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UNITED STATESSECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORTPursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934Date of Report (Date of earliest event reported): September 15, 2017
AMERICAN MIDSTREAM PARTNERS, LP(Exact name of registrant as specified in its charter)
Delaware 001-35257 27-0855785
(State or other jurisdictionof incorporation)
(CommissionFile Number)
(I.R.S. EmployerIdentification No.)
2103 CityWest Blvd., Bldg. 4, Suite 800 77042
Houston, TX (Zip Code)
(Address of principal executive offices)
Registrant’s telephone number, including area code: (346) 241-3400Not applicable
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the Registrant under any of the followingprovisions:
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) orRule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
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Item 8.01 Other Events.
On March 8, 2017, American Midstream Partners, LP (the “Partnership’’) completed its acquisition of JP Energy Partners LP (“JPE”) pursuant to thatcertain Agreement and Plan of Merger, dated as of October 23, 2016 (the “Merger Agreement”), by and among the Partnership, American Midstream GP, LLC, aDelaware limited liability company and the general partner of the Partnership, JPE, JPE Energy GP II LLC, a Delaware limited liability company and the generalpartner of JPE, Argo Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership (“AMID Merger Sub”), and ArgoMerger GP Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Partnership. Under the terms of the Merger Agreement, amongother things, AMID Merger Sub merged into and with JPE (the “JPE Merger”), with JPE surviving the JPE Merger as a wholly owned subsidiary of thePartnership. The JPE Merger was a transaction between entities under common control. As a result, the Partnership has recast its financial statements toretrospectively reflect the JPE Merger.
The Partnership’s Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”) as filed with the U.S. Securities and Exchange Commission(the “SEC”) on March 28, 2017 is hereby recast by this Current Report on Form 8-K as follows:
• Selected Financial Data included herein on Exhibit 99.1 supersedes Part II, Item 6 of the 2016 Form 10-K;• Management’s Discussion and Analysis of Financial Condition and Results of Operations included herein as Exhibit 99.2 supersedes Part II, Item 7
of the 2016 Form 10-K; and• Financial Statements and Supplementary Data included herein as Exhibit 99.3 supersedes Part II, Item 8 of the 2016 Form 10-K.
There have been no revisions or updates to any other sections of the 2016 Form 10-K other than the revisions noted above. This Current Report on Form8-K should be read in conjunction with the 2016 Form 10-K.
Item 9.01 Financial Statements and Exhibits
(d)Exhibits.
Exhibit Number Description23.1 Consent of Independent Registered Public Accounting Firm.99.1 Selected Financial Data.99.2 Management’s Discussion and Analysis of Financial Condition and Results of Operations.99.3 Financial Statements and Supplementary Data.
101.INS XBRL Instance Document101.SCH XBRL Taxonomy Extension Schema Document101.CAL XBRL Taxonomy Extension Calculation Linkbase Document101.DEF XBRL Taxonomy Extension Definition Linkbase Document101.LAB XBRL Taxonomy Extension Label Linkbase Document101.PRE XBRL Taxonomy Extension Presentation Linkbase Document
CAUTIONARY STATEMENTS
Disclosures in this Form 8-K and the exhibits filed herewith contain certain “forward-looking statements” within the meaning of Section 21E of the SecuritiesExchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. You can typically identify forward-looking statements by the useof words, such as "may," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast" and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projectedcosts and plans and objectives of management for future operations, are forward-looking statements.
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These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertaintiesand other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed orimplied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but arenot limited to, the risks set forth in "Item 1A. Risk Factors" in the 2016 Form 10-K as well as the following risks and uncertainties:
• our ability to generate sufficient cash from operations to pay distributions to unitholders;
• our ability to maintain compliance with financial covenants and ratios in our Credit Facility (as defined in the 2016 Form 10-K);
• our ability to timely and successfully identify, consummate and integrate our current and future acquisitions and complete strategic dispositions,including the realization of all anticipated benefits of any such transaction, which otherwise could negatively impact our future financial performance;
• the timing and extent of changes in natural gas, crude oil, NGLs and other commodity prices, interest rates and demand for our services;
• our ability to access capital to fund growth, including new and amended credit facilities and access to the debt and equity markets, which will depend ongeneral market conditions;
• severe weather and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;
• the level of creditworthiness of counterparties to transactions;
• the level and success of natural gas and crude oil drilling around our assets and our success in connecting natural gas and crude oil supplies to ourgathering and processing systems;
• our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks;
• changes in laws and regulations, particularly with regard to taxes, safety, regulation of over-the-counter derivatives market and entities, and protectionof the environment;
• our failure or our counterparties’ failure to perform on obligations under commodity derivative and financial derivative contracts;
• the performance of certain of our current and future projects and unconsolidated affiliates that we do not control;
• the demand for NGL products by the petrochemical, refining or other industries;
• our dependence on a relatively small number of customers for a significant portion of our gross margin;
• general economic, market and business conditions, including industry changes and the impact of consolidations and changes in competition;
• our ability to renew our gathering, processing, transportation and terminal contracts;
• our ability to successfully balance our purchases and sales of natural gas;
• the adequacy of insurance to cover our losses;
• our ability to grow through contributions from affiliates, acquisitions or internal growth projects;
• our management's history and experience with certain aspects of our business and our ability to hire as well as retain qualified personnel to execute ourbusiness strategy;
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• the cost and effectiveness of our remediation efforts with respect to the material weakness discussed in "Part II. Item 9A. Controls and Procedures" inthe 2016 Form 10-K;
• volatility in the price of our common units;
• security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and
• the amount of collateral required to be posted from time to time in our transactions.
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and,therefore, we cannot assure you that the forward-looking statements included in this Current Report on Form 8-K and the exhibits filed herewith will prove to beaccurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fullydescribed in "Item 1A. Risk Factors" in the 2016 Form 10-K. Statements in this Current Report on Form 8-K speak as of the date of this report. Except as may berequired by applicable securities laws, we undertake no obligation to publicly update or advise investors of any change in any forward-looking statement, whetheras a result of new information, future events or otherwise.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersignedhereunto duly authorized.
American Midstream Partners, LP By: American Midstream GP, LLC, itsGeneralPartnerDate: September 15, 2017 By: /s/ Eric T. Kalamaras Name: Eric T. Kalamaras Title: Senior Vice President & Chief Financial Officer
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EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S‑3 (Nos. 333-198888, 333-201434, and 333-201436) and on FormS‑8 (Nos. 333-216585, 333-176438, 333-183290, and 333-209614) of American Midstream Partners, LP of our report dated March 24, 2017, except with respectto our opinion on the consolidated financial statements insofar as it relates to the effects of the acquisition of JP Energy Partners, LP which is discussed in Note 2to the consolidated financial statements and to the third paragraph of Note 24, as to which the date is September 15, 2017, relating to the financial statements andthe effectiveness of internal control over financial reporting, which appears in this Current Report on Form 8‑K, dated September 15, 2017.
/s/ PricewaterhouseCoopers LLPHouston, TexasSeptember 15, 2017
EXHIBIT 99.1
Item 6. Selected Historical Financial and Operating Data
The following table presents selected historical consolidated financial and operating data for the periods and as of the dates indicated. We derived this informationfrom our historical consolidated financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, byreference to those consolidated financial statements and notes, which for the years 2016 , 2015 , and 2014 begin on F-1 included in Exhibit 99.3 to our CurrentReport on Form 8-K filed on September 15, 2017 (the "Recast Form 8-K").
On March 8, 2017 we acquired JP Energy Partners, LP ("JPE") in a unit-for-unit exchange. As both the Partnership and JPE were controlled by ArcLight, theacquisition represents a transaction among entities under common control and is accounted for as a common control transaction in a manner similar to a pooling ofinterests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before itobtained control the Partnership. The following selected historical financial information represent JPE’s historical cost basis financial information recast to reflectthe acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on which ArcLight obtained control of the Partnership.
For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" included inExhibit 99.2 to the Recast Form 8-K.
Years ended December 31,
2016 (1) 2015 (1) 2014 (1) 2013 (1) 2012 (6)
(in thousands, except per unit and operating data)Statements of Operations Data:
Revenues: Total operating revenue $ 726,922 $ 913,887 $ 1,020,792 $ 614,890 $ 204,391
Operating expenses: Cost of sales 443,023 630,303 789,872 435,783 151,478Direct operating expenses 123,372 127,480 109,543 81,377 26,292Corporate expenses 99,430 77,835 72,744 62,931 20,785Depreciation, amortization and accretion 106,818 98,596 72,527 57,096 12,941
Loss on sale of assets, net 2,870 3,920 5,080 1,492 1,142Loss on impairment of property, plant andequipment 697 — 21,344 8,830 —Loss on impairment of goodwill 15,456 148,488 — — — Total operating expenses 791,666 1,086,622 1,071,110 647,509 212,638
Operating loss (64,744) (172,735) (50,318) (32,619) (8,247)Other income (expense):
Interest expense (21,469) (20,120) (16,558) (15,513) (3,249)Other income (expense) 628 1,732 (662) 887 320Loss on extinguishment of debt — — (1,634) — (497)Earnings in unconsolidated affiliates 40,158 8,201 348 — —
Income (loss) from continuing operations beforeincome taxes (45,427) (182,922) (68,824) (47,245) (11,673)Income tax (expense) benefit (2,578) (1,888) (857) 287 (222)Income (loss) from continuing operations (48,005) (184,810) (69,681) (46,958) (11,895)Discontinued operations:
Income (loss) from discontinued operations, netof tax (539) (15,031) (9,886) 12,506 3,507
Net Loss (48,544) (199,841) (79,567) (34,452) (8,388)
EXHIBIT 99.1
Net income (loss) attributable to non-controllinginterests 2,766 (13) 3,993 705 —
Net loss attributable to the Partnership $ (51,310) $ (199,828) $ (83,560) $ (35,157) $ (8,388)
General Partner's Interest in net loss $ (233) $ (1,823) $ (398) $ (864) $ —
Limited Partners' Interest in net loss $ (51,077) $ (198,005) $ (83,162) $ (34,293) $ (8,388)
Limited Partners' net (loss) per common unit: Basic and diluted:
Loss from continuing operations $ (1.59) $ (4.59) $ (3.28) $ (3.16) $ (0.58)Loss from discontinued operations (0.01) (0.33) (0.01) (0.12) —
Net loss $ (1.60) $ (4.92) $ (3.29) $ (3.28) $ (0.58)Weighted average number of common unitsoutstanding:
Basic and diluted (2) 51,176 45,050 27,524 18,931 12,069
Statement of Cash Flow Data: Net cash provided by (used in):
Operating activities $ 90,639 $ 86,978 $ 51,635 $ 29,500 $ (6,990)Investing activities (564,504) (250,769) (518,023) (115,173) (292,334)Financing activities 477,544 161,954 466,577 79,156 304,991
Other Financial Data: Adjusted EBITDA (3) $ 167,012 $ 84,756 $ 60,698 $ 57,462 $ 14,560Gross margin (4) 310,787 269,054 231,133 170,616 51,326Cash distribution declared per common unit 3.01 3.17 1.85 1.75 —Segment gross margin:
Gathering and Processing 48,245 65,692 51,213 5,673 —Liquid Pipelines and Services 29,760 24,160 22,564 4,850 3,465Natural Gas Transportation Services 18,616 18,073 13,691 13,150 —Offshore Pipeline and Services 82,346 33,613 29,089 36,318 —Terminalling Services 42,872 36,079 34,493 36,248 1,732Propane Marketing Services 88,948 91,437 80,083 74,377 46,129
Balance Sheet Data (at period end): Cash and cash equivalents $ 5,666 $ 1,987 $ 3,824 $ 3,627 $ 10,099Accounts receivable and unbilled revenue 83,415 79,259 138,268 152,742 80,551Property, plant and equipment, net 1,145,003 1,071,514 972,351 618,012 181,142Total assets 2,349,321 1,751,889 1,865,210 1,292,695 562,124Current portion of long-term debt 5,485 2,899 3,291 3,284 2,973Long-term debt 1,235,538 687,100 457,075 314,984 164,766
Operating Data: Gas Gathering and Processing Services: Averagethroughput(MMcf/d) 220.6 240.0 155.8 129.5 —Averageplantinletvolume(MMcf/d)(5) 102.1 120.9 89.1 125.7 —AveragegrossNGLproduction(Mgal/d)(5) 192.9 231.1 64.2 50.4 —Averagegrosscondensateproduction(Mgal/d)(5) 82.9 97.1 70.8 45.5 —
Liquid Pipelines and Services:
EXHIBIT 99.1
AveragethroughputPipeline(Bbl/d) 32,257 34,946 20,868 13,738 —AveragethroughputTruck(Bbl/d) 1,628 — — — —Natural Gas Transportation Services: Averagethroughput(MMcf/d) 389.9 364.1 373.3 364.9 —Averagefirmtransportation-capacityreservation(MMcf/d) 634.7 637.2 567.9 592.5 —Averageinterruptibletransportation-throughput(MMcf/d) 65.3 70.2 65.3 106.4 —
Offshore Pipelines and Services: Averagethroughput(MMcf/d) 466.4 442.8 524.6 498.9 —
Averagegrosscondensateproduction(Mgal/d)(5) 3.6 2.7 4.4 1.2 —Averagefirmtransportation-capacityreservation(MMcf/d) 53.4 16.6 10.0 — —Averageinterruptibletransportation-throughput(MMcf/d) 288.7 340.1 403.7 361.6 —
Terminalling Services: StorageCapacity(Bbls) 5,011,133 4,487,542 4,247,058 4,114,792 3,000,000DesignCapacity(Bbls) 5,173,717 4,688,950 4,363,817 4,165,600 3,000,000Storageutilization 96.9% 95.7% 97.3% 99.0% 100.0%TerminallingandStoragethroughput(Bbls/d) 56,741 62,075 63,859 69,071 57,143
Propane Marketing Services: NGLandrefinedproductsales(Mgal/d) 181 211 200 181 129
(1) The following transactions affect comparability between years: i) in October 2016 and April 2016 we acquired 6.2% and 1% non-operated interests in DeltaHouse Class A Units,which we account for as equity method investments and are included in our Offshore Pipelines and Services segment; ii) in April2016, we acquired membership interests in Destin ( 49.7% ), Tri-States ( 16.7% ), Okeanos ( 66.7% ), and Wilprise ( 25.3% ), which we account for asequity method investments and are included in our Liquid Pipelines and Services and Offshore Pipelines and Services segments; iii) in April 2016 weacquired a 60% interest in American Panther which we consolidate for financial reporting purposes and is included in our Offshore Pipelines and Servicessegment; iv) in September 2015, we acquired a non-operated 12.9% indirect interest in Delta House Class A Units, which we account for as an equitymethod investment and is included in our Offshore Pipelines and Services segment; v) in February 2016, we completed the sale of our crude oil supply andlogistics operations which was included in our Liquid Pipelines and Services segment ;vi) in October 2014 and January 2014, we acquired the Costar andLavaca systems, respectively, both of which are included in our Gas Gathering and Processing Services segment; vii) in June 2014, we completed the saleof our crude oil logistics operations which was included in our Liquids Pipelines and Services segment; viii) in December 2013, we acquired Blackwater,which is included in our Terminals segment; and ix) in April 2013, we acquired the High Point System, which is included in Transmission segment.
(2) Includes unvested phantom units with distribution equivalent rights ("DERs"), which are considered participating securities, of 200,000 at December 31,2016 and 2015.
(3) For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance withGAAP and a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Item 7. Management's Discussion andAnalysis — How We Evaluate Our Operations" included in Exhibit 99.2 to the Recast Form 8-K.
(4) For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAPand a discussion of how we use gross margin to evaluate our operating performance, please read "Item 7. Management's Discussion and Analysis — HowWe Evaluate Our Operations" included in Exhibit 99.2 to the Recast Form 8-K.
(5) Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read"Item 7. Management's Discussion and Analysis — Our Operations - Gathering and Processing Segment" included in Exhibit 99.2 to the Recast Form 8-K.
(6) The 2012 selected financial data represents JPE financial activity only, given the common control was April 15, 2013; as mentioned above.
EXHIBIT 99.2
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
ThefollowingdiscussionandanalysisofourfinancialconditionandresultsofoperationsshouldbereadinconjunctionwiththeauditedconsolidatedfinancialstatementsandtherelatednotestheretoincludedelsewhereinExhibit99.3totheCurrentReportonForm8-KfiledbyAmericanMidstreamPartners,LP(alongwithitsconsolidatedsubsidiaries,“we,”“us,”“our,”orthe“Partnership”)onSeptember15,2017(the“RecastForm8-K”).Thisdiscussioncontainsforward-lookingstatementsthatreflectmanagement’scurrentviewswithrespecttofutureeventsandfinancialperformance.Ouractualresultsmaydiffermateriallyfromthoseanticipatedintheseforward-lookingstatementsorasaresultofcertainfactorssuchasthosesetforthunderthecaption“CautionaryStatementAboutForward-LookingStatements”includedinourAnnualReportonForm10-KfortheyearendedDecember31,2016(the“2016Form10-K”)asfiledwiththeU.S.SecuritiesandExchangeCommission(the“SEC”)onMarch28,2017.
On March 8, 2017, the Partnership completed the acquisition of JP Energy Partners, LP ("JPE"), an entity controlled by ArcLight affiliates, in a unit-for-unitexchange. In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right toreceive 0.5775 of a Partnership common unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225of a Partnership common unit. The Partnership issued a total of 20.2 million of its common units to complete the acquisition, including 9.8 million common unitsto ArcLight affiliates. Based upon the closing price for our common units on March 8, 2017, the units issued in the exchange had an estimated fair value of $322.2million.
JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refinedproducts terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil,refined products and NGLs, in the United States.
As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and is accounted for asa common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer foraccounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPEhistorical cost basis financial statements, recast to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date onwhich ArcLight obtained control of the Partnership. See Item 8. Financial Statements and Supplementary Data - Note 2 in Exhibit 99.3 to the Recast Form 8-K formore information on the JPE Merger.
As previously reported in Part II, Item 9A of our 2016 Form 10-K management assessed the effectiveness of the Partnership’s internal control over financialreporting as of December 31, 2016, based on criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on this evaluation of internal control over financial reporting, management concluded that as of December 31,2016, the Partnership did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, expertise and trainingcommensurate with its financial reporting requirements. Specifically, individuals within the Partnership’s financial accounting and reporting functions did not havethe appropriate level of expertise to ensure that complex, non-routine transactions of the Partnership were recorded appropriately. This control deficiency resultedin out-of-period adjustments recorded to the consolidated statement of operations in the fourth quarter of 2016 and a revision to the 2015 consolidated balancesheet and consolidated statement of cash flows. Management concluded that this deficiency in internal control over financial reporting could result in materialmisstatements of the Partnership’s annual or interim consolidated financial statements that would not be prevented or detected on a timely basis. Accordingly, inconnection with the assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016, management concludedthat this control deficiency constituted a material weakness. Because of this material weakness in internal control over financial reporting, management concludedthat the Partnership’s internal control over financial reporting was not effective as of December 31, 2016. Management has not undertaken, and is not required tohave undertaken, an assessment of the effectiveness of the Partnership’s internal control over financial reporting since the assessment of the Partnership’s internalcontrol over financial reporting as of December 31, 2016, as described above.
The controls of JPE were not part of the Partnership’s internal control over financial reporting as of December 31, 2016. Accordingly, the controls operated at JPEwere not included in either management’s assessment of the Partnership’s internal controls over financial reporting as of December 31, 2016 or inPricewaterhouseCoopers, LLP’s audit of such controls. Effective March 8, 2017, JPE is a wholly-owned subsidiary of the Partnership whose total assets and totalrevenue represented 28.7% and 68.0%, respectively, of the recast consolidated financial statement amounts as of and for the year ended December 31, 2016included in Exhibit 99.3 to the Recast Form 8-K.
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EXHIBIT 99.2
Overview
We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of midstreamenergy assets. We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerousintermediate and end-use markets. Through our six financial reporting segments, (i) gas gathering and processing services, (ii) liquids pipelines and services, (iii)natural gas transportation services, (iv) offshore pipelines and services, (v) terminalling services and (vi) propane marketing services, we engage in the business ofgathering, treating, processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transportingcrude oil and condensates; storing specialty chemical products; and selling propane and refined products.
Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Ourgathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the EagleFord Shale of South Texas, and (iv) offshore in the Gulf of Mexico. Our liquids pipelines, natural gas transportation and offshore pipelines and terminal assets arelocated in prolific producing regions and key demand markets in Alabama, Louisiana, Mississippi, North Dakota, Texas, Tennessee and in the Port of New Orleansin Louisiana and the Port of Brunswick in Georgia. Additionally, our Propane Marketing Services assets are located in 46 states in the U.S. and we also operate afleet of NGL gathering and transportation trucks in the Eagle Ford shale and the Permian Basin.
We own or have ownership interests in more than 3,800 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 16 gatheringsystems, six interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floatingproduction system with nameplate processing capacity of 80 MMBbl/d of crude oil and 200 MMcf/d of natural gas; and six marine terminal sites withapproximately 6.7 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products; and 97transportation trucks.
A portion of our cash flow is derived from our investments in unconsolidated affiliates including a 49.7% operated interest in Destin, a natural gas pipeline; a20.1% non-operated interest in the Class A Units of Delta House, which is a floating production system platform and related pipeline infrastructure; a 16.7% non-operated interest in Tri-States, an NGL pipeline; a 66.7% operated interest in Okeanos, a natural gas pipeline; a 25.3% non-operated interest in Wilprise, a NGLpipeline; and a 66.7% non-operated interest in MPOG, a crude oil gathering and processing system.
Significant financial highlights during the year ended December 31, 2016 , include the following:
• Net loss attributable to the Partnership decreased by $148.5 million for the year ended December 31, 2016 as compared to the same period in 2015,primarily due to a decrease of $133.0 million in goodwill impairment charges, an increase in earnings in unconsolidated affiliates of $32.0 millionprimarily from our investments in Delta House and the entities underlying the Emerald Transactions, offset by an increase in corporate expense of $21.6million due to our corporate relocation and JPE Merger expenses;
• Adjusted gross margin increased by $41.7 million , or 15.5% , as compared to the same period in 2015 primarily attributable to an increase in ourOffshore Pipelines and Services segment gross margin of $48.7 million as a result of increased revenues received by the Partnership due to the Pascagoulaplant shutdown. The Pascagoula plant is not controlled or owned by the Partnership. As a result of the Pascagoula plant shutdown, volumes wereredirected to our High Point system. Additionally, the incremental earnings from our equity method investees increased by $32.0 million, of which $29.9million was attributable to our Offshore Pipelines and Services segment;
• Adjusted EBITDA increased by $82.3 million, or 97.1%, as compared to the same period in 2015 primarily due to distributions from our investments inDelta House and entities underlying the Emerald Transactions; and
• We distributed $112.1 million to our common unitholders;
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EXHIBIT 99.2
• On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the "Mid-Continent Business"), in connection with JPDevelopment's, an affiliated entity, sale of its GSPP pipeline assets to a third party buyer. The sales price related to the Mid-Continent Business was $9.7million; which included certain adjustments related to inventory and working capital items. We recognized a loss on the disposal of approximately $12.9million during the year ended December 31, 2015. We continue to retain our crude oil storage operations in the Mid-Continent area of Oklahoma;
• On April 25, 2016 and April 27, 2016, we acquired a 16.7% interest in Tri-States, an NGL pipeline; a 66.7% interest in Okeanos, a natural gas pipeline, a49.7% interest in Destin, a natural gas pipeline, and a 25.3% interest Wilprise, an NGL pipeline for $211.0 million. We funded the aggregate purchaseprice with the issuance of 8,571,429 Series C Convertible Preferred Units and a warrant to purchase up to 800,000 of our common units at an exerciseprice of $7.25 per common unit with a combined value of approximately $120.0 million , plus additional borrowings of $91.0 million under our revolvingcredit agreement;
• On April 25, 2016, the Partnership increased its investment in Delta House through the purchase of 100% of the outstanding membership interests in D-Day, which owned 1.0% of Delta House Class A Units in exchange for approximately $9.9 million;
• On September 30, 2016, we completed the issuance of the 3.77% Senior Notes, which provided net proceeds of approximately $57.7 million afterdeducting related issuance costs;
• On October 23, 2016, we announced the acquisition of JPE. The transaction closed on March 8, 2017 and resulted in a larger and more diversifiedmidstream business;
• On October 31, 2016, we acquired an additional 6.2% non-operated direct interest in Delta House Class A Units for a purchase price of approximately$48.8 million , which was funded with net proceeds of $34.5 million from the issuance of 2,333,333 Series D Convertible Preferred Units plus $14.3million of additional borrowings under our revolving credit agreement. If any Series D Units remain outstanding on June 30, 2017, the Partnership willissue the Series D unitholders a warrant to purchase up to 700,000 common units at an exercise price of $22.00 per common unit;
• On December 28, 2016, we completed the issuance of the 8.50% Senior Notes which provided net proceeds of approximately $291.3 million afterdeducting issuances costs;
Significant operational highlights during the year ended December 31, 2016 , include the following:
• The percentage of gross margin generated from fee-based, fixed-margin, firm and interruptible transportation contracts and firm storage contracts(excluding propane) was 91.4% representing a 2.8% increase compared to 2015;
• Average gross condensate production totaled 86.6 Mgal/d, representing a 13.2 Mgal/d or 13.2% decrease compared to 2015 due to lower condensateprices of 10.9% and 22.1% in our Gas Gathering and Processing Services and Offshore Pipelines and Services segments, respectively;
• Throughput volumes attributable to the Partnership totaled 1,076.9 MMcf/d, representing a 2.9% increase compared to 2015 due to the Pascagoula plantshutdown, which redirected volumes to our High Point system;
• Pipelines throughput volumes attributable to our Liquid Pipelines and Services segment totaled 32,257 Bbls/d, representing a 14.2% increase compared to2015 due to an increase in activity around our Silver Dollar Pipeline system;
• Contracted capacity for our Terminals segment averaged 5,011,233 barrels, representing a 11.7% increase compared to 2015 due to the expansion effortsat our Harvey terminal;
• Average gross NGL production totaled 192.9 Mgal/d, representing a 38.2 Mgal/d or 16.5% decrease compared to 2015; and,
• NGL and refined product sales totaled 181 Mgal/d, representing a 30 Mgal/d or 14.2% decrease compared to 2015, driven by a decline in volumesassociated with oilfield services and overall warmer than normal temperatures sustained in the year ended December 31, 2016.
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EXHIBIT 99.2
Our Operations
We manage our business and analyze and report our results of operations through six reportable segments:
• Gas Gathering and Processing Services. Our Gas Gathering and Processing segment provides "wellhead-to-market" services to producers ofnatural gas and natural gas liquids, which include transporting raw natural gas from various receipt points through gathering systems, treating theraw natural gas, processing raw natural gas to separate the NGLs from the natural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.
• Liquid Pipelines and Services. Our Liquid Pipelines and Services segment provides transportation, purchase and sales of crude oil from variousreceipt points including lease automatic customer transfer ("LACT") facilities and deliveries to various markets.
• Natural Gas Transportation Services . Our Natural Gas Transportation Services segment transports and delivers natural gas from producingwells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies ("LDCs"), utilitiesand industrial, commercial and power generation customers.
• Offshore Pipelines and Services. Our Offshore Pipelines and Services segment gathers and transports natural gas and crude oil from variousreceipt points to other pipeline interconnects, onshore facilities and other delivery points.
• Terminalling Services. Our Terminalling Services segment provides above-ground leasable storage operations at our marine terminals thatsupport various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and alsoincludes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas.
• Propane Marketing Services. Our Propane Marketing Services segment gathers, transports and sells natural gas liquids (NGLs). This isaccomplished through cylinder tank exchange, sales through retail, commercial and wholesale distribution and through a fleet of trucks operatingin the Eagle Ford and Permian Basin areas.
Gas Gathering and Processing Services Segment
Our results of operations from our Gas Gathering and Processing Services segment are determined primarily by the volumes of natural gas and crude oil we gather,process and fractionate, the commercial terms in our current contract portfolio and natural gas, crude oil, NGL, and condensate prices. We gather and processnatural gas and crude oil primarily pursuant to the following arrangements:
• Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed fee for gathering, processing and transporting natural gasand crude oil.
• Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas and off-spec condensate from producers or suppliers atreceipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas or off-spec condensate at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales ofnatural gas or off-spec condensate, we are able to lock in a fixed margin on these transactions. We view the segment gross margin earned underour fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements.
• Percent-of-Proceeds Arrangements ("POP"). Under these arrangements, we generally gather raw natural gas from producers at the wellhead orother supply points, transport it through our gathering system, process it and sell the residue natural gas, NGLs and condensate at market prices.Where we provide processing services at the processing plants that we own, or obtain processing services for our own account in connectionwith our elective processing arrangements, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. However, wealso have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas. Our POParrangements also often contain a fee-based component.
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EXHIBIT 99.2
Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas and crude oil that flows through our systemsand is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in throughput volumes fromproducers and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but upside in higher commodity-price environments is limited to an increase in throughput volumes from producers. Under our typical POP arrangement, our gross margin is directly impacted bythe commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our POP arrangementsalso often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. Wefurther seek to mitigate our exposure to commodity price risk through our hedging program.
Liquid Pipelines and Services Segment
Results of operations from the Liquid Pipelines and Services segment are determined by the volumes of crude oil transported on the interstate and intrastatepipelines we own. Tariffs associated with our Bakken system are regulated by FERC for volumes gathered via pipeline and trucked to the AMID Truck facility inWatford City, North Dakota. Volumes transported on our Silver Dollar system are underpinned by long-term, fee-based contracts. Our transportation arrangementsare further described below:
• Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport crude oilnominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipperpays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use chargewith respect to quantities actually transported by us.
• Uncommitted Shipper Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated totransport crude oil nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation chargebut pays a variable-use charge for quantities actually shipped.
• Fee-Based Arrangements. Under these arrangements our operations are underpinned by long-term, fee-based contracts with leading producersin the Midland Basin. Some of these contracts also have minimum volume commitments as well as some have acreage dedications.
Natural Gas Transportation Services Segment
Results of operations from our Natural Gas Transportation Services segment are determined by capacity reservation fees from firm transportation contracts and thevolumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Ourtransportation arrangements are further described below:
• Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gasnominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipperpays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use chargewith respect to quantities actually transported by us.
• Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated totransport natural gas nominated by the shipper to the extent that we have available capacity. For this service, the shipper pays no reservationcharge but pays a variable-use charge for quantities actually shipped.
• Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systemsat an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at thesame undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportationarrangements.
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EXHIBIT 99.2
Offshore Pipelines and Services Segment
Results of operations from the Offshore Pipelines and Services segment are determined by capacity reservation fees from firm and interruptible transportationcontracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margincontracts. Our transportation arrangements are further described below:
• Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gasnominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipperpays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use chargewith respect to quantities actually transported by us.
• Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated totransport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservationcharge but pays a variable-use charge for quantities actually shipped.
• Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systemsat an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at thesame undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportationarrangements.
Terminalling Services Segment
Our Terminalling Services segment provides above-ground leasable storage services at our marine terminals that support various commercial customers, includingcommodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agriculturalproducts. We generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products areeither received or disbursed and other fee-based charges associated with ancillary services provided to our customers, such as excess throughput and truckweighing. Our firm storage contracts are typically multi-year contracts with renewal options.
