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AMID > SEC Filings for AMID > Form 10-K on 11-Mar-2014All Recent SEC Filings

Show all filings for AMERICAN MIDSTREAM PARTNERS, LP

Form 10-K for AMERICAN MIDSTREAM PARTNERS, LP


11-Mar-2014

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the audited consolidated financial statements and the related notes thereto included elsewhere in this Form 10-K. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption "Cautionary Statement Regarding Forward-Looking Statements."
Overview

We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of gathering, treating, processing, fractionating and transporting natural gas through our ownership and operation of eleven gathering systems, two processing facilities, one fractionation facility, four terminal sites, three interstate pipelines and five intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Recently, we became an owner, developer and operator of petroleum, agricultural, and chemical liquid terminal storage facilities. Our primary assets, which are strategically located in Alabama, Georgia, Louisiana, Maryland, Mississippi, Tennessee and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas and NGL markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 2,100 miles of pipelines that gather and transport approximately 1 Bcf/d of natural gas and operate approximately 1.3 million barrels of storage capacity across four marine terminal sites.

Significant financial highlights during the year ended December 31, 2013, include the following:


For the year ended December 31, 2013, gross margin increased to $76.6 million or 57.3% compared to the same period in 2012;

Incremental gross margin of $7.8 million, included in the increase disclosed above, for the year ended December 31, 2013, was a result of the Blackwater Acquisition, which represented a transaction between entities under common control and a change in reporting entity. Therefore we have accounted for Blackwater and our Terminals segment as if the transaction occurred April 15, 2013. Please read "Recent Events" below for more information;

We distributed $13.2 million to our limited partner unitholders, or $1.75 per unit, for the year ended December 31, 2013 as compared to $1.73 per unit for the same period in 2012;

We completed the Equity Restructuring. Please read "Recent Events" below for more information. On September 30, 2013, we received approximately $12.5 million from HPIP, which was used to repay outstanding borrowings under the credit agreement in connection with the Equity Restructuring;

We issued, in a public offering, 2,568,712 common units representing limited partner interests in the Partnership at a price to the public of $22.47 per common unit. We used the net proceeds of $54.9 million to fund a portion of the purchase price for Blackwater; and

On January 24, 2013, we entered into the second waiver to the credit facility that extended the waiver period with respect to the consolidated total leverage ratio to April 16, 2013. Through amendments and repayments of borrowings, we are in compliance with the consolidated total leverage ratio as of December 31, 2013. As of December 31, 2013, we had approximately $130.7 million of outstanding borrowings and approximately $64.5 million of available borrowing capacity.

Significant operational highlights during the year ended December 31, 2013, include the following:
Throughput attributable to the Partnership totaled 921.9 MMcf/d for the year ended December 31, 2013, representing a 33.6% increase compared to the same period in 2012;

Average gross condensate production totaled 46.2 Mgal/d for the year ended December 31, 2013, representing a 104.4% increase compared to the same period in 2012;

Average gross NGL production totaled 52.0 Mgal/d for the year ended December 31, 2013, representing a 4.2% increase compared to the same period in 2012; and

Effective April 15, 2013, our General Partner contributed the High Point System, consisting of 100% of the limited liability company interests in High Point Gas Transmission, LLC and High Point Gas Gathering, LLC. The High Point System consists of approximately 700 miles of natural gas and liquids pipeline assets located in southeast Louisiana, in the Plaquemines and St. Bernard parishes, and the shallow water and deep shelf Gulf of Mexico, including the Mississippi Canyon, Viosca Knoll, West Delta, Main Pass, South Pass and Breton Sound zones.

Our Operations
We manage our business and analyze and report our results of operations through
three business segments:
            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 various
             receipt points through gathering systems, treating the raw natural
             gas, processing raw natural gas to separate the NGLs from the
             natural gas, fractionating NGLs, and selling or delivering
             pipeline-quality natural gas as well as 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, which include LDCs,
             utilities and industrial, commercial and power generation customers.


            Terminals. Our Terminals segment provides above-ground storage
             services at our marine terminals that support various commercial
             customers, including commodity brokers, refiners and chemical
             manufacturers to store a range of products, including crude oil,
             bunker fuel, distillates, chemicals and agricultural products.


