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TMCNet:  MARLIN MIDSTREAM PARTNERS, LP - 10-K/A - Management's Discussion and Analysis of Financial Condition and Results of Operations

[March 28, 2014]

MARLIN MIDSTREAM PARTNERS, LP - 10-K/A - Management's Discussion and Analysis of Financial Condition and Results of Operations

(Edgar Glimpses Via Acquire Media NewsEdge) Unless the context otherwise requires, references in this report to "we," "our," "us," or like terms, when used in a historical context, refer to the combined businesses and assets of Marlin Midstream and Marlin Logistics, and when used in the present tense or prospectively, refer to the Partnership and its subsidiaries.


OVERVIEW We are a fee-based, growth-oriented Delaware limited partnership formed to develop, own, operate and acquire midstream energy assets. We currently provide natural gas gathering, compression, dehydration, treating, processing and hydrocarbon dew-point control and transportation services, which we refer to as our midstream natural gas business, and crude oil transloading services, which we refer to as our crude oil logistics business. Our assets and operations are organized into the following two segments: Midstream Natural Gas Our primary midstream natural gas assets currently consist of (i) two related natural gas processing facilities located in Panola County, Texas with an approximate design capacity of 220 MMcf/d, (ii) a natural gas processing facility located in Tyler County, Texas with an approximate design capacity of 80 MMcf/d, (iii) two natural gas gathering systems connected to our Panola County processing facilities that include approximately 65 miles of natural gas pipelines with an approximate design capacity of 200 MMcf/d, and (iv) two NGL transportation pipelines with an approximate design capacity of 20,000 Bbls/d that connect our Panola County and Tyler County processing facilities to third party NGL pipelines. Our primary midstream natural gas assets are located in long-lived oil and natural gas producing regions in East Texas and gather and process NGL-rich natural gas streams associated with production primarily from the Cotton Valley Sands, Haynesville Shale, Austin Chalk and Eaglebine formations.

Crude Oil Logistics Our crude oil logistics assets currently consist of two crude oil transloading facilities: (i) our Wildcat facility located in Carbon County, Utah, where we currently operate one skid transloader and two ladder transloaders, and (ii) our Big Horn facility located in Big Horn County, Wyoming, where we currently operate one skid transloader and one ladder transloader. Our transloaders are used to unload crude oil from tanker trucks and load crude oil into railcars and temporary storage tanks. Our Wildcat and Big Horn facilities provide transloading services for production originating from well-established crude oil producing basins, such as the Uinta and Powder River Basins, which we believe are currently underserved by our competitors. Our skid transloaders each have a transloading capacity of 475 Bbls/hr, and our ladder transloaders each have a transloading capacity of 210 Bbls/hr.

General Trends and Outlook In 2014, our strategic objectives will continue to be focused on maintaining stable distributable cash flows from our existing assets and executing on growth opportunities to increase our long-term distributable cash flows. We believe the key elements to stable distributable cash flows are our significant fee-based business plus our assets that are strategically positioned to capitalize on drilling activity and related demand for midstream natural gas services.

We expect to continue to pursue a multi-faceted growth strategy, which includes maximizing opportunities provided by our partnership with NuDevco Midstream Partners LP, pursuing strategic and accretive third party acquisitions and capitalizing on organic expansion opportunities in order to grow our distributable cash flows.

HIGHLIGHTS Significant financial highlights during the year ended December 31, 2013 include the following: • In connection with our IPO on July 31, 2013, we issued 6,875,000 common units, representing a 38.6% limited partner interest, to the public for $20.00 per common unit. Net proceeds of $125.3 million, after underwriting discounts, structuring fees, and other direct IPO costs, were used to repay the existing credit facility of $121.9 million, outstanding amounts on the revolving credit facility of approximately $10.0 million, and settling the interest rate swap liability of approximately $0.1 million.

• In connection with our IPO on July 31, 2013, we entered into a new $50.0 million senior secured revolving credit facility, which matures on July 31, 2017.

- 48-------------------------------------------------------------------------------- • We declared and paid a prorated cash distribution for the third quarter of 2013 in the amount of $0.23 per unit and declared a cash distribution for the fourth quarter of 2013 in the amount of $0.35 per unit.

• Following the closing of the IPO, we assigned all of our existing commodity-based gathering and processing agreements with third party customers to AES and entered into a new three-year fee-based gathering and processing agreement with AES with a minimum volume commitment of 80 MMcf/d.

• We entered into transloading services agreements with AES, each with three year terms, minimum volume commitments and annual inflation adjustments.

Significant operational highlights during the year ended December 31, 2013 included the following: • Our crude oil logistics assets became operational in 2013. Following the closing of the IPO, our crude oil logistics revenues are generated under transloading services agreements that we entered into with AES.

• We completed construction of our Oak Hill Lateral gathering line and installed molecular sieves at our Panola 1 processing facility.

INITIAL PUBLIC OFFERING On July 31, 2013, we completed an initial public offering ("IPO") of 6,875,000 common units at a public offering price of $20.00 per common unit less an underwriting discount of $1.20 per common unit for net proceeds, before expenses, of $18.80 per common unit. Our sponsor, NuDevco Partners, LLC ("NuDevco"), is the ultimate parent company of Spark Energy Ventures, LLC ("SEV"). NuDevco also owns NuDevco Midstream Development, LLC ("NuDevco Midstream") and Associated Energy Services, LP ("AES"). Following the closing of the offering, we entered into fee-based commercial agreements with AES, substantially all of which include minimum volume commitments and annual inflation adjustments. In connection with the offering, NuDevco and its affiliates conveyed Marlin Midstream, LLC ("Marlin Midstream") and Marlin Logistics, LLC ("Marlin Logistics") to us.

Additionally at the closing of the IPO, we issued 2,474,545 common units and 8,724,545 subordinated units to NuDevco Midstream Development. We terminated our commodity-based gas gathering and processing agreement with AES and assigned all our remaining keep-whole and other commodity-based gathering and processing agreements with third party customers to AES. We entered into transloading services agreements with AES, each with three year terms, minimum volume commitments and annual inflation adjustments.

We also transferred to affiliates of our sponsor (i) our 50% interest in a CO2 processing facility located in Monell, Wyoming, (ii) certain transloading assets and purchase commitments owned by Marlin Logistics not currently under a service contract, (iii) certain property, plant and equipment and other equipment not yet in service and (iv) certain other immaterial contracts. The total net asset value transferred to the affiliates was $9.4 million. Additionally, NuDevco assumed $11.7 million of the non-current accounts payable balance owed by Marlin Midstream to affiliates of SEV and Marlin Midstream was released from such obligation.

Our partnership agreement provides for a minimum quarterly distribution of $0.35 per unit for each whole quarter, or $1.40 per unit on an annualized basis.

