabilities asserted against and expenses incurred by persons
for our activities, regardless of whether we would have the
power to indemnify the person against liabilities under our
partnership agreement.
Reimbursement
of Expenses
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with operating our business. These expenses include salary,
bonus, incentive compensation and other amounts paid to persons
who perform services for us or on our behalf and expenses
allocated to our general partner by its affiliates. Our general
partner is entitled to determine in good faith the expenses that
are allocable to us.
Books and
Reports
Our general partner is required to keep or cause to be kept
appropriate books and records of our business at our principal
offices. The books will be maintained for both tax and financial
reporting purposes on an accrual basis. For fiscal and tax
reporting purposes, we use the calendar year.
We will furnish or make available (by posting on our website or
other reasonable means) to record holders of common units,
within 120 days after the close of each fiscal year, an
annual report containing audited financial statements and a
report on those financial statements by our independent public
accountants, including a balance sheet and statements of
operations, and our equity and cash flows. Except for our fourth
quarter, we will also furnish or make available summary
financial information within 90 days after the close of
each quarter.
As soon as practicable, but in no event later than 90 days
after the close of each quarter except the last quarter of each
fiscal year, our general partner will mail or make available to
each record holder of a unit a report containing our unaudited
financial statements and such other information as may be
required by applicable law, regulation or rule. This information
is expected to be furnished in summary form so that some complex
calculations normally required of partners can be avoided. Our
ability to furnish this summary information to unitholders will
depend on the cooperation of unitholders in supplying us with
specific information. Every unitholder will receive information
to assist him in determining its federal and state tax liability
and filing its federal and state income tax returns, regardless
of whether he supplies us with information.
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Right to
Inspect Our Books and Records
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to its interest as a limited
partner, upon reasonable demand and at its own expense, have
furnished to him:
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a current list of the name and last known business, residence or
mailing address of each partner;
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a copy of our federal, state and local income tax returns;
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true and full information as to the amount of cash, and a
description and statement of the net agreed value of any other
capital contribution by each partner and that each partner has
agreed to contribute in the future, and the date on which each
became a partner;
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copies of our partnership agreement, the certificate of limited
partnership of the partnership, related amendments, and powers
of attorney under which they have been executed;
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information regarding the status of our business and financial
condition; and
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any other information regarding our affairs as is just and
reasonable.
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Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests or that we are required by law or
by agreements with third parties to keep confidential.
Registration
Rights
Under our partnership agreement, we have agreed to register for
resale under the Securities Act and applicable state securities
laws any common units, subordinated units, or other partnership
securities proposed to be sold by our general partner or any of
its affiliates, other than individuals, or their assignees if an
exemption from the registration requirements is not otherwise
available. These registration rights continue for two years and
for so long thereafter as is required for the holder to sell its
partnership securities following any withdrawal or removal of
American Midstream GP as our general partner. We are obligated
to pay all expenses incidental to the registration, excluding
underwriting discounts and commissions. Please read Units
Eligible for Future Sale.
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UNITS
ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus,
AIM Midstream Holdings will hold an aggregate
of
common units
and
subordinated units
(or
common units
and
subordinated units if the underwriters exercise their option to
purchase additional units in full). All of the subordinated
units will convert into common units at the end of the
subordination period. The sale of these common and subordinated
units could have an adverse impact on the price of the common
units or on any trading market that may develop.
The common units sold in this offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units held by an
affiliate of ours may not be resold publicly except
in compliance with the registration requirements of the
Securities Act or under an exemption under Rule 144 or
otherwise. Rule 144 permits securities acquired by an
affiliate of the issuer to be sold into the market in an amount
that does not exceed, during any three-month period, the greater
of:
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1.0% of the total number of the securities outstanding; or
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the average weekly reported trading volume of the common units
for the four calendar weeks prior to the sale.
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Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about us. A person who is not deemed to have been an affiliate
of ours at any time during the three months preceding a sale,
and who has beneficially owned his common units for at least six
months (provided we are in compliance with the current public
information requirement) or one year (regardless of whether we
are in compliance with the current public information
requirement), would be entitled to sell common units under
Rule 144 without regard to the rules public
information requirements, volume limitations, manner of sale
provisions and notice requirements.
Our partnership agreement provides that we may issue an
unlimited number of limited partner interests of any type
without a vote of the unitholders at any time. Any issuance of
additional common units or other equity securities would result
in a corresponding decrease in the proportionate ownership
interest in us represented by, and could adversely affect the
cash distributions to and market price of, common units then
outstanding. Please read The Partnership
Agreement Issuance of Additional Securities.
Under our partnership agreement, our general partner and its
affiliates, excluding any individual who is an affiliate of our
general partner, have the right to cause us to register under
the Securities Act and applicable state securities laws the
offer and sale of any common units that they hold. Subject to
the terms and conditions of our partnership agreement, these
registration rights allow our general partner and its affiliates
or their assignees holding any common units to require
registration of any of these common units and to include any of
these common units in a registration by us of other common
units, including common units offered by us or by any
unitholder. Our general partner and its affiliates will continue
to have these registration rights for two years following the
withdrawal or removal of our general partner. In connection with
any registration of this kind, we will indemnify each unitholder
participating in the registration and its officers, directors,
and controlling persons from and against any liabilities under
the Securities Act or any applicable state securities laws
arising from the registration statement or prospectus. We will
bear all costs and expenses incidental to any registration,
excluding any underwriting discounts and commissions. Except as
described below, our general partner and its affiliates may sell
their common units in private transactions at any time, subject
to compliance with applicable laws.
AIM Midstream Holdings, our general partner and the executive
officers and directors of our general partner have agreed not to
sell any common units they beneficially own for a period of
180 days from the date of this prospectus. Please read
Underwriting for a description of these
lock-up
provisions.
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MATERIAL
FEDERAL INCOME TAX CONSEQUENCES
This section is a summary of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the U.S. and, unless
otherwise noted in the following discussion, is the opinion of
Andrews Kurth LLP, counsel to our general partner and us,
insofar as it relates to legal conclusions with respect to
matters of U.S. federal income tax law. This section is
based upon current provisions of the Internal Revenue Code of
1986, as amended (the Internal Revenue Code),
existing and proposed Treasury regulations promulgated under the
Internal Revenue Code (the Treasury Regulations) and
current administrative rulings and court decisions, all of which
are subject to change. Later changes in these authorities may
cause the tax consequences to vary substantially from the
consequences described below. Unless the context otherwise
requires, references in this section to us or
we are references to American Midstream Partners, LP
and our operating subsidiaries.
The following discussion does not comment on all federal income
tax matters affecting us or our unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the U.S. and has only limited application to
corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, IRAs, real estate
investment trusts (REITs) or mutual funds. In addition, the
discussion only comments, to a limited extent, on state, local,
and foreign tax consequences. Accordingly, we encourage each
prospective unitholder to consult, and depend on, his own tax
advisor in analyzing the federal, state, local and foreign tax
consequences particular to him of the ownership or disposition
of common units.
No ruling has been or will be requested from the IRS regarding
any matter affecting us or prospective unitholders. Instead, we
will rely on opinions of Andrews Kurth LLP. Unlike a ruling, an
opinion of counsel represents only that counsels best
legal judgment and does not bind the IRS or the courts.
Accordingly, the opinions and statements made herein may not be
sustained by a court if contested by the IRS. Any contest of
this sort with the IRS may materially and adversely impact the
market for the common units and the prices at which common units
trade. In addition, the costs of any contest with the IRS,
principally legal, accounting and related fees, will result in a
reduction in cash available for distribution to our unitholders
and our general partner and thus will be borne indirectly by our
unitholders and our general partner. Furthermore, the tax
treatment of us, or of an investment in us, may be significantly
modified by future legislative or administrative changes or
court decisions. Any modifications may or may not be
retroactively applied.
All statements as to matters of federal income tax law and legal
conclusions with respect thereto, but not as to factual matters,
contained in this section, unless otherwise noted, are the
opinion of Andrews Kurth LLP and are based on the accuracy of
the representations made by us.
For the reasons described below, Andrews Kurth LLP has not
rendered an opinion with respect to the following specific
federal income tax issues: (i) the treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units (please read
Tax Consequences of Unit Ownership
Treatment of Short Sales); (ii) whether our monthly
convention for allocating taxable income and losses is permitted
by existing Treasury Regulations (please read
Disposition of Common Units
Allocations Between Transferors and Transferees); and
(iii) whether our method for depreciating Section 743
adjustments is sustainable in certain cases (please read
Tax Consequences of Unit Ownership
Section 754 Election and Uniformity
of Units).
Partnership
Status
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partnership or the partner unless the amount of cash distributed
to him is in excess of the partners adjusted basis in his
partnership interest.
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Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from the transportation, storage, processing and
marketing of crude oil, natural gas and other products thereof.
Other types of qualifying income include interest (other than
from a financial business), dividends, gains from the sale of
real property and gains from the sale or other disposition of
capital assets held for the production of income that otherwise
constitutes qualifying income. We estimate that less
than % of our current gross income
is not qualifying income; however, this estimate could change
from time to time. Based upon and subject to this estimate, the
factual representations made by us and our general partner and a
review of the applicable legal authorities, Andrews Kurth LLP is
of the opinion that at least 90% of our current gross income
constitutes qualifying income. The portion of our income that is
qualifying income may change from time to time.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status or the status of our
operating subsidiaries for federal income tax purposes or
whether our operations generate qualifying income
under Section 7704 of the Internal Revenue Code. Instead,
we will rely on the opinion of Andrews Kurth LLP on such
matters. It is the opinion of Andrews Kurth LLP that, based upon
the Internal Revenue Code, its regulations, published revenue
rulings and court decisions and the representations described
below that:
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We will be classified as a partnership for federal income tax
purposes; and
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Each of our operating subsidiaries will be disregarded as an
entity separate from us or will be treated as a partnership for
federal income tax purposes.
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In rendering its opinion, Andrews Kurth LLP has relied on
factual representations made by us and our general partner. The
representations made by us and our general partner upon which
Andrews Kurth LLP has relied are:
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Neither we nor the operating subsidiaries has elected or will
elect to be treated as a corporation; and
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For each taxable year, more than 90% of our gross income has
been and will be income of the type that Andrews Kurth LLP has
opined or will opine is qualifying income within the
meaning of Section 7704(d) of the Internal Revenue Code.
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We believe that these representations have been true in the past
and expect that these representations will continue to be true
in the future.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery (in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts), we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock in that corporation, and then distributed that stock
to the unitholders in liquidation of their interests in us. This
deemed contribution and liquidation should be tax-free to
unitholders and us so long as we, at that time, do not have
liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal
income tax purposes.
If we were taxed as a corporation for federal income tax
purposes in any taxable year, either as a result of a failure to
meet the Qualifying Income Exception or otherwise, our items of
income, gain, loss and deduction would be reflected only on our
tax return rather than being passed through to our unitholders,
and our net income would be taxed to us at corporate rates. In
addition, any distribution made to a unitholder would be treated
as taxable dividend income, to the extent of our current and
accumulated earnings and profits, or, in the absence of earnings
and profits, a nontaxable return of capital, to the extent of
the unitholders tax basis in his common units, or taxable
capital gain, after the unitholders tax basis in his
common units is reduced to zero. Accordingly, taxation as a
corporation would result in a material reduction
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in a unitholders cash flow and after-tax return and thus
would likely result in a substantial reduction of the value of
the units.
The discussion below is based on Andrews Kurth LLPs
opinion that we will be classified as a partnership for federal
income tax purposes.
Limited
Partner Status
Unitholders who are admitted as limited partners of American
Midstream Partners, LP will be treated as partners of American
Midstream Partners, LP for federal income tax purposes. Also,
unitholders whose common units are held in street name or by a
nominee and who have the right to direct the nominee in the
exercise of all substantive rights attendant to the ownership of
their common units will be treated as partners of American
Midstream Partners, LP for federal income tax purposes.
A beneficial owner of common units whose units have been
transferred to a short seller to complete a short sale would
appear to lose his status as a partner with respect to those
units for federal income tax purposes. Please read
Tax Consequences of Unit Ownership
Treatment of Short Sales.
Income, gain, deductions or losses would not appear to be
reportable by a unitholder who is not a partner for federal
income tax purposes, and any cash distributions received by a
unitholder who is not a partner for federal income tax purposes
would therefore appear to be fully taxable as ordinary income.
These holders are urged to consult their own tax advisors with
respect to their tax consequences of holding common units in
American Midstream Partners, LP. The references to
unitholders in the discussion that follows are to
persons who are treated as partners in American Midstream
Partners, LP for federal income tax purposes.
Tax
Consequences of Unit Ownership
Flow-Through
of Taxable Income
Subject to the discussion below under
Entity-Level Collections, we will
not pay any federal income tax. Instead, each unitholder will be
required to report on his income tax return his share of our
income, gains, losses and deductions without regard to whether
we make cash distributions to him. Consequently, we may allocate
income to a unitholder even if he has not received a cash
distribution. Each unitholder will be required to include in
income his allocable share of our income, gains, losses and
deductions for our taxable year ending with or within his
taxable year. Our taxable year ends on December 31.
Treatment
of Distributions
Distributions by us to a unitholder generally will not be
taxable to the unitholder for federal income tax purposes,
except to the extent the amount of any such cash distribution
exceeds his tax basis in his common units immediately before the
distribution. Cash distributions made by us to a unitholder in
an amount in excess of a unitholders tax basis generally
will be considered to be gain from the sale or exchange of the
common units, taxable in accordance with the rules described
under Disposition of Common Units below.
Any reduction in a unitholders share of our liabilities
for which no partner, including the general partner, bears the
economic risk of loss, known as nonrecourse
liabilities, will be treated as a distribution by us of
cash to that unitholder. To the extent our distributions cause a
unitholders at-risk amount to be less than
zero at the end of any taxable year, he must recapture any
losses deducted in previous years. Please read
Limitations on Deductibility of Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash. This deemed
distribution may constitute a non-pro rata distribution. A
non-pro rata distribution of money or property may result in
ordinary income to a unitholder, regardless of his tax basis in
his common units, if the distribution reduces the
unitholders share of our unrealized
receivables, including depreciation recapture, depletion
recapture
and/or
substantially appreciated inventory items, each as
defined in the Internal Revenue Code, and collectively,
Section 751 Assets. To that extent, the
unitholder will be treated as having been distributed his
proportionate share of the Section 751 Assets and then
having
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exchanged those assets with us in return for the non-pro rata
portion of the actual distribution made to him. This latter
deemed exchange will generally result in the unitholders
realization of ordinary income, which will equal the excess of
(i) the non-pro rata portion of that distribution over
(ii) the unitholders tax basis (generally zero) for
the share of Section 751 Assets deemed relinquished in the
exchange.
Ratio
of Taxable Income to Distributions
We estimate that a purchaser of common units in this offering
who owns those common units from the date of closing of this
offering through the record date for distributions for the
period
ending ,
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amount of federal taxable income for that period that will
be % or less of the cash
distributed with respect to that period. Thereafter, we
anticipate that the ratio of allocable taxable income to cash
distributions to the unitholders will increase. These estimates
are based upon the assumption that gross income from operations
will approximate the amount required to make the minimum
quarterly distribution on all units and other assumptions with
respect to capital expenditures, cash flow, net working capital
and anticipated cash distributions. These estimates and
assumptions are subject to, among other things, numerous
business, economic, regulatory, legislative, competitive and
political uncertainties beyond our control. Further, the
estimates are based on current tax law and tax reporting
positions that we will adopt and with which the IRS could
disagree. Accordingly, we cannot assure you that these estimates
will prove to be correct. The actual percentage of distributions
that will constitute taxable income could be higher or lower
than expected, and any differences could be material and could
materially affect the value of the common units. For example,
the ratio of allocable taxable income to cash distributions to a
purchaser of common units in this offering will be greater, and
perhaps substantially greater, than our estimate with respect to
the period described above if:
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gross income from operations exceeds the amount required to make
minimum quarterly distributions on all units, yet we only
distribute the minimum quarterly distributions on all
units; or
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we make a future offering of common units and use the proceeds
of the offering in a manner that does not produce substantial
additional deductions during the period described above, such as
to repay indebtedness outstanding at the time of this offering
or to acquire property that is not eligible for depreciation or
amortization for federal income tax purposes or that is
depreciable or amortizable at a rate significantly slower than
the rate applicable to our assets at the time of this offering.
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Basis
of Common
Units
A unitholders initial tax basis for his common units will
be the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his
share of our income and by any increases in his share of our
nonrecourse liabilities. That basis will be decreased, but not
below zero, by distributions from us, by the unitholders
share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures
that are not deductible in computing taxable income and are not
required to be capitalized. A unitholder will have no share of
our debt that is recourse to our general partner to the extent
of the general partners net value, as defined
in Treasury Regulations under Section 752 of the Internal
Revenue Code, but will have a share, generally based on his
share of profits, of our nonrecourse liabilities. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Limitations
on Deductibility of
Losses
The deduction by a unitholder of his share of our losses will be
limited to the tax basis in his units and, in the case of an
individual unitholder, estate, trust, or corporate unitholder
(if more than 50% of the value of the corporate
unitholders stock is owned directly or indirectly by or
for five or fewer individuals or some tax-exempt organizations)
to the amount for which the unitholder is considered to be
at risk with respect to our activities, if that is
less than his tax basis. A common unitholder subject to these
limitations must recapture losses deducted in previous years to
the extent that distributions cause his at-risk amount to be
less than zero at the end of any taxable year. Losses disallowed
to a unitholder or recaptured as a result of these limitations
will carry forward and will be allowable as a deduction to the
extent that his at-risk amount is subsequently increased,
provided such losses do not exceed such common unitholders
tax basis in his common units. Upon
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the taxable disposition of a unit, any gain recognized by a
unitholder can be offset by losses that were previously
suspended by the at-risk limitation but may not be offset by
losses suspended by the basis limitation. Any loss previously
suspended by the at-risk limitation in excess of that gain would
no longer be utilizable.
In general, a unitholder will be at risk to the extent of the
tax basis of his units, excluding any portion of that basis
attributable to his share of our nonrecourse liabilities,
reduced by (i) any portion of that basis representing
amounts otherwise protected against loss because of a guarantee,
stop loss agreement or other similar arrangement and
(ii) any amount of money he borrows to acquire or hold his
units, if the lender of those borrowed funds owns an interest in
us, is related to the unitholder or can look only to the units
for repayment. A unitholders at-risk amount will increase
or decrease as the tax basis of the unitholders units
increases or decreases, other than tax basis increases or
decreases attributable to increases or decreases in his share of
our nonrecourse liabilities.
In addition to the basis and at-risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations can deduct losses
from passive activities, which are generally defined as trade or
business activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our investments or
a unitholders investments in other publicly traded
partnerships, or salary or active business income. Passive
losses that are not deductible because they exceed a
unitholders share of income we generate may be deducted in
full when he disposes of his entire investment in us in a fully
taxable transaction with an unrelated party. The passive loss
limitations are applied after other applicable limitations on
deductions, including the at-risk rules and the basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
Limitations
on Interest Deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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our interest expense attributed to portfolio income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment or (if applicable)
qualified dividend income. The IRS has indicated that the net
passive income earned by a publicly traded partnership will be
treated as investment income to its unitholders. In addition,
the unitholders share of our portfolio income will be
treated as investment income.
Entity-Level Collections
If we are required or elect under applicable law to pay any
federal, state, local or foreign income tax on behalf of any
unitholder or our general partner or any former unitholder, we
are authorized to pay those taxes from our funds. That payment,
if made, will be treated as a distribution of cash to the
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
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determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units
and to adjust later distributions, so that after giving effect
to these distributions, the priority and characterization of
distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation
of Income, Gain, Loss and Deduction
In general, if we have a net profit, our items of income, gain,
loss and deduction will be allocated among our general partner
and the unitholders in accordance with their percentage
interests in us. At any time that distributions are made to the
common units in excess of distributions to the subordinated
units, or incentive distributions are made to our general
partner, gross income will be allocated to the recipients to the
extent of these distributions. If we have a net loss, that loss
will be allocated first to our general partner and the
unitholders in accordance with their percentage interests in us
to the extent of their positive capital accounts and, second, to
our general partner.
Specified items of our income, gain, loss and deduction will be
allocated to account for (i) any difference between the tax
basis and fair market value of our assets at the time of an
offering and (ii) any difference between the tax basis and
fair market value of any property contributed to us by the
general partner and its affiliates that exists at the time of
such contribution, together, referred to in this discussion as
the Contributed Property. The effect of these
allocations, referred to as Section 704(c) Allocations, to
a unitholder purchasing common units from us in this offering
will be essentially the same as if the tax bases of our assets
were equal to their fair market values at the time of this
offering. In the event we issue additional common units or
engage in certain other transactions in the future,
reverse Section 704(c) Allocations, similar to
the Section 704(c) Allocations described above, will be
made to the general partner and all of our unitholders
immediately prior to such issuance or other transactions to
account for the difference between the book basis
for purposes of maintaining capital accounts and the fair market
value of all property held by us at the time of such issuance or
future transaction. In addition, items of recapture income will
be allocated to the extent possible to the unitholder who was
allocated the deduction giving rise to the treatment of that
gain as recapture income in order to minimize the recognition of
ordinary income by some unitholders. Finally, although we do not
expect that our operations will result in the creation of
negative capital accounts, if negative capital accounts
nevertheless result, items of our income and gain will be
allocated in an amount and manner sufficient to eliminate the
negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction,
other than an allocation required by the Internal Revenue Code
to eliminate the difference between a partners
book capital account, credited with the fair market
value of Contributed Property, and tax capital
account, credited with the tax basis of Contributed Property,
referred to in this discussion as the Book-Tax
Disparity, will generally be given effect for federal
income tax purposes in determining a partners share of an
item of income, gain, loss or deduction only if the allocation
has substantial economic effect. In any other case,
a partners share of an item will be determined on the
basis of his interest in us, which will be determined by taking
into account all the facts and circumstances, including:
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his relative contributions to us;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Andrews Kurth LLP is of the opinion that, with the exception of
the issues described in Section 754
Election and Disposition of Common
Units Allocations Between Transferors and
Transferees, allocations under our partnership agreement
will be given effect for federal income tax purposes in
determining a partners share of an item of income, gain,
loss or deduction.
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Treatment
of Short Sales
A unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of those units. If so, he would no longer be
treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or
loss from the disposition. As a result, during this period:
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any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
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any cash distributions received by the unitholder as to those
units would be fully taxable; and
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all of these distributions would appear to be ordinary income.
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Because there is no direct or indirect controlling authority on
the issue relating to partnership interests, Andrews Kurth LLP
has not rendered an opinion regarding the tax treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units; therefore, unitholders
desiring to assure their status as partners and avoid the risk
of gain recognition from a loan to a short seller are urged to
modify any applicable brokerage account agreements to prohibit
their brokers from borrowing and loaning their units. The IRS
has previously announced that it is studying issues relating to
the tax treatment of short sales of partnership interests.
Please also read Disposition of Common
Units Recognition of Gain or Loss.
Alternative
Minimum Tax
Each unitholder will be required to take into account his
distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The
current minimum tax rate for noncorporate taxpayers is 26% on
the first $175,000 of alternative minimum taxable income in
excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors as to the impact of an
investment in units on their liability for the alternative
minimum tax.
Tax
Rates
Under current law, the highest marginal U.S. federal income
tax rate applicable to ordinary income of individuals is 35% and
the highest marginal U.S. federal income tax rate
applicable to long-term capital gains (generally, capital gains
on certain assets held for more than twelve months) of
individuals is 15%. However, absent new legislation extending
the current rates, beginning January 1, 2013, the highest
marginal U.S. federal income tax rate applicable to
ordinary income and long-term capital gains of individuals will
increase to 39.6% and 20%, respectively. Moreover, these rates
are subject to change by new legislation at any time.
Recently enacted legislation will impose a 3.8% Medicare tax on
certain net investment income earned by individuals, estates and
trusts for taxable years beginning after December 31, 2012.
For these purposes, net investment income generally includes a
unitholders allocable share of our income and gain
realized by a unitholder from a sale of units. In the case of an
individual, the tax will be imposed on the lesser of
(i) the unitholders net investment income or
(ii) the amount by which the unitholders modified
adjusted gross income exceeds $250,000 (if the unitholder is
married and filing jointly or a surviving spouse), $125,000 (if
the unitholder is married and filing separately) or $200,000 (in
any other case). In the case of an estate or trust, the tax will
be imposed on the lesser of (i) undistributed net
investment income, or (ii) the excess adjusted gross income
over the dollar amount at which the highest income tax bracket
applicable to an estate or trust begins.
