American Midstream Partners, LP - FORM 10-Q

Attached files

file	filename
EX-31.2 - EXHIBIT 31.2 - American Midstream Partners, LP	a2017q3exhibit312302certif.htm
EX-32.2 - EXHIBIT 32.2 - American Midstream Partners, LP	a2017q3exhibit322906certif.htm
EX-32.1 - EXHIBIT 32.1 - American Midstream Partners, LP	a2017q3exhibit321906certif.htm
EX-31.1 - EXHIBIT 31.1 - American Midstream Partners, LP	a2017q3exhibit311302certif.htm
EX-10.4 - EXHIBIT 10.4 - American Midstream Partners, LP	a2017q3exhibit104distribut.htm
EX-10.2 - EXHIBIT 10.2 - American Midstream Partners, LP	a2017q3exhibit102membershi.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35257

AMERICAN MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)



Delaware	27-0855785
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

2103 CityWest Boulevard
Building #4, Suite 800
Houston, TX	77042
(Address of principal executive offices)	(Zip code)

(346) 241-3400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ý Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” or an “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	¨	Accelerated filer	ý
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨
		Emerging growth company	¨
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 or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.			¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes ý No

There were 52,684,359 common units, 10,536,915 Series A Units, and 8,792,205 Series C Units of American Midstream Partners, LP outstanding as of October 27, 2017. Our common units trade on the New York Stock Exchange under the ticker symbol “AMID.”

Table of Contents

Glossary of Terms

As generally used in the energy industry and in this Quarterly Report on Form 10-Q (the “Quarterly Report”), the identified terms have the following meanings:

Bbl Barrels: 42 U.S. gallons measured at 60 degrees Fahrenheit.

Bbl/d Barrels per day.


Btu	British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.


Condensate	Liquid hydrocarbons present in casing head gas that condense within the gathering system and are removed prior to delivery to the natural gas plant. This product is generally sold on terms more closely tied to crude oil pricing.

/d Per day.

FERC Federal Energy Regulatory Commission.

Fractionation Process by which natural gas liquids are separated into individual components.

GAAP Generally Accepted Accounting Principles in the United States of America.

Gal Gallons.

Mgal/d Thousand gallons per day.

MBbl Thousand barrels.

MMBbl Million barrels.

MMBbl/day Million barrels per day.

MMBtu Million British thermal units.

Mcf Thousand cubic feet.

MMcf Million cubic feet.

MMcf/d Million cubic feet per day.


NGL or NGLs	Natural gas liquid(s): The combination of ethane, propane, normal butane, isobutane and natural gasoline that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.


Throughput	The volume of natural gas and NGL transported or passing through a pipeline, plant, terminal or other facility during a particular period.

As used in this Quarterly Report, unless the context otherwise requires, “we,” “us,” “our,” the “Partnership” and similar terms refer to American Midstream Partners, LP, together with its consolidated subsidiaries.

TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
	Condensed Consolidated Balance Sheets as of September 30, 2017 (unaudited) and December 31, 2016	4
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016 (unaudited)	5
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016 (unaudited)	6
	Condensed Consolidated Statements of Changes in Partners’ Capital and Noncontrolling Interests as of and for the nine months ended September 30, 2017 and 2016 (unaudited)	7
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016 (unaudited)	8
	Notes to Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	Forward-Looking Statements	42
	Overview	43
	Recent Developments	43
	Our Operations	46
	How We Evaluate Our Operations	49
	General Trends and Outlook	52
	Results of Operations	52
	Liquidity and Capital Resources	65
	Critical Accounting Estimates	69
	Recent Accounting Pronouncements	69

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	69

Item 4.	Controls and Procedures	70

PART II. OTHER INFORMATION		71

Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 6.	Exhibits	74

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Balance Sheets

(Unaudited, in thousands, except unit amounts)



	September 30, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	6,739		$	5,666
Restricted cash	18,683			—
Accounts receivable, net of allowance for doubtful accounts of $0.1 and $0.6 million, respectively	25,897			14,715
Unbilled revenue	53,168			52,910
Inventory	5,970			1,990
Other current assets	17,144			25,516
Current assets of discontinued operations	—			22,727
Total current assets	127,601			123,524
Risk management assets-long term	7,545			10,627
Property, plant and equipment, net	1,140,826			1,066,608
Goodwill	202,135			202,135
Restricted cash-long term	5,693			323,564
Intangible assets, net	194,456			205,071
Investments in unconsolidated affiliates	334,026			291,987
Other assets, net	10,925			11,773
Noncurrent assets of discontinued operations	—			114,032
Total assets	$	2,023,207		$	2,349,321
Liabilities, Equity and Partners’ Capital
Current liabilities
Accounts payable	$	27,285		$	39,569
Accrued gas purchases	16,696			7,891
Accrued expenses and other current liabilities	67,505			72,721
Current portion of long-term debt	1,234			5,438
Current liabilities of discontinued operations	—			14,319
Total current liabilities	112,720			139,938
Asset retirement obligations	52,046			44,363
Other long-term liabilities	2,448			1,858
3.77% Senior secured notes (Non-recourse)	55,186			55,979
8.50% Senior unsecured notes	293,007			291,309
Revolving credit facility	709,652			888,250
Deferred tax liability	9,695			8,205
Noncurrent liabilities of discontinued operations	—			172
Total liabilities	1,234,754			1,430,074
Commitments and contingencies (Note 18)
Convertible preferred units (Note 14)	343,579			334,090
Equity and partners’ capital
General Partner interests (953 thousand and 680 thousand units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively)	(86,224		)	(47,645		)
Limited Partner interests (52,740 thousand and 51,351 thousand units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively)	517,081			616,087
Accumulated other comprehensive income (loss)	2			(40		)
Total partners’ capital	430,859			568,402
Noncontrolling interests	14,015			16,755
Total equity and partners’ capital	444,874			585,157
Total liabilities, equity and partners’ capital	$	2,023,207		$	2,349,321

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Table of Contents

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited, in thousands, except per unit amounts)



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Revenue:
Commodity sales	$	124,052		$	119,194		$	372,049		$	304,084
Services	38,835			40,385			116,382			110,998
Gain (loss) on commodity derivatives, net	(597		)	324			(33		)	(1,929		)
Total revenue	162,290			159,903			488,398			413,153
Operating expenses:
Costs of sales	112,398			107,249			342,886			270,712
Direct operating expenses	20,705			17,571			56,819			53,872
Corporate expenses	27,083			22,103			84,570			60,945
Depreciation, amortization and accretion	26,781			22,668			78,834			65,937
(Gain) loss on sale of assets, net	(4,061		)	36			(4,064		)	297
Total operating expenses	182,906			169,627			559,045			451,763
Operating loss	(20,616		)	(9,724		)	(70,647		)	(38,610		)
Other income (expense), net
Interest expense	(17,759		)	(5,830		)	(51,037		)	(24,723		)
Other income (expense), net	34,085			(1		)	32,248			245
Earnings in unconsolidated affiliates	16,827			10,468			49,781			29,513
Income (loss) from continuing operations before income taxes	12,537			(5,087		)	(39,655		)	(33,575		)
Income tax expense	(731		)	(401		)	(2,611		)	(1,839		)
Income (loss) from continuing operations	11,806			(5,488		)	(42,266		)	(35,414		)
Income (loss) from discontinued operations, including net gain on disposition of $46.5 million (Note 4)	44,696			(2,310		)	42,185			7,532
Net income (loss)	56,502			(7,798		)	(81		)	(27,882		)
Less: Net income attributable to noncontrolling interests	621			1,241			3,386			2,192
Net income (loss) attributable to the Partnership	$	55,881		$	(9,039	)	$	(3,467	)	$	(30,074	)

General Partner’s interest in net income (loss)	$	697		$	(31	)	$	(98	)	$	(235	)
Limited Partners’ interest in net income (loss)	$	55,184		$	(9,008	)	$	(3,369	)	$	(29,839	)

Distribution declared per common unit ⁽¹⁾	$	0.4125		$	0.4125		$	1.2375		$	1.2975
Limited Partners’ net income (loss) per common unit (Note 16):
Basic and diluted:
Income (loss) from continuing operations	$	0.05		$	(0.29	)	$	(1.35	)	$	(1.14	)
Income (loss) from discontinued operations	0.86			(0.05		)	0.81			0.15
Net income (loss)	$	0.91		$	(0.34	)	$	(0.54	)	$	(0.99	)
Weighted average number of common units outstanding:
Basic and diluted	52,021			51,310			52,021			51,310

____________________________

⁽¹⁾ Declared and paid each quarter related to prior quarter.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Table of Contents

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

(Unaudited, in thousands)



	Three months ended September 30,					Nine months ended September 30,
	2017		2016			2017			2016
Net income (loss)	$	56,502	$	(7,798	)	$	(81	)	$	(27,882	)
Unrealized gain (loss) related to postretirement benefit plan	—		(2		)	42			33
Comprehensive income (loss)	56,502		(7,800		)	(39		)	(27,849		)
Less: Comprehensive income attributable to noncontrolling interests	621		1,241			3,386			2,192
Comprehensive income (loss) attributable to the Partnership	$	55,881	$	(9,041	)	$	(3,425	)	$	(30,041	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Table of Contents

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Changes in Partners’ Capital

and Noncontrolling Interests

(Unaudited, in thousands)



	General Partner Interests			Limited Partner Interests			Series B Convertible Units			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Capital			Non controlling Interests			Total Equity and Partners’ Capital
Balances at December 31, 2015	$	(47,091	)	$	753,388		$	33,593		$	40		$	739,930		$	12,111		$	752,041
Net income (loss)	(235		)	(29,839		)	—			—			(30,074		)	2,192			(27,882		)
Issuance of common units, net of offering costs	—			2,955			—			—			2,955			—			2,955
Cancellation of escrow units	—			(6,817		)	—			—			(6,817		)	—			(6,817		)
Conversion of Series B units	—			33,593			(33,593		)	—			—			—			—
Contributions	1,901			7,500			—			—			9,401			—			9,401
Distributions	(7,637		)	(96,134		)	—			—			(103,771		)	—			(103,771		)
Issuance of warrant	4,481			—			—			—			4,481			—			4,481
General Partner’s contribution for acquisition	990			—			—			—			990			—			990
Contributions from noncontrolling interests owners	—			—			—			—			—			649			649
LTIP vesting	(3,163		)	3,163			—			—			—			—			—
Tax netting repurchase	—			(514		)	—			—			(514		)	—			(514		)
Equity compensation expense	2,892			1,393			—			—			4,285			—			4,285
Post-retirement benefit plan	—			—			—			33			33			—			33
Addition of Mesquite noncontrolling interest	—			—			—			—			—			1,230			1,230
Acquisition of Gulf of Mexico Pipeline																1,831			1,831
Balances at September 30, 2016	$	(47,862	)	$	668,688		$	—		$	73		$	620,899		$	18,013		$	638,912

Balances at December 31, 2016	$	(47,645	)	$	616,087		$	—		$	(40	)	$	568,402		$	16,755		$	585,157
Net income (loss)	(98		)	(3,369		)	—			—			(3,467		)	3,386			(81		)
Contributions	38,270			4,000			—			—			42,270						42,270
Distributions	(976		)	(93,144		)	—			—			(94,120		)				(94,120		)
Contributions from noncontrolling interests owners	—			—			—			—			—			296			296
Distributions to noncontrolling interests owners	—			—			—			—			—			(1,777		)	(1,777		)
Distribution for acquisition of Delta House (Note 10)	(75,572		)	—			—			—			(75,572		)	—			(75,572		)
Issuance of common units for Panther acquisition (Note 3)	—			12,532			—			—			12,532			—			12,532
Acquisition of noncontrolling interest (Note 3)	—			(23,653		)	—			—			(23,653		)	(4,645		)	(28,298		)
LTIP vesting	(4,633		)	4,633			—			—			—			—			—
Tax netting repurchase	—			(1,642		)	—			—			(1,642		)	—			(1,642		)
Equity compensation expense	4,430			1,637			—			—			6,067			—			6,067
Post-retirement benefit plan	—			—			—			42			42			—			42
Balances at September 30, 2017	$	(86,224	)	$	517,081		$	—		$	2		$	430,859		$	14,015		$	444,874

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Table of Contents

American Midstream Partners, LP and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited, in thousands)



	Nine months ended September 30,
	2017			2016
Cash flows from operating activities
Net loss	$	(81	)	$	(27,882	)
Adjustments to reconcile net loss to net cash provided by operating activities including discontinued operations:
Depreciation, amortization and accretion	88,700			78,168
Amortization of deferred financing costs	3,610			2,328
Corporate overhead support from General Partner	4,000			7,500
Amortization of weather derivative premium	753			708
Unrealized loss on derivatives contracts, net	2,818			1,803
Non-cash compensation expense	6,067			4,285
Gain on MPOG acquisition (Note 3)	(32,383		)	—
(Gain) loss on sale of assets and business, net of transaction costs of $2.5 million (Note 4)	(50,580		)	2,247
Other non-cash items	1,842			(1,590		)
Earnings in unconsolidated affiliates	(49,781		)	(29,513		)
Distributions from unconsolidated affiliates	49,781			29,513
Deferred tax expense	1,490			1,276
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable	(4,172		)	1,140
Inventory	(4,011		)	(5,593		)
Unbilled revenue	696			3,853
Risk management assets and liabilities	(974		)	(1,030		)
Other current assets	10,624			9,496
Other assets, net	(1,994		)	772
Restricted cash	(3,135		)	—
Accounts payable	(17,419		)	(4,497		)
Accrued gas purchases	8,805			1,904
Accrued expenses and other current liabilities	8,889			10,466
Asset retirement obligations	(603		)	(598		)
Other liabilities	426			(697		)
Net cash provided by operating activities	23,368			84,059
Cash flows from investing activities
Acquisitions, net of cash acquired and settlements (Note 3)	(71,383		)	(2,676		)
Investments in unconsolidated affiliates (Note 10)	(49,828		)	(114,007		)
Additions to property, plant and equipment and other	(66,039		)	(85,652		)
Proceeds from sale of business and assets, net of cash on hand	167,979			11,761
Insurance proceeds from involuntary conversion of property, plant and equipment	150			—
Distributions from unconsolidated affiliates, return of capital	9,196			33,284
Restricted cash	302,736			(43,691		)
Net cash provided by (used in) investing activities	292,811			(200,981		)
Cash flows from financing activities
Proceeds from issuance of common units to public, net of offering costs	—			2,910
Unitholder distributions for common control transactions	(75,572		)	—
Contributions	38,270			1,901
Distributions	(88,851		)	(82,782		)
Series C Units issuance cost	—			(62		)
Acquisition of noncontrolling interests	—			1,831
Contribution from noncontrolling interest owners	296			649
Distributions to noncontrolling interests owners	(1,777		)	—

Table of Contents



	Nine months ended September 30,
	2017			2016
LTIP tax netting unit repurchase	(1,642		)	(514		)
Payment of deferred financing costs	(2,234		)	(3,987		)
Proceeds from 3.77% Senior Notes	—			60,000
Payment of 3.77% Senior Notes	(1,351		)	—
Payments of other debt	(3,732		)	(2,769		)
Payments of credit agreement	(546,408		)	(172,650		)
Borrowings on credit agreement	367,809			317,243
Other	86			(188		)
Net cash provided by (used in) financing activities	(315,106		)	121,582
Net increase in cash and cash equivalents	1,073			4,660
Cash and cash equivalents
Beginning of period	5,666			1,987
End of period	$	6,739		$	6,647

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

Table of Contents

American Midstream Partners, LP and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(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, 2009 to 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% indirectly owned by Magnolia Infrastructure Holdings, LLC, both of which are affiliates of ArcLight Capital Partners, LLC ("ArcLight"). Our capital accounts consist of notional General Partner units and units representing limited partner interests.

JPE Acquisition

On March 8, 2017, we completed the acquisition of JP Energy Partners LP (“JPE”), an entity controlled by ArcLight affiliates, in a unit-for-unit merger (“JPE Acquisition”). In connection with the transaction, we issued approximately 20.2 million common units to holders of the JPE common and subordinated units, including 9.8 million common units to ArcLight affiliates. In connection with the completion of the JPE Acquisition, we entered into a supplemental indenture pursuant to which the JPE Entities jointly and severally, fully and unconditionally, guarantee the 8.50% Senior Notes (as defined below).

As both we and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. Although we are the legal acquirer, JPE was considered the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of us on April 15, 2013. As a result, we adjusted our historical financial statements to reflect ArcLight’s acquisition cost basis of their investment in us back to April 15, 2013. In addition, the accompanying financial statements and related notes have been retrospectively adjusted to include the historical results of JPE prior to the effective date of the JPE Acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of JPE at historical cost.

Disposition of Propane Business

On September 1, 2017, we completed the disposition of our Propane Marketing Services business the ("Propane Business") pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholly owned subsidiary of the Partnership, and SHV Energy N.V. As a result of the disposition of our Propane Business, we classified the results of operations of the Propane Business as discontinued operations. See Note 4 - Discontinued Operations.

Nature of business

We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our five reportable segments, (1) gas gathering and processing services, (2) liquid pipelines and services, (3) natural gas transportation services, (4) offshore pipelines and services and (5) terminalling 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 and condensates; storing specialty chemical products and selling refined products.

Most of our cash flow is generated from fee-based and fixed-margin arrangements for gathering, processing, transporting and treating natural gas and crude oil, firm capacity reservation charges, interruptible transportation 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. Our gathering 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 Eagle Ford Shale of South Texas, (iv) the Bakken Shale of North Dakota, and (v) offshore in the Gulf of Mexico. Our natural gas transportation, offshore pipelines and terminal assets are in key demand markets in Alabama, Arkansas, Louisiana, Mississippi and Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia.

Table of Contents

Basis of presentation

The financial statements and supplementary data, management’s discussion and analysis of financial condition and results of operations and certain selected financial data in our Form 10-K for the year ended December 31, 2016 (the “Annual Report”), as filed with the U.S. Securities and Exchange Commission (the “SEC”) on March 28, 2017, were recast by the Current Report on Form 8-K, dated September 18, 2017 (“Recast Form 8-K”). There have been no revisions or updates to any other sections of the Annual Report other than the revisions noted above.

The unaudited financial information included in this Quarterly Report has been prepared on the same basis as the audited consolidated financial statements included in the Recast Form 8-K, and recast to retrospectively reflect the change in classification of the Propane Business to discontinued operations for all periods presented. The results of operations for the three and nine months ended September 30, 2017 are not necessarily indicative of results expected for the full year. In the opinion of our management, such financial information reflects all adjustments necessary for a fair statement of the financial position and the results of operations for such interim periods in accordance with GAAP. All such adjustments are of a normal recurring nature. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Transactions between entities under common control

We have entered, and may enter, into transactions with ArcLight affiliates whereby we receive midstream assets or other businesses in exchange for cash or Partnership equity. We account for the net assets acquired at the affiliate's historical cost basis as the transactions are between entities under common control. In certain cases, our historical financial statements were revised to include the results attributable to the assets acquired from the later of June 2011 (the date Arclight affiliates obtained control of JPE) or the date the ArcLight affiliate obtained control of the assets acquired.

Summary of Significant Accounting Policies

Use of estimates

When preparing consolidated financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and assumptions are based on information available at the time such estimates and assumptions are made. Adjustments made with respect to the use of these estimates and assumptions often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates and assumptions are used in, among other things, i) estimating unbilled revenues, product purchases and operating and general and 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, guarantees and 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 of cash 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, asset retirement obligations and contracted arrangements. Such amounts are included in Restricted cash in our unaudited condensed consolidated balance sheets.

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 is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method, historical collection experience and the age of accounts receivable.

Table of Contents

Investments 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 the equity method and are reported in Investment in unconsolidated affiliates in the condensed consolidated balance sheets. We evaluate 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. The unconsolidated affiliates that were determined to be variable interest entities (“VIE”) due to disproportionate economic interests and decision making rights were further evaluated under the VIE method of consolidation. In each case, we lack the power to direct the activities that most significantly impact the unconsolidated affiliate’s economic performance. Therefore, as we do not hold a controlling financial interest in these affiliates, we account for our related investments using the equity method. Additionally, our maximum exposure to loss related to each entity is limited to our equity investment as presented on the condensed consolidated balance sheets as of the balance sheet date. In each case, we are not obligated to absorb losses greater than our proportional ownership percentages. Our right to receive residual returns is not limited to any amount less than the ownership percentages. We also have a joint venture arrangement in which we and our partners share proportional ownership and responsibilities and receive returns in accordance with our ownership percentage.

Revenue recognition

We recognize revenue from the sale of commodities (e.g., natural gas, crude oil, NGLs, refined products 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 or services have been rendered, iii) the price is fixed or determinable, and iv) collectability is reasonably assured. We recognize revenue from the sale of commodities and 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.

Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales taxes, are presented on a net basis within the unaudited condensed consolidated statements of operations.

(2) New Accounting Pronouncements

Accounting Standards Issued Not Yet Adopted

In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which amends the existing accounting guidance for revenue 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 that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2015-14 was subsequently issued and deferred the effective date to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that period. From March 2016 to May 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal Versus Agent Considerations, as further clarification on principal versus agent considerations; ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, as clarifying guidance on specific narrow scope improvements and practical expedients. We are in the process of reviewing our various customer arrangements in order to determine the impact the new accounting guidance for revenue recognition will have on our consolidated financial statements and related disclosures. We also have engaged a third-party consulting firm to assist us with all the three phases of adoption of the new guidance (Impact Assessment, Convert and Implement). We are currently in the Convert phase and revenue streams have been determined. Certain preliminary testing has been performed to validate such streams. We will adopt the new standard on its effective date January 1, 2018 using the modified retrospective method of adoption.