As of the closing of the IPO, the unit ownership was as follows: Number of units at Limited Partner July 31, 2013 Interest Publicly held common units 6,875,000 38.6 % Common units held by NuDevco 1,849,545 10.4 % Subordinated units held by NuDevco 8,724,545 49.0 % General partner units 356,104 2.0 % Total 17,805,194 100.0 % - 49-------------------------------------------------------------------------------- HOW WE EVALUATE OUR OPERATIONS Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our results of operations and profitability and include: (i) gross margin; (ii) volume commitments and throughput volumes (including gathering, plant, and transloader throughput); (iii) operation and maintenance expenses; (iv) adjusted EBITDA; and (v) distributable cash flow. Gross margin, adjusted EBITDA and distributable cash flow are not measures under accounting principles generally accepted in the United States of America, or GAAP. To the extent permitted, we present certain non-GAAP measure and reconciliations of those measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP. These non-GAAP measures may not be comparable to a similarly titled measure of another company because other entities may not calculate these non-GAAP measures in the same manner.

Volumes - We view throughput and storage volumes for our gathering and processing and our crude oil logistics segment as important factors affecting our profitability. We gather and transport the natural gas and NGLs under fee-based transportation contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time as wells deplete. Accordingly, to maintain or to increase throughput levels on these pipelines and the utilization rate of our natural gas processing plants, we must continually obtain new supplies of natural gas and NGLs. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are impacted by: (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines; and (2) our ability to compete for volumes from successful new wells in other areas. The throughput volumes of NGLs and gas on our pipelines are substantially dependent upon the quantities of NGLs and gas produced at our processing plants. We regularly monitor producer activity in the areas we serve and in which our pipelines are located, and pursue opportunities to connect new supply to these pipelines. d.

In Thousands, except volume data Years Ended December 31, 2013 2012 2011 Gross Margin $ 38,861 $ 30,026 $ 36,962 Gas volumes (MMcf/d) (2) 219 Transloading volumes (Bbls/d) (2) 18,980 Adjusted EBITDA $ 16,880 $ 9,239 $ 19,730 Distributable Cash Flow (1) $ 12,982 n/a n/a (1) We will distribute available cash within 45 days after the end of the quarter, beginning with the quarter ending September 30, 2013. For the three months ended September 30, 2013, distributable cash is prorated from our IPO on July 31, 2013 through September 30, 2013.

(2) Volumes reflect the minimum volume commitment under our fee-based contracts or actual throughput, whichever is greater, for the post-IPO period.

Gross Margin Gross margin is a primary performance measure used by our management. We define gross margin as revenues less cost of revenues. Gross margin represents our profitability with minimal exposure to commodity price fluctuations, which we believe are not significant components of our operations.

Gross margin is calculated as follows: - 50 -------------------------------------------------------------------------------- In Thousands Years Ended December 31, 2013 2012 2011 Total operating income $ 5,671 $ 1,550 $ 14,365 Operation and maintenance 12,401 15,035 12,031 Operation and maintenance-affiliates 3,490 793 327 General and administrative 3,699 3,045 3,260 General and administrative-affiliates 4,187 1,021 907 Property and other taxes 1,216 893 490 Depreciation expense 8,197 7,689 5,365 Loss on disposals of equipment - - 217 Gross Margin $ 38,861 $ 30,026 $ 36,962 Volume Commitments and Throughput We view the volumes of natural gas and crude oil committed to our midstream natural gas and crude oil logistics assets, respectively, as well as the throughput volume of natural gas and crude oil as an important factor affecting our profitability. The amount of revenues we generate primarily depends on the volumes of natural gas and crude oil committed to our midstream natural gas assets and crude oil logistics assets, respectively, under our commercial agreements, the volumes of natural gas that we gather, process, treat and transport, the volumes of NGLs that we transport and sell, and the volumes of crude oil that we transload. Our success in attracting additional committed volumes of natural gas and crude oil and maintaining or increasing throughput is impacted by our ability to: • utilize the remaining uncommitted capacity on, or add additional capacity to, our gathering and processing systems and our transloaders; • capitalize on successful drilling programs by our customers on our current acreage dedications; • increase throughput volumes on our gathering systems by increasing connections to other pipelines or wells; • secure volumes from new wells drilled on non-dedicated acreage; • attract natural gas and crude oil volumes currently gathered, processed, treated or transloaded by our competitors; and • identify and execute organic expansion projects.

Adjusted EBITDA and Distributable Cash Flow We use adjusted EBITDA to analyze our performance and define it as net income (loss) before interest expense (net of amounts capitalized) or interest income, Texas margin tax, depreciation expense, equity based compensation expense and any gain/loss from interest rate derivatives. Although we have not quantified distributable cash flow on a historical basis, after the closing of the IPO we compute and present this measure, which we define as adjusted EBITDA plus interest income, less cash paid for interest expense and maintenance capital expenditures.

Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated and combined financial statements, such as industry analysts, investors, commercial banks and others, may use 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 earnings sufficient to support our decision to make cash distributions to our unitholders and general partner; • our ability to fund capital expenditures and incur and service debt; • our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and • the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

- 51-------------------------------------------------------------------------------- Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ended September 30, 2013, we distribute all of our available cash to unitholders of record on the applicable record date.

Our cash distribution for the period from the completion of the IPO through September 30, 2013 was adjusted based on the actual length of the period. For the three months ended September 30, 2013, a distribution of $0.23 per unit was declared on October 18, 2013 and paid on November 4, 2013 to unitholders of record as of October 29, 2013. For the three months ending December 31, 2013, a distribution of $0.35 per unit was declared on January 21, 2014 and paid on February 7, 2014 to unitholders of record as of February 3, 2014.

Adjusted EBITDA is calculated as follows: In Thousands Years Ended December 31, 2013 2012 2011 Net income (loss) $ 1,186 $ (4,306 ) $ 8,541 Interest expense, net of amounts capitalized 4,349 4,927 3,733 Interest and other income - (23 ) (20 ) Texas margin tax expense 88 101 (65 ) Equity based compensation 3,012 - - Loss on interest rate swap 48 851 2,176 Depreciation expense 8,197 7,689 5,365 Adjusted EBITDA $ 16,880 $ 9,239 $ 19,730 Distributable cash flow subsequent to the IPO is calculated as follows: Distributable cash flow for the period from July 31, 2013 to December 31, 2013: In Thousands Net income post IPO $ 7,190 Add: Equity based compensation 3,012 Interest expense, net of amounts capitalized 352 Depreciation expense 3,425 Texas margin tax 60 Adjusted earnings 14,039 Less: Maintenance capital expenditures (782 ) Cash interest expense (215 ) Texas margin tax (60 ) Distributable cash flow $ 12,982 Note Regarding Non-GAAP Financial Measures Gross margin, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial condition and results of operations.