Section 754
Election
We will make the election permitted by Section 754 of the
Internal Revenue Code. That election is irrevocable without the
consent of the IRS unless there is a constructive termination of
the partnership. Please read Disposition of
Common Units Constructive Termination. The
election will generally permit us to adjust a common unit
purchasers tax basis in our assets, or inside basis, under
Section 743(b) of the Internal
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Revenue Code to reflect his purchase price. This election does
not apply with respect to a person who purchases common units
directly from us. The Section 743(b) adjustment belongs to
the purchaser and not to other unitholders. For purposes of this
discussion, the inside basis in our assets with respect to a
unitholder will be considered to have two components:
(i) his share of our tax basis in our assets, or common
basis, and (ii) his Section 743(b) adjustment to that
basis.
We will adopt the remedial allocation method as to all our
properties. Where the remedial allocation method is adopted, the
Treasury Regulations under Section 743 of the Internal
Revenue Code require a portion of the Section 743(b)
adjustment that is attributable to recovery property that is
subject to depreciation under Section 168 of the Internal
Revenue Code and whose book basis is in excess of its tax basis
to be depreciated over the remaining cost recovery period for
the propertys unamortized Book-Tax Disparity. Under
Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straight-line method or the 150% declining balance
method. Under our partnership agreement, our general partner is
authorized to take a position to preserve the uniformity of
units even if that position is not consistent with these and any
other Treasury Regulations. Please read
Uniformity of Units.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the methods employed by other
publicly traded partnerships but is arguably inconsistent with
Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take a depreciation or amortization position under which
all purchasers acquiring units in the same month would receive
depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our assets. This kind of aggregate approach may result in lower
annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read
Uniformity of Units. A unitholders
tax basis for his common units is reduced by his share of our
deductions (whether or not such deductions were claimed on an
individuals income tax return) so that any position we
take that understates deductions will overstate the common
unitholders basis in his common units, which may cause the
unitholder to understate gain or overstate loss on any sale of
such units. Please read Disposition of Common
Units Recognition of Gain or Loss. Andrews
Kurth LLP is unable to opine as to whether our method for
depreciating Section 743 adjustments is sustainable for
property subject to depreciation under Section 167 of the
Internal Revenue Code or if we use an aggregate approach as
described above, as there is no direct or indirect controlling
authority addressing the validity of these positions. Moreover,
the IRS may challenge our position with respect to depreciating
or amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the units. If such a challenge were
sustained, the gain from the sale of units might be increased
without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation deductions and his share of any
gain or loss on a sale of our assets would be less. Conversely,
a Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial built-in
loss immediately after the transfer, or if we distribute
property and have a substantial basis reduction. Generally a
built-in loss or a basis reduction is substantial if it exceeds
$250,000.
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The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of our assets and other matters. For example, the
allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally nonamortizable or amortizable over a longer period of
time or under a less accelerated method than our tangible
assets. We cannot assure you that the determinations we make
will not be successfully challenged by the IRS and that the
deductions resulting from them will not be reduced or disallowed
altogether. Should the IRS require a different basis adjustment
to be made, and should, in our opinion, the expense of
compliance exceed the benefit of the election, we may seek
permission from the IRS to revoke our Section 754 election.
If permission is granted, a subsequent purchaser of units may be
allocated more income than he would have been allocated had the
election not been revoked.
Tax
Treatment of Operations
Accounting
Method and Taxable Year
We use the year ending December 31 as our taxable year and the
accrual method of accounting for federal income tax purposes.
Each unitholder will be required to include in income his share
of our income, gain, loss and deduction for our taxable year
ending within or with his taxable year. In addition, a
unitholder who has a taxable year ending on a date other than
December 31 and who disposes of all of his units following the
close of our taxable year but before the close of his taxable
year must include his share of our income, gain, loss and
deduction in income for his taxable year, with the result that
he will be required to include in income for his taxable year
his share of more than twelve months of our income, gain, loss
and deduction. Please read Disposition of
Common Units Allocations Between Transferors and
Transferees.
Initial
Tax Basis, Depreciation and Amortization
The tax basis of our assets will be used for purposes of
computing depreciation and cost recovery deductions and,
ultimately, gain or loss on the disposition of these assets. The
federal income tax burden associated with the difference between
the fair market value of our assets and their tax basis
immediately prior to (i) this offering will be borne by our
general partner and its affiliates, and (ii) any other
offering will be borne by our general partner and all of our
unitholders as of that time. Please read Tax
Consequences of Unit Ownership Allocation of Income,
Gain, Loss and Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods, including bonus depreciation to the
extent available, that will result in the largest deductions
being taken in the early years after assets subject to these
allowances are placed in service. Please read
Uniformity of Units. Property we
subsequently acquire or construct may be depreciated using
accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction and
Disposition of Common Units
Recognition of Gain or Loss.
The costs we incur in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts and commissions we incur will be treated
as syndication expenses.
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Valuation
and Tax Basis of Our Properties
The federal income tax consequences of the ownership and
disposition of units will depend in part on our estimates of the
relative fair market values, and the initial tax bases, of our
assets. Although we may from time to time consult with
professional appraisers regarding valuation matters, we will
make many of the relative fair market value estimates ourselves.
These estimates and determinations of basis are subject to
challenge and will not be binding on the IRS or the courts. If
the estimates of fair market value or basis are later found to
be incorrect, the character and amount of items of income, gain,
loss or deductions previously reported by unitholders might
change, and unitholders might be required to adjust their tax
liability for prior years and incur interest and penalties with
respect to those adjustments.
Disposition
of Common Units
Recognition
of Gain or Loss
Gain or loss will be recognized on a sale of units equal to the
difference between the amount realized and the unitholders
tax basis for the units sold. A unitholders amount
realized will be measured by the sum of the cash or the fair
market value of other property received by him plus his share of
our nonrecourse liabilities. Because the amount realized
includes a unitholders share of our nonrecourse
liabilities, the gain recognized on the sale of units could
result in a tax liability in excess of any cash received from
the sale.
Prior distributions from us that in the aggregate were in excess
of cumulative net taxable income for a common unit and,
therefore, decreased a unitholders tax basis in that
common unit will, in effect, become taxable income if the common
unit is sold at a price greater than the unitholders tax
basis in that common unit, even if the price received is less
than his original cost.
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in units, on the sale or
exchange of a unit will generally be taxable as capital gain or
loss. Capital gain recognized by an individual on the sale of
units held for more than twelve months will generally be taxed
at a maximum U.S. federal income tax rate of 15% through
December 31, 2012 and 20% thereafter (absent new
legislation extending or adjusting the current rate). However, a
portion of this gain or loss, which will likely be substantial,
will be separately computed and taxed as ordinary income or loss
under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation
recapture or other unrealized receivables or to
inventory items we own. The term unrealized
receivables includes potential recapture items, including
depreciation recapture. Ordinary income attributable to
unrealized receivables, inventory items and depreciation
recapture may exceed net taxable gain realized upon the sale of
a unit and may be recognized even if there is a net taxable loss
realized on the sale of a unit. Thus, a unitholder may recognize
both ordinary income and a capital loss upon a sale of units.
Capital losses may offset capital gains and no more than $3,000
of ordinary income each year, in the case of individuals, and
may only be used to offset capital gains in the case of
corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling discussed
above, a common unitholder will be unable to select high or low
basis common units to sell as would be the case with corporate
stock, but, according to the Treasury Regulations, he may
designate specific common units sold for purposes of determining
the holding period of units transferred. A unitholder electing
to use the actual holding period of common units transferred
must consistently use that identification method for all
subsequent sales or exchanges of common units. A unitholder
considering the purchase of additional units or a sale of common
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units purchased in separate transactions is urged to consult his
tax advisor as to the possible consequences of this ruling and
application of the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract;
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in each case, with respect to the partnership interest or
substantially identical property.
Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations
Between Transferors and Transferees
In general, our taxable income and losses will be determined
annually, will be prorated on a monthly basis and will be
subsequently apportioned among the unitholders in proportion to
the number of units owned by each of them as of the opening of
the applicable exchange on the first business day of the month,
which we refer to in this prospectus as the Allocation
Date. However, gain or loss realized on a sale or other
disposition of our assets other than in the ordinary course of
business will be allocated among the unitholders on the
Allocation Date in the month in which that gain or loss is
recognized. As a result, a unitholder transferring units may be
allocated income, gain, loss and deduction realized after the
date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations as there is no
direct or indirect controlling authority on this issue.
Recently, however, the Department of the Treasury and the IRS
issued proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax
items must be prorated on a daily basis. Nonetheless, the
proposed regulations do not specifically authorize the use of
the proration method we have adopted. Existing publicly traded
partnerships are entitled to rely on these proposed Treasury
Regulations; however, they are not binding on the IRS and are
subject to change until final Treasury Regulations are issued.
Accordingly, Andrews Kurth LLP is unable to opine on the
validity of this method of allocating income and deductions
between transferor and transferee unitholders because the issue
has not been finally resolved by the IRS or the courts. If this
method is not allowed under the Treasury Regulations, or only
applies to transfers of less than all of the unitholders
interest, our taxable income or losses might be reallocated
among the unitholders. We are authorized to revise our method of
allocation between transferor and transferee unitholders, as
well as unitholders whose interests vary during a taxable year,
to conform to a method permitted under future Treasury
Regulations.
A unitholder who disposes of units prior to the record date set
for a cash distribution for any quarter will be allocated items
of our income, gain, loss and deductions attributable to the
month of sale but will not be entitled to receive that cash
distribution.
Notification
Requirements
A unitholder who sells any of his units is generally required to
notify us in writing of that sale within 30 days after the
sale (or, if earlier, January 15 of the year following the
sale). A purchaser of units who purchases units from another
unitholder is also generally required to notify us in writing of
that purchase
192
within 30 days after the purchase. Upon receiving such
notifications, we are required to notify the IRS of that
transaction and to furnish specified information to the
transferor and transferee. Failure to notify us of a purchase
may, in some cases, lead to the imposition of penalties.
However, these reporting requirements do not apply to a sale by
an individual who is a citizen of the U.S. and who effects
the sale or exchange through a broker who will satisfy such
requirements.
Constructive
Termination
We will be considered to have terminated our tax partnership for
federal income tax purposes upon the sale or exchange of our
interests that, in the aggregate, constitute 50% or more of the
total interests in our capital and profits within a twelve-month
period. For purposes of measuring whether the 50% threshold is
reached, multiple sales of the same interest are counted only
once. A constructive termination results in the closing of our
taxable year for all unitholders. In the case of a unitholder
reporting on a taxable year other than a fiscal year ending
December 31, the closing of our taxable year may result in
more than twelve months of our taxable income or loss being
includable in his taxable income for the year of termination. A
constructive termination occurring on a date other than December
31 will result in us filing two tax returns (and unitholders
could receive two Schedules K-1 if the relief discussed below is
not available) for one fiscal year and the cost of the
preparation of these returns will be borne by all common
unitholders. We would be required to make new tax elections
after a termination, including a new election under
Section 754 of the Internal Revenue Code, and a termination
would result in a deferral of our deductions for depreciation. A
termination could also result in penalties if we were unable to
determine that the termination had occurred. Moreover, a
termination might either accelerate the application of, or
subject us to, any tax legislation enacted before the
termination. The IRS has recently announced a relief procedure
whereby if a publicly traded partnership that has technically
terminated requests publicly traded partnership technical
termination relief and the IRS grants such relief, among other
things, the partnership will only have to provide one
Schedule K-1
to unitholders for the year notwithstanding two partnership tax
years.
Uniformity
of Units
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury Regulation
Section 1.167(c)-1(a)(6).
Any
non-uniformity
could have a negative impact on the value of the units. Please
read Tax Consequences of Unit
Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property the common basis of which is not
amortizable, consistent with the regulations under
Section 743 of the Internal Revenue Code, even though that
position may be inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. Please read Tax Consequences of
Unit Ownership Section 754 Election. To
the extent that the Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may adopt a depreciation and amortization position under
which all purchasers acquiring units in the same month would
receive depreciation and amortization deductions, whether
attributable to common basis or a Section 743(b)
adjustment, based upon the same applicable rate as if they had
purchased a direct interest in our assets. If this position is
adopted, it may result in lower annual depreciation and
amortization deductions than would otherwise be allowable to
some unitholders and risk the loss of depreciation and
amortization deductions not taken in the year that these
deductions are otherwise allowable. This position will not be
adopted if we determine that the loss of depreciation and
amortization deductions will have a material adverse effect on
the unitholders. If we choose not to utilize this aggregate
method, we may use any other reasonable depreciation and
amortization method
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to preserve the uniformity of the intrinsic tax characteristics
of any units that would not have a material adverse effect on
the unitholders. In either case, and as stated above under
Tax Consequences of Unit Ownership
Section 754 Election, Andrews Kurth LLP has not
rendered an opinion with respect to these methods. Moreover, the
IRS may challenge any method of depreciating the
Section 743(b) adjustment described in this paragraph. If
this challenge were sustained, the uniformity of units might be
affected, and the gain from the sale of units might be increased
without the benefit of additional deductions. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Tax-Exempt
Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations and
other foreign persons raises issues unique to those investors
and, as described below to a limited extent, may have
substantially adverse tax consequences to them. If you are a
tax-exempt entity or a
non-U.S. person,
you should consult your tax advisor before investing in our
common units.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable
to it.
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the U.S. because of the ownership of units. As a
consequence, they will be required to file federal tax returns
to report their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on their share of our
net income or gain. Moreover, under rules applicable to publicly
traded partnerships, we will withhold at the highest applicable
effective tax rate from cash distributions made quarterly to
foreign unitholders. Each foreign unitholder must obtain a
taxpayer identification number from the IRS and submit that
number to our transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns units will
be treated as engaged in a U.S. trade or business, that
corporation may be subject to the U.S. branch profits tax
at a rate of 30%, in addition to regular federal income tax, on
its share of our income and gain, as adjusted for changes in the
foreign corporations U.S. net equity,
which is effectively connected with the conduct of a
U.S. trade or business. That tax may be reduced or
eliminated by an income tax treaty between the U.S. and the
country in which the foreign corporate unitholder is a
qualified resident. In addition, this type of
unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue
Code.
A foreign unitholder who sells or otherwise disposes of a common
unit will be subject to U.S. federal income tax on gain
realized from the sale or disposition of that unit to the extent
the gain is effectively connected with a U.S. trade or
business of the foreign unitholder. Under a ruling published by
the IRS, interpreting the scope of effectively connected
income, a foreign unitholder would be considered to be
engaged in a trade or business in the U.S. by virtue of the
U.S. activities of the partnership, and part or all of that
unitholders gain would be effectively connected with that
unitholders indirect U.S. trade or business.
Moreover, under the Foreign Investment in Real Property Tax Act,
a foreign common unitholder generally will be subject to
U.S. federal income tax upon the sale or disposition of a
common unit if (i) he owned (directly or constructively
applying certain attribution rules) more than 5% of our common
units at any time during the five-year period ending on the date
of such disposition and (ii) 50% or more of the fair market
value of all of our assets consisted of U.S. real property
interests at any time during the shorter of the period during
which such unitholder held the common units or the five-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to federal income
tax on gain from the sale or disposition of their units.
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Administrative
Matters
Information
Returns and Audit Procedures
We intend to furnish to each unitholder, within 90 days
after the close of each calendar year, specific tax information,
including a
Schedule K-1,
which describes his share of our income, gain, loss and
deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take
various accounting and reporting positions, some of which have
been mentioned earlier, to determine each unitholders
share of income, gain, loss and deduction. We cannot assure you
that those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations
or administrative interpretations of the IRS. Neither we nor
Andrews Kurth LLP can assure prospective unitholders that the
IRS will not successfully contend in court that those positions
are impermissible. Any challenge by the IRS could negatively
affect the value of the units.
The IRS may audit our federal income tax information returns.
Adjustments resulting from an IRS audit may require each
unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. Our partnership agreement names American Midstream GP
as our Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on
our behalf and on behalf of unitholders. In addition, the Tax
Matters Partner can extend the statute of limitations for
assessment of tax deficiencies against unitholders for items in
our returns. The Tax Matters Partner may bind a unitholder with
less than a 1% profits interest in us to a settlement with the
IRS unless that unitholder elects, by filing a statement with
the IRS, not to give that authority to the Tax Matters Partner.
The Tax Matters Partner may seek judicial review, by which all
the unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee
Reporting
Persons who hold an interest in us as a nominee for another
person are required to furnish to us:
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the name, address and taxpayer identification number of the
beneficial owner and the nominee;
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whether the beneficial owner is:
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a person that is not a U.S. person;
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a foreign government, an international organization or any
wholly owned agency or instrumentality of either of the
foregoing; or
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a tax-exempt entity;
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the amount and description of units held, acquired or
transferred for the beneficial owner; and
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specific information including the dates of acquisitions and
transfers, means of acquisitions and transfers, and acquisition
cost for purchases, as well as the amount of net proceeds from
sales.
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Brokers and financial institutions are required to furnish
additional information, including whether they are
U.S. persons and specific information on units they
acquire, hold or transfer for their own account. A penalty of
$100 per failure, up to a maximum of $1.5 million per
calendar year, is imposed by the Internal Revenue Code for
failure to report that information to us. The nominee is
required to supply the beneficial owner of the units with the
information furnished to us.
Accuracy-Related
Penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to
penalty generally is reduced if any portion is attributable to a
position adopted on the return:
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for which there is, or was, substantial
authority; or
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as to which there is a reasonable basis and the pertinent facts
of that position are disclosed on the return.
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If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes
us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the adjusted basis of any property,
claimed on a tax return is 150% or more of the amount determined
to be the correct amount of the valuation or adjusted basis,
(b) the price for any property or services (or for the use
of property) claimed on any such return with respect to any
transaction between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts.
No penalty is imposed unless the portion of the underpayment
attributable to a substantial valuation misstatement exceeds
$5,000 ($10,000 for most corporations). If the valuation claimed
on a return is 200% or more than the correct valuation or
certain other thresholds are met, the penalty imposed increases
to 40%. We do not anticipate making any valuation misstatements.
In addition, the 20% accuracy-related penalty also applies to
any portion of an underpayment of tax that is attributable to
transactions lacking economic substance. To the extent that such
transactions are not disclosed, the penalty imposed is increased
to 40%. Additionally, there is no reasonable cause defense to
the imposition of this penalty to such transactions.
Reportable
Transactions
If we were to engage in a reportable transaction, we
(and possibly you and others) would be required to make a
detailed disclosure of the transaction to the IRS. A transaction
may be a reportable transaction based upon any of several
factors, including the fact that it is a type of tax avoidance
transaction publicly identified by the IRS as a listed
transaction or that it produces certain kinds of losses
for partnerships, individuals, S corporations, and trusts
in excess of $2 million in any single year, or
$4 million in any combination of 6 successive tax years.
Our participation in a reportable transaction could increase the
likelihood that our federal income tax information return (and
possibly your tax return) would be audited by the IRS. Please
read Information Returns and Audit
Procedures.
196
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following
provisions of the American Jobs Creation Act of 2004:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related
Penalties;
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for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
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in the case of a listed transaction, an extended statute of
limitations.
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We do not expect to engage in any reportable
transactions.
Recent
Legislative Developments
The present federal income tax treatment of publicly traded
partnerships, including us, or an investment in our common units
may be modified by administrative, legislative or judicial
interpretation at any time. For example, in the last session of
Congress, the U.S. House of Representatives passed
legislation that would provide for substantive changes to the
definition of qualifying income and the treatment of certain
types of income earned from profits interests in partnerships.
It is possible that these legislative efforts could result in
changes to the existing federal income tax laws that affect
publicly traded partnerships. As previously proposed, we do not
believe any such legislation would affect our tax treatment as a
partnership. However, the proposed legislation could be modified
in a way that could affect us. We are unable to predict whether
any of these changes, or other proposals, will ultimately be
enacted. Any such changes could negatively impact the value of
an investment in our units.
State,
Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject
to other taxes, such as state, local and foreign income taxes,
unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property or in
which you are a resident. We currently do business or own
property in several states, most of which impose personal income
taxes on individuals. Most of these states also impose an income
tax on corporations and other entities. Moreover, we may also
own property or do business in other states in the future that
impose income or similar taxes on nonresident individuals.
Although an analysis of those various taxes is not presented
here, each prospective unitholder should consider their
potential impact on his investment in us. A unitholder may be
required to file income tax returns and to pay income taxes in
many of these jurisdictions in which we do business or own
property and may be subject to penalties for failure to comply
with those requirements. In some jurisdictions, tax losses may
not produce a tax benefit in the year incurred and may not be
available to offset income in subsequent taxable years. Some of
the jurisdictions may require us, or we may elect, to withhold a
percentage of income from amounts to be distributed to a
unitholder who is not a resident of the jurisdiction.
Withholding, the amount of which may be greater or less than a
particular unitholders income tax liability to the
jurisdiction, generally does not relieve a nonresident
unitholder from the obligation to file an income tax return.
Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax Consequences of Unit
Ownership Entity-Level Collections. Based
on current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate
the legal and tax consequences, under the laws of pertinent
jurisdictions, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend upon, his
tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state, local and foreign, as well as U.S. federal tax
returns, that may be required of him. Andrews Kurth LLP has not
rendered an opinion on the state, local or foreign tax
consequences of an investment in us.
197
INVESTMENT
IN AMERICAN MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT
PLANS
An investment in us by an employee benefit plan is subject to
additional considerations because the investments of these plans
are subject to the fiduciary responsibility and prohibited
transaction provisions of ERISA and the restrictions imposed by
Section 4975 of the Internal Revenue Code and provisions
under any federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Internal Revenue Code or ERISA, collectively, Similar
Laws. For these purposes the term employee benefit
plan includes, but is not limited to, qualified pension,
profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and tax deferred annuities or IRAs or
annuities established or maintained by an employer or employee
organization, and entities whose underlying assets are
considered to include plan assets of such plans,
accounts and arrangements, collectively, Employee Benefit
Plans. Among other things, consideration should be given
to:
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whether the investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws;
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whether in making the investment, the plan will satisfy the
diversification requirements of Section 404(a)(1)(C) of
ERISA and any other applicable Similar Laws;
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whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential
after-tax investment return. Please read Material Federal
Income Tax Consequences Tax-Exempt Organizations and
Other Investors; and
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whether making such an investment will comply with the
delegation of control and prohibited transaction provisions of
ERISA, the Internal Revenue Code and any other applicable
Similar Laws.
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The person with investment discretion with respect to the assets
of an Employee Benefit Plan, often called a fiduciary, should
determine whether an investment in us is authorized by the
appropriate governing instrument and is a proper investment for
the plan.
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit Employee Benefit Plans from engaging,
either directly or indirectly, in specified transactions
involving plan assets with parties that, with
respect to the Employee Benefit Plan, are parties in
interest under ERISA or disqualified persons
under the Internal Revenue Code unless an exemption is
available. A party in interest or disqualified person who
engages in a non-exempt prohibited transaction may be subject to
excise taxes and other penalties and liabilities under ERISA and
the Internal Revenue Code. In addition, the fiduciary of the
ERISA plan that engaged in such a non-exempt prohibited
transaction may be subject to penalties and liabilities under
ERISA and the Internal Revenue Code.
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary should consider whether
the Employee Benefit Plan will, by investing in us, be deemed to
own an undivided interest in our assets, with the result that
our general partner would also be a fiduciary of such Employee
Benefit Plan and our operations would be subject to the
regulatory restrictions of ERISA, including its prohibited
transaction rules, as well as the prohibited transaction rules
of the Internal Revenue Code, ERISA and any other applicable
Similar Laws.
