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MARLIN MIDSTREAM PARTNERS, LP - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated and combined financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated and combined financial statements and notes thereto and management's discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2013 and 2012 included in the Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the Securities and Exchange Commission on February 27, 2014, as amended on March 26, 2014 and March 28, 2014 (the "Annual Report on Form 10-K"). Unless otherwise noted, references to "we," "us," "our," the "Partnership" or "Marlin Midstream Partners" refers to Marlin Midstream Partners, LP and its subsidiaries. CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS We have made in this report, and may from time to time otherwise make in other public filings, press releases and discussions by management, forward-looking statements concerning our operations, economic performance and financial condition. These statements can be identified by the use of forward-looking terminology including "may," "will," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or financial condition or include other "forward-looking" information. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will be realized. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties: • the volume of natural gas we gather and process and the volume of NGLs we transport; • the volume of crude oil that we transload; • the level of production of crude oil and natural gas and the resultant market prices of crude oil, natural gas and NGLs; • the level of competition from other midstream natural gas companies and crude oil logistics companies in our geographic markets; • the level of our operating expenses; • regulatory action affecting the supply of, or demand for, crude oil or natural gas, the transportation rates we can charge on our pipelines, how we contract for services, our existingcontracts, our operating costs or our operating flexibility; • capacity charges and volumetric fees that we pay for NGL fractionation services; • realized pricing impacts on our revenues and expenses that are directly subject to commodity price exposure; • the creditworthiness and performance of our customers,suppliers and contract counterparties, and any material nonpayment or non-performance by one or more of these parties; • damage to pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third party pipelines or facilities upon which we rely for transportation services; • outages at the processing or fractionation facilities owned by us or third parties caused by mechanical failure and maintenance, construction and other similar activities; • leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise; • the level and timing of our expansion capital expenditures and our maintenance capital expenditures; • the cost of acquisitions, if any; • the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates for services provided to us; 24--------------------------------------------------------------------------------• our debt service requirements and other liabilities; • fluctuations in our working capital needs; • our ability to borrow funds and access capital markets; • restrictions contained in our debt agreements; • the amount of cash reserves established by our general partner; • other business risks affecting our cash levels; and • other factors discussed below and elsewhere in "Risk Factors" in our Annual Report on Form 10-K and in our other public filings and press releases. The risk factors and other factors noted throughout or incorporated by reference in this report could cause our actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 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 three crude oil transloading facilities: (i) our Wildcat facility located in Carbon County, Utah, where we currently operate one skid transloader and two ladder transloaders, (ii) our Big Horn facility located in Big Horn County, Wyoming, where we currently operate one skid transloader and one ladder transloader, and (iii) our East New Mexico facility located in Sandoval County, New Mexico, where we currently operate one skid transloader. Our transloaders are used to unload crude oil from tanker trucks and load crude oil into railcars and temporary storage tanks. Our 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. Initial Public Offering 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. See Note 1 ("Organization and Formation of the Partnership") for further discussion. 25 -------------------------------------------------------------------------------- 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. 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 the IPO. Gathering and Processing Agreements • 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 are 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, or subsequent to, 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 and administrative expenses will decrease, compared to historical amounts. In addition, our general and administrative costs have increased due to the costs of operating as a publicly traded partnership. 