Gross margin is a primary performance measure used by our management. We define gross margin as revenues less cost of revenues. Gross margin represents our profitability without regard to commodity sales and purchases, which we believe are not significant components of our operations. We use adjusted EBITDA to analyze our performance and define it as net income (loss) before interest expense (net of amounts capitalized) or interest income, state franchise tax, depreciation expense and any gain/loss from interest rate derivatives. Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial - 52 -------------------------------------------------------------------------------- measures that management and external users of our combined financial statements, such as industry analysts, investors, commercial banks and others, may use 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 earnings sufficient to support our decision to make cash distributions to our unitholders and general partner; • our ability to fund capital expenditures and incur and service debt; • our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and • the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

The GAAP measure most directly comparable to gross margin is operating income.

The GAAP measure most directly comparable to adjusted EBITDA and distributable cash flow is net income. These measures should not be considered as an alternative to operating income, net income, or any other measure of financial performance presented in accordance with GAAP. Each of these non-GAAP financial measures has important limitations as an analytical tool because it excludes some but not all items that affect net income. You should not consider these non-GAAP financial measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because each of these non-GAAP financial measures may be defined differently by other companies in our industry, our definition of them may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

FACTORS AFFECTING THE COMPARABILITY OF OPERATING RESULTS Our future results of operations may not be comparable to our historical results of operations for the reasons described below: Revenues There are differences in the way we generated revenues historically and the way we generate revenues subsequent to the closing of our IPO.

• Gathering and Processing Agreements • Until 2011, our gathering and processing agreements with third parties and our affiliates were primarily keep-whole contracts.

Under these contracts, we were required to make up or "keep the producer whole" for the condensate and NGL volumes extracted from the natural gas stream through the delivery of or payment for a thermally equivalent volume of residue gas. The cost of these "replacement" natural gas volumes was recorded in our cost of revenues. Beginning in late 2011, we contracted with Anadarko and other third party producers at our Panola County processing facilities for significant volumes under a fee-based processing model. A substantial majority of these agreements provide for minimum volume commitments.

• Beginning on January 1, 2012, our commercial agreements with Anadarko at our Panola County processing facilities were amended such that Anadarko began receiving the NGLs extracted on an in-kind basis. As a result, we do not sell the NGLs extracted under these amended agreements, and therefore the NGLs recovered under these amended agreements are not included in our natural gas, NGLs and condensate sales. Under our commercial agreements that do not require us to deliver NGLs to the customer in kind, including our gathering and processing agreement with AES that we entered into in connection with the closing of the IPO, we provide NGL transportation services to the customer whereby we purchase the NGLs from the customer at an index price, less fractionation and transportation fees, and simultaneously sell the NGLs to third parties at the same index price, less fractionation fees. The revenues generated by these activities is substantially offset by a corresponding cost of revenue that is recorded when we compensate the customer for its contractual share of the NGLs.

• Following the closing of the IPO, we assigned all of our existing commodity-based gathering and processing agreements with third party customers to AES and entered into a new three-year fee-based gathering and processing agreement with AES with a minimum volume commitment of 80 MMcf/d.

• Transloading Services Agreements • Following the closing of the IPO, our crude oil logistics revenues are generated under transloading services agreements that we entered into with AES at the closing of the IPO. Under the transloading services agreements with AES, we receive a per barrel fee for crude oil transloading services, including fees in respect of shortfall payments related to AES' minimum volume commitments under these agreements from time to time. Because our crude oil logistics assets did not become operational until 2013, our future results of operations will not be comparable to our historical results of operations regarding our crude oil logistics segment.

Operating and General and Administrative Expenses With respect to our operation and maintenance expenses and general and administrative expenses, prior to the IPO, we employed all of our operational personnel and most of our general and administrative personnel directly, and incurred direct operating and general and administrative charges with respect to their compensation. In connection with the closing of the IPO, all of our personnel were transferred to affiliates of NuDevco. As a result, following the closing of the IPO, we reimburse NuDevco for the compensation of these employees on a direct or allocated basis, depending on whether those employees spend all or only a part of their time working for us. As a result of this change, the amount of our affiliate operation and maintenance expenses and affiliate general and administrative expenses will increase, and the amount of our non-affiliate operation and maintenance expenses and non-affiliate general administrative expenses will decrease, compared to historical amounts.

Our historical general and administrative expenses included certain expenses allocated by affiliates of NuDevco for general corporate services, such as information technology, treasury, accounting and legal services, as well as direct expenses. These allocated expenses were charged or allocated to us based on the nature of the expenses and our proportionate share of departmental usage, wages or headcount. Following the closing of the IPO, affiliates of NuDevco will continue to charge us a combination of direct and allocated monthly expenses related to the management and operation of our midstream natural gas and crude oil logistics businesses, and will also charge us an annual fee, initially in the amount of $0.6 million, for executive management services.

In addition, we expect our general and administrative expenses will increase due to the costs of operating as a publicly traded partnership, including costs associated with ongoing SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley compliance expenses, expenses associated with listing on NASDAQ, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director compensation expenses.

Financing There are differences in the way we finance our operations now as compared to the way we financed our operations on a historical basis. Historically, our operations were financed by cash generated from operations, equity investments by our sole member and borrowings under our existing credit facility. In connection with the closing of the IPO, we repaid the full amount of our previous credit facility, settled our related interest rate swap liability and entered into a new $50.0 million senior secured revolving credit facility.

Approximately $4.0 million was outstanding under our new senior secured revolving credit facility as of December 31, 2013 and $126.5 million was outstanding under our previous credit facility as of December 31, 2012.

Following the closing of the IPO, we intend to make minimum cash distributions to our unitholders at an initial distribution rate of $0.35 per unit per quarter ($1.40 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect to fund future capital expenditures primarily from external sources, including borrowings under our new revolving credit facility and future issuances of equity and debt securities.

- 53 -------------------------------------------------------------------------------- RESULTS OF OPERATIONS Year Ended December 31, 2013 Compared to Year Ended December 31, 2012 The following table presents selected financial data for each of the years ended December 31, 2013 and 2012.

In Thousands Years ended December 31, 2013 2012 Change % Change REVENUES: Natural gas, NGLs and condensate revenue $ 15,792 $ 34,708 $ (18,916 ) (54.5 )% Gathering, processing, transloading and other revenue 37,068 16,341 20,727 126.8 % Total Revenues 52,860 51,049 1,811 3.5 % OPERATING EXPENSES: Cost of natural gas, NGLs and condensate revenue 13,999 21,023 (7,024 ) (33.4 )% Operation and maintenance 15,891 15,828 63 0.4 % General and administrative 7,886 4,066 3,820 93.9 % Property tax expense 1,216 893 323 36.2 % Depreciation expense 8,197 7,689 508 6.6 % Total operating expenses 47,189 49,499 (2,310 ) (4.7 )% Operating income 5,671 1,550 4,121 265.9 % Interest expense, net of amounts capitalized (4,349 ) (4,927 ) 578 (11.7 )% Interest and other income - 23 (23 ) (100.0 )% Loss on interest rate swap (48 ) (851 ) 803 (94.4 )% Net income (loss) before tax $ 1,274 $ (4,205 ) $ 5,479 130.3 % Texas margin tax expense 88 101 (13 ) (12.9 )% Net income (loss) 1,186 (4,306 ) 5,492 (127.5 )% Key performance metrics: Gross margin 38,861 30,026 8,835 29.4 % Adjusted EBITDA 16,880 9,239 7,641 82.7 % Volumes: Processing Facilities (MMcf/d) (1) 219 Transloading Facilities (Bbls/d) (1) 18,980 (1) Volumes reflect the minimum volume commitment under our fee-based contracts or actual throughput, whichever is greater, for the post-IPO period.