In February 2016, the FASB issued ASU No. 2016-02 (Topic 842) "Leases", which supersedes the lease recognition requirements in ASC Topic 840, "Leases". Under ASU No. 2016-02 lessees are required to recognize assets and liabilities on the balance sheet for most leases and provide enhanced disclosures. Leases will continue to be classified as either finance or operating. ASU No. 2016-02 is effective for annual reporting periods, and interim periods within those years beginning after December 15, 2018. Entities are required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, and there are certain optional practical expedients that an entity may elect to apply. Full retrospective application is prohibited and early adoption by public entities is permitted. We are in the process of evaluating the impact of ASU 2016-02 on our consolidated financial statements as we will be required to reflect our various lease

Table of Contents

obligations and associated asset use rights on our consolidated balance sheets. The adoption may also impact our debt covenant compliance and may require us to modify or replace certain of our existing information systems. We will adopt the guidance on its effective date January 1, 2019.

In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments”, which addresses eight 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. The retrospective transition method of adoption is required unless it is impracticable. Early adoption is permitted, but only if all aspects are adopted in the same period. We are still evaluating the impact of this update on our consolidated statements of cash flows and the related disclosures. We will adopt the standard upon its effective date January 1, 2018.

In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash”, which aims to improve the disclosure of the change during the period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts 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 interim period. 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 and should be applied using a retrospective transition method to each period. We will adopt the standard on its effective date of January 1, 2018.

In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business”. The guidance provides criteria for use in determining when to conclude an integrated “set of assets and activities (as defined in the original guidance) being acquired or disposed in a transaction is not a business. Where the criteria are not met, more stringent screening has been provided to define a set as a business without an output, as more narrowly defined within the guidance. ASU No. 2017-01 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after the effective date. Early adoption is permitted. We are still in the process of evaluating the guidance and can not determine the impact of this guidance on our consolidated financial statements and related disclosures. We will adopt ASU 2017-01 on its effective date of January 1, 2018.

In January 2017, the FASB issued ASU No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”, in which the guidance on testing for goodwill was updated by the elimination of Step 2 in the determination on whether goodwill should be considered impaired. The annual and/or interim assessments are still required to be completed. Further, the guidance eliminates the requirement to assess reporting units with zero or negative carrying values, however, the carrying values for all reporting units must be disclosed. ASU No. 2017-04 is effective for annual or any interim goodwill impairment tests beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to early adopt the guidance in connection with our annual assessment to be performed in October 2017 using the required prospective method.

In May 2017, the FASB issued ASU No. 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting”, to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Pursuant to this ASU, an entity should account for the effects of a modification unless all the following are met: (1) the fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the modified award is the same as the fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the original award immediately before the original award is modified (if the modification does not affect any of the inputs to the valuation technique that the entity uses to value the award, the entity is not required to estimate the value immediately before and after the modification); (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. ASU No. 2017-09 is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted, including adoption in any interim period. This update should be applied prospectively to an award modified on or after the adoption date. We do not believe that the impact of this update on our consolidated financial statements and related disclosures will be material and will adopt the guidance on its effective date January 1, 2018.

Table of Contents

(3) Acquisitions

JP Energy Partners LP

On March 8, 2017, we completed the acquisition of JPE, a legal entity controlled by ArcLight affiliates, in a unit-for-unit merger. In connection with the transaction, each JPE common or subordinated unit held by investors not affiliated with ArcLight was converted into the right to receive 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 0.5225 of a Partnership common unit. We issued a total of 20.2 million of common units to complete the acquisition, including 9.8 million common units to ArcLight affiliates.

As both we and JPE were controlled by ArcLight affiliates, the acquisition represented a transaction among entities under common control. Although we were the legal acquirer, JPE was considered the acquirer for accounting purposes as ArcLight obtained control of JPE prior to obtaining control of us on April 15, 2013. As a result, we adjusted our historical financial statements to reflect ArcLight’s acquisition cost basis of us back to April 15, 2013. In addition, the accompanying financial statements and related notes have been retrospectively adjusted to include the historical results of JPE prior to the effective date of the JPE acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of JPE at historical cost.

JPE owns, operates and develops a diversified portfolio of midstream energy assets which provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs, in the United States.

Viosca Knoll

On June 2, 2017, we acquired 100% of the Viosca Knoll System (“Viosca Knoll”) from Genesis Energy, L.P. for total consideration of approximately $32 million in cash and have accounted for this acquisition as a business combination. The Viosca Knoll System serves producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico and connects to several major delivery pipelines including the Partnership’s High Point and Destin pipelines. Viosca Knoll will provide greater East-West Gulf connectivity, through the connection of the High Point Gas Transmission system and the Destin Pipeline, both controlled by us. The Viosca Knoll acquisition was funded with the borrowings under the Partnership’s revolving credit facility, and Viosca Knoll was added to our Offshore pipeline and services segment.

The following table presents our aggregated allocation of the purchase price based on estimated fair values of assets and liabilities acquired (in thousands):



As of September 30, 2017	Purchase Price Allocation
Property, plant and equipment:
Pipelines and right-of-way	$	13,433
Equipment	18,853
Total property, plant and equipment	32,286
Liability	(286		)
Total cash consideration	$	32,000

The purchase price allocation is subject to the measurement period that ends at the earlier of twelve months from the date of acquisition or when all information becomes available. We have reallocated approximately $3.3 million from Intangibles to Property, plant and equipment since the initial purchase price allocation disclosed in the second quarter of 2017.

Table of Contents

Panther

On August 8, 2017, the Partnership acquired 100% of the interest in Panther Offshore Gathering Systems, LLC (“POGS”), Panther Pipeline, LLC (“PPL”) and Panther Operating Company, LLC (“POC”) from Panther Asset Management LLC (“Panther”) for approximately $57.2 million. The consideration included $39.1 million cash, funded from borrowings under the Partnership’s revolving credit facility, and common units representing limited partner interests in the Partnership, valued at $12.5 million based on unit value as of the acquisition date. Panther owns and operates more than 1,000 miles of oil and gas pipelines, primarily in Texas and Louisiana offshore state and federal waters. The underlying acquired assets are highly complementary to the Partnership’s core Gulf of Mexico assets as a substantial portion of Panther’s cash flows are generated by our joint ventures.

As part of the purchase of POGS, we acquired the outstanding interests in one of our equity investments, Main Pass Oil Gathering (“MPOG”), as well as the remaining equity interest in our consolidated subsidiary, American Panther, LLC (“AmPan”). As such, the Partnership now owns 100% of MPOG and AmPan. We determined that the acquisition of the remaining interest in MPOG on August 8, 2017 resulted in a change in control and MPOG has been consolidated from the acquisition date. The effect was the Partnership’s previously held equity interest in MPOG was remeasured to fair value and the excess (approximately $32.3 million) of fair value over historical carrying value was recognized as a gain in Other income (expense) on the unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017.

For AmPan, which has historically been consolidated by the Partnership, the acquisition of Panther’s remaining interest resulted in the acquisition of a noncontrolling interest. Accordingly the excess of the fair value of the acquired interest (approximately $28.3 million) over the carrying value of the noncontrolling interest (approximately $4.6 million) has been reported as a distribution to unitholders.

PPL owns a 50% undivided ownership interest in the Matagorda and the Brazoria County Gas systems which will be proportionally consolidated from the acquisition date. POC operates pipeline assets on behalf of both third parties and affiliates of the Partnership for a fee and will be fully consolidated by the Partnership.

The following table presents the aggregated preliminary allocation of the purchase price based on estimated fair values of Panther’s assets acquired and liabilities assumed (in thousands):



	Purchase Price Allocation
Fair value of acquired noncontrolling interest	$	28,298
Property, plant and equipment	16,870
Intangibles (customer relationships)	9,989
Net working capital, net of cash acquired	2,410
Other	2,975
Asset retirement obligation	$	(3,367	)
Total consideration	$	57,175

The purchase price allocation is subject to the measurement period that ends at the earlier of twelve months from the acquisition date or when all information becomes available.

The pro forma effect of our business acquisitions was immaterial to our unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2017 and the comparative periods, respectively, and therefore is not separately disclosed.

(4) Discontinued Operations

Disposition of Propane Business

On September 1, 2017, we completed the disposition of the Propane Business pursuant to the Membership Interest Purchase Agreement dated July 21, 2017, between AMID Merger LP, a wholly owned subsidiary of the Partnership, and SHV Energy N.V. Through the transaction, we divested 100% of our Propane Business, including Pinnacle Propane’s 40 service locations; Pinnacle Propane Express’ cylinder exchange business and related logistic assets; and the Alliant Gas utility system. Prior to the sale, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment. With the disposition of the Propane Business, we eliminated the Propane Marketing Services segment.

Table of Contents

In connection with the transaction, we received approximately $170 million in cash, net of customary closing adjustments, and recorded a gain of approximately $46.5 million, net of $2.5 million of transaction costs. We have reported the results of our Propane Business, including the gain on sale, as discontinued operations in our unaudited condensed consolidated statements of operations for all periods presented.

The following tables summarize the financial information related to the Propane Business for the periods presented, as required by ASC 420 - Discontinued Operations.

Unaudited Condensed Consolidated Balance Sheet of the discontinued operation Propane Business (in thousands)



	December 31, 2016
Total current assets of discontinued operations	$	22,727
Total noncurrent assets of discontinued operations	114,032
Total assets of discontinued operations	$	136,759

Total current liabilities of discontinued operations	$	14,319
Other long-term liabilities of discontinued operations	172
Total liabilities of discontinued operations	$	14,491

Unaudited Condensed Consolidated Statements of Operations of the discontinued operation Propane Business (in thousands)



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016⁽¹⁾
Total revenue	$	20,458		$	27,756		$	87,615		$	103,718
Total operating expenses	22,489			30,158			92,196			96,003
Income (loss) from discontinued operations before taxes	(1,834		)	(2,310		)	(4,301		)	8,069
Income tax benefit (expense)	(15		)	—			(59		)	2
Income (loss) from discontinued operations	(1,849		)	(2,310		)	(4,360		)	8,071
Gain from the sale of discontinued operations	46,545			—			46,545			—
Partnership’s income (loss) from discontinued operations, including gain on sale.	$	44,696		$	(2,310	)	$	42,185		$	8,071

_____________________________________

⁽¹⁾Amounts for the nine months ended September 30, 2016 do not included the results of certain trucking and marketing assets of JPE in the Mid-Continent area (the “Mid Continent Business”), which were sold in the first quarter of 2016 and are classified as discontinued operations. The total revenue, total operating expenses and loss from discontinued operations related to the Mid Continent Business for the nine months ended September 30, 2016 were $11.5 million, $12.0 million and $0.5 million respectively.

Other selected unaudited financial information related to the Propane Business (in thousands)



	Three months ended September 30,					Nine months ended September 30,
	2017			2016		2017			2016
Depreciation and amortization	$	2,355		$	3,850	$	9,823		$	12,020
Capital expenditures	722			1,483		3,143			3,451

Other operating and investing non-cash items related to discontinued operations:
(Gain) loss on sales of assets, net	118			725		(55		)	2,064
Unrealized (gain) loss on derivatives contracts, net	(526		)	106		530			(628		)

Table of Contents

(5) Inventory

Inventory consists of the following (in thousands):



	September 30, 2017		December 31, 2016
Crude oil	$	4,565	$	1,216
NGLs	232		288
Refined products	674		—
Materials, supplies and equipment	499		486
Total inventory	$	5,970	$	1,990

(6) Other Current Assets

Other current assets consist of the following (in thousands):



	September 30, 2017		December 31, 2016
Prepaid insurance	$	1,428	$	9,702
Insurance receivables	3,728		1,624
Due from related parties	5,062		4,833
Other receivables	2,768		2,997
Risk management assets	1,827		469
Other assets	2,331		5,891
Total other current assets	$	17,144	$	25,516

(7) Risk Management Activities

We are exposed to certain market risks related to the volatility of commodity prices and changes in interest rates. To monitor and manage these market risks, we have established comprehensive risk management policies and procedures. We do not enter into derivative instruments for any purpose other than hedging commodity price risk, interest rate risk, and weather risk. We do not speculate using derivative instruments.

Commodity Derivatives

To manage the impact of the risks associated with changes in the market price of NGL purchases, crude oil, refined products and natural gas in our day-to-day business, we used a combination of fixed price swap and forward contracts.

Our forward contracts that qualify for the Normal Purchase Normal Sale (“NPNS”) exception under GAAP are recognized when the underlying physical transaction is delivered. In accordance with ASC 815, Derivatives and Hedging, if it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet (as an asset or liability) and the difference between the fair value and the contract amount is immediately recognized through earnings. We measure our commodity derivatives at fair value using the income approach which discounts the future net cash settlements expected under the derivative contracts to a present value. These valuations utilize indirectly observable (“Level 2”) inputs, including contractual terms and commodity prices observable at commonly quoted intervals.

The following table summarizes the net notional volumes of our outstanding commodity-related derivatives, excluding those contracts that qualified for the NPNS exception as of September 30, 2017 and December 31, 2016, none of which were designated as hedges for accounting purposes.

Table of Contents



	September 30, 2017		December 31, 2016
Commodity Swaps	Volume	Maturity	Volume	Maturity
NGLs Fixed Price (gallons)	819,000	January 8, 2018
Crude Oil Fixed Price (barrels)	125,000	October 6, 2017 - December 7, 2017	—	—
Crude Oil Basis (barrels)	—	—	180,000	January 25, 2017- March 25, 2017

Interest Rate Swaps

To manage the impact of the interest rate risk associated with our Credit Agreement, as defined in Note 13 - Debt Obligations, we enter into interest rate swaps from time to time, effectively converting a portion of the cash flows related to our long-term variable rate debt into fixed rate cash flows.

As of September 30, 2017 and December 31, 2016, we had a combined notional principal amount of $650.0 million of variable to fixed interest rate swap agreements. As of September 30, 2017, the maximum length of time over which we have hedged a portion of our exposure due to interest rate risk is through December 31, 2022.

The fair value of our interest rate swaps was estimated using a valuation methodology based upon forward interest rates and volatility curves as well as other relevant economic measures, if necessary. Discount factors may be utilized to extrapolate a forecast of future cash flows associated with long dated transactions or illiquid market points. The inputs, which represent Level 2 inputs in the valuation hierarchy, are obtained from independent pricing services and we have made no adjustments to those prices.

Weather Derivative

In the second quarter of 2017, we entered into a yearly weather derivative arrangement to mitigate the impact of potential unfavorable weather on our operations under which we could receive payments totaling up to $30.0 million in the event that a hurricane of certain strength passes through the areas identified in the derivative agreement. The weather derivative, which is accounted for using the intrinsic value method, was entered into with a single counterparty, and we were not required to post collateral.

We paid $1.1 million and $1.0 million in premiums during the nine months ended September 30, 2017 and 2016, respectively. Premiums are amortized to Direct operating expenses on a straight-line basis over the one year term of the contract. Unamortized amounts associated with the weather derivatives were approximately $0.8 million and $0.4 million as of September 30, 2017 and December 31, 2016, respectively, and are included in Other current assets on the unaudited condensed consolidated balance sheets.

The following table summarizes the fair values of our derivative contracts (before netting adjustments) included in the condensed consolidated balance sheets (in thousands):



		Asset Derivatives				Liability Derivatives
Type	Balance Sheet Classification	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016
Commodity swaps	Other current assets	$	267	$	112	$	—		$	—
Commodity swaps	Accrued expenses and other current liabilities	—		—		(653		)	(1		)
Commodity swaps	Other liabilities	—		—		—			(1		)

Interest rate swaps	Other current assets	1,041
Interest rate swaps	Risk management assets (long-term)	7,545		10,628		—			—
Interest rate swaps	Accrued expenses and other current liabilities	—		—		—			(252		)

Weather derivatives	Other current assets	$	786	$	429	$	—		$	—
	Total	$	9,639	$	11,169	$	(653	)	$	(254	)

Table of Contents

The following tables present the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset in the condensed consolidated balance sheets that are subject to enforceable master netting arrangements (in thousands):



	Gross Risk Management Position						Netting Adjustments						Net Risk Management Position
Balance Sheet Classification	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016
Other current assets	$	2,094		$	541		$	(267	)	$	(72	)	$	1,827		$	469
Risk management assets- long term	7,545			10,628			—			(1		)	7,545			10,627
Total assets	$	9,639		$	11,169		$	(267	)	$	(73	)	$	9,372		$	11,096

Accrued expenses and other liabilities	$	(653	)	$	(253	)	$	267		$	72		$	(386	)	$	(181	)
Other liabilities	—			(1		)	—			1			—			—
Total liabilities	$	(653	)	$	(254	)	$	267		$	73		$	(386	)	$	(181	)

For each of the three and nine months ended September 30, 2017 and 2016 the realized and unrealized gains (losses) associated with our commodity, interest rate and weather derivative instruments were recorded in our unaudited condensed consolidated statements of operations as follows (in thousands):



	Three months ended September 30,						Nine months ended September 30,
Statement of Operations Classification	Realized			Unrealized			Realized			Unrealized
2017
Gains (losses) on commodity derivatives, net	$	(51	)	$	(546	)	$	465		$	(498	)
Interest expense	51			221			(19		)	(1,790		)
Direct operating expenses	(278		)	—			(753		)	—
Total	$	(278	)	$	(325	)	$	(307	)	$	(2,288	)
2016
Gains (losses) on commodity derivatives, net	$	(742	)	$	1,066		$	(1,432	)	$	(497	)
Interest expense	(75		)	2,109			(106		)	(1,934		)
Direct operating expenses	(257		)	—			(708		)	—
Total	$	(1,074	)	$	3,175		$	(2,246	)	$	(2,431	)

(8) Property, Plant and Equipment

Property, plant and equipment, net, consists of the following (in thousands):



	Useful Life (in years)	September 30, 2017			December 31, 2016
Land	Infinite	$	18,440		$	18,861
Construction in progress	N/A	81,133			128,519
Buildings and improvements	4 to 40	13,782			13,762
Transportation equipment	5 to 15	22,743			20,010
Processing and treating plants	8 to 40	141,334			120,977
Pipelines, compressors and right-of-way	3 to 40	958,004			804,815
Storage	3 to 40	146,473			146,408
Equipment	3 to 31	79,567			77,978
Total property, plant and equipment		1,461,476			1,331,330
Accumulated depreciation		(320,650		)	(264,722		)
Property, plant and equipment, net		$	1,140,826		$	1,066,608

At September 30, 2017 and December 31, 2016, gross property, plant and equipment included $314.8 million and $291.1 million, respectively, related to our FERC regulated interstate and intrastate assets.

Table of Contents

Depreciation expense totaled $20.1 million and $17.8 million for the three months ended September 30, 2017 and 2016, respectively, and $56.9 million and $51.6 million for the nine months ended September 30, 2017 and 2016, respectively.

Capitalized interest was $0.5 million and $0.7 million for each of the three months ended September 30, 2017 and 2016, respectively and $2.0 million and $1.7 million for the nine months ended September 30, 2017 and 2016, respectively.

(9) Goodwill and Intangible Assets

Goodwill consists of the following (in thousands):



	September 30, 2017		December 31, 2016
Liquid Pipelines and Services	$	113,671	$	113,671
Terminalling Services	88,464		88,464
Total	$	202,135	$	202,135

Intangible assets, net, consists of customer relationships, dedicated acreage agreements, collaborative arrangements, noncompete agreements and trade names. 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 44 years.

Intangible assets, net, consist of the following (in thousands):



	September 30, 2017
	Gross carrying amount		Accumulated amortization			Net carrying amount
Customer relationships	$	116,345	$	(28,088	)	$	88,257
Customer contracts	94,693		(46,927		)	47,766
Dedicated acreage	53,350		(5,773		)	47,577
Collaborative arrangements	11,884		(1,203		)	10,681
Noncompete agreements	1,064		(1,064		)	—
Other	198		(23		)	175
Total	$	277,534	$	(83,078	)	$	194,456

	December 31, 2016
	Gross carrying amount		Accumulated amortization			Net carrying amount
Customer relationships	$	106,417	$	(23,245	)	$	83,172
Customer contracts	94,692		(33,228		)	61,464
Dedicated acreage	53,350		(4,439		)	48,911
Collaborative arrangements	11,884		(601		)	11,283
Noncompete agreements	1,063		(1,000		)	63
Other	198		(20		)	178
Total	$	267,604	$	(62,533	)	$	205,071

Amortization expense related to our intangible assets totaled $5.1 million and $4.4 million for the three months ended September 30, 2017 and 2016, respectively, and $20.6 million and $13.3 million for the nine months ended September 30, 2017 and 2016, respectively.

(10) Investments in unconsolidated affiliates

Joint Venture with Targa Midstream Services, LLC

On August 8, 2017, we entered into a joint venture agreement with Targa Midstream Services, LLC (“Targa”) by which our previously wholly owned subsidiary Cayenne Pipeline, LLC (“Cayenne”) became the Cayenne joint venture between Targa and us (“Cayenne JV”). We received $5.0 million in cash in exchange for the sale of 50% ownership interest in Cayenne to Targa. The sole asset of the joint venture is a natural gas pipeline which is being converted into a natural gas liquids pipeline. Both parties

Table of Contents

will each have 50% economic interests and 50% voting rights, with Targa serving as the operator of the pipeline and the joint venture. The additional costs of conversion and associated construction are shared equally by us and Targa. By the end of the fourth quarter of 2017, the pipeline is expected to be operational.