Propane Marketing Services Segment
Results of operations for our Propane Marketing and Services Segment are determined by the gallons of NGLs we sell through our cylinder exchange and NGLsales businesses. In addition, our NGL transportation operations generate revenue based on the number of gallons of NGLs we gather and the distance we transportthose gallons for our customers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating ourprofitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, storageutilization, segment gross margin, gross margin, operating margin, direct operating expenses on a segment basis, and Adjusted EBITDA on a company-wide basis.
Throughput Volumes
In our Gas Gathering and Processing Services segment, we must continually obtain new supplies of natural gas, NGLs and condensate to maintain or increasethroughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas, NGLs and condensate is impacted by i) the level of work-overs or recompletions of existing connected wells and successful drilling activity of our significant producers in areas currently dedicated to or near our gatheringsystems, ii) our ability to compete for volumes from successful new wells in the areas in which we operate, iii) our ability to obtain natural gas, NGLs andcondensate that has been released from other commitments and iv) the volume of natural gas, NGLs and condensate that we purchase from connected systems. Weactively monitor producer activity in the areas served by our gathering and processing systems to maintain current throughput volumes and pursue new supplyopportunities.
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EXHIBIT 99.2
In our Liquid Pipelines and Services segment, t he amount of revenue we generate from our crude oil pipelines business depends primarily on throughput volumes.We generate a portion of our crude oil pipeline revenues through long-term contracts containing acreage dedications or minimum volume commitments.Throughput volumes on our pipeline system are affected primarily by the supply of crude oil in the market served by our assets. The revenue generated from ourcrude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, tradersand refiners as well as the volumes of crude oil that we gather and transport. The volume of our crude oil supply and logistics activities and the volumestransported by our crude oil gathering and transportation trucks are affected by the supply of crude oil in the markets served directly or indirectly by our assets.Accordingly, we actively monitor producer activity in the areas served by our crude oil supply and logistics business and other producing areas in the United Statesto compete for volumes from crude oil producers. Revenues in this business are also impacted by changes in the market price of commodities that we pass throughto our customers.
In our Natural Gas Transportation Services and Offshore Pipelines and Services segments, the majority of our segment gross margin is generated by firm capacityreservation charges and interruptible transportation services from throughput volumes on our interstate and intrastate pipelines. Substantially all of the segmentgross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gastransportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to maintain current throughputvolumes and pursue new shipper opportunities.
In our Terminalling Services segment, we generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to ourcustomers when their products are either received or disbursed, and other operational charges associated with ancillary services provided to our customers, such asexcess throughput, steam heating and truck weighing at our marine terminals. The amount of revenue we generate from our refined products terminals dependsprimarily on the volume of refined products that we handle. These volumes are affected primarily by the supple of and demand for refined products in the marketsserved directly or indirectly by our refined products terminals. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impacton the revenue generated by our crude oil storage business because we receive a fixed monthly fee per barrel of shell capacity that is not contingent on the usage ofour storage tanks.
In our Propane Marketing Services segment the amount of revenue we generate depends on the gallons of NGLs we sell through our cylinder exchange and NGLsales businesses. In addition, our NGL transportation operations generate revenue based on the number of gallons of NGLs we gather and the distance we transportthose gallons for our customers. Revenues in this segment are also impacted by changes in the market price of commodities that we pass through to our customers.
Storage Utilization
Storage utilization is a metric that we use to evaluate the performance of our Terminalling Services segment. We define storage utilization as the percentage of thecontracted capacity in barrels compared to the design capacity of the tank.
Segment Gross Margin and Gross Margin
We define segment gross margin in our Gas Gathering and Processing Services segment as total revenue plus unconsolidated affiliate earnings less unrealizedgains (losses) on commodity derivatives, construction and operating management agreement income and cost of sales.
We define segment gross margin in our Liquid Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains (losses)on commodity derivatives and the cost of sales in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based orfixed-margin, with little to no direct commodity price risk.
We define segment gross margin in our Natural Gas Transportation Services segment as total revenue plus unconsolidated affiliate earnings less the cost of sales inconnection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodityprice risk.
We define segment gross margin in our Offshore Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less the cost of sales inconnection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodityprice risk.
We define segment gross margin in our Terminalling Services segment as total revenue less the cost of sales utilized in our blending and injection of additives lessdirect operating expense.
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EXHIBIT 99.2
We define segment gross margin in our Propane Marketing Services segment as total revenue less cost of sales less unrealized gains (losses) on commodityderivatives.
Gross margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define gross margin as the sum of the segment grossmargins. The GAAP measure most directly comparable to gross margin is Net income (loss) attributable to the Partnership. For a reconciliation of gross margin toNet income (loss) attributable to the Partnership, please see “- Note About Non-GAAP Financial Measures” below.
Operating Margin
Operating margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define operating margin as total gross margin lessdirect operating expenses. The GAAP measure most directly comparable to operating margin is net income (loss) attributable to the Partnership. For areconciliation of Operating Margin to net income (loss), please see “- Note About Non-GAAP Financial Measures” below.
Direct Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or theenvironment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs,utilities, lost and unaccounted for gas, and contract services comprise most of our operating expenses. These expenses are relatively stable and largely independentof throughput volumes through our systems but may fluctuate depending on the activities performed during a specific period.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure used by our management and external users of our financial statements, such as investors,commercial banks, research analysts and others, to assess: the financial performance of our assets without regard to financing methods, capital structure orhistorical cost basis; the ability of our assets to generate cash flow to make cash distributions to our unitholders and our General Partner; our operating performanceand return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and theattractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus interest expense, income tax expense, depreciation, amortization andaccretion, debt issuance costs paid during the period, distributions from investments in unconsolidated affiliates, transaction expenses primarily associated with ourJPE Merger and Delta House investments, certain non-cash charges such as non-cash equity compensation expense, unrealized (gains) losses on derivatives andselected charges that are unusual, less construction and operating management agreement income, post-retirement benefit plan expense, earnings in unconsolidatedaffiliates, gains (losses) on the sale of assets, net, and selected other gains (losses) that are unusual. The GAAP measure most directly comparable to ourperformance measure Adjusted EBITDA is net income (loss) attributable to the Partnership. For a reconciliation of Adjusted EBITDA to net loss attributable to thePartnership, please see “- Note About Non-GAAP Financial Measures” below.
Note about Non-GAAP Financial Measures
Gross margin, operating margin and Adjusted EBITDA are non-GAAP financial measures. Each has important limitations as an analytical tool because theyexclude some, but not all, items that affect the most directly comparable GAAP financial measure. Management compensates for the limitations of these non-GAAP measure as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these datapoints into management’s decision-making process.
You should not consider gross margin, operating margin, or Adjusted EBITDA in isolation or as a substitute for, or more meaningful than analysis of, our results asreported under GAAP. Gross margin, operating margin and Adjusted EBITDA may be defined differently by other companies in our industry. Our definitions ofthese non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
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EXHIBIT 99.2
The following tables reconcile the non-GAAP financial measures of gross margin, operating margin and Adjusted EBITDA used by management to Net income(loss) attributable to the Partnership, their most directly comparable GAAP measure, for the years ended December 31, 2016 , 2015 and 2014 , respectively:
Years Ended December 31,
2016 (1) 2015 (1) 2014 (1)
(In thousands) Reconciliation of Segment Gross Margin to Net loss attributable to the Partnership Gas Gathering and Processing Services $ 48,245 $ 65,692 $ 51,213Liquid Pipelines and Services 29,760 24,160 22,564Natural Gas Transportation Services 18,616 18,073 13,691Offshore Pipelines and Services 82,346 33,613 29,089Terminalling Services 42,872 36,079 34,493Propane Marketing Services 88,948 91,437 80,083Total Segment Gross Margin 310,787 269,054 231,133Less:
Direct operating expenses (2) 112,590 117,066 98,018Operating margin 198,197 151,988 133,115Add:
Gains (losses) on commodity derivatives, net (455) (1,732) (12,671)Deduct:
Corporate expenses 99,430 77,835 72,744Depreciation, amortization and accretion 106,818 98,596 72,527Loss on sale of assets, net 2,870 3,920 5,080Loss on impairment of property, plant and equipment 697 — 21,344Loss on impairment of goodwill 15,456 148,488 —Loss on extinguishment of debt — — 1,634Interest expense 21,469 20,120 16,558Other (income) expense (628) (1,732) 662Other, net (3) (2,943) (14,049) (1,281)Income tax expense 2,578 1,888 857Loss from discontinued operations, net of tax 539 15,031 9,886Net income (loss) attributable to noncontrolling interest 2,766 (13) 3,993
Net loss attributable to the Partnership $ (51,310) $ (199,828) $ (83,560)_______________________
(1) During these years, we had the following transactions that affect comparability: i) in October 2016 and April 2016 we acquired 6.2% and 1% non-operatedinterests in Delta House Class A Units which we account for as equity method investments and are included in our Offshore Pipelines and Services segment;ii) in April 2016, we acquired membership interests in Destin ( 49.7% ), Tri-States ( 16.7% ), Okeanos ( 66.7% ), and Wilprise ( 25.3% ), which we accountfor as equity method investments and are included in our Liquid Pipelines and Services and Offshore Pipelines and Services segments; iii) in April 2016 weacquired a 60% interest in American Panther which we consolidate for financial reporting purposes and is included in our Offshore Pipelines and Servicessegment; iv) in September 2015, we acquired a non-operated 12.9% indirect interest in Delta House, which we account for as an equity method investment andis included in our Offshore Pipelines and Services segment; and v) in October 2014 and January 2014, we acquired the Costar and Lavaca systems,respectively, both of which are included in our Gas Gathering and Processing Services segment.
(2) Direct operating expenses includes Gas Gathering and Processing Services segment direct operating expenses of $33.8 million, $35.3 million, and $21.2million, respectively, Liquid Pipelines and Services segment direct operating expenses of $8.4 million, $8.3 million, and $5.8 million, respectively, NaturalGas Transportation Services segment direct operating expenses of $5.9 million, $6.7 million, and $7.0 million, respectively, Offshore Pipelines and Servicessegment direct operating expenses of
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EXHIBIT 99.2
$10.9 million, $9.4 million, and $11.1 million, respectively, and Propane Marketing Services segment direct operating expenses of $53.5 million, $57.4million, and $52.9 million for the year ended December 31, 2016, 2015 and 2014, respectively. Direct operating expenses exclude amounts related to theTerminalling segment as those costs are included in segment gross margin for Terminalling.
(3) Other, net includes realized gain (loss) on commodity derivatives of $1.5 million , $13.2 million and $0.3 million and COMA income of $1.5 million, $0.8million and $0.9 million, respectively, for each of the years ended December 31, 2016 , 2015 , and 2014 , respectively.
Years Ended December 31,
2016 2015 2014Reconciliation of Net loss attributable to the Partnership to Adjusted EBITDA:
Net loss attributable to the Partnership $ (51,310) $ (199,828) $ (83,560)Add:
Depreciation, amortization and accretion 106,818 98,596 72,527Interest expense 18,233 17,729 13,440Debt issuance costs paid 5,328 2,244 7,034Unrealized (gain) loss on derivatives, net (11,400) (11,269) 12,050Non-cash equity compensation expense 5,658 5,172 3,415Corporate office relocation 9,096 — —Transaction expenses (1) 14,084 3,303 5,560Income tax expense 2,578 1,888 857Loss on impairment of property, plant and equipment 697 — 21,344Loss on impairment of noncurrent assets held for sale — — 673Loss on impairment of goodwill 15,456 148,488 —Loss on extinguishment of debt — — 1,634Distributions from unconsolidated affiliates 83,046 20,568 1,980General Partner contribution for cost reimbursement 7,500 3,000 —
Deduct: Earnings in unconsolidated affiliates 40,158 8,201 348Construction and operating management agreement income 1,465 841 943Other post-employment benefits plan net periodic benefit 17 14 45Loss on sale of assets, net (2,870) (3,920) (5,080)
Adjusted EBITDA $ 167,014 $ 84,755 $ 60,698 _______________________
(1) Transaction expenses for the year ended December 31, 2016 included JPE Merger costs of $7.2 million. The JPE Merger closed on March 8, 2017.
General Trends and Outlook
During 2017, our business objectives will continue to focus on maintaining stable cash flows from our existing assets and executing on growth opportunities toincrease our long-term cash flows. We believe the key elements to stable cash flows are the diversity of our asset portfolio and our fee-based business whichrepresents a significant portion of our expected gross margins.
We anticipate maintenance capital expenditures between $12.0 million and $16.0 million , and approved expenditures for expansion capital between $65.0 millionand $85.0 million , for the year ending December 31, 2017. Forecasted growth capital expenditures include East Texas Processing consolidation, expansion of theHarvey terminal, continued build-out of the Bakken system, continued development of the Silver Dollar System, growth at Pinnacle Propane and other organicgrowth projects.
We expect to continue to pursue a multi-faceted growth strategy, which includes maximizing drop down opportunities provided by our relationship with ArcLight,capitalizing on organic expansion and pursuing strategic third-party acquisitions in order to grow our cash flows. We expect commodity prices in 2017 to continuewithin the same range as 2016 and as a result we expect
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EXHIBIT 99.2
producer and supplier activities to be impacted, which may increase the growth rate of our Gas Gathering and Processing Services and Natural Gas TransportationServices segments.
We expect our business to continue to be affected by the key trends discussed below. Our expectations are based on assumptions made by us and informationcurrently available to us. To the extent our underlying assumptions prove to be incorrect, our actual results may vary materially from our expected results.
Gas Gathering and Processing Services Segment. Except for our fee-based contracts, which may be impacted by throughput volumes, the profitability of our GasGathering and Processing Services segment is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate.
Liquid Pipelines and Services Segment. Profitability of our Liquid Pipelines and Services segment is dependent upon the price of crude oil. Throughput volumescould decline should crude oil prices remain low resulting in decreased production in our areas of operation.
Natural Gas Transportation Services and Offshore Pipelines and Services Segments. Profitability of our Natural Gas Transportation Services and OffshorePipelines and Services segments are dependent upon the demand to transport natural gas pursuant under our firm and interruptible transportation contracts.Throughput volumes could decline should natural gas prices and drilling levels decline.
Terminalling Services Segment. Profitability of our Terminalling Services segment is dependent upon the demand from our customers to store their products,which is generally not tied to the crude oil and natural gas commodity markets. Currently, we have not experienced deterioration of terminal gross margin inconnection with the volatility of the natural gas, crude oil, NGL or condensate markets. Further, the terms of our firm storage contracts are multiple years, withrenewal options.
Propane Marketing Services Segment. Profitability of our Propane Marketing Services segment is dependent upon the seasonal nature of propane demand. Ourretail propane business experiences increased demand during the months of November through March primarily for the purpose of providing heating in residentialand commercial buildings. Accordingly, the volume of propane used by our customers for this purpose is affected by the severity of winter weather in the regionswe serve, which was 7% warmer for the year ended December 31, 2016. If these regions were to experience a cooling trend, we could expect demand for propaneto increase.
Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $54.45 per barrel to a low of $26.21 per barrel from January 1, 2016through July 7, 2017. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu fromJanuary 1, 2016 through July 7, 2017. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannotpredict the ultimate impact of prices on our operations. If commodity prices decline, this could lead to reduced profitability and may impact our liquidity,compliance with financial covenants in our revolving credit agreement, and our ability to maintain our current distribution levels. Our long-term view is that aseconomic conditions improve, commodity prices should reach levels that will support continued natural gas and crude oil production in the United States. Reducedprofitability may result in future potential non-cash impairments of long-lived assets, goodwill, or intangible assets.
On January 26, 2017 the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit or $1.65 per common unit onan annualized basis. The distribution was paid on February 13, 2017, to unitholders of record as of the close of business on February 6, 2017. On April 25, 2017,the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit for the quarter ended March 31, 2017, or $1.65 percommon unit on an annualized basis. The distribution was paid on May 12, 2017, to unitholders of record as of the close of business on May 5, 2017. The amountof our cash distributions on our units principally depends upon the amount of cash we generate from our operations, which could be adversely impacted by marketconditions and factors outside of our control. The Partnership Agreement allows us to reduce or eliminate quarterly distributions, if required to maintain ongoingoperations.
Capital Markets. Volatility in the capital markets may impact our operations in multiple ways, including limiting our producers' ability to finance their drilling andworkover programs and limiting our ability to fund drop downs, organic growth projects and acquisitions.
Impact of Inflation on Direct Operating Expenses. Inflation has been relatively low in the United States in recent years. However, the inflation rates impactingour operations fluctuate throughout the broad economic and energy business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, laborand major equipment purchases may increase during periods of general business inflation or periods of relatively high-energy commodity prices.
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EXHIBIT 99.2
Results of Operations
Net loss attributable to the Partnership decreased by $148.5 million for the year ended December 31, 2016 as compared to 2015 primarily due to the loss onimpairment of goodwill of $148.5 million recognized in 2015 and an increase in earnings from unconsolidated affiliates of $32.0 million from our investments inDelta House and the entities underlying the Emerald Transactions, offset by an increase in corporate expense of $21.6 million due to corporate relocation and JPEMerger expenses.
Gross margin increased by $41.7 million , or 15.5% , for the year ended to December 31, 2016 to $310.8 million as compared to the same period in 2015 . Theincrease in gross margin was primarily due to an increase in our Offshore Pipelines and Services segment gross margin of $48.7 million as a result of increasedrevenues received by the Partnership due to the Pascagoula plant shutdown. The Pascagoula plant is not controlled or owned by the Partnership, and the shutdownrequired volumes to be directed to our High Point system. This was offset by a decrease in our Propane Marketing and Services segment gross margin of $2.5million due to a decrease in propane revenues in 2016 driven by a reduction in NGL and refined product sales volumes as well as a decline in prices. The reductionin volumes was due to a decline associated with oilfield services resulting from lower exploration and production activity and overall warmer than normaltemperatures sustained in the year ended December 31, 2016. The reduction in prices was due to less favorable market conditions and lower realized prices.
For the year ended December 31, 2016 , Adjusted EBITDA increased by $82.3 million, or 97.1% compared to 2015 . The increase is primarily related to higherdistributions from our unconsolidated affiliates of $62.5 million largely due to our investments in Delta House and the entities underlying the EmeraldTransactions.
We distributed $112.1 million and $100.4 million to holders of our common units during the year ended December 31, 2016 and 2015 , respectively.
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EXHIBIT 99.2
The following table and discussion presents certain of our historical consolidated financial data for the periods indicated.
The results of operations by segment are discussed in further detail following this combined overview (in thousands):
For the Years Ended
December 31,
2016 2015 2014
Statements of Operations Data: Revenues:
Commodity sales $ 568,527 $ 772,857 $ 909,765Services 158,850 142,762 123,698Gains (losses) on commodity derivatives, net (455) (1,732) (12,671)
Total revenue 726,922 913,887 1,020,792Operating expenses:
Cost of sales 443,023 630,303 789,872Direct operating expenses 123,372 127,480 109,543Corporate expenses 99,430 77,835 72,744Depreciation, amortization and accretion 106,818 98,596 72,527Loss on sale of assets, net 2,870 3,920 5,080Loss on impairment of property, plant and equipment 697 — 21,344Loss on impairment of goodwill 15,456 148,488 —
Total operating expenses 791,666 1,086,622 1,071,110Operating loss (64,744) (172,735) (50,318)Other income (expenses):
Interest expense (21,469) (20,120) (16,558)Loss on extinguishment of debt — — (1,634)Other expense 628 1,732 (662)Earnings in unconsolidated affiliates 40,158 8,201 348Income (loss) from continuing operations before income taxes (45,427) (182,922) (68,824)
Income tax expense (2,578) (1,888) (857)Income (loss) from continuing operations (48,005) (184,810) (69,681)
Loss from discontinued operations, net of tax (539) (15,031) (9,886)Net income (loss) (48,544) (199,841) (79,567)
Net income (loss) attributable to noncontrolling interests 2,766 (13) 3,993
Net income (loss) attributable to the Partnership $ (51,310) $ (199,828) $ (83,560)
Other Financial Data (1): Gross margin $ 310,787 $ 269,054 $ 231,133Adjusted EBITDA $ 167,014 $ 84,755 $ 60,698
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(1) For definitions of gross margin and Adjusted EBITDA and reconciliations to their most directly comparable financial measure calculated and presented inaccordance with GAAP, and a discussion of how we use gross margin and Adjusted EBITDA to evaluate our operating performance, please read the informationin this Item under the caption “How We Evaluate Our Operations.”
Year ended December 31, 2016 , compared to year ended December 31, 2015
Commodity Sales . Commodity sales revenue for the year ended December 31, 2016 were $568.5 million compared to $772.9 million for the year ended December31, 2015 . This decrease of $204.4 million was primarily due to the following:
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EXHIBIT 99.2
• a decrease in crude oil sales revenue of $152.9 million due to a decrease in sales volumes of 15,830 (bbls/day) from an overall reduction in our customercrude oil production volumes in our areas of operation;
• a decrease in NGL sales revenue of $30.6 million was primarily due to decline in volumes, representing $22.5 million of the decrease, as well as declinein prices which represents approximately $8.1 million of the decrease in NGL sales revenue. The reduction in volumes was due to a decline in volumesassociated with oilfield services as a result of lower exploration and production activity and overall warmer than normal temperatures. The reduction inprices is due to less favorable market conditions and increased competition;
• a decrease in natural gas revenue of $10.7 million primarily due to lower realized natural gas prices of $2.51 /Mcf, which is a decrease of $0.40 /Mcf or13.7% period over period;
• a decrease in condensate revenues of $6.7 million due to lower realized condensate prices of $0.11 /gal or 11.3% period over period;• a decrease in NGL revenues of $6.3 million due to lower gross NGL production volumes of 38.2 Mgal/d from our Gas Gathering and Processing Services
segment and lower realized NGL prices of $0.57 /gal, which is a decrease of $0.01 /gal period over period; and• these decreases were partially offset by an increase in crude oil gathering fee-based revenues of $4.7 million.
Service Revenue . Our service revenue for the year ended December 31, 2016 was $158.9 million compared to $142.8 million for the year ended December 31,2015 . This increase of $16.1 million was primarily due to the following:
• an increase in firm and interruptible transportation of $8.5 million primarily as a result of the Pascagoula plant shutdown and additional revenueassociated with our Gulf of Mexico Pipeline which we acquired in April 2016. The Pascagoula plant is not controlled or owned by the Partnership, andthe shutdown required volumes to be redirected to our High Point system; and
• an increase in Terminalling Services segment revenue of $9.8 million as a result of incremental storage utilization and ancillary increases.
Cost of sales . Cost of sales for the year ended December 31, 2016 , were $443.0 million compared to $630.3 million in the year ended December 31, 2015 . Thisdecrease of $187.3 million was due to lower NGL and natural gas purchases of $26.1 million and $10.4 million, respectively. There was also a decrease in crudeoil purchases of $162.8 million which was driven by the 2016 reduction in crude sales volumes and overall reduction in crude prices. The NGL purchases decreasewas primarily due to the reduction in NGL sales volumes. NGL sales volumes decreased 30,000/gallons per day in 2016 compared to 2015 due to a decline involumes associated with oilfield services as a result of lower exploration and production activity and overall warmer than normal temperatures.
Gross Margin . Gross margin for the year ended December 31, 2016 , was $310.8 million compared to $269.1 million for the year ended December 31, 2015 . Thisincrease of $41.7 million was primarily due to our increased Offshore Pipelines and Services segment gross margin of $8.5 million as a result of increasedrevenues received by the Partnership due to the Pascagoula plant shutdown. The Pascagoula plant is not controlled or owned by the Partnership, and the shutdownrequired volumes to be directed to our High Point system. Additionally, the incremental earnings from our equity method investees increased by $32.0 million, ofwhich $29.9 million was attributable to our Offshore Pipelines and Services segment.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 , were $123.4 million compared to $127.5 million for the year endedDecember 31, 2015 . This decrease of $4.1 million was primarily due to a decrease of contract services and labor costs.
Corporate Expenses . Corporate expenses for the year ended December 31, 2016 , were $99.4 million compared to $77.8 million for the year ended December 31,2015 . This increase of $21.6 million was primarily due to corporate relocation expenses of $9.1 million, JPE Merger expenses of $7.2 million, and increases insalaries, wages and benefits of $2.6 million due to increased employee expenses as we transitioned our corporate headquarters from Denver to Houston,information and technology maintenance costs of $1.1 million primarily related to systems and licenses that were implemented in the prior year, contract servicesof $1.0 million, and legal and regulatory compliance fees of $0.7 million in support of corporate activities.
Depreciation, Amortization and Accretion . Depreciation, amortization and accretion for the year ended December 31, 2016 , was $106.8 million compared to$98.6 million for the year ended December 31, 2015 . This increase of $8.2 million was primarily due to incremental depreciation of fixed assets related to ourGulf of Mexico Pipeline acquisition in April 2016, our Mesquite joint venture which began operations in April 2016, and our Bakken system which beganoperations in October 2015.
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EXHIBIT 99.2
Loss on Impairment of Goodwill. Goodwill impairment expense for the year ended December 31, 2015 was $148.5 million compared to $15.5 million for the yearended December 31, 2016. The 2015 impairment charges were comprised of $95.0 million and $23.6 million related to the Costar and Lavaca acquisitions,respectively, $23.6 million in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business, and a $6.3 millionimpairment charge in our Propane Marketing Services reportable segment related to JP Liquids. In 2016, we recognized goodwill impairment charges totaling$15.5 million in our Propane Marketing Services reportable segment, which consisted of $12.8 million and $2.7 million related to our Pinnacle Propane Expressand JP Liquids businesses, respectively. Given the market condition trend surrounding Pinnacle Propane Express and JP Liquids, we may recognize furtherimpairments related to those assets in the future.
Interest Expense . Interest expense for the year ended December 31, 2016 , was $21.5 million compared to $20.1 million for the year ended December 31, 2015 .This increase of $1.4 million was primarily due to higher outstanding borrowings under our revolving credit agreements, and an increase in our weighted averageinterest rate, offset by $10.4 million of unrealized gains on our interest rate swaps.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the year ended December 31, 2016 were $40.2 million compared to $8.2 millionfor the year ended December 31, 2015 . This increase of $32.0 million was primarily due to incremental earnings of $22.8 million related to our investment inDelta House and $9.7 million related to the interests in the entities underlying the Emerald Transactions which were acquired in April 2016.
Year ended December 31, 2015 , compared to year ended December 31, 2014
Commodity Sales . Commodity sales for the year ended December 31, 2015 was $772.9 million compared to $909.8 million for the year ended December 31, 2014. This decrease of $136.9 million was primarily due to the following:
• a decrease of $47.0 million due to converting fixed-margin contracts in our Natural Gas Transportation Services segment to firm or interruptibletransportation contracts;
• a decrease of $46.7 due to the following:◦ lower realized natural gas prices of $2.91 /Mcf, which is a decrease of $2.01 /Mcf, or 40.9%, period over period,◦ lower realized NGL prices of $0.58 gal, which is a decrease of $0.33 /gal., or 36.3%, period over period, offset by higher gross NGL production
volumes of 166.9 Mgal/d, or 260%, period over period, and◦ lower realized condensate prices of $0.97 /gal, which is a decrease of $0.65 /gal, or 40.1%, period over period, offset by higher gross condensate
production volumes of 24.6 Mgal/d, or 32.7% , period over period;• a decrease in propane revenue of approximately $30.0 million primarily due to a 56% reduction in propane prices from a 2014 MB average of $1.04/gal to
a 2015 average of $0.46/gal. The significant price decline is slightly offset by increase in NGL sales volumes (11,000 gal/day) due to organic growth inour customer base and the acquisition of Southern Propane in May 2015; and
• a $12.9 million decrease due to a 48% reduction in crude prices from a 2014 WTI average of $93.26/bbl to a 2015 average of $0.46/gal.
Services Revenue . Our service revenue for the year ended December 31, 2015 was $142.8 million compared to $123.7 million for the year ended December 31,2014 . This increase of $19.1 million was primarily due an increase in the Terminalling Services segment revenue of $2.3 million as a result of increased storageutilization from acquiring new customers and contractual storage rate escalations.
Cost of Sales . Cost of sales for the year ended December 31, 2015 were $630.3 million compared to $789.9 million in the year ended December 31, 2014 . Thisdecrease of $159.6 million was due to lower natural gas purchases of $94.3 million primarily as a result of lower natural gas prices and lower natural gas volumesrelated to our elective processing arrangements in our Gas Gathering and Processing segment, as well as the conversion of certain fixed-margin contracts tointerruptible transportation contracts in our Natural Gas Transportation Services segment as mentioned above. NGL purchases decreased by $66.0 millionprimarily driven by 56% reduction in propane prices from a 2014 average of $1.04/gal compared to a 2015 average of $0.46/gal. Crude purchases decreased by$14.0 million due to a 48% reduction in crude prices from a 2014 WTI average of $93.26/bbl to a 2015 average of $0.46/gal. The price decline is slightly offset byincreases in crude sales (24,643 bbls/day) and throughput volumes (7,378 bbls/day) due to expansions on our Silver Dollar Pipeline.
This decrease was partially offset by incremental NGL, crude oil and condensate purchases of $2.2 million primarily associated with the gathering and processingsystems acquired in the Costar Acquisition.
Gross Margin . Gross margin for the year ended December 31, 2015 was $269.1 million compared to $231.1 million for the year ended December 31, 2014 . Thisincrease of $37.9 million was primarily due to an increase in our Gas Gathering and Processing
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EXHIBIT 99.2
Services segment gross margin of $14.5 million as a result of higher NGL and condensate production of 166.9 Mgal/d and 24.6 Mgal/d, respectively, and higherthroughput volumes of 63.4 MMcf/d. There was an additional increase in our Propane Marketing Services segment gross margin of $11.4 million as a result of a$55.2 million decrease in the cost of sales; offset by a decrease in segment revenue of $19.4 million.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $127.5 million compared to $109.5 million in the year endedDecember 31, 2014 . This increase of $18.0 million was primarily due to $13.4 million of incremental operating costs, including costs related to direct labor andbenefits, associated with the gathering and processing systems acquired from Costar in October 2014, and an increase of $2.1 million in operating costs associatedwith compression rentals used at our Lavaca System.
Corporate Expenses . Corporate expenses for the year ended December 31, 2015 were $77.8 million compared to $72.7 million for the year ended December 31,2014 . This increase of $5.1 million was primarily due to personnel costs incurred to manage and integrate our recent acquisitions and support continuing growth.
Depreciation, Amortization and Accretion . Depreciation, amortization and accretion for the year ended December 31, 2015 was $98.6 million compared to $72.5million for the year ended December 31, 2014 . This increase of $26.1 million was primarily due to incremental depreciation of fixed assets and amortization ofcertain intangible assets associated with the Costar Acquisition and the continuing capital expansion of the Lavaca System.
Loss on Impairment of Property, Plant and Equipment. During the fourth quarter of 2014, management noted the declining commodity markets and relatedimpact on producers and shippers to whom we provide gathering and processing services. The decline in the market price of crude oil has led to a correspondingdecrease in crude oil and natural gas production and is impacting the volume of natural and NGLs we gather and process on certain assets. As a result, assetimpairment charges of $21.3 million related to certain gathering and processing assets were recorded during the fourth quarter of 2014.
