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AMID > SEC Filings for AMID > Form 10-K on 16-Apr-2013All Recent SEC Filings

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Form 10-K for AMERICAN MIDSTREAM PARTNERS, LP


16-Apr-2013

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 by affiliates of 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, fractionating and transporting natural gas through our ownership and operation of ten gathering systems, four processing facilities, two interstate pipelines and four intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, 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 600 MMcf/d of natural gas.
Significant financial highlights during the year ended December 31, 2012, include the following:
Our distributable cash flow for the year ended December 31, 2012 was $9.6 million. We distributed $16.1 million to our unitholders or $1.73 per unit.

For the year ended December 31, 2012, gross margin increased to $50.6 million or 10.2% compared to the same period in 2011;

The Partnership acquired an 87.4% interest in the Chatom processing and fractionation plant and associated gathering infrastructure (the "Chatom system") from affiliates of Quantum Resources Management, LLC, effective July 1, 2012, for approximately $51.4 million; and

The Partnership amended its August 2011 credit facility to increase the borrowing capacity from $100 million to $200 million with a syndicate of eight banks led by Bank of America, N.A., as Administrative Agent, Collateral Agent, L/C Issuer and Lender.

Significant operational highlights and challenges during the year ended December 31, 2012, include the following:
Throughput attributable to American Midstream Partners, LP totaled 697.8 MMcf/d for the year, representing a 10.4% increase compared to the same period in 2011;

Certain assets were impacted by Hurricane Isaac, the negative financial impact for which was approximately $3.0 million. A portion of this amount related to foregone cash flows resulting from production curtailments immediately following the hurricane, and the remainder resulted from costs incurred to repair the damaged assets during the third and fourth quarters of 2012. The Partnership is insured for named windstorms on the affected assets after a $1.0 million deductible. The gathering and processing volumes associated with the assets that were damaged during Hurricane Isaac have returned to pre-hurricane levels;

The Partnership completed a scheduled turnaround of its Bazor Ridge processing plant in eastern Mississippi. The turnaround took longer than anticipated as a result of unscheduled repairs and upgrades that slowed the turnaround process but are expected to deliver long-term, improved efficiencies at the plant. The negative financial impact of the turnaround in the fourth quarter was approximately $1.1 million; and

The Partnership saw a decline in volumes on one of its offshore pipeline systems during the third and fourth quarters of 2012 as a result of a producer's work on one of its platforms. The Partnership continues to work with this producer to negotiate the return of incremental volumes to the offshore pipeline system, although the contract terms may change for the incremental volumes going forward and a change in contract terms may have a material negative impact on financial results. While the Partnership expects the incremental volumes to return during the first half of 2013, the reduced volumes during the third and fourth quarters of 2012 resulted in a negative financial impact of approximately $2.0 million.

Our Operations
We manage our business and analyze and report our results of operations through
two 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 local
             distribution companies ("LDCs"), utilities and industrial,
             commercial and power generation customers.

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 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
             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 87.4% undivided
             interest in the Chatom system pursuant to 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 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:
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.


Contract Mix
Set forth below is a table summarizing our average contract mix for the years
ended December 31, 2012 and 2011:

                                             For the Year Ended                       For the Year Ended
                                             December 31, 2012                        December 31, 2011
                                          Segment            Percent of            Segment            Percent of
                                           Gross               Segment              Gross               Segment
                                           Margin           Gross Margin            Margin           Gross Margin
                                       (in millions)                            (in millions)
Gathering and Processing
Fee based                          $           8.7                23.6 %    $           9.3                28.6 %
Fixed Margin                                   2.5                 6.6 %                4.1                12.6 %
Percent-of-Proceeds                           26.0                69.8 %               19.1                58.8 %
Total                              $          37.2               100.0 %    $          32.5               100.0 %
Transmission
Firm transportation                $          10.8                81.2 %    $          10.4                75.9 %
Interruptible transportation                   1.9                14.3 %                2.1                15.3 %
Fixed margin                                   0.6                 4.5 %                1.2                 8.8 %
Total                              $          13.3               100.0 %    $          13.7               100.0 %

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 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 capacity reservation fees, as opposed to the actual 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.
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.
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 non-recurring, 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 non-recurring. 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. Distributable Cash Flow
Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial


measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). Distributable cash flow will not reflect changes in working capital balances.
We define distributable cash flow as adjusted EBITDA plus interest income, less cash paid for interest expense, normalized integrity management costs and normalized maintenance capital expenditures. The GAAP measure most directly comparable to distributable cash flow is net cash flows from operating activities.
Note About Non-GAAP Financial Measures
Gross margin, adjusted EBITDA and distributable cash flows are all 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, 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. For a reconciliation of segment gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 19 to our audited consolidated financial statements included in this Form 10-K.
The following tables reconcile the non-GAAP financial measures, adjusted EBITDA and distributable cash flow used by management to their most directly comparable GAAP measures:


                                                            For the Year Ended
                                                               December 31,
                                                   2012            2011            2010
                                                              (in thousands)
Reconciliation of Adjusted EBITDA to Net
Income (Loss)
Net income (loss) attributable to the          $    (6,508 )   $   (11,698 )   $    (8,644 )
Partnership
Add:
Depreciation and accretion expense                  21,414          20,705          20,013
Interest expense                                     3,875           4,508           5,406
Debt issuance costs                                  1,564               -               -
Realized loss on early termination of                    -           2,998               -
commodity derivatives
Realized loss on commodity put purchase costs            -             308               -
Unrealized (gain) loss on commodity                   (992 )           541               -
derivatives
Non-cash equity compensation expense                 1,783           1,607           1,185
Advisory services agreement termination fee              -           2,500               -
Special distribution to holders of LTIP                  -           1,624               -
phantom units
Transaction expenses                                     -             282             303
Deduct:
COMA income                                          3,373             879               -
Straight-line amortization of put costs (1)            291             409               -
OPEB plan net periodic benefit (cost)                   88              82               -
Gain (loss) on acquisition of assets                     -             565               -
Gain (loss) on involuntary conversion of            (1,021 )             -               -
property, plant and equipment
Gain (loss) on sale of assets, net                     128             399               -
Adjusted EBITDA                                $    18,277     $    21,041     $    18,263
Deduct:
Cash interest expense (2)                            3,854           3,246           4,591
Normalized maintenance capital (3)                   3,828           3,083           2,623
Normalized integrity management (4)                  1,007           1,500           1,500
Distributable Cash Flow                        $     9,588     $    13,212     $     9,549

(1) Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract.

(2) Excludes amortization of debt issuance costs and mark-to-market adjustments related to interest rate derivatives.

(3) Amounts noted represent estimated annual maintenance capital expenditures of $3.8 million for the year ended December 31, 2012 which is what we expect to be required to maintain our assets over the long term.

(4) Amounts noted represent average estimated integrity management costs over the seven year mandatory testing cycle net of integrity management costs that are expensed in Selling, general and administrative expenses.

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:
After our initial public offering, we began incurring 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 NYSE; 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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