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 natural gas, NGL and condensate
prices. We gather and process gas primarily pursuant to the following
arrangements:
            Fee-Based Arrangements. Under these arrangements, we generally are
             paid a fixed cash fee for gathering and processing and transporting
             natural gas.


            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.


            Percent-of-Proceeds Arrangements ("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, NGLs and condensate at
             market prices. Where we provide processing services at the
             processing plants that we own, or obtain processing services for our
             own account in connection with our elective processing arrangements,
             such as under our Toca contract, we generally retain and sell a
             percentage of the residue natural gas and resulting NGLs. However,
             we also have contracts under which we retain a percentage of the
             resulting NGLs and do not retain a percentage of residue natural
             gas, such as for our interest in the Burns Point Plant. Our POP
             arrangements also often contain a fee-based component.


            Interest in the Burns Point Plant. We account for our interest in
             the Burns Point Plant using the proportionate consolidation method.
             Under this method, we include in our consolidated statement of
             operations, our value of plant revenues taken in-kind and plant
             expenses reimbursed to the operator.


            Interest in the Chatom System. We account for our 92.2% undivided
             interest in the Chatom system pursuant to Accounting Standards
             Clarification ("ASC") No. 810-10-65-1, Noncontrolling Interests.
             Under this method, revenues, expenses, gains, losses, net income or
             loss, and other comprehensive income are reported in the
             consolidated financial statements at the consolidated amounts, which
             include the amounts attributable to the partners' and the
             noncontrolling interests. The consolidated income statement shall
             separately present net income attributable to the partners' and the
             noncontrolling interests.

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 POP 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 POP 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 by capacity reservation fees from firm transportation contracts and 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:

            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 the shipper utilizes the capacity. In most cases, the
             shipper also pays a variable-use charge with respect to quantities
             actually transported by us.


            Interruptible Transportation Arrangements. 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.


            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.

Terminals Segment

In our Terminals segment, we generally receive fee-based compensation on guaranteed firm storage contracts and throughput fees charged to our customers when their products are either received or disbursed along with other operational charges associated with ancillary services provided to our customers, such as excess throughput, truck weighing, etc. The terms of our firm storage contracts are multiple years, with renewal options. Contract Mix
Set forth below is a table summarizing our average contract mix for the years ended December 31, 2013 and 2012 (in millions):

                                           For the Year Ended                    For the Year Ended
                                            December 31, 2013                     December 31, 2012
                                         Segment          Percent of           Segment          Percent of
                                          Gross             Segment             Gross             Segment
                                         Margin          Gross Margin          Margin          Gross Margin
Gathering and Processing
Fee-based                          $        7.0                19.1 %    $        8.5                24.0 %
Fixed margin                                1.6                 4.5 %             1.9                 5.4 %
Percent-of-proceeds                        27.9                76.4 %            25.0                70.6 %
Total                              $       36.5               100.0 %    $       35.4               100.0 %
Transmission
Firm transportation                $       10.6                32.6 %    $       10.8                81.2 %
Interruptible transportation               21.7                67.0 %             1.9                14.3 %
Fixed margin                                0.1                 0.4 %             0.6                 4.5 %
Total                              $       32.4               100.0 %    $       13.3               100.0 %
Terminals (a)
Firm storage                       $        7.8               100.0 %    $          -                   - %
Total                              $        7.8               100.0 %    $          -                   - %

(a) Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.

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 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 work-overs 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 and interruptible capacity reservation fees from throughput volumes on our interstate and intrastate pipelines. Substantially all Transmission 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.


In our Terminals segment, throughput fees are charged to our customers when their products are either received or disbursed along with other operational charges associated with ancillary services; such as excess throughput, truck weighing, etc.
Gross Margin and Segment Gross Margin
Gross margin and segment gross margin are metrics that we use to evaluate our performance. 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. 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.
We define segment gross margin in our Terminals segment as revenue generated from fee-based compensation on guaranteed firm storage contracts and throughput fees charged to our customers less direct operating expense which includes direct labor, general materials and supplies and direct overhead.
We define gross margin as the sum of our segment gross margin for our Gathering and Processing, Transmission and Terminals segments. The GAAP measure most comparable to gross margin is net income.
Effective January 1, 2011, we changed our gross margin and segment gross margin measure to exclude unrealized mark-to-market adjustments related to our commodity derivatives. For the year ended December 31, 2011, $0.5 million of unrealized losses was excluded from gross margin and the Gathering and Processing segment gross margin.
Effective April 1, 2011, we changed our gross margin and segment gross margin measure to exclude realized gains and losses associated with the early termination of commodity derivative contracts. For the year ended December 31, 2011, $3.0 million in such realized losses was excluded from gross margin and the Gathering and Processing segment gross margin.
Effective October 1, 2012, we changed our segment gross margin measure to exclude construction, operating and maintenance agreement ("COMA") income. For the year ended December 31, 2012, $0.7 million and $2.7 million in COMA income was excluded from our Gathering and Processing segment gross margin and our Transmission segment gross margin, respectively. Direct Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. 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
Adjusted EBITDA is a measure used by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, 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 unit holders 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.