The Department of Labor regulations and Section 3(42) of
ERISA provide guidance with respect to whether, in certain
circumstances, the assets of an entity in which Employee Benefit
Plans acquire equity interests would be deemed plan
assets. Under these rules, an entitys assets would
not be considered to be plan assets if, among other
things:
(a) the equity interests acquired by the Employee Benefit
Plan are publicly offered securities i.e., the
equity interests are widely held by 100 or more investors
independent of the issuer and each other, are freely
transferable and are registered under certain provisions of the
federal securities laws;
(b) the entity is an operating
company, i.e., it is primarily engaged in the
production or sale of a product or service, other than the
investment of capital, either directly or through a
majority-owned subsidiary or subsidiaries; or
198
(c) there is no significant investment by benefit
plan investors, which is defined to mean that less than
25% of the value of each class of equity interest, disregarding
any such interests held by our general partner, its affiliates
and some other persons, is held generally by Employee Benefit
Plans.
Our assets should not be considered plan assets
under these regulations because it is expected that the
investment will satisfy the requirements in (a) and
(b) above.
In light of the serious penalties imposed on persons who engage
in prohibited transactions or other violations, plan fiduciaries
contemplating a purchase of common units should consult with
their own counsel regarding the consequences under ERISA, the
Internal Revenue Code and other Similar Laws.
199
UNDERWRITING
Citigroup Global Markets Inc. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated are acting as joint
book-running managers of the offering and as representatives of
the underwriters named below. Subject to the terms and
conditions stated in the underwriting agreement dated the date
of this prospectus, each underwriter named below has severally
agreed to purchase, and we have agreed to sell to that
underwriter, the number of common units set forth opposite the
underwriters name.
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Number of
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Common
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Underwriter
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Units
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Citigroup Global Markets Inc.
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Merrill Lynch, Pierce, Fenner & Smith
Incorporated
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Total
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The underwriting agreement provides that the obligations of the
underwriters to purchase the common units included in this
offering are subject to approval of legal matters by counsel and
to other conditions. The underwriters are obligated to purchase
all the common units (other than those covered by the
over-allotment option described below) if they purchase any of
the common units.
Common units sold by the underwriters to the public will
initially be offered at the initial public offering price set
forth on the cover of this prospectus. Any common units sold by
the underwriters to securities dealers may be sold at a discount
from the initial public offering price not to exceed
$ per common unit. If all the
common units are not sold at the initial offering price, the
underwriters may change the offering price and the other selling
terms. The representatives have advised us that the underwriters
do not intend to make sales to discretionary accounts.
If the underwriters sell more common units than the total number
set forth in the table above, we have granted to the
underwriters an option, exercisable for 30 days from the
date of this prospectus, to purchase up
to
additional common units at the public offering price less
underwriting discounts and commissions, and the structuring fee.
The underwriters may exercise the option solely for the purpose
of covering over-allotments, if any, in connection with this
offering. To the extent the option is exercised, each
underwriter must purchase a number of additional common units
approximately proportionate to that underwriters initial
purchase commitment. Any common units issued or sold under the
option will be issued and sold on the same terms and conditions
as the other common units that are the subject of this offering.
We, our officers and directors, and our other unitholders,
including our general partner and AIM Midstream Holdings and its
affiliates, have agreed that, for a period of 180 days from
the date of this prospectus, we and they will not, without the
prior written consent of Citigroup Global Markets Inc. and
Merrill Lynch, Pierce, Fenner & Smith Incorporated,
dispose of or hedge any common units or any securities
convertible into or exchangeable for our common stock. Citigroup
Global Markets Inc. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated in their sole discretion
may release any of the securities subject to these
lock-up
agreements at any time without notice. Notwithstanding the
foregoing, if (i) during the last 17 days of the
180-day
restricted period, we issue an earnings release or material news
or a material event relating to our partnership occurs; or
(ii) prior to the expiration of the
180-day
restricted period, we announce that we will release earnings
results during the
16-day
period beginning on the last day of the
180-day
restricted period, the restrictions described above shall
continue to apply until the expiration of the
18-day
period beginning on the issuance of the earnings release or the
occurrence of the material news or material event.
Prior to this offering, there has been no public market for our
common units. Consequently, the initial public offering price
for the common units was determined by negotiations among us and
the representatives. Among the factors considered in determining
the initial public offering price were our results of
operations, our current financial condition, our future
prospects, our markets, the economic conditions in and future
prospects for the industry in which we compete, our management,
and currently prevailing general conditions in the equity
securities markets, including current market valuations of
publicly traded companies considered
200
comparable to our partnership. We cannot assure you, however,
that the price at which the common units will sell in the public
market after this offering will not be lower than the initial
public offering price or that an active trading market in our
common units will develop and continue after this offering.
We intend to apply to have our common units listed on the Nasdaq
Global Market under the symbol
.
The following table shows the underwriting discounts,
commissions and the structuring fee that we are to pay to the
underwriters in connection with this offering. These amounts are
shown assuming both no exercise and full exercise of the
underwriters over-allotment option.
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Paid by American Midstream Partners, LP(1)
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No Exercise
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Full Exercise
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Per common unit
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$
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$
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$
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$
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Excludes a structuring fee of
$ million, or
$ million if the underwriters
exercise their over-allotment option in full, payable by us to
Citigroup Global Markets, Inc. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated. |
We will pay a structuring fee equal
to % of the gross proceeds of this
offering, including the gross proceeds from any exercise of the
underwriters over-allotment option, to Citigroup Global
Markets Inc. and Merrill, Lynch, Pierce, Fenner &
Smith Incorporated. This structuring fee will compensate
Citigroup Global Markets Inc. and Merrill, Lynch, Pierce,
Fenner & Smith Incorporated for providing advice
regarding the capital structure of our partnership, the terms of
the offering, the terms of our partnership agreement and the
terms of certain other agreements between us and our affiliates.
We estimate that our total expenses for this offering will be $.
In connection with the offering, the underwriters may purchase
and sell common units in the open market. Purchases and sales in
the open market may include short sales, purchases to cover
short positions, which may include purchases pursuant to the
over-allotment option, and stabilizing purchases.
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Short sales involve secondary market sales by the underwriters
of a greater number of common units than they are required to
purchase in the offering.
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Covered short sales are sales of
common units in an amount up to the number of common units
represented by the underwriters over-allotment option.
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Naked short sales are sales of common
units in an amount in excess of the number of common units
represented by the underwriters over-allotment option.
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Covering transactions involve purchases of common units either
pursuant to the over-allotment option or in the open market
after the distribution has been completed in order to cover
short positions.
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To close a naked short position, the underwriters must purchase
common units in the open market after the distribution has been
completed. A naked short position is more likely to be created
if the underwriters are concerned that there may be downward
pressure on the price of the common units in the open market
after pricing that could adversely affect investors who purchase
in the offering.
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To close a covered short position, the underwriters must
purchase common units in the open market after the distribution
has been completed or must exercise the over-allotment option.
In determining the source of common units to close the covered
short position, the underwriters will consider, among other
things, the price of common units available for purchase in the
open market as compared to the price at which they may purchase
common units through the over-allotment option.
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Stabilizing transactions involve bids to purchase common units
so long as the stabilizing bids do not exceed a specified
maximum.
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201
Purchases to cover short positions and stabilizing purchases, as
well as other purchases by the underwriters for their own
accounts, may have the effect of preventing or retarding a
decline in the market price of the common units. They may also
cause the price of the common units to be higher than the price
that would otherwise exist in the open market in the absence of
these transactions. The underwriters may conduct these
transactions on the Nasdaq Global Market, in the
over-the-counter
market or otherwise. If the underwriters commence any of these
transactions, they may discontinue them at any time.
The underwriters have performed commercial banking, investment
banking and advisory services for us from time to time for which
they have received customary fees and reimbursement of expenses.
The underwriters may, from time to time, engage in transactions
with and perform services for us in the ordinary course of their
business for which they may receive customary fees and
reimbursement of expenses.
We have agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act, or
to contribute to payments the underwriters may be required to
make because of any of those liabilities.
Notice to
Prospective Investors in the European Economic Area
In relation to each member state of the European Economic Area
that has implemented the Prospectus Directive (each, a relevant
member state), with effect from and including the date on which
the Prospectus Directive is implemented in that relevant member
state (the relevant implementation date), an offer of securities
described in this prospectus may not be made to the public in
that relevant member state other than:
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to any legal entity that is authorized or regulated to operate
in the financial markets or, if not so authorized or regulated,
whose corporate purpose is solely to invest in securities;
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to any legal entity that has two or more of (1) an average
of at least 250 employees during the last financial year;
(2) a total balance sheet of more than 43,000,000 and
(3) an annual net turnover of more than 50,000,000,
as shown in its last annual or consolidated accounts;
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to fewer than 100 natural or legal persons (other than qualified
investors as defined in the Prospectus Directive) subject to
obtaining the prior consent of the representatives; or
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in any other circumstances that do not require the publication
of a prospectus pursuant to Article 3 of the Prospectus
Directive, provided that no such offer of securities shall
require us or any underwriter to publish a prospectus pursuant
to Article 3 of the Prospectus Directive.
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For purposes of this provision, the expression an offer of
securities to the public in any relevant member state
means the communication in any form and by any means of
sufficient information on the terms of the offer and the
securities to be offered so as to enable an investor to decide
to purchase or subscribe for the securities, as the expression
may be varied in that member state by any measure implementing
the Prospectus Directive in that member state, and the
expression Prospectus Directive means Directive
2003/71/EC and includes any relevant implementing measure in
each relevant member state.
We have not authorized and do not authorize the making of any
offer of securities through any financial intermediary on their
behalf, other than offers made by the underwriters with a view
to the final placement of the securities as contemplated in this
prospectus. Accordingly, no purchaser of the securities, other
than the underwriters, is authorized to make any further offer
of the securities on behalf of us or the underwriters.
Notice to
Prospective Investors in the United Kingdom
Our partnership may constitute a collective investment
scheme as defined by section 235 of the Financial
Services and Markets Act 2000, or FSMA, that is not a
recognised collective investment scheme for the
purposes of FSMA, or CIS, and that has not been authorised or
otherwise approved. As an unregulated
202
scheme, it cannot be marketed in the United Kingdom to the
general public, except in accordance with FSMA. This prospectus
is only being distributed in the United Kingdom to, and are only
directed at:
(i) if our partnership is a CIS and is marketed by a person
who is an authorised person under FSMA, (a) investment
professionals falling within Article 14(5) of the Financial
Services and Markets Act 2000 (Promotion of Collective
Investment Schemes) Order 2001, as amended (the CIS
Promotion Order) or (b) high net worth companies and
other persons falling with Article 22(2)(a) to (d) of
the CIS Promotion Order; or
(ii) otherwise, if marketed by a person who is not an
authorised person under FSMA, (a) persons who fall within
Article 19(5) of the Financial Services and Markets Act
2000 (Financial Promotion) Order 2005, as amended (the
Financial Promotion Order) or
(b) Article 49(2)(a) to (d) of the Financial
Promotion Order; and
(iii) in both cases (i) and (ii) to any other
person to whom it may otherwise lawfully be made, (all such
persons together being referred to as relevant
persons). Our partnerships common units are only
available to, and any invitation, offer or agreement to
subscribe, purchase or otherwise acquire such common units will
be engaged in only with, relevant persons. Any person who is not
a relevant person should not act or rely on this document or any
of its contents.
An invitation or inducement to engage in investment activity
(within the meaning of Section 21 of FSMA) in connection
with the issue or sale of any common units which are the subject
of the offering contemplated by this prospectus will only be
communicated or caused to be communicated in circumstances in
which Section 21(1) of FSMA does not apply to our
partnership.
Notice to
Prospective Investors in Germany
This prospectus has not been prepared in accordance with the
requirements for a securities or sales prospectus under the
German Securities Prospectus Act
(Wertpapierprospektgesetz), the German Sales Prospectus
Act (Verkaufsprospektgesetz), or the German Investment
Act (Investmentgesetz). Neither the German Federal
Financial Services Supervisory Authority (Bundesanstalt
für Finanzdienstleistungsaufsicht-BaFin) nor any other
German authority has been notified of the intention to
distribute our common units in Germany. Consequently, our common
units may not be distributed in Germany by way of public
offering, public advertisement or in any similar manner and this
prospectus and any other document relating to this offering, as
well as information or statements contained therein, may not be
supplied to the public in Germany or used in connection with any
offer for subscription of the common units to the public in
Germany or any other means of public marketing. Our common units
are being offered and sold in Germany only to qualified
investors which are referred to in Section 3,
paragraph 2 no. 1, in connection with Section 2,
no. 6, of the German Securities Prospectus Act,
Section 8f paragraph 2 no. 4 of the German Sales
Prospectus Act, and in Section 2 paragraph 11 sentence
2 no. 1 of the German Investment Act. This prospectus is
strictly for use of the person who has received it. It may not
be forwarded to other persons or published in Germany.
This offering of our common units does not constitute an offer
to buy or the solicitation or an offer to sell our common units
in any circumstances in which such offer or solicitation is
unlawful.
Notice to
Prospective Investors in the Netherlands
Our common units may not be offered or sold, directly or
indirectly, in the Netherlands, other than to qualified
investors (gekwalificeerde beleggers) within the meaning
of Article 1:1 of the Dutch Financial Supervision Act
(Wet op het financieel toezicht).
Notice to
Prospective Investors in Switzerland
This prospectus is being communicated in Switzerland to a small
number of selected investors only. Each copy of this prospectus
is addressed to a specifically named recipient and may not be
copied, reproduced, distributed or passed on to third parties.
Our common units are not being offered to the public in
Switzerland,
203
and neither this prospectus, nor any other offering materials
relating to our common units may be distributed in connection
with any such public offering.
We have not been registered with the Swiss Financial Market
Supervisory Authority FINMA as a foreign collective investment
scheme pursuant to Article 120 of the Collective Investment
Schemes Act of June 23, 2006, or CISA. Accordingly, our
common units may not be offered to the public in or from
Switzerland, and neither this prospectus, nor any other offering
materials relating to our common units may be made available
through a public offering in or from Switzerland. Our common
units may only be offered and this prospectus may only be
distributed in or from Switzerland by way of private placement
exclusively to qualified investors (as this term is defined in
the CISA and its implementing ordinance).
204
VALIDITY
OF THE COMMON UNITS
The validity of the common units offered hereby will be passed
upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal
matters in connection with the common units offered hereby will
be passed upon for the underwriters by Latham &
Watkins LLP, Houston, Texas.
EXPERTS
The consolidated financial statements of American Midstream
Partners, LP and subsidiaries as of and for the year ended
December 31, 2010 and as of December 31, 2009 and for
the period from August 20, 2009 to December 31, 2009
included in this prospectus have been so included in reliance on
the report of PricewaterhouseCoopers LLP, an independent
registered public accounting firm, given on the authority of
said firm as experts in accounting and auditing.
The combined financial statements of American Midstream Partners
Predecessor as of October 31, 2009 and for the
ten-month
period ended October 31, 2009 and as of and for the year
ended December 31, 2008 included in this prospectus have
been so included in reliance on the report of
PricewaterhouseCoopers LLP, an independent registered public
accounting firm, given on the authority of said firm as experts
in accounting and auditing.
WHERE YOU
CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on
Form S-1
regarding the common units. This prospectus does not contain all
of the information found in the registration statement. For
further information regarding us and the common units offered in
this prospectus, you may desire to review the full registration
statement, including the exhibits. The registration statement,
including the exhibits, may be inspected and copied at the
public reference facilities maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. Copies of this material can also be
obtained upon written request from the Public Reference Section
of the SEC at 100 F Street, N.E., Room 1580,
Washington, D.C. 20549 at prescribed rates or from the
SECs web site on the Internet at
http://www.sec.gov.
Please call the SEC at
1-800-SEC-0330
for further information on public reference rooms.
As a result of the offering, we will file with or furnish to the
SEC periodic reports and other information. These reports and
other information may be inspected and copied at the public
reference facilities maintained by the SEC or obtained from the
SECs website as provided above. Our website is located at
http://www. .com,
and we expect to make our periodic reports and other information
filed with or furnished to the SEC available, free of charge,
through our website, as soon as reasonably practicable after
those reports and other information are electronically filed
with or furnished to the SEC. Information on our website or any
other website is not incorporated by reference into this
prospectus and does not constitute a part of this prospectus.
We intend to furnish or make available to our unitholders annual
reports containing our audited financial statements prepared in
accordance with GAAP. Our annual report will contain a detailed
statement of any transactions with our general partner or its
affiliates, and of fees, commissions, compensation and other
benefits paid, or accrued to our general partner or its
affiliates for the fiscal year completed, showing the amount
paid or accrued to each recipient and the services performed. We
also intend to furnish or make available to our unitholders
quarterly reports containing our unaudited interim financial
information, including the information required by
Form 10-Q,
for the first three fiscal quarters of each fiscal year.
FORWARD-LOOKING
STATEMENTS
Some of the information in this prospectus may contain
forward-looking statements. These statements can be identified
by the use of forward-looking terminology including
will, may, believe,
expect, anticipate,
estimate, continue, or other similar
words. These statements discuss future expectations, contain
projections of financial condition or of results of operations,
or state other forward-looking information. These
forward-looking statements involve risks and uncertainties. When
considering these forward-looking statements, you should keep in
mind the risk factors and other cautionary statements in this
prospectus. The risk factors and other factors noted throughout
this prospectus could cause our actual results to differ
materially from those contained in any forward-looking statement.
205
Report of
Independent Registered Public Accounting Firm
To the Board of Directors of the General Partner of
American Midstream Partners, LP
We have audited the accompanying consolidated balance sheets of
American Midstream Partners, LP and its subsidiaries as of
December 31, 2009 and 2010, and the related consolidated
statements of operations, of changes in partners capital
and of cash flows for the period from August 20, 2009
(inception date) to December 31, 2009 and year ended
December 31, 2010. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of American Midstream Partners, LP and its subsidiaries
at December 31, 2009 and 2010, and the results of their
operations and their cash flows for the period from
August 20, 2009 (inception date) to December 31, 2009
and year ended December 31, 2010 in conformity with
accounting principles generally accepted in the United States of
America.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
March 30, 2011
F-2
American
Midstream Partners, LP and Subsidiaries
December 31,
2009 and 2010
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,149
|
|
|
$
|
63
|
|
Accounts receivable, net
|
|
|
1,447
|
|
|
|
656
|
|
Unbilled revenue
|
|
|
18,329
|
|
|
|
22,194
|
|
Other current assets
|
|
|
1,523
|
|
|
|
1,523
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
22,448
|
|
|
|
24,436
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
149,266
|
|
|
|
146,808
|
|
Other assets
|
|
|
2,679
|
|
|
|
1,985
|
|
Risk management assets
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
174,470
|
|
|
$
|
173,229
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Partners Capital
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
1,934
|
|
|
$
|
980
|
|
Accrued gas purchases
|
|
|
14,881
|
|
|
|
18,706
|
|
Current portion of long-term debt
|
|
|
5,000
|
|
|
|
6,000
|
|
Other loans
|
|
|
815
|
|
|
|
615
|
|
Accrued expenses and other current liabilities
|
|
|
2,237
|
|
|
|
2,676
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
24,867
|
|
|
|
28,977
|
|
Other liabilities
|
|
|
399
|
|
|
|
8,078
|
|
Long-term debt
|
|
|
56,000
|
|
|
|
50,370
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
81,266
|
|
|
|
87,425
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (see Note 16)
|
|
|
|
|
|
|
|
|
Partners capital
|
|
|
|
|
|
|
|
|
General partner interest
|
|
|
2,010
|
|
|
|
2,124
|
|
Limited partner interest
|
|
|
91,148
|
|
|
|
83,624
|
|
Accumulated other comprehensive income
|
|
|
46
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
93,204
|
|
|
|
85,804
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners equity
|
|
$
|
174,470
|
|
|
$
|
173,229
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-3
American
Midstream Partners, LP and Subsidiaries
Period from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
August 20,
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
(Inception Date)
|
|
|
|
|
|
|
to
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Total revenue
|
|
$
|
32,833
|
|
|
$
|
211,940
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
26,593
|
|
|
|
173,821
|
|
Direct operating expenses
|
|
|
1,594
|
|
|
|
12,187
|
|
Selling, general and administrative expenses
|
|
|
1,346
|
|
|
|
8,854
|
|
One-time transaction costs
|
|
|
6,404
|
|
|
|
303
|
|
Depreciation expense
|
|
|
2,978
|
|
|
|
20,013
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
38,915
|
|
|
|
215,178
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(6,082
|
)
|
|
|
(3,238
|
)
|
Other expenses (income):
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
910
|
|
|
|
5,406
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(6,992
|
)
|
|
$
|
(8,644
|
)
|
|
|
|
|
|
|
|
|
|
General partners interest in net income (loss)
|
|
|
(140
|
)
|
|
|
(173
|
)
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income (loss)
|
|
$
|
(6,852
|
)
|
|
$
|
(8,471
|
)
|
|
|
|
|
|
|
|
|
|
Limited partners net income (loss) per common unit
(Note 19)
|
|
$
|
(1.52
|
)
|
|
$
|
(.81
|
)
|
|
|
|
|
|
|
|
|
|
Weighted average number of common units used in computation of
limited partners net income (loss) per common unit
|
|
|
4,507
|
|
|
|
10,506
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
December 31, 2009 and Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
Limited
|
|
|
General
|
|
|
Other
|
|
|
|
|
|
|
Partner
|
|
|
Partner
|
|
|
Comprehensive
|
|
|
|
|
|
|
Interest
|
|
|
Interest
|
|
|
Income
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
Balances at August 20, 2009 (Inception Date)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions by partners
|
|
|
98,000
|
|
|
|
2,000
|
|
|
|
|
|
|
|
100,000
|
|
Net loss
|
|
|
(6,852
|
)
|
|
|
(140
|
)
|
|
|
|
|
|
|
(6,992
|
)
|
Unit based compensation
|
|
|
|
|
|
|
150
|
|
|
|
|
|
|
|
150
|
|
Adjustments to other post retirement benefit plan assets and
liabilities
|
|
|
|
|
|
|
|
|
|
|
46
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009
|
|
|
91,148
|
|
|
|
2,010
|
|
|
|
46
|
|
|
|
93,204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions by partners
|
|
|
11,760
|
|
|
|
240
|
|
|
|
|
|
|
|
12,000
|
|
Net loss
|
|
|
(8,471
|
)
|
|
|
(173
|
)
|
|
|
|
|
|
|
(8,644
|
)
|
Unitholder distributions
|
|
|
(11,545
|
)
|
|
|
(234
|
)
|
|
|
|
|
|
|
(11,779
|
)
|
LTIP vesting
|
|
|
903
|
|
|
|
(903
|
)
|
|
|
|
|
|
|
|
|
Tax netting repurchase
|
|
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
(171
|
)
|
Unit based compensation
|
|
|
|
|
|
|
1,184
|
|
|
|
|
|
|
|
1,184
|
|
Adjustments to other post retirement benefit plan assets and
liabilities
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2010
|
|
$
|
83,624
|
|
|
$
|
2,124
|
|
|
$
|
56
|
|
|
$
|
85,804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
American
Midstream Partners, LP and Subsidiaries
Period
from August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
August 20,
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
(Inception Date)
|
|
|
|
|
|
|
to
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(6,992
|
)
|
|
$
|
(8,644
|
)
|
Adjustments to reconcile change in net assets to net cash used
in operating activities:
|
|
|
|
|
|
|
|
|
Depreciation expense
|
|
|
2,978
|
|
|
|
20,013
|
|
Amortization of deferred financing costs
|
|
|
118
|
|
|
|
807
|
|
Mark to market on derivatives
|
|
|
5
|
|
|
|
385
|
|
Unit based compensation
|
|
|
150
|
|
|
|
1,185
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,447
|
)
|
|
|
791
|
|
Unbilled revenue
|
|
|
(18,329
|
)
|
|
|
(3,865
|
)
|
Risk management assets
|
|
|
(82
|
)
|
|
|
(308
|
)
|
Other current assets
|
|
|
(1,523
|
)
|
|
|
|
|
Other assets
|
|
|
(199
|
)
|
|
|
(104
|
)
|
Accounts payable
|
|
|
1,934
|
|
|
|
(954
|
)
|
Accrued gas purchase
|
|
|
14,881
|
|
|
|
3,825
|
|
Accrued expenses and other current liabilities
|
|
|
1,997
|
|
|
|
268
|
|
Other liabilities
|
|
|
(22
|
)
|
|
|
392
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) in operating activities
|
|
|
(6,531
|
)
|
|
|
13,791
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
Acquisition of operating assets from Enbridge Midcoast Energy, LP
|
|
|
(150,818
|
)
|
|
|
|
|
Additions to property, plant and equipment
|
|
|
(1,158
|
)
|
|
|
(10,268
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(151,976
|
)
|
|
|
(10,268
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
Capital contributions
|
|
|
100,000
|
|
|
|
12,000
|
|
Unit holder distributions
|
|
|
|
|
|
|
(11,779
|
)
|
Payment of deferred financing costs
|
|
|
(2,158
|
)
|
|
|
|
|
Borrowings on other loans
|
|
|
903
|
|
|
|
800
|
|
Payments on other loan
|
|
|
(89
|
)
|
|
|
(1,000
|
)
|
Borrowings on long-term debt
|
|
|
63,000
|
|
|
|
26,500
|
|
Payments on long-term debt
|
|
|
(2,000
|
)
|
|
|
(31,130
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
159,656
|
|
|
|
(4,609
|
)
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
1,149
|
|
|
|
(1,086
|
)
|
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
|
|
|
|
1,149
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
1,149
|
|
|
$
|
63
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Interest payments
|
|
$
|
337
|
|
|
$
|
4,523
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from
August 20, 2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010
|
|
1.
|
Summary
of Significant Accounting Policies
|
Nature of
Business
American Midstream Partners, LP (the Partnership)
was formed on August 20, 2009 (date of
inception) as a Delaware limited partnership for the
purpose of acquiring and operating certain natural gas pipeline
and processing businesses. We provide natural gas gathering,
treating, processing, marketing and transportation services in
the Gulf Coast and Southeast regions of the United States. We
hold our assets in a series of wholly owned limited liability
companies as well as a limited partnership. Our capital accounts
consist of general partner interests and limited partner
interests.