Acquisition of additional ownership interest in Delta House

On September 29, 2017, we acquired an additional 15.5% equity interest in Class A units of Delta House FPS LLC (“FPS”) and Delta House Oil and Gas Lateral LLC (“Lateral”) (collectively referred to as “Delta House”), from affiliates of ArcLight for total cash consideration of approximately $125.4 million. FPS operates a semi-submersible floating production and processing system in the Gulf of Mexico. Lateral operates oil and natural gas lateral transportation facilities that receive and transport production from the FPS floating production system. Post-closing, the Partnership and ArcLight indirectly own a 35.7% and 23.3% interest, respectively, in Delta House.

As our 15.5% interest in Delta House was previously owned directly by ArcLight, we have accounted for our investment at our affiliate's carry-over basis resulting in $49.8 million recorded in Investments in unconsolidated affiliates in our unaudited condensed consolidated balance sheets, and as an investing activity within the related unaudited condensed consolidated statements of cash flows. The amount by which the total consideration exceeded the carry-over basis was $75.6 million and was recorded as a distribution to our general partner within the unaudited condensed consolidated statements of changes in partners’ capital and noncontrolling interests and a financing activity in the unaudited condensed consolidated statements of cash flows.

For the three and nine months ended September 30, 2017, the Partnership recorded $12.5 million and $34.6 million, respectively, in equity earnings from Delta House. The Partnership also received cash distributions of $10.3 million and $26.2 million for the three and nine months ended September 30, 2017, respectively. The excess of the cash distributions received over the earnings recorded from Delta House is classified as a return of capital within cash flows from investing activities in our condensed consolidated statements of cash flows.

The following table presents the activity in our equity method investments in unconsolidated affiliates (in thousands):



	Delta House ⁽¹⁾						Emerald Transactions ⁽²⁾
	FPS			OGL			Destin			Tri-States			Okeanos			Wilprise			MPOG⁽⁴⁾			Cayenne JV⁽³⁾			Total
Ownership % - 12/31/2016	20.1		%	20.1		%	49.7		%	16.7		%	66.7		%	25.3%			66.7%			-
Ownership % - 9/30/2017	35.7		%	35.7		%	49.7		%	16.7		%	66.7		%	25.3%			-			50.0		%

Balances at December 31, 2016	$	64,483		$	25,450		$	110,882		$	55,022		$	27,059		$	4,944		$	4,147		$	—		$	291,987
Acquisitions	22,539			27,289			—			—			—			—			(2,363		)	—			47,465
Earnings in unconsolidated affiliates	23,994			10,589			6,243			3,394			5,706			493			(683		)	45			49,781
Contributions	—			—			—			—			—			—			—			3,770			3,770
Distributions	(13,990		)	(12,183		)	(17,334		)	(4,359		)	(9,333		)	(677		)	(1,101		)	—			(58,977		)
Balances at September 30, 2017	$	97,026		$	51,145		$	99,791		$	54,057		$	23,432		$	4,760		$	—		$	3,815		$	334,026

^{___________________________________________________}

⁽¹⁾ Represents direct and indirect ownership interests in Class A units and common units.

⁽²⁾ Represents our Emerald equity method investments which were acquired in the second quarter of 2016.

⁽³⁾ We formed Cayenne JV effective August 8, 2017.

⁽⁴⁾ Beginning August 8, 2017, the Partnership consolidated MPOG. See Note 3 - Acquisitions.

Table of Contents

The following tables present the summarized combined financial information for our equity investments (amounts represent 100% of investee financial information) (in thousands):



Balance Sheets⁽¹⁾:	September 30, 2017		December 31, 2016
Current assets	$	100,400	$	120,167
Non-current assets	1,294,333		1,369,492
Current liabilities	139,217		133,085
Non-current liabilities	$	422,988	$	541,312



	Three months ended September 30,				Nine months ended September 30,
Statements of Operations⁽¹⁾:	2017		2016		2017		2016
Revenue	$	104,904	$	93,440	$	304,801	$	278,720
Gross profit	97,636		83,350		280,996		253,447
Net income	$	77,238	$	62,775	$	222,005	$	199,591

_____________________________________

⁽¹⁾ MPOG was consolidated by us as of August 8, 2017, therefore the tables above do not include MPOG as of September 30, 2017 and for the three and nine months ended September 30, 2017.

(11) Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consists of the following (in thousands):



	September 30, 2017		December 31, 2016
Accrued interest	$	9,973	$	5,743
Taxes payable	7,052		1,186
Current portion of asset retirement obligation	6,416		6,499
Additional Blackwater acquisition consideration	5,000		5,000
Due to related parties	5,115		4,072
Royalties payable	3,548		3,926
Convertible preferred unit distributions	2,871		7,103
Legal accrual	2,783		—
Capital expenditures	4,032		14,274
Accrued operating expenses	2,938		—
Gas imbalances payable	1,860		1,098
Customer deposits	1,537		148
Employee compensation	1,505		8,438
Transaction costs	736		3,000
Other	12,139		12,234
Total accrued expenses and other current liabilities	$	67,505	$	72,721

(12) Asset Retirement Obligations

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations (collectively referred to as “AROs”) that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. Generally, the fair value of the liability is calculated using discounted cash flow techniques and based on internal estimates and assumptions related to (i) future retirement costs, (ii) future inflation rates, and (iii) credit-adjusted risk-free interest rates. Significant increases or decreases in the assumptions would result in a significant change to the fair value measurement.

Certain assets related to our Offshore Pipelines and Services segment have regulatory obligations to perform remediation, and in some instances, dismantlement and removal activities when the assets are abandoned. These AROs include varying levels of

Table of Contents

activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transmission services will cease, however, we do not believe that such demand will cease for the foreseeable future. The majority of the current portion of our AROs is related to the retirement of the Midla pipeline discussed in Note 18 - Commitments and Contingencies.

The following table presents activity in our asset retirement obligations for the nine months ended September 30, 2017 (in thousands):



Non-current balance	$	44,363
Current balance	6,499
Balances at December 31, 2016	$	50,862
Additions	6,805
Expenditures	(697		)
Accretion expense	1,492
Balances at September 30, 2017	$	58,462
Less: current portion	6,416
Noncurrent asset retirement obligation	$	52,046

^{___________________________________________________}

We are required to establish security against potential obligations relating to the abandonment of certain transmission assets that may be imposed on the previous owner by applicable regulatory authorities. We have deposited $5.0 million with a third party to secure our performance on these potential obligations. These deposits are included in Restricted cash-long term in our unaudited condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016.

(13) Debt Obligations

Our outstanding debt consists of the following (in thousands):



	September 30, 2017			December 31, 2016
Revolving credit facility	$	709,652		$	888,250
8.50% Senior unsecured notes, due 2021	300,000			300,000
3.77% Senior secured notes, due 2031 (non-recourse)	58,649			60,000
Other debt ⁽²⁾	116			3,762
Total debt obligations	1,068,417			1,252,012
Unamortized debt issuance costs ⁽¹⁾	(9,338		)	(11,036		)
Total debt	1,059,079			1,240,976
Less: Current portion, including unamortized debt issuance costs	(1,234		)	(5,438		)
Long term debt	$	1,057,845		$	1,235,538

___________________________

⁽¹⁾ Unamortized debt issuance costs related to the revolving credit facility are included in our unaudited condensed consolidated balance sheets in Other assets, net.

⁽²⁾ Other debt includes capital lease and miscellaneous long-term obligations, which are reported in Current portion of debt and Other liabilities line items on our unaudited condensed consolidated balance sheets.

Credit Facilities

Revolving Credit Facility

On March 8, 2017, we entered into the Second Amended and Restated Credit Agreement with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders (the “Credit Agreement”) which increased our borrowing capacity from $750.0 million to $900.0 million and provided

Table of Contents

for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion. 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% to 3.25% depending on our total leverage ratio 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 for such 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 from 1.00% 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 revolving loan under the Credit Agreement, which matures on September 5, 2019.

The Credit Agreement contains certain financial covenants that are applicable as of the end of any fiscal quarter, including a consolidated total leverage ratio which requires our indebtedness not to exceed 5.00 times adjusted consolidated EBITDA (except for the fiscal quarters ended March 31, 2017, and the subsequent two quarters, at which time the covenant is increased to 5.50 times adjusted consolidated EBITDA), a consolidated secured leverage ratio which requires our secured indebtedness not to exceed 3.50 times adjusted consolidated EBITDA, and a minimum interest coverage ratio that requires our adjusted consolidated EBITDA to exceed consolidated interest charges by not less than 2.50 times. The letters of credit outstanding as of September 30, 2017 and December 31, 2016 were $33.1 million and $7.4 million, respectively.

As of September 30, 2017, our consolidated total leverage ratio was 4.68 and our interest coverage ratio was 4.41, which were both in compliance with the related requirements of our Credit Agreement. Our ability to maintain compliance with the leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions or drop down transactions, as well as the associated financing for such initiatives.

The carrying value of amounts outstanding under our Credit Agreement approximates the related fair value, as interest charges vary with market rates conditions.

JPE Revolver

JPE had a $275.0 million revolving loan, which included a sub-limit of up to $100.0 million for letters of credit with Bank of America, N.A. (the “JPE Revolver”). The JPE Revolver was scheduled to mature on February 12, 2019, but on March 8, 2017, in connection with the closing of the JPE acquisition, the $199.5 million outstanding balance of the JPE Revolver was paid off in full and terminated.

For the nine months ended September 30, 2017 and 2016, the weighted average interest rate on borrowings under our Credit Agreement was approximately 4.85% and 2.82%, respectively.

8.50% Senior Unsecured Notes

On December 28, 2016, we and American Midstream Finance Corporation, our wholly-owned subsidiary (the “Issuers”), completed the issuance and sale of $300 million in aggregate principal amount of senior notes due 2021 (the “8.50% Senior Notes”). The 8.50% Senior Notes are jointly and severally guaranteed by certain of our existing direct and indirect wholly owned subsidiaries that guarantee our Credit Agreement. 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 of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting the initial purchasers' discount of $6.0 million. This amount was deposited into escrow pending completion of the JPE Acquisition and was included in Restricted cash-long term on our consolidated balance sheet as of December 31, 2016.

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 June 15, 2017.

As of September 30, 2017, the fair value of the 8.50% Senior Notes was $310.2 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.

3.77% Senior Secured 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 (the “Note Purchase Agreement”) with certain institutional investors (the “Purchasers”) whereby Midla Financing issued $60.0 million in aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031.

Table of Contents

Midla Financing must maintain a debt service reserve account containing six months of principal and interest payments, and Midla Financing and the Note Guarantors (including any entities that become guarantors under the terms of the Note Purchase Agreement) are restricted from making distributions (a) until June 30, 2017, (b) unless the debt service coverage ratio is not less than, and is not projected for the following 12 calendar months to be less than, 1.20:1.00, and (c) unless certain other requirements are met.

Net proceeds from the 3.77% Senior Notes are restricted and are used (1) to fund project costs incurred in connection with (a) the construction of the Midla-Natchez Line (b) the retirement of Midla’s existing 1920’s vintage pipeline (c) the move of our Baton Rouge operations to the MLGT system (d) the reconfiguration of the DeSiard compression system and all related ancillary facilities, (2) to pay transaction fees and expenses in connection with the issuance of the 3.77% Senior Notes, and (3) for other general corporate purposes of Midla Financing.

As of September 30, 2017, the fair value of the 3.77% Senior Notes was $55.4 million. This estimate was based on similar private placement transactions along with changes in market interest rates which represent a Level 2 measurement.

(14) Convertible Preferred Units

Our convertible preferred units consist of the following (in thousands):



	Series A			Series C			Series D			Total
	Units	$		Units	$		Units	$		$
December 31, 2016	10,107	$	181,386	8,792	$	118,229	2,333	$	34,475	$	334,090
Paid in kind unit distributions	429	6,645		—	2,844		—	—		9,489
September 30, 2017	10,536	$	188,031	8,792	$	121,073	2,333	$	34,475	$	343,579

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. The convertible preferred unitholders have the right to receive cumulative distributions in the same priority and prior to any other distributions 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 such distribution, the amount of cash available will be paid to our convertible preferred unitholders on a pro rata basis while the difference between the distribution and the available cash will become arrearages and accrue interest until paid.

Series A-1 Convertible Preferred Units

On April 15, 2013, we, 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 in exchange 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 $0.4125 per unit or the declared distribution to common unitholders. The Series A-1 Units may be converted into common units, subject to customary anti-dilutive adjustments, at the option of the unitholders on or any time after January 1, 2014. As of September 30, 2017, the conversion price is $15.24 and the conversion ratio is 1 to 1.1483.

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 we issued, in separate private placements, newly-designated Series A-2 Units (the “Series A-2 Units”) 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 with common 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 made in 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 and transfer 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 any equity distribution, subdivision or combination of equity

Table of Contents

interests in the Partnership). We may exercise the Call Right at any time, in connection with our or our affiliate’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. We may 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 have provided 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 our affiliates’ financing agreements or obligations. As of September 30, 2017, the conversion price is $15.24 and the conversion ratio is 1 to 1.1483.

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 and A-2 Units have been classified as mezzanine equity in the condensed consolidated balance sheets.

Series C Convertible Preferred Units

On April 25, 2016, we issued 8,571,429 Series C Units to an ArcLight affiliate in connection with the purchase of membership interests in certain midstream entities.

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 as converted 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 also have separate class voting rights 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 C Units. The Series C Units are convertible in whole or in part into common units at any time. The number of common 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 we issue, sell or grant any common units or convertible securities at an indicative per common unit price that is less than $14.00 per common unit (subject to customary anti-dilution adjustments), then the conversion price will be adjusted according to a formula to provide for an increase in the number of common units into which Series C Units are convertible. As of September 30, 2017, the conversion price is $13.40 and the conversion ratio is 1 to 1.0448.

In connection with the issuance of the Series C Units, we 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 seven years.

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 thus represent 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 the following 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 an aggregate fair value of $4.5 million.

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 C Units have been classified as mezzanine equity in the condensed consolidated balance sheets.

Series D Convertible Preferred Units

On October 31, 2016, we issued 2,333,333 shares of our 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 during the third quarter 2016. The related agreement provides that if any of the Series D Units remain outstanding on June 30, 2017 (the “ Series D Determination Date”), we will issue the holder of the Series D Units a warrant (the “Series D Warrant”) to purchase 700,000 common units representing 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 of issuance was immaterial. On July 14, 2017, the Partnership entered into an amendment to the related agreement and Amendment No. 5 to the Partnership Agreement, pursuant to which the Series D Warrant Determination Date was extended to August 31, 2017.

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 would have 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 voting rights 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 Unit at any time after October 2, 2017. As of the date of issuance, the conversion rate for each Series D Unit was one-to-one (the “Conversion Rate”). As of September 30, 2017, the conversion price is $14.83 and the conversion ratio is 1 to 1.0035.

Table of Contents

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 D Units have been classified as mezzanine equity in the condensed consolidated balance sheets.

On October 2, 2017, AMID exercised its call right to repurchase all of the 2,333,333 outstanding Series D Units. As a result, no Series D Units are outstanding currently. See Note 22 - Subsequent Events.

Third Amendment to Partnership Agreement

On March 8, 2017, the Partnership executed Amendment No. 3 to our Fifth Amended and Restated Partnership Agreement (as amended, the “Partnership Agreement”), which amends the distribution payment terms of the Partnership’s outstanding Series A Preferred Units to provide for the payment of a number of Series A payment-in-kind (“PIK”) preferred units for the quarter (the “Series A Preferred Quarterly Distribution”) in which the JPE Acquisition is consummated (which is the quarter ended March 31, 2017) and each quarter thereafter equal to the quotient of (i) the greater of (a) $0.4125 and (b) the "Series A Distribution Amount," as such term is defined in the Partnership Agreement, divided by (ii) the Series A Adjusted Issue Price, as such term is defined in the Partnership Agreement. However, in our General Partner’s discretion, which determination shall be made prior to the record date for the relevant quarter, the Series A Preferred Quarterly Distribution may be paid as a combination (x) an amount in cash up to the greater of (1) $0.4125 and (2) the Series A Distribution Amount, and (y) a number of Series A Preferred Units equal to the quotient of (a) the remainder of (i) the greater of (I) $0.4125 and (II) the Series A Distribution Amount less (ii) the amount of cash paid pursuant to clause (x), divided by (b) the Series A Adjusted Issue Price. This calculation results in a reduced Series A Preferred Quarterly Distribution, which was previously calculated under the Partnership Agreement using $0.50 in place of $0.4125 in the preceding calculations.

(15) Partners’ Capital

Our capital accounts are comprised of approximately 1.3% notional General Partner interests and 98.7% limited partner interests as of September 30, 2017. Our limited partners have limited rights of ownership as provided for under our Partnership Agreement and the right to participate in our distributions. Our General Partner manages our operations and participates in our distributions, including certain incentive distributions pursuant to the incentive distribution rights that are non-voting limited partner interests held by our General Partner. Pursuant to our Partnership Agreement, our General Partner participates in losses and distributions based 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 a deficit to its capital account. As such, allocation of losses and distributions, including distributions for previous transactions between entities under common control, has resulted in a deficit to the General Partner’s capital account included in our condensed consolidated balance sheets.

Outstanding Units

The following table presents unit activity (in thousands):



	General Partner Interest	Limited Partner Interest
Balances at December 31, 2016	680	51,351
LTIP vesting	—	460
Issuance of GP units	273	—
Issuance of common units⁽¹⁾	—	929
Balances at September 30, 2017	953	52,740

____________________________________

⁽¹⁾ Including common units issued in connection with the Panther acquisition. See Note 3 - Acquisitions.

General Partner Units

In order to maintain the ownership percentage, we received proceeds of $3.9 million from our General Partner as consideration for the issuance of 272,811 additional notional General Partner units for the nine months ended September 30, 2017. For the nine months ended September 30, 2016, we received proceeds of $1.9 million for the issuance of 135,813 additional notional General Partner units.

Table of Contents

Distributions

We made the following distributions (in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Series A Units
Cash Paid	$	2,145	$	2,449	$	6,790	$	2,449
Accrued	4,105		4,806		4,105		4,806
Paid-in-kind units	1,924		2,152		6,838		6,623

Series C Units
Cash Paid	3,627		1,302		10,880		1,302
Accrued	4,150		3,611		4,150		3,611
Paid-in-kind units	—		948		—		948

Series D Units
Cash Paid	963		—		2,888		—
Accrued	—		—		—		—

Limited Partner Units
Cash Paid	21,345		24,874		67,648		76,656

General Partner Units
Cash Paid	277		174		645		2,375

Summary
Cash Paid	28,357		28,799		88,851		82,782
Accrued	8,255		8,417		8,255		8,417
Paid-in-kind units	1,924		3,100		6,838		7,571

The fair value of the paid-in-kind distributions was determined using the market and income approaches, requiring significant inputs which are not observable in the market and thus represent a Level 3 measurement as defined by ASC 820. Under the income approach, the fair value estimates for all periods presented were based on i) present value of estimated future contracted distributions, ii) option values ranging from $0.88 per unit to $3.39 per unit using a Black-Scholes model, iii) assumed discount rates ranging from 5.8% to 10.0% and iv) assumed growth rates of 1.0%.

Table of Contents

(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 to distributions on our convertible preferred units and General Partner units, including incentive distribution rights. Unvested unit-based compensation awards that contain non-forfeitable rights to distributions (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net limited partners' net income (loss) per common unit. Basic and diluted limited partners' net income (loss) per common unit is calculated by dividing limited partners' interest in net loss by the weighted average number of outstanding limited partner units during the period.

As discussed in Note 1, the JPE Acquisition was a combination between entities under common control. As a result, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings combining both entities were allocated among our General Partners and common unitholders assuming JPE units were converted into our common units in the comparative historical periods.

The calculation of basic and diluted limited partners' net income (loss) per common unit is summarized below (in thousands, except per unit amounts):



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Net income (loss) from continuing operations	$	11,806		$	(5,488	)	$	(42,266	)	$	(35,414	)
Less: Net income attributable to noncontrolling interests	621			1,241			3,386			2,192
Net income (loss) from continuing operations attributable to the Partnership	11,185			(6,729		)	(45,652		)	(37,606		)
Less:
Distributions on Series A Units	4,105			4,806			12,472			13,879
Distributions on Series C Units	4,150			3,611			11,403			5,860
Distributions on Series D Units	—			—			1,925			—
General partner's distribution	287			174			763			2,375
General partner's share in undistributed loss	(210		)	(375		)	(1,729		)	(1,334		)
Net income (loss) from continuing operations attributable to Limited Partners	2,853			(14,945		)	(70,486		)	(58,386		)
Net income (loss) from discontinued operations attributable to Limited Partners	44,696			(2,310		)	42,185			7,532
Net income (loss) attributable to Limited Partners	$	47,549		$	(17,255	)	$	(28,301	)	$	(50,854	)

Weighted average number of common units used in computation of Limited Partners' net loss per common unit - basic and diluted	52,021			51,310			52,021			51,310

Limited Partners' net income (loss) from continuing operations per unit	$	0.05		$	(0.29	)	$	(1.35	)	$	(1.14	)
Limited Partners' net income (loss) from discontinued operations per unit	0.86			(0.05		)	0.81			0.15
Limited Partners' net income (loss) per common unit ⁽¹⁾	$	0.91		$	(0.34	)	$	(0.54	)	$	(0.99	)

_____________________________________

⁽¹⁾ Potential common unit equivalents are antidilutive for all periods presented and, as a result, have been excluded from the determination of diluted limited partners' net loss per common unit.