Loss on Impairment of Goodwill. During the fourth quarter of 2015, management performed the Partnership's annual goodwill impairment test. As a result of thecontinuing decline in commodity prices, as well as the decline in the market price for the Partnership's common units during the fourth quarter, key assumptionsrelating to expected producer volumes and commodity prices used in management's impairment testing cash flow models were updated. The updated assumptionsresulted in the estimated fair value of the Costar and Lavaca reporting units being less than their respective carrying values, indicating that the related goodwill wasimpaired. After completing an allocation of the estimated fair value of each reporting unit to the associated assets and liabilities, management determined that thegoodwill of the Costar and Lavaca reporting units had a nominal fair value and that impairment charges of $118.6 million were required. We also recorded agoodwill impairment charge of $29.9 million during the year ended December 31, 2015 related to the JP Energy Crude Oil Supply and Logistics and JP Liquidsreporting units. Additionally, in connection with the sale of the Mid-Continent Business, we recorded a goodwill impairment charge of $7.9 million during the yearended December 31, 2015 which is classified in net loss from discontinuing operations in the consolidated statements of operations.
Interest Expense . Interest expense for the year ended December 31, 2015 , was $20.1 million compared to $16.6 million for the year ended December 31, 2014 .This increase of $3.5 million was primarily due to higher outstanding borrowings under our revolving credit agreements primarily to fund our capital growthprojects and the Costar acquisition and Delta House investment.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the year ended December 31, 2015 were $8.2 million compared to $0.3 million forthe year ended December 31, 2015 . This increase of $7.9 million was due to incremental earnings of $7.5 million related to Delta House, and higher earnings fromMPOG of $0.4 million .
Results of Operations — Segment Results
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EXHIBIT 99.2
Gas Gathering and Processing Services Segment
The table below contains key segment performance indicators related to our Gas Gathering and Processing Services segment (in thousands except operating andpricing data).
For the Years Ended
December 31,
2016 2015 2014
Segment Financial and Operating Data: Gas Gathering and Processing Services Segment
Financial data: Commodity Sales $ 91,444 $ 107,680 $ 148,198Services 22,558 30,196 15,248Revenue from operations 114,002 137,876 163,446Gain (loss) on commodity derivatives, net (833) 1,240 1,050Segment revenue $ 113,169 $ 139,116 $ 164,496Cost of sales 63,832 72,960 112,719Direct operating expenses 33,802 35,250 21,197
Other financial data: Segment gross margin $ 48,245 $ 65,692 $ 51,213
Operating data: Average throughput (MMcf/d) 220.6 240.0 155.8Average plant inlet volume (MMcf/d) (1) 102.1 120.9 89.1Average gross NGL production (Mgal/d) (1) 192.9 231.1 64.2Average gross condensate production (Mgal/d) (1) 82.9 97.1 70.8
Average realized prices: Natural gas ($/Mcf) $ 2.06 $ 2.68 $ 4.57NGLs ($/gal) $ 0.57 $ 0.58 $ 0.91Condensate ($/gal) $ 0.87 $ 0.98 $ 1.60
(1) Excludes volumes and gross production under our elective processing arrangements.
Year Ended December 31, 2016 , Compared to Year Ended December 31, 2015
Commodity Sales . Commodity sales for the year ended December 31, 2016 were $91.4 million compared to $107.7 million for the year ended December 31, 2015. This decrease of $16.3 million was primarily due to the following:
• lower realized natural gas, NGL, and condensate prices of 23.2%, 1.9%, and 10.9%, respectively; and• lower average NGL and condensate production of 38.2 Mgal/d and 14.1 Mgal/d, respectively, primarily due to a decrease in volumes at our Longview
system.
Services Revenue. Services revenue for the year ended December 31, 2016 were $22.6 million compared to $30.2 million for the year ended December 31, 2015 .This decrease of $7.6 million was primarily due to lower average throughput and plant inlet volumes of 19.4 MMcf/d and 18.8 MMcf/d, respectively.
Cost of Sales . Cost of sales for the year ended December 31, 2016 were $63.8 million compared to $73.0 million for the year ended December 31, 2015 . Thisdecrease of $9.2 million was primarily due to lower realized commodity prices as well as lower NGL and condensate purchased volumes at our Longview system.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2016 was $48.2 million compared to $65.7 million for the year ended December31, 2015 . This decrease of $17.5 million was primarily due to lower production on our Longview and Lavaca systems.
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EXHIBIT 99.2
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 were $33.8 million compared to $35.3 million for the year endedDecember 31, 2015 . This decrease of $1.5 million was primarily due to lower compressor rentals due to ongoing cost cutting efforts.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014
Commodity Sales . Commodity sales for the year ended December 31, 2015 were $107.7 million compared to $148.2 million for the year ended December 31,2014 . This decrease of $40.5 million was primarily due to the following:
• lower realized natural gas, NGL, and condensate prices of 41.4%, 36.6%, and 39%, respectively; and• these decreases were partially offset by an increase in NGL and condensate production of 166.9 Mgal/d and 26.2 Mgal/d, respectively.
Services Revenue. Services revenue for the year ended December 31, 2015 were $30.2 million compared to $15.2 million for the year ended December 31, 2014 .This increase of $15.0 million was primarily due to higher throughput volumes of 84.2 MMcf/d related to the Costar and Lavaca acquisitions which occurred in2014.
Cost of Sales . Cost of sales for the year ended December 31, 2015 were $73.0 million compared to $112.7 million for the year ended December 31, 2014 . Thisdecrease of $39.7 million was primarily due to lower purchase costs associated with natural gas and NGLs due to lower realized natural gas and NGL prices andlower natural gas volumes associated with our elective processing arrangements. These decreases were partially offset by incremental purchases associated withoff-spec NGL and condensate throughput volumes related to the Longview system.
Segment Gross Margin. Segment gross margin for the year ended December 31, 2015 was $65.7 million compared to $51.2 million for the year endedDecember 31, 2014 . This increase of $14.5 million was primarily due to incremental gross margin of $24.0 million on our Longview, Chapel Hill, Danville, andYellow Rose systems and higher gross margin of $4.8 million at our Lavaca system. These increases were partially offset by lower NGL and condensateproduction associated with our elective processing arrangements.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $35.3 million compared to $21.2 million for the year endedDecember 31, 2014 . This increase of $14.1 million was primarily due to incremental operating costs associated with the gathering and processing systemsacquired in the Costar and Lavaca acquisitions, partially offset by the timing of activities related to our integrity management and plant repair and maintenanceprograms.
Liquid Pipelines and Services Segment
The table below contains key segment performance indicators related to our Liquid Pipelines and Services segment (in thousands except operating data).
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EXHIBIT 99.2
For the Years Ended
December 31,
2016 2015 2014
Segment Financial and Operating Data: Liquid Pipelines & Services
Financial data: Commodity sales $ 304,501 $ 457,390 $ 470,336Services 12,146 12,895 11,548Revenue from operations 316,647 470,285 481,884Gains (losses) on commodity derivatives (net) (341) — —Earnings in unconsolidated affiliates 2,070 — —Segment revenue $ 318,376 $ 470,285 $ 481,884Cost of sales 288,496 446,125 459,319
Direct operating expense 8,383 8,310 5,819 Other financial data: Segment gross margin $ 29,760 $ 24,160 $ 22,564
Operating data: Average throughput Pipeline (Bbls/d) 32,257 34,946 20,868 Average throughput Trucking (Bbls/d) 1,628 — —
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 .
Commodity Sales . Commodity sales for the year ended December 31, 2016 were $304.5 million compared to $457.4 million for the year ended December 31,2015 . This decrease of $152.9 million was primarily due to a decrease in crude oil sales volumes to 24,425 barrels per day for the year ended December 31, 2016from 40,255 barrels per day for the year ended December 31, 2015. These decreases are primarily due to an overall reduction in our customer crude oil productionvolumes in our areas of operation.
Services Revenue. Services revenue for the year ended December 31, 2016 were $12.1 million compared to $12.9 million for the year ended December 31, 2015 .This decrease of $0.8 million was primarily due to a decrease in crude oil throughput volumes to 32,257 barrels per day for the year ended December 31, 2016from 34,946 barrels per day for the year ended December 31, 2015. These decreases are due to an overall reduction in our customer crude oil production volumesin our area of operation. However, producer activity around our Silver Dollar Pipeline has recently increased, resulting in average pipeline throughput volumes ofapproximately 31,000 barrels per day in the quarter ended December 31, 2016.
Cost of Sales . Cost of sales for the year ended December 31, 2016 were $288.5 million compared to $446.1 million for the year ended December 31, 2015 . Thisdecrease of $157.6 million was primarily due to a decrease in crude oil sales volumes resulting from an overall reduction in our customer crude oil productionvolumes, as described above.
Earnings in Unconsolidated Affiliates. Earning in unconsolidated affiliates for the year ended December 31, 2016 increased $2.1 million. This change was drivenby the Emerald transaction that occurred on April 2016 adding interests in the Wilprise and Tri-States entities that own and operate pipeline systems.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2016 was $29.8 million compared to $24.2 million for the year ended December31, 2015 . This increase of $5.6 million was primarily due to an increase in crude oil sales margin of $10.0 million due to the capturing of more favorable marginsassociated with previously stored inventory during contango market conditions as well as more favorable regional pricing spreads on bulk purchased crude oil.This increase is partially offset by a decrease in crude oil sales and throughput volumes of $6.9 million and $0.7 million, respectively.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 were $8.4 million compared to $8.3 million for the year endedDecember 31, 2015 . This increase of $0.1 million was primarily due to the incremental expenses associated with our Bakken system, partially offset by reductionsin personnel costs from lower headcount.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014 .
19
EXHIBIT 99.2
Commodity Sales . Commodity sales for the year ended December 31, 2015 were $457.4 million compared to $470.3 million for the year ended December 31,2014. This decrease of $12.9 million was primarily due to the impact of the current lower priced crude oil market per barrel and the lack of any market dislocationopportunities for the year ended December 31, 2015. This decrease is partially offset by a $4.7 million increase in crude oil sales volumes, as sales volumesincreased to 40,255 barrels per day for the year ended December 31, 2015 from 15,612 barrels per day for the year ended December 31, 2014 due to the expansionsof the Silver Dollar Pipeline System in the third quarter of 2014 throughout 2015.
Services Revenue. Services revenue for the year ended December 31, 2015 were $12.9 million compared to $11.5 million for the year ended December 31, 2014.This increase of $1.4 million was primarily due to the incremental revenue from our Bakken system which commenced operations in 2015.
Cost of Sales . Cost of sales for the year ended December 31, 2015 were $446.1 million compared to $459.3 million for the year ended December 31, 2014. Thisdecrease of $13.2 million was primarily due to the impact of the current lower priced crude oil market per barrel, as described above.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2015 was $24.2 million compared to $22.6 million for the year ended December31, 2014. This increase of $1.6 million was primarily due to an increase in production from the Bakken system which commenced operations in 2015.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $8.3 million compared to $5.8 million for the year endedDecember 31, 2014. This increase of $2.5 million was primarily due to increases in insurance premiums of $0.8 million, property tax expenses of $0.2 million, andrepairs and maintenance expenses of $0.2 million in 2015.
Natural Gas Transportation Services Segment
The table below contains key segment performance indicators related to our Natural Gas Transportation Services segment (in thousands except operating andpricing data).
For the Years Ended
December 31,
2016 2015 2014
Segment Financial and Operating Data: Natural Gas Transportation Services
Financial data: Commodity Sales $ 21,999 $ 23,972 $ 70,964Services 18,109 16,035 12,925Segment revenue $ 40,108 $ 40,007 $ 83,889Cost of sales 21,288 21,858 70,100Direct operating expenses 5,923 6,728 6,975
Other financial data: Segment gross margin $ 18,616 $ 18,073 $ 13,691
Operating data: Average throughput (MMcf/d) 389.9 364.1 373.3Average firm transportation - capacity reservation (MMcf/d) 634.7 637.2 567.9Average interruptible transportation - throughput (MMcf/d) 65.3 70.2 65.3Average realized prices: Natural gas ($/Mcf) $2.57 $2.86 $4.60
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 .
Commodity Sales . Commodity sales for the year ended December 31, 2016 were $22.0 million compared to $24.0 million for the year ended December 31, 2015 .This decrease of $2.0 million was primarily due to lower realized natural gas prices of 10.1%.
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EXHIBIT 99.2
Services Revenue. Services revenue for the year ended December 31, 2016 were $18.1 million compared to $16.0 million for the year ended December 31, 2015 .This increase of $2.1 million was primarily due to higher average throughput volumes of 26 MMcf/d from new firm transportation contracts associated with ourMLGT pipeline.
Cost of Sales . Cost of sales for the year ended December 31, 2016 were $21.3 million compared to $21.9 million for the year ended December 31, 2015 . Thisdecrease of $0.6 million was primarily due to a decline in realized natural gas prices, as described above.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2016 was $18.6 million compared to $18.1 million for the year ended December31, 2015 . This increase of $0.5 million was primarily due to higher average throughput volumes offset by lower realized natural gas prices.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 were $5.9 million compared to $6.7 million for the year endedDecember 31, 2015 . This decrease of $0.8 million was primarily due to lower employee costs.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014 .
Commodity Sales . Commodity sales for the year ended December 31, 2015 were $24.0 million compared to $71.0 million for the year ended December 31, 2014.This decrease of $47.0 million was primarily due to converting certain fixed-margin arrangements to interruptible and firm transportation agreements during thefirst quarter of 2015, which substantially reduced the sales of natural gas throughput volumes and also the need for us to purchase such volumes.
Services Revenue. Services revenue for the year ended December 31, 2015 were $16.0 million compared to $12.9 million for the year ended December 31, 2014.This increase of $3.1 million was primarily due to an increase in firm transportation capacity commitments of 69 MMcf/d.
Cost of Sales . Cost of sales for the year ended December 31, 2015 were $21.9 million compared to $70.1 million for the year ended December 31, 2014. Thisdecrease of $48.2 million was primarily due to converting certain fixed-margin arrangements to interruptible and firm transportation agreements during the firstquarter of 2015, and therefore substantially reducing our need to purchase natural gas.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2015 was $18.1 million compared to $13.7 million for the year ended December31, 2014. This increase of $4.4 million was primarily due to an increase in firm transportation capacity and the incremental increase resulting from convertingfixed-margin arrangements to interruptible and firm transportation agreements, as described above.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $6.7 million compared to $7.0 million for the year endedDecember 31, 2014. This decrease of $0.3 million was primarily due to an ongoing cost cutting effort to reduce operating expenses.
Offshore Pipelines and Services Segment
The table below contains key segment performance indicators related to our Offshore Pipelines and Services segment (in thousands except operating data).
21
EXHIBIT 99.2
For the Years Ended
December 31,
2016 2015 2014
Segment Financial and Operating Data: Offshore Pipelines & Services
Financial data: Commodity sales $ 6,812 $ 13,798 $ 20,044Services 40,502 21,457 24,426Revenue from operations 47,314 35,255 44,470Gains (losses) on commodity derivatives, net (7) 84 41Earnings in unconsolidated affiliates 38,088 8,201 348Segment revenue $ 85,395 $ 43,540 $ 44,859Cost of sales 3,049 9,914 15,133
Direct operating expense 10,945 9,425 11,142Other financial data:
Segment gross margin $ 82,346 $ 33,613 $ 29,089 Operating data: Average throughput (MMcf/d) 466.4 442.8 524.6 Gross condensate production (Mgal/d) 3.6 2.7 4.4 Average firm transportation - capacity reservation (MMcf/d) 53.4 16.6 10.0 Average interruptible transportation - throughput (MMcf/d) 288.7 340.1 403.7 Average realized prices: Natural gas ($/Mcf) $ 2.63 $ 2.97 $ 5.09 NGLs ($/gal) $ — $ 0.42 $ 0.88 Condensate ($/gal) $ 0.72 $ 0.92 $ 1.89
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 .
Commodity Sales . Commodity sales for the year ended December 31, 2016 were $6.8 million compared to $13.8 million for the year ended December 31, 2015 .This decrease of $7.0 million was primarily due to a reduction in the average realized prices for natural gas and condensate of 11.4% and 22.1%, respectively.
Services Revenue. Services revenue for the year ended December 31, 2016 were $40.5 million compared to $21.5 million for the year ended December 31, 2015 .This increase of $19.0 million was primarily due to the Pascagoula plant shutdown which required volumes to be redirected to our High Point system, andincreased fees associated with our acquisition of the Gulf of Mexico Pipeline. The Pascagoula plant is not controlled or owned by the Partnership.
Cost of Sales . Cost of sales for the year ended December 31, 2016 were $3.0 million compared to $9.9 million for the year ended December 31, 2015 . Thisdecrease of $6.9 million was primarily due to lower realized commodity prices, as described above.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the year ended December 31, 2016 were $38.1 million compared to $8.2 millionfor the year ended December 31, 2015. This increase of $29.9 was primarily due to the incremental investments in the Delta House entities in 2016, as well as theEmerald transaction that occurred in April 2016.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2016 was $82.3 million compared to $33.6 million for the year ended December31, 2015 . This increase of $48.7 million was primarily due to increased revenues for our Highpoint system of $7.1 million as a result of the shutdown of thePascagoula plant, increased fees associated with our acquisition of the Gulf of Mexico Pipeline of $12.5 million, incremental earnings of $22.8 million related toour investment in Delta House and $8.4 million associated with the offshore interests acquired in the Emerald transaction, partially offset by decrease incommodity realized prices.
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EXHIBIT 99.2
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 were $10.9 million compared to $9.4 million for the year endedDecember 31, 2015 . This increase of $1.5 million was primarily due to the incremental expenses associated with our acquisition of the Gulf of Mexico Pipeline,partially offset by lower employee costs.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014 .
Commodity Sales . Commodity sales for the year ended December 31, 2015 were $13.8 million compared to $20.0 million for the year ended December 31, 2014.This decrease of $6.2 million was primarily due to a reduction in the average realized prices for natural gas, NGLs, and condensate of 41.7%, 52.0%, and 51.3%,respectively.
Services Revenue. Service revenues for the year ended December 31, 2015 were $21.5 million compared to $24.4 million for the year ended December 31, 2014.This decrease of $2.9 million was primarily due to a decrease in average throughput and interruptible transportation throughput of 82 MMcf/d and 64 MMcf/d,respectively.
Cost of Sales . Cost of sales for the year ended December 31, 2015 were $9.9 million compared to $15.1 million for the year ended December 31, 2014. Thisdecrease of $5.2 million was primarily due to lower realized commodity prices, as described above.
Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the year ended December 31, 2015 were $8.2 million compared to $0.3 million forthe year ended December 31, 2014. This increase of $7.9 was primarily due to the Delta House investment that occurred in September 2015.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2015 was $33.6 million compared to $29.1 million for the year ended December31, 2014. This increase of $4.5 million was primarily due to incremental earnings of $7.5 million associated with our investment in Delta House and higherearnings of $0.4 million from our investment in MPOG, partially offset by a decrease in average throughput volumes described above.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $9.4 million compared to $11.1 million for the year endedDecember 31, 2014. This decrease of $1.7 million was primarily due to an ongoing effort to reduce operating expenses.
Terminalling Services Segment
The table below contains key segment performance indicators related to our Terminalling Services segment (in thousands except operating data).
For the Years Ended
December 31,
2016 2015 2014
Segment Financial and Operating Data: Terminalling Services
Financial data: Commodity sales $ 14,655 $ 10,343 $ 11,521Services 50,999 45,022 41,357
Revenue from operations 65,654 55,365 52,878Gains (losses) on commodity derivatives, net (436) 21 —Segment revenue $ 65,218 $ 55,386 $ 52,878Cost of sales 11,564 8,893 6,859Direct operating expense 10,783 10,414 11,525
Other financial data: Segment gross margin $ 42,872 $ 36,079 $ 34,493
Operating data: Contracted Capacity (Bbls) 5,011,133 4,487,542 4,247,058Design Capacity (Bbls) (2) 5,173,717 4,688,950 4,363,817Storage Utilization (1) 96.9% 95.7% 97.3%Terminalling and storage throughput (Bbls/d) 56,741 62,075 63,859
23
EXHIBIT 99.2
(1) Excludes storage utilization associated with our discontinued operations.(2) Excludes 1.2M Bbls at our North Little Rock and Caddo Mills locations.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 .
Commodity Sales . Commodity sales for the year ended December 31, 2016 were $14.7 million compared to $10.3 million for the year ended December 31, 2015.The increase of $4.4 million was attributable to an increase in refined products sales related to the addition of butane blending capabilities at our North Little RockTerminal in the second quarter of 2015.
Services Revenue. Services revenue for the year ended December 31, 2016 , were $51.0 million compared to $45.0 million for the year ended December 31, 2015 .The increase of $6.0 million was primarily attributable to increases in contracted storage capacity due to the expansion efforts at our Harvey terminal of $5.1million and $0.7 million from increased refined product storage due to additional blending and injection of additives.
Cost of Sales. Cost of sales for the year ended December 31, 2016 were $11.6 million compared to $8.9 million for the year ended December 31, 2015. Theincrease of $2.7 million was primarily due to an increase in butane blending sales volume.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2016 was $42.9 million compared to $36.1 million for the year ended December31, 2015 . The increase of $6.8 million was primarily attributable to an increase in storage revenue and to a lesser extent margins from refined product sales.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 were $10.8 million compared to $10.4 million for the year endedDecember 31, 2015 . The increase of $0.4 million was related to liability classified unit-based compensation.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014 .
Commodity Sales . Commodity sales for the year ended December 31, 2015 were $10.3 million compared to $11.5 million for the year ended December 31, 2014.The decrease of $1.2 million was attributable to a decrease in commodity prices of $4.1 million, partially offset by an increase in refined product sales volume of$3.0 million due to the addition of butane blending capabilities at our North Little Rock Terminal in the second quarter of 2015.
Services Revenue. Services revenue for the year ended December 31, 2015 were $45.0 million compared to $41.4 million for the year ended December 31, 2014 .The increase of $3.6 million was primarily attributable to increases in contracted storage capacity due to the expansion efforts at the Harvey terminal.
Cost of Sales. Cost of sales for the year ended December 31, 2015 were $8.9 million compared to $6.9 million for the year ended December 31, 2014. The increaseof $2.0 million was primarily due to an increase in refined products sales volume.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2015 was $36.1 million compared to $34.5 million for the year endedDecember 31, 2014 . The increase of $1.6 million was primarily attributable to an increase in storage revenue while managing direct labor costs associated withproviding ancillary services.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $10.4 million compared to $11.5 million for the year endedDecember 31, 2014 . The decrease of $1.1 million is primarily attributable to managing direct labor associated with providing ancillary services.
Propane Marketing and Services Segment
The table below contains key segment performance indicators related to our Propane Marketing and Services segment (in thousands except operating data).
24
EXHIBIT 99.2
For the Years Ended
December 31,
2016 2015 2014
Segment Financial and Operating Data: Propane Marketing and Services
Financial data: Commodity sales $ 129,116 $ 159,674 $ 188,702Services 14,536 17,157 18,194Revenue from operations 143,652 176,831 206,896Gains (losses) on commodity derivatives, net 1,162 (3,077) (13,762)Segment revenue $ 144,814 $ 173,754 $ 193,134Cost of sales 54,794 70,553 125,742Direct operating expense 53,536 57,353 52,885
Other financial data: Segment gross margin $ 88,948 $ 91,437 $ 80,083 Operating data: NGL and refined product sales (Mgal/d) 181 211 200
Year Ended December 31, 2016, Compared to Year Ended December 31, 2015 .
Commodity Sales. Commodity sales for the year ended December 31, 2016 were $129.1 million compared to $159.7 million for the year ended December 31,2015. This decrease of $30.6 million was due to a reduction in NGL revenue from lower NGL sales volumes driven by a decline in volumes associated withoilfield services and overall warmer than normal temperatures sustained in the year ended December 31, 2016.
Services Revenue. Services revenue for the year ended December 31, 2016 were $14.5 million compared to $17.2 million for the year ended December 31, 2015.This decrease of $2.7 million was due to a reduction in NGL revenue from lower NGL trucking volumes driven by a decline in volumes associated with oilfieldservices and overall warmer than normal temperatures sustained in the year ended December 31, 2016.
Cost of Sales. Cost of sales for the year ended December 31, 2016 were $54.8 million compared to $70.6 million for the year ended December 31, 2015. Thisdecrease of $15.8 million was due to lower NGL sales volumes driven by a decline in volumes associated with oilfield services, as described above.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2016 was $88.9 million compared to $91.4 million for the year ended December31, 2015. The decrease of $2.5 million was primarily attributable to a reduction in NGL and refined product sales.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2016 were $53.5 million compared to $57.4 million for the year endedDecember 31, 2015 . The decrease of $3.8 million was related to a reduction in distribution and employee costs of $1.5 million and $1.2 million, respectively. Thedecrease in distribution costs was driven by lower volumes and improved fleet efficiencies while the decline in employee costs was related to a reduction inheadcount. Facility maintenance expenses also declined $0.7 million for the year ended December 31, 2016 due to overall cost reduction initiatives.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014 .
Commodity Sales. Commodity sales for the year ended December 31, 2015 were $159.7 million compared to $188.7 million for the year ended December 31,2015. The decrease of $29.0 million was driven by a reduction in NGL and refined product sales volumes. The reduction was due to a decline in volumesassociated with oilfield services resulting from lower exploration and production activity.
Services Revenue. Services revenue for the year ended December 31, 2015 were $17.2 million compared to $18.2 million for the year ended December 31, 2014.This decrease of $1.0 million was due to a reduction in NGL revenue from lower NGL trucking volumes driven by a decline in volumes associated with oilfieldservices resulting from lower exploration and production activities.
25
EXHIBIT 99.2
Cost of Sales. Cost of sales for the year ended December 31, 2015 were $70.6 million compared to $125.7 million for the year ended December 31, 2014. Thisdecrease of $55.1 million was due to lower NGL sales volumes driven by a decline in volumes associated with oilfield services, as described above.
Segment Gross Margin . Segment gross margin for the year ended December 31, 2015 was $91.4 million compared to $80.1 million for the year ended December31, 2014. The increase of $11.4 million was primarily due to the more favorable position of our propane hedges during the year ended December 31, 2015.
Direct Operating Expenses . Direct operating expenses for the year ended December 31, 2015 were $57.4 million compared to $52.9 million for the year endedDecember 31, 2014. The increase of $4.5 million was primarily due to increases in employee costs of $4.0 million, distribution expenses of $0.6 million andinsurance premiums of $0.5 million.
Liquidity and Capital Resources
Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems andfacilities.
Our principal sources of liquidity include cash from operating activities, borrowings under our revolving credit agreements, issuance of equity in the capitalmarkets or through private transactions, and financial support from ArcLight, who controls our General Partner. In addition, we may continue to seek to raisecapital through the issuance of secured and unsecured senior notes. Given our historical success in accessing various sources of liquidity, we believe that thesources of liquidity described above will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditurerequirements, and quarterly cash distributions for at least the next twelve months. In the event these sources are not sufficient, we would pursue other sources ofcash funding, including, but not limited to, additional forms of debt or equity financing. In addition, we would reduce non-essential capital expenditures,controllable direct operating expenses and corporate expenses, as necessary. Our Partnership Agreement also allows us to reduce or eliminate quarterlydistributions, if required to maintain ongoing operations.
Our liquidity for the year ended December 31, 2016 was impacted by the following:
• The issuance in April 2016 of 8,571,429 Series C Units along with warrants to purchase up to 800,000 common units at an exercise price of $7.25 percommon unit with a combined issuance date fair value of approximately $120.0 million , proceeds of which were used to partially fund the purchase ourmembership interests in the entities underlying the Emerald Transactions.
• The issuance in October of 2,333,333 Series D Units with a value of $34.5 million , the proceeds of which were used to partially fund the purchase ofadditional Delta House Class A Units. We also agreed to grant the Series D unitholders a warrant to purchase up to 700,000 common units at an exerciseprice of $22.00 per common unit if the Series D Units are still outstanding at June 30, 2017.
• Revolving credit agreements borrowings of $425.1 million and repayments of $224.0 million .
• Issuance of the 3.77% Senior Notes resulting in net proceeds of approximately $57.7 million .
• Issuance of 8.50% Senior Notes resulting in net proceeds of approximately $291.3 million .
Changes in natural gas, crude oil, NGL and condensate prices and the terms of our customer contracts have a direct impact on our generation and use of cash fromoperations due to their impact on net income (loss), along with the resulting changes in working capital. During 2016, we mitigated a portion of our anticipatedcommodity price risk associated with the volumes from our gathering and processing activities with fixed price commodity swaps. For additional informationregarding our derivative activities, please read Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" included in the 2016 Form 10-K.
The counterparties to our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to providecollateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us andeach counterparty, as applicable, in the master contract that governs our financial transactions based on our respective assessments of creditworthiness. Theassessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis, and is impacted by the representativeforward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative natural gas and crude oil forward pricecurves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiplecommodities with the same counterparty. Depending on daily commodity prices,
26
EXHIBIT 99.2
the amount of collateral posted can go up or down on a daily basis. As of December 31, 2016 , we are not required to post collateral with our counterparties.
At-The-Market (“ATM”) Offering
On October 18, 2015, we filed a prospectus supplement related to the offer and sale from time to time of up to $100.0 million of our common units through an at-the-market offering program. For the year ended December 31, 2016 , we sold 248,561 common units resulting in net proceeds of $2.9 million, after deductingoffering costs of $0.3 million . The net proceeds were used to repay amounts outstanding under the Partnership Credit Agreement. As of December 31, 2016 ,approximately $96.8 million remained available for sale under the program.
AMID Credit Agreement
Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement, which provided for maximumborrowings up to $750.0 million , with the ability to further increase the borrowing capacity to $900.0 million subject to lender approval.
On September 30, 2016 and in connection with entering into the 3.77% Note Purchase Agreement, the Partnership entered into the Limited Waiver and ThirdAmendment to the Amended and Restated Credit Agreement, which among other things, (i) allowed Midla Holdings, for so long as the 3.77% Senior Notes areoutstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain covenants thereunder, (ii) released the liengranted under the Credit Agreement related to D-Day’s equity interests in Delta FPS, LLC and (iii) deemed the equity interests in Delta House FPS, LLC to beexcluded property under the Amended and Restated Credit Agreement.
On November 18, 2016, the Partnership entered into the Fourth Amendment to the Amended and Restated Credit Agreement. The Fourth Amendment (i) modifiedcertain investment covenants to reflect the recently completed incremental acquisition of additional interests in Delta House (ii) permitted JPE’s existing creditagreement (the “JPE Credit Agreement”) to remain in place during the time period between (a) the consummation of the JPE Merger and (b) the payoff of the JPECredit Agreement, (iii) permitted the joining of JPE and its subsidiaries as guarantors under the Amended and Restated Credit Agreement, and (iv) permitted theintegration of JPE and its subsidiaries into the Partnership’s ownership structure.
Effective with the closing of the JPE Merger on March 8, 2017, the Partnership entered into the Second Amended and Restated Credit Agreement, which increasedour borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to the customary conditions, theborrowing capacity under the facility to be increased to a maximum of $1.1 billion.
Our obligations under the Second Amended and Restated Credit Agreement are secured by a lien on substantially all of our assets. Advances made under theSecond Amended and Restated Credit Agreement are guaranteed on a senior unsecured basis by certain of our subsidiaries (the “Guarantors”). These guaranteesare full and unconditional and joint and several among the Guarantors. The terms of the Second Amended and Restated Credit Agreement include covenants thatrestrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interestwill be due and payable in full at maturity on September 5, 2019.
