Southcross Energy Partners 8-K Other Events

EXHIBIT 99.4

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.

Overview and How We Evaluate our Operations

Overview

Southcross Energy Partners, L.P. (the "Partnership," "Southcross," "we," "our" or "us") is a Delaware limited partnership formed in April 2012. Southcross Energy LLC is a Delaware limited liability company, and the predecessor for accounting purposes (the "Predecessor") of the Partnership. References in this Form 10-K to the Partnership, when used for periods prior to our initial public offering ("IPO") on November 7, 2012, refer to Southcross Energy LLC and its consolidated subsidiaries, unless otherwise specifically noted. References in this Form 10-K to the Partnership, when used for periods beginning at or following our IPO, refer collectively to the Partnership and its consolidated subsidiaries. Until August 4, 2014, Southcross Energy LLC held all of the equity interests in Southcross Energy Partners GP, LLC, a Delaware limited liability company and our general partner (“General Partner”), all of our subordinated units, as well as a portion of our common units and Series A Convertible Preferred Units (“Series A Preferred Units”). Southcross Energy LLC is controlled through investment funds and entities associated with Charlesbank Capital Partners, LLC (“Charlesbank”).

On August 4, 2014, Southcross Energy LLC and TexStar Midstream Services, LP (“TexStar”) combined pursuant to a contribution agreement in which Southcross Holdings LP, a Delaware limited partnership (“Holdings”), was formed (the “Holdings Transaction”). As a result of the Holdings Transaction, Holdings indirectly owns 100% of our General Partner (and therefore controls us), all of our subordinated units and a portion of our common units. Charlesbank, EIG Global Energy Partners, LLC (“EIG”) and Tailwater Capital LLC (“Tailwater”) (collectively, the “Sponsors”) each indirectly own approximately one-third of Holdings. Affiliates of Energy Capital Partners Mezzanine Opportunities Fund and GE Energy Financial Services own certain additional ownership interests in Holdings as well.

On May 7, 2015, we acquired gathering, treating, compression and transportation assets (the “2015 Holdings Acquisition”) from Holdings and its subsidiaries consisting of the Valley Wells sour gas gathering and treating system (the "Valley Wells System"), compression assets that are part of the Valley Wells and Lancaster gathering and treating systems (the "Compression Assets") and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Because of the common control aspects in the 2015 Holdings Acquisition, the 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction. The acquired NGL pipelines were accounted for as an asset acquisition and will be included in the historical financial statements beginning on May 7, 2015. As a carve-out transaction, the 2015 Holdings Acquisition has no cash accounts. As such, accounts receivable and accounts payable, along with certain other assets and liabilities that would be settled in cash, were the rights and obligations of Holdings as of December 31, 2014. Given their nature and the fact that carve-out financial statements are meant to represent an entity’s operations as if it had existed as of the time common control occurred, we have presented these amounts as third-party receivables and payables.

We are a master limited partnership that provides natural gas gathering, processing, treating, compression and transportation services and NGL fractionation and transportation services. We also source, purchase, transport and sell natural gas and NGLs. Our assets are located in South Texas, Mississippi and Alabama and include four gas processing plants, two fractionation facilities and approximately 3,041 miles of pipeline. We are headquartered in Dallas, Texas.

See Note 2 to our consolidated financial statements for a discussion of our liquidity.

General Trends and Outlook

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 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.

1

Natural Gas and NGL Environment

According to the U.S. Energy Information Administration (the “EIA”) natural gas production in the United States reached its highest recorded annual total in 2014 and is expected to increase from over 74 billion cubic feet per day (“Bcf/d”) on average in 2014 to over 78 Bcf/d on average in 2016, with almost all of the growth coming from shale formations. In 2007, shale gas wells made up approximately 9% of total natural gas produced in the U.S. By the end of 2014, shale gas wells accounted for nearly half of U.S. natural gas production. Natural gas production from shale formations in seven U.S. regions including the Eagle Ford, Permian, Haynesville, Niobrara, Bakken, Utica and Marcellus regions, accounted for 100% of domestic natural gas production growth from 2011 to 2013. The continued growth in shale gas production is expected to result from the dual application of horizontal drilling and hydraulic fracturing. Another contributing factor is ongoing drilling in shale and other plays with high concentrations of NGLs and crude oil, which in energy-equivalent terms, have a higher value than dry natural gas.

The EIA projects that U.S. natural gas consumption will increase to an average of 73.8 Bcf/d in 2015 and 74.8 Bc/d in 2016, compared with an estimated 73.6 Bcf/d in 2014. The growth in consumption is expected to be driven largely by the industrial and electric power sectors. Major consumers of natural gas in the United States in 2014 included the electric power generation sector with consumption of 22.7 Bcf/d, the industrial sector with 25.3 Bcf/d, the residential sector with 12.5 Bcf/d and 8.7 Bcf/d from the commercial sector. Growing domestic natural gas production is expected to reduce demand for imports from Canada and spur exports to Mexico. EIA expects exports to Mexico, particularly from the Eagle Ford Shale in South Texas, to increase because of growing demand from Mexico’s electric power sector coupled with flat Mexican natural gas production.

In certain regions where the economics of natural gas production are less favorable, some natural gas producers have cut back or suspended their drilling operations as a result of the current low natural gas price environment. Drilling activities focused in liquids-rich regions have continued at better rates than dry gas regions as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.

Average daily gas production in the Eagle Ford Shale in South Texas reached 6.6 Bcf/d on average in 2014, 25% higher than in 2013. The Eagle Ford Shale accounted for approximately 7.3 Bcf/d of U.S. natural gas production in December 2014, an increase of approximately 1.7 Bcf/d from December 2013. According to the EIA, average rig count in the Eagle Ford Shale region in 2014 increased by 2 rigs or approximately 1% to 288 rigs while the average gas production per rig increased by approximately 10% to approximately 1.4 MMcf/d. The outpaced growth in natural gas production relative to the increase in rig count primarily reflects increased drilling productivity including enhanced drilling and recovery techniques. EIA expects that increases in drilling efficiency and growth in oil production will continue to support growing natural gas production in the coming years.