(17) Long-Term Incentive Plan

Our General Partner manages our operations and activities and employs the personnel who provide support to our operations. On November 19, 2015, the Board of Directors of our General Partner approved the Third Amended and Restated Long-Term Incentive Plan to, among other things, increase the number of common units authorized for issuance by 6,000,000 common units. On February 11, 2016, the unitholders approved the Third Amended and Restated Long-Term Incentive Plan (as amended and as currently in effect as of the date hereof, the “LTIP”). On March 9, 2017, an additional 312,716 common units were registered to be issued

Table of Contents

pursuant to the American Midstream Partners, LP Amended and Restated 2014 Long-Term Incentive Plan, which were assumed by the Partnership, in relation to the converted JPE phantom units as part of the merger with JP Energy LP.

All such equity-based awards issued under the LTIP consist of phantom units, distribution equivalent rights (“DERs”) or option grants. DERs and options have been granted 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 our General Partner.

Phantom Unit Awards.

Ownership in the phantom unit awards is subject to forfeiture until the vesting date. The LTIP is administered by the Compensation Committee 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 units equivalent to the fair market value at the date of vesting in lieu of cash. Although our General Partner has the option to settle in cash upon the vesting of phantom units, our General Partner has not historically settled these awards in cash. Under the LTIP, phantom units typically vest over 3-4 years and do not contain any vesting requirements other than continued employment.

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 based on the extent to which our Series A Unitholders receive distributions in cash. These units will vest on the three year anniversary of the date of grant, subject to acceleration in certain circumstances.

The following table summarizes activity in our phantom unit-based awards for the nine months ended September 30, 2017:



	Units		Weighted-Average Grant Date Fair Value Per Unit
Outstanding units at December 31, 2016	1,558,835		$	6.98
Granted	2,000		11.20
Forfeited	(18,919	)	13.49
Vested	(570,038	)	11.13
Outstanding units at September 30, 2017	971,878		$	4.43

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. Compensation expenses related to these awards were $0.8 million and $1.8 million for the three months ended September 30, 2017 and 2016, respectively, and were $6.1 million and $4.3 million for the nine months ended September 30, 2017 and 2016, respectively, and are included in Corporate expenses and Direct operating expenses in our unaudited condensed consolidated statements of operations and Equity compensation expense in our unaudited condensed consolidated statements of changes in partners’ capital and noncontrolling interests.

The total fair value of units at the time of vesting was $9.4 million and $1.8 million for the nine months ended September 30, 2017 and 2016, respectively.

(18) 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 the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition, results of operations or cash flows.

Environmental matters

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to our operations, and we could, at times, be subject to environmental cleanup and enforcement actions. We attempt to manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.

Table of Contents

Regulatory matters

On October 8, 2014, Midla reached an agreement in principle with its customers regarding the interstate pipeline that traverses 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 allowing Midla to retire the existing 1920’s pipeline and replace it with the Midla-Natchez Line to serve existing residential, commercial, and industrial customers. Under the Midla Agreement, customers not served by the new Midla-Natchez Line will be connected to other interstate or intrastate pipelines, other gas distribution systems, or offered conversion to propane service. On June 29, 2015, we filed with FERC for authorization to construct the Midla-Natchez pipeline, which was approved on December 17, 2015. Construction commenced in the second quarter of 2016, and services commenced on March 31, 2017. Under the Midla Agreement, Midla executed long-term agreements seeking to recover its investment in the Midla-Natchez Line.

Acquisition related costs

As part of the JPE Acquisition, management of JPE communicated to its employees a severance plan. The plan includes termination benefits in the form of severance and accelerated vesting of phantom units for employees who render service through their respective termination date. The remaining liability associated with these termination benefits was immaterial as of September 30, 2017.

(19) Related Party Transactions

To the extent applicable, our discussion below includes the nature of our relationship and activities that we had with our Related Parties, as defined and required by ASC 850 - Related Party Disclosures, in the three and nine months ended September 30, 2017 and comparative periods. Balances associated with our investments in unconsolidated affiliates are disclosed in Note 10 - Investments in unconsolidated affiliates.

Blackwater Midstream Holdings, LLC

In December 2013, we acquired Blackwater Midstream Holdings, LLC (“Blackwater”) from an affiliate of ArcLight. The acquisition agreement included a provision whereby an ArcLight affiliate would be entitled to an additional $5.0 million of merger consideration based on Blackwater meeting certain operating targets. During the third quarter of 2016, we determined that it was probable the operating targets would be met in 2017 and recorded a $5.0 million accrued distribution to the ArcLight affiliate which is included in Accrued expense and other current liabilities in the accompanying unaudited condensed consolidated balance sheets.

General Partner

Employees of our General Partner are assigned to work for us or other affiliates of our General Partner. Where directly attributable, all compensation and related expenses for these employees are charged directly by our General Partner to our wholly-owned subsidiary, American Midstream, LLC, which, in turn, charges the appropriate subsidiary or affiliate. Our General Partner does not record any profit or margin on the expenses charged to us.

In connection with the JPE Acquisition closing during the first quarter of 2017, our General Partner agreed to provide quarterly financial support up to a maximum of $25.0 million. The financial support will continue for eight (8) consecutive quarters following the closing of the acquisition, or earlier, until $25.0 million in support has been provided. As of September 30, 2017, we have utilized the full $25.0 million of the financial support mentioned above.

Separate from the financial support described above, our General Partner also agreed to absorb $9.6 million corporate overhead expenses, which were incurred by us in the first quarter of 2017, and subsequently paid the amount in the second quarter of 2017. These two cash amounts, and the $3.9 million received related to the General Partner’s ownership percentage, totaled $38.3 million which was presented as part of the contribution line item on our unaudited condensed consolidated statements of cash flows. As of September 30, 2017 and December 31, 3016, we had $4.7 million and $3.9 million of account payables, respectively, due to our General Partner, which has been recorded in Accrued expenses and other current liabilities and relates primarily to compensation. This payable is generally settled on a quarterly basis related to the foregoing transactions.

Republic Midstream, LLC

Table of Contents

Republic Midstream, LLC (“Republic”), is an entity owned by ArcLight in which we charge a monthly fee of approximately $0.1 million. The monthly fee reduced the Corporate expenses in the condensed consolidated statements of operations by $0.4 million and $1.0 million for three and nine months ended September 30, 2017, respectively, and $0.2 million and $0.6 million for the three and nine months ended September 30, 2016, respectively. As of September 30, 2017, we had a receivable balance due from Republic of $1.5 million, which is included in the account Receivables from related parties, which is part of Other current assets in the condensed consolidated balance sheets.

Transactions with our unconsolidated affiliates

Destin and Okeanos

On November 1, 2016, we became operator of the Destin and Okeanos pipelines and entered into operating and administrative management agreements under which the affiliates pay a monthly fee for general and administrative services provided by us. In addition, the affiliates reimburse us for certain transition related expenses. For the nine months ended September 30, 2017, we recognized $1.9 million of management fee income. As of September 30, 2017 and December 31, 2016, we had an outstanding accounts receivable balance of $1.0 million and $2.2 million, respectively, which is recorded in Receivables from related parties and is part of Other current assets in the unaudited condensed consolidated balance sheets.

AmPan

AmPan was a 60%-owned subsidiary of ours which was consolidated for financial reporting purposes. Panther was the 40% non-controlling interest owner of AmPan. Pursuant to a related party agreement which began in the second quarter of 2016, POGS provided management services to AmPan in exchange for related fees, which in 2016 totaled $0.8 million of Direct operating expenses and $0.4 million of Corporate expenses in the unaudited condensed consolidated statements of operations. During January 1, 2017 to August 7, 2017, such management services totaled approximately $1.5 million of Direct operating expenses and $0.3 million of Corporate expenses in the unaudited condensed consolidated statements of operations. Effective August 8, 2017, AmPan and POGS became our wholly-owned subsidiaries. See Note 3 - Acquisitions.

JP Energy Development

JP Energy Development (“JP Development”), an affiliate owned by Arclight, had a pipeline transportation business that provided crude oil pipeline transportation services to JPE’s discontinued Mid-Continent Business. As a result of utilizing JP Development’s pipeline transportation services, JPE incurred pipeline tariff fees of $0.4 million for the six months ended June 30, 2016, which have been included in net loss from discontinued operations in the condensed consolidated statements of operations. As of December 31, 2015, we had a net receivable from JP Development of $7.9 million, primarily as the result of the prepayments made in 2014 for the crude oil pipeline transportation services to be provided by JP Development. We recovered these amounts in full on February 1, 2016.

On February 1, 2016, JPE sold certain trucking and marketing assets in the Mid-Continent area to JP Development in connection with JP Development’s sale of its GSPP pipeline assets to a third party. During the year ended December 31, 2016, JPE’s general partner agreed to absorb corporate overhead expenses incurred by us and not pass such expense through to us. We record non-cash contributions for these expenses in the quarters subsequent to when they were incurred, which was $0.0 million and $4.0 million for the three and nine months ended September 30, 2017, respectively, and $3.5 million and $7.5 million for the three and nine months ended September 30, 2016, respectively. JPE’s general partner agreed to absorb $0.0 million and $5.0 million of such corporate overhead expenses in the three and nine months ended September 30, 2016, respectively.

Purchases and sales of natural gas and crude oil with a related party

We enter into separate purchases and sales of natural gas and crude oil with a company whose chief financial officer is the brother of one of our executive officers. During the three months ended September 30, 2017 and 2016, we recognized revenue of $3.7 million and $1.1 million, respectively, and had purchases not related to receivables totaling $1.1 million, and $1.2 million, respectively. During the nine months ended September 30, 2017 and 2016, we recognized revenue of $6.2 million and $2.7 million, respectively, and had purchases not related to receivables totaling $3.7 million and $3.0 million, respectively.

Capstone Ventures, LLC

Capstone Ventures, LLC (“Capstone”) is a marketing company where one of the Partnership’s employees is a partial, non-participating owner. During the three months ended September 30, 2017 and 2016, we recognized revenue of $0.2 million in both

Table of Contents

periods. During the nine months ended September 30, 2017 and 2016, we recognized revenue of $0.7 million and $0.5 million, respectively.

McCown Enterprises, LLC

McCown Enterprises, LLC (“HCLM”) is a marketing company where one of the Partnership’s employee has 50% ownership. During the nine months ended September 30, 2017 and 2016, we recognized revenue from HCLM of $0.3 million and $0.2 million, respectively.

(20) Supplemental Cash Flow Information

Supplemental cash flows and non-cash transactions consist of the following (in thousands):



	Nine months ended September 30,
	2017			2016
Supplemental non-cash information
Investing
Increase (decrease) in accrued property, plant and equipment purchases	$	(15,112	)	$	4,597
Financing
Issuance of common units for the Panther acquisition	12,532			—
Contributions from an affiliate holding limited partner interests	4,000			7,500
Issuance of Series C Units and Warrant in connection with the Emerald Transactions	—			120,000
Accrued distributions on convertible preferred units	8,255			8,417
Paid-in-kind distributions on convertible preferred units	6,838			7,571
Cancellation of escrow units	—			6,817
Accrued distribution from unconsolidated affiliates	—			5,000

(21) Reportable Segments

Since the first quarter of 2017, as a result of the acquisition of JPE described in Note 1 - Organization, Basis of Presentation and Summary of Significant Accounting Policies, we realigned the composition of our reportable segments. We restated the items of segment information as reported for the three and nine months ended September 30, 2016 to reflect this new segment adjustment.

On September 1, 2017, we sold the Propane Business, as described in Note 4 - Discontinued Operations. Prior to the sale, during July 2017, we moved the trucking business from the Propane Marketing Services segment to the Liquid Pipelines and Services segment. The prior periods were adjusted to reflect that change. With the disposition of the Propane Business, we eliminated the Propane Marketing Services segment. We have classified the results of our Propane Marketing Services segment, including the gain on sale, as discontinued operations in our condensed consolidated statements of operations for all periods presented.

Our operations are located in the United States and are organized into five reportable segments: 1) Gas Gathering and Processing Services, 2) Liquid Pipelines and Services, 3) Natural Gas Transportation Services, 4) Offshore Pipelines and Services and 5) Terminalling Services.

•

Gas Gathering and Processing Services. Our Gas Gathering and Processing Services segment provides “wellhead-to-market” services to producers of natural gas and natural gas liquids, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw 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 various receipt 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 producing wells, receipt points, or pipeline interconnects for shippers and other customers,

Table of Contents

which include local distribution companies (“LDCs”), utilities and 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 various receipt 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 that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas.

These segments are monitored separately by our chief operating decision maker (“CODM”) for performance and are consistent with our internal financial reporting. The CODM periodically reviews segment gross margin information for each segment to make business decisions. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations.

We define total segment gross margin as the sum of the segment gross margins for our Gas Gathering and Processing Services,

Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipelines and Services and Terminalling Services.

We define segment gross margin in our Gas Gathering and Processing Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives, construction and operating management agreement income and the cost of natural gas, crude oil and NGLs and condensate purchased.

We define segment gross margin in our Liquid Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less unrealized gains or plus unrealized losses on commodity derivatives and the cost of crude oil purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-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 natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Offshore Pipelines and Services segment as total revenue plus unconsolidated affiliate earnings less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.

We define segment gross margin in our Terminalling Services segment as total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.

Table of Contents

A reconciliation from Total segment gross margin to Net income (loss) attributable to the Partnership for the periods presented is below (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Reconciliation of Segment Gross Margin to Net income (loss) attributable to the Partnership:
Gas Gathering and Processing Services segment gross margin	$	12,761		$	12,627		$	36,663		$	37,586
Liquid Pipelines and Services segment gross margin	7,808			7,600			21,209			23,829
Natural Gas Transportation Services segment gross margin	5,356			3,709			17,106			13,115
Offshore Pipelines and Services segment gross margin	29,312			24,126			80,738			57,947
Terminalling Services segment gross margin ⁽¹⁾	8,509			10,731			30,429			31,760
Total segment gross margin (non-GAAP)	63,746			58,793			186,145			164,237
Less:
Direct operating expenses ⁽¹⁾	17,274			14,695			47,316			45,999
Plus:
Gain (loss) on commodity derivatives, net	(597		)	324			(33		)	(1,929		)
Less:
Corporate expenses	27,083			22,103			84,570			60,945
Depreciation, amortization and accretion expense	26,781			22,668			78,834			65,937
(Gain) loss on sale of assets, net	(4,061		)	36			(4,064		)	297
Interest expense	17,759			5,830			51,037			24,723
Other (income) expense	(34,085		)	1			(32,248		)	(245		)
Other (income) expense, net	(139		)	(1,129		)	322			(1,773		)
Income tax expense	731			401			2,611			1,839
(Income) loss from discontinued operations, net of tax	(44,696		)	2,310			(42,185		)	(7,532		)
Net income attributable to noncontrolling interests	621			1,241			3,386			2,192
Net income (loss)	$	55,881		$	(9,039	)	$	(3,467	)	$	(30,074	)

_____________________________________

⁽¹⁾

Direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $8.7 million and $7.9 million, Liquid Pipelines and Services segment direct operating expenses of $2.4 million and $2.6 million, Natural Gas Transportation Services segment direct operating expenses of $2.2 million and $1.3 million and Offshore Pipelines and Services segment direct operating expenses of $3.9 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively. Direct operating expenses related to our Terminalling Services segment of $3.4 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.

Other direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $24.8 million and $25.3 million, Liquid Pipelines and Services segment direct operating expenses of $7.1 million and $8.2 million, Natural Gas Transportation Services segment direct operating expenses of $5.4 million and $4.5 million, and Offshore Pipelines and Services segment direct operating expenses of $10.0 million and $8.0 million for the nine months ended September 30, 2017 and 2016, respectively. Direct operating expenses related to our Terminalling Services segment of $9.5 million and $7.9 million for the nine months ended September 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.

Table of Contents

The following tables set forth our segment information for the three and nine months ended September 30, 2017 and 2016 (in thousands):



	Three months ended September 30, 2017
	Gas Gathering and Processing Services			Liquid Pipelines and Services			Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
Revenue	$	37,287		$	87,022		$	11,131	$	14,360	$	13,087	$	162,887
Gain (loss) on commodity derivatives, net	(65		)	(532		)	—		—		—		(597		)
Total revenue	37,222			86,490			11,131		14,360		13,087		162,290
Earnings in unconsolidated affiliates	—			1,317			—		15,510		—		16,827
Operating expenses:
Cost of Sales	24,492			80,510			5,692		558		1,146		112,398
Direct operating expenses	8,655			2,438			2,240		3,940		3,432		20,705
Corporate expenses													27,083
Depreciation, amortization and accretion expense													26,781
Gain on sale of assets, net													(4,061		)
Total operating expenses													182,906
Interest expense													17,759
Other income													(34,085		)
Income from continuing operations before income taxes													12,537
Income tax expense													731
Income from continuing operations													11,806
Income from discontinued operations, including gain on disposition (Note 4)													44,696
Net income													56,502
Less: Net income attributable to non-controlling interests													621
Net income attributable to the Partnership													$	55,881

Segment gross margin	$	12,761		$	7,808		$	5,356	$	29,312	$	8,509

Table of Contents



	Three months ended September 30, 2016
	Gas Gathering and Processing Services			Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services			Terminalling Services			Total
Revenue	$	31,650		$	87,898	$	10,709	$	14,879		$	14,443		$	159,579
Gain (loss) on commodity derivatives, net	149			177		—		(2		)	—		—	324
Total revenue	31,799			88,075		10,709		14,877			14,443			159,903
Earnings in unconsolidated affiliates	(1		)	650		—		9,819			—			10,468

Operating expenses:
Cost of Sales	18,477			80,372		6,994		570			836			107,249
Direct operating expenses	7,856			2,617		1,324		2,898			2,876			17,571
Corporate expenses														22,103
Depreciation, amortization and accretion expense														22,668
Loss on sale of assets, net														36
Total operating expenses														169,627
Interest expense														5,830
Other expense														1
Loss from continuing operations before income taxes														(5,087		)
Income tax expense														401
Loss from continuing operations														(5,488		)
Loss from discontinued operations														(2,310		)
Net loss														(7,798		)
Less: Net income attributable to non-controlling interests														1,241
Net loss attributable to the Partnership														$	(9,039	)

Segment gross margin	$	12,627		$	7,600	$	3,709	$	24,126		$	10,731

Table of Contents



	Nine months ended September 30, 2017
	Gas Gathering and Processing Services			Liquid Pipelines and Services		Natural Gas Transportation Services		Offshore Pipelines and Services		Terminalling Services		Total
Revenue	$	111,001		$	253,590	$	34,966	$	41,330	$	47,544	$	488,431
Gain (loss) on commodity derivatives, net	(170		)	137		—		—		—		(33		)
Total revenue	110,831			253,727		34,966		41,330		47,544		488,398
Earnings in unconsolidated affiliates	—			3,886		—		45,895		—		49,781
Operating expenses:
Cost of Sales	74,261			236,896		17,630		6,487		7,612		342,886
Direct operating expenses	24,766			7,137		5,403		10,010		9,503		56,819
Corporate expenses												84,570
Depreciation, amortization and accretion expense												78,834
Gain on sale of assets, net												(4,064		)
Total operating expenses												559,045
Interest expense												51,037
Other income												(32,248		)
Loss from continuing operations before income taxes												(39,655		)
Income tax expense												2,611
Loss from continuing operations												(42,266		)
Income from discontinued operations, including gain on disposition (Note 4)												42,185
Net loss												(81		)
Less: Net income attributable to non-controlling interests												3,386
Net loss attributable to the Partnership												$	(3,467	)

Segment gross margin	$	36,663		$	21,209	$	17,106	$	80,738	$	30,429

Table of Contents



	Nine months ended September 30, 2016
	Gas Gathering and Processing Services			Liquid Pipelines and Services			Natural Gas Transportation Services		Offshore Pipelines and Services			Terminalling Services			Total
Revenue	$	85,655		$	221,866		$	28,383	$	32,526		$	46,652		$	415,082
Gain (loss) on commodity derivatives, net	(716		)	(772		)	—		(5		)	(436		)	(1,929		)
Total revenue	84,939			221,094			28,383		32,521			46,216			413,153
Earnings in unconsolidated affiliates	—			1,658			—		27,855			—			29,513

Operating expenses:
Cost of Sales	47,344			199,111			15,245		2,429			6,583			270,712
Direct operating expenses	25,344			8,186			4,515		7,954			7,873			53,872
Corporate expenses															60,945
Depreciation, amortization and accretion expense															65,937
Loss on sale of assets, net															297
Total operating expenses															451,763
Interest expense															24,723
Other income															(245		)
Loss from continuing operations before income taxes															(33,575		)
Income tax expense															1,839
Loss from continuing operations															(35,414		)
Income from discontinued operations															7,532
Net loss															(27,882		)
Less: Net income attributable to non-controlling interests															2,192
Net loss attributable to the Partnership															$	(30,074	)

Segment gross margin	$	37,586		$	23,829		$	13,115	$	57,947		$	31,760

A reconciliation of total assets by segment to the amounts included in the condensed consolidated balance sheets follows:



	September 30,		December 31,
	2017		2016
Segment assets:
Gas Gathering and Processing Services	$	416,498	$	530,889
Liquid Pipelines and Services	443,771		425,389
Offshore Pipelines and Services	544,895		400,193
Natural Gas Transportation Services	172,813		221,604
Terminalling Services	256,922		299,534
Other ⁽¹⁾	188,308		334,953
Discontinued Operations	—		136,759
Total Assets	$	2,023,207	$	2,349,321

_____________________________________

⁽¹⁾ Other assets not allocable to segments consist of corporate leasehold improvements and other miscellaneous assets.