Revenues. Natural gas, NGLs and condensate revenue decreased by $18.9 million, or 55%, to $15.8 million for the year ended December 31, 2013 from $34.7 million for the year ended December 31, 2012. The decrease in natural gas, NGLs and condensate revenue is primarily due to the shift in business strategy to fee-based contracts following our IPO, declining NGL prices and a decrease in NGL volumes sold from our Panola County processing facilities. The average price of ethane decreased by 35% to $0.26 per gallon for the year ended December 31, 2013 from $0.40 per gallon for the year ended December 31, 2012. Similarly, the average price per gallon of isobutane and normal butane decreased by 21% and 16% respectively, for the year ended December 31, 2013 as compared to the year ended December 31, 2012. Declining NGL prices attributed to a $7.1 million decrease in our NGL sales for the year ended December 31, 2013 as compared to the year ended December 31, 2012.

We entered into an additional commercial agreement with Anadarko at our Panola County processing facilities, effective August 1, 2012. Under this agreement, Anadarko receives the NGLs extracted on an in-kind basis. We do not sell the NGLs extracted under this agreement, and therefore the NGLs recovered under this agreement are not included in our natural gas, NGLs and condensate sales. As a result, although the number of barrels of NGLs that we recovered increased by 9% for the - 54 -------------------------------------------------------------------------------- year ended December 31, 2013 as compared to the year ended December 31, 2012, the number of barrels of NGLs that we sold decreased by 52% for the year ended December 31, 2013 as compared to the year ended December 31, 2012. This decrease was partially offset by an increase in condensate volumes and other NGLs sold under third-party purchase contracts. These changes resulted in a total net decrease of $11.8 million in natural gas, NGLs and condensate revenue for the year ended December 31, 2013 as compared to the year ended December 31, 2012.

Gathering, processing, transloading and other revenue increased by $20.7 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012, primarily from our minimum volume commitment agreements with Anadarko and AES. Minimum volume commitment agreements for our gathering and processing segment account for an increase of approximately $14.9 million in fee-based revenue. We expect the trend of increased volumes under fee-based agreements to continue, consistent with our overall business strategy. Our crude oil logistics assets became operational in 2013. As such, there are no results of operations or assets related to this segment for the year ended December 31, 2012. For the year ended December 31, 2013, the crude oil logistics segment generated revenues of approximately $5.8 million related directly to our fee-based logistics contracts.

Cost of Revenues. Cost of revenues are derived primarily from the creation of natural gas, NGLs and condensate revenue. Total cost of natural gas, NGLs and condensate revenue decreased by $7.0 million, or 33%, to $14.0 million for the year ended December 31, 2013 as compared to $21.0 million for the year ended December 31, 2012 primarily due to the volume of redelivered gas at the tailgate of our plant in addition to a decline in prices for NGLs. The volume of gas redelivered or sold at the tailgates of our processing facilities is lower than the volume received or purchased at delivery points on our gathering systems or interconnecting pipelines due to the NGLs extracted when the natural gas is processed. Under the keep-whole agreements that were in place during 2012, we were required to make up or "keep the producer whole" for the condensate and NGL volumes extracted from the natural gas stream through the delivery of or payment for a thermally equivalent volume of residue gas. Under certain keep-whole agreements, we purchased natural gas from a subsidiary of SEV in order to make up or "keep the producer whole" for the condensate and NGL volumes extracted from the natural gas stream during processing. The cost of these "replacement" natural gas volumes was recorded in our cost of natural gas, NGLs and condensate revenue. Under our fee-based agreements, we do not bear the cost of these "replacement" volumes. Furthermore, at the closing of our IPO, we assigned all of our keep-whole agreements to AES. The cost of natural gas, NGLs and condensate revenue from affiliates recorded for the year ended December 31, 2013 includes the purchase of $2.5 million of NGLs under our gathering and processing agreement with AES.

Operation and Maintenance Expense. Operation and maintenance expense increased by $0.1 million, or 0.4%, for the year ended December 31, 2013 as compared to the year ended December 31, 2012 primarily due to equity-based compensation expense of $0.9 million and $0.6 million in operating expenses for our crude oil logistics contracts. These increases were offset by a decrease in maintenance and operational expenses for our midstream natural gas segment of $1.4 million.

Operation and maintenance expenses are primarily composed of expenses related to labor, utilities and chemicals, property insurance premiums, compression costs and maintenance and repair expenses, which generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during the period and the timing of these expenses.

General and Administrative Expense. General and administrative expense increased by approximately $3.8 million, or 94%, to $7.9 million for the year ended December 31, 2013 as compared to $4.1 million for the year ended December 31, 2012. The increase is primarily due to increased audit costs and other professional fees associated with being a publicly traded partnership.

Additionally, approximately $2.2 million of equity-based compensation expense from affiliates was recorded to general and administrative expense, for which no such costs were incurred in 2012.

Interest Expense. Interest expense, net of amounts capitalized, decreased by approximately $0.6 million or 12%, to $4.3 million for the year ended December 31, 2013 as compared to $4.9 million for the year ended December 31, 2012. Interest expense increased due to expensing capitalized loan costs associated with our previous credit facilities of $0.8 million for the year ended December 31, 2013 and $0.2 million for the year ended December 31, 2012.

This increase was offset against a lower outstanding average principal balance which contributed to a decrease of $1.2 million for interest incurred on our credit facilities during the year ended December 31, 2013 as compared to the year ended December 31, 2012.

Loss on Interest Rate Swap. Loss on interest rate swap decreased by $0.8 million, or 94%, to less than $0.1 million for the year ended December 31, 2013 as compared to $0.9 million for the year ended December 31, 2012. The decrease is primarily due to smaller movements in the interest rate market during 2013.

The interest rate swap was settled on July 31, 2013 in connection with the IPO.

- 55 -------------------------------------------------------------------------------- Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 The following table presents selected financial data for each of the years ended December 31, 2011 and 2012.