We are controlled by our general partner, American Midstream GP,
LLC, which is a wholly owned subsidiary of AIM Midstream
Holdings, LLC.
Our interstate natural gas pipeline assets transport natural gas
through Federal Energy Regulatory Commission (the
FERC) regulated interstate natural gas pipelines in
Louisiana, Mississippi, Alabama and Tennessee. Our interstate
pipelines include:
|
|
|
|
|
American Midstream (Midla), LLC, which owns and operates
approximately 370 miles of interstate pipeline that runs
from the Monroe gas field in northern Louisiana south through
Mississippi to Baton Rouge, Louisiana.
|
|
|
|
American Midstream (AlaTenn), LLC, which owns and operates more
than approximately 295 miles of interstate pipeline that
runs through the Tennessee River Valley from Selmer, Tennessee
to Huntsville, Alabama and serves an eight county area in
Alabama, Mississippi and Tennessee.
|
Basis of
Presentation
We have prepared the consolidated financial statements in
accordance with accounting principles generally accepted in the
United States of America (GAAP). The accompanying
consolidated financial statements include the accounts of
American Midstream Partners, LP and its controlled subsidiaries.
All significant inter-company accounts and transactions have
been eliminated in the preparation of the accompanying
consolidated financial statements.
The financial position at December 31, 2009 and results of
operations and changes in cash flows for the period then ended
reflect operations from August 20, 2009, the date of
inception. Between the date of inception and the date of the
acquisition of the assets discussed in Note 2 on
November 2, 2009, no operating activity occurred in the
Partnership.
Use of
Estimates
When preparing financial statements in conformity with
accounting principles generally accepted in the United States of
America, management must make estimates and assumptions based on
information available at the time. These estimates and
assumptions affect the reported amounts of assets, liabilities,
revenues and expenses, as well as the disclosures of contingent
assets and liabilities as of the date of the financial
statements. Estimates and judgments are based on information
available at the time such estimates and judgments are made.
Adjustments made with respect to the use of these estimates and
judgments often relate to information not previously available.
Uncertainties with respect to such estimates and judgments are
inherent in the preparation of financial statements. Estimates
and judgments are used in, among other things,
(1) estimating unbilled revenues, product purchases and
operating and general and administrative costs
(2) developing fair value assumptions, including estimates
of future cash flows and discount rates, (3) analyzing
long-lived assets for possible impairment, (4) estimating
the useful lives of assets and (5) determining amounts
F-7
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
to accrue for contingencies, guarantees and indemnifications.
Actual results, therefore, could differ materially from
estimated amounts.
Accounting
for Regulated Operations
Certain of our natural gas pipelines are subject to regulation
by the FERC. The FERC exercises statutory authority over matters
such as construction, transportation rates we charge and our
underlying accounting practices, and ratemaking agreements with
customers. Accordingly, we record costs that are allowed in the
ratemaking process in a period different from the period in
which the costs would be charged to expense by a non-regulated
entity. Also, we record assets and liabilities that result from
the regulated ratemaking process that would not be recorded
under GAAP for our regulated entities. As of December 31,
2009 and 2010, the Partnership had no such significant
regulatory assets or liabilities.
Revenue
Recognition and the Estimation of Revenues and Cost of Natural
Gas
We recognize revenue when all of the following criteria are met:
(1) persuasive evidence of an exchange arrangement exists,
(2) delivery has occurred or services have been rendered,
(3) the price is fixed or determinable and
(4) collectibility is reasonably assured. We record revenue
and cost of product sold on a gross basis for those transactions
where we act as the principal and take title to natural gas,
NGLs or condensates that are purchased for resale. When our
customers pay us a fee for providing a service such as
gathering, treating or transportation, we record those fees
separately in revenues. For the period and year ended
December 31, 2009 and 2010, respectively, the Partnership
had the following revenues by category:
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|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
August 20
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
(Inception Date)
|
|
|
|
|
|
|
to
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
Transportation firm
|
|
$
|
2,274
|
|
|
$
|
10,610
|
|
Transportation interruptible
|
|
|
444
|
|
|
|
3,313
|
|
Sales of natural gas, NGLs and condensate
|
|
|
30,078
|
|
|
|
197,398
|
|
Other
|
|
|
37
|
|
|
|
619
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
32,833
|
|
|
$
|
211,940
|
|
|
|
|
|
|
|
|
|
|
We derive revenue in our business from the following types of
arrangements:
Fee-Based
Under these arrangements, we generally are paid a fixed cash fee
for gathering and transporting natural gas.
Percent-of-Proceeds,
or POP
Under these arrangements, we generally gather raw natural gas
from producers at the wellhead or other supply points, transport
it through our gathering system, process it and sell the residue
natural gas and NGLs at market prices. Where we provide
processing services at the processing plants that we own, or
obtain
F-8
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
processing services for our own account under our elective
processing arrangements we typically retain and sell a
percentage of the residue natural gas and resulting NGLs.
Fixed-Margin
Under these arrangements, we purchase natural gas from producers
or suppliers at receipt points on our systems at an index price
less a fixed transportation fee and simultaneously sell an
identical volume of natural gas at delivery points on our
systems at the same, undiscounted index price.
Firm
Transportation
Our obligation to provide firm transportation service means that
we are obligated to transport natural gas nominated by the
shipper up to the maximum daily quantity specified in the
contract. In exchange for that obligation on our part, the
shipper pays a specified reservation charge, whether or not it
utilizes the capacity. In most cases, the shipper also pays a
variable use charge with respect to quantities actually
transported by us.
Interruptible
Transportation
Our obligation to provide interruptible transportation service
means that we are only obligated to transport natural gas
nominated by the shipper to the extent that we have available
capacity. For this service the shipper pays no reservation
charge but pays a variable use charge for quantities actually
shipped.
Cash and
Cash Equivalents
We consider all highly liquid investments with an original
maturity of three months or less at the date of purchase to be
cash equivalents. The carrying value of cash and cash
equivalents approximates fair value because of the short term to
maturity of these investments.
Allowance
for Doubtful Accounts
We establish provisions for losses on accounts receivable when
we determine that we will not collect all or part of an
outstanding balance. Collectability is reviewed regularly and an
allowance is established or adjusted, as necessary, using the
specific identification method. For each of the period and year
ended December 31, 2009 and 2010, the Partnership recorded
no allowances for losses on accounts receivable.
Inventory
Inventory includes primarily product inventory. The Partnership
records all product inventories at the lower of cost or market
(LCM), which is determined on a weighted average
basis.
Operational
Balancing Agreements and Natural Gas Imbalances
To facilitate deliveries of natural gas and provide for
operational flexibility, we have operational balancing
agreements in place with other interconnecting pipelines. These
agreements ensure that the volume of natural gas a shipper
schedules for transportation between two interconnecting
pipelines equals the volume actually delivered. If natural gas
moves between pipelines in volumes that are more or less than
the volumes the shipper previously scheduled, a natural gas
imbalance is created. The imbalances are settled through
periodic cash payments or repaid in-kind through future receipt
or delivery of natural gas. Natural gas imbalances are recorded
as gas imbalances and classified within other current assets or
other current liabilities on our consolidated balance sheets
based on the market value. Natural gas imbalances are recorded
as gas imbalances within Accrued gas purchases on
the consolidated balance sheets.
F-9
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Property,
Plant and Equipment
We capitalize expenditures related to property, plant and
equipment that have a useful life greater than one year for
(1) assets purchased or constructed; (2) existing
assets that are replaced, improved, or the useful lives of which
have been extended; and (3) all land, regardless of cost.
Maintenance and repair costs, including any planned major
maintenance activities, are expensed as incurred.
We record property, plant and equipment at its original cost,
which we depreciate on a straight-line basis over its estimated
useful life. Our determination of the useful lives of property,
plant and equipment requires us to make various assumptions,
including the supply of and demand for hydrocarbons in the
markets served by our assets, normal wear and tear of the
facilities, and the extent and frequency of maintenance
programs. We record depreciation using the group method of
depreciation, which is commonly used by pipelines, utilities and
similar entities.
Impairment
of Long Lived Assets
We evaluate the recoverability of our property, plant and
equipment when events or circumstances such as economic
obsolescence, business climate, legal and other factors indicate
we may not recover the carrying amount of the assets. We
continually monitor our businesses, the market and business
environment to identify indicators that could suggest an asset
may not be recoverable. We evaluate the asset for recoverability
by estimating the undiscounted future cash flows expected to be
derived from operating the asset as a going concern. These cash
flow estimates require us to make projections and assumptions
for many years into the future for pricing, demand, competition,
operating cost, contract renewals, and other factors. We
recognize an impairment loss when the carrying amount of the
asset exceeds its fair value as determined by quoted market
prices in active markets or present value techniques. The
determination of the fair value using present value techniques
requires us to make projections and assumptions regarding future
cash flows and weighted average cost of capital. Any changes we
make to these projections and assumptions could result in
significant revisions to our evaluation of the recoverability of
our property, plant and equipment and the recognition of an
impairment loss in our consolidated statements of income. No
impairment losses were recognized during the period ended and
year ended December 31, 2009 and 2010.
We assess our long-lived assets for impairment using
authoritative guidance. A long-lived asset is tested for
impairment whenever events or changes in circumstances indicate
its carrying amount may exceed its fair value. Fair values, for
the purposes of the impairment test, are based on the sum of the
undiscounted future cash flows expected to result from the use
and eventual disposition of the assets.
Examples of long-lived asset impairment indicators include:
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|
|
A significant decrease in the market price of a long-lived asset
or group;
|
|
|
|
A significant adverse change in the extent or manner in which a
long-lived asset or asset group is being used or in its physical
condition;
|
|
|
|
A significant adverse change in legal factors or in the business
climate could affect the value of a long-lived asset or asset
group, including an adverse action or assessment by a regulator
which would exclude allowable costs from the rate-making process;
|
|
|
|
An accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of the
long-lived asset or asset group; and
|
F-10
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
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A current-period operating cash flow loss combined with a
history of operating cash flow losses or a projection or
forecast that demonstrates continuing losses associated with the
use of a long lived asset or asset group;
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|
A current expectation that, more likely than not, a long-lived
asset or asset group will be sold or otherwise disposed of
significantly before the end of its previously estimated useful
life.
|
Income
Taxes
We are not a taxable entity for U.S. federal income tax
purposes or for the majority of states that impose an income
tax. Taxes on our net income generally are borne by our
unitholders through the allocation of taxable income. Our income
tax expense results from the enactment of state income tax laws
by the State of Texas that apply to entities organized as
partnerships. The Texas margin tax is computed on our modified
gross margin and was not significant for each of the period or
year ended December 31, 2009 and 2010.
Net income for financial statement purposes may differ
significantly from taxable income allocable to unitholders as a
result of differences between the tax basis and financial
reporting basis of assets and liabilities and the taxable income
allocation requirements under our partnership agreement. The
aggregate difference in the basis of our net assets for
financial and tax reporting purposes cannot be readily
determined because information regarding each partners tax
attributes in us is not available.
Commitments,
Contingencies and Environmental Liabilities
We expense or capitalize, as appropriate, expenditures for
ongoing compliance with environmental regulations that relate to
past or current operations. We expense amounts we incur for
remediation of existing environmental contamination caused by
past operations that do not benefit future periods by preventing
or eliminating future contamination. We record liabilities for
environmental matters when assessments indicate that remediation
efforts are probable, and the costs can be reasonably estimated.
Estimates of environmental liabilities are based on currently
available facts, existing technology and presently enacted laws
and regulations taking into consideration the likely effects of
inflation and other factors. These amounts also take into
account our prior experience in remediating contaminated sites,
other companies
clean-up
experience and data released by government organizations. Our
estimates are subject to revision in future periods based on
actual costs or new information. We evaluate recoveries from
insurance coverage separately from the liability and, when
recovery is probable, we record and report an asset separately
from the associated liability in our consolidated financial
statements.
We recognize liabilities for other commitments and contingencies
when, after fully analyzing the available information, we
determine it is either probable that an asset has been impaired,
or that a liability has been incurred and the amount of
impairment or loss can be reasonably estimated. When a range of
probable loss can be estimated, we accrue the most likely
amount, or if no amount is more likely than another, we accrue
the minimum of the range of probable loss. We expense legal
costs associated with loss contingencies as such costs are
incurred.
We have legal obligations requiring us to decommission our
offshore pipeline systems at retirement. In certain rate
jurisdictions, we are permitted to include annual charges for
removal costs in the regulated cost of service rates we charge
our customers. Additionally, legal obligations exist for a
minority of our onshore
right-of-way
agreements due to requirements or landowner options to compel us
to remove the pipe at final abandonment. Sufficient data exists
with certain onshore pipeline systems to reasonably estimate the
cost of abandoning or retiring a pipeline system. However, in
some cases, there is insufficient information to reasonably
determine the timing
and/or
method of settlement for estimating the fair value of the asset
F-11
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
retirement obligation. In these cases, the asset retirement
obligation cost is considered indeterminate because there is no
data or information that can be derived from past practice,
industry practice, managements experience, or the
assets estimated economic life. The useful lives of most
pipeline systems are primarily derived from available supply
resources and ultimate consumption of those resources by end
users. Variables can affect the remaining lives of the assets
which preclude us from making a reasonable estimate of the asset
retirement obligation. Indeterminate asset retirement obligation
costs will be recognized in the period in which sufficient
information exists to reasonably estimate potential settlement
dates and methods.
Asset
Retirement Obligations (AROs)
AROs are legal obligations associated with the retirement of
tangible long-lived assets that result from the assets
acquisition, construction, development
and/or
normal operation. An ARO is initially measured at its estimated
fair value. Upon initial recognition of an ARO, we record an
increase to the carrying amount of the related long-lived asset
and an offsetting ARO liability. We depreciate the capitalized
ARO using the straight-line method over the period during which
the related long-lived asset is expected to provide benefits.
After the initial period of ARO recognition, we revise the ARO
to reflect the passage of time or revisions to the amounts of
estimated cash flows or their timing.
Derivative
Financial Instruments
Our net income and cash flows are subject to volatility stemming
from changes in interest rates on our variable rate debt,
commodity prices and fractionation margins (the relative
difference between the price we receive from NGL sales and the
corresponding cost of natural gas purchases). In an effort to
manage the risks to unitholders, we use a variety of derivative
financial instruments including swaps, put options and interest
rate caps to create offsetting positions to specific commodity
or interest rate exposures. In accordance with the authoritative
accounting guidance, we record all derivative financial
instruments in our consolidated balance sheets at fair market
value. We record the fair market value of our derivative
financial instruments in the consolidated balance sheets as
current and long-term assets or liabilities on a net basis by
counterparty. We record changes in the fair value of our
derivative financial instruments in our consolidated statements
of operations as follows:
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|
|
|
|
Commodity-based derivatives: Total revenue
|
|
|
|
Corporate interest rate derivatives: Interest expense
|
Our formal hedging program provides a control structure and
governance for our hedging activities specific to identified
risks and time periods, which are subject to the approval and
monitoring by the board of directors of our general partner. We
employ derivative financial instruments in connection with an
underlying asset, liability or anticipated transaction, and we
do not use derivative financial instruments for speculative
purposes.
The price assumptions we use to value our derivative financial
instruments can affect net income for each period. We use
published market price information where available, or
quotations from
over-the-counter,
or OTC, market makers to find executable bids and offers. The
valuations also reflect the potential impact of liquidating our
position in an orderly manner over a reasonable period of time
under present market conditions, including credit risk of our
counterparties. The amounts reported in our consolidated
financial statements change quarterly as these valuations are
revised to reflect actual results, changes in market conditions
or other factors, many of which are beyond our control.
Our earnings are affected by use of the
mark-to-market
method of accounting as required under GAAP for derivative
financial instruments. The use of
mark-to-market
accounting for derivative financial instruments
F-12
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
can cause noncash earnings volatility resulting from changes in
the underlying indices, primarily commodity prices.
The Partnerships other comprehensive income is comprised
of changes in the net pension asset or liability associated with
the OPEB plan (Note 15). Comprehensive income for the
period and year ended December 31, 2009 and 2010 was as
follows:
|
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|
|
|
|
|
|
|
|
|
Period Ended
|
|
|
Year Ended
|
|
|
|
December 31, 2009
|
|
|
December 31, 2010
|
|
|
Net income (loss)
|
|
$
|
(6,992
|
)
|
|
$
|
(8,644
|
)
|
Unrealized gains (losses) on post retirement benefit plan assets
and liabilities
|
|
|
46
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
(6,946
|
)
|
|
$
|
(8,634
|
)
|
|
|
|
|
|
|
|
|
|
Unit-Based
Employee Compensation
We award unit-based compensation to management, nonmanagement
employees and directors in the form of phantom units, which are
deemed to be equity awards. Compensation expense on phantom
units is measured by the fair value of the award at the date of
grant as determined by management. Compensation expense is
recognized in general and administrative expense over the
requisite service period of each award. See Note 14.
Fair
Value Measurements
We apply the authoritative accounting provisions for measuring
fair value of our derivative instruments and disclosures
associated with our outstanding indebtedness. We define fair
value as an exit price representing the expected amount we would
receive when selling an asset or pay to transfer a liability in
an orderly transaction with market participants at the
measurement date.
We employ a hierarchy which prioritizes the inputs we use to
measure recurring fair value into three distinct categories
based upon whether such inputs are observable in active markets
or unobservable. We classify assets and liabilities in their
entirety based on the lowest level of input that is significant
to the fair value measurement. Our methodology for categorizing
assets and liabilities that are measured at fair value pursuant
to this hierarchy gives the highest priority to unadjusted
quoted prices in active markets and the lowest level to
unobservable inputs as outlined below:
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|
|
|
|
Level 1 We include in this category the fair
value of assets and liabilities that we measure based on
unadjusted quoted prices in active markets that are accessible
at the measurement date for identical, unrestricted assets or
liabilities. We consider active markets as those in which
transactions for the assets or liabilities occur with sufficient
frequency and volume to provide pricing information on an
ongoing basis. We have no assets and liabilities included in
this category.
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|
|
|
Level 2 We categorize the fair value of assets
and liabilities that we measure with either directly or
indirectly observable inputs as of the measurement date, where
pricing inputs are other than quoted prices in active markets
for the identical instrument, as Level 2. Assets and
liabilities that we value using either models or other valuation
methodologies are derived from observable market data. These
models are primarily industry-standard models that consider
various inputs including: (a) quoted prices for assets and
liabilities, (b) time value, (c) volatility factors
and (d) current market and contractual prices for the
underlying instruments, as well as other relevant economic
measures. Substantially all of these inputs are observable in
the marketplace throughout the full term of the assets and
liabilities, can
|
F-13
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
|
|
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|
|
be derived from observable data, or are supported by observable
levels at which transactions are executed in the marketplace. We
have no fair value of assets or liabilities included in this
category.
|
|
|
|
|
|
Level 3 We include in this category the fair
value of assets and liabilities that we measure based on prices
or valuation techniques that require inputs which are both
significant to the fair value measurement and less observable
from objective sources (i.e., values supported by lesser volumes
of market activity). We may also use these inputs with
internally developed methodologies that result in our best
estimate of the fair value. Level 3 assets and liabilities
primarily include debt and derivative instruments for which we
do not have sufficient corroborating market evidence support
classifying the asset or liability as Level 2.
Additionally, Level 3 valuations may utilize modeled
pricing inputs to derive forward valuations, which may include
some or all of the following inputs: nonbinding broker quotes,
time value, volatility, correlation and extrapolation methods.
|
We utilize a mid-market pricing convention, or the market
approach, for valuation for assigning fair value to our
derivative assets and liabilities. Our credit exposure for
over-the-counter
derivatives is directly with our counterparty and continues
until the maturity or termination of the contracts. As
appropriate, valuations are adjusted for various factors such as
credit and liquidity considerations.
Debt
Issuance Costs
Costs incurred in connection with the issuance of long-term debt
are deferred and charged to interest expense over the term of
the related debt. Gains or losses on debt repurchase and debt
extinguishments include any associated unamortized debt issue
costs.
Limited
Partners Net Income Per Unit
We compute Limited Partners Net Income per Unit by
dividing our limited partners interest in net income by
the weighted average number of units outstanding during the
period. The overall computation, presentation, and disclosure
requirements for our Limited Partners Net Income per Unit
are made in accordance with the Earnings per Share
Topic of the Codification.
Accounting
Pronouncements Recently Adopted
In December 2009, the Financial Accounting Standards Board
(FASB) issued Accounting Standards Update
No. 2009-16,
Accounting for Transfers of Financial Assets and
Accounting Standards Update
No. 2009-17,
Improvements to Financial Reporting by Enterprises
Involved with Variable Interest Entities. ASU
No. 2009-16
amended the Codifications Transfers and
Servicing Topic to include the provisions included within
the FASBs previous Statement of Financial Accounting
Standards (SFAS) No. 166, Accounting for Transfers of
Financial Assets an amendment of FASB Statement
No. 140, issued June 12, 2009. ASU
No. 2009-17
amended the Codifications Consolidations Topic
to include the provisions included within the FASBs
previous SFAS No. 167, Amendments to FASB
Interpretation No. 46(R), also issued June 12,
2009. These two Updates changed the way entities must account
for securitizations and special-purpose entities. ASU
No. 2009-16
requires more information about transfers of financial assets,
including securitization transactions, and where companies have
continuing exposure to the risks related to transfer financial
assets. ASU
No. 2009-17
changes how a company determines whether an entity that is
insufficiently capitalized or is not controlled through voting
(or similar rights) should be consolidated. For us, both Updates
were effective January 1, 2010; however, the adoption of
these Updates did not have any impact on our consolidated
financial statements.
F-14
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
In January 2010, the FASB issued Accounting Standards Update
No. 2010-06,
Improving Disclosures about Fair Value Measurements.
This ASU requires both the gross presentation of activity within
the Level 3 fair value measurement roll forward and the
details of transfers in and out of Levels 1 and 2 fair
value measurements. It also clarifies certain disclosure
requirements on the level of disaggregation of fair value
measurements and disclosures on inputs and valuation techniques.
For us, this ASU was effective January 1, 2010 (except for
the Level 3 roll forward which was effective for us
January 1, 2011); however, the adoption of this ASU did not
have a material impact on our consolidated financial statements.
Furthermore, during each of the period and year ended
December 31, 2010 and 2009, we made no transfers in and out
of Level 1, Level 2, or Level 3 of the fair value
hierarchy.
In July 2010, the FASB issued Accounting Standards Update
No. 2010-20,
Disclosures about the Credit Quality of Financing
Receivables and the Allowance for Credit Losses. ASU No.
2010-20
requires companies that hold financing receivables, which
include loans, lease receivables, and the other long-term
receivables to provide more information in their disclosures
about the credit quality of their financing receivables and the
credit reserves held against them. On December 31, 2010, we
adopted all amendments that require disclosures as of the end of
a reporting period, and on January 1, 2011, we adopted all
amendments that require disclosures about activity that occurs
during a reporting period (the remainder of this ASU). The
adoption of this ASU did not have a material impact on our
consolidated financial statements.