(22) Subsequent Events

Table of Contents

Series D Units Redemption

On October 2, 2017, pursuant to the terms of the Fifth Amended and Restated Agreement of Limited Partnership, as amended, of the Partnership, we exercised our call right to repurchase all of the 2,333,333 outstanding Series D Convertible Preferred Units representing limited partner interests in the Partnership (“Series D Units”) from Magnolia Infrastructure Holdings, LLC, an affiliate of ArcLight, for approximately $37.0 million in cash, which was funded through our existing revolver. After the closing date of such redemption, which occurred on October 2, 2017, no Series D Units remain outstanding.

Distribution

On October 26, 2017, we announced that the Board of Directors of our General Partner declared a quarterly cash distribution of $0.4125 per common unit and preferred unit, Series A and Series C, for the quarter ended September 30, 2017, or $1.65 per common unit on an annualized basis. The distribution is expected to be paid on November 14, 2017, to unitholders of record as of the close of business on November 7, 2017.

Acquisition of additional ownership interest in Destin

On October 27, 2017, American Midstream Emerald, LLC, a wholly-owned subsidiary of the Partnership, entered into a Purchase and Sale Agreement with Emerald Midstream, LLC, an ArcLight affiliate, to purchase an additional 17.0% equity interest in Destin Pipeline Company, LLC (“Destin”) for total consideration of $30.0 million. With the acquisition, the Partnership will own a 66.67% interest in Destin. The Destin pipeline is a FERC-regulated, 255-mile natural gas transport system with total capacity of 1.2 Bcf/d.

Southcross Energy Partners, L.P. Merger

On October 31, 2017, we, our General Partner, our wholly owned subsidiary Cherokee Merger Sub LLC (“Merger Sub”), Southcross Energy Partners, L.P. (“SXE”), and Southcross Energy Partners GP, LLC (“SXE GP”), entered into an Agreement and Plan of Merger (the “SXE Merger Agreement”). Upon the terms and subject to the conditions set forth in the SXE Merger Agreement, SXE will merge with Merger Sub (the “SXE Merger”), with SXE continuing its existence under Delaware law as the surviving entity in the SXE Merger and wholly owned subsidiary of us. The acquisition is valued at approximately $815 million, including the repayment of estimated net debt of $139 million.

At the effective time of the SXE Merger (the “Effective Time”), each common unit of SXE (each, an “SXE Common Unit”) issued and outstanding or deemed issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.160 (the “Exchange Ratio”) of a common unit (each, an “AMID Common Unit”) representing limited partner interests in us (the “Merger Consideration”), except for those SXE Common Units held by affiliates of SXE and SXE GP, which will be cancelled for no consideration. Each SXE Common Unit, Subordinated Unit (as defined in the SXE Merger Agreement) and Class B Convertible Unit (as defined in the SXE Merger Agreement) held by Southcross Holdings LP (“Holdings LP”) or any of its subsidiaries and the SXE Incentive Distribution Rights (as defined in the SXE Merger Agreement) outstanding immediately prior to the Effective Time will be cancelled in connection with the closing of the SXE Merger.

In connection with the SXE Merger Agreement, on October 31, 2017, we and our General Partner entered into a Contribution Agreement (the “SXE Contribution Agreement” and, together with the SXE Merger Agreement, the “SXE Transaction Agreements”) with Holdings LP. Upon the terms and subject to the conditions set forth in the SXE Contribution Agreement, Holdings LP will contribute its equity interests in its new wholly owned subsidiary (“SXH Holdings”), which will hold substantially all the current subsidiaries (Southcross Holdings Intermediary LLC, Southcross Holdings Guarantor GP LLC and Southcross Holdings Guarantor LP) and business of Holdings LP, to us and our General Partner in exchange for (i) the number of AMID Common Units with a value equal to $185,697,148, subject to certain adjustments for cash, indebtedness, working capital and transaction expenses contemplated by the SXE Contribution Agreement, divided by $13.69 per AMID Common Unit, (ii) 4,500,000 AMID Preferred Units (as defined in the SXE Contribution Agreement), (iii) options to purchase 4,500,000 AMID Common Units (the “Options”), and (iv) 3,000 AMID GP Class D Units (as defined in the SXE Contribution Agreement) (the transactions contemplated thereby and the agreements ancillary thereto, the “SXE Contribution”). A portion of the consideration will be deposited into escrow in order to secure certain post-closing obligations of Holdings LP. Concurrently with the closing of the transaction, our agreement of limited partnership will be amended to reflect the issuance of AMID Preferred Units, and the GP LLC Agreement will be amended to reflect the issuance of such AMID GP Class D Units.

Acquisition of Trans-Union pipeline

On November 6, 2017, we announced the acquisition and closing of 100% of the equity interests in Trans-Union Interstate Pipeline, LP (“Trans-Union”) from affiliates of ArcLight, for a total consideration of approximately $48.0 million. The

Table of Contents

consideration consisted of approximately $15.5 million cash funded from borrowings under our revolving credit facility and the assumption of $32.5 million of non-recourse debt. Trans-Union owns a 42-mile, 30-inch diameter high-pressure FERC-regulated natural gas interstate pipeline with 546,000 MMbtu/day of maximum capacity. We believe that this acquisition represents a transaction among entities under common control. Accordingly we may have to recast our historical financial statements to reflect the accounts of Trans-Union from the date ArcLight obtained control.

Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management’s discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2016 included in our Current Report on Form 8-K (the “Recast Form 8-K”) as filed with the Securities and Exchange Commission (“SEC”) on September 18, 2017. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Forward-Looking Statements.”

Forward-Looking Statements

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements”. You can typically identify forward-looking statements by the use of forward-looking 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, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Examples of these risks and uncertainties, many of which are beyond our control, include, but are not limited to, the following:


•	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 Agreement (as defined below);


•	our ability to timely and successfully identify, consummate and integrate our recent, pending and future acquisitions (including the merger with Southcross, Energy Partner, L.P.) 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, refined products 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 on general 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 our gathering and processing systems;


•	the volumes of natural gas and crude oil that we gather, process, transport and store, the throughput volume at our refined products terminals and our NGL sales volumes;


•	the fees that we receive for the natural gas, crude oil, refined products and NGL volumes we handle;


•	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 protection of 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 natural gas, crude oil, NGL and refined 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;

Table of Contents


•	leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;


•	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 our business strategy;


•	the cost and effectiveness of our remediation efforts with respect to the material weakness discussed in "Part II. Item 9A. Controls and Procedures" of our Annual Report;


•	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 Quarterly Report will prove to be accurate. Some of these and additional risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in Part II, Item 1A of this Quarterly Report under the caption “Risk Factors”, Part I, Item 1A of our Annual Report, as filed with the SEC on March 28, 2017, under the caption “Risk Factors” and elsewhere in this Quarterly Report. The forward-looking statements in this report speak as of the filing date of this report. Except as may be required by applicable securities laws, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

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 midstream energy assets. We provide critical midstream infrastructure that links producers of natural gas, crude oil, NGLs, condensate and specialty chemicals to numerous intermediate and end-use markets. Through our five financial reporting segments, (i) gas gathering and processing services, (ii) liquid pipelines and services, (iii) natural gas transportation services, (iv) offshore pipelines and services and (v) terminalling 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 and condensates; storing specialty chemical products and selling refined products. As of September 1, 2017, as a result of the disposition of the Propane Business described in in Note 4 - Discontinued Operations, we have eliminated the Propane Marketing Services segment.

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. Our gathering 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 Eagle Ford Shale of South Texas, and (iv) offshore in the Gulf of Mexico. Our liquid pipelines, natural gas transportation and offshore pipelines and terminal assets are located in prolific producing regions and key demand markets in Alabama, Louisiana, Mississippi, North Dakota, Texas, Tennessee and in the Port of New Orleans in Louisiana and the Port of Brunswick in Georgia. Additionally, we operate a fleet of NGL gathering and transportation trucks in the Eagle Ford shale and the Permian Basin. See Recent Developments regarding the recent acquisitions and dispositions in the third quarter of 2017.

We own or have ownership interests in more than 5,100 miles of onshore and offshore natural gas, crude oil, NGL and saltwater pipelines across 17 gathering systems, six interstate pipelines and nine intrastate pipelines; eight natural gas processing plants; four fractionation facilities; an offshore semisubmersible floating production system with nameplate processing capacity of 90 MBbl/d of crude oil and 220 MMcf/d of natural gas; six marine terminal sites with approximately 6.7 MMBbls of above-ground aggregate storage capacity for petroleum products, distillates, chemicals and agricultural products; and 90 transportation trucks and a total trailer fleet of 130, of which 35 are LPG trailers and 95 are crude oil trailers.

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; a 35.7% non-operated interest in the Class A Units and common 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; and a 25.3% non-operated interest in Wilprise, a NGL pipeline.

Recent Developments

Table of Contents

Our business objectives continue to focus on maintaining stable cash flows from our existing assets and executing on growth opportunities to increase 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 which represents a significant portion of our estimated margins, the objective of which is to protect against downside risk in our cash flows.

Strategic acquisitions and disposition

During the third quarter of 2017, we divested 100% of our Propane Business to SHV Energy N.V., received $162.7 million, net of $2.5 million of transaction cost and cash on hand, from proceeds of the sale and recognized a net gain of $46.5 million from the sale, as part of our efforts to re-focus on our core competencies. See Note 4 - Discontinued Operations. As part of our growth strategy, we also made a series of acquisitions in the second and third quarters of 2017 to enhance our Offshore pipeline and services segment and Gas gathering and processing segment with the purchase of Viosca Knoll, Panther and an additional ownership percentage of Delta House. We also formed the Cayenne JV with Targa. See Note 3 - Acquisitions and Note 10 - Investments in unconsolidated affiliates.

Southcross Energy Partners, L.P. Merger

Financial Highlights

Financial highlights for the three months ended September 30, 2017, include the following:

•

Net income attributable to the Partnership increased to $55.9 million, as compared to net loss of $9.0 million in the same period in 2016, primarily due to the net gain on disposition of the Propane Business of $46.5 million, the gain of $32.3 million related to the MPOG acquisition and the $4.0 million gain recognized on Cayenne, offset partially by an increase in operating loss of $10.9 million and interest expense of $11.9 million.

Table of Contents


•	Earnings in unconsolidated affiliates were $16.8 million, an increase of $6.4 million as compared to the same period in 2016, primarily due to the additional 6.2 % Delta House investments in the fourth quarter of 2016 which continues to perform near nameplate capacity as a result of the strong performance by producers.


•	Segment gross margin amounted to $63.7 million, or a increase of $4.9 million as compared to the same period in 2016, primarily due to higher segment gross margin in our Offshore pipelines and services segment as a result of higher earnings in unconsolidated affiliates, offset by a decrease in the Terminalling services segment mainly due to lower contract rates at our North Little Rock facility;


•	Adjusted EBITDA increased to $42.3 million, or an increase of 24.0% as compared to the same period in 2016, primarily due to support from our General Partner for cost reimbursement, partially offset by lower distributions from our unconsolidated affiliates; and


•	We distributed $21.3 million to our common unitholders, or $0.4125 per common unit, with respect to the quarter, which was the 25th consecutive distribution since our initial public offering.

Operational highlights for the three months ended September 30, 2017, include the following:


•	Contracted capacity for our Terminalling Services segment averaged 4,759,978 Bbls, representing an 8.8% decrease compared to the same period in 2016;


•	Average condensate production totaled 57.5 Mgal/d, representing a 29.6 Mgal/d or 34% decrease compared to the same period in 2016;


•	Average gross NGL production totaled 324.3 Mgal/d, representing a 142.6 Mgal/d or 78% increase compared to the same period in 2016;


•	Throughput volumes attributable to the Natural gas transportation services and Offshore pipelines and services segments totaled 423 MMcf/d, representing a 94 MMcf/d or 18% decrease compared to the same period in 2016;


•	Throughput volumes attributable to the Liquid pipelines and services segment totaled 35,403Bbls/d, representing a 5,032 Bbls/d or 16% increase compared to the same period in 2016; and


•	The percentage of gross margin generated from fee based, fixed margin, firm and interruptible transportation contracts and firm storage contracts was 86.6%, representing a decrease of 4.5% as compared to the same period in 2016.

Commodity Prices

Average daily prices for NYMEX West Texas Intermediate crude oil ranged from a high of $54.45 per barrel to a low of $42.53 per barrel from January 1, 2017 through October 27, 2017. Average daily prices for NYMEX Henry Hub natural gas ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu from January 1, 2017 through October 27, 2017.

Fluctuations in energy prices can greatly affect the development of new crude oil and natural gas reserves. Further declines in commodity prices of crude oil and natural gas could have a negative impact on exploration, development and production activity, and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to continued or further reduced utilization of our assets. We are unable to predict future potential movements in the market price for natural gas, crude oil and NGLs and thus, cannot predict the ultimate impact of commodity prices on our operations.

Capital Markets

Volatility in the capital markets continues to impact our operations in multiple ways, including limiting our producers’ ability to finance their drilling and workover programs and limiting our ability to fund drop downs, organic growth projects and acquisitions. We may opportunistically consider accessing the capital markets.

Table of Contents

Our Operations

On September 1, 2017, we completed the disposition of our Propane Business. Prior to the classification as discontinued operations, we reported the Propane Business in our Propane Marketing Services segment, which was dissolved at the time of the Propane Business disposition. Accordingly, we have recast our financial statements to retrospectively reflect this change in classification for the Propane Business to discontinued operations for all periods presented. See Note 1 - Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 4 - Discontinued Operations.

We manage our business and analyze and report our results of operations through five reportable segments.

•


•	Liquid Pipelines and Services. Our Liquid Pipelines and Services segment provides transportation, purchase and sales of crude oil from various receipt 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 producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and 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 various receipt 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 that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products and also includes crude oil storage in Cushing, Oklahoma and refined products terminals in Texas and Arkansas.

Gas Gathering and Processing Services Segment

Results of operations from the Gas Gathering and Processing Services segment are determined primarily by the volumes of natural gas 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 process natural gas 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 gas.

•

Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas and off-spec condensate from producers or suppliers at receipt 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 of natural gas or off-spec condensate, we are able to lock in a fixed margin on these transactions. We view the segment gross margin earned under our 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 or other 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 connection with our elective processing arrangements, we generally retain and sell a percentage of the residue natural gas and resulting NGLs. However, we also have contracts under which we retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas. Our POP arrangements also often contain a fee-based component.

Table of Contents

Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in throughput volumes from producers 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 by the commodity prices we realize on our share of natural gas and NGLs received as compensation for processing raw natural gas. However, our POP arrangements often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. See the information set forth in Part I, Item 3 of this Quarterly Report under the caption “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

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 intrastate pipelines we own. Tariffs associated with our Bakken system are regulated by FERC for volumes gathered via pipeline and trucked to the AMID Truck facility in Watford City, North Dakota. Volumes transported on our Silver Dollar system are underpinned by long-term, fee-based contracts. Our transportation arrangements are further described below:

•

Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport crude oil nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us.


•	Uncommitted Shipper Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport crude oil nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but 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 producers in the Midland Basin. Some of these contracts also have minimum volume commitments as well as some have acreage dedications.

•

Buy-Sell Arrangements. We enter into outright purchase and sales contracts as well as buy/sell contracts with counterparties, under which contracts we gather and transport different types of crude oil and eventually sell the crude oil to either the same counterparty or different counterparties. We account for such revenue arrangements on a gross basis. Occasionally, we enter into crude oil inventory exchange arrangements with the same counterparty which the purchase and sale of inventory are considered in contemplation of each other. Revenues from such inventory exchange arrangements are recorded on a net basis.

Natural Gas Transportation Services Segment

Results of operations from the Natural Gas Transportation Services segment are determined by capacity reservation fees from firm and interruptible transportation contracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. 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 gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable-use charge with respect to quantities actually transported by us.


•	Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped.

Table of Contents

•

Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements.

Offshore Pipelines and Services

Results of operations from the Offshore Pipelines and Services segment are determined by capacity reservation fees from firm and interruptible transportation contracts and the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:

•


•	Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable-use charge for quantities actually shipped.

•

Terminalling Services Segment

Our Terminalling Services segment provides above-ground leasable storage services at our marine terminals that support various commercial customers, including commodity brokers, refiners and chemical manufacturers to store a range of products, including petroleum products, distillates, chemicals and agricultural products. We generally receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed and other fee-based charges associated with ancillary services provided to our customers, such as excess throughput, truck weighing, etc. Our firm storage contracts are typically multi-year contracts with renewal options. Our refined products terminals have butane blending capabilities.

Contract Mix

For the three months ended September 30, 2017 and 2016, $38.6 million and $43.3 million, or 86.6% and 91.0%, respectively, of our gross margin (excluding our Investments in unconsolidated affiliates) was generated from fee-based, fixed margin, firm and interruptible transportation contracts and firm storage contracts.

Cash distributions received from our unconsolidated affiliates amounted to $20.6 million and $22.7 million for the three months ended September 30, 2017 and 2016, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.

For the nine months ended September 30, 2017 and 2016, $115.3 million and $119.3 million, or 87.7% and 91.9%, respectively, of our gross margin (excluding our Investments in unconsolidated affiliates) was generated from fee-based, fixed margin, firm and interruptible transportation contracts and firm storage contracts.

Cash distributions received from our unconsolidated affiliates amounted to $59.0 million and $62.8 million for the nine months ended September 30, 2017 and 2016, respectively. Cash distributions derived from our unconsolidated affiliates are primarily generated from fee-based gathering and processing arrangements.

Table of Contents

How We Evaluate Our Operations

Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, storage utilization, 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 increase throughput 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 gathering systems, 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, crude oil, NGLs and condensate that has been released from other commitments and iv) the volume of natural gas, NGLs and condensate that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to maintain current throughput volumes and pursue new supply opportunities.

In our Liquid Pipelines and Services segment, the 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 our crude oil supply and logistics business depends on the volume of crude oil we purchase from producers, aggregators and traders and then sell to producers, traders and 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 volumes transported 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 States to 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 through to 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 capacity reservation charges and interruptible transportation services from throughput volumes on our interstate and intrastate pipelines. Substantially all of the segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to maintain current throughput volumes and pursue new shipper opportunities.

In our Terminalling Services segment, we receive fee-based compensation on guaranteed firm storage contracts, throughput fees charged to our customers when their products are either received or disbursed, and other operational charges associated with ancillary services provided to our customers, such as excess throughput, steam heating, and truck weighing at our marine terminals. The amount of revenue we generate from our refined products terminals depends primarily on the volume of refined products that we handle. These volumes are affected primarily by the supply of and demand for refined products in the markets served directly or indirectly by our refined products terminals. Our refined products terminals have butane blending capabilities. The volume of crude oil stored at our crude oil storage facility in Cushing, Oklahoma has no impact on 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 of our storage tanks.

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 the contracted capacity in barrels compared to the design capacity of the tank.

Segment Gross Margin and Total Segment Gross Margin

Segment gross margin and total segment gross margin are metrics that we use to evaluate our performance.

Table of Contents

We define segment gross margin in our Terminalling Services segment as total revenue less direct operating expense which includes direct labor, general materials and supplies and direct overhead.

Total segment gross margin is a supplemental non-GAAP financial measure that we use to evaluate our performance. We define total segment gross margin as the sum of the segment gross margins for our Gas Gathering and Processing Services, Liquid Pipelines and Services, Natural Gas Transportation Services, Offshore Pipelines and Services, Terminalling Services segments. The GAAP measure most directly comparable to gross margin is Net income (loss) attributable to the Partnership. For a reconciliation of gross margin to net income (loss), see “Non-GAAP Financial Measures” below.

Operating Margin

We define operating margin as total segment gross margin less other direct operating expenses. The GAAP measure most directly comparable to operating margin is net income (loss) attributable to the Partnership. For a reconciliation of Operating Margin to net income (loss), see “- Non-GAAP Financial Measures.”

Direct Operating Expenses

Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. 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 the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of 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 or historical cost basis; the ability of our assets to generate cash flow to make cash distributions to our unitholders and our General Partner; our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

We define Adjusted EBITDA as net income (loss) attributable to the Partnership, plus depreciation, amortization and accretion expense, interest expense, debt issuance costs, unrealized losses on derivatives, non-cash charges such as non-cash equity compensation expense, and charges that are unusual such as transaction expenses primarily associated with our acquisitions (such as JPE, Viosca Knoll, Delta House and Panther), income tax expense, distributions from unconsolidated affiliates and general partner’s contribution, less earnings in unconsolidated affiliates, discontinued operations, gains (losses) that are unusual such as gain on revaluation of equity interest, other, net, and gain on sale of assets, net.

The GAAP measure most directly comparable to our performance measure Adjusted EBITDA is net income (loss) attributable to the Partnership. For a reconciliation of Adjusted EBITDA to net income (loss), see “Non-GAAP Financial Measures” below.