The Second Amended and Restated Credit Agreement contains certain financial covenants, including (i) a consolidated total leverage ratio that requires ourconsolidated total indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (as defined in the Second Amended and Restated Credit Agreement) forthe prior twelve month period, adjusted in accordance with the Second Amended and Restated Credit Agreement (except for the current and up to the subsequenttwo quarters after the consummation of a permitted acquisition, at which time the covenant may be increased to 5.50 times adjusted consolidated EBITDA), (ii) aminimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by at least 2.50 times for the prior twelvemonth period, and (iii) a consolidated secured leverage ratio that requires our consolidated secured indebtedness not to exceed 3.50 times adjusted consolidatedEBITDA for the prior twelve month period. The financial covenants in the Second Amended and Restated Credit Agreement may limit the amount available to usfor borrowing to less than $900.0 million. We can elect to have loans under the Second Amended and Restated Credit Agreement bear interest either at aEurodollar-based rate plus a margin ranging from 2.00% to 3.25% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate perannum equal to the highest of (i) the Federal Funds Rate, plus 0.50%, (ii) the rate of interest in effect for such day as publicly announced from time to time byBank of America as its “prime rate”, or (iii) the Eurodollar Rate plus 1.00%, plus a margin ranging from 1.00% to 2.25% depending on the total leverage ratio thenin effect. We also pay a commitment fee ranging between 0.375% to 0.50% per annum, depending on our total leverage ratio then in effect, on the undrawn portionof the revolving loan.
27
EXHIBIT 99.2
The Second Amended and Restated Credit Agreement also contains customary representations and warranties (including those relating to organization andauthorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetarydefaults, covenant defaults, cross defaults and bankruptcy events).
At December 31, 2016 and 2015 , letters of credit outstanding under the Credit Agreement were $7.4 million and $1.8 million , respectively.
As of December 31, 2016 , our consolidated total leverage ratio was 4.07 and our interest coverage ratio was 7.43 , which were both in compliance with the relatedrequirements of our Credit Agreement. At December 31, 2016 , we had approximately $711.3 million of borrowings and $7.4 million in letters of creditoutstanding under the $750.0 million Amended and Restated Credit Agreement leaving $31.3 million of available borrowing capacity.
As of December 31, 2016, we were in compliance with the covenants included in the Credit Agreement. Our ability to maintain compliance with the leverage andinterest coverage ratios included in the Second Amended and Restated Credit Agreement may be subject to, among other things, the timing and success ofinitiatives we are pursuing, which may include expansion capital projects, acquisitions, or drop down transactions, as well as the associated financing for suchinitiatives.
JPE Credit Agreement
On February 12, 2014, JPE entered into the JPE Credit Agreement with Bank of America, N.A, which was available for refinancing and repayment of certainexisting indebtedness, working capital, capital expenditures, permitted acquisitions and other general partnership purposes. The JPE Credit Agreement consisted ofa $275.0 million revolving loan, which included a sub-limit of up to $100.0 million for letters of credit. The JPE Credit Agreement was scheduled to mature onFebruary 12, 2019, but was paid off and terminated on March 8, 2017 in connection with the Partnership's acquisition of JPE.
Borrowings under the JPE Credit Agreement bore interest at a rate per annum equal to, at out option, either (a) a base rate determined by reference to the highest of(1) the federal funds effective rate plus 0.5%, (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, ineach case plus an applicable rate. The applicable rate was (a) 1.25% for prime rate borrowing and 2.25% for LIBOR borrowings. The commitment fee was subjectto an adjustment each quarter based in the Consolidated Net Total Leverage Ratio, as defined in the related agreement.
8.50% Senior Notes
On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly owned subsidiary (together with the Partnership, the “Issuers”)completed the issuance and sale of the 8.50% Senior Notes. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds,after deducting initial purchasers' discount of $6.0 million . This amount was deposited into escrow pending completion of the JPE Merger and is included inRestrictedcashon our consolidated balance sheet as of December 31, 2016. The Partnership also incurred $2.7 million of direct issuance costs resulting in netproceeds related to the 8.50% Senior Notes of $291.3 million.
Under the terms of the escrow agreement governing the disbursement of the net proceeds, upon the closing of the JPE Merger and the satisfaction of the otherconditions contained therein, the restricted cash was released from escrow and was used to repay and terminate JPE Credit Facility and reduce borrowings underthe Partnership’s Credit Agreement.
The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in cash semi-annually in arrears on June 15 and December 15, commencing June15, 2017.
At any time prior to December 15, 2018, the Issuers may on one or more occasions redeem up to 35% of the aggregate principal amount of 8.50% Senior Notes, ata redemption price of 108.50% of the principal amount, plus accrued and unpaid interest to the redemption date, in an amount not greater than the net cashproceeds of one or more equity offerings by the Partnership, provided that:
• at least 65% of the aggregate principal amount of the 8.50% Senior Notes remains outstanding immediately after such redemption (excluding 8.50%Senior Notes held by the Partnership and its subsidiaries); and
• the redemption occurs within 180 days of the closing of each such equity offering.
28
EXHIBIT 99.2
Prior to December 15, 2018, the Issuers may redeem all or part of the 8.50% Senior Notes, at a redemption price equal to the sum of:
• the principal amount thereof, plus
• the make whole premium (as defined in the Indenture) at the redemption date, plus
• accrued and unpaid interest, to the redemption date
On and after December 15, 2018, the Issuers may redeem all or a part of the 8.50% Senior Notes, at the redemption prices (expressed as percentages of principalamount) set forth below, plus accrued and unpaid interest to the applicable redemption date, if redeemed during the twelve-month period beginning on December15 of the years indicated below:
Year Percentage2018 104.250%2019 102.125%2020 and thereafter 100.000%
The Indenture restricts the Partnership’s ability and the ability of certain of its subsidiaries to, among other things: (i) incur, assume or guarantee additionalindebtedness, issue any disqualified stock or issue preferred units, (ii) create liens to secure indebtedness, (iii) pay distributions on equity securities, redeem orrepurchase equity securities or redeem or repurchase subordinated securities, (iv) make investments, (v) restrict distributions, loans or other asset transfers fromrestricted subsidiaries, (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person, (vii) sell or otherwise dispose ofassets, including equity interests in subsidiaries, (viii) enter into transactions with affiliates, (ix) engage in certain business activities and (x) enter into sale andleaseback transactions. These covenants are subject to a number of important exceptions and qualifications. If at any time the 8.50% Senior Notes are ratedinvestment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default (as each are defined in theIndenture) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to suchcovenants.
3.77% Senior Notes
On September 30, 2016, Midla Financing, Midla, and MLGT entered into the 3.77% Senior Note Purchase Agreement with the Purchasers. Pursuant to the 3.77%Senior Note Purchase Agreement, Midla Financing sold $60.0 million in aggregate principal amount of 3.77% Senior Notes. Principal and interest on the 3.77%Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2017 with the remaining balance payable in full on June 30,2031. The average quarterly principal payment is approximately $1.1 million . The 3.77% Senior Notes were issued at par and provided net proceeds ofapproximately $57.7 million after deducting related issuance costs of $2.3 million.
Net proceeds from the 3.77% Senior Notes are restricted and will be used to fund project costs incurred in connection with the construction of the Midla-NatchezLine, the retirement of Midla’s existing 1920’s pipeline, the move of our Baton Rouge operations to the MLGT system and the reconfiguration of the DeSiardcompression system and all related ancillary facilities. These proceeds can also be used to pay costs incurred in connection with the issuance of the 3.77% SeniorNotes, and for general corporate purposes of Midla Financing.
The Note Purchase Agreement includes customary representations and warranties, affirmative and negative covenants (including financial covenants), and eventsof default that are customary for a transaction of his type. Midla Financing must maintain a debt service reserve account containing six months of principal andinterest payments, and Midla Financing and the Note Guarantors (including any entities that become guarantors under the terms of the 3.77% Senior Note PurchaseAgreement) are restricted from making distributions until June 30, 2017, unless the debt service coverage ratio is not less than, and is not projected to be for thefollowing 12 calendar months less than, 1.20:1.00, and unless certain other requirements are met.
In connection with the 3.77% Senior Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations. Also,Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible assets, including the membership interestsin each Note Guarantor held by Midla Financing, and Financing Holdings pledged the membership interests in Midla Financing to the Collateral Agent.
Working Capital
29
EXHIBIT 99.2
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Ourworking capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices ofcommodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of decliningcommodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable andaccounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can alsocause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. Weexpect that our future working capital requirements will be impacted by these same factors. Our working capital deficit was $16.4 million at December 31, 2016compared to a surplus of $6.6 million at December 31, 2015 with the $23.0 million increase in the deficit due primarily to capital expenditures in connection withthe Midla-Natchez Line and convertible preferred unit distributions which were included in Accruedexpensesandothercurrentliabilitiesat December 31, 2016.The Partnership plans to utilize the increase in the Second Amended and Restated Credit Agreement of $150.0 million to cover any working capital requirements.
Cash Flows
The following table reflects cash flows for the applicable periods (in thousands):
For the Years Ended
December 31,
2016 2015 2014Net cash provided by (used in):
Operating activities $ 90,639 $ 86,978 $ 51,635Investing activities (564,504) (250,769) (518,023)Financing activities 477,544 161,954 466,577
Year Ended December 31, 2016 , Compared to Year Ended December 31, 2015
Operating Activities . Net cash provided by operating activities was $90.6 million for the year ended December 31, 2016 , compared to $87.0 million for the yearended December 31, 2015 . Net cash provided by operating activities for the year ended December 31, 2016 , compared to December 31, 2015 increased by $3.6million mainly driven by a reduction in net loss of $18.3 million , excluding the $148.5 million goodwill impairment charge recorded in 2015, offset by a decreasein the change in operating assets and liabilities of $10.1 million.
Investing Activities . Net cash used in investing activities was $564.5 million for the year ended December 31, 2016 , compared to $250.8 million for the yearended December 31, 2015 . Cash used in investing activities for the year ended December 31, 2016 increased by $313.7 million period over period primarily due tothe change in restricted cash of $325.6 million as a result of the issuance of our 8.50% Senior Notes and our 3.77% Senior Notes and an increase in investments inunconsolidated affiliates specifically for our interests in the Emerald Transactions and additional interests in Delta House Investment of $84.5 million .
These increases were partially offset by a $60.2 million decrease in capital expenditures and $30.5 million of higher cash distributions received from investmentsin unconsolidated affiliates as a return of capital.
Financing Activities . Net cash provided by financing activities was $477.5 million for the year ended December 31, 2016 , compared to net cash provided byfinancing activities of $162.0 million for the year ended December 31, 2015 . Cash provided by financing activities for the year ended December 31, 2016increased by $315.5 million period over period primarily due proceeds from the 8.50% Senior Notes of $294.0 million , proceeds from the 3.77% Senior Notes of$60.0 million , partially offset by lower borrowings primarily on our revolving credit agreements of $46.2 million.
Year Ended December 31, 2015 , Compared to Year Ended December 31, 2014
Operating Activities . Net cash provided by operating activities was $87.0 million for the year ended December 31, 2015 , compared to $51.6 million for the yearended December 31, 2014 . Net cash provided by operating activities for the year ended December 31, 2015 , increased by $35.3 million period over period mainlydriven by a decrease in net loss of $28.2 million, excluding the $148.5 million goodwill impairment charge recorded in 2015.
30
EXHIBIT 99.2
Investing Activities . Net cash used in investing activities was $250.8 million for the year ended December 31, 2015 , compared to $518.0 million for the yearended December 31, 2014 . Cash used in investing activities for the year ended December 31, 2015 decreased by $267.2 million period over period primarily dueto a decrease in cost of acquisitions of $357.1 million, return of restricted cash of $16.2 million , and higher cash disbursements received from unconsolidatedaffiliates in excess of cumulative earnings of $10.7 million . These increases were offset by higher capital expenditures of $54.2 million primarily related to theLavaca and Bakken Systems, and higher acquisitions of unconsolidated affiliates of $53.7 million related to equity method investments primarily related to theDelta House Investment.
Financing Activities . Net cash provided by financing activities was $162.0 million for the year ended December 31, 2015 , compared to $ 466.6 million for theyear ended December 31, 2014. Cash provided by financing activities for the year ended December 31, 2014 decreased by $304.6 million primarily due to lowerproceeds from the issuance of common units to the public of $384.4 million , offset by higher net borrowings on debt of $83.5 million .
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At December 31, 2016 , ourmaterial off-balance sheet arrangements and transactions included operating lease arrangements and service contracts. Please see " ContractualObligations" formore information. There are no other transactions, arrangements, or other relationships associated with our investments in unconsolidated affiliates or relatedparties that are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.
Capital Requirements
The energy business is capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of newsystems and facilities. We categorize our capital expenditures as either:
• maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, ourcapital assets) made to maintain our operating income or operating capacity; or
• expansion capital expenditures, incurred for acquisitions of capital assets or capital improvements that we expect will increase our operating income oroperating capacity over the long term.
Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in theregions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the year endedDecember 31, 2016 , capital expenditures totaled $147.8 million including expansion capital expenditures of $137.3 million, maintenance capital expenditures of$6.8 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party)of $3.7 million . Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do notnecessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our Partnership Agreement. Weanticipate maintenance capital expenditures related to the Partnership between $12.0 million and $16.0 million and expansion capital expenditures between $65.0million and $85.0 million for the year ending December 31, 2017 . Forecasted growth capital expenditures include East Texas Processing consolidation, expansionof the Harvey terminal, continued build-out of the Bakken system, continued development of the Silver Dollar System, growth at Pinnacle Propane and otherorganic growth projects.
We intend to make cash distributions to our unitholders, convertible preferred unitholders and our General Partner and expect that we will distribute most of thecash generated by our operations.
As a result, we expect to fund acquisitions and future capital expenditures with funds generated from our operations, borrowings under our revolving creditagreements, and additional debt and equity issuances. If these sources are not sufficient, we may pursue the divestiture of non-core assets or reduce discretionaryspending.
Integrity Management
Certain operating assets require an ongoing integrity management program under regulations of the U.S. Department of Transportation, or DOT. These regulationsrequire transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our total program addressesapproximately 106 high consequence areas that require on-going testing pursuant to DOT regulations. Over the course of the seven-year cycle, we expect to incurup to $7.2 million in integrity management testing expenses.
31
EXHIBIT 99.2
Distributions
We intend to pay a quarterly distribution for the foreseeable future although we do not have a legal obligation to make distributions except as provided in ourPartnership Agreement.
On January 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash a distribution of $0.4125 per American Midstreamcommon unit for the fourth quarter ended December 31, 2016, or $1.65 per common unit on an annualized basis. The cash distribution was paid on February 13,2017, to unitholders of record as of the close of business on February, 6 2017. A distribution of $0.3250 per JPE common unit and subordinated unit for the threemonths ended December 31, 2016 was declared on January 24, 2017 and paid on February 14, 2017 to unitholders of record as of February 7, 2017. On April 25,2017, the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit for the quarter ended March 31, 2017,or $1.65 per common unit on an annualized basis. The distribution was paid on May 12, 2017, to unitholders of record as of the close of business on May 5, 2017.On July 15, 2017, the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit for the quarter ended June 30,2017, or $1.65 per common unit on an annualized basis. The distribution was paid on August 14, 2017, to unitholders of record as of the close of business onAugust 7, 2017.
Contractual Obligations
The table below summarizes our contractual obligations and other commitments as of December 31, 2016 (in thousands):
Total Revolving Credit
Agreements 3.77% Senior
Notes 8.50% Senior
Notes Asset Retirement
Obligation (1) OtherLess Than 1 Year $ 18,045 $ — $ 1,677 $ — $ 6,499 $ 9,8691 - 3 Years 902,699 888,250 3,039 — — 11,4103 - 5 Years 311,887 — 6,729 300,000 — 5,158More Than 5 Years 110,909 — 48,555 — 44,363 17,991Total $ 1,343,540 $ 888,250 $ 60,000 $ 300,000 $ 50,862 $ 44,428(1) In some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of theasset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can bederived from past practice, industry practice, management's experience, or the asset's estimated economic life.
Impact of Seasonality
Results of operations in our Natural Gas Transportation Services segment are directly affected by seasonality due to higher demand for natural gas during thewinter months, primarily driven by our LDC customers. On our AlaTenn system, we offer some customers seasonally-adjusted firm transportation rates thatrequire customers to reserve capacity at rates that are higher in the period from October to March compared to other times of the year. On our Midla system, weoffer customers seasonally-adjusted firm transportation reservation volumes that allow customers to reserve more capacity during the period from October toMarch compared to other times of the year. The combination of seasonally-adjusted rates and reservation volumes, as well as higher volumes overall, result inhigher revenue and segment gross margin in our Natural Gas Transportation Services segment during the period from October to March compared to other times ofthe year. We generally do not experience seasonality in our Gas Gathering and Processing and Terminalling segments.
Weather conditions have a significant impact on the demand for our products, particularly propane and refined fuels for heating purposes. Many of our customersrely on propane primarily as a heating source. Accordingly, the volumes sold are directly affected by the severity of the winter weather in our service areas, whichcan vary substantially from year to year. In any given area, sustained warmer than normal temperatures, as was the case in the heating season over the last threeyears throughout our operating territories, will tend to result in reduced propane, fuel oil and natural gas consumption, while sustained colder than normaltemperatures will tend to result in greater consumption. Meanwhile, our cylinder exchange operations experience higher volumes in the spring and summer, whichincludes the majority of the grilling season. Sustained periods of poor weather, particularly in the grilling season, can negatively affect our cylinder exchangerevenues. In addition, poor weather may reduce consumers’ propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demandfor cylinder exchange.
32
EXHIBIT 99.2
The volume of propane used by customers of our NGL sales business is higher during the first and fourth calendar quarters and lower during the second and thirdcalendar quarters. Conversely, the volume of propane that we sell through our cylinder exchange business is higher during the second and third calendar quartersand lower in the first and fourth calendar quarters. We believe that the combination of our winter-weighted NGL sales business with our higher-margin, summer-weighted cylinder exchange business reduces overall seasonal fluctuations in volumes and financial results, as our cylinder exchange business is more active insummer months and our NGL sales business is more active in winter months. The impact of seasonality is also mitigated by non-heating related demandthroughout the year for propane for oilfield services, fuel for automobiles and for industrial applications, such as forklifts, mowers and generators. The volume of product that is handled, transported, throughput or stored in our refined products terminals is directly affected by the level of supply and demand inthe wholesale markets served by our terminals. Overall supply of refined products in the wholesale markets is influenced by the absolute prices of the products, theavailability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the market’s perception of future product prices. Although demand forgasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months, most of therevenues generated at our refined products terminals do not experience any effects from such seasonality. However, the butane blending operations at our refinedproducts terminals are affected by seasonality because of federal regulations governing seasonal gasoline vapor pressure specifications. Accordingly, we expectthat the revenues we generate from butane blending will be highest in the winter months and lowest in the summer months.
The butane blending operations at our refined products terminals are affected by seasonality because of federal regulations governing seasonal gasoline vaporpressure specifications. Accordingly, we expect that the revenues we generate from butane blending will be highest in the winter months and lowest in the summermonths.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts ofassets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expensesduring the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by our management to be critical toan understanding of the financial statements because their application requires the most significant judgments from management in estimating matters for financialreporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about ourcritical accounting policies and estimates.
Use of Estimates. When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based oninformation available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as thedisclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the timesuch estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previouslyavailable. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are usedin, among other things, i) estimating unbilled revenues, product purchases and operating and general and administrative costs, ii) developing fair valueassumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets, goodwill and intangible assets for possible impairment,iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, coulddiffer materially from estimated amounts.
Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the period itbenefits. Our property, plant and equipment is depreciated using the straight-line method over the estimated useful lives of the assets. The costs of renewals andbetterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects areexpensed as incurred.
Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. As circumstances warrant,depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives orsalvage values which would impact future depreciation expense.
Impairment of Long-Lived Assets . We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events orcircumstances indicate we may not recover the carrying amount of the assets. We continually monitor our operations, the market, and business environment toidentify indicators that could suggest an asset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating theundiscounted future cash flows expected to
33
EXHIBIT 99.2
be derived from their use and disposition. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing,demand, competition, operating cost, contract renewals, and other factors. An asset or asset group is considered impaired when the estimated undiscounted cashflows are less than the carrying amount. In that event, an impairment loss is recognized to the extent that the carrying amount of the asset or asset group exceeds itsfair value as determined by quoted market prices in active markets or present value techniques. The determination of fair values using present value techniquesrequires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections andassumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairmentloss in our consolidated statements of operations.
Impairment of Goodwill. We evaluate goodwill for impairment annually in the fourth quarter, and whenever events or changes in circumstances indicate it is morelikely than not that the fair value of a reporting unit is less than its carrying amount. We determine fair value using widely accepted valuation techniques, namelydiscounted cash flow and market multiple analyses. These techniques are also used when allocating the purchase price to acquired assets and liabilities. Thesetypes of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is ourpolicy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.
Investment in Unconsolidated Affiliates. We hold membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oilpipelines in and around Louisiana, Alabama, Mississippi and the Gulf of Mexico. While we have significant influence over these entities, we do not control themand therefore, they are accounted for using the equity method and are reported in Investmentinunconsolidatedaffiliates in the consolidated balance sheets. Weevaluate the recoverability of these investments on a regular basis and recognize impairment write downs if we determine a loss in value represents an other-than-temporary decline.Environmental Remediation . We recognize a liability and expense associated with environmental remediation if the existence of a liability is probable and theamount can be reasonably estimated. If governmental regulations change, we could be required to incur remediation costs that may have a material impact on ourprofitability.
Asset Retirement Obligations. Asset retirement obligations ("ARO") are legal obligations associated with the retirement of tangible long-lived assets that resultfrom the asset's acquisition, construction, development and operation. An ARO is initially measured at its estimated fair value. Upon initial recognition, we alsorecord an increase to the carrying amount of the related long-lived asset. We depreciate the asset using the straight-line method over the period during which it isexpected to provide benefits. After initial recognition, we revise the ARO to reflect the passage of time and for changes in the estimated amount or timing of cashflows.
We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annualcharges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for certain of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshorepipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information toreasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation. In these cases, the assetretirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice,management's experience, or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resourcesand ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonableestimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists toreasonably estimate potential settlement dates and methods.
Revenue Recognition. We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs or condensate) as well as from the provision ofgathering, processing, transportation or storage services when all of the following criteria are met: i) persuasive evidence of an exchange arrangement exists,ii) delivery has occurred or services have been rendered, iii) the price is fixed or determinable and iv) collectability is reasonably assured. We recognize revenuefrom the sale of commodities and the related cost of product sold on the gross basis for those transactions where we act as the principal and take title tocommodities that are purchased for resale. Revenue from firm storage contracts is recognized ratably, which is typically monthly, over the term of the lease.Revenue from throughput fees and ancillary fees are recognized as services are provided to the customer.
Price Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to helpmaintain compliance with certain financial covenants in our credit agreement. These hedging activities rely upon forecasts of our expected operations and financialstructure. If our operations or financial structure are significantly
34
EXHIBIT 99.2
different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure byretaining an operational cushion between our forecasted transactions and the level of hedging activity executed.
We used mark-to-market accounting for our commodity hedges and interest rate swaps. We record monthly realized gains and losses on hedge instruments basedupon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also recordunrealized gains and losses for the net change in the mark-to-market valuation of the hedges.
Recent Accounting Pronouncements.
For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, please refer to Note 1"Organization, Basis of Presentation and Summary of Significant Accounting Policies" in Part II, Item 8 of our 2016 10-K, which is incorporated herein byreference.
35
EXHIBIT 99.3
AMERICAN MIDSTREAM PARTNERS, LPINDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm F-1
Consolidated Balance Sheets as of December 31, 2016 and 2015 F-3
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 F-4
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2016, 2015 and2014
F-5
Consolidated Statements of Changes in Equity, Partners' Capital and Noncontrolling Interests for theYears Ended December 31, 2016, 2015 and 2014
F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 F-7
Notes to Consolidated Financial Statements F-9
1
Report of Independent Registered Public Accounting Firm
To the Partners of American Midstream Partners, LP
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes inequity, partners’ capital and noncontrolling interests, and of cash flows present fairly, in all material respects, the financial position of American MidstreamPartners, LP and its subsidiaries ("the Partnership") at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the threeyears in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, thePartnership did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established inInternal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a materialweakness in internal control over financial reporting existed as of that date related to the Partnership not maintaining a sufficient complement of resources with anappropriate level of accounting knowledge, expertise and training commensurate with its financial reporting requirements. A material weakness is a deficiency, ora combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual orinterim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management’s AnnualReport on Internal Control over Financial Reporting (not presented herein) appearing under Item 9A of the Partnership’s 2016 Annual Report on Form 10-K. Weconsidered this material weakness in determining the nature, timing and extent of audit tests applied in our audit of the 2016 consolidated financial statements, andour opinion regarding the effectiveness of the Partnership’s internal control over financial reporting does not affect our opinion on those consolidated financialstatements. The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting included in management’s report referred to above. Our responsibility is to expressopinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits. We conducted our audits in accordancewith the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtainreasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting wasmaintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statementpresentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing therisk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits alsoincluded performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for ouropinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactionsand dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance withthe policies or procedures may deteriorate.
As discussed in Note 2 to the consolidated financial statements, the Partnership acquired JP Energy Partners, LP (“JPE”) on March 8, 2017 in a transactionbetween entities under common control as both the Partnership and JPE are controlled by affiliates of ArcLight Capital Partners, LLC (“ArcLight”). Although thePartnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLight obtained control of JPE before it obtained control of thePartnership. The accompanying financial statements represent JPE’s historical cost basis financial statements, retrospectively adjusted to reflect the acquisition ofthe Partnership at ArcLight’s historical cost basis on April 15, 2013. The controls of JPE were not part of the Partnership’s internal control over financial reportingas of December 31, 2016. Accordingly, the controls operated at JPE were not included in either management’s assessment of internal control over financialreporting or in our audit of the Partnership’s internal control over financial reporting as of December 31, 2016. JPE is a wholly-owned subsidiary of the Partnershipwhose total assets and total revenue represent 28.7% and 68.0%, respectively, of the related consolidated financial statement amounts as of and for the year endedDecember 31, 2016.
F-1
/s/ PricewaterhouseCoopers LLPHouston, TexasMarch 24, 2017, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the acquisition of JP EnergyPartners, LP discussed in Note 2 to the consolidated financial statements and to the third paragraph of Note 24, as to which the date is September 15, 2017.
F-2
American Midstream Partners, LP, and SubsidiariesConsolidated Balance Sheets
(In thousands, except unit amounts)
December 31, 2016 2015
AssetsCurrent assets
Cash and cash equivalents $ 5,666 $ 1,987Accounts receivable, net of allowance for doubtful accounts of $1,871 and $1,217 as ofDecember 31, 2016 and December 31, 2015, respectively 27,769 23,831Unbilled revenue 55,646 55,428Inventory 6,776 5,241Other current assets 27,667 25,526
Total current assets 123,524 112,013Risk management assets - long term 10,664 —Property, plant and equipment, net 1,145,003 1,071,514Restricted cash - long term 323,564 5,037Investment in unconsolidated affiliates 291,987 63,704Intangible assets, net 225,283 247,281Goodwill 217,498 232,954Other assets, net 11,798 19,386
Total assets $ 2,349,321 $ 1,751,889
Liabilities, Convertible Preferred Units, Equity and Partners' CapitalCurrent liabilities
Accounts payable $ 45,278 $ 48,526Accrued gas purchases 7,891 7,281Accrued expenses and other current liabilities 81,284 46,751Current portion of debt 5,485 2,899
Total current liabilities 139,938 105,457Asset retirement obligations 44,363 28,549Other liabilities 2,030 2,8573.77% Senior notes (Non-Recourse) 55,979 —8.50% Senior notes 291,309 —Revolving credit agreements 888,250 687,100Deferred tax liability 8,205 6,173
Total liabilities 1,430,074 830,136Commitments and contingencies (see Note 19)Convertible preferred units 334,090 169,712Equity and partners' capital
General Partner Interests (680 thousand and 536 thousand units issued and outstanding as ofDecember 31, 2016 and December 31, 2015, respectively) (47,645) (47,091)Limited Partner Interests (51,351 thousand and 50,504 thousand units issued and outstandingas of December 31, 2016 and December 31, 2015, respectively) 616,087 753,388Series B convertible units (1,350 thousand units issued and outstanding as of December 31,2015) — 33,593Accumulated other comprehensive income (loss) (40) 40
Total partners' capital 568,402 739,930Noncontrolling interests 16,755 12,111Total equity and partners' capital 585,157 752,041
Total liabilities, convertible preferred units, equity and partners' capital $ 2,349,321 $ 1,751,889
The accompanying notes are an integral part of these consolidated financial statements.
F-3
American Midstream Partners, LP, and SubsidiariesConsolidated Statements of Operations(In thousands, except per unit amounts)
Years Ended December 31,
2016 2015 2014
Revenues: Commodity sales $ 568,527 $ 772,857 $ 909,765Services 158,850 142,762 123,698Losses on commodity derivatives, net (455) (1,732) (12,671)
Total revenue 726,922 913,887 1,020,792Operating expenses:
Cost of sales 443,023 630,303 789,872Direct operating expenses 123,372 127,480 109,543Corporate expenses 99,430 77,835 72,744Depreciation, amortization and accretion 106,818 98,596 72,527Loss on sale of assets, net 2,870 3,920 5,080Loss on impairment of property, plant and equipment 697 — 21,344Loss on impairment of goodwill 15,456 148,488 —
Total operating expenses 791,666 1,086,622 1,071,110Operating loss (64,744) (172,735) (50,318)Other income (expense): Interest expense (21,469) (20,120) (16,558) Loss on extinguishment of debt — — (1,634)
Other income (expense) 628 1,732 (662)Earnings in unconsolidated affiliates 40,158 8,201 348 Loss from continuing operations before income taxes (45,427) (182,922) (68,824)
Income tax expense (2,578) (1,888) (857)Loss from continuing operations (48,005) (184,810) (69,681)
Loss from discontinued operations, net of tax (539) (15,031) (9,886)Net loss (48,544) (199,841) (79,567)
Net income (loss) attributable to noncontrolling interests 2,766 (13) 3,993
Net loss attributable to the Partnership $ (51,310) $ (199,828) $ (83,560)
General Partner's interest in net loss $ (233) $ (1,823) $ (398)
Limited Partners' interest in net loss $ (51,077) $ (198,005) $ (83,162)
Distribution declared per common unit (1) $ 3.01 $ 3.17 $ 1.85Limited Partners' net income (loss) per common unit (See Note 16):
Basic and diluted: Loss from continuing operations $ (1.59) $ (4.59) $ (3.28)Loss from discontinued operations (0.01) (0.33) (0.01)
Net loss $ (1.60) $ (4.92) $ (3.29)
Weighted average number of common units outstanding: Basic and diluted 51,176 45,050 27,524
(1) Declared and paid during the years ended December 31, 2016 , 2015 and 2014 .
The accompanying notes are an integral part of these consolidated financial statements.
F-4
American Midstream Partners, LP, and SubsidiariesConsolidated Statements of Comprehensive Loss
(In thousands)
Years Ended December 31,
2016 2015 2014
Net loss $ (48,544) $ (199,841) $ (79,567)Unrealized gain (loss) relating to postretirement benefit plan (80) 38 (102)Comprehensive loss $ (48,624) $ (199,803) $ (79,669)Less: Comprehensive income (loss) attributable to noncontrolling interests 2,766 (13) 3,993
Comprehensive loss attributable to Partnership $ (51,390) $ (199,790) $ (83,662)
The accompanying notes are an integral part of these consolidated financial statements.
