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SXE > SEC Filings for SXE > Form 10-K on 15-Apr-2013All Recent SEC Filings

Show all filings for SOUTHCROSS ENERGY PARTNERS, L.P. | Request a Trial to NEW EDGAR Online Pro



Annual Report

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion of our historical consolidated financial condition and results of operations that is intended to help the reader understand our business, results of operations and financial condition. It should be read in conjunction with other sections of this report, including our historical consolidated financial statements and accompanying notes thereto included in Part II-Item 8 of this report.

This Management's Discussion and Analysis and Financial Condition and Results of Operations includes the following sections:

Overview and How We Evaluate our Operations

Current Year Highlights

Results of Operations

Liquidity and Capital Resources

Off-Balance Sheet Arrangements

Contractual Obligations

Critical Accounting Estimates

New Accounting Pronouncements

Overview and How We Evaluate our Operations


Southcross Energy Partners, L.P. (the "Partnership," "Southcross," the "Company", "we", "our" or "us"), which closed its initial public offering ("IPO") on November 7, 2012, is a Delaware limited partnership formed in April 2012. Southcross Energy LLC is a Delaware limited liability company, and Southcross Energy LLC is our predecessor for accounting purposes (the "Predecessor"). References in this Form 10-K to the Partnership or the Company, when used for periods prior to the IPO, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership or the Company, when used for periods beginning at or following the IPO, refer collectively to the Partnership and its consolidated subsidiaries. This report reflects the consolidated assets, liabilities, results of operations and cash flows of Southcross Energy Partners, L.P. beginning November 7, 2012 and Southcross Energy LLC for periods ending prior to November 7, 2012.

The Partnership provides natural gas gathering, processing, treating, compression and transportation services and natural gas liquid ("NGL") fractionation and transportation services for its producer customers. We also source, purchase, transport and sell natural gas and NGLs to our power generation, industrial and utility customers. Our assets are located in South Texas, Mississippi and Alabama and as of December 31, 2012 include three gas processing plants, two NGL fractionation plants and approximately 2,700 miles of pipeline. Our South Texas assets operate in or within close proximity to the Eagle Ford shale region. Our assets are strategically positioned to provide transportation of natural gas and NGLs to power generation, industrial and utility customers as well as to unaffiliated intrastate and interstate pipelines. The Partnership is a midstream natural gas company and operates as one reportable segment.

Industry Conditions and Trends

Our business environment and corresponding operating results are affected by 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

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to be incorrect, our actual results may vary materially from our expected results. Key trends that we monitor while managing our business include natural gas supply and demand dynamics overall and in our markets as well as growth production from U.S. shale plays, with specific attention on the Eagle Ford shale region.

A critical component of energy supply and demand in the United States is natural gas. Recently, the price of natural gas has been at relatively low levels. The primary driver behind this trend is increased production, especially from unconventional sources, such as natural gas shale plays, high levels of natural gas in storage and warm winter weather.

According to the U.S. Energy Information Administration, average annual natural gas production in the United States increased significantly from 2008 through 2011 with modest growth of natural gas consumption over the same period, thereby increasing storage. According to the Texas Railroad Commission, well permits increased from 2011 to 2012 in the Eagle Ford shale region by approximately 47% from 2,826 to 4,143 permitted.

We believe that growth opportunities for our business through increased demand for natural gas are likely to occur, especially as there is continued increased use of natural gas production in locations such as the Eagle Ford shale region.

Our Operations

Our integrated operations provide a full range of complementary services from wellhead to market, including gathering natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, transporting natural gas and NGLs on our pipeline, processing natural gas to separate the NGLs from the natural gas, fractionating the resulting NGLs into the various components and selling or delivering pipeline quality natural gas and NGLs to various industrial and energy markets as well as interstate pipeline systems. Through our network of pipelines, we connect our suppliers of natural gas to our customers, which include local distribution companies, and industrial, commercial and power generation customers.

Our results are determined primarily by the volumes of natural gas we gather and process, the efficiency of our processing plants and NGL fractionation plants, the commercial terms of our contractual arrangements, natural gas and NGL prices, and our operations and maintenance expense. We manage our business to attempt to maximize the gross operating margin we earn from contracts balanced against any risks we assume in our contracts. Our contracts vary in duration from one month to ten years and the pricing under our contracts varies depending upon several factors, including our competitive position, our acceptance of risks associated with longer-term contracts and our desire to recoup over the term of the contract any capital expenditures that we are required to incur in order to provide service to our customers. We purchase, gather, process, transport and sell natural gas and purchase, fractionate, and sell NGLs primarily pursuant to the following arrangements:

Fixed-Fee. We receive a fixed-fee per unit of natural gas volume that we gather at the wellhead, process, treat, compress and/or transport for our customers, or we receive a fixed-fee per unit of NGL volume that we fractionate. Some of our arrangements also provide for a fixed-fee for guaranteed transportation capacity on our systems.