Table of Contents

Non-GAAP Financial Measures

Total segment gross margin, operating margin and Adjusted EBITDA are performance measures that are non-GAAP financial measures. Each has important limitations as an analytical tool because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

You should not consider total segment gross margin, operating margin, or Adjusted EBITDA in isolation or as a substitute for, or more meaningful than analysis of, our results as reported under GAAP. Total segment gross margin, operating margin and Adjusted EBITDA may be defined differently by other companies in our industry. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following tables reconcile the non-GAAP financial measures of total segment 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 three and nine months ended September 30, 2017 and 2016 (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Reconciliation of Segment Gross Margin to Net income (loss) attributable to the Partnership:
Gas Gathering and Processing Services segment gross margin	$	12,761		$	12,627		$	36,663		$	37,586
Liquid Pipelines and Services segment gross margin	7,808			7,600			21,209			23,829
Natural Gas Transportation Services segment gross margin	5,356			3,709			17,106			13,115
Offshore Pipelines and Services segment gross margin	29,312			24,126			80,738			57,947
Terminalling Services segment gross margin ⁽¹⁾	8,509			10,731			30,429			31,760
Total segment gross margin (non-GAAP)	63,746			58,793			186,145			164,237
Less:
Direct operating expenses ⁽¹⁾	17,274			14,695			47,316			45,999
Plus:
Gain (loss) on commodity derivatives, net	(597		)	324			(33		)	(1,929		)
Less:
Corporate expenses	27,083			22,103			84,570			60,945
Depreciation, amortization and accretion expense	26,781			22,668			78,834			65,937
(Gain) loss on sale of assets, net	(4,061		)	36			(4,064		)	297
Interest expense	17,759			5,830			51,037			24,723
Other (income) expense	(34,085		)	1			(32,248		)	(245		)
Other (income) expense, net	(139		)	(1,129		)	322			(1,773		)
Income tax expense	731			401			2,611			1,839
(Income) loss from discontinued operations, net of tax	(44,696		)	2,310			(42,185		)	(7,532		)
Net income attributable to noncontrolling interests	621			1,241			3,386			2,192
Net Income (loss) attributable to the Partnership	$	55,881		$	(9,039	)	$	(3,467	)	$	(30,074	)

_______________________

⁽¹⁾ Direct operating expenses include Gas Gathering and Processing Services segment direct operating expenses of $8.7 million and $7.9 million for the three months ended September 30, 2017 and 2016, respectively, and $24.8 million and $25.3 million, for the nine months ended September 30, 2017 and 2016, respectively, Liquid Pipelines and Services segment direct operating expenses of $2.4 million and $2.6 million for the three months ended September 30, 2017 and 2016, respectively, and $7.1 million and $8.2 million for the nine months ended September 30, 2017 and 2016, respectively, Natural Gas Transportation Services segment direct operating expenses of $2.2 million and $1.3 million for the three months ended September 30, 2017 and 2016, respectively, and $5.4 million and $4.5 million for the nine months ended September 30, 2017 and 2016, respectively, Offshore Pipelines and Services segment direct operating expenses of $3.9 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively, and $10.0 million and $8.0 million for the nine months ended September

Table of Contents

30, 2017 and 2016, respectively, and Direct operating expenses related to our Terminalling Services segment of $3.4 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively, as well as $9.5 million and $7.9 million for the nine months ended September 30, 2017 and 2016, respectively, are included within the calculation of Terminalling Services segment gross margin.



	Three months ended September 30,					Nine months ended September 30,
	2017		2016			2017			2016
Reconciliation of Net income (loss) attributable to the Partnership to Adjusted EBITDA:
Net income (loss) attributable to the Partnership	$	55,881	$	(9,039	)	$	(3,467	)	$	(30,074	)
Add:
Depreciation, amortization and accretion expense	26,685		22,668			78,173			65,937
Interest expense	14,959		5,014			43,769			22,395
Debt issuance costs paid	119		2,512			2,235			3,987
Unrealized losses (gains) on derivatives, net	325		(3,175		)	2,288			2,431
Non-cash equity compensation expense	835		1,234			6,067			4,285
Transaction expenses	10,470		4,983			31,155			9,145
Income tax expense	731		401			2,611			1,839
Distributions from unconsolidated affiliates	20,582		22,720			58,976			62,797
General Partner contribution for cost reimbursement	9,870		—			34,614			5,000
Deduct:
Earnings in unconsolidated affiliates	16,827		10,468			49,781			29,513
Gain on revaluation of equity interest	32,383		—			32,383			—
Discontinued operations	44,780		2,323			36,358			(7,561		)
Other income	86		389			241			342
OPEB plan net periodic benefit	5		20			16			13
Gain (loss) on sale of assets, net	4,061		(36		)	4,064			(297		)
Adjusted EBITDA	$	42,315	$	34,154		$	133,578		$	125,732

General Trends and Outlook

We expect our business to continue to be affected by the key trends discussed in the Recast Form 8-K, under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook.”

Results of Operations — Consolidated

Net income attributable to the Partnership increased by $64.8 million to $55.9 million for the three months ended September 30, 2017, as compared to net loss of $9.0 million in the same period in 2016, which was primarily due to the net gain on disposition of the Propane Business of $46.5 million, the gain of $32.3 million related to the MPOG acquisition and the $4.0 million gain recognized on Cayenne, offset partially by an increase in operating loss of $10.9 million and interest expense of $11.9 million.

Net loss decreased by $26.6 million, to $3.5 million for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the net gain on disposition of the Propane Business, gain related to the MPOG acquisition, offset partially by an increase in operating loss of approximately $32.0 million and an increase in interest expense of $26.3 million due to higher average debt balances from our growth initiatives as well as higher average interest costs.

Table of Contents

For the three months ended September 30, 2017, direct operating expenses increased by $3.1 million primarily due to the recent acquisitions of Viosca Knoll and Panther. Corporate expenses increased by $5.0 million, or 22.5%, due to an increase of $4.5 million of merger/disposition related costs which include legal, consulting services and employee severance costs. Interest expense increased by $12.0 million, or 206.9%, as a result of additional borrowings to fund capital growth and acquisitions. Earnings from unconsolidated affiliates increased by $6.4 million, or 60.7%, as result of our additional 6.6% investment in Delta House that occurred in the fourth quarter of 2016.

For the nine months ended September 30, 2017, direct operating expenses increased by $2.9 million primarily due to the recent acquisitions of Viosca Knoll and Panther partially offset by lower compressor rental costs. Corporate expenses increased by $23.7 million, or 38.9%, due to an increase of $18.6 million of merger-related costs which include legal, consulting services and employee severance costs; $3.0 million relating to a settlement of litigation claim; and $1.4 million of compensation relating to severance costs. Interest expense increased by $26.3 million, or 106.4%, as a result of a $25.0 million increase of interest expense due to additional borrowings to fund capital growth and acquisitions. Earnings from unconsolidated affiliates increased by $20.3 million, or 68.8%, as result of our additional 6.6% investment in Delta House that occurred in Q4 2016.

Segment gross margin was $63.7 million for the three months ended September 30, 2017 and $186.1 million for the nine months ended September 30, 2017 compared to $58.8 million for the three months ended September 30, 2016 and $164.2 million for the nine months ended September 30, 2016. The increase of $4.9 million for the three months ended September 30, 2017 was primarily due to our Offshore Pipelines and Services segment increase of $5.2 million as a result of higher earnings in unconsolidated affiliates. For the nine months ended September 30, 2017, the increase of $21.9 million was primarily due to our Offshore Pipelines and Services segment of $22.8 million as a result of increased earnings in unconsolidated affiliates and the American Panther system that was acquired in Q3 2016, and an increase in our Natural Gas Transportation Services segment of $4.0 million mostly due to higher throughput as a result of new firm transportation contracts on our Mid Louisiana Gas Transmission (MLGT), Midla and AlaTenn systems. These increases were partially offset by a decrease of $2.6 million related to our Liquids Pipeline and Services segment primarily attributable to higher average cost of crude barrels in 2017 compared to 2016 on Crude Oil Supply and Logistics (COSL) offset by higher sour crude marketing transactions that began in May 2017.

For the three and nine months ended September 30, 2017, Adjusted EBITDA increased $8.2 million, or 24.0%, and $7.8 million, or 6.2%, compared to the same periods in 2016, respectively. The increase is primarily related to support from our General Partner for cost reimbursement and partially offset by lower distributions from our unconsolidated affiliates.

We distributed $21.3 million to holders of our common units, or $0.4125 per common unit, during the three months ended September 30, 2017, and $67.6 million, or $1.2375 per common unit, during the nine months ended September 30, 2017.

Table of Contents

The results of operations by segment are discussed in further detail following this overview (in thousands):



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Statement of Operations Data:
Revenue:
Commodity sales	$	124,052		$	119,194		$	372,049		$	304,084
Services	38,835			40,385			116,382			110,998
Gain (loss) on commodity derivatives, net	(597		)	324			(33		)	(1,929		)
Total revenue	162,290			159,903			488,398			413,153
Operating expenses:
Costs of sales	112,398			107,249			342,886			270,712
Direct operating expenses	20,705			17,571			56,819			53,872
Corporate expenses	27,083			22,103			84,570			60,945
Depreciation, amortization and accretion	26,781			22,668			78,834			65,937
Total operating expenses	186,967			169,591			563,109			451,466
(Gain) loss on sale of assets, net	(4,061		)	36			(4,064		)	297
Operating loss	(20,616		)	(9,724		)	(70,647		)	(38,610		)
Other income (expense), net
Interest expense	(17,759		)	(5,830		)	(51,037		)	(24,723		)
Other income (expense)	34,085			(1		)	32,248			245
Earnings in unconsolidated affiliates	16,827			10,468			49,781			29,513
Income (loss) from continuing operations before income taxes	12,537			(5,087		)	(39,655		)	(33,575		)
Income tax expense	(731		)	(401		)	(2,611		)	(1,839		)
Income (loss) from continuing operations	11,806			(5,488		)	(42,266		)	(35,414		)
Income (loss) from discontinued operations, including net gain on disposition of $46.5 million (Note 4)	44,696			(2,310		)	42,185			7,532
Net income (loss)	56,502			(7,798		)	(81		)	(27,882		)
Less: Net income attributable to noncontrolling interests	621			1,241			3,386			2,192
Net income (loss) attributable to the Partnership	$	55,881		$	(9,039	)	$	(3,467	)	$	(30,074	)
Other Financial Data:
Total segment gross margin ⁽¹⁾	$	63,746		$	58,793		$	186,145		$	164,237
Adjusted EBITDA ⁽¹⁾	$	42,315		$	34,154		$	133,578		$	125,732

______________________


⁽¹⁾	For definitions of gross margin and Adjusted EBITDA and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP, and a discussion of how we use gross margin and Adjusted EBITDA to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Total Revenue. Our total revenue for the three months ended September 30, 2017 was $162.3 million compared to $159.9 million for the three months ended September 30, 2016. This increase of $2.4 million was primarily due to the following:


•	an increase in our Gas Gathering and Processing segment revenue of $5.6 million primarily due to new contracts at our Longview plant for NGLs, natural gas and condensate for $12.9 million, partially offset by a decrease in natural gas and condensate volumes at Chatom/Bazor Ridge for $5.3 million due to lower system volumes, and due to marketing contracts that ended in Q4 of 2016 for $1.1 million;

Table of Contents


•	a decrease in our Liquid Pipelines and Services revenue from operations of $0.9 million primarily due to the expiration of short-term marketing deals on COSL partially offset by sour crude marketing contracts that started in May 2017 for $0.7 million; and


•	a decrease in our Terminalling Services segment revenue of $1.4 million primarily due to a $1.5 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms.

Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude for the three months ended September 30, 2017 was $112.4 million compared to $107.2 million for the three months ended September 30, 2016. The increase of $5.2 million was mostly due to our Gas Gathering and Processing segment from higher NGL, natural gas and condensate purchases of $7.1 million due to an increase in throughput at the Longview Plant and an increase of $2.1 million primarily due to new sour crude marketing contracts partially offset by short-term marketing contracts on COSL that expired in 2016 in our Liquid Pipelines and Services segment, and the expiration of a marketing contract for $1.5 million in our Natural Gas Transportations Services segment.

Total Segment Gross Margin. Total segment gross margin for the three months ended September 30, 2017 was $63.7 million compared to $58.8 million for the three months ended September 30, 2016. The increase of $4.9 million was primarily due to our Offshore Pipelines and Services segment of $5.2 million as a result of increased earnings in unconsolidated affiliates mostly attributable to Delta House and Okeanos partially offset by a decrease in our Terminalling Services segment mainly due to lower contracted storage and rate terms at our Cushing terminal.

Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2017 were $20.7 million compared to $17.6 million for the three months ended September 30, 2016. This increase of $3.1 million was primarily due to an increase of $0.9 million related to the acquisitions of Viosca Knoll and Panther in 2017, an increase of $0.6 million due to fuel loss and recovery expense related to our Bamagas system, $0.7 million related to chemical purchases and $0.8 million in outside services and additional utilities charges.

Corporate Expenses. Corporate expenses for the three months ended September 30, 2017 were $27.1 million compared to $22.1 million for the three months ended September 30, 2016. This increase of $5.0 million was primarily due to an increase of $4.5 million of merger related costs which include legal, consulting services and employee severance costs. The remaining balance is primarily related to recruitment fees and higher employee costs due to increased headcount.

Depreciation, Amortization and Accretion Expense. Depreciation, amortization and accretion expense for the three months ended September 30, 2017 was $26.8 million compared to $22.7 million for the three months ended September 30, 2016. This increase of $4.1 million was primarily due to the decrease in useful life of certain intangible assets for $1.8 million and incremental depreciation of fixed assets primarily related to our recent acquisitions of Viosca Knoll and Panther.

Interest Expense. Interest expense for the three months ended September 30, 2017 was $17.8 million compared to $5.8 million for the three months ended September 30, 2016. The increase of $12.0 million was primarily due to interest charges on the 8.50% and 3.77% Senior Notes, which were issued in the fourth quarter of 2016, $6.4 million; unfavorable interest rate swaps contributed $2.2 million and the increased interest cost due to the borrowings on our revolving credit facility of $709.7 million.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended September 30, 2017 was $16.8 million compared to $10.5 million for the three months ended September 30, 2016. This increase of $6.3 million was primarily due to incremental earnings of $4.8 million related to our investment in Delta House and $0.9 million from Okeanos due to wells coming on line from the Thunderhorse expansion.

Income from discontinued operations. Income from discontinued operations is primarily associated with our Propane Business, including a net gain on disposition of $46.5 million for the three months ended September 30, 2017. The prior period’s results have been recast for comparative purposes.

Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016

Total Revenue. Our total revenue for the nine months ended September 30, 2017 was $488.4 million compared to $413.2 million for the nine months ended September 30, 2016. This increase of $75.2 million was primarily due to the following:

•

an increase in our Gas Gathering and Processing segment revenue of $25.3 million primarily due to increased revenue from sales of NGLs and condensate at the Longview Plant of $38.2 million due to three new contracts, two of which started in Q1 2017, partially offset by a decrease in NGL and condensate volumes at Chatom/Bazor Ridge of $6.4 million due to lower system volumes and due to marketing contracts that ended in fourth quarter of 2016 for $4.5 million;

Table of Contents


•	an increase in our Liquid Pipelines and Services segment revenue of $31.7 million primarily due to an increase in revenue of $34.6 million due to sour crude marketing transactions that started in May 2017;


•	an increase in our Natural Gas Transportation Services segment revenue of $6.6 million primarily due to an increase on the Magnolia system of $3.6 million due to favorable prices and $2.8 million of additional revenues on our MLGT, Midla and AlaTenn systems due to new firm transportation contracts;

•

an increase in our Offshore Pipelines and Services segment revenue of $8.8 million due primarily to higher volumes and management fees from our American Panther system for $7.0 million, $2.5 million of platform fee and transportation revenues as a result of the acquisition of the VKGS system in June 2017, increased volumes sold to the Alliance Refinery and new wells on our Gloria system for $3.8 million, partially offset by our High Point Gas Transmission (HPGT) system as a result of contracts expiring contributing to lower volumes for $5.0 million; and


•	an increase in our Terminalling Services segment revenue of $0.9 million primarily due to an expansion at our Harvey terminal for $1.9 million.

Cost of Sales. Our purchases of natural gas, NGLs, condensate and crude for the nine months ended September 30, 2017 was $342.9 million compared to $270.7 million for the nine months ended September 30, 2016. The increase of $72.2 million was primarily due to the Gas Gathering and Processing segment and higher NGL, natural gas and condensate purchases of $28.0 million due to an increase in throughput at the Longview Plant and an increase of $37.8 million in our Liquid Pipelines and Services segment mostly driven by sour crude marketing transactions that began in May 2017, and an increase in the average purchase cost for crude barrels in 2017 compared to 2016.

Total Segment Gross Margin. Total segment gross margin for the nine months ended September 30, 2017 was $186.1 million compared to $164.2 million for the nine months ended September 30, 2016. This increase of $21.9 million was primarily due to higher segment gross margin in our Offshore Pipelines and Services segment of $22.8 million as a result of increased earnings in unconsolidated affiliates and the VKGS system and American Panther that were acquired in the second quarter and third quarter of 2017, respectively, and due to an increase in our Natural Gas Transportation Services segment of $4.0 million mostly due to an increase in throughput as a result of new firm transportation contracts on our MLGT, Midla and AlaTenn systems. These increases were partially offset by a decrease of $2.6 million related to our Liquid Pipelines and Services segment primarily attributable to items discussed above, partially offset by increased volumes on Tri-States.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2017 were $56.8 million compared to $53.9 million for the nine months ended September 30, 2016. This increase of $2.9 million was primarily due to $0.8 million related to the newly acquired VKGS and Panther entities, $0.8 million related to chemical purchases, $0.7 million related to fuel loss and recovery at Bamagas and $0.3 million in repair and maintenance.

Corporate Expenses. Corporate expenses for the nine months ended September 30, 2017 were $84.6 million compared to $60.9 million for the nine months ended September 30, 2016. This increase of $23.7 million was primarily due to an increase of $18.6 million of merger related costs which include legal, consulting services and employee severance costs; $3.0 million relating to the settlement of a litigation claim and $0.6 million higher insurance premiums on offshore assets.

Depreciation, Amortization and Accretion Expense. Depreciation, amortization and accretion expense for the nine months ended September 30, 2017 was $78.8 million compared to $65.9 million for the nine months ended September 30, 2016. This increase of $12.9 million was primarily due to $7.0 million increase in amortization expense caused by the acceleration of customer list useful life and incremental depreciation of fixed assets acquired in the last 12 months mainly related to our Midla and Mesquite projects, as well as a increase in depreciation due to our recent acquisitions.

Interest Expense. Interest expense for the nine months ended September 30, 2017 was $51.0 million compared to $24.7 million for the nine months ended September 30, 2016. This increase of $26.3 million was primarily due to interest on the 8.50% and 3.77% Senior Notes issued in the fourth quarter of 2016 increasing interest expense $21.0 million, and increased interest expense associated with higher borrowings on the Credit agreement of $2.7 million and $1.3 million in amortization of financing costs.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the nine months ended September 30, 2017 was $49.8 million compared to $29.5 million for the nine months ended September 30, 2016. This increase of $20.3 million was primarily due to incremental earnings of $12.6 million related to our increased investment in Delta House, $6.2 million from our interests in the Destin and Okeanos systems and $2.2 million from our interests in Tri-States and Wilprise.

Income from discontinued operations. Income from discontinued operations is primarily associated with our Propane Business, including a net gain on disposition of $46.5 million for the nine months ended September 30, 2017. The prior period’s results have been recast for comparative purposes.

Table of Contents

Results of Operations — Segment Results

Gas Gathering and Processing Services Segment

The table below contains key segment performance indicators related to our Gathering and Processing Services segment (in thousands except operating and pricing data).



	Three months ended September 30,					Nine months ended September 30,
	2017			2016		2017			2016
Segment Financial and Operating Data:
Gas Gathering and Processing Services segment
Financial data:
Commodity sales	$	31,651		$	25,776	$	94,074		$	67,053
Services	5,636			5,874		16,927			18,602
Revenue from operations	37,287			31,650		111,001			85,655
Gain (loss) on commodity derivatives, net	(65		)	149		(170		)	(716		)
Segment revenue	37,222			31,799		110,831			84,939
Cost of sales	24,492			18,477		74,261			47,344
Direct operating expenses	8,655			7,856		24,766			25,344
Other financial data:
Segment gross margin ⁽²⁾	$	12,761		$	12,627	$	36,663		$	37,586
Operating data:
Average throughput (MMcf/d)	201.0			211.0		205.0			218.0
Average plant inlet volume (MMcf/d) ⁽¹⁾	94.9			103.7		100.0			103.0
Average gross NGL production (Mgal/d) ⁽¹⁾	324.3			181.7		340.0			240.0
Average gross condensate production (Mgal/d) ⁽¹⁾	57.5			87.1		73.0			81.0

_______________________

⁽¹⁾ Excludes volumes and gross production under our elective processing arrangements.

⁽²⁾ For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Commodity sales. Commodity sales revenue for the three months ended September 30, 2017 was $31.7 million compared to $25.8 million for the three months ended September 30, 2016. The increase of $5.9 million resulted from a combination of the following:


•	increased revenue from sales of NGLs, natural gas and condensate at the Longview Plant of $12.5 million due to three new contracts, two of which started in first quarter of 2017;


•	offset by reduced NGL, natural gas and condensate volumes at Chatom/Bazor Ridge for $5.3 million due to lower system volumes (production declines and loss of Y-grade product); and


•	also offset by marketing contracts that ended in fourth quarter of 2016 for $1.1 million.

Services. Segment services revenue for the period ended September 30, 2017 was $5.6 million compared to $5.9 million for the three months ended September 30, 2016. The decrease is primarily due to a reduction in Construction, Operating and Management Agreement (COMA) fee revenue on Yellow Rose of $0.3 million and lower gathering charges of $0.1 million on our Lavaca system, offset by increased service fee revenue of $0.2 million at Chatom/Bazor Ridge for a pipeline connection recovery fee.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended September 30, 2017 were $24.5 million compared to $18.5 million for the three months ended September 30, 2016. The increase of $6.0 million was primarily due to the increase of NGL, natural gas and condensate sales at the Longview Plant, as discussed above.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017 was $12.8 million compared to $12.6 million for the three months ended September 30, 2016, for reasons discussed above.