F-5
American Midstream Partners, LP, and SubsidiariesConsolidated Statements of Changes in Equity, Partners' Capital and Noncontrolling Interest
(In thousands)
GeneralPartnerInterest
LimitedPartnerInterests
Series BConvertible
Units
AccumulatedOther
ComprehensiveIncome (loss)
Total Partners'Capital
Non-controllingInterests
Balances at December 31, 2013 $ 59,754 $ 611,335 $ — $ 104 $ 671,193 $ 7,884
Net income (loss) (398) (83,162) — — (83,560) 3,993
Issuance of common units, net of offering costs — 609,707 — — 609,707 —
Issuance of Series B Units — — 32,220 — 32,220 Unitholder contributions 5,678 — — — 5,678 —
Unitholder distributions (2,913) (131,106) — — (134,019) —
Issuance and exercise of warrants (7,164) 7,164 — — — —
Contributions from noncontrolling interest owners — 21 — — 21 189
Distributions to noncontrolling interest owners — — — — — (314)
LTIP vesting (823) 1,067 — — 244 —
Tax netting repurchases — (256) — — (256) —
Equity compensation expense 1,356 1,789 — — 3,145 —
Postretirement benefit plan — — — (102) (102) —
Unitholder distribution for JP Development Transaction — (47,678) — — (47,678) —
Balances at December 31, 2014 $ 55,490 $ 968,881 $ 32,220 $ 2 $ 1,056,593 $ 11,752
Net loss (1,823) (198,005) — — (199,828) (13)
Issuance of common units, net of offering costs — 85,465 — — 85,465 —
Issuance of Series B Units — — 1,373 — 1,373 —
Unitholder contributions 1,996 — — 1,996 —
Unitholder distributions (7,023) (111,740) — — (118,763) —
Unitholder distribution for Delta House Transaction (96,297) — — — (96,297) —
Contributions from noncontrolling interest owners — — — — — 739
Distributions to noncontrolling interest owners — (20) — — (20) (367)
LTIP vesting (2,490) 2,686 — — 196 —
Tax netting repurchases — (756) — — (756) —
Equity compensation expense 3,056 1,309 — — 4,365 —
Contributions from general partner — 5,568 — — 5,568 —
Postretirement benefit plan — — — 38 38 —
Balances at December 31, 2015 $ (47,091) $ 753,388 $ 33,593 $ 40 $ 739,930 $ 12,111
Net income (loss) (233) (51,077) — — (51,310) 2,766
Cancellation of escrow units — (6,817) — — (6,817) —
Conversion of Series B Units — 33,593 (33,593) — — —
Contributions from general partner 9,900 9,900 Issuance of warrants 4,481 — — — 4,481 —
Issuance of common units, net of offering costs — 2,697 — — 2,697 —
Unitholder contributions 1,998 — — — 1,998 —
Unitholder distributions (7,938) (130,761) — — (138,699) —
General Partner's contribution for acquisition 990 — — — 990 —Contributions from noncontrolling interest owners — — — — — 3,366
Distributions to noncontrolling interest owners — — — — — (1,488)
LTIP vesting (3,486) 3,486 — — — —
Tax netting repurchases — (346) — — (346) —
Equity compensation expense 3,634 2,024 — — 5,658 —
Postretirement benefit plan — — — (80) (80) —
Balances at December 31, 2016 $ (47,645) $ 616,087 $ — $ (40) $ 568,402 $ 16,755
The accompanying notes are an integral part of these consolidated financial statements.
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American Midstream Partners, LP, and SubsidiariesConsolidated Statements of Cash Flows
(In thousands)
Years Ended December 31, 2016 2015 2014
Cash flows from operating activitiesNet loss $ (48,544) $ (199,841) $ (79,567)Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion 107,029 100,877 76,219Amortization of deferred financing costs 3,236 2,391 3,118Amortization of weather derivative premium 966 912 1,035Unrealized (gain) loss on derivative contracts, net (11,400) (11,269) 12,050Non-cash compensation expense 5,658 5,172 3,415Postretirement benefit plan benefit (17) (14) (45)Loss on sale of assets, net 2,756 4,189 12,443Loss on impairment of property, plant and equipment 697 4,970 23,328Loss on impairment of noncurrent assets held for sale — — 673Loss on impairment of goodwill 15,456 156,427 —Loss on extinguishment of debt — — 1,634Other non-cash items (469) (1,256) 656Earnings in unconsolidated affiliates (40,158) (8,201) (348)Distributions from unconsolidated affiliates 40,158 8,201 348Deferred tax expense 2,057 953 213Allowance for bad debts 1,038 1,212 820
Changes in operating assets and liabilities, net of effects of assets acquired and liabilities assumed:Accounts receivable (5,430) 5,609 79,804Inventory (1,909) 13,095 17,716Unbilled revenue (219) 53,120 (51,158)Risk management assets and liabilities (1,030) (875) (809)Other current assets (795) 1,948 (16,099)Other assets, net 682 (80) 6,068Accounts payable (2,242) (50,885) (28,732)Accrued gas purchases 610 (7,045) (5,540)Accrued expenses and other current liabilities 15,384 3,623 (4,657)Asset retirement obligations (858) (90) (1,030)Other liabilities 483 835 80Corporate overhead support from General Partner 7,500 3,000 —
Net cash provided by operating activities 90,639 86,978 51,635Cash flows from investing activitiesCost of acquisitions, net of cash acquired and settlements (2,676) (5,200) (362,316)Investments in unconsolidated affiliates (150,179) (65,701) (12,000)Additions to property, plant and equipment (147,796) (208,040) (153,876)Proceeds from disposal of property, plant and equipment 11,788 8,730 17,648Distributions from unconsolidated affiliates, return of capital 42,886 12,367 1,632Restricted cash (318,527) 7,075 (9,111)
Net cash used in investing activities (564,504) (250,769) (518,023)
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Cash flows from financing activitiesProceeds from issuance of common units, net of offering costs 2,825 82,488 466,893Unitholder contributions 1,998 1,905 5,588Unitholder distributions (112,136) (100,411) (119,965)Issuance of convertible preferred units, net of offering costs 34,413 44,768 —Issuance of Series B Units — — 30,000Issuance of Series D preferred units - JPE — — 40,000Redemption of Series D preferred units - JPE — — (42,436)Unitholder distributions for common control transactions — (96,297) (52,000)Contributions from noncontrolling interest owners 3,366 584 —Distributions to noncontrolling interest owners (1,488) (114) (322)LTIP tax netting unit repurchases (521) (1,045) (610)Payment of financing costs (5,327) (2,244) (7,034)Proceeds from 3.77% Senior Notes 60,000 — —Proceeds from 8.50% Senior Notes 294,000 — —Payments on other debt (3,136) (4,069) (7,621)Other — (688) (1,344)Borrowings on other debt — 4,709 3,449Payments on revolving credit agreements (223,950) (240,150) (736,227)Borrowings on revolving credit agreements 425,100 471,300 883,885Contributions from the predecessor 2,400 1,218 4,321
Net cash provided by financing activities 477,544 161,954 466,577Net increase (decrease) in cash and cash equivalents 3,679 (1,837) 189
Cash and cash equivalentsBeginning of period 1,987 3,824 3,635
End of period $ 5,666 $ 1,987 $ 3,824
The accompanying notes are an integral part of these consolidated financial statements.
F-8
American Midstream Partners, LP, and SubsidiariesNotes to Consolidated Financial Statements
1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
General
American Midstream Partners, LP (the “Partnership”, “we”, “us”, or “our”) is a growth-oriented Delaware limited partnership that was formed on August 20, 2009to own, operate, develop and acquire a diversified portfolio of midstream energy assets. The Partnership’s general partner, American Midstream GP, LLC (the“General Partner”), is 77% owned by High Point Infrastructure Partners, LLC (“HPIP”) and 23% owned by Magnolia Infrastructure Holdings, LLC, both of whichare affiliates of ArcLight Capital Partners, LLC ("ArcLight"). Our capital accounts consist of notional General Partner units and units representing limited partnerinterests.
Nature of business
We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate andend-use markets. Through our six reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportationservices, (4) offshore pipelines and services, (5) terminalling services and (6) propane marketing services, we engage in the business of gathering, treating,processing, and transporting natural gas; gathering, transporting, storing, treating and fractionating NGLs; gathering, storing and transporting crude oil andcondensates; storing specialty chemical products; and distributing and selling propane and refined products. Most of our cash flow is generated from fee-based andfixed-margin compensation for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptibletransportation charges, guaranteed firm storage contracts, throughput fees and other optional charges associated with ancillary services.
Our primary assets are strategically located in some of the most prolific onshore and offshore producing regions and key demand markets in the United States. Ourgathering and processing assets are primarily located in (i) the Permian Basin of West Texas, (ii) the Cotton Valley/Haynesville Shale of East Texas, (iii) the EagleFord Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our transmission and terminal assets are in key demandmarkets in Oklahoma, Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick inGeorgia. Our propane marketing services include commercial and retail operations across 46 of the lower 48 states.
Basis of presentation
As discussed in Note 2, we acquired JP Energy Partners, LP ("JPE") in a unit-for-unit exchange on March 8, 2017. As both the Partnership and JPE were controlledby ArcLight, the acquisition represents a transaction among entities under common control and has been accounted for as a common control transaction in amanner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer for accounting purposes as ArcLightobtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPE historical cost basis financialstatements retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15, 2013, the date on whichArcLight obtained control of the Partnership. As the Partnership was the legal acquirer, unit amounts included in the accompanying financial statements representthe Partnership’s historical unit amounts plus the JPE unit amounts adjusted by the applicable exchange ratios.
Transactions between entities under common control We may enter into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. Weaccount for the net assets acquired at the affiliate's historical cost basis as the transactions are between entities under common control. In certain cases, ourhistorical financial statements will be revised to include the results attributable to the assets acquired from the later of April 15, 2013 (the date Arclight affiliatesobtained control of our General Partner) or the date the ArcLight affiliate obtained control of the assets acquired.
Consolidation policy
The accompanying consolidated financial statements include accounts of American Midstream Partners, LP, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.
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Use of estimates
When preparing consolidated financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP"),management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts ofassets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates andassumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimatesand assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparationof financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and generaland administrative costs, ii) developing fair value assumptions, including estimates of future cash flows and discount rates, iii) analyzing long-lived assets,goodwill and intangible assets for possible impairment, iv) estimating the useful lives of assets and v) determining amounts to accrue for contingencies, guaranteesand indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Cash, cash equivalents and restricted cash
We consider all highly liquid investments with an original maturity of three months or less at the date of purchase to be cash equivalents. The carrying value ofcash and cash equivalents approximates fair value because of the short term to maturity of these investments.
From time to time we are required to maintain cash in separate accounts the use of which is restricted by the terms of our debt agreements or asset retirementobligations. Such amounts are included in Restrictedcashin our consolidated balance sheets.
Inventory
Inventory is mainly comprised of crude oil, NGLs, and refined products for resale, as well as propane cylinders expected to be sold to customers. Inventory isstated at the lower of cost or market. The cost of crude oil, NGL, and refined products is determined using the first-in, first-out (FIFO) method while the cost ofpropane cylinders is determined using the weighted average cost method.
Allowance for doubtful accounts
We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability isreviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. We recorded allowances for doubtfulaccounts of $1.9 million and $ 1.2 million , respectively, as of December 31, 2016 and December 31, 2015. Bad debt expense for the years ended December 31,2016, 2015 and 2014 was $1.0 million , $1.2 million and $0.8 million , respectively.
Derivative financial instruments
Our net income (loss) and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt, commodity prices and fractionationmargins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). In an effort to manage the risksto unitholders, we use a variety of derivative financial instruments including swaps, collars and interest rate caps to create offsetting positions to specificcommodity or interest rate exposures. We record all derivative financial instruments in our consolidated balance sheets at fair value as current and long-term assetsor liabilities on a net basis by counterparty. We record changes in the fair value of our commodity derivatives in Gains(losses)oncommodityderivatives,netwhilechanges in the fair value of our interest rate swaps are included in Interestexpensein our consolidated statements of operations.
Our hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to theapproval and monitoring by the Board of Directors of our General Partner. We employ derivative financial instruments in connection with an underlying asset,liability or anticipated transaction, and we do not use derivative financial instruments for speculative or trading purposes.
The price assumptions we use to value our derivative financial instruments can affect our net income (loss) each period. We use published market priceinformation where available, or quotations from over-the-counter, market makers to find executable bids and offers. The valuations also reflect the potential impactof related conditions, including credit risk of our counterparties. The
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amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions orother factors, many of which are beyond our control.
We are also a party to a number of contracts that have elements of a derivative instrument. These contracts are primarily forward propane and crude oil purchaseand sales contracts with counterparties. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for thenormal purchase and normal sales exception because they provide for the delivery of products or services in quantities that are expected to be used in the normalcourse of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service beingpurchased or sold. As a result, these contracts are not recorded in our consolidated financial statements until they are settled.
Fair value measurements
We apply the authoritative accounting provisions for measuring the fair value of our derivative financial instruments and disclosures associated with ouroutstanding indebtedness. We define fair value as an exit price representing the expected amount we would receive when selling an asset or pay to transfer aliability in an orderly transaction with market participants at the measurement date.
We use various assumptions and methods in estimating the fair values of our financial instruments. The carrying amounts of cash and cash equivalents, accountsreceivable and accounts payable approximated their fair value due to the short-term maturity of these instruments.
We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs areobservable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair valuemeasurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority tounadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:
• Level 1 – Inputs represent unadjusted quoted prices in active markets for identical assets or liabilities;• Level 2 – Inputs include quoted prices for similar assets and liabilities in active markets that are either directly or indirectly observable; and• Level 3 – Inputs are unobservable and considered significant to fair value measurement.
We utilize a mid-market pricing convention, or the "market approach," for valuation for assigning fair value to our derivative assets and liabilities. Our creditexposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate,valuations are adjusted for various factors such as credit and liquidity considerations.
Property, plant and equipment
We capitalize expenditures related to property, plant and equipment that have a useful life greater than one year. We also capitalize expenditures that improve orextend the useful life of an asset. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.
We record property, plant, and equipment at cost and recognize depreciation expense on a straight-line basis over the related estimated useful lives of the assetswhich range from 3 to 40 years. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including thesupply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenanceprograms. We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar assets.
We classify long-lived assets to be disposed of through sales that meet specific criteria as held for sale. We cease depreciating those assets effective on the date theasset is classified as held for sale. We record those assets at the lower of their carrying value or the estimated fair value less the cost to sell. Until the assets aredisposed of, our estimate of fair value is re-determined when related events or circumstances change.
Impairment of long lived Assets
We evaluate the recoverability of our property, plant and equipment and intangible assets with definite lives when events or circumstances indicate we may notrecover the carrying amount of the assets. We continually monitor our operations, the market, and business environment to identify indicators that could suggest anasset or asset group may not be recoverable. We evaluate the asset or asset group for recoverability by estimating the undiscounted future cash flows expected to bederived from their use
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and disposition. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition,operating cost, contract renewals, and other factors. An asset or asset group is considered impaired when the estimated undiscounted cash flows are less than thecarrying amount. In that event, an impairment loss is recognized to the extent that the carrying amount of the asset or asset group exceeds its fair value asdetermined by quoted market prices in active markets or present value techniques. The determination of fair values using present value techniques requires us tomake projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptionscould result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in ourconsolidated statements of operations.
Goodwill and intangible assets
We record goodwill for the excess of the cost of an acquisition over the fair value of the net assets of the acquired business. Goodwill is reviewed for impairment atleast annually or more frequently if an event or change in circumstance indicates that an impairment may have occurred. We first assess qualitative factors toevaluate whether it is more likely than not that an impairment has occurred and it is therefore necessary to perform the two-step goodwill impairment test. If thetwo-step goodwill impairment test indicates that the goodwill is impaired, an impairment loss is recorded.
We record the estimated fair value of acquired customer contracts, relationships and dedicated acreage agreements as intangible assets. These intangible assetshave definite lives and are subject to amortization on a straight-line basis over their economic lives, currently ranging between 5 years and 30 years . We assessintangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amountof an asset may not be recoverable.
Investment in unconsolidated affiliates
We hold membership interests in entities that own and operate natural gas pipeline systems and NGL and crude oil pipelines in and around Louisiana, Alabama,Mississippi and the Gulf of Mexico. While we have significant influence over these entities, we do not control them and therefore, they are accounted for using theequity method and are reported in Investmentinunconsolidatedaffiliates in the consolidated balance sheets. We evaluate the recoverability of these investmentson a regular basis and recognize impairment write downs if we determine a loss in value represents an other than temporary decline.
Deferred financing costs
Costs incurred in connection with our revolving credit agreements are deferred and charged to interest expense over the term of the related credit arrangement.Such amounts are included in Otherassets,netin our consolidated balance sheets. Costs incurred in connection with our 8.50% Senior Notes and 3.77% SeniorNotes are also deferred and charged to interest expense over the respective term of the agreements; however, these amounts are reflected as a reduction of therelated obligation. Gains or losses on debt repurchases or extinguishment include any associated unamortized deferred financing costs.
Asset retirement obligations
Asset retirement obligations ("ARO") are legal obligations associated with the retirement of tangible long-lived assets that result from the asset's acquisition,construction, development and operation. An ARO is initially measured at its estimated fair value. Upon initial recognition, we also record an increase to thecarrying amount of the related long-lived asset. We depreciate the asset using the straight-line method over the period during which it is expected to providebenefits. After initial recognition, we revise the ARO to reflect the passage of time and for changes in the estimated amount or timing of cash flows.
We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annualcharges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for certain of our offshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshorepipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information toreasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation. In these cases, the assetretirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice,management's experience, or the asset's estimated economic life. The useful lives of most pipeline systems are primarily derived from available supply resourcesand ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonableestimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists toreasonably estimate potential settlement dates and methods.
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Commitments, contingencies and environmental liabilities
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expenseamounts we incur from the remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing oreliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs canbe reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws andregulation taking into consideration the likely effects of inflation and other factors. These amounts also take into account our prior experience in remediatingcontaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periodsbased on actual cost or new information. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we recordan asset separately from the associated liability in our consolidated financial statements.
We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liabilityhas been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount or if noamount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costsare incurred.
Noncontrolling interests
Noncontrolling interests represent the minority interest holders' proportionate share of the equity in certain of our consolidated subsidiaries and are adjusted for theminority interest holders' proportionate share of the subsidiaries' earnings or losses each period.
Revenue recognition
We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs or condensate) as well as from the provision of gathering, processing,transportation or storage services when all of the following criteria are met: i) persuasive evidence of an exchange arrangement exists, ii) delivery has occurred orservices have been rendered, iii) the price is fixed or determinable, and iv) collectability is reasonably assured. We recognize revenue from the sale of commoditiesand the related cost of product sold on a gross basis for those transactions where we act as the principal and take title to commodities that are purchased for resale.
Cost of sales
Cost of sales represent the cost of commodities purchased for resale or obtained in connection with certain of our customer revenue arrangements. These costs donot include an allocation of depreciation expense or direct operating costs.
Corporate expenses
Corporate expenses include compensation costs for executives and administrative personnel, professional service fees, rent expense and other general andadministrative expenses and are recognized as incurred.
Operational balancing agreements and natural gas imbalances
To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnectingpipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volumeactually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gasimbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through future receipt or delivery of natural gas. Natural gasimbalances are recorded in Othercurrentassetsor Accruedexpensesandothercurrentliabilitieson our consolidated balance sheets at cost which approximatesfair value.
Equity-based compensation
We award equity-based compensation to management, non-management employees and directors under our long-term incentive plans, which provide for theissuance of options, unit appreciation rights, restricted units, phantom units, other unit-based awards, unit awards or replacement awards, as well as tandemdistribution equivalent rights ("DERs"). Compensation expense is measured by the fair value of the award at the date of grant as determined by management.Compensation expense is recognized in Corporateexpensesand Directoperatingexpensesover the requisite service period of each award.
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Income taxes
The Partnership is not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income aregenerally borne by our unitholders through the allocation of taxable income. American Midstream Blackwater, LLC, a subsidiary of the Partnership, owns asubsidiary that has operations which are subject to both federal and state income taxes. We account for income taxes of that subsidiary using the asset and liabilityapproach. If it is more than likely that a deferred tax asset will not be realized, a valuation allowance is recognized.
Margin tax expense results from the enactment of laws by the State of Texas that apply to entities organized as partnerships and is included in Incometaxexpensein our consolidated statements of operations. The Texas margin tax is computed on the portion of our taxable margin which is apportioned to Texas.
Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) allocable to unitholders as a result of differences betweenthe financial reporting and income tax bases of our assets and liabilities and the taxable income allocation requirement under our Partnership Agreement. Theaggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding eachpartner's tax attributes in us is not available.
Accumulated other comprehensive income (loss)
Accumulatedothercomprehensiveincome(loss)is comprised solely of adjustments related to the Partnership's postretirement benefit plan.
Limited partners' net income (loss) per unit
We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security beconsidered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for theperiod were distributed under the terms of the Partnership Agreement, regardless of whether the General Partner has discretion over the amount of distributions tobe made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, orwhether the General Partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings fora particular period.
The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregatedistributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregateearnings, as if distributed, is allocated to the incentive distribution rights of the General Partner, even though we make distributions on the basis of available cashand not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not haveany impact on our calculation of earnings per limited partner unit.
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New Accounting Pronouncements
Recently Adopted Accounting Standards
In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Simplifying the Presentation ofDebt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction fromthe carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, includinginterim periods therein, and is applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. ASU 2015-15,Presentation and Subsequent Measurement of Debt Issue Costs Associated with Line of Credit Arrangements, was subsequently issued to address the absence ofauthoritative guidance for debt issuance costs related to line-of-credit arrangements and states that the Securities and Exchange Commission ("SEC") staff will notobject to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of theline-of-credit arrangement.
The Partnership adopted the requirements of ASU No. 2015-03 effective January 1, 2016 and classifies the debt issuance costs applicable to its 8.50% Senior Notesand 3.77% Senior Notes as a reduction of the related debt obligation. Additionally, the Partnership continues to classify the debt issuance costs relating to its CreditAgreement within Otherassets,netas allowed by ASU No. 2015-15. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805). This update requires that an acquirer recognize adjustments toprovisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 iseffective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Partnership adopted the updated guidanceeffective January 1, 2016 without impact to its financial statements.
Accounting Standards Issued Not Yet Adopted
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting guidance forrevenue recognition. The update requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount thatreflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2015-14 was subsequently issued anddeferred the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that period. In March 2016,the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations, as further clarification onprincipal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): IdentifyingPerformance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016,the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, as clarifyingguidance on specific narrow scope improvements and practical expedients. We are in the process of reviewing our various customer arrangements in order todetermine the impact that these updates will have on our consolidated financial statements and related disclosures. We have engaged a third-party consultant toassist with our review, which we currently expect to complete in the third quarter of 2017.
In February 2016, the FASB issued ASU No. 2016-02 (Topic 842) "Leases" which supersedes the lease recognition requirements in Accounting StandardsCodification Topic 840, "Leases". Under ASU No. 2016-02 lessees are required to recognize assets and liabilities on the balance sheet for most leases and provideenhanced disclosures. Leases will continue to be classified as either finance or operating. ASU No. 2016-02 is effective for annual reporting periods, and interimperiods within those years beginning after December 15, 2018. Entities are required to use a modified retrospective approach for leases that exist or are entered intoafter the beginning of the earliest comparative period in the financial statements, and there are certain optional practical expedients that an entity may elect toapply. Full retrospective application is prohibited and early adoption by public entities is permitted. Based upon our evaluation to date, we anticipate that theadoption of ASU 2016-02 will have a material effect on our consolidated financial statements as we will be required to reflect our various lease obligations andassociated asset use rights on our consolidated balance sheets. The adoption may also impact our debt covenant compliance and may require us to modify orreplace certain of our existing information systems. We have not yet determined the timing or manner in which we will implement the updated guidance.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments, which addresseseight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if allaspects are adopted in the same
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period. The Partnership is currently evaluating the impact this update will have on its consolidated statements of cash flows and related disclosures.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash, which aims to improve the disclosure of the changeduring the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described asrestricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period totalamounts on the statement of cash flows. The update is effective beginning first quarter of 2018. Early adoption is permitted, but it must occur in the first interimperiod. Any adjustments required in early adoption of this update should be reflected as of the beginning of the fiscal year that includes the interim period andshould be applied using a retrospective transition method to each period. The Partnership is evaluating the impact that this update will have on our consolidatedstatement of cash flows and related disclosures.
2. Acquisitions and Divestitures
JP Energy Partners
On March 8, 2017, the Partnership completed the acquisition of JPE, an entity controlled by ArcLight affiliates, in a unit-for-unit exchange. In connection with thetransaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 0.5775 of a Partnershipcommon unit, and each JPE common or subordinated unit held by ArcLight affiliates was converted into the right to receive 0.5225 of a Partnership common unit.The Partnership issued a total of 20.2 million of its common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates. Basedupon the closing price for our common units on March 8, 2017, the units issued in the exchange had an estimated fair value of $322.2 million .
JPE owns, operates and develops a diversified portfolio of midstream energy assets with three business segments (i) crude oil pipelines and storage, (ii) refinedproducts terminals and storage and (iii) NGL distribution and sales, which together provide midstream infrastructure solutions for the growing supply of crude oil,refined products and NGLs, in the United States.
As both the Partnership and JPE were controlled by ArcLight, the acquisition represents a transaction among entities under common control and is accounted for asa common control transaction in a manner similar to a pooling of interests. Although the Partnership is the legal acquirer, JPE is considered to be the acquirer foraccounting purposes as ArcLight obtained control of JPE before it obtained control the Partnership. The accompanying financial statements represent the JPEhistorical cost basis financial statements, retrospectively adjusted to reflect its acquisition of the Partnership at ArcLight’s historical cost basis effective April 15,2013, the date on which ArcLight obtained control of the Partnership.
Delta House Investment
On September 18, 2015, the Partnership acquired a 26.3% interest in Pinto Offshore Holdings, LLC ("Pinto"), an entity that owns 49% of the Class A Units ofDelta House FPS LLC and of Delta House Oil and Gas Lateral LLC (collectively referred to herein as "Delta House"), a floating production system platform withassociated crude oil and gas export pipelines, located in the Mississippi Canyon region of the deepwater Gulf of Mexico ("Delta House").
We acquired our 26.3% non-operated interest in Pinto in exchange for $ 162.0 million in cash, funded by the proceeds of a public offering of 7.5 million of thePartnership's common units and with borrowings under the Partnership’s Amended and Restated Credit Agreement (the "Credit Agreement"). As a result, we owna minority interest in Pinto, which represents an indirect interest in 12.9% of Delta House's Class A Units. Pursuant to the Pinto LLC Agreement, we have nomanagement control or authority over the day-to-day operations. Our interest in Pinto is accounted for as an equity method investment in the consolidated financialstatements.
Because our interest in Delta House was previously owned by an ArcLight affiliate, we recorded our investment at the affiliate's historical cost basis of $65.7million in Investmentsinunconsolidatedaffiliatesin our consolidated balance sheets and as an investing activity within the related consolidated statements of cashflows. The amount by which the total consideration exceeded affiliate's historical cost basis was $96.3 million and is recorded as a distribution within theconsolidated statements of changes in equity, partners’ capital and noncontrolling interests and as a financing activity in the consolidated statements of cash flows.
On April 25, 2016, the Partnership increased its investment in Delta House through the purchase of 100% of the outstanding membership interests in D-DayOffshore Holdings, LLC (“D-Day”), an Arclight affiliate which owned 1.0% of Delta House Class A Units in exchange for approximately $9.9 million in cashfunded with borrowings under our revolving credit agreement.
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Because the additional investment in Delta House was previously owned by an ArcLight affiliate, we recorded our investment in D-Day at the affiliate’s historicalcost basis of $9.9 million in Investments in unconsolidated affiliates on our consolidated balance sheets and as an investing activity within our condensedconsolidated statements of cash flows.
On October 31, 2016, D-Day acquired an additional 6.2% direct interest in Delta House Class A Units from unrelated parties for approximately $48.8 millionwhich was funded with $34.5 million in net proceeds from the issuance of 2,333,333 Series D convertible preferred units ("Series D Preferred Units") to anArcLight affiliate, plus $14.3 million in cash funded with borrowings under our Credit Agreement. Our share of Delta House earnings is included in the OffshorePipelines and Services segment gross margin.
Our investments in D-Day and Pinto result in our holding a 20.1% non-operated direct and indirect interests in the Class A units of Delta House as of December31, 2016 . Such interests include a 20.1% interest in Class A Units of Delta House FPS, which are currently entitled to receive 100% of the distributions from DeltaHouse FPS until a certain payout threshold is met. Once the payout threshold is met, approximately 7% of distributions from Delta House FPS will be paid to theClass B membership interests in Delta House FPS.
Emerald Transactions
On April 25, 2016 and April 27, 2016, American Midstream Emerald, LLC (“Emerald”), a wholly-owned subsidiary of the Partnership, entered into two purchaseand sale agreements with Emerald Midstream, LLC, an ArcLight affiliate, for the purchase of membership interests in certain midstream entities.
On April 25, 2016, Emerald entered into the first purchase and sale agreement for the purchase of membership interests in entities that own and operate natural gaspipeline systems and NGL pipelines in and around Louisiana, Alabama, Mississippi, and the Gulf of Mexico (the “Pipeline Purchase Agreement”). Pursuant to thePipeline Purchase Agreement, Emerald acquired (i) 49.7% of the issued and outstanding membership interests of in Destin Pipeline Company, L.L.C. (“Destin”),(ii) 16.7% of the issued and outstanding membership interests of Tri-States NGL Pipeline, L.L.C. ("Tri-States"), and (iii) 25.3% of the issued and outstandingmembership interests of Wilprise Pipeline Company, L.L.C. (“Wilprise”), in exchange for approximately $183.6 million (the “Pipeline Transaction”).
The Destin pipeline is a FERC-regulated, 255 -mile natural gas transportation system with total capacity of 1.2 Bcf/d. The system originates offshore in the Gulf ofMexico and includes connections with four producing platforms and six producer-operated laterals, including Delta House. The 120 -mile offshore portion of theDestin system terminates at the Pascagoula processing plant, which is owned by Enterprise Products Partners, LP, and is the single source of raw natural gas to theplant. The onshore portion of Destin is the sole delivery point for merchant-quality gas from the Pascagoula processing plant and extends 135 miles north inMississippi. Destin currently serves as the primary transfer of gas flows from the Barnett and Haynesville shale plays to Florida markets through interconnectionswith major interstate pipelines. Contracted volumes on the Destin pipeline are based on life-of-field dedications, dedicated volumes over a given period, orinterruptible volumes as capacity permits. We became the operator of the Destin pipeline on November 1, 2016. The Tri-States pipeline is a FERC-regulated, 161 -mile NGL pipeline and sole form of transport to Louisiana-based fractionators for NGLs produced at the Pascagoula plant served by Destin and other facilities.The Wilprise pipeline is a FERC-regulated, approximately 30 -mile NGL pipeline that originates at the Kenner Junction and terminates in Sorrento, Louisiana,where volumes flow via pipeline to a Baton Rouge fractionator.