On October 2, 2009, American Midstream, LLC, a wholly owned
subsidiary, entered into a purchase and sale agreement to
acquire certain pipeline businesses from Enbridge Midcoast
Energy, L.P., for an aggregate purchase price of approximately
$150.8 million. The acquisition was effective as of
November 1, 2009. Prior to the acquisition, we had no
operating tangible assets.
The acquired businesses were renamed as follows:
American Midstream (Alabama Intrastate), LLC
American Midstream (Bamagas Intrastate), LLC
American Midstream (Tennessee River), LLC
American Midstream (Mississippi), LLC
American Midstream (Midla), LLC
American Midstream (Alabama Gathering), LLC
American Midstream (AlaTenn), LLC
American Midstream Onshore Pipelines, LLC
Mid Louisiana Gas Transmission, LLC
American Midstream Offshore (Seacrest), LP
American Midstream (SIGCO Intrastate), LLC
American Midstream (Louisiana Intrastate), LLC
The acquisition qualifies as a business combination and, as
such, the Partnership estimated the fair value of each property
as of the acquisition date (the date on which the Partnership
obtained control of the properties). The fair value is the price
that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at the measurement date. Fair value measurements also utilize
assumptions of market participants. The Partnership used a
discounted cash flow model and made market assumptions as to
future commodity prices, expectations for timing and amount of
future development and operating costs, projections of future
rates of production, and risk adjusted discount rates. These
assumptions represent Level 3 inputs.
F-15
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
The following table summarizes the consideration paid to the
seller and the amounts of the assets acquired and liabilities
assumed in the acquisition.
|
|
|
|
|
|
|
(in thousands)
|
|
|
Consideration paid to seller
|
|
|
|
|
Cash consideration
|
|
$
|
150,818
|
|
|
|
|
|
|
Recognized amounts of identifiable assets acquired and
liabilities assumed
|
|
|
|
|
Property, plant and equipment
|
|
|
151,085
|
|
Other post-retirement benefit plan assets, net
|
|
|
394
|
|
Other liabilities assumed
|
|
|
(661
|
)
|
|
|
|
|
|
Total identifiable net assets
|
|
$
|
150,818
|
|
|
|
|
|
|
Acquisition costs of $6.4 million and $0.3 million
have been recorded in the statements of operations under the
caption Transaction costs on acquisitions for the period and
year ended December 31, 2009 and 2010.
|
|
3.
|
Concentration
of Credit Risk and Trade Accounts Receivable
|
Our primary market areas are located in the United States along
the Gulf Coast and in the Southeast. We have a concentration of
trade receivable balances due from companies engaged in the
production, trading, distribution and marketing of natural gas
and NGL products. These concentrations of customers may affect
our overall credit risk in that the customers may be similarly
affected by changes in economic, regulatory or other factors.
Our customers historical financial and operating
information is analyzed prior to extending credit. We manage our
exposure to credit risk through credit analysis, credit
approvals, credit limits and monitoring procedures, and for
certain transactions, we may request letters of credit,
prepayments or guarantees. We maintain allowances for
potentially uncollectible accounts receivable. For the period
and year ended December 31, 2009 and 2010, no allowances on
accounts receivable were recorded.
Enbridge Marketing (US) L.P., ConocoPhillips Corporation and
ExxonMobil Corporation were significant customers, representing
at least 10% of our consolidated revenue, accounting for
$17.8 million, $5.0 million and $0.1 million,
respectively, of our consolidated revenue in the consolidated
statement of operations in the period ended December 31,
2009 and $63.9 million, $53.4 million and
$22.9 million for the year ended December 31, 2010.
Other current assets as of December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Prepaid insurance current portion
|
|
$
|
815
|
|
|
$
|
767
|
|
NGL inventory
|
|
|
121
|
|
|
|
101
|
|
Other receivables
|
|
|
431
|
|
|
|
30
|
|
Other prepaid amounts
|
|
|
156
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,523
|
|
|
$
|
1,523
|
|
|
|
|
|
|
|
|
|
|
For each of the period and year ended December 31, 2009 and
2010, the Partnership recorded no LCM write-downs.
F-16
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Commodity
Derivatives
To minimize the effect of a downturn in commodity prices and
protect the Partnerships profitability and the economics
of its development plans, the Partnership enters into commodity
economic hedge contracts from time to time. The terms of
contracts depend on various factors, including managements
view of future commodity prices, acquisition economics on
purchased assets and future financial commitments. This hedging
program is designed to moderate the effects of a severe
commodity price downturn while allowing us to participate in
some commodity price increases. Management regularly monitors
the commodity markets and financial commitments to determine if,
when, and at what level some form of commodity hedging is
appropriate in accordance with policies which are established by
the board of directors of our general partner. Currently, the
commodity hedges are in the form of swaps and puts.
Neither the Partnership nor its counterparties are required to
post collateral in connection with its derivative positions and
netting agreements are in place with each of the
Partnerships counterparties allowing the Partnership to
offset its commodity derivative asset and liability positions.
As of December 31, 2010, the notional volumes of our
commodity hedges for 2011 were 2,404,584 gallons, with no
amounts hedged in 2012 or after.
Interest
Rate Derivatives
The Partnership also utilizes interest rate caps to protect
against changes in interest rates on its floating rate debt.
At December 31, 2010, the Partnership had
$56.4 million outstanding under its credit facility, with
interest accruing at a rate plus an applicable margin. In order
to mitigate the risk of changes in cash flows attributable to
changes in market interest rates, the Partnership has entered
into interest rate caps that mitigate the risk of increases in
interest rates. As of December 31, 2010, we had interest
rate caps with a notional amount of $26.5 million that
effectively fix the base rate on that portion of our debt, with
a fixed maximum rate of 4%.
For accounting purposes, no derivative instruments were
designated as hedging instruments and were instead accounted for
under the
mark-to-market
method of accounting, with any changes in the
mark-to-market
value of the derivatives recorded in the balance sheets and
through earnings, rather than being deferred until the
anticipated transactions affect earnings. The use of
mark-to-market
accounting for financial instruments can cause noncash earnings
volatility due to changes in the underlying commodity prices
indices or interest rates.
As of December 31, 2009 and 2010, the fair value associated
with the Partnerships derivative instruments were recorded
in our financial statements, under the caption Risk management
assets, as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Commodity derivatives
|
|
$
|
|
|
|
$
|
|
|
Interest rate derivatives
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
77
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
F-17
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
During 2009 and 2010, we recorded the following
mark-to-market
losses:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Commodity derivatives
|
|
$
|
|
|
|
$
|
(308
|
)
|
Interest rate derivatives
|
|
|
(5
|
)
|
|
|
(77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(5
|
)
|
|
$
|
(385
|
)
|
|
|
|
|
|
|
|
|
|
Fair
Value Measurements
The Partnerships interest rate caps and commodity
derivatives discussed above were classified as Level 3
derivatives for all periods presented.
The table below includes a roll forward of the balance sheet
amounts (including the change in fair value) for financial
instruments classified by us within Level 3 of the
valuation hierarchy. When a determination is made to classify a
financial instrument within Level 3 of the valuation
hierarchy, the determination is based upon the significance of
the unobservable factors to the overall fair value measurement.
Level 3 financial instruments typically include, in
addition to the unobservable or Level 3 components,
observable components (that is, components that are actively
quoted and can be validated to external sources).
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
August 20, 2009
|
|
|
|
|
|
|
(Inception Date)
|
|
|
|
|
|
|
to
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Fair value asset (liability), beginning of period
|
|
$
|
|
|
|
$
|
77
|
|
Total realized and unrealized (losses) gains included in revenue
|
|
|
(5
|
)
|
|
|
(385
|
)
|
Purchases, sales and settlements, net
|
|
|
82
|
|
|
|
308
|
|
|
|
|
|
|
|
|
|
|
Fair value (liability) asset, end of period
|
|
$
|
77
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
F-18
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
|
|
6.
|
Property,
Plant and Equipment, Net
|
Property, plant and equipment, net, as of December 31 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Useful Life
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(in thousands)
|
|
|
Land
|
|
|
|
|
|
$
|
41
|
|
|
$
|
41
|
|
Buildings and improvements
|
|
|
4 to 40
|
|
|
|
1,427
|
|
|
|
2,523
|
|
Processing and treating plants
|
|
|
8 to 40
|
|
|
|
10,255
|
|
|
|
11,954
|
|
Pipelines
|
|
|
5 to 40
|
|
|
|
131,845
|
|
|
|
143,805
|
|
Compressors
|
|
|
4 to 20
|
|
|
|
7,164
|
|
|
|
7,163
|
|
Equipment
|
|
|
8 to 20
|
|
|
|
825
|
|
|
|
1,711
|
|
Computer software
|
|
|
5
|
|
|
|
687
|
|
|
|
1,390
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
|
|
|
|
152,244
|
|
|
|
168,587
|
|
Accumulated depreciation
|
|
|
|
|
|
|
(2,978
|
)
|
|
|
(21,779
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
|
|
|
$
|
149,266
|
|
|
$
|
146,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Of the gross property, plant and equipment balances at
December 31, 2009 and 2010, $20.3 million and
$24.3 million, respectively, relate to regulated assets.
|
|
7.
|
Asset
Retirement Obligations
|
We record a liability for the fair value of asset retirement
obligations and conditional asset retirement obligations that we
can reasonably estimate, on a discounted basis, in the period in
which the liability is incurred. We collectively refer to asset
retirement obligations and conditional asset retirement
obligations as ARO. Typically we record an ARO at the time the
assets are installed or acquired, if a reasonable estimate of
fair value can be made. In connection with establishing an ARO,
we capitalize the costs as part of the carrying value of the
related assets. We recognize an ongoing expense for the interest
component of the liability as part of depreciation expense
resulting from changes in the value of the ARO due to the
passage of time. We depreciate the initial capitalized costs
over the useful lives of the related assets. We extinguish the
liabilities for an ARO when assets are taken out of service or
otherwise abandoned.
During the year ended December 31, 2010, we recognized
$6.1 million of AROs for specific assets that we intend to
retire for operational purposes. We recorded accretion expense
of $1.2 million, in our consolidated statements of
operations for the year ended December 31, 2010 related to
these AROs.
No assets are legally restricted for purposes of settling our
ARO for each of the period and year ended December 31, 2009
and 2010. Following is a reconciliation of the beginning and
ending aggregate carrying amount of our ARO liabilities for each
of the period and year ended December 31, 2009 and 2010,
respectively.
F-19
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Balance at beginning of period
|
|
$
|
|
|
|
$
|
|
|
Additions
|
|
$
|
|
|
|
|
6,058
|
|
Accretion expense
|
|
$
|
|
|
|
|
1,191
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
|
|
|
$
|
7,249
|
|
|
|
|
|
|
|
|
|
|
The Partnership did not recognize AROs as of December 31,
2009 given that, at that time, it did not intend to retire any
of its existing assets, nor were retirement costs estimable.
However, after the Partnership had obtained sufficient operating
experience with assets during 2010, it determined certain assets
would be retired from an operational perspective.
Other assets, net, as of December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Deferred financing costs
|
|
$
|
2,040
|
|
|
$
|
1,338
|
|
Other post-retirement benefit plan assets, net
|
|
|
440
|
|
|
|
450
|
|
Prepaid insurance long term portion
|
|
|
189
|
|
|
|
140
|
|
Security deposits
|
|
|
10
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,679
|
|
|
$
|
1,985
|
|
|
|
|
|
|
|
|
|
|
Deferred
Financing Costs
Deferred financing costs related to the term loan portion of our
credit facility are amortized using the effective interest
method over the term of the term credit facility. See
Note 12 for more information about our credit facility.
Deferred financing costs related to the revolver portion of our
credit facility are amortized on a straight line basis over the
term of the credit facility. During the year ended
December 31, 2010, we incurred deferred financing costs of
$2.2 million related to our November 2009 $85 million
credit facility.
F-20
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
|
|
9.
|
Accrued
Expenses and Other Current Liabilities
|
Other current liabilities as of December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Accrued interest payable
|
|
$
|
508
|
|
|
$
|
407
|
|
Accrued expenses
|
|
|
651
|
|
|
|
839
|
|
Accrued salaries
|
|
|
267
|
|
|
|
957
|
|
Accrued property taxes
|
|
|
217
|
|
|
|
3
|
|
Contract obligations short term
|
|
|
240
|
|
|
|
240
|
|
Deferred revenue
|
|
|
|
|
|
|
210
|
|
Other
|
|
|
354
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,237
|
|
|
$
|
2,676
|
|
|
|
|
|
|
|
|
|
|
Other long term liabilities as of December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Deferred revenue
|
|
$
|
|
|
|
$
|
528
|
|
ARO
|
|
|
|
|
|
|
7,249
|
|
Contract obligations long term
|
|
|
399
|
|
|
|
208
|
|
Other deferred expenses
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
399
|
|
|
$
|
8,078
|
|
|
|
|
|
|
|
|
|
|
Other loan represents insurance premium financing in the
original amounts of $0.8 million bearing interest at 4.25%
per annum, that is repayable in equal monthly installments of
less than $0.1 million through October 1, 2011.
On November 4, 2009, we entered into an $85 million
secured credit facility (credit facility) with a
consortium of lending institutions. The credit facility is
composed of a $50 million term loan facility and a
$35 million revolving credit facility.
F-21
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Our outstanding borrowings under the credit facility at December
31 were:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Term loan facility
|
|
$
|
50,000
|
|
|
$
|
45,000
|
|
Revolving loan facility
|
|
|
11,000
|
|
|
|
11,370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,000
|
|
|
|
56,370
|
|
Less: Current portion
|
|
|
5,000
|
|
|
|
6,000
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
56,000
|
|
|
$
|
50,370
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009 and 2010, letters of credit
outstanding under the credit facility were $2.0 million and
$0.6 million, respectively.
The credit facility provides for a maximum borrowing equal to
the lesser of (i) $85 million less the required
amortization of term loan payments and (ii) 3.50 times
adjusted consolidated EBITDA (as defined: $20.9 and
$18.8 million at December 31, 2009 and 2010,
respectively). We may elect to have loans under the credit
facility bear interest either (i) at a Eurodollar-based
rate with a minimum of 2.0% plus a margin ranging from 3.25% to
4.0% depending on our total leverage ratio then in effect, or
(ii) at a base rate (the greater of (i) the daily
adjusting LIBOR rate and (ii) a Prime-based rate which is
equal to the greater of (A) the Prime Rate and (B) an
interest rate per annum equal to the Federal Funds Effective
Rate in effect that day, plus one percent) plus a margin ranging
from 2.25% to 3.00% depending on the total leverage ratio then
in effect. We also pay a facility fee of 1.0% per annum. In
December 2009, we entered into an interest rate cap with
participating lenders with a $26.5 million notional amount
at December 31, 2010 that effectively caps our
Eurodollar-based rate exposure on that portion of our debt at a
maximum of 4.0%. For the period and year ended December 31,
2009 and 2010, the weighted average interest rate on borrowings
under our credit facility was approximately 5.79% and 7.48%,
respectively.
Our obligations under the credit facility are secured by first
mortgage in favor of the lenders in our real property. The terms
of the credit facility include covenants that restrict our
ability to make cash distributions and acquisitions in some
circumstances. The remaining principal balance of loans and any
accrued and unpaid interest will be due and payable in full on
the maturity date, November 3, 2012.
The term loan facility also provides for quarterly principal
installment payments as described below:
|
|
|
|
|
Year
|
|
Amount
|
|
|
|
(in thousands)
|
|
|
2011
|
|
$
|
6,000
|
|
2012
|
|
|
39,000
|
|
|
|
|
|
|
|
|
$
|
45,000
|
|
|
|
|
|
|
The credit facility also contains customary representations and
warranties (including those relating to organization and
authorization, compliance with laws, absence of defaults,
material agreements and litigation) and customary events of
default (including those relating to monetary defaults, covenant
defaults, cross defaults and bankruptcy events). The primary
financial covenants contained in the credit facility are
(i) a total leverage ratio test (not to exceed 3.50 times)
and a minimum interest coverage ratio test (not less than 2.50
times). We were in compliance with all of the covenants under
our credit facility as of December 31, 2009 and 2010.
F-22
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Fair
Market Value of Financial Instruments
The Partnership used various assumptions and methods in
estimating the fair values of its financial instruments. The
carrying amounts of cash and cash equivalents and accounts
receivable approximated their fair value due to the short-term
maturity of these instruments. The carrying amount of the
Partnerships credit facility approximates fair value,
because the interest rate on the facility is variable.
Our capital accounts are comprised of a 2% general partner
interest and 98% limited partner interests. Our limited partners
have limited rights of ownership as provided for under our
partnership agreement and, as discussed below, the right to
participate in our distributions. Our general partner manages
our operations, and participates in our distributions, including
certain incentive distributions pursuant to the incentive
distribution rights that are nonvoting limited partner interests
held by our general partner.
The number of units outstanding as of December 31, were as
follows:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Common units
|
|
|
9,800
|
|
|
|
11,049
|
|
General partner units
|
|
|
200
|
|
|
|
224
|
|
Distributions
The Partnership made distributions of $0 million and
$11.8 million for the period and year ended
December 31, 2009 and 2010, respectively. The Partnership
made no distributions in respect of our general partners
incentive distribution rights.
|
|
14.
|
Long-Term
Incentive Plan
|
Our general partner manages our operations and activities and
employs the personnel who provide support to our operations. On
November 2, 2009, the board of directors of our general
partner adopted a long-term incentive plan for its employees and
consultants and directors who perform services for it or its
affiliates. On May 25, 2010, the board of directors of our
general partner adopted an amended and restated long-term
incentive plan (as amended, the LTIP). The LTIP
currently permits the grant of awards in the form of Partnership
units, which may include distribution equivalent rights
(DERs), covering an aggregate of 625,532 of our
units. A DER entitles the grantee to a cash payment equal to the
cash distribution made by the Partnership with respect to a unit
during the period such DER is outstanding. At December 31,
2009 and 2010, 154,737 and 111,112 units, respectively,
were available for future grant under the LTIP.
Ownership in the awards is subject to forfeiture until the
vesting date. The LTIP is administered by the board of directors
of our general partner.
Although other types of awards are contemplated under the LTIP,
currently outstanding awards are limited to phantom units with
DERs issued on November 2, 2009. The board of directors of
our general partner, at its discretion, may elect to settle such
vested phantom units with a number of units equivalent to the
fair market value at the date of vesting in lieu of cash.
Although, our general partner has the option to settle in cash
upon the vesting of phantom unit our general partner does not
intend to settle these awards in cash.
F-23
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
The following table summarizes our unit-based awards for each of
the periods indicated, in units:
|
|
|
|
|
|
|
|
|
|
|
Period Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
Outstanding at beginning of period
|
|
|
|
|
|
|
361,052
|
|
Granted
|
|
|
361,052
|
|
|
|
153,368
|
|
Converted
|
|
|
|
|
|
|
(90,263
|
)
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
361,052
|
|
|
|
424,157
|
|
|
|
|
|
|
|
|
|
|
Grant date fair value per share
|
|
$
|
10.0
|
|
|
$
|
10.0
|
|
The fair value of our phantom units, which are subject to equity
classification, is based on the fair value of our units at each
balance sheet date. Compensation costs related to these awards
during 2009 and 2010 was $0.2 million and
$1.2 million, respectively, which is classified in selling,
general and administrative expenses in the consolidated
statement of operations and partners capital on the
consolidated balance sheet.
The total compensation cost related to nonvested awards not yet
recognized on December 31, 2009 and 2010 was
$3.5 million and $3.9 million, respectively, and the
weighted average period over which this cost is expected to be
recognized is approximately 2 years.
|
|
15.
|
Post-Employment
Benefits
|
Post-Employment
Benefits other than Pensions
As a result of our acquisition from Enbridge, the sponsorship of
the AlaTenn VEBA plans were transferred from Enbridge to us
effective November 1, 2009. Accordingly, we sponsor a
contributory postretirement plan that provides medical, dental
and life insurance benefits for qualifying U.S. retired
employees (referred to as the OPEB Plan).
The tables below detail the changes in the benefit obligation,
the fair value of plan assets and the recorded asset or
liability of the OPEB Plan using the accrual method.
F-24
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Change In Benefit Obligation
|
|
|
|
|
|
|
|
|
Obligation assumed from the acquisition from Enbridge
|
|
$
|
771
|
|
|
$
|
734
|
|
Service cost
|
|
|
2
|
|
|
|
10
|
|
Interest cost
|
|
|
7
|
|
|
|
43
|
|
Actuarial (gain) loss
|
|
|
(44
|
)
|
|
|
112
|
|
Benefits paid
|
|
|
(2
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
Benefit obligation, December 31
|
|
$
|
734
|
|
|
$
|
869
|
|
|
|
|
|
|
|
|
|
|
Change In Plan Assets
|
|
|
|
|
|
|
|
|
Plan assets acquired from Enbridge
|
|
$
|
1,165
|
|
|
$
|
1,174
|
|
Actual return on plan assets
|
|
|
11
|
|
|
|
61
|
|
Employers contributions
|
|
|
|
|
|
|
113
|
|
Benefits paid
|
|
|
(2
|
)
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets, December 31
|
|
$
|
1,174
|
|
|
$
|
1,319
|
|
|
|
|
|
|
|
|
|
|
Funded Status
|
|
|
|
|
|
|
|
|
Funded status
|
|
$
|
394
|
|
|
$
|
440
|
|
Unrecognized actuarial gain
|
|
|
46
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
Prepaid (accrued) benefit cost, December 31
|
|
$
|
440
|
|
|
$
|
450
|
|
|
|
|
|
|
|
|
|
|
The amounts of plan net assets recognized in our consolidated
balance sheets at December 31, 2009 and December 31,
2010 were as follows:
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Other assets, net
|
|
$
|
440
|
|
|
$
|
450
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
440
|
|
|
$
|
450
|
|
|
|
|
|
|
|
|
|
|
The amounts included in accumulated other comprehensive income
that have not yet been recognized as components of net periodic
benefit expense are $46,000 and $56,000 as of December 31,
2009 and 2010, respectively.
The accumulated benefit obligation for the OPEB Plan at
December 31, 2009 and December 31, 2010 was
$0.7 million and $0.9 million, respectively.
F-25
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Economic
Assumptions
The assumptions made in measurement of the projected benefit
obligations or assets of the OPEB Plan were as follows:
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2009
|
|
|
2010
|
|
|
Discount rate
|
|
|
6.00
|
%
|
|
|
5.50
|
%
|
Expected return on plan assets
|
|
|
4.50
|
%
|
|
|
4.50
|
%
|
A one percent increase in the assumed medical and dental care
trend rate would result in an increase of $0.1 million in
the accumulated post-employment benefit obligations. A one
percent decrease in the assumed medical and dental care trend
rate would result in a decrease of $0.1 million in the
accumulated post-employment benefit obligations.
The above table reflects the expected long-term rates of return
on assets of the OPEB Plan on a weighted-average basis. The
overall expected rates of return are based on the asset
allocation targets with estimates for returns on equity and debt
securities based on long term expectations. We believe this rate
approximates the return we will achieve over the long-term on
the assets of our plans. Historically, we have used a discount
rate that corresponds to one or more high quality corporate bond
indices as an estimate of our expected long-term rate of return
on plan assets for our OPEB Plan assets. For 2009 and 2010 we
selected the discount rate using the Citigroup Pension Discount
Curve, or CPDC. The CPDC spot rates represent the equivalent
yield on high-quality, zero-coupon bonds for specific
maturities. These rates are used to develop a single, equivalent
discount rate based on the OPEB Plans expected future cash
flows.
Expected
Future Benefit Payments
The following table presents the benefits expected to be paid in
each of the next five fiscal years, and in the aggregate for the
five years thereafter by the OPEB Plan:
|
|
|
|
|
|
|
Gross Benefit
|
|
|
|
Payments
|
|
For the year ending
|
|
OPEB Plan
|
|
|
|
(in thousands)
|
|
|
2011
|
|
$
|
56
|
|
2012
|
|
|
56
|
|
2013
|
|
|
55
|
|
2014
|
|
|
55
|
|
2015
|
|
|
55
|
|
Five years thereafter
|
|
|
235
|
|
The expected future benefit payments are based upon the same
assumptions used to measure the projected benefit obligations of
the OPEB Plan including benefits associated with future employee
service.