The current depressed natural gas, NGL and crude oil price environment could negatively affect the level of natural gas, NGL and crude oil production which in turn could negatively impact the volume of natural gas flowing on our system.

We expect that the continued long term environment for natural gas demand will be favorable, driven by population, economic growth and the export market, as well as the continued replacement of coal electricity generation by natural gas electricity generation due to the low prices of natural gas and stricter governmental and environmental regulations on the mining and burning of coal.

According to EIA forecasts, the United States will become a net exporter of liquid natural gas (“LNG”) in 2016. U.S. exports of LNG from new liquefaction capacity are expected to average 0.8 Bcf/d in 2016.

Interest rate environment

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. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. The current depressed natural gas, NGL and crude oil price environment could also negatively affect our ability to access the debt capital markets. Although these risk factors could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as we believe our competitors would likely face similar circumstances.

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Our Operations

Our integrated operations provide a full range of complementary services extending from wellhead to market, including gathering natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, processing natural gas to separate NGLs from natural gas, fractionating NGLs into the various components and selling or delivering pipeline quality natural gas, y-grade and purity product NGLs to various industrial and energy markets as well as large pipeline systems. Through our network of pipelines, we connect supplies of natural gas to our customers, which include industrial, commercial and power generation customers and local distribution companies. All of our operations are managed as and presented in one reportable segment.

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 with the goal 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 several 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 to provide service to our customers. We purchase, gather, process, treat, compress, transport and sell natural gas and purchase, fractionate, transport and sell NGLs. Contracts with a counterparty generally contain one or more of 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 on 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 off 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 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, 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 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 and NGLs 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.

The following table summarizes our gross operating margins from these arrangements (in thousands):

	Year Ended December 31,
	2014				2013				2012
	Gross Operating Margin		%		Gross Operating Margin		%		Gross Operating Margin		%
Fixed-fee	$	90,758	71.2	%	$	59,532	63.7	%	$	48,055	67.0	%
Fixed-spread	9,009		7.1	%	11,143		11.9	%	18,737		26.2	%
Sub-total	99,767		78.3	%	70,675		75.6	%	66,792		93.2	%
Commodity-sensitive	27,614		21.7	%	22,871		24.4	%	4,848		6.8	%
Total gross operating margin	$	127,381	100.0	%	$	93,546	100.0	%	$	71,640	100.0	%

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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 quarterly basis for consistency and trend analysis. These performance metrics include (a) volume, (b) gross operating margin, (c) operations and maintenance expense, (d) Adjusted EBITDA and (e) 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 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 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 and 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 and distributable cash flow are widely accepted financial indicators of our operational performance and our ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA and distributable cash flow are not measures calculated in accordance with GAAP.

We define Adjusted EBITDA as net income/loss, plus interest expense, income tax expense, depreciation and amortization expense, equity in losses of joint venture investments, certain non-cash charges (such as non-cash unit-based compensation, impairments, loss on extinguishment of debt and unrealized losses on derivative contracts), major litigation costs net of recoveries, transaction-related costs, revenue deferral adjustment, loss on sale of assets and selected charges that are unusual or non-recurring; less interest income, income tax benefit, unrealized gains on derivative contracts, equity in earnings of joint venture investments 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 our 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 investment opportunities.

We define distributable cash flow as Adjusted EBITDA, plus interest income and income tax benefit, less cash paid for interest (net of capitalized costs), income tax expense and maintenance capital expenditures. We use distributable cash flow to analyze our performance and liquidity. 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.

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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, results of operations and cash flows from 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,
	2014			2013			2012
Reconciliation of gross operating margin to net loss
Gross operating margin	$	127,381		$	93,546		$	71,640
Add (deduct):
Income tax expense	(52		)	(385		)	(246		)
Equity in losses of joint venture investments	(6,496		)	—			—
Interest expense	(15,562		)	(12,590		)	(5,767		)
Loss on extinguishment of debt	(2,316		)	—			(1,764		)
Other expense	(77		)	—			—
Loss (gain) on sale of assets	(365		)	25			—
General and administrative	(32,723		)	(21,764		)	(13,842		)
Impairment of assets	(1,556		)	—			—
Depreciation and amortization	(46,050		)	(33,548		)	(18,977		)
Operations and maintenance	(59,915		)	(41,254		)	(35,532		)
Net loss	$	(37,731	)	$	(15,970	)	$	(4,488	)