On April 27, 2016, Emerald entered into a second purchase and sale agreement for the purchase of 66.7% of the issued and outstanding membership interests ofOkeanos Gas Gathering Company, LLC ("Okeanos"), in exchange for a cash purchase price of approximately $27.4 million (such Purchase and Sale Agreement,the “Okeanos Purchase Agreement,” and such transaction, the “Okeanos Transaction,” and together with the Pipeline Transaction, the “Emerald Transactions”).The Okeanos pipeline is a 100 -mile natural gas gathering system located in the Gulf of Mexico with a total capacity of 1.0 Bcf/d. The Okeanos pipeline connectstwo platforms and one lateral, terminating at the Destin Main Pass 260 platform in the Mississippi Canyon region of the Gulf of Mexico. Contracted volumes onthe Okeanos pipeline are based on life-of-field dedication. We became the operator of the Okeanos pipeline on November 1, 2016.
The Partnership funded the aggregate purchase price for the Emerald Transactions with the issuance of 8,571,429 Series C convertible preferred units (the “SeriesC Units”) representing limited partnership interests in the Partnership and a warrant (the “ Series C Warrant”) to purchase up to 800,000 common unitsrepresenting limited partnership interests in the Partnership (“common units”) at an exercise price of $7.25 per common unit amounting to a combined value ofapproximately $120.0 million , plus additional borrowings of $91.0 million under our Credit Agreement. ArcLight affiliates hold and participate in distributions onour Series C Units with such distributions being made in paid-in-kind Series C Units, cash or a combination thereof at the election
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of the Board of Directors of our General Partner. Our share of earnings of the entities underlying the Emerald transaction is included in the Liquid Pipelines andServices segment gross margin.
Because our interests in the entities underlying the Emerald Transactions were previously owned by an ArcLight affiliate, we recorded our investments at theaffiliate’s historical cost basis of $212.0 million , in Investment in unconsolidated affiliates in our consolidated balance sheets, and as an investing activity of$100.9 million within the consolidated statements of cash flows. The amount by which the affiliate's historical basis exceeded total consideration paid was $1.0million and is recorded as a contribution from our General Partner in the consolidated statements of changes in partners’ capital and noncontrolling interests.
Gulf of Mexico Pipeline
On April 15, 2016, American Panther LLC, ("American Panther"), a 60% -owned subsidiary of the Partnership, acquired approximately 200 miles of crude oil,natural gas, and salt water onshore and offshore Gulf of Mexico pipelines (“Gulf of Mexico Pipeline”) from Chevron Pipeline Company and Chevron MidstreamPipeline, LLC for approximately $2.7 million in cash and the assumption of certain asset retirement obligations. The Partnership controls American Panther andtherefore consolidates it for financial reporting purposes.
The American Panther acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assetsacquired and liabilities assumed based on their respective estimated fair values as of the acquisition date. The purchase price allocation included $16.6 million inpipelines, $0.4 million in land, $14.3 million in asset retirement obligations, and $1.8 million in noncontrolling interests.American Panther contributed revenue of $13.2 million and operating income of $7.4 million to the Partnership for the year ended December 31, 2016 . Suchamounts are included in the Partnership’s Offshore Pipelines and Services segment. During the year ended December 31, 2016 , the Partnership incurred $0.3million of transaction costs related to the American Panther acquisition which are included in Corporateexpensesin our consolidated statements of operations forthe periods.Unaudited pro forma financial information depicting what the Partnership's revenue, net income and per unit amounts would have been had the American Pantheracquisition occurred on January 1, 2016, is not available because Chevron Pipeline Company and Chevron Midstream Pipeline, LLC did not historically operatethe acquired assets as a standalone business.
Southern Propane Inc.
On May 8, 2015, we acquired substantially all of the assets of Southern Propane Inc. (“Southern”), a Houston-based industrial and commercial propane distributionand logistics company. The acquisition expanded the asset base and market share of our Propane Marketing and Services segment, specifically the acceleration ofour entry into the Houston, Texas market, as well as expansion of our industrial, non-seasonal customers. The total purchase price of $16.3 million consisted of a$12.5 million cash payment that was paid on the acquisition date, and which was funded through the use of borrowings from our revolving credit facility, a $0.1million cash payment to the seller as the final working capital adjustment, the issuance of 266,951 common units valued at $3.4 million and a contingent earn-outliability with an acquisition date fair. The gross profit targets were not achieved and the remaining $0.2 million liability was released to income in 2016.
The $16.3 million purchase price was allocated to customer relationship intangible assets $6.2 million , goodwill $5.8 million , property, plant and equipment $3.0million , accounts receivable $1.0 million and other intangible assets $0.3 million . Goodwill associated with the acquisition principally results from synergiesexpected from integrated operations. The fair values of the acquired intangible assets were estimated by applying the income approach which is based onsignificant inputs that are not observable in the market and represents a Level 3 measurement. The customer relationship assets are being amortized over aweighted average useful life of 12 years.
Costar Acquisition
On October 14, 2014, the Partnership acquired 100% of the membership interests of Costar Midstream, L.L.C. ("Costar") from Energy Spectrum Partners VI LPand Costar Midstream Energy, LLC, in exchange for cash and common units with an aggregate value of $405.3 million . Costar is an onshore gathering andprocessing company with its primary gathering, processing, fractionation, and off-spec condensate treating and stabilization assets in East Texas and the Permianbasin, with a significant crude oil gathering system project in the Bakken oil play.
The Costar acquisition was accounted for using the acquisition method of accounting and as a result, the purchase price was allocated to the assets acquired andliabilities assumed based on their respective fair values as of the acquisition date. The excess of the aggregate purchase price of the fair values of the assetsacquired, liabilities assumed and the noncontrolling interest was
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classified as goodwill, which was attributable to future prospective customer agreements expected to be obtained as a result of the acquisition. The operatingsystems acquired have been included in the Partnership’s Gathering and Processing segment from the acquisition date.
During 2015, the Partnership reached agreements with the Costar sellers regarding certain matters which resulted in a return of $7.4 million of cash to thePartnership and related reductions in the goodwill initially recorded. Additionally, in February 2016, the Partnership reached a settlement of certainindemnification claims with the Costar sellers whereby 1,034,483 common units held in escrow with a fair value of $6.8 million were returned to the Partnership,while the Partnership agreed to pay the Costar sellers an additional $0.3 million . The net impact of this settlement was recorded as a reduction in property, plantand equipment in the first quarter of 2016. The Partnership recognized a $95.0 million impairment of the remaining Costar goodwill in fourth quarter of 2015.
Lavaca Acquisition
On January 31, 2014, the Partnership acquired approximately 120 miles of high- and low-pressure pipelines and associated facilities located in the Eagle Ford shalein Gonzales and Lavaca Counties, Texas from Penn Virginia Corporation (NYSE: PVA) ("PVA") for $104.4 million in cash. The Lavaca acquisition was financedwith proceeds from the Partnership's January 2014 equity offering and from the issuance of Series B Units to our General Partner.
The Lavaca acquisition was accounted for using the acquisition method of accounting and, as a result, the purchase price was allocated to the assets acquired upontheir respective fair values as of the acquisition date. The excess of the purchase price over the fair value of the assets acquired was classified as goodwill, whichwas attributable to future prospective customer agreements expected to be obtained as a result of the acquisition. The operating systems acquired have beenincluded in the Partnership’s Gathering and Processing segment from the acquisition date. The Partnership recognized a $23.6 million impairment of the remainingLavaca goodwill in the fourth quarter of 2015.
JP Development
On February 12, 2014, JPE acquired a variety of midstream assets from JP Energy Development, LP (“JP Development”), an entity controlled by ArcLight, for$319.1 million , comprised of 5,841,205 of JPE Class A Common Units and $52.0 million in cash funded by borrowings under JPE’s revolving credit facility. Asboth JPE and JP Development were controlled by ArcLight, the acquisition represented a transaction among entities under common control and was accounted foras a common control transaction in a manner similar to a pooling of interests. In connection with the acquisition, ArcLight forgave related amounts receivabletotaling $4.3 million . The cash portion of the purchase less the receivable forgiven has been reflected as a unitholder distribution for the JP Developmenttransaction in the consolidated statement of equity and partners’ capital for the year ended December 31, 2014.
3. Discontinued Operations
Mid-Continent
On February 1, 2016, we sold certain trucking and marketing assets in the Mid-Continent area (the “Mid-Continent Business”) to JP Development for $9.7 millionin cash. We recognized a loss on the disposal of approximately $12.9 million during the year ended December 31, 2015, which primarily related to goodwill andlong-lived asset impairment charges. Prior to the classification as discontinued operations, we reported the Mid-Continent Business in our Liquid Pipelines andServices segment.
Financial information for the Mid-Continent Business which is included in Loss from discontinued operations, net of tax in the consolidated statement ofoperations is summarized below:
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Year Ended December 31,
2016 2015 2014 (in thousands)Revenues Total revenues $ 11,495 $ 429,784 $ 967,480Costs and Expenses Costs of sales 11,687 426,886 961,428Direct operating expenses 203 2,269 2,866Loss on impairment of goodwill and assets held for sale — 12,909 —Depreciation, amortization and accretion 211 2,281 2,258(Gain) loss on sale of assets, net (114) 119 229 Total expenses 11,987 444,464 966,781
Operating (loss) income (492) (14,680) 699
Other income (expense) (47) (271) (366)(Loss) income from discontinued operations beforeincome tax expense (539) (14,951) 333 Income tax expense — — —
Net (loss) income from discontinued operations $ (539) $ (14,951) $ 333
Bakken Business
On June 30, 2014, we sold our trucking and related assets in North Dakota, Montana and Wyoming (the “Bakken Business”) to Gold Spur Trucking, LLC for $9.1million . We recognized a loss on this sale of approximately $7.3 million during the second quarter of 2014, which primarily related to the write-off of a relatedcustomer contract. We also recognized a $2.0 million goodwill impairment charge in connection with the transaction
Financial information for the Bakken Business which is included in Loss from discontinued operations, net of tax in the consolidated statement of operations issummarized below:
Year Ended December 31, 2014 (in thousands)Total revenues $ 7,865Net loss from discontinued operations, including loss on disposal of $7,288 (9,608)
Blackwater
On December 17, 2013, we acquired Blackwater Midstream Holdings LLC ("Blackwater") from an ArcLight affiliate. As part of the Blackwater acquisition, weacquired certain long-lived terminal assets which were immediately classified as held for sale. Due to deteriorating market conditions, the Partnership recognizedan impairment charge on these assets of $0.7 million in 2014. These assets were sold during the third quarter of 2015 at a nominal loss.
Financial information for the portion of the Blackwater business sold which is included in Loss from discontinued operations, net of tax in the consolidatedstatement of operations is summarized below:
Years Ended December 31, 2015 2014 (in thousands)Total revenues $ 74 $ 474Loss from discontinued operations, net of tax (80) (611)
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Due to immateriality, we elected to not separately present the cash flows from operating, investing and financing activities related to the discontinued operationsdescribed above in our consolidated statements of cash flows.
4. Concentration of Credit Risk
Significant customers are defined as those who represent 10% of more of our consolidated revenue during the year. In 2016, we had two such customers whoaccounted for 17% and 10% , respectively, of our consolidated revenue. In 2015, we had one such customer who accounted for 28% of our consolidated revenue.In 2014, we had one such customer who accounted for 16% of our consolidated revenue.
We are party to various commercial netting agreements that allow us and contractual counterparties to net receivable and payable obligations. These agreementsare customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.
5. Inventory
Inventory consists of the following:
December 31,
2016 2015 (in thousands)Crude oil $ 1,216 $ 486NGLs 3,482 2,638Refined products 291 463Materials, supplies and equipment 1,787 1,654
Total inventory $ 6,776 $ 5,241
6. Other Current Assets
Other current assets consists of the following:
December 31,
2016 2015 (in thousands)Prepaid insurance $ 9,702 $ 5,187Insurance receivables 2,895 115Other receivables 2,998 2,688Due from related parties 4,805 8,688Risk management assets 964 365Other assets 6,303 5,753Discontinued operations, current assets — 2,730 Total other current assets $ 27,667 $ 25,526
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7. Risk Management Activities
Commodity Derivatives
To limit the effect of commodity price changes and maintain our cash flow and the economics of our development plans, we enter into commodity derivativecontracts from time to time. The terms of the contracts depend on various factors, including management's view of future commodity prices, economics onpurchased assets and future financial commitments. This hedging program is designed to mitigate the effect of commodity price declines while allowing us toparticipate to some extent in commodity price increases. Management regularly monitors the commodity markets and our financial commitments to determine if,when, and at what level commodity hedging is appropriate in accordance with policies that are established by the board of directors of our General Partner.
To meet this objective, we use a combination of fixed price swaps, basis swaps and forward contracts. We enter into commodity contracts with multiplecounterparties, and in some cases, may be required to post collateral with our counterparties in connection with our derivative positions. The counterparties are notrequired to post collateral with us in connection with their derivative positions. Netting agreements are in place that permit us to offset our commodity derivativeasset and liability positions with our counterparties. At times, we may also terminate or unwind hedges or portions of hedges in order to meet cash flow objectivesor when the expected future volumes do not support the level of hedges. Our forward contracts that qualify for the normal purchase normal sale exception arerecognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments, they are not recorded atfair value, but on an accrual basis of accounting. If it is determined that a transaction no longer meets the exception, the fair value of the related contract isrecorded on the consolidated balance sheets and immediately recognized through earnings.
In August 2015, we paid approximately $8.7 million to settle all of our then-outstanding propane financial swap contracts that were scheduled to mature at variousdates through April 2017. We simultaneously executed new propane financial swap contracts at the then current forward market prices for the purpose ofeconomically hedging a substantial majority of our fixed price propane sales contracts through July 2017.
The following table summarizes the net notional volume buy (sell) of our outstanding commodity-related derivatives, excluding those derivatives that qualified forthe normal purchase normal sale exception as of December 31, 2016 and 2015, none of which were designated as hedges for accounting purposes.
December 31, 2016 December 31, 2015
Notional Volume Maturity Notional Volume MaturityCommodity Swaps: Propane Fixed Price (Gallons) 4,364,880 Jan 2017 - Nov 2018 8,614,631 Jan 2016 - July 2017Crude Oil Fixed Price (Barrels) — — (93,000) Jan 2016Crude Oil Basis (Barrels) 180,000 Jan 2017 - Mar 2017 — —
Interest Rate Swaps
To manage the impact of the interest rate risk associated with our Credit Agreement, we enter into interest rate swaps from time to time, effectively converting aportion of the cash flows related to our long-term variable rate debt into fixed rate cash flows.
Notional Amount Term Fair Value(in thousands) (in thousands)
$200,000 January 3, 2017 thru September 3, 2019 $ 1,912$100,000 January 1, 2017 thru December 31, 2017 (71)$100,000 January 1, 2018 thru January 31, 2019 226$100,000 January 1, 2018 thru December 31, 2021 3,090$150,000 January 1, 2018 thru December 31, 2022 5,219
$ 10,376
The fair value of our interest rate swaps was estimated using a valuation methodology based upon forward interest rate and volatility curves as well as otherrelevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of
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future cash flows associated with long dated transactions or illiquid market points. The inputs, which represent Level 2 inputs in the valuation hierarchy, areobtained from independent pricing services and we have made no adjustments to those prices.
Weather Derivative
In the second quarters of 2016 and 2015, we entered into weather derivatives to mitigate the impact of potential unfavorable weather to our operations under whichwe could receive payments totaling up to $30.0 million in the event that a hurricane or hurricanes of certain strength pass through the area as identified in therelated agreement. The weather derivatives, which are accounted for using the intrinsic value method, were entered into with a single counterparty and we were notrequired to post collateral.
We paid premiums of $1.0 million and $0.9 million in 2016 and 2015, respectively, which are amortized to Directoperatingexpenseson a straight-line basis overthe 1 year term of the contract. Unamortized amounts associated with weather derivatives were approximately $0.4 million at December 31, 2016 and 2015 , andare included in Othercurrentassetson the consolidated balance sheets.
Our interest rate swaps, commodity swaps and weather derivatives were recorded in our consolidated balance sheets, under the following captions:
Gross Risk Management Position Netting Adjustment Net Risk Management Position
Balance Sheet Classification December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015 December 31, 2016 December 31, 2015
(in thousands)Other current assets $ 1,036 $ 457 $ (72) $ (92) $ 964 $ 365Risk management assets - long term 10,665 — (1) — 10,664 —
Total assets $ 11,701 $ 457 $ (73) $ (92) $ 11,628 $ 365
Accrued expenses and other currentliabilities $ (253) $ (450) $ 72 $ 92 $ (181) $ (358)Other liabilities (1) (24) 1 — — (24)
Total liabilities $ (254) $ (474) $ 73 $ 92 $ (181) $ (382)
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For the years ended December 31, 2016 , 2015 and 2014 , the realized and unrealized gains (losses) associated with our commodity, interest rate and weatherderivative instruments were recorded in our consolidated statements of operations, under the following captions:
Realized Unrealized
(in thousands)2016 Lossesoncommodityderivatives,net $ (1,480) $ 1,025Interestexpense (144) 10,375Directoperatingexpenses (966) —
Total $ (2,590) $ 11,400
2015 Lossesoncommodityderivatives,net $ (13,209) $ 11,477Interestexpense (425) 373Directoperatingexpenses (913) —
Total $ (14,547) $ 11,850
2014 Lossesoncommodityderivatives,net $ (337) $ (12,334)Interestexpense (707) 284Directoperatingexpenses (1,035) —
Total $ (2,079) $ (12,050)
8. Property, Plant and Equipment, Net
Property, plant and equipment, net. consists of the following:
Useful Life(in years)
December 31, 2016
December 31, 2015
(in thousands)Land N/A $ 23,520 $ 18,902Construction in progress N/A 131,448 58,146Transportation Equipment 5 to 15 44,060 46,582Buildings and improvements 4 to 40 24,225 22,398Processing and treating plants 8 to 40 120,977 102,111Pipelines and compressors 3 to 40 804,815 775,486Storage 3 to 40 210,579 210,208Equipment 5 to 20 102,409 78,131
Total property, plant and equipment 1,462,033 1,311,964Less accumulated depreciation (317,030) (240,450)Property, plant and equipment, net $ 1,145,003 $ 1,071,514
At December 31, 2016 and 2015 , gross property, plant and equipment included $291.1 million and $228.9 million , respectively, related to our FERC regulatedinterstate and intrastate assets.
Depreciation expense totaled $82.8 million , $75.0 million and $50.9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, which isincluded in the depreciation,amortizationandaccretionexpensein the consolidated statements of operations. Depreciation expense amounts have been adjustedby $0.1 million , $1.1 million , and $1.7 million for the years ended December 31, 2016, 2015 and 2014, respectively, to present the Mid-Continent and BakkenBusiness's operations as discontinued operations. Capitalized interest was $2.7 million , $1.9 million and $0.8 million for the years ended December 31, 2016 ,2015 and 2014 , respectively.
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During the fourth quarter of 2014, management noted the declining commodity markets and related impact on producers and shippers to whom we providegathering and processing services. The decline in the market price of crude oil led to a corresponding decrease in natural gas and crude oil production impactingthe volume of natural gas and NGLs we gather and process on certain assets. As a result, an asset impairment charge of $21.3 million was recorded to reduce thecarrying value of the impacted assets to their estimated fair value. The related fair value measurements were based on significant inputs not observable in themarket and thus represented Level 3 measurements. Primarily using the income approach, the fair value estimates were based on i) present value of estimatedEBITDA, ii) an assumed discount rate of 9.5% , and iii) the expected remaining useful life of the asset groups.
9. Goodwill and Intangible Assets, Net
Management performs an annual goodwill assessment at the reporting unit level. We first assess qualitative factors to evaluate whether it is more likely than notthat an impairment has occurred and if it is then necessary to perform the two-step goodwill impairment test. The two-step goodwill impairment test involves fairvalue measurements that are based on significant inputs not observable in the market and thus represent Level 3 measurements. In the two-step assessment,management primarily uses a discounted cash flow analysis, supplemented by a market approach analysis. Key assumptions in the discounted cash flow analysisinclude an appropriate discount rate, estimated volumes, storage utilization, terminal year multiples, operating costs and maintenance capital expenditures. Inestimating cash flows, management incorporates current market information, as well as historical and other factors into the forecasted commodity prices andcontracted rates used.
As a result of our step one analysis in the fourth quarter of 2015, we determined that the estimated fair value of certain reporting units within our Gas Gatheringand Processing Services, Liquid Pipelines and Services and Propane Marketing Services reportable segments were less than their respective carrying amounts,primarily due to changes in assumptions related to commodity prices, the timing of estimated drilling by producers, and discount rates. These assumptions wereadversely impacted by the continuing decline in market conditions within the energy sector at the time.
The second step of the goodwill impairment test involved allocating the estimated fair value of each reporting unit among the assets and liabilities of the reportingunit in a hypothetical purchase price allocation. The results of the hypothetical purchase price allocation indicated there was no fair value attributable to goodwillof the reporting units within our Gas Gathering and Processing Services reportable segment and we recognized an impairment charge of $118.6 million whichconsisted of $95.0 million and $23.6 million related to the Costar and Lavaca acquisitions, respectively. In addition, we recognized a $23.6 million impairmentcharge in our Liquid Pipelines and Services reportable segment relating to our Crude Oil Supply and Logistics business, and a $6.3 million impairment charge inour Propane Marketing Services reportable segment related to JP Liquids. As a result, we recognized total goodwill impairment charges of $148.5 million duringthe year ended December 31, 2015. In 2016, we recognized additional goodwill impairment charges totaling $15.5 million in our Propane Marketing Servicesreportable segment, which consisted of $12.8 million and $2.7 million related to our Pinnacle Propane Express and JP Liquids businesses, respectively. Given themarket condition trend surrounding Pinnacle Propane Express and JP Liquids, we may recognize further impairments related to those assets in the future.
The following table presents activity in the Partnership's goodwill balance:
Gas Gathering andProcessing Services
Liquid Pipelinesand Services
TerminallingServices
Propane MarketingServices Total
(in thousands)Balance at January 1, 2015 $ 125,974 $ 137,243 $ 88,466 $ 31,335 $ 383,018Goodwill acquired during the year — — — 5,806 5,806Return of purchase price (7,382) — — — (7,382)Impairment charges (118,592) (23,574) — (6,322) (148,488)Balance at December 31, 2015 — 113,669 88,466 30,819 232,954Impairment charges — — (15,456) (15,456)Balance at December 31, 2016 $ — $ 113,669 $ 88,466 $ 15,363 $ 217,498
Intangible assets, net, consists of customer relationships, customer contracts, dedicated acreage agreements, and collaborative arrangements as acquired inconnection with business combinations. These intangible assets have definite lives and are subject to amortization on a straight-line basis over their economic lives,currently ranging from approximately 5 years to 30 years. Intangible assets, net, consist of the following:
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December 31,
2016 2015 (in thousands)Gross carrying amount: Customer relationships $ 133,503 $ 136,030Customer contracts 95,594 95,594Dedicated acreage 53,350 53,350Collaborative arrangements 11,884 11,884Noncompete agreements 3,423 3,575Other 751 751
$ 298,505 $ 301,184Accumulated amortization: Customer relationships $ (31,471) $ (23,885)Customer contracts (33,414) (24,538)Dedicated acreage (4,439) (2,661)Collaborative arrangements (601) —Noncompete agreements (3,086) (2,664)Other (211) (155)
$ (73,222) $ (53,903)Net carrying amount: Customer relationships $ 102,032 $ 112,145Customer contracts 62,180 71,056Dedicated acreage 48,911 50,689Collaborative arrangements 11,283 11,884Noncompete agreements 337 911Other 540 596
$ 225,283 $ 247,281
In connection with the sale of the Mid-Continent Business we recorded an impairment charge of $0.7 million related to customer relationships during the yearended December 31, 2015, which is included in net loss from discontinued operations, net of tax in the consolidated statement of operations. In addition, as a resultof the sale of the Bakken Business, we wrote-off $8.1 million in customer contracts during the year ended December 31, 2014.
For the years ended December 31, 2016 , 2015 and 2014 , amortization expense on our intangible assets totaled $22.0 million , $22.8 million and $20.8 million ,respectively, which is included depreciation, amortization and accretion in the consolidated statements of operations. Amortization expense of $0.1 million , $1.2million and $2.0 million for the years ended December 31 2016, 2015 and 2014, respectively, relating to the Mid-Continent Business and Bakken Business isincluded in the net loss from discontinued operations, net of tax, in the consolidated statement of operations.
Estimated amortization expense for each of the next five years ranges from $14.3 million to $19.9 million , with an aggregate $138.1 million to be recognized insubsequent years.
The storage tank capacity in our crude oil storage facility in Cushing, Oklahoma is dedicated to one customer pursuant to a long-term contract with an initialexpiration date of August 3, 2017 and an optional two year renewal term. We did not receive a notice of the customer's intent to renew this contract by the requireddate of February 3, 2017. While we continue to be in discussions with the customer and other parties about renting the storage capacity, we began to accelerate theremaining amortization of the related customer relationship intangible of $10.0 million over the remaining term of the original agreement.
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10. Investment in Unconsolidated Affiliates
The following table presents activity in the Partnership's investments in unconsolidated affiliates:
Delta House (1) Emerald Transactions FPS OGL Destin Tri-States Okeanos Wilprise MPOG Total
(in thousands) Ownership % at December 31, 2016 20.1% 20.1% 49.7% 16.7% 66.7% 25.3% 66.7% Balance at December 31, 2013 $ — $ — $ — $ — $ — $ — $ — $ —
Investments — — — — — — 12,000 12,000
Earnings in unconsolidated affiliates — — — — — — 348 348
Contributions — — — — — — — —
Distributions — — — — — — (1,980) (1,980)Balance at December 31, 2014 — — — — — — 10,368 10,368
Investments 40,559 25,144 — — — — — 65,703
Earnings in unconsolidated affiliates 5,457 2,013 — — — — 731 8,201
Contributions — — — — — — — —
Distributions (12,551) (4,097) — — — — (3,920) (20,568)Balance at December 31, 2015 33,465 23,060 — — — — 7,179 63,704
Investments 55,461 3,255 122,830 56,681 27,451 5,064 — 270,742
Earnings in unconsolidated affiliates 21,022 9,260 3,946 1,633 3,642 437 218 40,158
Contributions — — — — — — 429 429
Distributions (45,465) (10,125) (15,894) (3,292) (4,034) (557) (3,679) (83,046)Balance at December 31, 2016 $ 64,483 $ 25,450 $ 110,882 $ 55,022 $ 27,059 $ 4,944 $ 4,147 $ 291,987
(1) Represents direct and indirect ownership interests in Class A Units.
The following tables include summarized data for the entities underlying our equity method investments:
December 31,
2016 2015 (in thousands)Current assets $ 120,167 $ 182,264Non-current assets 1,369,492 1,418,299Current liabilities 133,085 146,490Non-current liabilities 541,312 419,215
Years ended December 31,
2016 2015 2014 (in thousands)Revenue $ 370,263 $ 235,041 $ 102,290Operating expenses 99,084 90,453 72,775Net income 261,200 135,083 28,173
Our investments in the unconsolidated affiliates underlying the Emerald Transactions were acquired in late April 2016. The following table presents informationfor each of these affiliates for the portion of 2016 that we held the related investments:
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Emerald Transactions
Destin Tri-States Okeanos Wilprise
Revenues $ 34,360 $ 25,557 $ 10,453 $ 3,306
Net income 8,272 15,983 1,911 2,028
Partnership ownership % 49.7% 16.7% 66.7% 25.3%
Partnership share of investee net income 4,109 2,664 1,274 513
Basis difference amortization (163) (1,031) 2,368 (76)
Earnings in unconsolidated affiliates 3,946 1,633 3,642 437
The unconsolidated affiliates were determined to be variable interest entities due to disproportionate economic interests and decision making rights. In each case,the Partnership lacks the power to direct the activities that most significantly impact the unconsolidated affiliate's economic performance. As the Partnership doesnot hold a controlling financial interest in these affiliates, the Partnership accounts for its related investments using the equity method. Additionally, thePartnership’s maximum exposure to loss related to each entity is limited to its equity investment as presented on the consolidated balance sheets, as it is notobligated to absorb losses greater than its proportional ownership percentages indicated above. The Partnership’s right to receive residual returns is not limited toany amount less than the ownership percentages indicated above.
11. Accrued Expenses and Other Current Liabilities
Accrued expenses and other current liabilities consists of the following (in thousands):
December 31,
2016 2015Capital expenditures $ 14,499 $ 7,780Employee compensation 10,804 7,870Convertible preferred unit distributions 7,103 —Current portion of asset retirement obligation 6,499 6,822Accrued interest 5,743 1,838Additional Blackwater acquisition consideration 5,000 —Due to related parties 4,072 3,894Royalties payable 3,926 4,163Transaction costs 3,000 —Customer deposits 3,080 3,742Deferred financing costs 2,743 —Taxes payable 1,688 1,563Recoverable gas costs 1,126 1,337Gas imbalances payable 1,098 413Other 10,903 7,329 Total accrued expenses and other current liabilities $ 81,284 $ 46,751
12. Asset Retirement Obligations
The following table presents activity in the Partnership's asset retirement obligations (in thousands):
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Years Ended December 31,
2016 2015
Beginning balance $ 35,371 $ 34,645Liabilities assumed (1) 14,542 —Revision in estimate 230 —Expenditures (858) (91)Accretion expense 1,577 817Ending balance 50,862 35,371Less: current portion 6,499 6,822
Noncurrent asset retirement obligation $ 44,363 $ 28,549
(1) Includes $14.3 million assumed in connection with the Gulf of Mexico Pipeline acquisition described in Note 2.
We are required to establish security against potential obligations relating to the abandonment of certain transmission assets that may be imposed on the previousowner by applicable regulatory authorities. We have deposited $5.0 million with a third party to secure our performance on these potential obligations. Thesedeposits are included in Restrictedcashin our consolidated balance sheets as of December 31, 2016 and 2015 .
13. Debt Obligations
Our outstanding debt consists of the following as of December 31, 2016:
AMID JPE 8.5% Senior 3.77% Senior Revolving Credit Revolving Credit Notes due Notes due Other Agreement (1) Agreement (1) 2021 2031 Debt Total
(in thousands)Balance $ 711,250 $ 177,000 $ 300,000 $ 60,000 $ 3,809 $ 1,252,059Less unamortized deferred financingcosts and discount — — (8,691) (2,345) — (11,036)
Subtotal 711,250 177,000 291,309 57,655 3,809 1,241,023
Less current portion — — — (1,676) (3,809) (5,485)
Non-current portion $ 711,250 $ 177,000 $ 291,309 $ 55,979 $ — $ 1,235,538
Our outstanding debt consists of the following as of December 31, 2015:
AMID JPE Revolving Credit Revolving Credit Other Agreement (1) Agreement (1) Debt Total
(in thousands)Balance $ 525,100 $ 162,000 $ 3,639 $ 690,739
Less current portion — — (2,899) (2,899)
Non-current portion $ 525,100 $ 162,000 $ 740 $ 687,840
______________________(1) Unamortized deferred financing costs related to the Credit Agreement are included in Otherassets,net.
AMID Credit Agreement
Effective as of April 25, 2016, the Partnership entered into the Second Amendment to the Amended and Restated Credit Agreement (as amended, the "CreditAgreement"), which provides for maximum borrowings up to $750.0 million , with the ability to further increase the borrowing capacity to $900.0 million subjectto lender approval. We can elect to have loans under our Credit Agreement bear interest either at a Eurodollar-based rate, plus a margin ranging from 2.00% to3.25% depending on our total leverage ratio
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then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (i) the Federal Funds Rate plus 0.50% , (ii) the rate of interest in effect forsuch day as publicly announced from time to time by Bank of America as its "prime rate," or (iii) the Eurodollar Rate plus 1.00% plus a margin ranging from1.00% to 2.25% depending on the total leverage ratio then in effect. We also pay a commitment fee of 0.50% per annum on the undrawn portion of the revolvingloan under the Credit Agreement.