26 -------------------------------------------------------------------------------- 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 have continued to charge us a combination of direct and allocated monthly general and administrative expenses related to the management and operation of our midstream natural gas and crude oil logistics businesses and charge us an annual fee, initially in the amount of $0.6 million, for executive management services. Financing There are differences in the way we finance our operations as compared to the way we financed our operations on a historical basis prior to the IPO. Historically, our operations were financed by cash generated from operations, equity investments by our sole member and borrowings under our previous 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 $50.0 million senior secured revolving credit facility. We had $11.0 million outstanding under our senior secured revolving credit facility as of September 30, 2014. 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 revolving credit facility and future issuances of equity and debt securities. 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. Three Months Ended September Nine Months Ended September In Thousands, except volume data 30, 30, 2014 2013 2014 2013 Gross margin $ 14,457 $ 12,471 $ 44,273 $ 25,064 Gas volumes (MMcf/d) (1) 191 224 208 Transloading volumes (Bbls/d) (1) 21,317 18,980 19,768 Adjusted EBITDA $ 8,781 $ 6,699 $ 26,525 $ 8,412 Distributable cash flow (2) $ 8,105 $ 5,346 $ 24,516 (1) Volumes reflect the minimum volume commitment under our fee-based contracts or actual throughput, whichever is greater, for the post-IPO period. (2) We will distribute available cash within 45 days after the end of the quarter, beginning with the quarter ended September 30, 2013. 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 is a non-GAAP supplemental financial measure that represents our profitability with minimal exposure to commodity price fluctuations, which we believe are not significant components of our operations. 27 --------------------------------------------------------------------------------The following table presents a reconciliation of the non-GAAP financial measure of gross margin to the GAAP financial measure of operating income: In Thousands Three Months Ended September 30, Nine Months Ended September 30, 2014 2013 2014 2013 Total operating income $ 6,490 $ 3,357 $ 18,435 $ 1,035 Operation and maintenance 2,132 2,961 6,947 10,048 Operation and maintenance-affiliates 1,505 1,322 5,007 1,830 General and administrative 748 849 2,467 2,927 General and administrative-affiliates 981 1,633 3,795 2,287 Property tax expense 363 291 994 844 Depreciation expense 2,238 2,058 6,568 6,093 Loss on disposal of equipment - - 60 - Gross margin $ 14,457 $ 12,471 $ 44,273 $ 25,064 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, 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, income tax expense, 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 prior to the IPO, we compute and present this measure for periods subsequent to the IPO, 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 condensed 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 28-------------------------------------------------------------------------------- • the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. The following table presents a reconciliation of the non-GAAP financial measure of adjusted EBITDA to the GAAP financial measure of net income (loss): In Thousands Three Months Ended September 30, Nine Months Ended September 30, 2014 2013 2014 2013 Net income (loss) $ 6,140 $ 1,922 $ 17,611 $ (3,218 ) Interest expense, net of amounts capitalized 212 1,382 549 4,171 Income tax expense 138 11 275 35 Depreciation expense 2,238 2,058 6,568 6,093 Equity based compensation 53 1,284 1,522 1,284 Loss on interest rate swap - 42 - 47 Adjusted EBITDA $ 8,781 $ 6,699 $ 26,525 $ 8,412 The following table presents a reconciliation of the non-GAAP financial measure of distributable cash flow to the GAAP financial measure of net income: For the period from July 31, Three Months Ended Nine Months Ended 2013 to September In Thousands September 30, 2014 September 30, 2014 30, 2013 Net income $ 6,140 $ 17,611 $ 2,785 Add: Interest expense, net of amounts capitalized 212 549 174 Income tax expense 138 275 8 Depreciation expense 2,238 6,568 1,321 Equity based compensation 53 1,522 1,284 Adjusted EBITDA 8,781 26,525 5,572 Less: Maintenance capital expenditures (230 ) (1,201 ) (133 ) Cash interest expense (148 ) (373 ) (85 ) Income tax expense (138 ) (275 ) (8 ) Adjustment (1) (160 ) (160 ) - Distributable cash flow $ 8,105 $ 24,516 $ 5,346 (1) Removes the results of the East New Mexico Dropdown for the period prior to the acquisition (July 2, 2014 to July 31, 2014). 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. 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. 29 --------------------------------------------------------------------------------RESULTS OF OPERATIONS Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 The following table presents selected financial data for each of the three months ended September 30, 2014 and 2013. In Thousands Three Months Ended September 30, 2014 2013 Change % Change REVENUES: Natural gas, NGLs and condensate revenue $ 2,511 $ 7,026 $ (4,515 ) (64.3 )% Gathering, processing, transloading and other revenue 14,708 11,924 2,784 23.3 % Total Revenues 17,219 18,950 (1,731 ) (9.1 )% OPERATING EXPENSES: Cost of natural gas, NGLs and condensate revenue 2,762 6,479 (3,717 ) (57.4 )% Operation and maintenance 3,637 4,283 (646 ) (15.1 )% General and administrative 1,729 2,482 (753 ) (30.3 )% Property tax expense 363 291 72 24.7 % Depreciation expense 2,238 2,058 180 8.7 % Total operating expenses 10,729 15,593 (4,864 ) (31.2 )% Operating income 6,490 3,357 3,133 93.3 % Interest expense, net of amounts capitalized (212 ) (1,382 ) 1,170 (84.7 )% Gain on interest rate swap - (42 ) 42 (100.0 )% Net income before tax $ 6,278 $ 1,933 $ 4,345 224.8 % Key performance metrics: Gross Margin (1) $ 14,457 $ 12,471 $ 1,986 15.9 % Adjusted EBITDA (1) $ 8,781 $ 6,699 $ 2,082 31.1 % Volumes: Processing Facilities (MMcf/d) (2) 191 224 Transloading Facilities (Bbls/d) (2) 21,317 18,980 (1) Gross Margin and Adjusted EBITDA are not financial measures presented in accordance with GAAP. For a reconciliation of Gross Margin and Adjusted EBITDA to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see "How We Evaluate Our Operations." (2) 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 $4.5 million, or 64.3%, to $2.5 million for the three months ended September 30, 2014 as compared to $7.0 million for the three months ended September 30, 2013. The decrease in natural gas, NGLs and condensate revenue is primarily due to a decrease in net NGL barrels sold, most notably under short-term third-party purchase contracts. This decline attributed to an approximate decrease of $3.7 million in NGL sales for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013. The remaining decrease of approximately $0.8 million is primarily due to declining NGL prices and a decrease in condensate volumes sold. The average price of ethane decreased by 4% to $0.24 per gallon for the three months ended September 30, 2014 from $0.25 per gallon for the three months ended September 30, 2013. Similarly, the average price per gallon of iso butane, normal butane, and natural gasoline decreased by 5%, 6%, and 2%, respectively, for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013. 30 -------------------------------------------------------------------------------- Gathering, processing, transloading and other revenue increased by $2.8 million, or 23.3%, to $14.7 million for the three months ended September 30, 2014 as compared to $11.9 million for the three months ended September 30, 2013, primarily from our minimum volume commitment agreements with Anadarko and AES and the escalation of prices on existing agreements. At our IPO date, we entered into a three-year fee-based gathering and processing agreement with AES with a minimum volume commitment and annual inflation adjustments. For the three months ended September 30, 2014, we recorded $5.1 million in gathering, processing, transloading and other revenue as a result of this contract, as compared to $2.3 million for the three months ended September 30, 2013. At our IPO date, we entered into three-year transloading services agreements with AES, requiring minimum monthly volume commitments for crude oil transloading services. In connection with the East New Mexico Dropdown (see Note 5 "Property, Plant and Equipment"), the Partnership entered into a three-year transloading services agreement with AES, requiring minimum monthly volume commitments for crude oil transloading services. For the three months ended September 30, 2014, we recorded $4.2 million in gathering, processing, transloading and other revenue as a result of these contracts, as compared to $2.3 million for the three months ended September 30, 2013. These increases are net against a decrease of $1.9 million in gathering, processing, transloading and other revenue, primarily a result of decreased volumes under third-party fee-based agreements. 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 $3.7 million, or 57.4%, to $2.8 million for the three months ended September 30, 2014 from $6.5 million for the three months ended September 30, 2013. The decrease is primarily due to a decline in the purchase of NGLs under short-term third-party purchase contracts, which attributed to an approximate decrease of $3.3 million in the cost of natural gas, NGLs and condensate revenue. No such purchases were made during the three months ended September 30, 2014. In addition, a decline in NGL prices and lower volumes of redelivered gas at the tailgate of our plant attributed to an approximate decrease of $0.6 million in cost of natural gas, NGLs and condensate revenue for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013. These decreases were offset by an increase of $0.2 million in cost of natural gas, NGLs and condensate revenue from affiliates, primarily related to the purchase of NGLs from AES under our gathering and processing agreement. Operation and Maintenance Expense. Operation and maintenance expense decreased by $0.6 million, or 15.1%, to $3.6 million for the three months ended September 30, 2014 from $4.3 million for the three months ended September 30, 2013. This decrease is primarily due to a $0.3 million decrease in equity-based compensation expense for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013. In addition, we incurred approximately $0.3 million less in maintenance expense for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013. 