In Thousands Years ended December 31, 2012 2011 Change % Change REVENUES: Natural gas, NGLs and condensate revenue 34,708 55,558 (20,850 ) (37.5 )% Gathering, processing, transloading and other revenue 16,341 10,260 6,081 59.3 % Total Revenues 51,049 65,818 (14,769 ) (22.4 )% OPERATING EXPENSES: Cost of natural gas, NGLs and condensate revenue 21,023 28,856 (7,833 ) (27.1 )% Operation and maintenance 15,828 12,358 3,470 28.1 % General and administrative 4,066 4,167 (101 ) (2.4 )% Property tax expense 893 490 403 82.2 % Depreciation expense 7,689 5,365 2,324 43.3 % Loss on disposals of equipment - 217 (217 ) (100.0 )% Total operating expenses 49,499 51,453 (1,954 ) (3.8 )% Operating income 1,550 14,365 (12,815 ) (89.2 )% Interest expense, net of amounts capitalized (4,927 ) (3,733 ) (1,194 ) 32.0 % Interest and other income 23 20 3 15.0 % Loss on interest rate swap (851 ) (2,176 ) 1,325 (60.9 )% Net income (loss) before tax (4,205 ) 8,476 (12,681 ) (149.6 )% Texas margin tax expense 101 (65 ) 166 (255.4 )% Net income (loss) (4,306 ) 8,541 (12,847 ) (150.4 )% Key performance metrics: Gross margin 30,026 36,962 (6,936 ) (18.8 )% Adjusted EBITDA 9,239 19,730 (10,491 ) (53.2 )% Revenues. Natural gas, NGLs and condensate revenue decreased by $20.9 million, or 38%, from $55.6 million for the year ended December 31, 2011 to $34.7 million for the year ended December 31, 2012. The decrease in natural gas, NGLs and condensate revenue is primarily due to declining NGL prices and a decrease in NGL volumes sold from our Panola County processing facilities. The average annual price of ethane decreased by 48% from $0.77 in 2011 to $0.40 in 2012, and the average annual price of propane decreased by 32% from $1.46 in 2011 to $1.00 in 2012. Similarly, the average annual price of isobutane, normal butane and natural gasoline decreased by 12%, 10%, and 8%, respectively, from 2011 to 2012.

Declining NGL prices attributed to a $9.7 million decrease in our NGL sales from 2011 to 2012.

In addition, beginning on January 1, 2012, our commercial agreements with Anadarko at our Panola County processing facilities were amended such that Anadarko began receiving the NGLs extracted on an in-kind basis. As a result, we do not sell the NGLs extracted under these amended agreements, and therefore the NGLs recovered under these amended agreements are not included in our natural gas, NGLs and condensate revenue. As a result of this change in contractual terms, even though the number of barrels of NGLs that we recovered increased by 25% from 2011 to 2012, the number of barrels of NGLs that we sold decreased by 23% from 2011 to 2012. This resulted in an $11.2 million decrease in natural gas, NGLs and condensate sales from the year ended December 31, 2011 to the year ended December 31, 2012.

Gathering, processing and other revenue increased by $6.1 million from the year ended December 31, 2011 to the year ended December 31, 2012 as a result of increased throughput under fee-based agreements. We expect the trend of increased volumes under fee-based agreements to continue, consistent with our overall business strategy.

- 56 -------------------------------------------------------------------------------- Cost of Revenues. The decrease in total revenues was partially offset by a decrease in cost of revenues. Cost of revenues are derived primarily from the creation of natural gas, NGLs and condensate revenue. Total cost of natural gas, NGLs and condensate revenue decreased by $7.9 million, or 27%, from $28.9 million for the year ended December 31, 2011 to $21.0 million for the year ended December 31, 2012. The volume of gas redelivered or sold at the tailgates of our processing facilities is lower than the volume received or purchased at delivery points on our gathering systems or interconnecting pipelines due to the NGLs extracted when the natural gas is processed. Under the keep-whole agreements that were in place during 2011, we were required to make up or "keep the producer whole" for the condensate and NGL volumes extracted from the natural gas stream through the delivery of or payment for a thermally equivalent volume of residue gas. The cost of these "replacement" natural gas volumes was recorded in our cost of natural gas, NGLs and condensate revenue. Under our fee-based agreements, we do not bear the cost of these "replacement" volumes. As such, the increase in revenues generated under our fee-based agreements during 2012 resulted in an $8.5 million decrease in our cost of revenues. The decrease is net of a $1.8 million increase in cost of natural gas, NGLs and condensate revenue related to costs incurred by us to pay our fee-based customers, other than Anadarko, their share of NGLs. We expect the cost of the replacement natural gas volumes to continue to decrease as a substantial majority of our volumes are subject to fee-based agreements. However, as total volumes under fixed fee contracts with customers other than Anadarko increase, the cost of natural gas, NGLs and condensate revenue for shares of NGLs paid to third parties will increase. There are no material costs categorized as costs of revenue directly identified with gathering, processing and other revenue.

Operation and Maintenance Expense. Operation and maintenance expense increased by $3.4 million, or 28%, from $12.4 million for the year ended December 31, 2011 to $15.8 million for the year ended December 31, 2012. The increase primarily is due to operating costs incurred in connection with the startup and continued operation of our Panola 2 processing plant, which became fully operational in May 2012.

Property Tax Expense. Property taxes increased by $0.4 million from $0.5 million for the year ended December 31, 2011 to $0.9 million for the year ended December 31, 2012. The increase primarily is due to the inclusion of our Panola 2 processing plant in our taxable basis during 2012. In addition, during 2011, we received a one-time property tax settlement resulting in a taxable basis reduction for tax years 2009 through 2011 and a related refund.

Depreciation Expense. Depreciation expense increased by $2.3 million, or 43%, from $5.4 million for the year ended December 31, 2011 to $7.7 million for the year ended December 31, 2012. The increase primarily is due to our Panola 2 processing plant, which became fully operational in May 2012.

Interest Expense. Interest expense, net of amounts capitalized increased by $1.2 million, or 32%, from $3.7 million for the year ended December 31, 2011 to $4.9 million for the year ended December 31, 2012. The increase is primarily due to a decrease in capitalized interest of $1.5 million related to the Panola 2 processing plant, which was placed into service in 2011 and became fully operational in May 2012, offset by lower interest expense as a result of the lower average principal balance on long-term debt during the year.

Loss on Interest Rate Swap. Loss on interest rate swap decreased by $1.3 million, or 61%, from $2.2 million for the year ended December 31, 2011 to $0.9 million for the year ended December 31, 2012. The decrease is primarily due to smaller movements in the interest rate market during 2012.

LIQUIDITY AND CAPITAL RESOURCES We closely manage our liquidity and capital resources. The key variables we use to manage our liquidity requirements include our discretionary operation and maintenance expense, general and administrative expense, capital expenditures, credit facility capacity and availability, working capital levels, and the level of investments required to support our growth strategies.

Historically, our sources of liquidity included cash generated from operations, equity investments by our sole member and borrowings under our historical credit facility.