Expected
Contributions to the Plans
We expect to make contributions to the OPEB Plan for the year
ending December 31, 2011 of $0.1 million.
F-26
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Plan
Assets
The weighted average asset allocation of our OPEB Plan at the
measurement date by asset category, are as follows:
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2009
|
|
|
2010
|
|
|
Fixed income(1)
|
|
|
76.7
|
%
|
|
|
70.7
|
%
|
Cash and short-term assets(2)
|
|
|
23.3
|
%
|
|
|
29.3
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
United States government securities, municipal corporate bonds
and notes and as set backed securities. |
|
(2) |
|
Cash and securities with maturities of one year or less. |
|
|
16.
|
Commitments
and Contingencies
|
We are subject to federal and state laws and regulations
relating to the protection of the environment. Environmental
risk is inherent to natural gas pipeline operations and we
could, at times, be subject to environmental cleanup and
enforcement actions. We attempt to manage this environmental
risk through appropriate environmental policies and practices to
minimize any impact our operations may have on the environment.
Future noncancelable commitments related to certain contractual
obligations are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period (in thousands)
|
|
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
Thereafter
|
|
|
Operating leases and service contract
|
|
$
|
2,057
|
|
|
$
|
580
|
|
|
$
|
405
|
|
|
$
|
342
|
|
|
$
|
351
|
|
|
$
|
349
|
|
|
$
|
30
|
|
ARO
|
|
|
8,340
|
|
|
|
914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,397
|
|
|
$
|
1,494
|
|
|
$
|
405
|
|
|
$
|
342
|
|
|
$
|
351
|
|
|
$
|
349
|
|
|
$
|
7,456
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses related to operating leases, asset retirement
obligations, land site leases and
right-of-way
agreements were:
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
August 20, 2009
|
|
|
|
|
|
|
(Inception Date)
|
|
|
|
|
|
|
to
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands)
|
|
|
Operating leases
|
|
$
|
60
|
|
|
$
|
757
|
|
ARO
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
60
|
|
|
$
|
782
|
|
|
|
|
|
|
|
|
|
|
|
|
17.
|
Related-Party
Transactions
|
Employees of our general partner are assigned to work for us.
Where directly attributable, the costs of all compensation,
benefits expenses and employer expenses for these employees are
charged directly by our general partner to American Midstream,
LLC which, in turn, charges the appropriate subsidiary. Our
general
F-27
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
partner does not record any profit or margin for the
administrative and operational services charged to us. During
the period and year ended December 31, 2009 and 2010,
administrative and operational services expenses of
$0.9 million and $0.9 million were allocated to us by
our general partner.
We have entered into an advisory services agreement with
American Infrastructure MLP Management, L.L.C., American
Infrastructure MLP PE Management, L.L.C., and American
Infrastructure MLP Associates Management, L.L.C., as the
advisors. The agreement provides that we pay $0.3 million
in 2010 and annual fees of $0.3 million plus annual
increases in proportion to the increase in budgeted gross
revenues thereafter. In exchange, the advisors have agreed to
provide us services in obtaining equity, debt, lease and
acquisition financing, as well as providing other financial,
advisory and consulting services. For the period and year ended
December 31, 2009 and 2010, less than $0.1 million and
$0.3 million, respectively, had been recorded to selling,
general and administrative expenses under this agreement.
Our operations are located in the United States and are
organized into two reporting segments: (1) Gathering and
Processing; and (2) Transmission
Gathering
and Processing
Our Gathering and Processing segment provides wellhead to
market services to producers of natural gas and oil, which
include transporting raw natural gas from the wellhead through
gathering systems, treating the raw natural gas, processing raw
natural gas to separate the NGLs and selling or delivering
pipeline quality natural gas and NGLs to various markets and
pipeline systems.
Transmission
Our Transmission segment transports and delivers natural gas
from producing wells, receipt points or pipeline interconnects
for shippers and other customers, including local distribution
companies, or LDCs, utilities and industrial, commercial and
power generation customers.
These segments are monitored separately by management for
performance and are consistent with internal financial
reporting. These segments have been identified based on the
differing products and services, regulatory environment and the
expertise required for these operations. Gross margin is a
performance measure utilized by management to monitor the
business of each segment.
F-28
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
The following tables set forth our segment information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
|
|
|
|
|
|
|
|
|
|
and
|
|
|
|
|
|
|
Transmission
|
|
|
Processing
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
Period from August 20, 2009 (Inception date) to
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
4,976
|
|
|
$
|
27,857
|
|
|
$
|
32,833
|
|
Segment gross margin(a)
|
|
$
|
2,542
|
|
|
$
|
3,698
|
|
|
$
|
6,240
|
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
|
|
1,594
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
1,346
|
|
One-time transaction costs
|
|
|
|
|
|
|
|
|
|
|
6,404
|
|
Depreciation expense
|
|
|
|
|
|
|
|
|
|
|
2,978
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
910
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
$
|
(6,992
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
|
|
|
|
|
|
|
|
|
|
and
|
|
|
|
|
|
|
Transmission
|
|
|
Processing
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
Year ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue(b)
|
|
$
|
53,485
|
|
|
$
|
158,455
|
|
|
$
|
211,940
|
|
Segment gross margin(a)(b)
|
|
$
|
13,524
|
|
|
$
|
24,595
|
|
|
$
|
38,119
|
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
|
|
12,187
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
8,854
|
|
One-time transaction costs
|
|
|
|
|
|
|
|
|
|
|
303
|
|
Depreciation expense
|
|
|
|
|
|
|
|
|
|
|
20,013
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
5,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
$
|
(8,644
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Segment gross margin for our Gathering and Processing segment
consists of total revenue, including commodity derivative
activity, less purchases of natural gas, NGLs and condensate.
Segment gross margin for our Transmission segment consists of
total revenue, less purchases of natural gas. Gross margin
consists of the sum of the segment gross margin amounts for each
of these segments. As an indicator of our operating performance,
gross margin should not be considered an alternative to, or more
meaningful than, net income or cash flow from operations as
determined in accordance with GAAP. Our gross margin may not be
comparable to a similarly titled measure of another company
because other entities may not calculate gross margin in the
same manner. |
|
(b) |
|
Noncash derivative
mark-to-market
is included in total revenue and segment gross margin in our
Gathering and Processing segment. |
F-29
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
Asset information including capital expenditures, by segment is
not included in reports used by our management in its monitoring
of performance and therefore, is not disclosed.
For the purposes of our Transmission segment, for the period
ended December 31, 2009 and the year ended
December 31, 2010, Enbridge Marketing (US) L.P., ExxonMobil
Corporation and Calpine Corporation represented significant
customers, each representing more than 10% of our segment
revenue in this segment. Our segment revenue derived from
Enbridge Marketing (US) L.P., ExxonMobil Corporation and Calpine
Corporation represented $3.0 million, $0.1 million and
$0.9 million of segment revenue for the period ended 2009
and $16.6 million, $22.9 million and $5.1 million
for the year ended 2010, respectively.
For the purposes of our Gathering and Processing segment, for
the period ended December 31, 2009 and the year ended
December 31, 2010, Enbridge Marketing (US) L.P.,
ConocoPhillips Corporation and Dow Hydrocarbons and Resources
represented significant customers, each representing more than
10% of our segment revenue in this segment. Our segment revenue
derived from Enbridge Marketing (US) L.P., ConocoPhillips
Corporation and Dow Hydrocarbons and Resources represented
$14.7 million, $5.0 million and $3.1 million of
segment revenue for the period ended 2009 and
$47.3 million, $53.4 million and $16.4 million
for the year ended 2010, respectively.
|
|
19.
|
Net
Income (Loss) per Limited and General Partner Unit
|
In June 2008, the FASB issued authoritative guidance, which
clarifies that share-based payment awards that entitle their
holders to receive nonforfeitable dividends before vesting
should be considered participating securities. As participating
securities, these instruments should be included in the earnings
allocation in computing basic earnings per unit under the two
class method. For the purposes of our earnings per unit
calculation, our LTIP phantom units discussed in Note 14
have been considered participating securities and are therefore
included in our basic earnings per unit calculation.
We allocate our net income among our general partner and limited
partners using the two-class method in accordance with
applicable authoritative accounting guidance. Under the
two-class method, we allocate our net income, to our general
partner and our limited partners according to the distribution
formula for available cash as set forth in our partnership
agreement. We also allocate any earnings in excess of
distributions to our general partner and limited partners
utilizing the distribution formula for available cash specified
in our partnership agreement. We allocate any distributions in
excess of earnings for the period to our general partner and
limited partners based on their sharing of losses of 2% and 98%,
respectively, as set forth in our partnership agreement.
F-30
American
Midstream Partners, LP and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2009 and 2010 and Period from August 20,
2009 (Inception Date) to
December 31, 2009 and Year Ended December 31,
2010 (continued)
We determined basic and diluted net income per general partner
unit and limited partner unit as follows:
|
|
|
|
|
|
|
|
|
|
|
For the
|
|
|
|
|
|
|
Period from
|
|
|
|
|
|
|
August 20, 2009
|
|
|
|
|
|
|
(Inception Date)
|
|
|
For The
|
|
|
|
to
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(in thousands, except per unit amounts)
|
|
|
Net loss attributable to general partner and limited partners
|
|
$
|
(6,992
|
)
|
|
$
|
(8,644
|
)
|
Weighted average general partner and limited partner units
outstanding(1)
|
|
|
4,596
|
|
|
|
10,711
|
|
Earnings per general partner and limited partner unit (basic and
diluted)
|
|
$
|
(1.52
|
)
|
|
$
|
(.81
|
)
|
Net loss attributable to limited partners
|
|
$
|
(6,852
|
)
|
|
$
|
(8,471
|
)
|
Weighted average limited partner units outstanding(1)
|
|
|
4,507
|
|
|
|
10,506
|
|
Earnings per limited partner unit (basic and diluted)
|
|
$
|
(1.52
|
)
|
|
$
|
(.81
|
)
|
Net loss attributable to general partner
|
|
$
|
(140
|
)
|
|
$
|
(173
|
)
|
Weighted average general partner units outstanding
|
|
|
89
|
|
|
|
205
|
|
Earnings per general partner unit (basic and diluted)
|
|
$
|
(1.58
|
)
|
|
$
|
(.84
|
)
|
|
|
|
(1) |
|
Includes unvested phantom units, which are considered
participating securities, of 361,052 and 424,157 as of
December 31, 2009 and 2010, respectively. |
The Partnership has evaluated subsequent events through
March 30, 2011.
On February 11, 2011, the Board of Directors of our general
partner approved a distribution in the amount of
$3.8 million, consisting of payments of $3.6 million
to the limited partners, $0.1 million to the general
partner and $0.1 million in DER payments.
On March 1, 2011, the Compensation Committee of the Board
of Directors of our general partner approved the award of a
total of 35,000 phantom units to certain employees under the
Partnership LTIP program. The units vest over four years and do
not contain distribution equivalent rights.
F-31
Report of
Independent Registered Public Accounting Firm
To the Board of Directors of the General Partner of
American Midstream Partners, LP
We have audited the accompanying combined balance sheets of
American Midstream Partners Predecessor (the Predecessor) as of
December 31, 2008 and October 31, 2009, and the
related combined statements of operations, of changes in group
equity and of cash flows for the year ended December 31,
2008 and the ten-month period ended October 31, 2009. These
financial statements are the responsibility of the management of
American Midstream Partners, LP. Our responsibility is to
express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the combined financial statements referred to
above present fairly, in all material respects, the financial
position of the Predecessor at December 31, 2008 and
October 31, 2009, and the results of their operations and
their cash flows for the year ended December 31, 2008 and
the ten-month period ended October 31, 2009 in conformity
with accounting principles generally accepted in the United
States of America.
As discussed in Note 11 to the financial statements, the
financial results contain significant transactions with related
parties.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 30, 2011
F-32
American
Midstream Partners Predecessor
December 31,
2008 and October 31, 2009
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
October 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
421
|
|
|
$
|
149
|
|
Trade accounts receivable, net
|
|
|
1,411
|
|
|
|
248
|
|
Unbilled revenue
|
|
|
8,121
|
|
|
|
8,508
|
|
Due from affiliates
|
|
|
20,635
|
|
|
|
33,779
|
|
Notes receivable affiliates
|
|
|
26,872
|
|
|
|
|
|
Other current assets
|
|
|
2,314
|
|
|
|
1,668
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
59,774
|
|
|
|
44,352
|
|
Property, plant and equipment, net
|
|
|
216,903
|
|
|
|
205,126
|
|
Other assets
|
|
|
565
|
|
|
|
684
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
277,242
|
|
|
$
|
250,162
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Group Equity
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
273
|
|
|
$
|
1,515
|
|
Accrued gas purchases
|
|
|
19,688
|
|
|
|
11,575
|
|
Notes payable affiliate
|
|
|
39,339
|
|
|
|
|
|
Accrued expenses and other current liabilities
|
|
|
3,538
|
|
|
|
2,616
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
62,838
|
|
|
|
15,706
|
|
Other liabilities
|
|
|
2,605
|
|
|
|
2,864
|
|
Long-term debt
|
|
|
60,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
125,443
|
|
|
|
18,570
|
|
Commitments and contingencies (see Note 10)
|
|
|
|
|
|
|
|
|
Group equity
|
|
|
151,799
|
|
|
|
231,592
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and group equity
|
|
$
|
277,242
|
|
|
$
|
250,162
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-33
American
Midstream Partners Predecessor
Year
Ended December 31, 2008 and Period Ended October 31,
2009
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Period Ended
|
|
|
|
December 31,
|
|
|
October 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Total revenue
|
|
$
|
366,348
|
|
|
$
|
143,132
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Purchases of natural gas, NGLs and condensate
|
|
|
323,205
|
|
|
|
113,227
|
|
Direct operating expenses
|
|
|
13,423
|
|
|
|
10,331
|
|
Selling, general and administrative expenses
|
|
|
8,618
|
|
|
|
8,577
|
|
Depreciation expense
|
|
|
13,481
|
|
|
|
12,630
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
358,727
|
|
|
|
144,765
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
7,621
|
|
|
|
(1,633
|
)
|
Other (income) expenses
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
5,747
|
|
|
|
3,728
|
|
Other (income) expense
|
|
|
(854
|
)
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
Total other (income) expenses
|
|
|
4,893
|
|
|
|
3,704
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,728
|
|
|
$
|
(5,337
|
)
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-34
American
Midstream Partners Predecessor
Year
Ended December 31, 2008 and Period Ended October 31,
2009
|
|
|
|
|
|
|
(in thousands)
|
|
|
Group equity at December 31, 2007
|
|
$
|
145,833
|
|
Contributions by parent
|
|
|
10,500
|
|
Distributions to parent
|
|
|
(7,245
|
)
|
Other comprehensive loss
|
|
|
(17
|
)
|
Net income
|
|
|
2,728
|
|
|
|
|
|
|
Group equity at December 31, 2008
|
|
|
151,799
|
|
Contributions by parent
|
|
|
111,103
|
|
Distributions to parent
|
|
|
(25,772
|
)
|
Other comprehensive loss
|
|
|
(201
|
)
|
Net loss
|
|
|
(5,337
|
)
|
|
|
|
|
|
Group equity at October 31, 2009
|
|
$
|
231,592
|
|
|
|
|
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-35
American
Midstream Partners Predecessor
Combined Statements of Cash Flows
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Period Ended
|
|
|
|
December 31,
|
|
|
October 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,728
|
|
|
$
|
(5,337
|
)
|
Adjustments to reconcile change in net assets to net cash
provided by operating activities
|
|
|
|
|
|
|
|
|
Depreciation expense
|
|
|
13,481
|
|
|
|
12,630
|
|
Changes in operating assets and liabilities
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
1,102
|
|
|
|
1,163
|
|
Unbilled revenue
|
|
|
3,009
|
|
|
|
(387
|
)
|
Due from affiliates
|
|
|
8,262
|
|
|
|
(13,144
|
)
|
Notes receivable from affiliates
|
|
|
(4,400
|
)
|
|
|
26,872
|
|
Other current assets
|
|
|
(1,755
|
)
|
|
|
646
|
|
Other assets
|
|
|
(156
|
)
|
|
|
(320
|
)
|
Accounts payable
|
|
|
(807
|
)
|
|
|
1,242
|
|
Accrued gas purchase
|
|
|
(1,662
|
)
|
|
|
(8,113
|
)
|
Accrued expenses and other current liabilities
|
|
|
(1,761
|
)
|
|
|
(922
|
)
|
Other liabilities
|
|
|
114
|
|
|
|
259
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
18,155
|
|
|
|
14,589
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment
|
|
|
(10,486
|
)
|
|
|
(853
|
)
|
|
|
|
|
|
|
|
|
|
Net cash (used in) investing activities
|
|
|
(10,486
|
)
|
|
|
(853
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
Contributions from parent
|
|
|
10,500
|
|
|
|
111,103
|
|
Distributions to parent
|
|
|
(7,245
|
)
|
|
|
(25,772
|
)
|
Repayments of notes to affiliates
|
|
|
(11,184
|
)
|
|
|
(39,339
|
)
|
Repayments of long term debt
|
|
|
|
|
|
|
(60,000
|
)
|
|
|
|
|
|
|
|
|
|
Net cash (used in) financing activities
|
|
|
(7,929
|
)
|
|
|
(14,008
|
)
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(260
|
)
|
|
|
(272
|
)
|
Cash and cash equivalents
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
681
|
|
|
|
421
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
421
|
|
|
$
|
149
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Interest payments
|
|
$
|
325
|
|
|
$
|
132
|
|
The accompanying notes are an integral part of these combined
financial statements.
F-36
|
|
1.
|
Summary
of Significant Accounting Policies
|
Nature
of Business
These financial statements of American Midstream Partners
Predecessor (the Predecessor) have been prepared in
connection with the proposed initial public offering (the
Offering) of limited partner units in America
Midstream Partners, LP (the Partnership), which was
formed in Delaware on August 20, 2009. The Partnership
acquired certain natural gas pipeline and processing businesses
from Enbridge Energy Partners, LP (Enbridge) in
November 2009, as described below.
On October 2, 2009, Enbridge Midcoast Energy, L.P. (the
Parent), a wholly-owned subsidiary of Enbridge
entered into a purchase and sale agreement with American
Midstream, LLC, a wholly owned subsidiary of the Partnership,
for the sale of certain pipeline entities (collectively the
Entities). The sale was effective as of
November 1, 2009. In conjunction with the close of the
transaction, the Parent received cash consideration of
$150,817,898, excluding the subsequent settlement for working
capital as provided in the purchase and sale agreement.
The Entities were as follows:
Enbridge Pipelines Alabama Intrastate L.L.C.
Enbridge Pipelines Bamagas Intrastate L.L.C.
Enbridge Pipelines Tennessee River L.L.C.
Enbridge Pipelines Mississippi L.L.C.
Enbridge Pipelines Midla L.L.C.
Enbridge Pipelines Alabama Gathering L.L.C.
Enbridge Pipelines AlaTenn L.L.C.
Midcoast Holdings No. One L.L.C.
Mid Louisiana Gas Transmission L.L.C.
Enbridge Offshore Pipelines Seacrest, LP
Enbridge Pipelines SIGCO Intrastate L.L.C.
Enbridge Pipelines Louisiana Intrastate, L.L.C.
These combined financial statements represent the financial
position, results of operations, changes in group equity and
cash flows of the Predecessor, have been prepared from the
separate records maintained by Enbridge and include allocations
of certain Enbridge corporate expenses. Management of the
Partnership believes that the assumptions and estimates used in
preparation of the combined financial statements are reasonable.
However, the combined financial statements may not necessarily
reflect what the Predecessors financial position, results
of operations or cash flows would have been had it been a
stand-alone entity during the periods presented. Because of the
nature of these combined financial statements, the Parents
net investment in the Entities, including amounts due to the
Parent are shown as group equity.
The Predecessors interstate natural gas pipeline assets
transport natural gas through Federal Energy Regulatory
Commission (the FERC) regulated interstate natural
gas pipelines in Louisiana, Mississippi, Alabama and Tennessee.
The interstate pipelines include:
|
|
|
|
|
Enbridge Pipelines Midla L.L.C., which owns and
operates approximately 370 miles of interstate pipeline
that runs from the Monroe gas field in northern Louisiana south
through Mississippi to Baton Rouge, Louisiana.
|
|
|
|
Enbridge Pipelines AlaTenn L.L.C., which owns and
operates approximately 295 miles of interstate pipeline
that runs through the Tennessee River Valley from Selmer,
Tennessee to Huntsville, Alabama and serves an eight county area
in Alabama, Mississippi, and Tennessee.
|
F-37
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
Events and transactions subsequent to the balance sheet date
have been evaluated through March 30, 2011, the date these
combined financial statements were issued.
Basis
of Presentation and Use of Estimates
The combined financial statements have been prepared in
accordance with accounting principles generally accepted in the
United States (GAAP) on the basis of the
Parents historical ownership of the Predecessor. All
significant inter-company accounts and transactions have been
eliminated in the preparation of the accompanying combined
financial statements.
Use of
Estimates
When preparing financial statements in conformity with
accounting principles generally accepted in the United States of
America, the Predecessor must make estimates and assumptions
based on information available at the time. These estimates and
assumptions affect the reported amounts of assets, liabilities,
revenues and expenses, as well as the disclosures of contingent
assets and liabilities as of the date of the financial
statements. Estimates and judgments are based on information
available at the time such estimates and judgments are made.
Adjustments made with respect to the use of these estimates and
judgments often relate to information not previously available.
Uncertainties with respect to such estimates and judgments are
inherent in the preparation of financial statements. Estimates
and judgments are used in, among other things,
(1) estimating unbilled revenues, product purchases and
operating and general and administrative costs
(2) developing fair value assumptions, including estimates
of future cash flows and discount rates, (3) analyzing
long-lived assets for possible impairment, (4) estimating
the useful lives of assets and (5) determining amounts to
accrue for contingencies, guarantees and indemnifications.
Actual results, therefore, could differ materially from
estimated amounts.
Accounting
for Regulated Operations
Certain of the Predecessors natural gas pipelines are
subject to regulation by the FERC. The FERC exercises statutory
authority over matters such as construction, transportation
rates the Predecessor charges and the Predecessors
underlying accounting practices, and ratemaking agreements with
customers. Accordingly, the Predecessor records costs that are
allowed in the ratemaking process in a period different from the
period in which the costs would be charged to expense by a
nonregulated entity. Also, the Predecessor records assets and
liabilities that result from the regulated ratemaking process
that would not be recorded under GAAP for the Predecessors
regulated entities. As of December 31, 2008 and
October 31, 2009, the Predecessor had no significant
regulatory assets or liabilities.