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

	Year Ended December 31,
	2014			2013			2012
Net cash provided by operating activities	$	45,628		$	15,973		$	24,323
Add (deduct):
Depreciation and amortization	(46,050		)	(33,548		)	(18,977		)
Unit-based compensation	(10,074		)	(2,186		)	(630		)
Loss on extinguishment of debt	(2,316		)	—			(1,764		)
Amortization of deferred financing costs	(2,005		)	(1,287		)	(1,183		)
Loss (gain) on sale of assets, net	(365		)	25			—
Unrealized gain (loss) on financial instruments	(168		)	120			(141		)
Equity in losses of joint venture investments	(6,496		)	—			—
Impairment of assets	(1,556		)	—			—
Other, net	(65		)	(130		)	—
Changes in operating assets and liabilities:
Trade accounts receivable, including affiliates	24,770			6,675			9,760
Prepaid expenses and other current assets	5			1,197			1,246
Other non-current assets	29			(215		)	(1,786		)
Accounts payable and accrued expenses	(35,658		)	(1,411		)	(16,517		)
Other liabilities, including affiliates	(3,410		)	(1,183		)	1,181
Net loss	$	(37,731	)	$	(15,970	)	$	(4,488	)
Add (deduct):
Depreciation and amortization	46,050			33,548			18,977
Interest expense	15,562			12,590			5,767
Unrealized (gain) loss on commodity swaps	8			(120		)	141
Loss on extinguishment of debt	2,316			—			1,764
Revenue deferral adjustment	2,514			—			—
Unit-based compensation	2,931			2,186			630
Income tax expense	52			385			246
Loss (gain) on sale of assets, net	365			(25		)	—
Major litigation costs, net of recoveries	1,904			517			—
Equity in losses of joint venture investments	6,496			—			—
Transaction-related costs	9,850			—			—
Impairment of assets	1,556			—			—
Other, net	65			1,375			982
Adjusted EBITDA(1)	$	51,938		$	34,486		$	24,019
(Deduct):
Cash interest, net of capitalized costs	(13,371		)	(11,187		)	(4,584		)
Income tax expense	(52		)	(385		)	(246		)
Maintenance capital expenditures	(5,777		)	(3,353		)	(5,193		)
Distributable cash flow	$	32,738		$	19,561		$	13,996

(1) These amounts include an immaterial amount related to the effects of presenting our financial results on an as-if pooled basis (in connection with the 2015 Holdings Acquisition discussed in Note 2 to our consolidated financial statements).

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Current Year Highlights

The following events that took place during 2014 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 of this report for a more detailed account of such events.

Financing Activities

Public Equity Offering

In February 2014, we completed a public equity offering of 9,200,000 additional common units and received a capital contribution from our General Partner to maintain its 2.0% interest in us. The net proceeds from the public offering of common units were $144.7 million. The net proceeds from the offering were used to fund the construction of our new pipeline extending into Webb County, Texas (the "Webb Pipeline"), our Onyx pipelines acquisition in March 2014 and for general partnership purposes.

Onyx Pipelines Acquisition

On March 6, 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines near Corpus Christi, Texas and contracts related to these pipelines from Onyx Midstream, LP and Onyx Pipeline Company (collectively, “Onyx”) for $38.6 million in cash, net of certain adjustments as provided in the purchase agreement. See Note 3 to our consolidated financial statements.

TexStar Rich Gas System Acquisition

OnAugust 4, 2014, we acquired from TexStar certain gathering and processing assets (the "TexStar Rich Gas System") for $80 million in cash, the assumption of $100 million of debt (which was immediately repaid through our Term Loan Agreement (as defined below)) and our issuance of 14,633,000 of our Class B Convertible Units to TexStar (See Note 3 to our consolidated financial statements). The TexStar Rich Gas System consists of a 300 MMcf/d cryogenic processing plant, located in Bee County, Texas, and joint venture ownership in over 230 miles of rich natural gas gathering and residue pipelines across the core producing areas extending from Dimmit to Karnes Counties, Texas in the liquids-rich window of the Eagle Ford Shale. These pipelines are operated under split-capacity arrangements within joint ventures with Atlas Pipeline Partners, L.P. See Notes 1 and 3 to our consolidated financial statements.

Holdings Drop-Down Acquisition

On May 7, 2015, we acquired gathering, treating, compression and transportation assets in the 2015 Holdings Acquisition from Holdings and its subsidiaries consisting of the Valley Wells System, the Compression Assets and two NGL pipelines that were under construction at the time of the transaction (and that are now operational). Total consideration for the assets was $15.0 million in cash and 4.5 million new common units, valued as of the date of closing, issued to Holdings equating to $77.6 million. We also assumed the remaining capital expenditures for the completion of the NGL pipelines that were under construction. See Note 1 and 3 to our consolidated financial statements.

Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Holdings Transaction, we entered into (a) a Third Amended and Restated Revolving Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, JPMorgan Chase Bank, N.A., as Documentation Agent, and a syndicate of lenders (the “Third A&R Revolving Credit Agreement”) and (b) a Term Loan Credit Agreement with Wells Fargo Bank, N.A., as Administrative Agent, UBS Securities LLC and Barclays Bank PLC, as Co-Syndication Agents, and a syndicate of lenders (the “Term Loan Agreement” and, together with the Third A&R Revolving Credit Agreement, the “Senior Credit Facilities”). See Note 8 to our consolidated financial statements.

Equity Distribution Agreement

On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as our sales agent. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of

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sale in block transactions, or as otherwise agreed upon by us and any Manager. For additional details regarding the Distribution Agreement, see Note 12 to our consolidated financial statements.

Webb Pipeline Construction

During the first quarter of 2014, we began construction of an addition to our pipeline systems into Webb County, Texas (the "Webb Pipeline"), which was completed in October 2014. During 2014, we incurred $70.8 million related to the Webb Pipeline which we limited to approximately 45 miles in the third quarter of 2014 as a result of our ability to use a part of the TexStar Rich Gas System assets to connect the Webb Pipeline to the rest of our system.

Key Factors Affecting Operating Results and Financial Condition 

• Acquisition of rich gas assets from TexStar. In August 2014, we acquired the Lone Star plant, a 300 MMcf/d natural gas processing facility along with joint venture entities that own 176 miles of natural gas gathering and 57 miles of residue pipelines across core producing areas of the liquids-rich window of the Eagle Ford Shale.

• New pipelines in operation. In October 2014, we completed construction and commenced operation of our Webb County pipeline extension. The Webb Pipeline is a 45 mile 24 inch pipeline which connects Eagle Ford Shale region supply to our joint venture pipelines in La Salle County for further delivery to our processing plants.