We expect our ongoing sources of liquidity subsequent to the closing of the IPO to include cash generated from operations, our new revolving credit facility and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to sustain operations, to finance anticipated expansion plans and growth initiatives, and to make quarterly cash distributions on all of our outstanding units at the minimum quarterly distribution rate. However, in the event our liquidity is insufficient, we may be required to limit our spending on future growth plans or other business opportunities or to rely on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our growth.

- 57 -------------------------------------------------------------------------------- We intend to pay a minimum quarterly distribution of $0.35 per unit per quarter, which equates to $6.2 million per quarter, or approximately $24.9 million per year, based on the number of common, subordinated and general partner units outstanding immediately after the IPO plus unvested phantom units subsequently issued under our long-term incentive plan. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no obligation to make quarterly cash distributions in this or any other amounts and our general partner has considerable discretion to determine the amount of our available cash each quarter.

Credit Facilities In 2007, affiliates of NuDevco, including Marlin Midstream, entered into as co-borrowers a credit agreement that consisted of a working capital facility, a term loan and a revolving credit facility. The credit agreement was amended on May 30, 2008 to provide for a $177.5 million working capital facility, a $100.0 million term loan, and a $35.0 million revolving credit facility. In January 2011, the credit agreement was amended and restated to decrease the working capital facility from $177.5 million to $150.0 million, increase the term loan from $100.0 million to $130.0 million and eliminate the revolving credit facility. In December 2012, the credit agreement was amended and restated to decrease the working capital facility to $70.0 million, amend the term loan to $125.0 million and reinstate the revolving credit facility in the amount of $30.0 million. The amended and restated credit facility was scheduled to mature on December 17, 2014. We repaid the term loan and revolving credit facility with the proceeds of the IPO and a portion of the $25.0 million borrowed under our new $50.0 million senior secured revolving credit facility at the closing of the IPO.

Concurrently with the closing of our IPO, we entered into our new revolving credit facility, which matures on July 31, 2017. If no event of default has occurred, we have the right, subject to approval by the administrative agent and certain lenders, to increase the borrowing capacity under the new revolving credit facility to up to $150.0 million. The new revolving credit facility is available to fund expansions, acquisitions and working capital requirements for our operations and general corporate purposes.

At our election, interest will be generally determined by reference to: • the Eurodollar rate plus an applicable margin between 3.0% and 3.75% per annum (based upon the prevailing senior secured leverage ratio); or • the alternate base rate plus an applicable margin between 2.0% and 2.75% per annum (based upon the prevailing senior secured leverage ratio). The alternate base rate is equal to the highest of Société Générale's prime rate, the federal funds rate plus 0.5% per annum or the reference Eurodollar rate plus 1.0%.

Our new revolving credit facility is secured by the capital stock of our present and future subsidiaries, all of our and our subsidiaries' present and future property and assets (real and personal), control agreements relating to our and our subsidiaries' bank accounts and collateral assignments of our and our subsidiaries' material construction, ownership and operation agreements, including any agreements with AES or Anadarko.

Our new revolving credit facility also contains covenants that, among other things, requires us to maintain specified ratios or conditions. We must maintain a consolidated senior secured leverage ratio, consisting of consolidated indebtedness under our new revolving credit facility to consolidated EBITDA of not more than 4.0 to 1.0, as of the last day of each fiscal quarter. In addition, we must maintain a consolidated interest coverage ratio, consisting of our consolidated EBITDA minus capital expenditures to our consolidated interest expense, letter of credit fees and commitment fees of not less than 2.5 to 1.0, as of the last day of each fiscal quarter.

Our new revolving credit facility contains affirmative covenants that are customary for credit facilities of this type. Our new revolving credit facility also contains additional negative covenants that will limit our ability to, among other things, do any of the following: • incur certain additional indebtedness; • grant certain liens; • engage in certain asset dispositions; • merge or consolidate; • make certain payments, investments or loans; • enter into transactions with affiliates; • make certain changes in our lines of business or accounting practices, except as required by GAAP or its successor; • store inventory in certain locations; • place certain amounts of cash in accounts not subject to control agreements; - 58 -------------------------------------------------------------------------------- • amend or modify certain agreements and documents; • incur certain capital expenditures; • engage in certain prohibited transactions; • enter into burdensome agreements; and • act as a transmitting utility or as a utility.

Our new revolving credit facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, actual or asserted failure of any guaranty or security document supporting our new revolving credit facility to be in full force and effect and change of control. If such an event of default occurs, the lenders under our new revolving credit facility would be entitled to take various actions, including the acceleration of amounts due under our new revolving credit facility and all actions permitted to be taken by a secured creditor.

As of December 31, 2013, we had unused capacity under our new revolving credit facility of $46.0 million and outstanding borrowings of $4.0 million.

CASH FLOWS Net Cash Flows for the Years Ending December 31, 2013 and 2012 Net cash flows provided by (used in) operating activities, investing activities and financing activities for the year ended December 31, 2013 and 2012 were as follows: Year Ended In Thousands December 31, 2013 2012 Change Net cash provided by (used in): Operating activities $ 9,176 $ 11,214 $ (2,038 ) Investing activities $ (12,710 ) $ (12,445 ) $ (265 ) Financing activities $ 1,136 $ 6,355 $ (5,219 ) Operating Activities Cash flows provided by operating activities decreased by $2.0 million to $9.2 million for the year ended December 31, 2013 from $11.2 million for the year ended December 31, 2012. The decrease is primarily related to payments made to reimburse affiliates for costs incurred in the normal course of business prior to our initial public offering, which was partially offset by decreased losses incurred on our derivatives, the addition of our long-term incentive plan current liability of $3.0 million and long-term liability of $32,000 and an increase in net income for the year ended December 31, 2013 as compared to December 31, 2012.

Investing Activities Cash flows used in investing activities increased by $0.3 million to $12.7 million for the year ended December 31, 2013 as compared to $12.4 million for the year ended December 31, 2012. Cash paid for capital expenditures during the year ended December 31, 2013 primarily included payments made to construct the Oak Hill Lateral gathering line and install molecular sieves at our Panola 1 processing facility. Cash paid for capital expenditures during the year ended December 31, 2012 included payments for the amounts accrued as of December 31, 2011 for the Panola 2 processing plant, as well as commissioning activities incurred early in the twelve months ending December 31, 2012. We also began construction on our Oak Hill Lateral gathering line in the spring of 2012.

- 59 -------------------------------------------------------------------------------- Financing Activities Cash flows from financing activities in historical periods primarily were driven by borrowing under our historical credit facility and capital contributions from our sole member. We used these borrowings and capital contributions to fund our working capital needs and to finance maintenance and expansion capital expenditure projects that are reflected in cash flows used in investing activities.