Fixed-Spread. Under these arrangements, we purchase natural gas and NGLs from producers or suppliers at receipt points off our systems at an index price plus or minus a fixed price differential and sell these volumes of natural gas and NGLs at delivery points on our systems at the same index price, plus or minus a fixed price differential. By entering into such back-to-back purchases and sales, we are able to mitigate our risk associated with changes in the general commodity price levels of natural gas and NGLs. We remain subject to variations in our fixed-spreads to the extent we are unable to precisely match volumes purchased and sold in a given

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time period or are unable to secure the supply or to produce or market the necessary volume of products at our anticipated differentials to the index price.

Commodity-Sensitive. In exchange for our processing services, we may remit to a customer a percentage of the proceeds from our sales, or a percentage of the physical volume, of residue natural gas and/or NGLs that result from our natural gas processing, or we may purchase NGLs from customers at set fixed NGL recoveries and retain the balance of the proceeds or physical commodity for our own account. These arrangements are generally combined with fixed-fee and fixed-spread arrangements for processing services and, therefore, represent only a portion of a processing contract's value. The revenues we receive from these arrangements directly correlate with fluctuating general commodity price levels of natural gas and NGLs and the volume of NGLs recovered relative to the fixed recovery obligations.

We assess gross operating margin opportunities across our integrated value stream, so that processing margins may be supplemented by gathering and transportation fees and opportunities to sell residue gas at fixed-spreads. Gross operating margin earned under fixed-fee and fixed-spread arrangements is directly related to the volume of natural gas that flows through our systems and is generally independent from general commodity price levels. A sustained decline in commodity prices could result in a decline in volumes entering our system and, thus, a decrease in gross operating margin for our fixed-fee and fixed-spread arrangements.

Below is a table summarizing our contract mix (in thousands):

                                             Year ended December 31,
                            2012                       2011                       2010
                              Percent of                 Percent of                 Percent of
                                 total                      total                      total
                                 gross                      gross                      gross
                   Gross       operating      Gross       operating      Gross       operating
                   margin       margin        margin       margin        margin       margin
 Fixed-fee        $ 48,055            67.0 % $ 32,340            51.7 % $ 27,541            46.4 %
 Fixed-spread       18,737            26.2 %   14,544            23.2 %   15,521            26.2 %

 Sub-total          66,792            93.2 %   46,884            74.9 %   43,062            72.6 %
 sensitive           4,848             6.8 %   15,685            25.1 %   16,254            27.4 %

 Total gross
 margin           $ 71,640           100.0 % $ 62,569           100.0 % $ 59,316           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 quarterly basis for consistency and trend analysis. These performance metrics include (i) volume, (ii) gross operating margin, (iii) operations and maintenance expenses, (iv) Adjusted EBITDA and (v) distributable cash flow.

Volume-We determine and analyze volumes by operating unit, but report overall volumes after elimination of intercompany deliveries. The volume of natural gas and NGLs on our systems depends on the level of production from natural gas wells connected to our systems and also from wells connected with other pipeline systems that are interconnected with our systems.

Gross Operating Margin-Gross operating margin of our contracts is one of the metrics we use to measure and evaluate our performance. Gross operating margin is not a measure calculated in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We define gross operating margin as the sum of contract revenues less the cost of natural gas and NGLs sold. For our fixed-fee contracts, we record the fee as revenue and there is no offsetting cost of

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natural gas and NGLs sold. For our fixed-spread and commodity-sensitive arrangements, we record as revenue all of our proceeds from the sale of the natural gas or NGLs and record as an expense the associated cost of natural gas and NGLs sold.

Operations and Maintenance Expense-Our management seeks to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, and contract services comprise the most significant portion of our operations and maintenance expense. These expenses are relatively stable and largely independent of volumes delivered through our systems, but may fluctuate depending on the activities performed during a specific period.

Adjusted EBITDA and Distributable Cash Flow-We believe that Adjusted EBITDA is a widely accepted financial indicator of our operational performance and ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is not a measure calculated in accordance with GAAP, as it does not include deductions for items such as depreciation, amortization, interest and income taxes, which may be necessary to maintain the business. We define Adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation and amortization expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges and transaction costs 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. Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP.