• Acquisition of Onyx pipelines and contracts. In March 2014, our subsidiary, Southcross Nueces Pipelines LLC, acquired natural gas pipelines in Nueces and San Patricio Counties, Texas and contracts related to these pipelines from Onyx. These pipelines transport natural gas to two power plants in Nueces County, Texas under fixed-fee contracts that extend through 2029 and include an option to extend the agreements by an additional term of up to ten years.

• Acquisition of Holdings drop-down assets. In May 2015, we acquired gathering, treating, compression and transportation assets from Holdings and its subsidiaries consisting of the Valley Wells System's sour gas gathering and treating system with a capacity of approximately 100 MMcf/d, supported by a 35 MMcf/d minimum volume commitment, and the Compression assets with over 50,000 horsepower of compression capability that serve both the Valley Wells and Lancaster gathering systems located in the Eagle Ford Shale region, primarily in Dimmit and La Salle counties. Due to the common control aspects in the 2015 Holdings Acquisition, the Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction.

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Results of Operations

The following table summarizes our results of operations (in thousands, except operating data):

	Year Ended December 31,
	2014 (1)			2013			2012
Revenues
Revenues	$	835,246		$	634,722		$	496,129
Revenues - affiliates	13,267			—			—
Total revenues	848,513			634,722			496,129
Expenses:
Cost of natural gas and liquids sold	721,132			541,176			424,489
Operations and maintenance	59,915			41,254			35,532
Depreciation and amortization	46,050			33,548			18,977
General and administrative	32,723			21,764			13,842
Impairment of assets	1,556			—			—
Loss (gain) on sale of assets	365			(25		)	—
Total expenses	861,741			637,717			492,840
(Loss) income from operations	(13,228		)	(2,995		)	3,289
Other income (expense):
Equity in losses of joint venture investments	(6,496		)	—			—
Interest expense	(15,562		)	(12,590		)	(5,767		)
Loss on extinguishment of debt	(2,316		)	—			(1,764		)
Other expense	(77		)	—			—
Total other expense	(24,451		)	(12,590		)	(7,531		)
Loss before income tax expense	(37,679		)	(15,585		)	(4,242		)
Income tax expense	(52		)	(385		)	(246		)
Net loss	$	(37,731	)	$	(15,970	)	$	(4,488	)
Other financial data:
Adjusted EBITDA	$	51,938		$	34,486		$	24,019
Gross operating margin	127,381			93,546			71,640
Maintenance capital expenditures	5,777			3,353			5,193
Growth capital expenditures	162,840			90,510			164,623
Operating data:
Average throughput of gas (MMBtu/d)(2)	911,156			622,238			570,599
Average volume of processed gas (MMBtu/d)	353,456			240,825			206,045
Average volume of NGLs fractionated (Bbls/d)	17,815			12,545			9,385
Realized prices on natural gas volumes ($/MMBtu)	$	4.40		$	3.75		$	2.83
Realized prices on NGL volumes ($/gal)	0.78			0.88			0.87

_______________________________________________________________________________

(1) Due to the common control aspects in the 2015 Holdings Acquisition, the 2015 Holdings Acquisition was deemed a transaction between entities under common control and, as such, was accounted for on an “as if pooled” basis for all periods which common control existed (which began on August 4, 2014). The Partnership’s financial results retrospectively include the financial results of the Valley Wells System and Compression Assets for all periods ending after August 4, 2014, the date of the Holdings Transaction.

(2) Current and historical average throughput volumes of natural gas per day include sales, transportation, fuel and shrink volumes for all periods presented. Historical average throughput volumes of natural gas per day presented previously included sales and transportation volume only.

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The following table summarizes our average natural gas throughput volumes, amount of NGLs delivered, and volume of processed gas:

	Year Ended December 31,
	2014	2013	2012
Average throughput volumes of natural gas (MMBtu/d)
South Texas	716,077	422,775	369,964
Mississippi/Alabama	195,079	199,463	200,635
Total average throughput volumes of natural gas	911,156	622,238	570,599
Average volume of processed gas (MMBtu/d)	353,456	240,825	206,045
Average volume of NGLs fractionated (Bbls/d)	17,815	12,545	9,385

2014 Compared with 2013

Volume and overview. Our average throughput volume of natural gas increased by 288,918, or 46.4%, to 911,156 MMBtu/d during the year ended December 31, 2014, compared to 622,238 MMBtu/d for the year ended December 31, 2013, due primarily to increased gas volumes in South Texas from the TexStar Rich Gas System, 2015 Holdings Acquisition, and Onyx acquisitions as well as increases in volume from new and existing customers in the Eagle Ford Shale producing area. Beginning in the second half of 2014 and continuing through the issuance of our financial statements, commodity prices have experienced increased volatility. In particular, crude oil and NGL prices have decreased significantly. Our future cash flow may be materially adversely affected if we experience significant, prolonged pricing deterioration of the commodities we sell or a material reduction in drilling in the geographic footprints in which we operate, including the Eagle Ford Shale region.

Processed gas volumes increased 112,631, or 46.8%, to 353,456 MMBtu/d during the year ended December 31, 2014, compared to 240,825 MMBtu/d during the year ended December 31, 2013. This increase was due primarily to increased volumes from the TexStar Rich Gas System Transaction and increases in volumes from new and existing customers in the Eagle Ford Shale producing area.

NGLs fractionated for the year ended December 31, 2014 averaged 17,815 Bbls/d, an increase of 5,270 Bbls/d, or 42.0%, compared to 12,545 Bbls/d for the year ended December 31, 2013. This increase was due primarily to the impact of additional volumes of rich gas on our system and enhanced operational efficiency at our facilities during the year ended December 31, 2014 compared to the year ended December 31, 2013. 