Table of Contents

Direct Operating Expenses. Direct operating expenses for three months ended September 30, 2017 was $8.7 million compared to $7.9 million for the three months ended September 30, 2016. The $0.8 million increase is mainly due to $0.4 million in environmental compliance and chemical purchases as well as additional repairs of $0.3 million related to right-of-way sinkage and other repair and maintenance.

Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016

Commodity sales. Commodity sales revenue for the nine months ended September 30, 2017 was $94.1 million compared to $67.1 million for the nine months ended September 30, 2016. The increase of $27.0 million was primarily due to the following:


•	increased revenue from sales of NGLs and condensate at the Longview Plant of $38.2 million due to three new contracts, two of which started in Q1 2017;


•	offset by reduced NGL and condensate volumes at Chatom/Bazor Ridge for $6.4 million due to lower system volumes (production declines and loss of Y-grade product); and


•	also offset by marketing contracts that ended in Q4 of 2016 for $4.5 million.

Services. Segment services revenue for the six months ended September 30, 2017 was $16.9 million compared to $18.6 million for the nine months ended September 30, 2016. The decrease is primarily due to a decline in compression and gathering charges of $1.6 million on our Lavaca system, lower fractionation and transportation fees of $0.9 million on Longview, production ceasing at Southern Industrial Gas Corp. (SIGCO) for $0.4 million which was partially offset by increased service fee revenue of $1.2 million at Chatom/Bazor Ridge for a pipeline connection recovery fee.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $74.3 million compared to $47.3 million for the nine months ended September 30, 2016. This increase of $27.0 million was primarily due to the increase of NGL, natural gas and condensate sales at the Longview Plant, as discussed above.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $36.7 million compared to $37.6 million for the nine months ended September 30, 2016, for reasons as discussed above.

Direct Operating Expenses. Direct operating expenses of $24.8 million for nine months ended September 30, 2017 declined from $25.3 million for the nine months ended September 30, 2016, mainly due to our ongoing cost savings initiatives reducing compressor rentals and labor costs by $0.3 million and $0.2 million in lower regulatory costs.

Table of Contents

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 and pricing data).



	Three months ended September 30,					Nine months ended September 30,
	2017			2016		2017		2016
Segment Financial and Operating Data:
Liquid Pipelines and Services segment
Financial data:
Commodity sales	$	82,948		$	83,682	$	241,459	$	206,857
Services	4,074			4,216		12,131		15,009
Revenue from operations	87,022			87,898		253,590		221,866
Gain (loss) on commodity derivatives, net	(532		)	177		137		(772		)
Earnings in unconsolidated affiliates	1,317			650		3,886		1,658
Segment revenue	87,807			88,725		257,613		222,752
Cost of sales	80,510			80,372		236,896		199,111
Direct operating expenses	2,438			2,617		7,137		8,186
Other financial data:
Segment gross margin ⁽¹⁾	$	7,808		$	7,600	$	21,209	$	23,829
Operating data ⁽²⁾ :
Average throughput Pipeline (Bbls/d)	35,403			30,371		33,837		31,083
Average throughput Truck (Bbls/d)	2,632			1,638		2,048		1,625

_______________________

⁽¹⁾ For the definition of segment gross margin and a discussion of how we use segment gross margin to evaluate our operating performance, see the information in this Item under the caption “How We Evaluate Our Operations.”

⁽²⁾ These volumes exclude volumes from our equity investments.

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Commodity Sales. Segment revenue from crude oil for the three months ended September 30, 2017 was $82.9 million compared to $83.7 million for the three months ended September 30, 2016. The decrease of $0.8 million was primarily due to the expiration of short-term marketing deals on COSL that expired in second quarter of 2016 for $19.6 million partially offset by $18.9 million of sour crude marketing contracts that started in May 2017.

Services revenue. Segment services revenue for the three months ended September 30, 2017 was $4.1 million and remained relatively flat compared to $4.2 million for the three months ended September 30, 2016.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the three months ended September 30, 2017 was $1.3 million compared to $0.6 million for the three months ended September 30, 2016. The increase of $0.7 million was due to increased volumes on Tri-States as a result of increased production from the Delta House and Thunderhorse platforms.

Cost of Sales. Purchases of crude oil for the three months ended September 30, 2017 was $80.5 million compared to $80.4 million for the three months ended September 30, 2016. The increase of $0.1 million was primarily due to $18.7 million of sour crude marketing transactions that began in May 2017 partially offset by $18.2 million of short-term marketing deals on COSL that expired in third quarter of 2016, and price increases in 2017 compared to 2016.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017, was $7.8 million compared to $7.6 million for the three months ended September 30, 2016. The increase of $0.2 million is due to the reasons discussed above.

Direct Operating Expenses. Direct operating expenses of $2.4 million for the three months ended September 30, 2017 declined from $2.6 million for the three months ended September 30, 2016, mainly due to a decrease of $0.2 million for equipment lease and measurement costs.

Table of Contents

Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016

Commodity Sales. Segment revenue from crude oil for the nine months ended September 30, 2017 was $241.5 million compared to $206.9 million for the nine months ended September 30, 2016. The increase of $34.6 million was primarily due to the sour crude marketing transactions that started in May 2017.

Services revenue. Segment services revenue for the nine months ended September 30, 2017 was $12.1 million compared to $15.0 million for the nine months ended September 30, 2016. The decrease of $2.9 million was primarily due to a $2.0 million reduction in transport gallons on AMID Trucking and tariff rate reductions of $0.6 million on Bakken.

Earnings in Unconsolidated Affiliates. Earnings in unconsolidated affiliates for the nine months ended September 30, 2017 was $3.9 million compared to $1.7 million for the nine months ended September 30, 2016, resulting from the acquisition of Tri-States and Wilprise in late April 2016, and increased volumes on Tri-States, due to increased production from the Delta House and Thunderhorse platforms.

Cost of Sales. Purchases of crude oil for the nine months ended September 30, 2017 was $236.9 million compared to $199.1 million for the nine months ended September 30, 2016. The increase of $37.8 million is primarily due to the increase in sour crude marketing transactions that started in May 2017 for $33.7 million and an increase in the average purchase cost of barrels in 2017 compared to 2016 on COSL of $4.7 million.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017, was $21.2 million compared to $23.8 million for the nine months ended September 30, 2016. The Segment margin decreased by $2.6 million due to the reasons discussed above.

Direct Operating Expenses. Direct operating expenses of $7.1 million for the nine months ended September 30, 2017 declined from $8.2 million for the nine months ended September 30, 2016 mainly due to $0.6 million equipment lease costs, $0.3 million of lower property tax expense and $0.2 million for measurement equipment costs.

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 and pricing data).



	Three months ended September 30,				Nine months ended September 30,
	2017		2016		2017		2016
Segment Financial and Operating Data:
Natural Gas Transportation Services segment
Financial data:
Commodity sales	$	6,175	$	6,805	$	19,485	$	15,682
Services	4,956		3,904		15,481		12,701
Segment revenue	11,131		10,709		34,966		28,383
Cost of sales	5,692		6,994		17,630		15,245
Direct operating expenses	2,240		1,324		5,403		4,515
Other financial data:
Segment gross margin ⁽¹⁾	$	5,356	$	3,709	$	17,106	$	13,115
Operating data:
Average throughput (MMcf/d)	423.0		517.0		407.0		461.0

_______________________

Table of Contents

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended September 30, 2017 were $6.2 million compared to $6.8 million for the three months ended September 30, 2016. The small decrease of $0.6 million is primarily due to a contract expiration in June 2017.

Services revenue. Segment services revenue for the three months ended September 30, 2017 was $5.0 million compared to $3.9 million for the three months ended September 30, 2016. The increase of $1.1 million is primarily due to new firm transportation contracts on our Mid Louisiana Gas Transmission (MLGT) and Midla systems.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the three months ended September 30, 2017 were $5.7 million as compared to $7.0 million for the three months ended September 30, 2016. The decrease of $1.3 million is primarily due to the expiration of a marketing contract in June 2017 for $1.0 million and an imbalance cost of $0.5 million on Midla.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017, was $5.4 million compared to $3.7 million for the three months ended September 30, 2016. The increase of $1.7 million is primarily due to reasons discussed above.

Direct Operating Expenses. Direct operating expenses for the three months ended September 30, 2017 were $2.2 million compared to $1.3 million for the three months ended September 30, 2016. The increase of $0.9 million is primarily due to a $0.4 million increase in property tax expense, $0.3 million in environmental compliance fees and a $0.2 million increase in outside services.

Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $19.5 million compared to $15.7 million for the nine months ended September 30, 2016. The increase of $3.8 million is primarily due to an increase on the Magnolia system of $3.6 million from higher prices in 2017 and marketing increases for $0.2 million.

Services revenue. Segment services revenue for the nine months ended September 30, 2017 was $15.5 million compared to $12.7 million for the nine months ended September 30, 2016. The increase of $2.8 million was mostly due to new firm transportation contracts on MLGT of $1.2 million, Midla of $0.8 million and AlaTenn of $0.6 million.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $17.6 million as compared to $15.2 million for the nine months ended September 30, 2016. The increase of $2.4 million is primarily due to higher prices on Magnolia of $3.3 million, offset by imbalances of $1.0 million on our AlaTenn, Chalmette and Midla systems.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $17.1 million compared to $13.1 million for the nine months ended September 30, 2016. The increase of $4.0 million is primarily due to reasons discussed above.

Direct Operating Expenses. Direct operating expenses for the nine months ended September 30, 2017 were $5.4 million compared to $4.5 million for the nine months ended September 30, 2016. The increase of $0.9 million is primarily due to $0.6 million in property tax expense and environmental compliance fees as well as $0.3 million in outside services and repair and maintenance costs.

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 and pricing data).

Table of Contents



	Three months ended September 30,					Nine months ended Septmeber 30,
	2017		2016			2017		2016
Segment Financial and Operating Data:
Offshore Pipelines and Services segment
Financial data:
Commodity sales	$	2,182	$	1,734		$	8,385	$	5,556
Services	12,178		13,145			32,945		26,970
Revenue from operations	14,360		14,879			41,330		32,526
Gain (loss) on commodity derivatives, net	—		(2		)	—		(5		)
Earnings in unconsolidated affiliates	15,510		9,819			45,895		27,855
Segment revenue	29,870		24,696			87,225		60,376
Cost of sales	558		570			6,487		2,429
Direct operating expenses	3,940		2,898			10,010		7,954
Other financial data:
Segment gross margin ⁽¹⁾	$	29,312	$	24,126		$	80,738	$	57,947
Operating data ⁽²⁾:
Average throughput (MMcf/d)	257.0		467.0			328.0		464.0

_______________________

⁽²⁾ These volumes exclude Equity Investment volumes.

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the three months ended September 30, 2017 was $2.2 million compared to $1.7 million for the three months ended September 30, 2016. The increase of $0.5 million was primarily due to increased volumes sold to the Alliance Refinery on our Gloria system for $0.9 million, offset by reduced condensate revenue on High Point Gas Transmission facility (“HPGT”) for $0.4 million.

Services revenue. Segment services revenue for the three months ended September 30, 2017 was $12.2 million compared to $13.1 million for the three months ended September 30, 2016. The decrease of $0.9 million was primarily due to a contract expiration and lower production volumes on HPGT of $4.0 million, partially offset by platform fee and transportation revenues on the VKGS system of $2.0 million, higher management fees on American Panther of $0.8 million and higher firm transportation on Gloria for $0.4 million.

Earnings in unconsolidated affiliates. Earnings for the three months ended September 30, 2017 were $15.5 million compared to $9.8 million for the three months ended September 30, 2016. The increase of $5.7 million was due to the additional Delta House acquisition in fourth quarter of 2016 for $4.8 million and it is continuing to perform near nameplate capacity as a result of strong performance by the producers that supply volumes to the offshore facility, and $0.9 million on Okeanos due to wells coming online as a result of the Thunderhorse south platform expansion.

Cost of Sales. Purchases of natural gas, NGLs and condensate remained flat for the three months ended September 30, 2017 compared to the three months ended September 30, 2016.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017 was $29.3 million compared to $24.1 million for the three months ended September 30, 2016. The increase of $5.2 million was primarily due to increased earnings in unconsolidated affiliates as noted above.

Direct Operating Expenses. Direct operating expenses were $3.9 million and $2.9 million for the three months ended September 30, 2017 and 2016, respectively. The increase of $1.0 million is mainly due to $0.4 million in rental equipment, $0.3 million in property tax expense and $0.3 million in environmental compliance fees.

Table of Contents

Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016

Commodity Sales. Segment sales of natural gas, NGLs and condensate for the nine months ended September 30, 2017 was $8.4 million compared to $5.6 million for the nine months ended September 30, 2016. The increase of $2.8 million was primarily due to increased volumes sold to the Alliance Refinery for $2.6 million and new wells coming on line for $1.2 million on our Gloria system, partially offset by a $0.6 million decrease in condensate revenue on our HPGT system.

Services revenue. Segment services revenue for the nine months ended September 30, 2017 was $32.9 million compared to $27.0 million for the nine months ended September 30, 2016. The increase of $5.9 million was primarily due to higher management fees of $5.7 million and $1.3 million for crude transportation volumes as a result of the acquisition of American Panther in April 2016, $2.5 million of platform fee and transportation revenues on VKGS as a result of the acquisition of VKGS in June 2017, and $1.0 million of new firm transportation contracts that started October 2016 on our Gloria system, partially offset by $5.0 million as a result of contracts expiring in December 2016 and January 2017, along with lower production volumes on HPGT.

Earnings in unconsolidated affiliates. Earnings for the nine months ended September 30, 2017 were $45.9 million compared to $27.9 million for the nine months ended September 30, 2016. The increase of $18.0 million was due to the additional Delta House acquisition in fourth quarter of 2016 for $12.6 million and it is continuing to perform near nameplate capacity as a result of strong performance by the producers that supply volumes to the offshore facility, $3.1 million on Destin from nine months of ownership in 2017 compared to five months in 2016, and higher volumes on Okeanos for $3.0 million, which were partially offset by $0.8 million on our Main Pass Oil Gathering (MPOG) system due to lower volumes as a result of platform operational issues and maintenance downtime.

Cost of Sales. Purchases of natural gas, NGLs and condensate for the nine months ended September 30, 2017 were $6.5 million compared to $2.4 million for the nine months ended September 30, 2016. The increase of $4.1 million was primarily due to additional throughput on our Gloria system as noted above.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $80.7 million compared to $57.9 million for the nine months ended September 30, 2016. The increase of $22.8 million was primarily due to the items discussed above.

Direct Operating Expenses. Direct operating expenses were $10.0 million and $8.0 million for the nine months ended September 30, 2017 and 2016, respectively. This increase of $2.0 million is mainly due to $0.5 million in repair and maintenance, $0.4 million increase in rental equipment, $0.4 million increase in property tax expense, $0.4 million in environmental compliance fees and $0.3 million in outside services and contractors expense.

Terminalling Services Segment

The table below contains key segment performance indicators related to our Terminalling Services segment (in thousands except operating data).

Table of Contents



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
Segment Financial and Operating Data:
Terminalling Services segment
Financial data:
Commodity sales	$	1,094		$	1,197		$	8,644		$	8,936
Services	11,993			13,246			38,900			37,716
Revenue from operations	13,087			14,443			47,544			46,652
Loss on commodity derivatives, net	—			—			—			(436		)
Segment revenue	13,087			14,443			47,544			46,216
Cost of sales	1,146			836			7,612			6,583
Direct operating expenses	3,432			2,876			9,503			7,873
Other financial data:
Segment gross margin ⁽²⁾	$	8,509		$	10,731		$	30,429		$	31,760
Operating data:
Contracted capacity (Bbls)	4,759,978			5,224,067			5,066,337			4,920,533
Design capacity (Bbls) ⁽³⁾	5,400,800			5,342,467			5,400,800			5,098,022
Storage utilization ⁽¹⁾	88.1		%	97.8		%	93.8		%	96.5		%
Terminalling and Storage throughput (Bbls/d)	60,002			55,675			59,005			58,073

_______________________

⁽¹⁾ Excludes storage utilization associated with our discontinued operations.

⁽³⁾ Excludes Caddo Mills and North Little Rock.

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

Commodity Sales. Segment commodity sales for the three months ended September 30, 2017 was $1.1 million compared to $1.2 million for the three months ended September 30, 2016. The decrease of $0.1 million relates to our refined products and is driven by product volume losses.

Services Revenue. Segment services revenue for the three months ended September 30, 2017 was $12.0 million compared to $13.2 million for the three months ended September 30, 2016. The decrease of $1.2 million is primarily driven by a $1.5 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms and a $0.3 million reduction in storage and ancillary service revenue from the loss of a customer at our Harvey terminal, partially offset by $0.6 million increase in throughput revenues at our Caddo Mills terminal as a result of facility enhancements.

Cost of Sales. Segment purchases of NGLs for the three months ended September 30, 2017 were $1.1 million compared to $0.8 million for the three months ended September 30, 2016. The increase of $0.3 million is primarily due to higher butane costs.

Segment Gross Margin. Segment gross margin for the three months ended September 30, 2017 was $8.5 million compared to $10.7 million for the three months ended September 30, 2016. The $2.2 million decrease is mostly driven by the decrease in Cushing storage and higher operating costs at Harvey.

Direct Operating Expenses. Segment direct operating expenses for the three months ended September 30, 2017 was $3.4 million compared to $2.9 million for the three months ended September 30, 2016. This increase was mainly due to $0.3 million in environmental costs and $0.2 million for railcar derailment repairs, railroad demurrage and boiler repair costs at our Harvey facility.

Nine months ended September 30, 2017 Compared to Nine months ended September 30, 2016

Commodity Sales. Segment commodity sales for the nine months ended September 30, 2017 was $8.6 million compared to $8.9 million for the nine months ended September 30, 2016. The decrease of $0.3 million relates to our refined products and is driven by a decrease in butane blending volumes.

Table of Contents

Services Revenue. Segment services revenue for the nine months ended September 30, 2017 was $38.9 million compared to $37.7 million for the nine months ended September 30, 2016. The $1.2 million increase is driven by a $1.9 million increase in contracted capacity and related ancillary services as a result of the expansion efforts at the Harvey terminal and by a $1.3 million increase in throughput revenue primarily from new volumes from an existing customer starting in April 2017 and facility enhancements at our Caddo Mills terminal, partially offset by a $1.5 million reduction in storage and utilization at our Cushing terminal from a new contract with lower storage and rate terms and $0.5 million, and a decrease in throughput revenue at our North Little Rock terminal due to the loss of a customer in July 2016.

Cost of Sales. Segment purchases of NGLs for the nine months ended September 30, 2017 was $7.6 million compared to $6.6 million for the nine months ended September 30, 2016. The increase of $1.0 million is primarily due to higher butane costs.

Segment Gross Margin. Segment gross margin for the nine months ended September 30, 2017 was $30.4 million compared to $31.8 million for the nine months ended September 30, 2016. The $1.4 million decrease is mostly driven by the decrease in Cushing storage, higher operating costs at Harvey and higher butane costs, partially offset by the Harvey expansion efforts and the Caddo Mills facility enhancements discussed above.

Direct Operating Expenses. Segment direct operating expenses for the nine months ended September 30, 2017 was $9.5 million compared to $7.9 million for the nine months ended September 30, 2016. This increase was mainly driven by $0.5 million in environmental costs, $0.6 million in contractors and outside services for the Harvey facility expansion, $0.3 million increase in property taxes and $0.2 million for railcar derailment repairs, railroad demurrage and boiler repair costs at the Harvey facility.

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 and facilities.

Our principal sources of liquidity include cash from operating activities, borrowings under our Credit Agreement (as defined herein), or through private transactions. In addition, we may seek to raise capital through the issuance of secured and unsecured senior notes. Given our historical success in accessing various sources of liquidity, we believe that the sources of liquidity described above will be sufficient to meet our short-term working capital requirements, medium-term maintenance capital expenditure requirements, and quarterly cash distributions for at least the next four quarters. In the event these sources are not sufficient, we would pursue other sources of cash funding, including, but not limited to, additional forms of debt or equity financing. In addition, we would reduce non-essential capital expenditures, direct operating expenses and corporate expenses, as necessary, and our Partnership Agreement allows us to reduce or eliminate quarterly distributions, if required to maintain ongoing operations. We plan to finance our growth capital expenditures mainly through additional forms of debt or equity financing, as well as proceeds from the sale of non-core assets.

Changes in natural gas, crude oil, NGL and condensate prices and the terms of our contracts may have a direct impact on our generation and use of cash from operations due to their impact on net income (loss), along with the resulting changes in working capital. In the past, we mitigated a portion of our anticipated commodity price risk associated with the volumes from our gathering and processing activities with fixed price commodity swaps. For additional information regarding our derivative activities, see the information provided under Part II, Item 7A of our 2016 Annual Report on Form 10-K, under the caption, “Quantitative and Qualitative Disclosures about Market Risk” and Part I, Item 3 of this Quarterly Report under the caption “Quantitative and Qualitative Disclosures about Market Risk”.

The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds is determined on a counterparty by counterparty basis, and is impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative natural gas and crude oil forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. As of September 30, 2017, we have not been required to post collateral with our counterparties.