Our obligations under the Credit Agreement are secured by a lien on substantially all of our assets. Advances made under the Credit Agreement are guaranteed ona senior unsecured basis by certain of our subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors.The terms of the Credit Agreement include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remainingprincipal balance and any accrued and unpaid interest will be due and payable in full at maturity, on September 5, 2019.
On September 30, 2016, in connection with the 3.77% Senior Note Purchase Agreement described, the Partnership entered into the Limited Waiver and ThirdAmendment to the Credit Agreement, which among other things, (i) allows Midla Holdings (as defined below), for so long as the 3.77% Senior Notes areoutstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain convents thereunder, (ii) releases the liengranted under the original credit agreement on D-Day’s equity interests in Delta House FPS, LLC, and (iii) deems the equity interests in Delta House FPS, LLC tobe excluded property under the Credit Agreement. All other terms under the Credit Agreement remain the same.
On November 18, 2016, the Partnership entered into the Fourth Amendment to the Amended and Restated Credit Agreement. The Fourth Amendment (i) modifiescertain investment covenants to reflect the recently completed incremental acquisition of additional interests in Delta House Class A Units (ii) permits JPE’sexisting credit facility (the “JPE Credit Facility”) to remain in place during the time period between (a) the consummation of the JPE Merger and (b) the payoff ofthe JPE Credit Facility, (iii) permits the joining of JPE and its subsidiaries as guarantors under the Credit Agreement, and (iv) permits the integration of JPE and itssubsidiaries into the Partnership’s ownership structure.
The Credit Agreement contains certain financial covenants, including a consolidated total leverage ratio which requires our indebtedness not to exceed 4.75 timesadjusted consolidated EBITDA for the prior twelve month period adjusted in accordance with the Credit Agreement (except for the current and subsequent twoquarters after the consummation of a permitted acquisition, at which time the covenant is increased to 5.25 times adjusted consolidated EBITDA) and a minimuminterest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than 2.50 times. The financial covenantsin our Credit Agreement may limit the amount available to us for borrowing to less than $750.0 million . In addition to the financial covenants described above, theCredit Agreement also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws,absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, crossdefaults and bankruptcy events).
For the years ended December 31, 2016 , 2015 and 2014 , the weighted average interest rate on borrowings under our Credit Agreement was approximately 4.29%, 3.67% , and 3.80% , respectively.
As of December 31, 2016 , our consolidated total leverage ratio was 4.07 and our interest coverage ratio was 7.43 , which were both in compliance with the relatedrequirements of our Credit Agreement. At December 31, 2016 and 2015 , letters of credit outstanding under the Credit Agreement were $7.4 million and $1.8million , respectively. As of December 31, 2016, we had approximately $711.3 million of borrowings and $7.4 million of letters of credit outstanding under theCredit Agreement resulting in $ 31.3 million of available borrowing capacity.
As of December 31, 2016 , we were in compliance with the covenants included in the Credit Agreement. Our ability to maintain compliance with the leverage andinterest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which mayinclude expansion capital projects, acquisitions, or drop down transactions, as well as the associated financing for such initiatives.
The carrying value of amounts outstanding under the Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions.On March 8, 2017, the Partnership entered into the Second Amended and Restated Credit Agreement, which increased our borrowing capacity from $750.0 millionto $900.0 million and provided for an accordion feature that will permit, subject to the customary conditions, the borrowing capacity under the facility to beincreased to a maximum of $1.1 billion .
JPE Credit Agreement
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On February 12, 2014, we entered into the JPE Credit Agreement with Bank of America, N.A, which was available for refinancing and repayment of certainexisting indebtedness, working capital, capital expenditures, permitted acquisitions and other general partnership purposes. The JPE Credit Agreement consisted ofa $275.0 million revolving loan, which included a sub-limit of up to $100.0 million for letters of credit. The JPE Credit Agreement was scheduled to mature onFebruary 12, 2019, but was paid off and terminated on March 8, 2017 in connection with the Partnership's acquisition of JPE.
Borrowings under the JPE Credit Agreement bore interest at a rate per annum equal to, at out option, either (a) a base rate determined by reference to the highest of(1) the federal funds effective rate plus 0.5% , (2) the prime rate of Bank of America, and (3) LIBOR, subject to certain adjustments, plus 1.00% or (b) LIBOR, ineach case plus an applicable rate. The applicable rate was (a) 1.25% for prime rate borrowing and 2.25% for LIBOR borrowings. The commitment fee was subjectto an adjustment each quarter based in the Consolidated Net Total Leverage Ratio, as defined in the related agreement. The carrying value of amounts outstandingunder the JPE Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions.
8.50% Senior Notes
On December 28, 2016, the Partnership and American Midstream Finance Corporation, our wholly-owned subsidiary (the “Co-Issuer” and together with thePartnership, the “Issuers”), completed the issuance and sale of the 8.50% Senior Notes. The 8.50% Senior Notes are jointly and severally guaranteed by thePartnership’s existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of the Partnership’s future subsidiaries (the“Guarantors”). The 8.50% Senior Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right ofpayment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million inproceeds, after deducting the initial purchasers' discount of $6.0 million . This amount was deposited into escrow pending completion of the JPE Merger and isincluded in Restricted cashon our consolidated balance sheets as of December 31, 2016 . The Partnership also incurred $2.7 million of direct issuance costsresulting in net proceeds related to the 8.50% Senior Notes of $291.3 million .
Upon the closing of the JPE Merger and the satisfaction of other conditions related thereto, the restricted cash was released from escrow and was used to repay theJPE Credit Facility and to reduce borrowings under the Partnership’s Credit Agreement. The 8.50% Senior Notes will mature on December 15, 2021 with interest payable in arrears on June 15 and December 15, commencing June 15, 2017.
At any time prior to December 15, 2018, the Issuers may redeem up to 35% of the aggregate principal amount of 8.50% Senior Notes, at a redemption price of108.50% of the principal amount, plus accrued and unpaid interest to the redemption date, in an amount not greater than the net cash proceeds of one or moreequity offerings by the Partnership, provided that:
• at least 65% of the aggregate principal amount of the 8.50% Senior Notes remains outstanding immediately after such redemption (excluding 8.50%Senior Notes held by the Partnership and its subsidiaries); and
• the redemption occurs within 180 days of the closing of each such equity offering.
Prior to December 15, 2018, the Issuers may redeem all or part of the 8.50% Senior Notes, at a redemption price equal to the sum of:
• the principal amount thereof, plus
• the make whole premium (as defined in the Indenture) at the redemption date, plus
• accrued and unpaid interest, to the redemption date.
On and after December 15, 2018, the Issuers may redeem all or a part of the 8.50% Senior Notes, at the redemption prices (expressed as percentages of principalamount) set forth below, plus accrued and unpaid interest, if redeemed during the twelve-month period beginning on December 15 of the years indicated below:
Year Percentage2018 104.250%2019 102.125%2020 and thereafter 100.000%
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The Indenture restricts the Partnership’s ability and the ability of certain of its subsidiaries to, among other things: (i) incur, assume or guarantee additionalindebtedness, issue any disqualified stock or issue preferred units, (ii) create liens to secure indebtedness, (iii) pay distributions on equity securities, redeem orrepurchase equity securities or redeem or repurchase subordinated securities, (iv) make investments, (v) restrict distributions, loans or other asset transfers fromrestricted subsidiaries, (vi) consolidate with or merge with or into, or sell substantially all of its properties to, another person, (vii) sell or otherwise dispose ofassets, including equity interests in subsidiaries, (viii) enter into transactions with affiliates, (ix) engage in certain business activities and (x) enter into sale andleaseback transactions. These covenants are subject to a number of important exceptions and qualifications. If at any time the 8.50% Senior Notes are ratedinvestment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default or Event of Default (as each are defined in theIndenture) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to suchcovenants.The carrying value of the 8.50% Senior Notes as of December 31, 2016 approximates the related fair value as of that date as the Senior Notes were issued onDecember 28, 2016.
3.77% Senior Notes
On September 30, 2016, Midla Financing, LLC ("Midla Financing"), American Midstream (Midla), LLC (“Midla”), and Mid Louisiana Gas Transmission LLC("MLGT" and together with Midla, the "Note Guarantors") entered into a Note Purchase and Guaranty Agreement with certain institutional investors (the“Purchasers”) whereby Midla Financing issued $60.0 million in aggregate principal amount of 3.77% Senior Notes due June 30, 2031. Principal and interest on the3.77% Senior Notes is payable in installments on the last business day of each quarter beginning June 30, 2017 with the remaining balance payable in full on June30, 2031. The average quarterly principal payment is approximately $1.1 million . The 3.77% Senior Notes were issued at par and provided net proceeds ofapproximately $57.7 million after deducting related issuance costs of $2.3 million .
Net proceeds from the 3.77% Senior Notes are restricted and will be used to fund project costs incurred in connection with the construction of the Midla-NatchezLine, the retirement of Midla’s existing 1920’s pipeline, the move of our Baton Rouge operations to the MLGT system, and the reconfiguration of the DeSiardcompression system and all related ancillary facilities. These proceeds can also be used to pay costs incurred in connection with the issuance of the 3.77% SeniorNotes, and for general corporate purposes of Midla Financing. As of December 31, 2016 , Restrictedcashincludes $24.5 million from the issuance of the 3.77%Senior Notes.
The Note Purchase Agreement includes customary representations and warranties, affirmative and negative covenants (including financial covenants), and eventsof default that are customary for a transaction of this type. Midla Financing must maintain a debt service reserve account containing six months of principal andinterest payments, and Midla Financing and the Note Guarantors (including any entities that become guarantors under the terms of the 3.77% Senior Note PurchaseAgreement) are restricted from making distributions until June 30, 2017, unless the debt service coverage ratio is not less than, and is not projected to be for thefollowing 12 calendar months less than, 1.20 :1.00, and unless certain other requirements are met.
In connection with the 3.77% Senior Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s related obligations.Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal assets, including themembership interests in each Note Guarantor held by Midla Financing, and Midla Holdings pledged the membership interests in Midla Financing to the CollateralAgent.
As of December 31, 2016 , the fair value of the 3.77% Senior Notes was $54.6 million . This estimate was based on similar private placement transactions alongwith changes in market interest rates which represent a Level 2 measurement.
14. Convertible Preferred Units
Our convertible preferred units consist of the following:
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Series A Series C Series D Units $ Units $ Units $ (in thousands)December 31, 2013 5,279 $ 94,811 — $ — — $ —Issuance of units — — — — — —Paid in kind unit distributions 466 13,154 — — — —
December 31, 2014 5,745 107,965 — — — —Issuance of units 2,571 44,769 — — — —Paid in kind unit distributions 894 16,978 — — — —
December 31, 2015 9,210 169,712 — — — —Issuance of units — — 8,571 115,457 2,333 34,475Paid in kind unit distributions 897 11,674 221 2,772 — —
December 31, 2016 10,107 $ 181,386 8,792 $ 118,229 2,333 $ 34,475
Affiliates of our General Partner hold and participate in quarterly distributions on our convertible preferred units, with such distributions being made in cash, paid-in-kind units or a combination thereof, at the election of the Board of Directors of our General Partner, although quarterly distribution on our Series D Units willonly be paid in cash. The convertible preferred unitholders have the right to receive cumulative distributions in the same priority and prior to any otherdistributions made in respect of any other partnership interests.
To the extent that any portion of a quarterly distribution on our convertible preferred units to be paid in cash exceeds the amount of cash available for suchdistribution, the amount of cash available will be paid to our convertible preferred unitholders on a pro rata basis while the difference between the distribution andthe available cash will become arrearages and accrue interest until paid.
Series A-1 Convertible Preferred Units
On April 15, 2013, the Partnership, our General Partner and AIM Midstream Holdings entered into agreements with HPIP, pursuant to which HPIP acquired 90%of our General Partner and all of our subordinated units from AIM Midstream Holdings and contributed the High Point System and $15.0 million in cash to us inexchange for 5,142,857 of our Series A-1 Units.The Series A-1 Units receive distributions prior to distributions to our common unitholders. The distributions on the Series A-1 Units are equal to the greater of$0.50 per unit or the declared distribution to common unitholders. The Series A-1 Units may be converted into common units on a one -to-one basis, subject tocustomary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014. As of December 31, 2016, the conversion price is $15.87.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of its assets, the holders of Series A-1 Units will generally be entitled toreceive, in preference to the holders of any of the Partnership's other equity securities, but in parity with all convertible preferred units, an amount equal to the sumof $15.87 multiplied by the number of Series A-1 Units owned by such holders, plus all accrued but unpaid distributions on such Series A Units.
Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of commonunits are to receive securities, cash or other assets (a "Partnership Event"), we are obligated to make an irrevocable written offer, subject to consummation of thePartnership Event, to each holder of Series A Units to redeem all (but not less than all) of such holder's Series A-1 Units for a per unit price payable in cash asdescribed in the Partnership Agreement.
Upon receipt of such a redemption offer from us, each holder of Series A-1 Units may elect to receive such cash amount or a preferred security issued by theperson surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the PartnershipAgreement with respect to the Series A-1 Units without material abridgement.
Except as provided in the Partnership Agreement, the Series A-1 Units have voting rights that are identical to the voting rights of the common units and will votewith the common units as a single class, with each Series A-1 Unit entitled to one vote for each common unit into which such Series A-1 Unit is convertible.
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As conversion is at the option of the holder and redemption is contingent upon a future event which is outside the control of the Partnership, the Series A-1 Unitshave been classified as mezzanine equity in the consolidated balance sheets.
Under the Partnership Agreement, distributions on Series A-1 Units were made with paid-in-kind Series A-1 Units, cash or a combination thereof, at the discretionof the Board of Directors, through the distribution for the quarter ended March 31, 2016. The Partnership was previously required to pay distributions on the SeriesA-1 Units with a combination of paid-in-kind units and cash. The sale of the Series A-1 Units was exempt from registration under Securities Act pursuant to Rule4(a)(2) under the Securities Act.
Series A-2 Convertible Preferred Units
On March 30, 2015 and June 30, 2015, we entered into two Series A-2 Convertible Preferred Unit Purchase Agreements with Magnolia Infrastructure Partners("Magnolia") an affiliate of HPIP pursuant to which the Partnership issued, in separate private placements, newly-designated Series A-2 Units (the “Series A-2Units”) representing limited partnership interests in the Partnership. As a result, the Partnership issued a total of 2,571,430 Series A-2 Units for approximately$45.0 million in aggregate proceeds during the year ended December 31, 2015. The Series A-2 Units will participate in distributions of the Partnership along withcommon units in a manner identical to the existing Series A-1 Units (together with the Series A-2 Units, the "Series A Units"), with such distributions being madein cash or with paid-in-kind Series A Units at the election of the Board of Directors of our General Partner.
On July 27, 2015, we amended our Partnership Agreement to grant us the right (the “Call Right”) to require the holders of the Series A-2 Units to sell, assign andtransfer all or a portion of the then outstanding Series A-2 Units to us for a purchase price of $17.50 per Series A-2 Unit (subject to appropriate adjustment for anyequity distribution, subdivision or combination of equity interests in the Partnership). We may exercise the Call Right at any time, in connection with our or ouraffiliate’s acquisition of assets or equity from ArcLight Energy Partners Fund V, L.P., or one of its affiliates, for a purchase price in excess of $100 million . Wemay not exercise the Call Right with respect to any Series A-2 Units that a holder has elected to convert into common units on or prior to the date we haveprovided notice of our intent to exercise the Call Right, and we may also not exercise the Call Right if doing so would result in a default under any of our or ouraffiliates’ financing agreements or obligations. As of December 31, 2016, the conversion price is $15.87 . The sale of the Series A-2 Units was exempt fromregistration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.
Series C Convertible Preferred Units
On April 25, 2016, the Partnership issued 8,571,429 of its Series C Units to an ArcLight affiliate in connection with the Emerald Transactions described in Note 2.
The Series C Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class on an asconverted basis, with each Series C Unit initially entitled to one vote for each common unit into which such Series C Unit is convertible. The Series C Units alsohave separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of therights, preferences, privileges or terms of the Series C Units. The Series C Units are convertible in whole or in part into common units at any time. The number ofcommon units into which a Series C Unit is convertible will be an amount equal to the sum of $14.00 plus all accrued and accumulated but unpaid distributions,divided by the conversion price. The sale of the Series C Units was exempt from registration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.
In the event that the Partnership issues, sells or grants any common units or convertible securities at an indicative per common unit price that is less than $14.00per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase inthe number of common units into which Series C Units are convertible. As of December 31, 2016, the conversion price is $13.95 .
Prior to consummating any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common unitsare to receive securities, cash or other assets, we are obligated to make an irrevocable written offer, subject to consummating the Partnership Event, to the holdersof Series C Units to redeem all (but not less than all) of the Series C Units for a price per Series C Unit payable in cash as described in the Partnership Agreement.
Upon receipt of a redemption offer, each holder of Series C Preferred Units may elect to receive the cash amount or a preferred security issued by the personsurviving or resulting from the Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Fifth Amended and RestatedPartnership Agreement with respect to the Series C Preferred Units without material abridgement.
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Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series C Units generally willbe entitled to receive, in preference to the holders of any of the Partnership's other equity securities but in parity with all convertible preferred units, an amountequal to the sum of the $14.00 multiplied by the number of Series C Units owned by such holders, plus all accrued but unpaid distributions.
At any time prior to April 25, 2017, the Partnership has the right (the “Series C Call Right”) to require the holders of the Series C Units to sell, assign and transferall or a portion of the then outstanding Series C Units for a purchase price of $14.00 per Series C Unit (subject to customary anti-dilution adjustments), plus allaccrued but unpaid distributions on each Series C Unit.
The Partnership may not exercise the Series C Call Right if the holder has elected to convert it into common units on or prior to the date the Partnership hasprovided notice of its intent to exercise its Series C Call Right, and may not exercise the Series C Call Right if doing so would violate applicable law or result in adefault under any financing agreement or obligation of the Partnership or its affiliates.
In connection with the issuance of the Series C Units, the Partnership issued the holders a warrant to purchase up to 800,000 common units at an exercise price of$7.25 per common unit (the "Series C Warrant"). The Series C Warrant is subject to standard anti-dilution adjustments and is exercisable for a period of sevenyears.
On April 25, 2017, the number of common units that may be purchased pursuant to the exercise of the Series C Warrant will be adjusted by an amount, rounded tothe nearest whole common unit, equal to the product obtained by the following calculation: (i) 400,000 multiplied by (ii) (A) the Series C Issue Price multiplied bythe number of Series C Units then outstanding less $45.0 million divided by (B) the Series C Issue Price multiplied by the number of Series C Units issued, less$45.0 million .
Any Series C Units issued in-kind as a distribution to holders of Series C Units (“Series C PIK Units”) will increase the number of common units that can bepurchased upon exercise of the Series C Warrant by an amount, rounded to the nearest whole common unit, equal to the product obtained by the followingcalculation: (i) the total number of common units into which each Series C Warrant may be exercised immediately prior to the most recent issuance of the Series CPIK Units multiplied by (ii) (A) the total number of outstanding Series C Units immediately after the most recent issuance of Series C PIK Units divided by (B) thetotal number of outstanding Series C Units immediately prior to the most recent issuance of Series C PIK Units.
The fair value of the Series C Warrant was determined using a market approach that utilized significant inputs which are not observable in the market and thusrepresent a Level 3 measurement as defined by ASC 820. The estimated fair value of $4.41 per warrant unit was determined using a Black-Scholes model and thefollowing significant assumptions: i) a dividend yield of 18% , ii) common unit volatility of 42% and iii) the seven -year term of the warrant to arrive at anaggregate fair value of $4.5 million .
Series D Convertible Preferred Units
On October 31, 2016, Partnership issued 2,333,333 shares of its newly-designated Series D Units to an ArcLight affiliate at a price of $15.00 per unit, less a 1.5%closing fee, in connection with the Delta House transaction described in Note 2. The related agreement provides that if any of the Series D Units remainoutstanding on June 30, 2017, the Partnership will issue the holder of the Series D Units a warrant (the “Series D Warrant”) to purchase 700,000 common unitsrepresenting limited partnership interests with an exercise price of $22.00 per common unit. The fair value of the conditional Series D Warrant at the time ofissuance was immaterial.
The Series D Units are entitled to quarterly distributions payable in arrears equal to the greater of $0.4125 and the cash distribution that the Series D Units wouldhave received if they had been converted to common units immediately prior to the beginning of the quarter. The Series D Units also have separate class votingrights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences,privileges or terms of the Series D Units. The Series D Units are convertible in whole or in part into common units at the election of the holder of the Series D Unitat any time after June 30, 2017. As of the date of issuance, the conversion rate for each Series D Unit was one -to-one (the “Conversion Rate”). As of December31, 2016, the conversion price is $14.98 .
In the event that the Partnership issues, sells or grants any common units or securities convertible into common units at an indicative per common unit price that isless than $15.00 per unit (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide for anincrease in the number of common units into which Series D Units are convertible.
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Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of CommonUnits are to receive securities, cash or other assets (a “Partnership Event”), the Partnership is obligated to make an irrevocable written offer, subject toconsummation of the Partnership Event, to the holders of Series D Units to redeem all (but not less than all) of the Series D Units for a price per Series D Unitpayable in cash as described in the Partnership Agreement. The sale of the Series D Units was exempt from registration under Securities Act pursuant to Rule 4(a)(2) under the Securities Act.
Upon receipt of a redemption offer, each holder of Series D Units may elect to receive the cash amount or a preferred security issued by the person surviving orresulting from the Partnership Event.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series D Units generally willbe entitled to receive, in preference to the holders of any of the Partnership's other equity securities but in parity with all convertible preferred units, an amountequal to the sum of the $15.00 multiplied by the number of Series D Units owned by such holders, plus all accrued but unpaid distributions.
At any time prior to June 30, 2017, the Partnership has the right (the “Series D Call Right”) to redeem the Series D Units for the product of (i) the sum of $15.00and all accrued and accumulated but unpaid distributions for each Series D Unit (including a proportionate amount of the distribution on each Series D Unit thathas accrued for the quarter in which the redemption occurs); and (ii) 1.03 .
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15. Partners' Capital
American Midstream Outstanding Units
The following table presents unit activity (in thousands):
General
Partner Interest Limited Partner Interest Series B Convertible Units JPE Series D
Units
Balances at December 31, 2013 185 13,394 — —Initial issuance of Series B Units — — 1,168 Issuance of Series B Units — — 87 Issuance of JPE Series D Units — — — 1,008Redemption of JPE Series D Units — — — (1,008)LTIP vesting — 80 — Issuance of GP units 207 — — Exercise of warrants — 300 — Issuance of common units in JPDevelopment transaction — 5,841 — Issuance of common units — 23,025 — Balances at December 31, 2014 392 42,640 1,255 —Issuance of Series B Units — — 95 —LTIP vesting — 58 — —Exercise of unit options — 152 — —Issuance of GP units 144 — — —Issuance of common units — 7,654 — —Balances at December 31, 2015 536 50,504 1,350 —Conversion of Series B Units — 1,350 (1,350) —Return of escrow units — (1,034) — —LTIP vesting — 283 — —Issuance of GP units 144 — — —Issuance of common units — 248 — —
Balances at December 31, 2016 680 51,351 — —
Our capital accounts are comprised of approximately 1.3% notional General Partner interest and 98.7% limited partner interests as of December 31, 2016 . Ourlimited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to participate in our distributions. Our GeneralPartner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that arenon-voting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributionsbased on its interest. The General Partner's participation in the allocation of losses and distributions is not limited and therefore, such participation can result in adeficit to its respective capital account. As such, allocation of losses and distributions for previous transactions between entities under common control haveresulted in a deficit to the General Partner's capital account included in our consolidated balance sheets.
Series B Convertible Preferred Units
Effective January 31, 2014, the Partnership issued 1,168,225 Series B Units to its General Partner in exchange for approximately $30.0 million to fund a portion ofthe Lavaca acquisition described in Note 2. The Series B Units participated in distributions of the Board of Directors of our General Partner along with commonunits, with such distributions being made in cash distributions or with paid-in-kind Series B Units at the election of the Partnership. The Series B Units were issuedin a private placement in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof and thesafe harbor provided by Rule 506 of Regulation D promulgated thereunder. On February 1, 2016, all outstanding Series B Units were converted on a one -for-onebasis into common units.
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The Board of Directors of our General Partner elected to pay the Series B distributions using paid-in-kind Series B Units. For the years ended December 31, 2015and 2014 , the Partnership issued 94,923 and 86,461 , respectively, of paid-in-kind Series B Units with a fair value of $1.4 million and $2.2 million , respectively.
Equity Offerings
In October 2015, the Partnership and certain of its affiliates entered into an agreement with a group of investment banks under which it may issue up to $100.0million of its common units in at the market (“ATM”) offerings. During 2016, the Partnership issued 248,561 common units under this program resulting in netproceeds of $2.9 million after deducting related offering costs of $0.3 million . The net proceeds were used to repay amounts outstanding under the CreditAgreement. At December 31, 2016, $96.8 million remained available under the ATM program.
In September 2015, the Partnership sold 7,500,000 of its common units in a public offering at a price to the public of $11.31 per common unit. The net proceedsof approximately $81.0 million were used to fund a portion of the Delta House investment described in Note 2. In October 2016, the Partnership issued anadditional 151,937 common units at a price of $11.31 per unit pursuant to the partial exercise of the underwriters' overallotment option, resulting in net proceeds ofapproximately $1.7 million .
In October 2014, the Partnership acquired Costar from Energy Spectrum Partners VI LP and Costar Midstream Energy, LLC which was funded, in part, with6,892,931 of common units with an estimated fair value of $147.3 million issued directly to Energy Spectrum and Costar Midstream Energy LLC. In February2016, the Partnership reached a settlement of certain indemnification claims with the Costar sellers whereby approximately 1,034,483 common units held inescrow were returned to the Partnership.
On October 7, 2014, JPE issued 7,940,625 common units at a price of $34.63 per unit in its initial public offering ("IPO") resulting in net proceeds of $252.7million . Immediately prior to the IPO, JPE was recapitalized and common units were issued for each previously outstanding class of equity, resulting in11,848,735 outstanding common units immediately prior to the IPO.
On August 15, 2014, the Partnership sold 4,622,352 of its common units representing limited partner interests to institutional investors at a price of $25.8075 percommon unit resulting in net proceeds of $119.3 million .
On February 12, 2014, we issued 190,000 Class A Common Units to an affiliate for net proceeds of $8.0 million .
On March 28, 2014, we issued 1,008,000 Series D Preferred Units to an affiliate resulting in net proceeds of $40.0 million . On October 7, 2014, we redeemed allof the outstanding Series D Preferred Units for $42.4 million .
In January 2014, the Partnership sold 3,400,000 of its common units in a public offering at a price of $26.75 per common unit. The Partnership used the netproceeds of $86.9 million to fund a portion of the Lavaca acquisition described in Note 2.
General Partner Units
In order to maintain its ownership percentage, we received proceeds of $2.0 million from our General Partner as consideration for the issuance of 143,900additional notional general partner units for the year ended December 31, 2016 , proceeds of $1.9 million for the issuance of 143,517 additional notional generalpartner units for the year ended December 31, 2015 and proceeds of $5.7 million for the issuance of 206,810 additional notional general partner units for the yearended December 31, 2014.
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Distributions
We made the following distributions (in thousands):
Years Ended December 31,
2016 2015 2014
Series A Units Cash:
Paid $ 4,935 $ — $ 2,658
Accrued 2,514 — —
Paid-in-kind units 11,674 16,978 13,154
Total 19,123 16,978 15,812
Series B Units Paid-in-kind units — 1,373 2,220
Total — 1,373 2,220
Series C Units Cash:
Paid 3,089 — —
Accrued 3,626 — —
Paid-in-kind units 2,772 — —
Total 9,487 — —
Series D Units
AMID Series D Units Accrued 963 — —
JPE Series D Units Paid-in-kind units — — 2,436
Total 963 — 2,436
Limited Partner Units Cash:
Paid 101,561 93,622 114,612
Accrued — — —
Total 101,561 93,622 114,612
General Partner Units Cash:
Paid 2,551 6,789 2,695
Accrued — — —
Additional Blackwater acquisition consideration 5,000 — —
Total 7,551 6,789 2,695
Summary Cash
Paid 112,136 100,411 119,965
Accrued 7,103 — —
Paid-in-kind units 14,446 18,351 17,810
Additional Blackwater acquisition consideration 5,000 — —
Total $ 138,685 $ 118,762 $ 137,775
On January 26, 2017 , the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit or $1.65 per common uniton an annualized basis. The distribution was paid on February 13, 2017 , to unitholders of record as of the close of business on February 6, 201 7. Accrued cashdistributions on our preferred convertible units were also paid in February 2017.
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The fair value of the paid-in-kind distributions was determined using the market and income approaches, requiring significant inputs which are not observable inthe market and thus represent a Level 3 measurements as defined by ASC 820. Under the income approach, the fair value estimates for all years presented werebased on i) present value of estimated future contracted distributions, ii) option values ranging from $0.02 per unit to $9.68 per unit using a Black-Scholes model,iii) assumed discount rates ranging from 5.57% to 10.0% and iv) assumed growth rates of 1.0% .
The Fourth Amended and Restated Agreement of Limited Partnership provides that the General Partner may, in its sole discretion, make cash distributions, butthere is no requirement that we make any cash distributions.
16. Net Income (Loss) per Limited Partner Unit
Net income (loss) is allocated to the General Partner and the limited partners in accordance with their respective ownership percentages, after giving effect todistributions on our convertible preferred units and General Partner units, including incentive distribution rights. Unvested unit-based compensation awards thatcontain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic anddiluted net limited partners' net income (loss) per common unit. Basic and diluted limited partners' net income (loss) per common unit is calculated by dividinglimited partners' interest in net income (loss) by the weighted average number of outstanding limited partner units during the period.
As of December 31, 2016, JPE had approximately 36.7 million common and subordinated units outstanding. Additionally, as of that date, ArcLight ownedapproximately 18.7 million , or 50.9% , of those units while other unitholders owned approximately 18.0 million or 49.1% of those units. In order to affect the JPEMerger, the Partnership issued .5225 of a Partnership common unit for each JPE unit held by ArcLight Capital or approximately 9.8 million units and .5775 of aPartnership common unit for each JPE unit held by other unitholders or approximately 10.4 million units. The Partnership issued a total of 20.2 million units toaffect the JPE Merger.
In order to determine the weighted average number of units outstanding for purposes of calculating limited partner earnings per unit in the consolidated statementsof operations, the Partnership’s historical weighted average number of units outstanding for each year was added to an assumed weighted average number of JPEunits outstanding after applying the applicable exchange ratios mentioned previously. JPE’s common units were not publicly traded until October 7, 2014, when itcompleted its IPO. Concurrent with its IPO, JPE completed an equity restructuring whereby it converted its previously outstanding equity interests intoapproximately 22.7 million common and subordinated units.
For the year ended December 31, 2014, the applicable exchange ratios were applied to the 22.7 million of JPE common and subordinated units resulting from thepreviously mentioned equity restructuring as if such units were outstanding for the entire year, plus the 13.8 million common units issued in connection with JPE’sIPO on October 7, 2014 as if such units were outstanding for approximately 25% of the year. The aggregate amount was then added to the Partnership’s actualweighted average number of units outstanding for the year to arrive at the weighted average number of units outstanding for the year.