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 decreased by $0.8 million, or 30.3%, to $1.7 million for the three months ended September 30, 2014 from $2.5 million for the three months ended September 30, 2013. The decrease is primarily due to a $0.8 million decrease in equity-based compensation expense for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013. Interest Expense. Interest expense, net of amounts capitalized decreased by $1.2 million, or 84.7%, to $0.2 million for the three months ended September 30, 2014 from $1.4 million for the three months ended September 30, 2013. The decrease is primarily due to expensing capitalized loan costs associated with our previous revolving credit facility of $0.8 million during the three months ended September 30, 2013. Additionally, during the three months ended September 30, 2014, our outstanding indebtedness consisted of draws under our new revolving credit facility. During the three months ended September 30, 2013, our outstanding indebtedness consisted of a term loan and revolving credit facility, with significantly higher principal amounts. 31 --------------------------------------------------------------------------------Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013 The following table presents selected financial data for each of the nine months ended September 30, 2014 and 2013. In Thousands Nine Months Ended September 30, 2014 2013 Change % Change REVENUES: Natural gas, NGLs and condensate revenue $ 11,852 $ 14,106 $ (2,254 ) (16.0 )% Gathering, processing, transloading and other revenue 46,631 22,645 23,986 105.9 % Total Revenues 58,483 36,751 21,732 59.1 % OPERATING EXPENSES: Cost of natural gas, NGLs and condensate revenue 14,210 11,687 2,523 21.6 % Operation and maintenance 11,954 11,878 76 0.6 % General and administrative 6,262 5,214 1,048 20.1 % Property tax expense 994 844 150 17.8 % Depreciation expense 6,568 6,093 475 7.8 % Loss on disposal of equipment 60 - 60 100.0 % Total operating expenses 40,048 35,716 4,332 12.1 % Operating income 18,435 1,035 17,400 1,681.2 % Interest expense, net of amounts capitalized (549 ) (4,171 ) 3,622 (86.8 )% Loss on interest rate swap - (47 ) 47 (100.0 )% Net income (loss) before tax $ 17,886 $ (3,183 ) $ 21,069 661.9 % Key performance metrics: Gross Margin (1) $ 44,273 $ 25,064 $ 19,209 76.6 % Adjusted EBITDA (1) $ 26,525 $ 8,412 $ 18,113 215.3 % Volumes: Processing Facilities (MMcf/d) (2) 208 224 Transloading Facilities (Bbls/d) (2) 19,768 18,980 (1) Gross Margin and Adjusted EBITDA are not financial measures presented in accordance with GAAP. For a reconciliation of Gross Margin and Adjusted EBITDA to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see "How We Evaluate Our Operations." (2) 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 $2.3 million, or 16.0%, to $11.9 million for the nine months ended September 30, 2014 from $14.1 million for the nine months ended September 30, 2013. The decrease in natural gas, NGLs and condensate revenue is primarily due to a decrease in net NGL barrels sold under short-term third-party purchase contracts. This decline attributed to an approximate decrease of $3.4 million in NGL sales for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. This decrease is offset by an increase in NGL prices. The average price of ethane increased by 12% to $0.29 per gallon for the nine months ended September 30, 2014 from $0.26 per gallon for the nine months ended September 30, 2013, and the average price of propane increased by 20% to $1.13 per gallon for the nine months ended September 30, 2014 from $0.94 per gallon for the nine months ended September 30, 2013. Increasing NGL prices attributed to an approximate $1.1 million increase in our NGL sales for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. Gathering, processing and other revenue increased by $24.0 million, or 105.9%, to $46.6 million for the nine months ended September 30, 2014 as compared to $22.6 million for the nine months ended September 30, 2013, primarily from our 32 -------------------------------------------------------------------------------- minimum volume commitment agreements with Anadarko and AES and the escalation of prices on existing agreements. We expect the trend of increased volumes under fee-based agreements to continue, consistent with our overall business strategy. At our IPO date, we entered into a three-year fee-based gathering and processing agreement with AES with a minimum volume commitment and annual inflation adjustments. For the nine months ended September 30, 2014, we recorded $16.3 million in gathering, processing, transloading and other revenue as a result of this contract, as compared to $2.3 million for the nine months ended September 30, 2013. At our IPO date, we entered into three-year transloading services agreements with AES, requiring minimum monthly volume commitments for crude oil transloading services. In connection with the East New Mexico Dropdown (see Note 5 "Property, Plant and Equipment"), the Partnership entered into a three-year transloading services agreement with AES, requiring minimum monthly volume commitments for crude oil transloading services. For the nine months ended September 30, 2014, we recorded $11.1 million in gathering, processing, transloading and other revenue as a result of these contracts, as compared to $2.3 million for the nine months ended September 30, 2013. The remaining $1.2 million increase in gathering, processing, transloading and other revenue is primarily a result of increased volumes under third-party fee-based agreements. 