Adjusted EBITDA is used as a supplemental measure 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 the Partnership's indebtedness and make future cash distributions;

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 distributable cash flow as Adjusted EBITDA plus interest income, less cash paid for interest expense, taxes and maintenance capital expenditures and use distributable cash flow to analyze our performance. Distributable cash flow does not reflect changes in working capital balances.

Distributable cash flow is used to assess:

the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Non-GAAP Financial Measures

Gross operating 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 provides useful information to investors in assessing our financial condition and results of

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operations. Net income is the GAAP measure most directly comparable to each of gross operating margin and Adjusted EBITDA. The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Our non-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 each excludes some but not all items that affect the most directly comparable GAAP financial measure. You should not consider any of gross operating margin, Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross operating 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.

Reconciliations of Non-GAAP financial Measures

The following table presents a reconciliation of gross operating margin to net (loss) income (in thousands):

                                                    Year ended December 31,
                                                 2012        2011        2010
       Gross operating margin                  $  71,640   $  62,569   $  59,316
       Add (deduct):
       Income tax expense                           (246 )      (261 )        (1 )
       Interest expense                           (5,767 )    (5,348 )   (10,013 )
       Loss on extinguishment of debt             (1,764 )    (3,240 )         -
       General and administrative expense        (13,842 )    (9,129 )    (7,490 )
       Depreciation and amortization expense     (18,977 )   (12,345 )   (10,987 )
       Operations and maintenance expense        (35,532 )   (24,707 )   (21,106 )

       Net (loss) income                       $  (4,488 ) $   7,539   $   9,719

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The following table presents a reconciliation of net cash flows provided by operating activities to net (loss) income, Adjusted EBITDA, and distributable cash flow (in thousands):

                                                         Year ended December 31,
                                                      2012        2011        2010
  Net cash flows provided by operating activities   $  24,323   $  20,007   $  25,493
  Add (deduct):
  Depreciation and amortization expense               (18,977 )   (12,345 )   (10,987 )
  Unit-based compensation                                (630 )         -           -
  Loss on extinguishment of debt                       (1,764 )    (3,240 )         -
  Deferred financing costs amortization                (1,183 )      (882 )    (2,158 )
  Gain on sales of plant, property and equipment            -         522          13
  Unrealized derivatives loss                            (141 )       (21 )         -
  Changes in operating assets and liabilities:
  Trade accounts receivable                             9,760       2,806      (4,897 )
  Prepaid expenses and other                            1,246         497        (560 )
  Other non-current assets                             (1,786 )     2,155        (158 )
  Accounts payable and accrued expenses               (16,517 )    (2,759 )     3,836
  Accrued expenses and other liabilities                1,181         799        (863 )

  Net (loss) income                                 $  (4,488 ) $   7,539   $   9,719

  Add (deduct):
  Depreciation and amortization expense                18,977      12,345      10,987
  Interest expense                                      5,767       5,348      10,013
  Unrealized derivatives loss                             141          21           -
  Loss on extinguishment of debt                        1,764       3,240           -
  Unit-based compensation                                 630           -           -
  Transaction costs                                         -         203         149
  Income tax expense                                      246         261           1
  Management fees                                         568           -           -
  Expenses associated with significant items              414           -           -

  Adjusted EBITDA                                   $  24,019   $  28,957   $  30,869

  Add (deduct):
  Cash interest, net                                   (4,584 )    (4,466 )    (7,855 )
  Income tax expense                                     (246 )      (261 )        (1 )
  Maintenance capital expenditures                     (5,193 )    (5,317 )    (3,402 )

  Distributable cash flow                           $  13,996   $  18,913   $  19,611

Current Year Highlights

The following events took place during 2012 and in early 2013 and have impacted or are likely to impact our financial condition and results of operations. The following should be read in conjunction with Part I, Item 1., "Business" of this report for a more detailed account of such events.

Financing Activities

In connection with the closing of the IPO:

Our General Partner conveyed a limited liability company interest in Southcross Operating to the Partnership in exchange for (i) 498,518 general partner units in the Partnership representing

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a continuation of its 2.0% general partner interest; and (ii) the Partnership's incentive distribution rights ("IDRs");

Southcross Energy LLC conveyed its remaining interest in Southcross Operating to the Partnership in exchange for (i) 1,863,713 common units (after the underwriters fully exercised their option to purchase additional common units on November 26, 2012 (the "Over-Allotment Option")) representing a 7.5% limited partner interest (ii) 12,213,713 subordinated units representing a 49.0% limited partner interest,
(iii) the Partnership's assumption of Southcross Energy LLC's outstanding debt under its credit agreement, (iv) the right to receive $7.5 million sourced from new debt the Partnership incurred and
(v) the right to receive $38.5 million in cash, a portion of which was used to reimburse Southcross Energy LLC for certain capital expenditures it incurred with respect to the contributed assets;