Cash flows provided by financing activities decreased by $5.2 million to $1.1 million for the year ended December 31, 2013 from $6.4 million for the year ended December 31, 2012. The decrease in 2013 is primarily related to borrowings under our new revolving credit facility of $27.5 million and our previous credit facility of $9.0 million and net proceeds from the IPO of $125.3 million, net against debt repayments of $23.5 million on our new revolving credit facility and $135.5 million on our previous credit facility, and a capital contribution of $3.6 million prior to the IPO. During the year ended December 31, 2012, we repaid outstanding indebtedness in the amount of $123.5 million, had borrowings under our previous credit facility of $126.5 million and received capital contributions of $4.3 million.

Net Cash Flows for the Years Ending December 31, 2012 and 2011 Net cash flows provided by (used in) operating activities, investing activities and financing activities for the year ended December 31, 2012 and 2011 were as follows: Year Ended In Thousands December 31, 2012 2011 Change Net cash provided by (used in): Operating activities $ 11,214 $ 16,102 $ (4,888 ) Investing activities $ (12,445 ) $ (25,658 ) $ 13,213 Financing activities $ 6,355 $ 8,097 $ (1,742 ) Operating Activities Cash flows provided by operating activities decreased by $4.9 million to $11.2 million for the year ended December 31, 2012 from $16.1 million for the year ended December 31, 2011. The decrease is primarily due to the change in net income (loss) discussed above under "- Results of Operations," after excluding the effect of losses on asset disposals, amortization of deferred financing cost, depreciation expense, and unrealized gains or losses on derivatives, which had no effect on cash flows used in operating activities. The decrease is partially offset by an increase in accounts payable to affiliates of $9.0 million primarily related to natural gas purchases from affiliates to satisfy requirements under our keep-whole contracts.

Investing Activities Cash flows used in investing activities decreased by $13.3 million to $12.4 million for the year ended December 31, 2012 from $25.7 million for the year ended December 31, 2011. The decrease is primarily due to lower capital expenditures in 2012 as various projects with significant spending in 2011 were substantially complete by the end of 2011.

Financing Activities Cash flows provided by financing activities decreased by $1.7 million to $6.4 million for the year ended December 31, 2012 from $8.1 million for the year ended December 31, 2011. The decrease primarily is related to a decrease of $3.5 million in borrowings under our existing credit facility and a $2.7 million increase in repayments on the previous term loan relating to the refinancing of our existing credit facility in 2012, partially offset by an increase of $4.3 million in capital contributions from affiliates of our sponsor.

- 60 -------------------------------------------------------------------------------- CAPITAL EXPENDITURES Our operations are capital intensive, requiring investments to expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements have consisted of and are expected to continue to consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. Expansion capital expenditures include expenditures to acquire assets and expand existing facilities that increase throughput capacity on our pipelines, processing plants and crude oil logistics assets. Although historically we did not necessarily distinguish between maintenance capital expenditures and expansion capital expenditures in the same manner that we are required to under our partnership agreement subsequent to the closing of the IPO, for the years ended December 31, 2013, 2012 and 2011, we estimate that we incurred a total of $2.3 million, $2.0 million and $1.3 million, respectively, for maintenance capital expenditures and incurred a total of $11.0 million, $9.0 million and $26.1 million respectively, for expansion capital expenditures. Subsequent to the IPO from July 31, 2013 to December 31, 2013, we incurred $0.8 million of maintenance capital expenditures.

During the year ended December 31, 2013, expansion capital expenditures primarily related to the construction of our Oak Hill Lateral gathering line and the installation of molecular sieves at our Panola 1 processing facility. Our capital funding requirements were funded by borrowings under our previous credit facility and our current credit facility.

During the year ended December 31, 2012, expansion capital expenditures primarily related to our Panola 2 processing plant, which was placed into service in 2011 and became fully operational in May 2012. In 2012, we also began construction on our Oak Hill Lateral. Our capital requirements were funded by borrowings under our previous credit facility.

During the year ended December 31, 2011, expansion capital expenditures primarily relate to our Panola 2 processing plant, which was placed into service in 2011 and became fully operational in May 2012.

We budgeted maintenance capital expenditures of approximately $2.5 million and expansion capital expenditures of approximately $10.4 million for the year ending December 31, 2013. The majority of the $2.5 million in maintenance capital expenditures relates to overhauls and upgrades to our major equipment at our Panola County and Tyler County processing facilities in order to maintain the reliability and functionality of the equipment. Of the $10.4 million in expansion capital expenditures, $6.7 million relates to the completion of our Oak Hill Lateral gathering line, and $2.8 million relates to the installation of molecular sieves at our Panola 1 processing plant, expanded the capacity of our Panola County processing facilities by approximately 4%. The remaining $0.9 million of budgeted expansion capital expenditures relates to several projects to expand the services offered at, and the capacity of, our Panola County processing facilities.

For the year ending December 31, 2014, we budgeted maintenance capital expenditures of approximately $2.2 million and expansion capital expenditures of approximately $22.3 million. The majority of the $2.2 million in maintenance capital expenditures relates to overhauls and upgrades to our major equipment at our Panola County and Tyler County processing facilities in order to maintain the reliability and functionality of the equipment. Of the $22.3 million in expansion capital expenditures, $9.7 million relates to the construction of additional gathering systems, and $10.0 million relates to the expansion of our crude oil logistics segment. The remaining $2.6 million relates to several projects to expand the services offered at, and the capacity of, our Panola County processing facilities.

OFF-BALANCE SHEET ARRANGEMENTS We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

CONTRACTUAL OBLIGATIONS A summary of our contractual obligations as of December 31, 2013 is as follows: In Thousands 2014 2015 2016 2017 Thereafter Total Operating services agreements (1) $ 177 $ - $ - $ - $ - $ 177 Long-term debt (2) - - - 4,000 - 4,000 Total $ 177 $ - $ - $ 4,000 $ - $ 4,177 - 61-------------------------------------------------------------------------------- (1) Amounts relate to minimum payments for operating services agreements having initial or remaining non-cancellable lease terms in excess of one year, including our operating services agreements at (i) our Panola County processing facilities with a remaining term of 2 months and total payments of $0.1 million and (ii) our Tyler County processing facility with a remaining term of 6 months and total remaining payments of $0.1 million.

(2) $4.0 million was outstanding at December 31, 2013. This new senior secured revolving credit facility matures on July 31, 2017. For additional information relating to our long-term debt, please see Note 6 "Long-Term Debt and Interest Expense," to our consolidated financial statements included in this Form 10-K.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES As of December 31, 2013, there have been no significant changes to our critical accounting policies and estimates disclosed in our Prospectus. We have added a critical accounting policy and estimate with respect to the accounting for our long-term incentive plan awards.