Gross operating margin for the year ended December 31, 2014 was $127.4 million, compared to $93.5 million for the year ended December 31, 2013. This increase of $33.9 million, or 36.2%, was due primarily to increased processed gas volumes on our system, as well as increased transportation, gathering and processing fees.

Adjusted EBITDA increased by $17.4 million, or 50.6%, to $51.9 million for the year ended December 31, 2014, compared to $34.5 million for the year ended December 31, 2013, due to higher processed gas volumes and margins from processing and fractionation activities, partially offset by higher operating and general and administrative expenses. We had a net loss of $37.7 million for the year ended December 31, 2014 compared to a net loss of $16.0 million for the year ended December 31, 2013. Net loss increased due to higher overall expenses, including transaction-related costs affiliated with the Holdings Transaction and the TexStar Rich Gas System Transaction, and equity in losses of our joint venture investments, partially offset by higher gross operating margin.

Revenue. Our total revenues for 2014 increased 33.7% to $848.5 million compared to $634.7 million in 2013. This increase of $213.8 million was driven by acquisitions due primarily to greater revenue from sales of natural gas increasing of $125.7 million, greater revenues of NGLs and condensate of $56.7 million and higher revenue from transportation, gathering and processing fees of $25.6 million.  Realized average natural gas and NGL prices were as follows: 

	Years Ended December 31,
	2014	2013
Natural Gas	$4.40/MMBtu	$3.75/MMBtu
NGLs	$0.78/gal	$0.88/gal

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the year ended December 31, 2014 was $721.1 million, compared to $541.2 million for the year ended December 31, 2013. This increase of $179.9 million, or 33.3%, was due primarily to increased natural gas volumes purchased, increased NGL volumes purchased and higher natural gas prices compared to the same period in 2013.

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Operations and maintenance expenses. Operations and maintenance expenses for the year ended December 31, 2014 were $59.9 million, compared to $41.3 million for the year ended December 31, 2013. This increase of $18.6 million, or 45.2%, was due primarily to $3.0 million from higher labor costs including employee additions, $2.0 million from the accelerated vesting of our LTIP awards (which occurred as a result of our change of control in August 2014), higher fees of $1.5 million and higher operating costs of $1.4 million due to the acquisition of additional assets during the year ended December 31, 2014 compared to the year ended December 31, 2013.

General and administrative expenses. General and administrative expenses for the year ended December 31, 2014 were $32.7 million, compared to $21.8 million for the year ended December 31, 2013. This increase of $10.9 million, or 50.4%, was due primarily to increased expenses related to labor and benefits costs of $6.6 million from the accelerated vesting of LTIP awards (which occurred as a result of our change of control in August 2014), and $1.2 million from employee additions, together with higher professional fees of $2.5 million, mostly related to the TexStar Rich Gas System Transaction. Additionally, in the fourth quarter, the accrual for discretionary bonus was reduced after consideration of operating results.

Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2014 was $46.0 million, compared to $33.5 million for the year ended December 31, 2013. The increase of $12.5 million, or 37.3%, was due primarily to depreciation of the TexStar Rich Gas System and 2015 Holdings Acquisition assets acquired in the third quarter of 2014 and other capital projects placed in service during 2014.

Equity in losses of joint venture investments.  Our share of losses incurred by the joint venture investments acquired as part of the TexStar Rich Gas System assets was $6.5 million for the period from August 4, 2014 through December 31, 2014. We pay for our proportionate share of the joint ventures’ operating costs, excluding depreciation and amortization through lease capacity payments. As a result, our share of the joint ventures’ losses are primarily related to the joint ventures’ depreciation and amortization.

Loss on extinguishment of debt.  For the year ended December 31, 2014, we incurred a loss on the extinguishment of debt of $2.3 million in connection with the write-off of deferred financing costs related to exiting the Previous Credit Facility and entering into the Senior Credit Facilities in August 2014.

Interest expense. For the year ended December 31, 2014, interest expense was $15.6 million, compared to $12.6 million for the year ended December 31, 2013. This increase of $3.0 million, or 23.6%, was due to higher average borrowings related primarily to the debt incurred as part of the TexStar Rich Gas System.

2013 Compared with 2012

Volume and overview. Our average throughput volume of natural gas increased by 9.0% to 622,238 MMBtu/d during the year ended December 31, 2013, compared to 570,599 MMBtu/d during the year ended December 31, 2012, including an increase of 14.3% in our South Texas volumes. The increase was driven primarily by increased rich gas volumes entering our pipelines in South Texas to be processed at our facilities. 

Processed gas volumes increased by 16.9% to 240,825 MMBtu/d during the year ended December 31, 2013, compared to 206,045 MMBtu/d during the year ended December 31, 2012 as a result of increased processing capacity during 2013 at our Woodsboro processing plant, which was completed during the last half of 2012.

NGLs fractionated for the year ended December 31, 2013 was 12,545 Bbls/d, an increase of 33.7%, compared to 9,385 Bbls/d for the year ended December 31, 2012. This was due primarily to an increase in rich gas volumes processed at our facilities from the Eagle Ford Shale area.  Fractionation capacity of our Bonnie View fractionation facility increased from 11,500 Bbls/day during the last half of 2012 to 22,500 Bbls/day in February 2013. 

Gross operating margin for the year ended December 31, 2013 was $93.5 million, compared to $71.6 million for the year ended December 31, 2012. This increase of $21.9 million, or 30.6%, was due primarily to increased margin from NGLs and revenues from transportation, gathering and processing fees related to higher processed gas volumes.

Adjusted EBITDA increased by $10.5 million, or 43.6%, to $34.5 million for the year ended December 31, 2013, compared to $24.0 million for the year ended December 31, 2012, due primarily to higher margins partially offset by higher operating and general and administrative expenses. We had a net loss of $16.0 million for the year ended December 31, 2013 compared to a net loss of $4.5 million for the year ended December 31, 2012. Net loss increased due primarily to an increase in depreciation and amortization expense, an increase in general and administrative expenses, an increase in interest expense and higher operating expenses, partially offset by higher gross margin.