Revenue
Recognition and the Estimation of Revenues and Cost of Natural
Gas
The Predecessor recognizes revenue when all of the following
criteria are met: (1) persuasive evidence of an exchange
arrangement exists, (2) delivery has occurred or services
have been rendered, (3) the price is fixed or determinable
and (4) collectibility is reasonably assured. The
Predecessor records revenue and cost of product sold on the
gross basis for those transactions where the Predecessor acted
as the principal and takes title to natural gas, natural gas
liquids (NGLs) or condensate that are purchased for
resale. When the Predecessors customers pay it a fee for
providing a service such as gathering, treating or
transportation the
F-38
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
Predecessor records those fees separately in revenues. For the
year and period ended December 31, 2008 and October 31
2009, respectively, the Predecessor had the following revenues
by category:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Period Ended
|
|
|
|
December 31,
|
|
|
October 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
Transportation firm
|
|
$
|
15,780
|
|
|
$
|
10,616
|
|
Transportation interruptible
|
|
|
2,331
|
|
|
|
1,662
|
|
Sales of natural gas, NGLs and condensate
|
|
|
348,034
|
|
|
|
129,673
|
|
Other
|
|
|
203
|
|
|
|
1,181
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
366,348
|
|
|
$
|
143,132
|
|
|
|
|
|
|
|
|
|
|
The Predecessor derives revenue in its business from the
following types of arrangements:
|
|
|
|
|
Fee-Based. Under these arrangements,
the Predecessor generally is paid a fixed cash fee for gathering
and transporting natural gas.
|
|
|
|
Percent-of-Proceeds,
or POP. Under these arrangements, the
Predecessor generally gathers raw natural gas from producers at
the wellhead or other supply points, transports it through the
Predecessors gathering system, processes it and sells the
residue natural gas and NGLs at market prices. Where the
Predecessor provides processing services at the processing
plants that it owns, or obtains processing services for its own
account under its elective processing arrangements, the
Predecessor typically retains and sells a percentage of the
residue natural gas and resulting NGLs.
|
|
|
|
Fixed-Margin. Under these arrangements,
the Predecessor purchases natural gas from producers or
suppliers at receipt points on the Predecessors systems at
an index price less a fixed transportation fee and
simultaneously sells an identical volume of natural gas at
delivery points on the Predecessors systems at the same,
undiscounted index price.
|
|
|
|
Firm Transportation. The
Predecessors obligation to provide firm transportation
service means that the Predecessor is obligated to transport
natural gas nominated by the shipper up to the maximum daily
quantity specified in the contract. In exchange for that
obligation on the Predecessors part, the shipper pays a
specified reservation charge, whether or not it utilizes the
capacity. In most cases, the shipper also pays a variable use
charge with respect to quantities actually transported by the
Predecessor.
|
|
|
|
Interruptible Transportation. The
Predecessors obligation to provide interruptible
transportation service means that the Predecessor is only
obligated to transport natural gas nominated by the shipper to
the extent that the Predecessor was available capacity. For this
service the shipper pays no reservation charge but pays a
variable use charge for quantities actually shipped.
|
Estimates
of Revenue and Cost of Natural Gas
The Predecessor must estimate its current month revenue and cost
of gas to permit the timely preparation of the combined
financial statements. The Predecessor generally cannot compile
actual billing information nor obtain actual vendor invoices
within a timeframe that would permit the recording of this
actual data prior to the preparation of the combined financial
statements. As a result, the Predecessor records an estimate
each month for its operating revenues and cost of natural gas
based on the best available volume and price data for natural
gas delivered and received, along with a
true-up of
the prior months estimate to equal the prior months
actual data. As a result there is one month of estimated data
reported in the Predecessors operating
F-39
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
revenues and cost of natural gas for each of the year ended
December 31, 2008. The operating revenues and cost of
natural gas for the ten months ended October 31, 2009
reflects actual invoiced amounts.
Cash
and Cash Equivalents
The Predecessor considers all highly liquid investments with an
original maturity of three months or less at the date of
purchase to be cash equivalents. The carrying value of cash and
cash equivalents approximates fair value because of the short
term to maturity of these investments.
Allowance
for Doubtful Accounts
The Predecessor establishes provisions for losses on accounts
receivable when it determines that it will not collect all or
part of an outstanding balance. Collectability is reviewed
regularly and an allowance is established or adjusted, as
necessary, using the specific identification method. As of
December 31, 2008 and October 31, 2009 the Predecessor
has recorded, $170,393 and $985,956, respectively, in allowances
for doubtful accounts.
Inventory
Inventory includes product inventory and material and supplies
inventory. The Entities records all product inventories at the
lower of its cost, as determined on a weighted average basis, or
market value. The product inventory consists of liquid
hydrocarbons and natural gas. Upon disposition, product
inventory is recorded to Purchases of natural gas,
NGLs and Condensate at the weighted average cost of
inventory, including any adjustments recorded to reduce
inventory to market value.
Operational
Balancing Agreements and Natural Gas Imbalances
To facilitate deliveries of natural gas and provide for
operational flexibility, the Predecessor has operational
balancing agreements in place with other interconnecting
pipelines. These agreements ensure that the volume of natural
gas a shipper schedules for transportation between two
interconnecting pipelines equals the volume actually delivered.
If natural gas moves between pipelines in volumes that are more
or less than the volumes the shipper previously scheduled, a
natural gas imbalance is created. The imbalances are settled
through periodic cash payments or repaid in-kind through receipt
or delivery of natural gas. Natural gas imbalances are recorded
as gas imbalances and classified within Other currents
assets on the Predecessors combined balance sheets
using the posted index prices, which approximate market rates,
or the Predecessors weighted average cost of natural gas.
Property,
Plant and Equipment
The Predecessor capitalizes expenditures related to property,
plant and equipment that have a useful life greater than one
year for 1) assets purchased or constructed;
2) existing assets that are replaced, improved, or the
useful lives of which have been extended; and 3) all land,
regardless of cost. Maintenance and repair costs, including any
planned major maintenance activities, are expensed as incurred.
The Predecessor records property, plant and equipment at its
original cost, which the Predecessor depreciates on a
straight-line basis over the lesser of its estimated useful life
or the estimated remaining lives. The Predecessors
determination of the useful lives of property, plant and
equipment requires the Predecessor to make various assumptions,
including the supply of and demand for hydrocarbons in the
markets served by the Predecessors assets, normal wear and
tear of the facilities, and the extent and frequency of
maintenance
F-40
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
programs. The Predecessor records depreciation using the group
method of depreciation which is commonly used by pipelines,
utilities and similar entities.
Impairment
of Long Lived Assets
The Predecessor evaluates the recoverability of its property,
plant and equipment when events or circumstances such as
economic obsolescence, business climate, legal and other factors
indicate the Predecessor may not recover the carrying amount of
the assets. The Predecessor continually monitors its businesses,
the market and business environment to identify indicators that
could suggest an asset may not be recoverable. The Predecessor
evaluates the asset for recoverability by estimating the
undiscounted future cash flows expected to be derived from
operating the asset as a going concern. These cash flow
estimates require the Predecessor to make projections and
assumptions for many years into the future for pricing, demand,
competition, operating cost, contract renewals, and other
factors. The Predecessor recognizes an impairment loss when the
carrying amount of the asset exceeds its fair value as
determined by quoted market prices in active markets or present
value techniques. The determination of the fair value using
present value techniques requires the Predecessor to make
projections and assumptions regarding future cash flows and
weighted average cost of capital. Any changes the Predecessor
makes to these projections and assumptions could result in
significant revisions to the Predecessors evaluation of
the recoverability of its property, plant and equipment and the
recognition of an impairment loss in its consolidated statements
of income. No impairment losses were recognized during the year
ended and period ended December 31, 2008 and
October 31, 2009, respectively.
The Predecessor assess its long-lived assets for impairment
using authoritative guidance. A long-lived asset is tested for
impairment whenever events or changes in circumstances indicate
its carrying amount may exceed its fair value. Fair values, for
the purposes of the impairment test, are based on the sum of the
undiscounted future cash flows expected to result from the use
and eventual disposition of the assets.
Examples of long-lived asset impairment indicators include:
|
|
|
|
|
A significant decrease in the market price of a long-lived asset
or group;
|
|
|
|
A significant adverse change in the extent or manner in which a
long-lived asset or asset group is being used or in its physical
condition;
|
|
|
|
A significant adverse change in legal factors or in the business
climate could affect the value of a long-lived asset or asset
group, including an adverse action or assessment by a regulator
which would exclude allowable costs from the rate-making process;
|
|
|
|
An accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of the
long-lived asset or asset group;
|
|
|
|
A current-period operating cash flow loss combined with a
history of operating cash flow losses or a projection or
forecast that demonstrates continuing losses associated with the
use of a long lived asset or asset group; and
|
|
|
|
A current expectation that, more likely than not, a long-lived
asset or asset group will be sold or otherwise disposed of
significantly before the end of its previously estimated useful
life.
|
Income
Taxes
All of the entities of the Entities are disregarded for
U.S. federal income tax purposes or for the majority of
states that impose an income tax. The Entities income tax
expense results from the enactment of state income tax laws by
the State of Texas that apply to entities organized as
partnerships. The Texas margin tax is
F-41
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
computed on our modified gross margin and was not significant
for each of the year ended December 31, 2008 and the period
ended October 31, 2009. The Predecessor has determined
these taxes to be income taxes as set forth in the authoritative
accounting guidance.
Commitments,
Contingencies and Environmental Liabilities
The Predecessor expenses or capitalizes, as appropriate,
expenditures for ongoing compliance with environmental
regulations that relate to past or current operations. The
Predecessor expenses amounts it incurs for remediation of
existing environmental contamination caused by past operations
that do not benefit future periods by preventing or eliminating
future contamination. It records liabilities for environmental
matters when assessments indicate that remediation efforts are
probable, and the costs can be reasonably estimated. Estimates
of environmental liabilities are based on currently available
facts, existing technology and presently enacted laws and
regulations, taking into consideration the likely effects of
inflation and other factors. These amounts also consider the
Predecessors prior experience in remediating contaminated
sites, other companies
clean-up
experience and data released by government organizations. Its
estimates are subject to revision in future periods based on
actual costs or new information. The Predecessor evaluates
recoveries from insurance coverage separately from the liability
and, when recovery is probable, it records and reports an asset
separately from the associated liability in its combined
financial statements.
The Predecessor recognizes liabilities for other commitments and
contingencies when, after fully analyzing the available
information, determines it is either probable that an asset has
been impaired, or that a liability has been incurred and the
amount of impairment or loss can be reasonably estimated. When a
range of probable loss can be estimated, it accrues the most
likely amount, or if no amount is more likely than another, it
accrues the minimum of the range of probable loss. The
Predecessor expenses legal costs associated with loss
contingencies as such costs are incurred.
Asset
Retirement Obligations (AROs)
AROs are legal obligations associated with the retirement of
tangible long-lived assets that result from the assets
acquisition, construction, development
and/or
normal operation. An ARO is initially measured at its estimated
fair value. Upon initial recognition of an ARO, the Predecessor
records an increase to the carrying amount of the related
long-lived asset and an offsetting ARO liability. The
Predecessor depreciates the capitalized ARO using the
straight-line method over the period during which the related
long-lived asset is expected to provide benefits. After the
initial period of ARO recognition, the Predecessor revises the
ARO to reflect the passage of time or revisions to the amounts
of estimated cash flows or their timing.
Group
Equity
The group equity balance represents a net balance reflecting the
Parents initial investment in Entities and subsequent
adjustments resulting from the operations of the Entities and
various transactions between the Parent and the Entities. Other
transactions affecting the group equity include general,
administrative and overhead costs incurred by the Parent that
are allocated to the Entities. There are no terms of settlement
or interest charges associated with the group equity balance.
|
|
2.
|
Concentration
of Credit Risk and Trade Accounts Receivable
|
The Predecessors primary market areas are located in the
United States along the Gulf Coast and in the Southeast. The
Predecessor has a concentration of trade receivable balances due
from companies engaged in the production, trading, distribution
and marketing of natural gas and NGL products. These
concentrations of customers may affect our overall credit risk
in that the customers may be similarly affected by changes in
F-42
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
economic, regulatory or other factors. The Predecessors
customers historical financial and operating information
is analyzed prior to extending credit. The Predecessor manages
its exposure to credit risk through credit analysis, credit
approvals, credit limits and monitoring procedures, and for
certain transactions, the Predecessor may request letters of
credit, prepayments or guarantees. The Predecessor maintains
allowances for potentially uncollectible accounts receivable.
As of December 31, 2008, ConocoPhillips Corporation and Dow
Hydrocarbons and Resources were significant customers,
representing at least 10% of the Predecessors combined
revenue, accounting for $40.5 million and
$44.2 million, respectively, of the Predecessors
combined revenue in the combined statement of operations for the
year then ended. As of October 31, 2009, ConocoPhillips
Corporation and Enbridge Marketing were significant customers,
representing at least 10% of the Predecessors combined
revenue, accounting for $18.5 million and
$40.4 million, respectively, of the Predecessors
combined revenue in the consolidated statement of operations for
the period then ended.
Other current assets as of December 31, 2008 and
October 31, 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Gas imbalance
|
|
$
|
76
|
|
|
$
|
530
|
|
Inventory
|
|
|
2,045
|
|
|
|
180
|
|
Other receivables
|
|
|
42
|
|
|
|
773
|
|
Regulatory deferrals
|
|
|
74
|
|
|
|
88
|
|
Other prepaid amounts
|
|
|
77
|
|
|
|
97
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,314
|
|
|
$
|
1,668
|
|
|
|
|
|
|
|
|
|
|
|
|
4.
|
Property,
Plant and Equipment, Net
|
Property, plant and equipment, net, as of December 31, 2008
and October 31, 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Useful Life
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
(in thousands)
|
|
|
Land
|
|
|
|
|
|
$
|
433
|
|
|
$
|
433
|
|
Rights-of-way
|
|
|
40
|
|
|
|
26,628
|
|
|
|
26,633
|
|
Pipelines
|
|
|
40
|
|
|
|
180,470
|
|
|
|
181,096
|
|
Compressors, meters and other operating equipment
|
|
|
20
|
|
|
|
25,821
|
|
|
|
28,182
|
|
Vehicles, office furniture and equipment
|
|
|
5
|
|
|
|
6,847
|
|
|
|
6,937
|
|
Processing and treating plants
|
|
|
40
|
|
|
|
30,009
|
|
|
|
32,306
|
|
Construction in progress
|
|
|
|
|
|
|
7,222
|
|
|
|
1,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
|
|
|
|
277,430
|
|
|
|
276,697
|
|
Accumulated depreciation
|
|
|
|
|
|
|
(60,527
|
)
|
|
|
(71,571
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
|
|
|
$
|
216,903
|
|
|
$
|
205,126
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For regulatory purposes, the Predecessors uses
FERC-approved depreciation rates to depreciate the regulated
pipeline assets of Enbridge Pipelines Midla L.L.C.
and Enbridge Pipelines AlaTenn L.L.C. Of
F-43
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
the gross property, plant and equipment balances at
December 31, 2008 and October 31, 2009
$102.4 million and $101.8 million, respectively,
related to regulated assets.
|
|
5.
|
Asset
Retirement Obligations (AROs)
|
No assets are legally restricted for purposes of settling the
Predecessors AROs for the year ended December 31,
2008 and the period ended October 31, 2009. Following is a
reconciliation of the beginning and ending aggregate carrying
amount of the Predecessors ARO liabilities for the year
ended December 31, 2008 and the period ended
October 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Balance at beginning of period
|
|
$
|
1,926
|
|
|
$
|
2,006
|
|
Accretion expense
|
|
|
80
|
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period
|
|
$
|
2,006
|
|
|
$
|
2,114
|
|
|
|
|
|
|
|
|
|
|
Other assets, net, as of December 31, 2008 and
October 31, 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Other post-retirement benefit plan assets, net
|
|
$
|
258
|
|
|
$
|
395
|
|
Deferred charges, net
|
|
|
128
|
|
|
|
123
|
|
Other
|
|
|
179
|
|
|
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
565
|
|
|
$
|
684
|
|
|
|
|
|
|
|
|
|
|
|
|
7.
|
Accrued
Expenses and Other Current Liabilities
|
Other current liabilities as of December 31, 2008 and
October 31, 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Accrued expenses
|
|
$
|
2,972
|
|
|
$
|
1,109
|
|
Property taxes payable
|
|
|
500
|
|
|
|
1,103
|
|
Environmental reserves
|
|
|
45
|
|
|
|
380
|
|
Deferred revenue
|
|
|
21
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,538
|
|
|
$
|
2,616
|
|
|
|
|
|
|
|
|
|
|
|
|
8.
|
Notes
Payable Affiliate
|
Short-term
Borrowings
Throughout 2008 and 2009, the Entities periodically entered into
certain short-term demand promissory notes with Enbridge
Midcoast Limited Holdings, L.L.C. (EMLH), a wholly
owned subsidiary of the Parent. At December 31, 2008 and
October 31, 2009, the outstanding balances of short-term
borrowings were $39.3 and $0 million, respectively. Prior
to March 2008, interest on these borrowings is charged at 130%
of the applicable federal rate as published by the U.S Treasury
(AFR). Subsequent to March 2008, interest on these
borrowings is charged at the greater of i) the London
Interbank Offering Rate (LIBOR), plus 100 basis
F-44
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
points or ii) 130% of the published AFR. The weighted
average interest rate on outstanding borrowings at
October 31, 2009 and December 31, 2008 was 1.36% and
3.59%, respectively.
Long-term
Borrowings
During 2004, the Entities entered into a series of promissory
notes with EMLH, totaling $65 million, with repayment of
the principal balance of these notes due on November 26,
2014 (the Notes). Interest on the Notes was paid
semiannually in May and November of each year. The capitalized
deferred costs of approximately $0.1 million and
$0.1 million as of December 31, 2008 and
October 31, 2009 associated with the issuance of this debt
are amortized over the ten year life of the Notes.
Debt
Extinguishment
On October 29, 2009, the Parent made a capital contribution
of $111.1 million to the Entities. A portion of the
proceeds of this contribution were used by the Entities to repay
in full the short-term borrowings and the Notes outstanding with
EMLH.
Financial
Covenants
There were no restrictive covenants associated with either the
short-term borrowings or the Notes.
|
|
9.
|
Post-Employment
Benefits
|
Post-Employment
Benefits Other Than Pensions
We sponsor a contributory postretirement plan that provides
medical, dental and life insurance benefits for qualifying
U.S. retired employees (referred to as the OPEB
Plan).
The tables below detail the changes in the benefit obligation,
the fair value of plan assets and the recorded asset or
liability of the OPEB Plan using the accrual method.
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Change in benefit obligation
|
|
|
|
|
|
|
|
|
Benefit obligation, January 1
|
|
$
|
642
|
|
|
$
|
741
|
|
Service cost
|
|
|
11
|
|
|
|
8
|
|
Interest cost
|
|
|
46
|
|
|
|
36
|
|
Actuarial (gain) loss
|
|
|
71
|
|
|
|
10
|
|
Benefits paid
|
|
|
(29
|
)
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
Benefit obligation, December 31, and October 31
|
|
$
|
741
|
|
|
$
|
771
|
|
|
|
|
|
|
|
|
|
|
F-45
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Change in plan assets
|
|
|
|
|
|
|
|
|
Fair value of plan assets, January 1
|
|
$
|
987
|
|
|
$
|
999
|
|
Actual return on plan assets
|
|
|
(72
|
)
|
|
|
123
|
|
Employers contributions
|
|
|
113
|
|
|
|
68
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
Benefits paid
|
|
|
(29
|
)
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets, December 31 and October 31
|
|
$
|
999
|
|
|
$
|
1,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Funded status
|
|
|
|
|
|
|
|
|
Funded status
|
|
$
|
258
|
|
|
$
|
395
|
|
Unrecognized actuarial gain
|
|
|
(339
|
)
|
|
|
(138
|
)
|
|
|
|
|
|
|
|
|
|
Prepaid (accrued) benefit cost, December 31 and October 31
|
|
$
|
(81
|
)
|
|
$
|
257
|
|
|
|
|
|
|
|
|
|
|
The amounts of plan assets and liabilities recognized in our
statements of financial position at December 31, 2008 and
October 31, 2009 are as follows:
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
|
Long term other assets
|
|
$
|
258
|
|
|
$
|
395
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
258
|
|
|
$
|
395
|
|
|
|
|
|
|
|
|
|
|
The amounts included in accumulated other comprehensive income
that have not yet been recognized as components of net periodic
benefit expense are $339,000 and $138,000 as of
December 31, 2008 and October 31, 2009, respectively.
F-46
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
Economic
Assumptions
The assumptions made in measurement of the projected benefit
obligations or assets of the OPEB Plan were as follows:
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2008
|
|
|
2009
|
|
|
Discount rate
|
|
|
6.00%
|
|
|
|
5.70%
|
|
Expected return on plan assets
|
|
|
4.50%
|
|
|
|
6.00%
|
|
Rate of compensation increase
|
|
|
5%
|
|
|
|
0%
|
|
Health care trend
|
|
|
Grade 9% to
5% over 5 years
|
|
|
|
Grade 9% to
5% over 5 years
|
|
|
|
|
|
|
|
|
|
|
A one percent increase in the assumed medical and dental care
trend rate would result in an increase of $0.1 million in
the accumulated post-employment benefit obligations. A one
percent decrease in the assumed medical and dental care trend
rate would result in a decrease of $0.1 million in the
accumulated post-employment benefit obligations.
The above table reflects the expected long-term rates of return
on assets of the OPEB Plan on a weighted-average basis. The
overall expected rates of return are based on the asset
allocation targets with estimates for returns on equity and debt
securities based on long term expectations. We believe this rate
approximates the return we will achieve over the long-term on
the assets of our plans. Historically, we have used a discount
rate that corresponds to one or more high quality corporate bond
indices as an estimate of our expected long-term rate of return
on plan assets for our OPEB Plan assets. For 2008 and 2009 we
selected the discount rate using the Citigroup Pension Discount
Curve, or CPDC. The CPDC spot rates represent the equivalent
yield on high-quality, zero-coupon bonds for specific
maturities. These rates are used to develop a single, equivalent
discount rate based on the OPEB Plans expected future cash
flows.
Expected
Future Benefit Payments
The following table presents the benefits expected to be paid in
each of the next five fiscal years, and in the aggregate for the
five years thereafter by the OPEB Plan:
|
|
|
|
|
|
|
Gross Benefit
|
|
|
|
Payments
|
|
For the year ending
|
|
OPEB Plan
|
|
|
|
(in thousands)
|
|
|
2011
|
|
$
|
56
|
|
2012
|
|
|
56
|
|
2013
|
|
|
55
|
|
2014
|
|
|
55
|
|
2015
|
|
|
55
|
|
Five years thereafter
|
|
|
235
|
|
The expected future benefit payments are based upon the same
assumptions used to measure the projected benefit obligations of
the OPEB Plan including benefits associated with future employee
service.
F-47
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
Expected
Contributions to the Plans
We expect to make contributions to the OPEB Plan for the year
ending December 31, 2010 of $0.1 million.
Plan
Assets
The weighted average asset allocation of our OPEB Plan at the
measurement date by asset category, are as follows:
|
|
|
|
|
|
|
|
|
|
|
OPEB Plan
|
|
|
|
2008
|
|
|
2009
|
|
|
Fixed income(1)
|
|
|
77.0%
|
|
|
|
77.0%
|
|
Cash and short-term assets(2)
|
|
|
23.0%
|
|
|
|
23.0%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100.0%
|
|
|
|
100.0%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
United States government securities, corporate bonds and notes
and asset-backed securities. |
|
(2) |
|
Cash and securities with maturities of one year or less. |
|
|
10.
|
Commitments
and Contingencies
|
The Predecessor is subject to federal and state laws and
regulations relating to the protection of the environment.
Environmental risk is inherent to natural gas pipeline
operations, and the Predecessor could, at times, be subject to
environmental cleanup and enforcement actions. The Predecessor
attempts to manage this environmental risk through appropriate
environmental policies and practices to minimize any impact the
Predecessors operations may have on the environment.
|
|
11.
|
Related
Party Transactions
|
The Predecessor was wholly owned by the Parent and its
subsidiaries. The Parent has allocated certain overhead costs
associated with general and administrative services, including
executive management, accounting, information services,
engineering, and human resources support to the Predecessor.
These overhead costs were allocated based primarily on a
percentage of revenue, which management of the Partnership
believes is reasonable.
Revenues,
Purchases and Cost Allocations
The Predecessor recorded operating revenues to Enbridge
affiliates for natural gas gathering, treating, processing,
marketing and transportation services. Included in the
Predecessors results for the year ended December 31,
2008 and period ended October 31, 2009, are operating
revenues $202.9 of million and $73.9 million, respectively,
related to these transactions.
The Predecessor also purchased natural gas from Enbridge
affiliates for sale to third-parties at market prices on the
date of purchase. Included in the Predecessors results for
the year ended December 31, 2008 and period ended
October 31, 2009, are costs for natural gas purchases of
$0.1 million and $0.9 million, respectively, related
to these purchases.
The Predecessor incurred expenses related to managerial,
administrative, operational and director services provided by
the Parent and its affiliates and the ultimate parent, Enbridge
pursuant to service agreements (referred to as Enbridge
cost allocations).
F-48
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
The Enbridge cost allocations were charged based on a
combination of fixed monthly fees for operations and allocations
for overhead costs, which were based primarily on the direct
salaries of the employees by department and by entity. The
allocation method has been consistently applied in the
statements of operations.
The total amount charged to the Predecessor for Enbridge cost
allocations for the year ended December 31, 2008 and period
ended October 31, 2009 was $7.9 million and
$6.7 million, respectively.
At December 31, 2008 and October 31, 2009, the
Predecessor had affiliate receivables of $21.0 million and
$34.4 million, respectively related to these transactions.