The preparation of consolidated financial statements in accordance with GAAP requires our management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of properties and equipment, asset retirement obligations, litigation, environmental liabilities, income taxes and fair values. Although these estimates are based on management's best available knowledge of current and expected future events, changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with the audit committee of our general partner. For additional information relating to our accounting policies, please see Note 1-"Organization and Summary of Significant Accounting Policies" - to our consolidated financial statements included in Item 8 of this Form 10-K.

Our Revenue Recognition Policies and Use of Estimates for Revenues and Expenses In general, we recognize revenue from customers when all of the following criteria are met: • persuasive evidence of an exchange arrangement exists; • delivery has occurred or services have been rendered; • the price is fixed or determinable; and • collectability is reasonably assured.

We record revenue for natural gas and NGL sales and transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed).

While we make every effort to record actual volume and price data, there may be times where we need to make use of estimates for certain revenues and expenses.

If the assumptions underlying our estimates prove to be substantially incorrect, it could result in material adjustments in results of operations in future periods.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property, plant and equipment and revise our estimates when and as appropriate. Because of the expected long useful lives of the property, plant and equipment, we depreciate our property, plant and equipment over periods ranging from 5 years to 40 years.

Changes in the estimated useful lives of the property, plant and equipment could have a material adverse effect on our results of operations.

Impairment of Long-Lived Assets We review property, plant and equipment and other long-lived assets for impairment whenever events or changes in business circumstances indicate the net book values of the assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets' net book value. If this occurs, an impairment loss is recognized for the difference between the fair value and net book value. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset, and a significant change in the asset's physical condition or use. No impairments of long-lived assets were recorded during the periods included in these financial statements.

Contingencies - 62 -------------------------------------------------------------------------------- In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. As of December 31, 2013, we did not have any material outstanding lawsuits, administrative proceedings or governmental investigations.

Accounting for Derivative and Hedging Activities From time to time, we enter into derivative transactions to mitigate our exposure to price fluctuations in NGLs and utilize derivative instruments to manage our exposure to interest rate risk. We recognize all derivative instruments as either assets or liabilities in our consolidated and combined Balance Sheets at their respective fair value. For derivatives designated in hedging relationships, changes in the fair value are recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged, until the hedged item affects earnings.

We formally assess, both at the inception of the hedging transaction and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. For derivative instruments that are designated and qualify as part of a cash flow hedging transaction, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

We discontinue hedge accounting prospectively when we determine that the derivative is no longer effective in offsetting cash flows attributable to the hedged risk, the derivative expires or is sold, terminated, or exercised, the cash flow hedge is de-designated because a forecasted transaction is not probable of occurring, or management determines to remove the designation of the cash flow hedge.

In all situations in which hedge accounting is discontinued and the derivative remains outstanding, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, we discontinue hedge accounting and recognize immediately in earnings gains and losses that were accumulated in other comprehensive income related to the hedging relationship.

Our commodity derivative instruments are recorded at fair value using broker quoted market prices of similar contracts. Our interest rate swap derivatives are valued using current forward interest rates as quoted by brokers to be received in the cash market.

Accounting for Awards under the Long-term Incentive Plan In connection with the IPO, the board of directors of our general partner adopted the Marlin Midstream Partners, LP 2013 Long-Term Incentive Plan (LTIP).

Individuals who are eligible to receive awards under the LTIP include (1) employees of the Partnership and NuDevco Midstream Development and its affiliates, (2) directors of the Partnership's general partner, and (3) consultants. The LTIP provides for the grant of unit options, unit appreciation awards, restricted units, phantom units, distribution equivalent rights, unit awards, profits interest units, and other unit-based awards. The maximum number of common units issuable under the LTIP is 1,750,000.

On August 1, 2013, phantom units, with distribution equivalent rights, of 292,000 units were awarded to certain employees of NuDevco Midstream Development and its affiliates who provide direct or indirect services to us pursuant to affiliate agreements, and 20,000 units were awarded to certain board members of our general partner. All of the phantom unit awards granted to-date are considered non-employee equity based awards and are required to be remeasured at fair market value at each reporting period and amortized to compensation expense on a straight-line basis over the vesting period of the phantom units with a corresponding increase in a liability. We intend to settle the awards by allowing the recipient to choose between issuing the net amount of common units due, less common units equivalent to pay withholding taxes, due upon vesting with the Partnership paying the amount of withholding taxes due in cash or issuing the gross amount of common units due with the recipient paying the withholding taxes. The phantom unit awards were awarded to individuals who are not deemed to be employees of the Partnership.

Distribution equivalent rights are accrued for each phantom unit award as the Partnership declares cash distributions and are recorded as a decrease in partners' capital with a corresponding liability in accordance with the vesting period of the underlying phantom unit, which will be settled in cash when the underlying phantom units vest.

The phantom units awarded to employees of NuDevco Midstream Development and its affiliates will vest in five equal annual installments with the first installment vesting on June 30, 2014, provided that for any individual who has attained a total of five or more years of service with NuDevco Midstream Development or its affiliates at the grant date of award the phantom unit awards will fully vest on February 15, 2014. The phantom unit awards to board members of the Partnership's general partner will fully vest on February 15, 2014.

Subsequent Events - 63 -------------------------------------------------------------------------------- We evaluated our disclosure of subsequent events through the date, February 27, 2014, that our consolidated financial statements were issued.

NEW ACCOUNTING STANDARDS Liabilities In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-04, "Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date" ("ASU 2013-04") regarding accounting for obligations resulting from joint and several liability arrangements. ASU 2013-04 is effective for interim and annual periods beginning January 1, 2014. Early adoption is permitted with retrospective application. We adopted this standard upon issuance and have applied the requirements to our 2012 combined financial statements.

Reporting Amounts Reclassified Out of Accumulated Comprehensive Income In February 2013, the FASB also issued ASU No. 2013-02, "Reporting Amounts Reclassified Out of Accumulated Comprehensive Income" ("ASU 2013-02") related to the reporting of amounts reclassified out of accumulated other comprehensive income. This guidance requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the financial statements or in the related notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required to be reclassified in its entirety in the same reporting period. For amounts that are not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional details about those amounts. The guidance is effective for annual reporting periods, and interim periods within those years, beginning after December 15, 2012.

Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised accounting standards. As such, we can delay the adoption of certain accounting standards until these standards would otherwise apply to private companies. We have elected to delay such adoption of new or revised accounting standards, and as a result, we will not adopt ASU 2013-02 until interim periods in 2014, as required of private entities.

Offsetting Assets and Liabilities In December 2011, the FASB issued ASU No. 2011-11, "Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under International Financial Reporting Standards ("IFRS"). On January 31, 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities" ("ASU 2013-01"). ASU 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards will be effective for interim and annual periods beginning January 1, 2013 and should be applied retrospectively. We adopted both standards on January 1, 2013. The standards did not have an effect on our consolidated and combined financial statement footnotes, as our derivative financial instruments are not presented on a net basis in our consolidated and combined Balance Sheets.

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