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 nonrecurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, amortization of commodity put purchase costs, and selected gains that are unusual or nonrecurring. The GAAP measure most directly comparable to adjusted EBITDA is net income.


We changed our calculation of adjusted EBITDA for 2011 to include the straight-line amortization of commodity put premiums over the life of the associated commodity put contracts. This is necessary as all unrealized commodity gains and losses, by definition, are excluded in calculating adjusted EBITDA and such premium costs would only be included in the calculation of adjusted EBITDA at the expiration of the put contract. We believe this treatment better reflects the allocation of commodity put premium costs over the benefit period of the commodity put contract. Commodity put premium amortization included in the calculation of adjusted EBITDA was $0.4 million for the year ended December 31, 2011. Further, we made a change to the calculation to exclude COMA income from adjusted EBITDA. COMA income excluded from adjusted EBITDA for the year ended December 31, 2011, was $0.9 million. Note About Non-GAAP Financial Measures
Gross margin and adjusted EBITDA are non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management's decision-making process.
You should not consider any of gross margin or adjusted EBITDA in isolation or as a substitute for or more meaningful than analysis of our results as reported under GAAP. Gross margin and adjusted EBITDA 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.
The following table reconciles the non-GAAP financial measures of gross margin used by management to Net (loss) income attributable to the Partnership, their most directly comparable GAAP measure, for each of the three years ended December 31, 2013 (in thousands):


                                                       For the Year ending December 31,
                                                    2013              2012            2011
Reconciliation of Gross Margin to Net loss
attributable to the Partnership
Gathering and processing segment gross margin  $     36,464       $    35,393     $    30,123
Transmission segment gross margin                    32,408            13,313          13,737
Terminals segment gross margin (a)                    7,751                 -               -
Total gross margin                                   76,623            48,706          43,860
Plus:
Gain (loss) on commodity derivatives                     28             3,400          (5,450 )
Less:
Direct operating expenses (b)                        27,473            16,798          11,419
Selling, general and administrative expenses         21,402            14,309          11,082
Advisory services agreement termination fee               -                 -           2,500
Transaction expenses                                      -                 -               -
Equity compensation expense                           2,094             1,783           3,357
Depreciation, amortization and accretion
expense                                              29,999            21,284          20,449
Gain on acquisition of assets                             -                 -            (565 )
(Gain) loss on involuntary conversion of
property, plant and equipment                          (343 )           1,021               -
Gain on sale of assets                                    -              (123 )          (399 )
Loss on impairment of property, plant and
equipment                                            18,155                 -               -
Interest expense                                      9,291             4,570           4,508
Other, net (c)                                          226              (965 )        (1,911 )
Income tax benefit                                     (495 )               -               -
Income (loss) from operations of disposal
groups, net of tax                                    2,255              (319 )          (332 )
Net income attributable to noncontrolling
interest                                                633               256               -
Net loss attributable to the Partnership       $    (34,039 )     $    (6,508 )   $   (11,698 )

(a) Terminals segment amounts are for the period from April 15, 2013 to December 31, 2013.

(b) Direct operating expenses includes Gathering and Processing segment direct operating expenses of $14.2 million and Transmission segment direct operating expenses of $13.3 million for the year ended December 31, 2013. Direct operating expenses related to our Terminals segment of $2.1 million are included within the calculation of Terminals segment gross margin.

(c) Other, net includes realized gain (loss) on commodity derivatives of $1.1 million, $2.4 million and $(1.9) million and COMA income of $0.8 million, $3.4 million and zero for the year ended December 31, 2013, 2012 and 2011, respectively.


                                                       For the Year Ended December 31,
. . .
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