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 increased by $2.5 million, or 21.6%, to $14.2 million for the nine months ended September 30, 2014 as compared to $11.7 million for the nine months ended September 30, 2013. The increase is primarily due to the purchase of NGLs under our gathering and processing agreement with AES. During the nine months ended September 30, 2014, we purchased $10.5 million of NGLs from AES, as compared to $1.3 million purchases of NGLs from AES during the nine months ended September 30, 2013, resulting in an increase of $9.2 million in cost of natural gas, NGLs and condensate revenue. This increase is offset by an approximate decrease of $3.3 million in cost of natural gas, NGLs, and condensate revenue, related to purchases of NGLs under short-term third-party purchase contracts during the nine months ended September 30, 2013. No such purchases were made during the nine months ended September 30, 2014. In addition, we recorded $3.0 million of affiliate cost of revenues during the nine months ended September 30, 2013, primarily related to the purchase of natural gas from a subsidiary of SEV under certain keep-whole agreements. 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. Prior to our IPO, 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. At the closing of our IPO, we assigned all of our keep-whole agreements to AES. The remaining decrease of approximately $0.4 million is primarily related to lower volumes of redelivered gas at the tailgate of our plant during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. General and Administrative Expense. General and administrative expense increased by approximately $1.0 million, or 20.1%, to $6.3 million for the nine months ended September 30, 2014 from $5.2 million for the nine months ended September 30, 2013. The increase is primarily due to costs of being a publicly traded partnership, including board of director fees, internal control compliance costs, and other professional services fees. We incurred an increase of approximately $0.9 million in such costs for the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013. In addition, equity-based compensation expense increased by $0.1 million for the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013. Interest Expense. Interest expense, net of amounts capitalized, decreased by approximately $3.6 million, or 86.8%, to $0.5 million for the nine months ended September 30, 2014 as compared to $4.2 million for the nine months ended September 30, 2013. The decrease is primarily due to expensing capitalized loan costs associated with our previous revolving credit facility of $0.8 million during the nine months ended September 30, 2013. Additionally, during the nine months ended September 30, 2014, our outstanding indebtedness consisted of draws under our new revolving credit facility. During the nine months ended September 30, 2013, our outstanding indebtedness consisted of a term loan and revolving credit facility, with significantly higher principal amounts. 33-------------------------------------------------------------------------------- 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, sources of liquidity included cash generated from operations, equity investments by our sole member and borrowings under our historical credit facility prior to the IPO. We expect ongoing sources of liquidity 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. We intend to pay a minimum quarterly distribution of $0.365 per unit per quarter, which equates to $6.6 million per quarter, or approximately $26.4 million per year. 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 Concurrently with the closing of our IPO, we entered into a 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 revolving credit facility to up to $150.0 million. The 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 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 revolving credit facility also contains covenants that, among other things, require 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 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; • amend or modify certain agreements and documents; 34 --------------------------------------------------------------------------------• incur certain capital expenditures; • engage in certain prohibited transactions; • enter into burdensome agreements; and • act as a transmitting utility or as a utility. Our revolving credit facility also 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 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 revolving credit facility would be entitled to take various actions, including the acceleration of amounts due under our revolving credit facility and all actions permitted to be taken by a secured creditor. As of September 30, 2014, we were in compliance with all covenants under our revolving credit facility. As of September 30, 2014, we had unused capacity under our revolving credit facility of $39.0 million and outstanding borrowings of $11.0 million. CASH FLOWS Net cash flows provided by (used in) operating activities, investing activities and financing activities for the nine months ended September 30, 2014 and 2013 were as follows: In Thousands Nine Months Ended September 30, 2014 2013 Change Net cash provided by (used in): Operating activities $ 26,045 $ 1,582 $ 24,463 Investing activities $ (9,052 ) $ (10,947 ) $ 1,895 Financing activities $ (17,716 ) $ 9,763 $ (27,479 ) Operating Activities. Cash flows provided by operating activities increased by $24.5 million to $26.0 million for the nine months ended September 30, 2014, as compared to $1.6 million for the nine months ended September 30, 2013. The increase is primarily due to an increase in net income discussed above under "Results of Operations" after excluding the effect of depreciation expense, amortization of deferred financing costs and equity-based compensation. In addition, during the nine months ended September 30, 2014, amounts owed to