For the years ended December 31, 2015 and 2016, the applicable exchange ratios were applied to JPE’s actual weighted average number of units outstanding forthe respective periods and such amounts were added to the Partnership’s actual weighted average number of units outstanding for the respective periods to arrive atthe weighted average number of units outstanding for the respective periods.
The calculation of basic and diluted limited partners' net loss per common unit is summarized below (in thousands, except per unit amounts):
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Years Ended December 31,
2016 2015 2014
Net loss from continuing operations $ (48,005) $ (184,810) $ (69,681)Less: Net income (loss) attributable to noncontrolling interests 2,766 (13) 3,993Net loss from continuing operations attributable to the Partnership (50,771) (184,797) (73,674)Less:
Distributions on Series A Units 19,138 16,978 14,492Distributions on Series C Units 9,487 — —Distributions on Series D Units 963 — —Distributions on Series B Units — 1,373 2,220Net income (loss) from continuing operations attributable to JPE preferred units — — 656Net income (loss) from continuing operations attributable to predecessor capital — — (2,014)General partner's distributions 2,550 6,790 2,694General partner's share in undistributed loss (1,745) (3,309) (1,510)
Net loss from continuing operations attributable to Limited Partners (81,164) (206,629) (90,212)Net loss from discontinued operations attributable to Limited Partners (532) (15,031) (269)Net loss attributable to Limited Partners $ (81,696) $ (221,660) $ (90,481)
Weighted average number of common units used in computation of Limited Partners' net lossper common unit - basic and diluted 51,176 45,050 27,524
Limited Partners' net loss from continuing operations per unit (basic and diluted) $ (1.59) $ (4.59) $ (3.28)Limited Partners' net loss from discontinued operations per unit (basic and diluted) (0.01) (0.33) (0.01)
Limited Partners' net loss per common unit - basic and diluted (1) $ (1.60) $ (4.92) $ (3.29) _______________________(1) Potential common unit equivalents are antidilutive for all periods and, as a result, have been excluded from the determination of diluted limited partners' netincome (loss) per common unit.
17. Long-Term Incentive Plan
AMID Unit-Based Compensation
Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 19, 2015, the Board ofDirectors of our General Partner approved the Third Amended and Restated Long-Term Incentive Plan to, among other things, increase the number of commonunits authorized for issuance by 6,000,000 common units. On February 11, 2016, the unitholders approved the Third Amended and Restated Long-Term IncentivePlan (as amended and as currently in effect as of the date hereof, the "LTIP"). At December 31, 2016 , 2015 and 2014 , there were 5,017,528 , 15,484 and 688,976common units, respectively, available for future grant under the LTIP.
All equity-based awards issued under the LTIP consist of phantom units, distribution equivalent rights ("DER") or option grants. DERs and options have beengranted on a limited basis. Future awards may be granted at the discretion of the Compensation Committee and subject to approval by the Board of Directors of ourGeneral Partner.
Phantom Unit Awards. Ownership in the phantom unit awards is subject to forfeiture until the vesting date. The LTIP is administered by the CompensationCommittee of the Board of Directors of our General Partner, which at its discretion, may elect to settle such vested phantom units with a number of common unitsequivalent to the fair market value at the date of vesting in lieu of cash.
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Although our General Partner has the option to settle vested phantom units in cash, our General Partner has not historically settled these awards in cash. Under theLTIP, phantom units typically vest in increments of 25% on each grant anniversary date and do not contain any vesting requirements other than continuedemployment.
In December 2015, the Board of Directors of our General Partner approved a grant of 200,000 phantom units under the LTIP which contain DERs to the extent thePartnership’s Series A Preferred Unitholders receive distributions in cash. These units will vest on the three year anniversary of the date of grant, subject toacceleration in certain circumstances.
The following table summarizes activity in our phantom unit-based awards for the years ended December 31, 2016, 2015 and 2014:
Units
Weighted-AverageGrant Date Fair Value
Per Unit
Aggregate IntrinsicValue (1) (Inthousands)
Outstanding units at December 2013 75,529 $ 17.62 $ 2,045Granted 188,946 20.80 Forfeited (12,009) (18.28) Vested (51,334) (20.89) Outstanding units at December 2014 201,132 $ 19.85 $ 3,964Granted 546,329 12.25 Forfeited (31,298) (15.62) Vested (146,404) (18.47) Outstanding units at December 2015 569,759 $ 13.15 $ 4,609Granted 1,374,226 2.14 Forfeited (411,794) (2.60) Vested (286,348) (12.18) Outstanding units at December 2016 1,245,843 $ 4.72 $ 22,674
(1) The intrinsic value of phantom units was calculated by multiplying the closing market price of our underlying stock on December 31, 2016, 2015 and 2014 bythe number of phantom units.
The fair value of our phantom units, which are subject to equity classification, is based on the fair value of our common units at the grant date. Compensationexpense related to these awards for the years ended December 31, 2016 , 2015 , and 2014 was $3.6 million , $3.8 million and $1.5 million , respectively, and isincluded in Corporate expenses and Direct operating expenses in our consolidated statements of operations and the equity compensation expense in ourconsolidated statements of changes in partners' capital and noncontrolling interests.
The total fair value of units at the time of vesting was $2.4 million , $2.6 million , and $1.4 million for the years ended December 31, 2016 , 2015 , and 2014 ,respectively.
Equity compensation expense related to unvested phantom awards not yet recognized at December 31, 2016 was $4.2 million and the weighted average period overwhich this expense is expected to be recognized as of December 31, 2016 is approximately 2.2 years.
Performance and Service Condition Awards . In November 2015, the Board of Directors of our General Partner modified awards that introduced certainperformance and service conditions that were probable of being achieved, amounting to $2.0 million payable to certain employees. During the third quarter of2016, we settled $1.0 million of the obligation in cash while in the fourth quarter of 2016, forfeitures reduced the total payable amount from $2.0 million to $1.5million . These awards are accounted for as liability classified awards. Compensation expense related to these awards for the years ended December 31, 2016 and2015 was $0.9 million and $0.5 million , respectively, and is included in Directoperatingexpenses in our consolidated statements of operations. Compensationexpense related to unvested awards not yet recognized at December 31, 2016 was $0.1 million .
Option to Purchase Common Units .In December 2015, the Board of Directors of our General Partner approved the grant of an option to purchase 200,000common units at an exercise price per unit equal to $7.50 . The grant will vest on January 1, 2019, subject to acceleration in certain circumstances, and will expireon March 15th of the calendar year following the calendar year in which it vests.
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In August 2016, the Board of Directors of our General Partner approved the grant of an option to purchase 30,000 common units at an exercise price per unit equalto $12.00 . The grant will vest on July 31, 2019, subject to continued employment, and will expire on July 31st of the calendar year following the calendar year inwhich it vests.
In September 2016, the Board of Directors of our General Partner approved the grant of an option to purchase 45,000 common units of the Partnership at anexercise price per unit equal to $13.88 . The options will vest at a rate of 25% per year. The options will expire on September 30th of the calendar year followingthe calendar year in which it vests.
The Black-Scholes pricing model was used to determine the fair value of our options grants using the following assumptions:
Years Ended December 31,
2016 2015
Weighted average common unit price volatility 61.1% 47.0%Expected distribution yield 12.6% 26.3%Weighted average expected term (in years) 4.10 3.5Weighted average risk-free rate 1.1% 1.3%
The weighted average unit price volatility was based upon the historical volatility of our common units. The expected distribution yield was based on anannualized distribution divided by the closing unit price on the date of grant. The risk-free rate was based on the U.S. Treasury yield curve in effect on the date ofgrant.
Compensation expense related to these awards was not material for the years ended December 31, 2016 and 2015. Compensation cost related to unvested awardsnot yet recognized at December 31, 2016 was $0.2 million .
The following table summarizes our option activity for the years ended December 31, 2016 and 2015:
Units
Weighted-AverageExercise Price
Weighted-AverageGrant Date FairValue per Unit
Aggregate IntrinsicValue (1) (Inthousands)
Weighted AverageRemaining
Contractual Life(Years)
Outstanding at December 31, 2014 — $ — $ — $ — —Granted 200,000 7.50 0.33 — —Vested — — — —Forfeited — — — —Outstanding at December 31, 2015 200,000 $ 7.50 $ 0.33 $ 118 4.2Granted 75,000 13.13 2.65 — —Vested — — — —Forfeited — — — —Outstanding at December 31, 2016 275,000 $ 9.03 $ 0.96 $ 2,522 5.0(1) The intrinsic value of the stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option.
JPE Unit-Based Compensation
Long-TermIncentivePlanandPhantomUnits.The JPE 2014 Long-Term Incentive Plan (“JPE LTIP”) authorized grants of up to 3,642,700 common units.Phantom units issued under the JPE LTIP were primarily composed of two types of grants: (1) service condition grants with vesting over three years in equalannual installments; and (2) service condition grants with cliff vesting on April 1, 2018. Distributions related to these unvested phantom units are paid concurrentwith our distribution for common units. The fair value of phantom units issued under the JPE LTIP was determined by utilizing the market value of our commonunits on the respective grant date.
The following table presents phantom units activity for the years ended December 31, 2016 and 2015:
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Units Weighted Average
Grant date Fair Value
Outstanding units at December 2014 — $ —Granted 287,750 22.25Vested (4,766) 22.34Forfeited (56,005) 21.23Outstanding units at December 2015 226,979 $ 22.5Granted 209,507 9.23Vested (55,778) 19.51Forfeited (67,716) 18.74
Outstanding units at December 2016 312,992 $ 14.96
Total unit-based compensation expense related to JPE phantom units was $1.7 million and $0.8 million for the years ended December 31, 2016 and 2015,respectively, which was recorded in corporateexpensesin the consolidated statements of operations.
18. Income Taxes
With the exception of certain subsidiaries in our Terminals Segment, the Partnership is not subject to U.S. federal or state income taxes as such income taxes aregenerally borne by our unitholders through the allocation of our taxable income (loss) to them. The State of Texas does impose a franchise tax that is assessed onthe portion of our taxable margin which is apportioned to Texas.
Income tax (expense) benefit for the years ended December 31, 2016, 2015 and 2014 is as follows:
Years Ended December 31,
2016 2015 2014
Current income tax expense $ (521) $ (648) $ (146)Deferred income tax expense (2,057) (1,240) (711)
Effective income tax rate 5.7% 1.0% 1.2%
A reconciliation of our expected income tax (expense) benefit calculated at the U.S. federal statutory rate of 34% to our actual tax (expense) for the years endedDecember 31, 2016, 2015 and 2014 is as follows:
Years Ended December 31,
2016 2015 2014
Net income (loss) before income tax expense $ (45,427) $ (182,922) $ (68,824)US Federal statutory tax rate 34% 34% 34%Federal income tax (expense) benefit at statutory rate 15,445 62,193 23,400Reconciling items: Partnership loss not subject to income tax (benefit) (17,218) (63,083) (23,759) State and local tax expense (800) (857) (459) Other (5) (141) (39)
Income tax expense $ (2,578) $ (1,888) $ (857)
The Partnership’s deferred tax assets and liabilities as of December 31, 2016 and 2015 are summarized below:
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December 31,
2016 2015
Deferred tax assets: Net operating loss carryforwards $ 6,300 $ 7,570 Other 577 493 Total deferred tax assets 6,877 8,063Deferred tax liabilities: Property, plant and equipment (15,082) (14,236)
Deferred income tax liability, net $ (8,205) $ (6,173)
As of December 31, 2016 , certain subsidiaries in our Terminals Segment had net operating loss carryforwards for federal income tax purposes of approximately$16.1 million which begin to expire in 2028.
We recognize the tax benefits from uncertain tax positions if it is more likely than not that the position will be sustained on examination by the taxing authorities.As of December 31, 2016, we have not recognized tax benefits relating to uncertain tax positions.
The preparation of our income tax returns requires the use of management's estimates and interpretations which may be subjected to review by the respectivetaxing authorities and may result in an assessment of additional taxes, penalties and interest. Tax years subsequent to 2010 remain subject to examination byfederal and state taxing authorities.
19. Commitments and Contingencies
Legal proceedings
We are not currently party to any pending litigation or governmental proceedings, other than ordinary routine litigation incidental to our business. While theultimate impact of any proceedings cannot be predicted with certainly, our management believes that the resolution of any of our pending proceeds will not have amaterial adverse effect on our financial condition or results of operations.
Environmental matters
We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in our operations and wecould, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmentalpolicies and practices to minimize any impact our operations may have on the environment.
Regulatory matters
On October 8, 2014, American Midstream (Midla), LLC ("Midla") reached an agreement in principle with its customers regarding the interstate pipeline thattraverses Louisiana and Mississippi in order to provide continued service to its customers while addressing safety concerns with the existing pipeline.
On April 16, 2015, FERC approved the stipulation and agreement (the “Midla Agreement”) relating to the October 8, 2014 regulatory matter and allowing Midla toretire the existing 1920’s pipeline and replace it with the Midla-Natchez Line to serve existing residential, commercial, and industrial customers. Under the MidlaAgreement, customers not served by the new Midla-Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, oroffered conversion to propane service. On June 29, 2015, the Partnership filed with FERC for authorization to construct the Midla-Natchez pipeline, which wasapproved on December 17, 2015. Construction commenced in the second quarter of 2016 with service expected to begin in the first six months of 2017. Under theMidla Agreement, Midla plans to execute long-term agreements seeking to recover its investment in the Midla-Natchez Line.
Exit and disposal costs
On March 9, 2016, management committed to a corporate headquarters relocation plan and communicated that plan to the impacted employees. The plan includedrelocation assistance or one-time termination benefits for employees who rendered service until
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their respective termination dates. Charges associated with these termination benefits, which totaled $9.1 million were recognized ratably over the requisite serviceperiod and are presented in Corporate expenses in our consolidated statements of operations. At December 31, 2016 , payments under the plan had beencompleted.
Commitments and contractual obligations
The Partnership had the following non-cancelable contractual commitments as of December 31, 2016 :
Revolving Credit
Agreements 3.77% Senior Notes 8.50% Senior Notes (1) Asset Retirement
Obligation (2) Other Total
(in thousands)2017 $ — $ 1,677 $ — $ 6,499 $ 9,869 $ 18,0452018 — 806 — — 6,331 7,1372019 888,250 2,233 — — 5,079 895,5622020 — 2,299 — — 2,905 5,2042021 — 4,430 300,000 — 2,253 306,683Thereafter — 48,555 — 44,363 17,991 110,909
$ 888,250 $ 60,000 $ 300,000 $ 50,862 $ 44,428 $ 1,343,540(1) Upon closing of the JPE Merger, the proceeds from the 8.50% Senior Notes were used to repay the JPE Credit Agreement.(2) In some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of theasset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can bederived from past practice, industry practice, management's experience, or the asset's estimated economic life.
For the years ended December 31, 2016 , 2015 and 2014 , total rental expenses were $19.5 million , $17.7 million , and $10.6 million , respectively.
20. Related-Party Transactions
Employees of our General Partner are assigned to work for the Partnership or other ArcLight affiliates. Where directly attributable, all compensation and relatedexpenses for these employees are charged directly by our General Partner to American Midstream, LLC, which, in turn, charges the appropriate subsidiary oraffiliate. Our General Partner does not record any profit or margin on the expenses charged to us. During the years ended December 31, 2016, 2015, and 2014,related expenses of $89.8 million , $98.3 million , and $95.5 million respectively, were charged to the Partnership by our General Partner. As of December 31,2016, and 2015, the Partnership had $3.9 million and $3.8 million , respectively, due to our General Partner, which has been recorded in Accrued expenses andother current liabilities and relates primarily to compensation. This payable is generally settled on a quarterly basis related to the foregoing transactions.
During the second quarter of 2014, the Partnership and an ArcLight affiliate entered into an agreement under which the affiliate pays a monthly fee to reimbursethe Partnership for administrative expenses incurred on the affiliate’s behalf. For the years ended December 31, 2016, 2015, and 2014, the Partnership recognizedrelated management fee income of $0.8 million , $1.4 million and $0.9 million respectively, under this agreement and recorded such amounts as a reduction ofCorporate expenses in the consolidated statements of operations.
We also performed certain management services for another ArcLight affiliate for which we received a monthly fee of $50,000 through January 2016. The monthlyfee reduced Corporate expenses in the consolidated statements of operations by $0.1 million , $0.6 million and $0.6 million for the years ended December 31,2016, 2015 and 2014, respectively.
During the years ended December 31, 2016 and 2015, our General Partner agreed to absorb certain of our corporate expenses. We received reimbursements forthese expenses in the quarter subsequent to when they were incurred. We received reimbursements totaling $7.5 million and $3.0 million for the years endedDecember 31, 2016 and 2015, respectively. In the first quarter of 2015, certain executive bonuses related to the year ended December 31, 2014 were paid on ourbehalf by ArcLight. In addition, ArcLight reimbursed us for expenses we incurred for the years ended December 31, 2016 and 2015. The total amounts paid on ourbehalf or reimbursed to us were $2.4 million and $2.6 million for the years ended December 31, 2016 and 2015, respectively, and were treated as deemedcontributions from ArcLight.
An ArcLight affiliate provided crude oil pipeline transportation services to our discontinued Mid-Continent Business. During the years ended December 31, 2016,2015 and 2014, we incurred related pipeline transportation fees of $0.4 million , $6.0 million and
$8.9 million , respectively, which have been included in net loss from discontinued operations, net of tax in the consolidated statements of operations. As ofDecember 31, 2015, we had a net receivable of $7.9 million from this affiliate, primarily as the result of the prepayments made in 2014 for the crude oil pipelinetransportation services to be provided.
The Partnership acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from affiliates of ArcLight in December 2013. The acquisition agreement includeda provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operatingtargets. During the third quarter of 2016, the Partnership determined that it was probable the operating targets would be met in early 2017 and recorded a $5.0million accrued distribution to the ArcLight affiliate which is included in Accruedexpensesandothercurrentliabilitiesin the accompanying consolidated balancesheets at December 31, 2016 .
American Panther, LLC ("American Panther") is a 60% -owned subsidiary of the Partnership which is consolidated for financial reporting purposes. Pursuant to arelated agreement which began in the second quarter of 2016, an affiliate of the non-controlling interest holder provides services to American Panther in exchangefor related fees, which in 2016 totaled $1.2 million of which $0.8 million is included in Direct operating expenses and $0.4 million is included in Corporateexpenses in the consolidated statement of operations.
On November 1, 2016, the Partnership became operator of the Destin and Okeanos pipelines and entered into operating and administrative managementagreements under which the affiliates pay a monthly fee for general and administrative services provided by the Partnership. In addition, the affiliates reimbursedthe Partnership for certain transition related expenses. For the year ended December 31, 2016 , the Partnership recognized $0.4 million of management fee incomeand $1.0 million as reimbursement of transition related expenses in Corporateexpensesin the consolidated statements of operations.
During the second quarter of 2015, we began performing administrative, crude transportation and marketing services for an ArcLight affiliate. We charged $3.2million and $3.0 million for the years ended December 31, 2016 and 2015, respectively, for these services of which $3.2 million and $2.2 million was included inServices for the years ended December 31, 2016 and 2015, respectively, and $0.8 million was included in Commodity sales for the year ended December 31, 2015on the consolidated statements of operations. As of December 31, 2016 and 2015, we had receivables due from this affiliate of $2.1 million and $0.7 million ,respectively, which are included in other current assets in the consolidated balance sheets.
The Partnership enters into purchases and sales of natural gas and crude oil with a company whose chief financial officer is the brother of one of our executiveofficers. During the years ended December 31, 2016 , 2015 , and 2014 , the Partnership recognized related revenue of $3.6 million , $6.2 million and $10.1 million, respectively, while purchases from the company totaled $4.3 million , $5.9 million , and $3.7 million , respectively.
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21. Supplemental Cash Flow Information
Supplemental cash flows and non-cash transactions consists of the following (in thousands):
Years Ended December 31,
2016 2015 2014
Supplemental cash flow information Interest payments, net of capitalized interest $ 22,303 $ 16,540 $ 13,905Cash paid for taxes 530 450 108Supplemental non-cash information Increase (decrease) in accrued property, plant and equipment purchases $ 8,533 $ (21,841) $ 35,018Contributions from general partner 7,500 4,350 —Acquisitions partially funded by the issuance of common units — 3,442 414,396Assets acquired under capital lease 139 — 177Issuance of Series C Units and Warrant in connection with the Emerald Transactions 120,000 — —Accrued cash distributions on convertible preferred units 7,103 — —Paid-in-kind distributions on convertible preferred units 14,446 16,978 13,154Paid-in-kind distributions on Series B Units — 1,373 2,220Paid-in-kind distributions on JPE Series D units — — 2,436Cancellation of escrow units 6,817 — —Additional Blackwater acquisition consideration 5,000 — —
22. Reportable Segments
Our operations are located in the United States and are organized into the following reportable segments: Gas Gathering and Processing Services, Liquid Pipelinesand Services, Natural Gas Transportation Services, Offshore Pipeline and Services, Terminalling Services, and Propane Marketing Services. These segments, aredescribed below, have been identified based on the differing products and services, regulatory environments and the expertise required for these operations.
Gas Gathering and Processing Services provides “wellhead-to-market” services to producers of natural gas and crude oil, which include transporting raw naturalgas and crude oil from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from thenatural gas, fractionating NGLs, and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.
Liquid Pipelines and Services provides transportation, purchase and sales of crude oil from various receipt points including lease automatic custody transfer("LACT") facilities and delivering to various markets.
Natural Gas Transportation Services transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and othercustomers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers.
Offshore Pipelines and Services gathers and transports natural gas from various receipt points to other pipeline interconnects, onshore facilities and other deliverypoints.
Terminalling Services provides above-ground leasable storage operations at our marine terminals that support various commercial customers, includingcommodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, OK and refined productsterminals in Texas and Arkansas.
Propane Marketing Services gathers, transports and sells natural gas liquids (NGLs). This is accomplished through cylinder tank exchange, sales through retail,commercial and wholesale distribution and through a fleet of trucks operating in the Eagle Ford and Permian basin areas.
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Our Chief Executive Officer serves as our Chief Operating Decision Maker and evaluates the performance of our reportable segments primarily on the basis ofsegment gross margin, which is our segment measure of profitability. We define segment gross margin for each segment as summarized below:
Gas Gathering and Processing Services - total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives, constructionand operating management agreement income and the cost of sales.
Liquid Pipelines and Services - total revenue plus unconsolidated affiliate earnings less unrealized gains (losses) on commodity derivatives and the cost of sales.Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
Natural Gas Transportation Services - total revenue plus unconsolidated affiliate earnings less the cost of sales. Substantially all of our gross margin in thissegment is fee-based or fixed-margin, with little to no direct commodity price risk.
Offshore Pipelines and Services - total revenue plus unconsolidated affiliate earnings less the cost of sales. Substantially all of our gross margin in this segment isfee-based or fixed-margin, with little to no direct commodity price risk.
Terminalling Services - total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.
Propane Marketing Services - total revenue less cost of sales excluding non-cash charges such as non-cash unrealized gain (losses) on commodity derivatives.
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The following tables set forth our segment financial information for the periods indicated:
December 31, 2016
Gas Gatheringand Processing
ServicesLiquid Pipelines
and Services
Natural GasTransportation
Services
OffshorePipelines and
ServicesTerminalling
Services
PropaneMarketing
Services Total (in thousands)
Commodity sales $ 91,444 $ 304,501 $ 21,999 $ 6,812 $ 14,655 $ 129,116 $ 568,527
Services 22,558 12,146 18,109 40,502 50,999 14,536 158,850
Gains (losses) on commodity derivatives, net (833) (341) — (7) (436) 1,162 (455)
Total Revenue 113,169 316,306 40,108 47,307 65,218 144,814 726,922
Cost of sales 63,832 288,496 21,288 3,049 11,564 54,794 443,023
Direct operating expenses 33,802 8,383 5,923 10,945 10,783 53,536 123,372
Corporate expenses 99,430
Depreciation, amortization, and accretion 106,818
Loss on sale of assets, net 2,870Loss on impairment of plant, property andequipment 697
Loss on impairment of goodwill 15,456
Interest expense 21,469
Earnings in unconsolidated affiliates (40,158)
Other (income) expense (628)
Income tax expense 2,578
Income (loss) from continuing operations (48,005)
Loss from discontinuing operations, net of tax (539)
Net income (loss) (48,544)Net income (loss) attributable to non-controllinginterest 2,766
Net income (loss) attributable to partnership $ (51,310)
Segment gross margin $ 48,245 $ 29,760 $ 18,616 $ 82,346 $ 42,872 $ 88,948
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December 31, 2015
Gas Gatheringand Processing
Services
LiquidPipelines and
Services
Natural GasTransportation
Services
OffshorePipelines and
ServicesTerminalling
Services
PropaneMarketing
Services Total (in thousands)
Commodity sales $ 107,680 $ 457,390 $ 23,972 $ 13,798 $ 10,343 $ 159,674 $ 772,857
Services 30,196 12,895 16,035 21,457 45,022 17,157 142,762
Gains (losses) on commodity derivatives, net 1,240 — — 84 21 (3,077) (1,732)
Total Revenue 139,116 470,285 40,007 35,339 55,386 173,754 913,887
Cost of sales 72,960 446,125 21,858 9,914 8,893 70,553 630,303
Direct operating expenses 35,250 8,310 6,728 9,425 10,414 57,353 127,480
Corporate expenses 77,835
Depreciation, amortization, and accretion 98,596
Loss on sale of assets, net 3,920
Loss on impairment of goodwill 148,488
Interest expense 20,120
Earnings in unconsolidated affiliates (8,201)
Other (income) expense (1,732)
Income tax expense 1,888
Income (loss) from continuing operations (184,810)
Loss from discontinuing operations, net of tax (15,031)
Net income (loss) (199,841)Net income (loss) attributable to non-controlling interest (13)
Net income (loss) attributable to partnership $ (199,828)
Segment gross margin $ 65,692 $ 24,160 $ 18,073 $ 33,613 $ 36,079 $ 91,437
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December 31, 2014
Gas Gatheringand Processing
ServicesLiquid Pipelines
and Services
Natural GasTransportation
ServicesOffshore Pipelines
and ServicesTerminalling
Services
PropaneMarketing
Services Total (in thousands)
Commodity sales $ 148,198 $ 470,336 $ 70,964 $ 20,044 $ 11,521 $ 188,702 $ 909,765
Services 15,248 11,548 12,925 24,426 41,357 18,194 123,698Gains (losses) on commodity derivatives,net 1,050 — — 41 — (13,762) (12,671)
Total Revenue 164,496 481,884 83,889 44,511 52,878 193,134 1,020,792
Cost of dales 112,719 459,319 70,100 15,133 6,859 125,742 789,872
Direct operating expenses 21,197 5,819 6,975 11,142 11,525 52,885 109,543
Corporate expenses 72,744
Depreciation, amortization, and accretion 72,527
Loss on sale of assets, net 5,080Loss on impairment of plant, propertyand equipment 21,344
Interest expense 16,558
Earnings in unconsolidated affiliates (348)
Other (income) expense 662
Loss on extinguishment of debt 1,634
Income tax expense 857
Income (loss) from continuing operations (69,681)Loss from discontinuing operations, netof tax (9,886)
Net income (loss) (79,567)Net income (loss) attributable to non-controlling interest 3,993Net income (loss) attributable topartnership $ (83,560)
Segment gross margin $ 51,213 $ 22,564 $ 13,691 $ 29,089 $ 34,493 $ 80,083
A reconciliation of total assets by segment to the amounts included in the consolidated balance sheets is as follows:
December 31,
2016 2015Segment assets: (in thousands)
Gas Gathering and Processing Services $ 530,889 $ 496,014Liquid Pipelines and Services 422,636 426,854Natural Gas Transportation Services 221,604 146,927Offshore Pipelines and Services 400,193 190,271Terminalling Services 299,534 291,130Propane Marketing Services 140,864 173,558
Other (1) 333,601 27,135Total assets $ 2,349,321 $ 1,751,889
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_______________________(1) Other assets not allocable to segments consist of investment in unconsolidated affiliates, restricted cash and other assets.
23. Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data for 2016 and 2015 are as follows (in thousands, except per unit amounts):
First
Quarter SecondQuarter
ThirdQuarter
FourthQuarter (2)
Year Ended December 31, 2016 Total revenues $ 143,376 $ 185,836 $ 187,659 $ 210,051Gross margin (1) 74,045 81,072 76,427 79,243Operating loss (8,401) (10,368) (12,125) (33,850)Net income (loss) (10,603) (9,481) (7,797) (20,663)Net income (loss) attributable to the Partnership (10,600) (10,435) (8,993) (21,282)General Partner's Interest in net income (loss) (97) (107) (26) (3)Limited Partners' Interest in net income (loss) $ (10,503) $ (10,328) $ (8,967) $ (21,279)
Limited Partners' income (loss) per unit: Loss from continuing operations $ (0.32) $ (0.33) $ (0.33) $ (0.61)Net income (loss) $ (0.33) $ (0.33) $ (0.33) $ (0.61)
Year Ended December 31, 2015 Total revenues $ 238,035 $ 265,703 $ 209,416 $ 200,733Gross margin (1) 73,088 66,757 56,829 72,380Operating income (loss) 2,187 (5,769) (10,831) (158,322)Net income (loss) from continuing operations (1,525) (10,913) (15,207) (157,165)Income (loss) from discontinued operations, net of tax (402) 511 (1,300) (13,840)Net income (loss) attributable to noncontrolling interest 4 22 24 (63)Net income (loss) attributable to the Partnership (1,932) (10,425) (16,532) (170,939)General Partner's Interest in net income (loss) (32) (66) (104) (1,621)Limited Partners' Interest in net income (loss) $ (1,900) $ (10,358) $ (16,428) $ (169,319)
Limited Partners' income (loss) per unit: Loss from continuing operations $ (0.15) $ (0.39) $ (0.50) $ (3.55)Net loss $ (0.16) $ (0.38) $ (0.53) $ (3.85)
(1) For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP
and a discussion of how we use gross margin to evaluate our operating performance, please read Item 7. "Management's Discussion and Analysis, How WeEvaluate Our Operations."
(2) We recognized goodwill impairment charges of $15.4 million and $148.5 million in the fourth quarters of 2016 and 2015, respectively.
24. Subsequent Event
Distribution
On January 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of$0.4125 per common unit for the fourth quarter ended December 31, 2017, or $1.65 per common unit on an annualized basis. The distribution is expected to bepaid on February 13, 2017, to unitholders of record as of the close of business February 6, 2017.
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Dakota Access Connection Agreement
On March 1, 2017, the Partnership announced it has entered a connection agreement with Dakota Access Pipeline (“DAPL”), the 1,172 -mile pipeline that extendsfrom the Partnership’s Bakken formation production area in North Dakota to Patoka, Illinois. The new DAPL interconnect will tie into the Partnership’s Bakkencrude oil gathering system which consists of interstate pipelines with capacity to transport up to approximately 40,000 barrels per day of crude oil.
Sale of Propane Marketing Services Business
On July 21, 2017, the Partnership entered into an agreement to sell its Propane Marketing Services business to SHV Energy, N.V. for $170.0 million in cash. Thetransaction closed on September 1, 2017. The underlying agreement contemplates working capital and other adjustments which have not yet been determined.
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Recommended