Financing
Transactions with Affiliates
Demand
Notes Receivable and Notes Payable
At December 31, 2008 and October 31, 2009, the
Predecessor had affiliate notes receivable of $26.9 and
$0 million, respectively, and affiliate notes payable of
$39.3 million and $0 million, respectively. For the
twelve months ended December 31, 2008 and ten months ended
October 31, 2009, the Predecessor had interest income of
$0.8 million and $0.4 million, respectively. Interest
expense for the twelve months ended December 31, 2008 and
ten months ended October 31, 2009 was $6.7 million and
$4.1 million, respectively.
Equity
Transactions
For the twelve months ended December 31, 2008 and the ten
months ended October 31, 2009, the Predecessor received
contributions by the Parent of $10.5 million and
$111.1 million, respectively, and paid distributions to the
Parent of $7.3 million and $25.8 million, respectively.
The Predecessors operations are located in the United
States and are organized into two reporting segments:
(1) Gathering and Processing; and (2) Transmission.
Gathering
and Processing
The Predecessors Gathering and Processing segment provides
wellhead to market services to producers of natural
gas and oil, which include transporting raw natural gas from the
wellhead through gathering systems, treating the raw natural
gas, processing raw natural gas to separate the NGLs and selling
or delivering pipeline quality natural gas and NGLs to various
markets and pipeline systems.
Transmission
The Predecessors Transmission segment transports and
delivers natural gas from producing wells, receipt points or
pipeline interconnects for shippers and other customers,
including local distribution companies, or LDCs, utilities and
industrial, commercial and power generation customers.
These segments are monitored separately by American Midstream
Partners, LP for performance and are consistent with internal
financial reporting. These segments have been identified based
on the differing products and services, regulatory environment
and the expertise required for these operations. Gross margin is
a performance measure utilized by the Predecessor to monitor the
business of each segment.
F-49
American
Midstream Partners Predecessor
Notes to Combined Financial
Statements (Continued)
December 31, 2008 and October 31, 2009 and
Year Ended December 31, 2008 and Period Ended
October 31, 2009
The following tables set forth the Predecessors segment
information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
|
|
|
|
|
|
|
|
|
|
and
|
|
|
|
|
|
|
Transmission
|
|
|
Processing
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
Year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
16,487
|
|
|
$
|
349,861
|
|
|
$
|
366,348
|
|
Segment gross margin(a)
|
|
$
|
15,789
|
|
|
$
|
27,354
|
|
|
$
|
43,143
|
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
|
|
13,423
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
8,618
|
|
Depreciation expense
|
|
|
|
|
|
|
|
|
|
|
13,481
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
5,747
|
|
Other (income) expense
|
|
|
|
|
|
|
|
|
|
|
(854
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
$
|
2,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering
|
|
|
|
|
|
|
|
|
|
and
|
|
|
|
|
|
|
Transmission
|
|
|
Processing
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
Period ended October 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
10,175
|
|
|
$
|
132,957
|
|
|
$
|
143,132
|
|
Segment gross margin(a)
|
|
$
|
9,881
|
|
|
$
|
20,024
|
|
|
$
|
29,905
|
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
|
|
10,331
|
|
Depreciation expense
|
|
|
|
|
|
|
|
|
|
|
8,577
|
|
Selling, general and administrative expense
|
|
|
|
|
|
|
|
|
|
|
12,630
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
3,728
|
|
Other (income) expense
|
|
|
|
|
|
|
|
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
$
|
(5,337
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Segment gross margin for our Gathering and Processing segment
consists of total revenue, less purchases of natural gas,
propane and NGLs. Segment gross margin for our Transmission
segment consists of total revenue, less purchases of natural
gas. Gross margin consists of the sum of the segment gross
margin amounts for each of these segments. As an indicator of
our operating performance, gross margin should not be considered
an alternative to, or more meaningful than, net income or cash
flow as determined in accordance with GAAP. Our gross margin may
not be comparable to a similarly titled measure of another
company because other entities may not calculate gross margin in
the same manner. |
Asset information by segment, including capital expenditures, is
not included in reports used by management of American Midstream
Partners, LP in its monitoring of performance and therefore, is
not disclosed.
F-50
APPENDIX B
Glossary
of Terms
Bbl: One stock tank barrel, or 42
U.S. gallons liquid volume, used in reference to oil or
other liquid hydrocarbons.
Bcf/d: One billion cubic feet per day.
condensate: A natural gas liquid with a
low vapor pressure, mainly composed of propane, butane, pentane
and heavier hydrocarbon fractions.
dry gas: A gas primarily composed of
methane and ethane where heavy hydrocarbons and water either do
not exist or have been removed through processing.
end-use markets: The ultimate users and
consumers of transported energy products.
FERC: Federal Energy Regulatory
Commission.
gal: One gallon.
gal/d: One gallon per day.
Mcf: One thousand cubic feet.
Mgal/d: One thousand gallons per day.
MMBbl/d: One million stock tank barrels
per day.
MMBtu: One million British Thermal
Units.
MMBtu/d: One million British Thermal
Units per day.
MMcf: One million cubic feet.
MMcf/d: One
million cubic feet per day.
NGA: Natural Gas Act of 1938.
NGLs: Natural gas liquids. The
combination of ethane, propane, normal butane, iso-butane and
natural gasolines that when removed from natural gas become
liquid under various levels of higher pressure and lower
temperature.
NYMEX: New York Mercantile Exchange.
OPIS: Oil Price Information Service.
play: A proven geological formation
that contains commercial amounts of hydrocarbons.
receipt point: The point where
production is received by or into a gathering system or
transportation pipeline.
residue gas: The natural gas remaining
after being processed or treated.
tailgate: Refers to the point at which
processed natural gas and natural gas liquids leave a processing
facility for end-use markets.
Tcf: One trillion cubic feet.
throughput: The volume of natural gas
transported or passing through a pipeline, plant, terminal or
other facility during a particular period.
wellhead: The equipment at the surface
of a well used to control the wells pressure; also, the
point at which the hydrocarbons and water exit the ground.
WTI: West Texas Intermediate, a type of
crude oil commonly used as a price benchmark.
B-1
Common Units
American Midstream Partners,
LP
Common Units
Representing Limited Partner Interests
PRELIMINARY PROSPECTUS
,
2011
BofA Merrill Lynch
Until ,
2011 (25 days after the date of this prospectus), all
dealers that buy, sell or trade shares of our common units,
whether or not participating in this offering, may be required
to deliver a prospectus. This is in addition to the
dealers obligation to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments or
subscriptions.
PART II
INFORMATION
NOT REQUIRED IN PROSPECTUS
|
|
Item 13.
|
Other
Expenses of Issuance and Distribution.
|
Set forth below are the expenses (other than underwriting
discounts, commissions and structuring fees) expected to be
incurred in connection with the issuance and distribution of the
securities registered hereby. With the exception of the SEC
registration fee, the FINRA filing fee and the NASDAQ listing
fee, the amounts set forth below are estimates.
|
|
|
|
|
SEC registration fee
|
|
$
|
8,708
|
|
FINRA filing fee
|
|
|
8,000
|
|
NASDAQ listing fee
|
|
|
*
|
|
Printing and engraving expenses
|
|
|
*
|
|
Fees and expenses of legal counsel
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Transfer agent and registrar fees
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
|
|
|
|
|
Total
|
|
|
*
|
|
|
|
|
|
|
|
|
|
* |
|
To be filed by amendment. |
|
|
Item 14.
|
Indemnification
of Directors and Officers.
|
American
Midstream Partners, LP
Subject to any terms, conditions or restrictions set forth in
the partnership agreement,
Section 17-108
of the Delaware Revised Uniform Limited Partnership Act empowers
a Delaware limited partnership to indemnify and hold harmless
any partner or other person from and against any and all claims
and demands whatsoever. The section of the prospectus entitled
The Partnership Agreement
Indemnification discloses that we will generally indemnify
officers, directors and affiliates of our general partner to the
fullest extent permitted by the law against all losses, claims,
damages or similar events and is incorporated herein by
reference.
The underwriting agreement to be entered into in connection with
the sale of the securities offered pursuant to this registration
statement, the form of which will be filed as an exhibit to this
registration statement, provides for indemnification of American
Midstream Partners, LP and our general partner, their officers
and directors, and any person who controls our general partner,
including indemnification for liabilities under the Securities
Act.
American
Midstream GP, LLC
Subject to any terms, conditions or restrictions set forth in
the limited liability company agreement,
Section 18-108
of the Delaware Limited Liability Company Act empowers a
Delaware limited liability company to indemnify and hold
harmless any member or manager or other person from and against
any and all claims and demands whatsoever.
Under the limited liability agreement of our general partner, in
most circumstances, our general partner will indemnify the
following persons, to the fullest extent permitted by law, from
and against any and all losses, claims, damages, liabilities
(joint or several), expenses (including legal fees and
expenses), judgments, fines, penalties, interest, settlements or
other amounts arising from any and all claims, demands, actions,
suits or proceedings (whether civil, criminal, administrative or
investigative):
|
|
|
|
|
any person who is or was an affiliate of our general partner
(other than us and our subsidiaries);
|
II-1
|
|
|
|
|
any person who is or was a member, partner, officer, director,
employee, agent or trustee of our general partner or any
affiliate of our general partner;
|
|
|
|
any person who is or was serving at the request of our general
partner or any affiliate of our general partner as an officer,
director, employee, member, partner, agent, fiduciary or trustee
of another person; and
|
|
|
|
any person designated by our general partner.
|
Our general partner will purchase insurance covering its
officers and directors against liabilities asserted and expenses
incurred in connection with their activities as officers and
directors of our general partner or any of its direct or
indirect subsidiaries.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities.
|
On November 4, 2009, in connection with our formation, we
issued (i) 200,000 general partner units representing a
2.0% general partner interest in us and all of our incentive
distribution rights to our general partner in exchange for
$2.0 million and (ii) 9,800,000 common units
representing a 98.0% limited partner interest in us to AIM
Midstream Holdings in exchange for $98.0 million. These
transactions were exempt from registration under
Section 4(2) of the Securities Act.
On September 27, 2010, we issued (i) 10,000 general
partner units to our general partner in exchange for $100,000
and (ii) 490,000 common units to AIM Midstream Holdings in
exchange for $4.9 million. These transactions were exempt
from registration under Section 4(2) of the Securities Act.
On November 3, 2010, we issued (i) 14,000 general
partner units to our general partner in exchange for $140,000
and (ii) 686,000 common units to AIM Midstream Holdings in
exchange for $6.9 million. These transactions were exempt
from registration under Section 4(2) of the Securities Act.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules.
|
The following documents are filed as exhibits to this
registration statement:
II-2
|
|
|
|
|
Number
|
|
Description
|
|
|
1
|
.1*
|
|
Form of Underwriting Agreement
|
|
3
|
.1
|
|
Certificate of Limited Partnership of American Midstream
Partners, LP
|
|
3
|
.2
|
|
Amended and Restated Agreement of Limited Partnership of
American Midstream Partners, LP
|
|
3
|
.3*
|
|
Form of Second Amended and Restated Agreement of Limited
Partnership of American Midstream Partners, LP
|
|
3
|
.4
|
|
Certificate of Formation of American Midstream GP, LLC
|
|
3
|
.5
|
|
Amended and Restated Limited Liability Company Agreement of
American Midstream GP, LLC
|
|
3
|
.6*
|
|
Form of Second Amended and Restated Limited Liability Company
Agreement of American Midstream GP, LLC
|
|
5
|
.1*
|
|
Opinion of Andrews Kurth LLP as to the legality of the
securities being registered
|
|
8
|
.1*
|
|
Opinion of Andrews Kurth LLP relating to tax matters
|
|
10
|
.1*
|
|
Revolving and Term Loan Credit Agreement, dated as of
October 5, 2009, by and among American Midstream, LLC, as
the initial borrower, Comerica Bank, as the administrative
agent, BBVA Compass Bank, as the documentation agent and
Comerica Bank and BBVA Compass Bank as co-lead arrangers.
|
|
10
|
.2*
|
|
First Amendment to Revolving and Term Loan Credit Agreement,
dated effective as of October 5, 2009, among American
Midstream, LLC, American Midstream Marketing, LLC, American
Midstream (Alabama Gathering), LLC, American Midstream (Alabama
Intrastate), LLC, American Midstream (Alatenn), LLC, American
Midstream (Midla), LLC, American Midstream (Mississippi), LLC,
American Midstream (Tennessee River), LLC, American Midstream
Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC,
American Midstream (Louisiana Intrastate), LLC, American
Midstream (Sigco Intrastate), LLC and American Midstream
Offshore (Seacrest) LP, as borrowers, the Lenders named therein,
and Comerica Bank, as administrative agent.
|
|
10
|
.3*
|
|
Second Amendment and Waiver to Revolving and Term Loan Credit
Agreement, dated July 30, 2010, among American Midstream,
LLC, American Midstream Marketing, LLC, American Midstream
(Alabama Gathering), LLC, American Midstream (Alabama
Intrastate), LLC, American Midstream (Alatenn), LLC, American
Midstream (Midla), LLC American Midstream (Mississippi), LLC,
American Midstream (Tennessee River), LLC, American Midstream
Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC,
American Midstream (Louisiana Intrastate), LLC, American
Midstream (Sigco Intrastate), LLC And American Midstream
Offshore (Seacrest) LP, the Lenders named therein), and Comerica
Bank, as administrative agent.
|
|
10
|
.4*
|
|
Advisory Services Agreement, dated as of October 2, 2009,
by and between American Midstream, LLC, American Infrastructure
MLP Management, L.L.C., American Infrastructure MLP PE
Management, L.L.C. and American Infrastructure MLP Associates
Management, L.L.C.
|
|
10
|
.5*
|
|
Investors Rights Agreement, dated as of October 30,
2009, by and among AIM Midstream Holdings, LLC AIM Midstream
LLC, American Infrastructure MLP Fund, L.P., American
Infrastructure MLP Private Equity Fund, L.P., American
Infrastructure MLP Associates Fund and Stockwell Fund II,
L.P.
|
|
10
|
.6*
|
|
Employment Agreement, dated November 2, 2009, by and
between American Midstream GP, LLC and Brian Bierbach.
|
|
10
|
.7*
|
|
Employment Agreement, dated November 2, 2009, by and
between American Midstream GP, LLC and Marty W. Patterson.
|
|
10
|
.8*
|
|
Employment Agreement, dated November 2, 2009, by and
between American Midstream GP, LLC and John J. Connor.
|
|
10
|
.9*
|
|
Amended and Restated American Midstream GP, LLC Long-Term
Incentive Plan
|
|
10
|
.10*
|
|
Form of Phantom Unit Grant under American Midstream GP, LLC
Long-Term Incentive Plan.
|
|
10
|
.11*
|
|
Membership Interests Purchase and Sale Agreement, dated as of
October 2, 2009, by and between Enbridge Midcoast Energy,
L.P. and American Midstream, LLC
|
|
10
|
.12*
|
|
Gas Processing Agreement, dated July 1, 2010, by and
between American Midstream, LLC and Enterprise Gas Processing,
LLC.
|
II-3
|
|
|
|
|
Number
|
|
Description
|
|
|
10
|
.13*
|
|
Gas Processing Agreement, dated November 1, 2010, by and
between American Midstream, LLC and Enterprise Gas Processing,
LLC.
|
|
21
|
.1
|
|
List of Subsidiaries of American Midstream Partners, LP
|
|
23
|
.1
|
|
Consent of PricewaterhouseCoopers LLP
|
|
23
|
.2
|
|
Consent of PricewaterhouseCoopers LLP
|
|
23
|
.3*
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
|
|
23
|
.4*
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
|
|
24
|
.1
|
|
Powers of Attorney (contained on the signature page to this
Registration Statement)
|
|
|
|
* |
|
To be filed by amendment. |
The undersigned registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting
agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing
provisions, or otherwise, the registrant has been advised that
in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event
that a claim for indemnification against such liabilities (other
than the payment by the registrant of expenses incurred or paid
by a director, officer or controlling person of the registrant
in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant
will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in
the Securities Act and will be governed by the final
adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the
Securities Act, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective.
(2) For the purpose of determining any liability under the
Securities Act, each post-effective amendment that contains a
form of prospectus shall be deemed to be a new registration
statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
The undersigned registrant undertakes to send to each common
unitholder, at least on an annual basis, a detailed statement of
any transactions with American Midstream GP, our general
partner, or its affiliates, and of fees, commissions,
compensation and other benefits paid, or accrued to American
Midstream GP or its affiliates for the fiscal year completed,
showing the amount paid or accrued to each recipient and the
services performed.
The undersigned registrant undertakes to provide to the common
unitholders the financial statements required by
Form 10-K
for the first full fiscal year of operations of the company.
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, the registrant has duly caused this Registration
Statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Houston, State of
Texas, on March 30, 2011.
American Midstream Partners, LP
|
|
|
|
By:
|
American
Midstream GP, LLC
its general partner
|
|
|
|
|
By:
|
/s/ Brian F. Bierbach
Name: Brian
F. Bierbach
|
|
|
|
|
Title:
|
Chief Executive Officer and President
|
Each person whose signature appears below appoints Brian F.
Bierbach and William B. Mathews, and each of them, any of whom
may act without the joinder of the other, as his true and lawful
attorneys-in-fact and agents, with full power of substitution
and re-substitution, for him and in his name, place and stead,
in any and all capacities, to sign any and all amendments
(including post-effective amendments) to this Registration
Statement and any Registration Statement (including any
amendment thereto) for this offering that is to be effective
upon filing pursuant to Rule 462(b) under the Securities
Act of 1933, as amended, and to file the same, with all exhibits
thereto, and all other documents in connection therewith, with
the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and
authority to do and perform each and every act and thing
requisite and necessary to be done in connection therewith, as
fully to all intents and purposes as he might or could do in
person, hereby ratifying and confirming all that said
attorneys-in-fact and agents, or any of them, or their or his
substitute and substitutes, may lawfully do or cause to be done
by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as
amended, this Registration Statement has been signed by the
following persons in the capacities and the dates indicated.
II-5
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Brian
F. Bierbach
Brian
F. Bierbach
|
|
Chief Executive Officer and President (Principal Executive
Officer) and Director
|
|
March 30, 2011
|
|
|
|
|
|
/s/ Sandra
M. Flower
Sandra
M. Flower
|
|
Vice President of Finance
(Principal Financial Officer and Principal Accounting Officer)
|
|
March 30, 2011
|
|
|
|
|
|
/s/ Robert
B. Hellman
Robert
B. Hellman
|
|
Director
|
|
March 30, 2011
|
|
|
|
|
|
/s/ Matthew
P. Carbone
Matthew
P. Carbone
|
|
Director
|
|
March 30, 2011
|
|
|
|
|
|
/s/ Edward
O. Diffendal
Edward
O. Diffendal
|
|
Director
|
|
March 30, 2011
|
|
|
|
|
|
/s/ L.
Kent Moore
L.
Kent Moore
|
|
Director
|
|
March 30, 2011
|
|
|
|
|
|
/s/ David
L. Page
David
L. Page
|
|
Director
|
|
March 30, 2011
|
II-6
EXHIBIT
INDEX
|
|
|
|
|
Number
|
|
Description
|
|
|
1
|
.1*
|
|
Form of Underwriting Agreement
|
|
3
|
.1
|
|
Certificate of Limited Partnership of American Midstream
Partners, LP
|
|
3
|
.2
|
|
Amended and Restated Agreement of Limited Partnership of
American Midstream Partners, LP
|
|
3
|
.3*
|
|
Form of Second Amended and Restated Agreement of Limited
Partnership of American Midstream Partners, LP
|
|
3
|
.4
|
|
Certificate of Formation of American Midstream GP, LLC
|
|
3
|
.5
|
|
Amended and Restated Limited Liability Company Agreement of
American Midstream GP, LLC
|
|
3
|
.6*
|
|
Form of Second Amended and Restated Limited Liability Company
Agreement of American Midstream GP, LLC
|
|
5
|
.1*
|
|
Opinion of Andrews Kurth LLP as to the legality of the
securities being registered
|
|
8
|
.1*
|
|
Opinion of Andrews Kurth LLP relating to tax matters
|
|
10
|
.1*
|
|
Revolving and Term Loan Credit Agreement, dated as of
October 5, 2009, by and among American Midstream, LLC, as
the initial borrower, Comerica Bank, as the administrative
agent, BBVA Compass Bank, as the documentation agent and
Comerica Bank and BBVA Compass Bank as co-lead arrangers.
|
|
10
|
.2*
|
|
First Amendment to Revolving and Term Loan Credit Agreement,
dated effective as of October 5, 2009, among American
Midstream, LLC, American Midstream Marketing, LLC, American
Midstream (Alabama Gathering), LLC, American Midstream (Alabama
Intrastate), LLC, American Midstream (Alatenn), LLC, American
Midstream (Midla), LLC, American Midstream (Mississippi), LLC,
American Midstream (Tennessee River), LLC, American Midstream
Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC,
American Midstream (Louisiana Intrastate), LLC, American
Midstream (Sigco Intrastate), LLC and American Midstream
Offshore (Seacrest) LP, as borrowers, the Lenders named therein,
and Comerica Bank, as administrative agent.
|
|
10
|
.3*
|
|
Second Amendment and Waiver to Revolving and Term Loan Credit
Agreement, dated July 30, 2010, among American Midstream,
LLC, American Midstream Marketing, LLC, American Midstream
(Alabama Gathering), LLC, American Midstream (Alabama
Intrastate), LLC, American Midstream (Alatenn), LLC, American
Midstream (Midla), LLC American Midstream (Mississippi), LLC,
American Midstream (Tennessee River), LLC, American Midstream
Onshore Pipelines, LLC, Mid Louisiana Gas Transmission, LLC,
American Midstream (Louisiana Intrastate), LLC, American
Midstream (Sigco Intrastate), LLC And American Midstream
Offshore (Seacrest) LP, the Lenders named therein), and Comerica
Bank, as administrative agent.
|
|
10
|
.4*
|
|
Advisory Services Agreement, dated as of October 2, 2009,
by and between American Midstream, LLC, American Infrastructure
MLP Management, L.L.C., American Infrastructure MLP PE
Management, L.L.C. and American Infrastructure MLP Associates
Management, L.L.C.
|
|
10
|
.5*
|
|
Investors Rights Agreement, dated as of October 30,
2009, by and among AIM Midstream Holdings, LLC AIM Midstream
LLC, American Infrastructure MLP Fund, L.P., American
Infrastructure MLP Private Equity Fund, L.P., American
Infrastructure MLP Associates Fund and Stockwell Fund II,
L.P.
|
|
10
|
.6*
|
|
Employment Agreement, dated November 2, 2009, by and
between American Midstream GP, LLC and Brian Bierbach.
|
|
10
|
.7*
|
|
Employment Agreement, dated November 2, 2009, by and
between American Midstream GP, LLC and Marty W. Patterson.
|
|
10
|
.8*
|
|
Employment Agreement, dated November 2, 2009, by and
between American Midstream GP, LLC and John J. Connor.
|
|
10
|
.9*
|
|
Amended and Restated American Midstream GP, LLC Long-Term
Incentive Plan
|
|
10
|
.10*
|
|
Form of Phantom Unit Grant under American Midstream GP, LLC
Long-Term Incentive Plan.
|
|
10
|
.11*
|
|
Membership Interests Purchase and Sale Agreement, dated as of
October 2, 2009, by and between Enbridge Midcoast Energy,
L.P. and American Midstream, LLC
|
|
10
|
.12*
|
|
Gas Processing Agreement, dated July 1, 2010, by and
between American Midstream, LLC and Enterprise Gas Processing,
LLC.
|
|
10
|
.13*
|
|
Gas Processing Agreement, dated November 1, 2010, by and
between American Midstream, LLC and Enterprise Gas Processing,
LLC.
|
|
|
|
|
|
Number
|
|
Description
|
|
|
21
|
.1
|
|
List of Subsidiaries of American Midstream Partners, LP
|
|
23
|
.1
|
|
Consent of PricewaterhouseCoopers LLP
|
|
23
|
.2
|
|
Consent of PricewaterhouseCoopers LLP
|
|
23
|
.3*
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
|
|
23
|
.4*
|
|
Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
|
|
24
|
.1
|
|
Powers of Attorney (contained on the signature page to this
Registration Statement)
|
|
|
|
* |
|
To be filed by amendment |