Revenue. Our total revenues for the year ended December 31, 2013 were $634.7 million, compared to $496.1 million for the year ended December 31, 2012. This increase of $138.6 million, or 27.9%, was due primarily to revenue from sales of

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natural gas increasing by $79.8 million resulting from increased natural gas sales volumes.  Revenue also increased from sales of NGLs and condensate by $45.4 million, or 36.6%, to $169.5 million for the year ended December 31, 2013, compared to $124.1 million for the year ended December 31, 2012, reflecting the increased production of NGLs at our facilities. Additionally, revenue from transportation, gathering and processing fees increased $13.3 million, or 28.8%, reflecting the results of additional rich gas volumes in 2013. Realized average natural gas and NGL prices were as follows: 

	Years Ended December 31,
	2013	2012
Natural Gas	$3.75/MMBtu	$2.83/MMBtu
NGLs	$0.88/gal	$0.87/gal

Cost of natural gas and NGLs sold. Our cost of natural gas and NGLs sold for the year ended December 31, 2013 was $541.2 million, compared to $424.5 million for the year ended December 31, 2012. The $116.7 million, or 27.5%, increase was due to higher prices of natural gas and NGLs purchased and increased volumes of natural gas purchased compared to 2012.

Operations and maintenance expenses. Operations and maintenance expenses for the year ended December 31, 2013 were $41.3 million, compared to $35.5 million for the year ended December 31, 2012. This increase of $5.7 million, or 16.1%, was due primarily to higher labor and benefits of $2.5 million, increased utility costs of $2.2 million associated with our Woodsboro plant and Bonnie View fractionation facility and increased ad valorem and other taxes of $1.5 million due to investments in and expansion of our assets, which were partially offset by a reduction in operating expenses of $1.2 million associated with the operations of our pipeline assets due to a reduction in scheduled maintenance during 2013.

General and administrative expenses. General and administrative expenses for the year ended December 31, 2013 were $21.8 million, compared to $13.8 million for the year ended December 31, 2012. This increase of $7.9 million, or 57.2%, was due primarily to increased expenses from employee additions, expenses related to being a newly public company, insurance coverage to support our growing asset base and operations and increased legal expenses.

Depreciation and amortization expense. Depreciation and amortization expense for the year ended December 31, 2013 was $33.5 million for 2013 compared to $19.0 million for the year ended December 31, 2012. This increase of $14.6 million, or 76.8%, was due primarily to the timing of the completion of growth capital projects and the acceleration of $1.3 million in depreciation related to the planned abandonment of a compressor station during 2013.

Loss on extinguishment of debt. For the year ended December 31, 2012, we incurred a loss on the extinguishment of debt of $1.8 million in connection with the repayment of $270.0 million of Southcross Energy LLC's assumed debt balance following our IPO consisting of a partial write-down of deferred financing costs.

Interest expense. For the year ended December 31, 2013, interest expense was $12.6 million, compared to $5.8 million for the year ended December 31, 2012. This increase of $6.8 million, or 118.3%, was due to higher average borrowings.

Liquidity and Capital Resources

Sources of Liquidity

Our primary sources of liquidity are cash generated from operations, cash raised through issuances of additional equity and debt securities and borrowings under our credit facilities. Our primary cash requirements consist of operating and maintenance and general and administrative expenses, growth and maintenance capital expenditures to sustain existing operations or generate additional revenues, interest payments on outstanding debt, purchases and construction of new assets, business acquisitions and distributions to unitholders.

We expect to fund short-term cash requirements, such as operating and maintenance and general and administrative expenses and maintenance capital expenditures, primarily through operating cash flows. We expect to fund long-term cash requirements, such as for expansion projects and acquisitions, through several sources, including operating cash flows, borrowings under our Senior Credit Facilities and issuances of additional debt and equity securities, as appropriate and subject to market conditions. See Note 8 to our consolidated financial statements.

Beginning in the second half of 2014 and continuing through the issuance of our financial statements, commodity prices have experienced increased volatility. In particular, crude oil and NGL prices have decreased significantly. Our future cash flow may be materially adversely affected if we experience significant, prolonged pricing deterioration of the commodities we sell or a material reduction in drilling in the geographic footprints in which we operate, including the Eagle Ford Shale region. See Note 2 to our consolidated financial statements.

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As of March 2, 2015, we had $516.6 million in outstanding borrowings under our Senior Credit Facilities. Under our five-year revolving credit facility, pursuant to our Third A&R Revolving Credit Agreement, we have the ability to borrow up to $200.0 million (the "Credit Facility") less any letters of credit amounts outstanding, which as of March 2, 2015 provided us access to $104.9 million.

Capital expenditures.    Our business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of and will continue to include:

• growth capital expenditures, which are capital expenditures to expand or increase the efficiency of the existing operating capacity of our assets. Growth capital expenditures include expenditures that facilitate an increase in volumes within our operations, but exclude expenditures for acquisitions; and

• maintenance capital expenditures, which are capital expenditures that are not considered growth capital expenditures.

The following table summarizes our capital expenditures (in thousands):

	Year Ended December 31,
	2014		2013
Maintenance capital	$	5,777	$	3,353
Growth capital	162,840		90,510
Total Capital expenditures	$	168,617	$	93,863

Growth capital expenditures during the year ended December 31, 2014 related primarily to construction of the Webb Pipeline, Valley Wells System and Compression Assets.  The growth capital expenditures during year ended December 31, 2013 related primarily related to our Bonnie View NGL fractionation facility completed in February 2013 and our Bee Line pipeline completed in February 2013. Our growth capital expenditures in 2015 are estimated to be between $25 million and $30 million.