The Partnership issued 10,350,000 common units to the public including the exercise of the Over-Allotment Option, and received $187.8 million in net proceeds from the IPO, net of underwriters' discount and commissions, structuring fees, and IPO costs. These proceeds plus borrowings under the Partnership's $350.0 million senior secured credit facility with Wells Fargo Bank, N.A., and a syndicate of lenders (the "Senior Secured Credit Facility") were used to repay the outstanding debt of $270.0 million under Southcross Energy LLC's pre-existing credit agreement;

The Partnership may utilize its senior secured credit facility for working capital requirements and capital expenditures, the purchase of assets, the payment of distributions, repurchase of units and general purposes of the Partnership. For a complete description of Long-Term Debt, see Part II, Item 8, "Financial Statements and Supplementary Data-Notes to the Financial Statements-Note 6-Long-Term Debt".

Key Factors Affecting Operating Results and Financial Condition

Bonnie View NGL fractionation facility. In November 2012 we commenced operations and in February 2013, we completed the expansion of our NGL capacity at our Bonnie View fractionation facility increasing its capacity to 22,500 Bbls/d. The plant initiated operations with capacity of 11,500 Bbls/d. The plant fractionates y-grade NGLs produced at our Woodsboro processing plant and produces NGL component products.

Bonnie View startup lost revenue and expenses. During the start-up of our Bonnie View fractionation facility in the fourth quarter of 2012, we experienced periods of reduced recoveries and production of off-specification NGLs, which forced us to sell some products at reduced prices or leave NGLs in the natural gas stream and sell them at natural gas equivalent prices.

Bee Line gas pipeline commences operations. The Bee Line pipeline commenced gas deliveries in the fourth quarter of 2012 after partial completion of the pipeline. In February 2013, we completed construction of the 20-inch pipeline to move rich gas to our Woodsboro processing plant. The Bee Line is a 57-mile pipeline with capacity of 320 MMcf/d.

Gregory processing and NGL fractionation facility. Our Gregory facility includes 135 MMcf/d of gas processing capacity and an associated 4,800 barrels per day NGL fractionation facility. We commenced a turnaround maintenance project in November 2012 and we shut in this plant in January 2013 to perform extensive turnaround maintenance activities and connect additional equipment to enhance NGL recoveries. As the turnaround maintenance was nearing completion on January 26, 2013, we experienced a fire at this facility. Damage was limited to a small portion of the facility and we completed repairs and resumed operations during April 2013.

Formosa shut down and curtailment. In the third quarter of 2012, Formosa shut down its plant for 34 days. In addition, we were curtailed by approximately 518,748 MMBtu and 1,316,214 MMBtu

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of gas processing volumes by Formosa in the third and fourth quarter of 2012, respectively. Also Formosa adjusted ethane and propane recoveries to our detriment and in violation of our contract in the third quarter of 2012 and again in the fourth quarter of 2012.

Public company costs. We incurred significantly more general and administrative expenses in 2012 as a result of preparing to become and becoming a publicly traded master limited partnership in November 2012.

New facility operating costs. We incurred significantly more operations and maintenance costs associated with the startup of our Woodsboro and Bonnie View facilities in 2012.

As discussed above, during the fourth quarter 2012 and into first quarter 2013 we encountered operational difficulties related to a startup of our new Bonnie View NGL fractionator, curtailments and other actions by our third-party processor, and a fire on January 26, 2013 at our Gregory facility that prolonged the shutdown of the facility. We believe these items are now largely behind us. We completed the expansion of our Bonnie View NGL fractionator in February 2013. In addition, our Gregory facility became fully operational in April 2013 after repairing damage caused by the fire. These items, however, adversely impacted our operating results in the fourth quarter of 2012 and into the first quarter of 2013. As a result of this negative impact, we believed it was unlikely that we would be in compliance with our financial covenants calculated for the quarter ending March 31, 2013, such that we negotiated with our lenders and secured more favorable financial covenants and amended our Credit Facility. As a result of the amendments and after giving effect of the equity infusion and its use to repay debt on April 12, 2013, we have $27.2 million of borrowing capacity under our amended Credit Facility. Consequently, we believe we have and will continue to have sufficient liquidity to operate our business as the amended Credit Facility provides us with more favorable financial covenants than were provided previously and we believe these more favorable terms will allow us to operate our business and continue to meet our commitments. Please read "Liquidity and Capital Resources-Long-Term Debt" for a description of the . . .

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