affiliates increased primarily from the gathering and processing agreement with AES, and amounts due from affiliates decreased. This was offset by an increase in amounts due from third-party customers. Investing Activities. Cash flows used in investing activities increased by $1.9 million to $9.1 million for the nine months ended September 30, 2014 as compared to $10.9 million for the nine months ended September 30, 2013. Cash paid for capital expenditures during the nine months ended September 30, 2014 relates to several major construction projects, including projects to expand the services offered at, and the capacity of, our Panola County processing facilities. Cash paid for capital expenditures during the nine months ended September 30, 2013 primarily includes payments made to construct the Oak Hill Lateral, which was completed in March 2013, and install molecular mole sieves at our Panola 1 processing facility. 35 -------------------------------------------------------------------------------- Financing Activities. Cash flows from financing activities in historical periods were primarily driven by borrowing under our historical credit facility and capital contributions from our sole member prior to the IPO. 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 used in financing activities increased by $27.5 million to $17.7 million for the nine months ended September 30, 2014, as compared to cash provided by financing activities of $9.8 million for the nine months ended September 30, 2013. The increase in cash used in financing activities in 2014 is primarily related to distributions paid to unit holders of $19.2 million and an excess cash purchase price over the historical carrying value of assets acquired of $5.5 million related to the East New Mexico Dropdown purchased from NuDevco Midstream Development. In addition, we had borrowings under our revolving credit facility of $23.5 million, repayments of $16.5 million, and an issuance of general partner units of $0.1 million. During the nine months ended September 30, 2013, we had borrowings under our new revolving credit facility of $25.0 million and our previous credit facility of $9.0 million, net against debt repayments of $16.5 million on our new revolving credit facility and $135.5 million on our previous credit facility. We also recorded net proceeds from the IPO of $125.3 million, and capital contributions of $3.6 million prior to the IPO. 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 nine months ended September 30, 2014 and 2013, we incurred approximately $1.2 million and $1.6 million, respectively, for maintenance capital expenditures and incurred approximately $6.9 million and $9.7 million, respectively, for expansion capital expenditures. Subsequent to the IPO from July 31, 2013 to September 30, 2013, we incurred $0.1 million of maintenance capital expenditures. During the nine months ended September 30, 2014, expansion capital expenditures related to projects to expand the services offered at, and the capacity of, our Panola County processing facilities. During the nine months ended September 30, 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 I processing facility. OFF-BALANCE SHEET ARRANGEMENTS We do not have any off-balance sheet arrangements that have or are reasonably likely to have a significant current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. 36 -------------------------------------------------------------------------------- CONTRACTUAL OBLIGATIONS A summary of our contractual obligations as of September 30, 2014 is as follows: In Thousands 2014 2015 2016 Thereafter Total Operating services agreements (1) $ 136 $ 530 $ 478 $ 1,174 $ 2,318 Long-term debt (2) - - - 11,000 11,000 Total $ 136 $ 530 $ 478 $ 12,174 $ 13,318 (1) Amounts relate to minimum payments for operating services agreements having initial or remaining non-cancellable lease terms in excess of one year, primarily relating to our crude oil logistics facilities. (2) $11.0 million was outstanding under our revolving credit facility at September 30, 2014 (see Note 6 "Long-Term Debt and Interest Expense"). Our revolving credit facility matures on July 31, 2017. CRITICAL ACCOUNTING POLICIES AND ESTIMATES As of September 30, 2014, there have been no significant changes to our critical accounting policies and estimates disclosed in the Annual Report on Form 10-K. Our significant accounting policies are described in Note 2 to our audited consolidated and combined financial statements included in our Annual Report on Form 10-K. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America and pursuant to the rules and regulations of the SEC, which requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our financial condition and results of operations. 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. 37 -------------------------------------------------------------------------------- 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 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 September 30, 2014, we did not have any material outstanding lawsuits, administrative proceedings or governmental investigations. 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 fully vested on February 15, 2014. The phantom unit awards to board members of the Partnership's general partner fully vested on February 15, 2014. NEW ACCOUNTING STANDARDS On May 28, 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting. 38-------------------------------------------------------------------------------- |