Outlook.  Cash flow is affected by a number of factors, some of which we cannot control. These factors include prices and demand for our services, operational risks, volatility in commodity prices or interest rates, industry and economic conditions, conditions in the financial markets and other factors.

Our ability to benefit from growth projects to accommodate drilling activity and the associated need for infrastructure assets and services is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. These risks also impact third party service providers and their facilities. Delays or under-performance of our facilities or third party facilities may adversely affect our ability to generate cash from operations and comply with our obligations, including the covenants under our debt instruments. In other cases, actual production delivered may fall below volume estimates that we relied upon in deciding to pursue an acquisition or other growth project. Future cash flow and our ability to comply with our debt covenants would likewise be affected adversely if we experienced declining volumes over a sustained period and/or unfavorable commodity prices.

We believe that cash from operations, cash on hand, commitments from our Sponsors as discussed in Note 2 of the consolidated financial statements, and our unused borrowings under our Senior Credit Facilities will provide liquidity to meet future short-term capital requirements for a reasonable period of time. The sufficiency of these liquidity sources to fund necessary and committed capital needs will be dependent upon our ability to meet our covenant requirements of our Senior Credit Facilities. We believe we have and will continue to have sufficient liquidity to operate our business. See Notes 2 and 8 to our consolidated financial statements.

Growth projects and acquisitions are key elements of our business strategy. We intend to finance our growth capital primarily through the issuance of debt and equity. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate acquisitions or capital projects, we may require access to additional capital. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets and other financial and business factors, many of which are beyond our control.

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Cash Flows

The following table provides a summary of our cash flows by category (in thousands):

	Year Ended December 31,
	2014			2013			2012
Net cash provided by operating activities	$	45,628		$	15,973		$	24,323
Net cash used in investing activities	(288,427		)	(97,109		)	(169,816		)
Net cash provided by financing activities	241,099			76,995			151,571

2014 Compared with 2013

Operating Activities—Net cash provided by operating activities was $45.6 million for the year ended December 31, 2014, compared to $16.0 million for the year ended December 31, 2013. The increase in cash provided by operating activities of $29.6 million was primarily the result of increased gross operating margin during the year ended December 31, 2014 compared to the year ended December 31, 2013. In addition, the net changes in working capital of $17.0 million caused an increase in operating cash flows for the year ended December 31, 2014 compared to the year ended December 31, 2013.

Investing Activities—Net cash used in investing activities was $288.4 million for the year ended December 31, 2014, compared to $97.1 million for the year ended December 31, 2013. The increase of $191.3 million primarily relates to the TexStar Rich Gas System Transaction and the 2015 Holdings Acquisition in August 2014, the Onyx acquisition in March 2014 and increased capital expenditures in 2014.

Financing Activities—Net cash provided by financing activities was $241.1 million for the year ended December 31, 2014, compared to $77.0 million for the year ended December 31, 2013. The increase was due to proceeds received from our $144.7 million equity offering, net of expenses, in the first quarter of 2014, as well as additional net borrowings of $134.2 million from our debt instruments, and $50.6 million of expenses paid by Holdings on behalf of the Valley Wells System. The increase in cash provided by financing activities was partially offset by $100 million of debt assumed and immediately repaid by us in connection with the TexStar Rich Gas System Transaction, increased distributions paid of $16.7 million and additional financing costs of $15.6 million associated with the Senior Credit Facilities. 

2013 Compared with 2012

Operating activities—Net cash provided by operating activities was $16.0 million for the year ended December 31, 2013, compared to $24.3 million for the year ended December 31, 2012. The decrease in cash provided by operating activities was $8.3 million. The net loss in 2013 was more than offset by non-cash charges in 2013, principally depreciation expense, resulting in positive cash flows from operations before working capital items of $22.4 million. Working capital needs were higher in 2013 due primarily to the 2013 payment of accrued capital expenditures in 2012 and an increased accounts receivable balance.

Investing activities—Net cash used in investing activities was $97.1 million for the year ended December 31, 2013, compared to $169.8 million for the year ended December 31, 2012. The decrease in cash used in investing activities of $72.7 million primarily related to the decrease in capital spending due to the completion of the Bee Line and Bonnie View fractionation facility in February 2013. In addition to capital spending, we spent $3.4 million, net of insurance proceeds and deductible, at our Gregory facility related to a fire that occurred in January 2013 to return the plant to service.

Financing activities—Net cash provided by financing activities was $77.0 million for the year ended December 31, 2013, compared to $151.6 million for the year ended December 31, 2012. The decrease was driven primarily by the proceeds of $187.8 million from the issuance of common units from our IPO and the proceeds of $42.8 million and $30.0 million from our Predecessor's issuance of Series B redeemable preferred units and Series C redeemable preferred units, respectively, during the year ended December 31, 2012. This was partially offset by an increase in net borrowings of $93.6 million and the issuance of our Series A Preferred Units for $38.8 million during the year ended December 31, 2013.

Senior Credit Facilities

On August 4, 2014, in connection with the consummation of the Holdings Transaction and acquisition of the TexStar Rich Gas System, we entered into the Senior Credit Facilities. See Note 8 to our consolidated financial statements.

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The borrowings under our Credit Facility bear interest at the London Interbank Offered Rate (“LIBOR”) or a base rate plus an applicable margin as defined in the Third A&R Revolving Credit Agreement. As of December 31, 2014, our margin was LIBOR plus 3.25% the outstanding balance of the Credit Facility was $30.0 million and the unused portion totaled $139.9 million.

The borrowings under our seven-year $450 million senior secured term loan facility (the "Term Loan") under the Term Loan Credit Agreement bear interest at LIBOR plus 4.25% with a LIBOR floor of 1.00% or a base rate plus a margin as defined in that agreement. On August 4, 2014, the lenders funded the full amount of the Term Loan. As of December 31, 2014, the outstanding principal balance of the Term Loan was $445.6 million, net of original issuance discount of $2.1 million, and our borrowing rate was 5.25%. We are required to make quarterly amortization payments towards the Term Loan.

As of December 31, 2014, we were in compliance with the covenants set forth in the Senior Credit Facilities.

Series A Preferred Units

We entered into a Series A Convertible Preferred Unit Purchase Agreement with Southcross Energy LLC, pursuant to which we issued and sold 1,715,000 Series A Preferred Units to Southcross Energy LLC during the second quarter of 2013. Our total capital infusion of $40.0 million from all sales of Series A Preferred Units and General Partner capital contributions was used to reduce borrowings under our Credit Facility. The private placement of Series A Preferred Units resulted in proceeds to us of $39.2 million, and our General Partner contributed $0.8 million to maintain its 2.0% general partner interest in us.

On August 4, 2014, in connection with the Holdings Transaction and pursuant to the change in control provision in our Partnership Agreement applicable to our Series A Preferred Units, all holders of the Series A Preferred Units elected to convert their Series A Preferred Units into 2,015,638 common units based on the 110% exchange ratio specified in our Partnership Agreement.

Equity Distribution Agreement

On November 12, 2014, we established a $75 million "at-the-market" equity offering program pursuant to an equity distribution agreement (the “Distribution Agreement”) with Wells Fargo Securities, LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC (each, a “Manager” and, collectively, the “Managers”). Under the Distribution Agreement, we may offer and sell up to $75 million in aggregate gross sales proceeds of our common units (the “Offered Units”) from time to time through the Managers, each as a sales agent for the Partnership. Sales of the Offered Units, if any, made under the Distribution Agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices prevailing at the time of sale in block transactions, or as otherwise agreed upon by us and any Manager. The Offered Units have been registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Registration No. 333-192105, declared effective December 10, 2013, (the "Registration Statement"), including the prospectus contained therein, as supplemented by the prospectus supplement filed with the SEC on November 12, 2014. We intend to use the net proceeds from the sale of the Offered Units for general partnership purposes, including the repayment of debt, acquisitions and funding capital expenditures.

The Distribution Agreement contains customary representations, warranties and agreements by us, including our obligations to indemnify the Managers for certain liabilities under the Securities Act. The Managers and certain of their affiliates have engaged, and may in the future engage, in commercial and investment banking transactions with us in the ordinary course of their business for which they have received, and expect to receive, customary compensation and expense reimbursement. In particular, affiliates of each of the Managers are lenders under our Credit Facility, an affiliate of Wells Fargo Securities, LLC is a lender under our Term Loan and affiliates of the other sales agents may from time to time hold positions in the Term Loan. If we use any net proceeds of this offering to repay borrowings under our Credit Facility, such affiliates of the Managers will receive proceeds of the offering.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, except for our letters of credit under our Senior Credit Facilities described in Note 8 to our consolidated financial statements.

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Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2014 (in thousands):

		Total		Less Than 1 Year		1-3 Years		3-5 Years
Long-term debt:
	Principal(1)	$	475,629	$	4,500	$	9,000	$	39,000
	Interest(2)	85,863		21,922		43,845		20,096
Vehicle fleet lease		1,567		604		752		211
Office lease		4,450		1,141		2,254		1,055
Copiers		52		28		24		—
Total		$	567,561	$	28,195	$	55,875	$	60,362

_______________________________________________________________________________

(1) Contractual obligations related to the Credit Facility assume the $30.0 million outstanding as of December 31, 2014 is paid off at maturity in November 2019. Contractual obligations of the Term Loan are net of original issuance discount of $2.1 million.

(2) Interest is estimated at the weighted average interest rate for the year ended December 31, 2014 of 4.61% for periods through November 2019. The interest does not include interest rate swaps because they are considered to be immaterial.

Critical Accounting Policies

The accounting policies described below are considered critical to obtaining an understanding of our consolidated financial statements because their application requires significant estimates and judgments by management in preparing our consolidated financial statements. Management's estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the following conditions apply:

• the estimate requires significant assumptions; and

• changes in the estimate could have a material effect on our consolidated statements of operations or financial condition; or

• if different estimates that could have been selected had been used, there could be a material effect on our consolidated statements of operations or financial condition.

We have discussed the selection and application of these accounting estimates with the Audit Committee of the board of directors of our general partner and our independent registered public accounting firm. It is management's view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions.

Revenue Recognition

Using the revenue recognition criteria of persuasive evidence of an exchange arrangement exists, delivery has occurred or services have been rendered and the price is fixed or determinable, we record natural gas and NGL revenue in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue. In addition, collectability is evaluated on a customer-by-customer basis. New customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay.

Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations. These transactions are contractual arrangements that establish the terms of the purchase of natural gas or NGLs at a specified location and the sale of natural gas or NGLs at a different location on the same or on another specified date. These transactions require physical delivery and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

Impairment of Long-Lived Assets

We evaluate our long-lived assets, which include finite-lived intangible assets, for impairment when events or circumstances indicate that their carrying values may not be recoverable. These events include, but are not limited to, market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset,

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decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset's carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. With the recent decline in commodity prices negatively affecting the level of natural gas and crude oil production, we are more susceptible to potential impairment. During the year ended December 31, 2014, we recorded $1.6 million of impairment costs primarily related to right of way costs on a canceled project. At December 31, 2013 and 2012, we did not record any impairments of long-lived assets.

New Accounting Pronouncements

For a complete description of new accounting pronouncements, see Note 1 to our consolidated financial statements.

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