Table of Contents

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 common units in an at-the-market offering. For the quarter ended September 30, 2017, we did not sell any common units under our ATM program and have approximately $96.8 million remaining available for sale under the Partnership’s ATM Equity Offering Sales Agreement.

Our Revolving Credit Facilities

AMID

On March 8, 2017, we entered into the Second Amended and Restated Credit Agreement, with Bank of America N.A., as Administrative Agent, Collateral Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, and other lenders or Credit Agreement, which increased our borrowing capacity from $750.0 million to $900.0 million and provided for an accordion feature that will permit, subject to customary conditions, the borrowing capacity under the facility to be increased to a maximum of $1.1 billion.

On September 30, 2016, in connection with the Note Purchase Agreement (as defined below), we entered into the Limited Waiver and Third Amendment to the Credit Agreement, which among other things, (i) allows Midla Holdings (as defined below), for so long as the 3.77% Senior Notes are outstanding, to be excluded from guaranteeing the obligations under the Credit Agreement and being subject to certain covenants thereunder, (ii) releases the lien granted under the original credit agreement on D-Day’s equity interests in FPS Equity, and (iii) deems the FPS Equity excluded property under the Credit Agreement. All other terms under the Credit Agreement remain the same.

For the nine months ended September 30, 2017 and 2016, the weighted average interest rate on borrowings under our Credit Agreement and the JPE Revolver (as defined below) was approximately 4.85% and 2.82%, respectively. At September 30, 2017 and December 31, 2016, letters of credit outstanding under the Credit Agreement were $33.1 million and $7.4 million, respectively. As of September 30, 2017, we had approximately $709.7 million of borrowings and $33.1 million of letters of credit outstanding under the Credit Agreement resulting in $157.3 million of available borrowing capacity.

As of September 30, 2017, our consolidated total leverage ratio was 4.68 and our interest coverage ratio was 4.41, which were both in compliance with the related requirements of our Credit Agreement. Our ability to maintain compliance with the leverage and interest coverage ratios included in the Credit Agreement may be subject to, among other things, the timing and success of initiatives we are pursuing, which may include expansion capital projects, acquisitions, or drop down transactions, as well as the associated financing for such initiatives. See Note 13 - Debt Obligations to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report for further discussion of the Credit Agreement.

We use the term “revolving credit facility” or “Credit Agreement,” to refer to our First Amended and Restated Credit Facility and to our Second Amended and Restated Credit Facility, as the context may require.

JPE Revolver

8.50% Senior Unsecured Notes

On December 28, 2016, the Issuers completed the issuance and sale of the $300 million 8.50% Senior Notes. 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 of payment to any future subordinated indebtedness of the Issuers. The 8.50% Senior Notes were issued at par and provided approximately $294.0 million in proceeds, after deducting the initial purchasers' discount of $6.0 million. This amount was deposited into escrow pending completion of the JPE Acquisition and is included in Restricted cash-long term on our unaudited consolidated balance sheet as of December 31, 2016.

We also incurred $2.7 million of debt issuance costs resulting in net proceeds related to the 8.50% Senior Notes of $291.3 million. The 8.50% Senior notes were offered and sold to qualified institutional buyers in the United States pursuant to Rule 144A under the Securities Act, and to persons, other than U.S. persons, outside the United States pursuant to Regulation S under the Securities

Table of Contents

Act. Upon the closing of the JPE Acquisition and the satisfaction of other conditions related thereto, the proceeds were used to repay and terminate the JPE Revolver and reduce borrowings under our 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 June 15, 2017. See Note 13 - Debt Obligations to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report for further discussion of the 8.50% Senior Notes.

3.77% Senior Secured Notes

On September 30, 2016, Midla Financing (“Midla Financing”) American Midstream (Midla) LLC (“Midla”), and Mid Louisiana Gas Transmission LLC (“MLGT” and together with Midla, the “Note Guarantors”) entered into the 3.77% Senior Note Purchase and Guaranty Agreement (the “Note Purchase Agreement”) with the purchasers party thereto (the “Purchasers”). Pursuant to the Note Purchase Agreement, Midla Financing issued and sold $60.0 million in aggregate principal amount of 3.77% Senior Notes (non-recourse) due June 30, 2031 (the “3.77% Senior Notes”) to the Purchasers, which bear interest at an annual rate of 3.77% to be paid quarterly. The average quarterly principal payment is approximately $1.1 million. Principal on the 3.77% Senior Notes will be paid on the last business day of each fiscal quarter end which began June 30, 2017. The 3.77% Senior Notes are payable in full on June 30, 2031. The 3.77% Senior Notes were issued at par and provided net proceeds of approximately $49.8 million (after deducting related issuance costs). The proceeds are contractually restricted. The 3.77% Senior Notes are non-recourse to the Partnership.

In connection with the Note Purchase Agreement, the Note Guarantors guaranteed the payment in full of all Midla Financing’s obligations under the Note Purchase Agreement. Also, Midla Financing and the Note Guarantors granted a security interest in substantially all of their tangible and intangible personal property, including the membership interests in each Note Guarantor held by Midla Financing, and Financing Holdings pledged the membership interests in Midla Financing to the Collateral Agent.

Net proceeds from the 3.77% Senior Notes are restricted and have been be used (1) to fund project costs incurred in connection with (a) the construction of the Midla-Natchez Line (b) the retirement of Midla’s existing 1920’s vintage pipeline (c) the move of our Baton Rouge operations to the MLGT system (d) the reconfiguration of the DeSiard compression system and all related ancillary facilities, (2) to pay transaction fees and expenses in connection with the issuance of the 3.77% Senior Notes, and (3) for other general corporate purposes of Midla Financing. See Note 13 - Debt Obligations to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on further discussion of the 3.77% Senior Notes.

Acquisition Support and Reimbursement

During the third quarter of 2017, our general partner agreed to provide support of $9.8 million in terms of our support agreement that was executed in conjunction with the JPE Acquisition. The Partnership has utilized the full $25.0 million of support as of September 30, 2017.

Working Capital

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. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause 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. We expect that our future working capital requirements will be impacted by these same factors. Our working capital was $14.9 million at September 30, 2017, compared with a working capital deficit of $16.4 million at December 31, 2016.

Table of Contents

Cash Flows

The following table reflects cash flows for the applicable periods (in thousands):



	Nine months ended September 30,
	2017			2016
Net cash provided by (used in):
Operating activities	$	23,368		$	84,059
Investing activities	292,811			(200,981		)
Financing activities	(315,106		)	121,582
Net cash increase in cash and cash equivalents	$	1,073		$	4,660

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

Operating Activities. During the nine months ended September 30, 2017, we had $23.4 million of cash provided by operating activities, a decrease of $60.7 million when compared to $84.1 million of cash provided by operating activities in the same period in 2016. The decrease in cash flows from operating activities year-over-year, resulted primarily from a increase in corporate expenses of $23.6 million driven mostly by our transaction and merger related expenses and an increase in interest expense of $26.3 million driven by our higher borrowings and higher operating costs of $3 million related primarily to our newly acquired assets.,

Investing Activities. During the nine months ended September 30, 2017, net cash provided by investing activities was $292.8 million, an increase of $493.8 million as compared to net cash used in investing activities of $201.0 million in the same period of 2016. The increase of cash flows from investing activities resulted primarily from the release of $302.7 million in restricted cash in March 2017 that was recorded since the end of 2016 and held in escrow and the proceeds of $168.0 million from the sale of our Propane Business, net of cash on hand, partially offset by a cash outflow related to increased acquisitions as compared to the nine months ended September 30, 2016.

Financing Activities. During the nine months ended September 30, 2017, net cash used in financing activities was $315.1 million, a decrease of $436.7 million as compared to net cash provided by financing activities of $121.6 million in the same period in 2016. The decrease in cash flows from financing activities was due primarily to the additional pay downs on our Credit Agreement of $373.8 million and distributions to our General Partner from our common control transactions associated with Delta House for $75.5 million partially offset by $38.3 million related to General Partner’s contributions.

Distribution to our unitholders

In the nine months ended September 30, 2017, we paid a total of approximately $89.0 million of distributions to our unitholders. This was made possible primarily by $23.4 million of cash generated from operating activities, plus $38.2 million of support from our general partner and approximately $9.1 million of distributions relating to our unconsolidated affiliates return of capital.

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 September 30, 2017, our material off-balance sheet arrangements and transactions included operating lease arrangements and service contracts. There are no other transactions, arrangements, or other relationships associated with our investments in unconsolidated affiliates or related parties that are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources. At September 30, 2017, our off-balance sheet arrangements totaled $34.9 million.

Capital Requirements

The energy business is capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems 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, our capital assets) made to maintain our operating income or operating capacity; or

Table of Contents


•	expansion capital expenditures, incurred for acquisitions of capital assets or capital improvements that we expect will increase our operating income or operating 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 the regions 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. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our Partnership Agreement.

For the three months ended September 30, 2017, capital expenditures totaled $20.7 million, including expansion capital expenditures of $18.2 million, maintenance capital expenditures of $2.4 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 $0.1 million. For the nine months ended September 30, 2017, capital expenditures totaled $65.0 million, including expansion capital expenditures of $55.9 million, maintenance capital expenditures of $6.6 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 $2.6 million. Of these capital expenditures amounts, $0.7 million and $3.1 million were incurred for the Propane Business that we disposed on September 1, 2017, as discussed in Note 4 - Dispositions.

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 our Partnership Agreement.

On October 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 quarter ended September 30, 2017, or $1.65 per common unit on an annualized basis. The cash distribution is expected to be paid on November 14, 2017, to unitholders of record as of the close of business on November 7, 2017.

Critical Accounting Estimates

There were no changes to our critical accounting estimates from those disclosed in our Recast Form 8-K.

Recent Accounting Pronouncements

For information regarding new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements, refer to Note 2 - New Accounting Pronouncements in Part I, Item 1 of this Quarterly Report, which is incorporated herein by reference.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We manage exposure to commodity price risk in our business segments through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices. See Note 7 - Risk Management Activities to our condensed consolidated financial statements included in Part I, Item I of this Form 10-Q for additional information.

In our Liquid Pipelines and Services segment, we purchase and take title to a portion of the crude oil that we sell, which may expose us to changes in the price of crude oil in our sales markets. We manage this commodity price risk by limiting our net open positions and through the concurrent purchase and sale of like quantities of crude oil that are intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. In our Terminalling Services segment, we sell excess volumes of refined products and our gross margin could be impacted by changes in the market prices for these sales. We may execute forward sales contracts or financial swaps to reduce the risk of commodity price changes in this segment. In our NGL transportation business, we do not take title to the products we transport and therefore have no direct commodity price exposure.

Table of Contents

Sensitivity analysis

The table below summarizes our commodity-related financial derivative instruments and fair values, as well as the effect on fair value of an assumed hypothetical 10% change in the underlying price of the commodity (in thousand).



Derivative Instrument	Maturity	Notional Volume	Fair Value Asset (Liability)	Effect of Hypothetical +/-10% change

NGLs Fixed Price (gallons)	January 8, 2018	819,000	$17	$232
Crude Oil Fixed Price (barrels)	October 6, 2017 to December 7, 2017	125,000	$(403)	$762

Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of terms or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income (loss). The preceding hypothetical analysis is limited because changes in prices may or may not equal 10% and actual results may differ.

Interest Rate Risk

Our revolving credit facility bears interest at a variable rate and exposes us to interest rate risk. From time to time, we may use certain derivative instruments to hedge our exposure to variable interest rates. Based on our unhedged interest rate exposure to variable rate debt outstanding as of September 30, 2017, a 1% increase or decrease in interest rates would change annual interest expense by approximately $0.6 million.

We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

Credit risk

We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through analyzing the counterparties’ financial condition prior to entering into an agreement, establishing credit limits, monitoring the appropriateness of these limits on an ongoing basis and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to the management of our General Partner, including our General Partner’s principal executive and principal financial officers (whom we refer to as the “Certifying Officers”), as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision of the principal executive officer and principal financial officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on our evaluation, our principal executive officer and principal financial officer concluded that the Partnership’s disclosure controls and procedures were not effective as of September 30, 2017 as a result of a material weakness as described below.

Based on its evaluation of internal control over financial reporting as described above, management concluded that the Partnership did not maintain a sufficient complement of resources with an appropriate level of accounting knowledge, expertise and training commensurate with its financial reporting requirements. Specifically, individuals within the Partnership’s financial accounting and reporting functions did not have the appropriate level of expertise to ensure that complex, non-routine transactions of the Partnership were recorded appropriately. This control deficiency resulted in out-of-period adjustments recorded to the unaudited

Table of Contents

consolidated statement of operations in the fourth quarter of 2016 and a revision to the 2015 consolidated balance sheet and consolidated statement of cash flows.

Despite the material weakness, our principal executive officer and principal financial officer have concluded that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Material Weakness Remediation

Management is actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness identified. Specifically, we are taking numerous steps that we believe will address the underlying causes of the material weakness, primarily through the hiring of additional accounting personnel with technical accounting and financial reporting experience, the enhancement of our training and cross-training programs within our accounting department, and the enhancement of our internal review procedures during the financial statement preparation process.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications of our Certifying Officers pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report on Form 10-Q as Exhibits 31.1 and 31.2. The certifications of our Certifying Officers pursuant to 18 U.S.C. 1350 are furnished with this Quarterly Report on Form 10-Q as Exhibits 32.1 and 32.2.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

On December 18, 2015, Vintage Assets, Inc., et al. (“Vintage”), filed a lawsuit in the Judicial District Court in Plaquemines Parish, Louisiana alleging that defendants Southern Natural Gas Company, L.L.C. (“SNG”) and Tennessee Gas Pipeline Company, L.L.C. failed to maintain the canals in which their pipelines were laid and failed to maintain the associated banks causing erosion, ecological damage, and unspecified monetary damages, and trespassed on Plaintiffs’ property. The case was removed to the United States District Court for the Eastern District of Louisiana on January 27, 2016. Our subsidiaries High Point Gas Transmission, L.L.C. (“HPGG”) and High Point Gas Gathering, L.L.C. (“HPGT”) are successors in interest to SNG with regard to certain of the property interests at issue in this proceeding. On October 24, 2016, HPGT and HPGG were added to the lawsuit as co-defendants. Plaintiffs subsequently demanded either restoration of their property or, alternatively, $44.0 million in damages (the plaintiff’s alleged estimated cost of restoration). A bench trial was held in September 2017, but a judgment has not been rendered. The purchase and sale agreements pursuant to which HPGG and HPGT acquired its property interests contain provisions pursuant to which the sellers agreed to indemnify HPGT or HPGG, as applicable, from all liabilities, including attorney’s fees, attributable to the period prior to such acquisition.

While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending proceedings will not have a material adverse effect on our financial condition or results of operations.

Item 1A. Risk Factors

In addition to the information about our business, financial conditions and results of operations set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed under the caption “Risk Factors” in Part I, Item 1A of the Annual Report on Form 10-K and below in this Quarterly Report. Such risks are not the only risks we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also have a material adverse effect on our business or our operations.

We and our general partner will incur substantial transaction-related costs in connection with the SXE Merger, the SXE Contribution and related transactions (collectively, the “SXE Transactions”).

Table of Contents

We and the other parties to the SXE Transactions expect to incur substantial non-recurring transaction-related costs associated with completing the SXE Transactions, which are currently estimated to total approximately $[] million. Non-recurring transaction costs include, but are not limited to, fees paid to financial advisors, legal counsel, accountants and auditors and governmental filing fees. There can be no assurance that the elimination of certain costs due to the fact that SXE will no longer be publicly traded will offset the incremental transaction-related costs over time. Thus, any net cost savings may not be achieved in the near term, the long term or at all.

We are exposed to certain risks during the pendency of the SXE Transactions. The SXE Transactions are subject to conditions beyond our control and may not be completed, and failure to complete, or significant delays in completing, the SXE Transactions could negatively affect the trading price of our common units and our future business and financial results.

Completion of the SXE Transactions is not assured and is subject to risks, including the risks that approval of the SXE Merger by the SXE unitholders or of the SXE Transactions by governmental agencies is not obtained or that other closing conditions are not satisfied. The SXE Transaction Agreements each contain conditions that, if not satisfied or waived, would result in the applicable transaction not occurring, even though the SXE unitholders may have voted in favor of the SXE Merger proposal presented to them. Satisfaction of some of the conditions to the transactions, such as receipt of required regulatory approvals, is not in the control of the parties to the agreements. In addition, we and the other parties to the SXE Transaction Agreements can agree not to consummate the transactions even if all approvals have been obtained. The closing conditions to the SXE Transactions may not be satisfied, and we or the other parties to the SXE Transaction Agreements, as applicable, may choose not to, or may be unable to, waive an unsatisfied condition, which may cause the applicable transaction not to occur. If the SXE Transactions are not completed, or if there are significant delays in completing the SXE Transactions, the trading price of our common units and our future business and financial results could be negatively affected, and may not be able to realize some or all of the synergies expected to be achieved. If the SXE Transactions are terminated, we will not be able to recover costs incurred, and in certain circumstances, we will be required to pay a cash termination fee to SXE.

In connection with the SXE Transactions, we will be subject to several risks, including the following:


•	negative reactions from the financial markets if the anticipated benefits from the SXE Transactions are not realized or if the SXE Transactions are not completed, including declines in the price of our common units due to the fact that current prices may reflect a market assumption that the SXE Transactions will be completed;


•	potential issues with customers or suppliers that could negatively impact earnings and cash flow regardless of whether the SXE Transactions are consummated;


•	potential loss of key personnel during the pendency of the SXE Transactions;


•	the attention of our management will have been diverted to the SXE Transactions rather than our operations and pursuit of other opportunities that could have been beneficial to us, some of which alternate activities are restricted under the SXE Transaction Agreements; and


•	having to pay certain significant costs relating to the SXE Transactions, as discussed above.

A downgrade in our credit ratings following the SXE Merger could impact our access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

Following the SXE Transactions, rating agencies may reevaluate our ratings, and any additional actual or anticipated downgrades in such credit ratings could limit our ability to access credit and capital markets, including to finance the SXE Transactions, or to restructure or refinance our indebtedness. On November 1, 2017, Moody’s announced that our credit ratings were on negative watch. As a result of any such downgrades, future financings or refinancings, including to finance the SXE Transactions, may result in higher borrowing costs and require more restrictive terms and covenants, including obligations to post collateral with third parties, which may further restrict our operations and negatively impact liquidity.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

Because the number of common units exchanged per SXE Common Unit (as defined below) in the SXE Merger and the value per AMID Common Unit issued to Holdings LP in the SXE Contribution are fixed and will not be adjusted in the

Table of Contents

event of any change in our unit price or SXE’s unit price, the value of the common units issued by us may be higher or lower at the closing of the SXE Transactions than when the SXE Transaction Agreements were executed.

At the Effective Time of the SXE Merger, each SXE Common Unit issued and outstanding or deemed issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.160 (the “Exchange Ratio”) of an AMID Common Unit, except for those SXE Common Units held by affiliates of SXE and SXE GP, which will be canceled for no consideration.

The Exchange Ratio is fixed in the Merger Agreement, and the value of the AMID Common Units to be issued to LP Holdings is set at $13.69 per AMID Common Unit (the “Holdings Ratio”) in the Contribution Agreement. Neither the Exchange Ratio nor the Holdings Ratio will be adjusted for changes in the market price of either AMID Common Units or SXE Common Units. Changes in the market price of AMID Common Units prior to the Merger will affect the market value of the unit consideration that SXE unitholders will receive on the closing date of the SXE Merger. Unit price changes may result from a variety of factors (many of which are beyond our control), including the following factors:


•	market reaction to the announcement of the SXE Transactions;


•	changes in our or SXE’s respective businesses, operations, assets, liabilities and prospects;


•	changes in market assessments of the business, operations, financial position and prospects of either company or the combined company;


•	market assessments of the likelihood that the SXE Transactions will be completed;


•	interest rates, general market and economic conditions and other factors generally affecting the market prices of AMID Common Units and SXE Common Units;


•	federal, state and local legislation, governmental regulation and legal developments in the businesses in which AMID operates; and


•	other factors beyond our control, including those described or referred to elsewhere in this “Risk Factors” section.

The market price of AMID Common Units at the closing of the SXE Transactions may vary from its price on the date the Transaction Agreements were executed, on the date of any proxy statement/prospectus filed in connection with the SXE Merger and on the date of SXE’s special meeting. As a result, the market value of the consideration for the SXE Merger represented by the Exchange Ratio also will vary.

Therefore, while the number of AMID Common Units to be issued per share of SXE Common Units is fixed, (1) our unitholders cannot be sure of the market value of the consideration that will be paid to SXE unitholders upon completion of the SXE Merger and (2) SXE unitholders cannot be sure of the market value of the consideration they will receive upon completion of the SXE Merger. Neither we nor SXE has the right to terminate the Merger Agreement based on an increase or decrease in the market price of AMID Common Units or SXE Common Units.

A substantial number of AMID Common Units and other securities convertible into, or exercisable for, AMID Common Units, will be issued in connection with the SXE Transactions, which will dilute the ownership interests of existing unitholders, or may otherwise reduce the value of AMID Common Units.

Upon the terms and subject to the conditions set forth in the SXE Merger Agreement, at the Effective Time, each SXE Common Units issued and outstanding or deemed issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.160 of an AMID Common Unit. In addition, upon the terms and subject to the conditions set forth in the SXE Contribution Agreement, Holdings LP will receive AMID Common Units, AMID Preferred Units, which will be convertible into AMID Common Units, and the Options, which will be exercisable into AMID Common Units. The issuance of AMID Common Units in the SXE Transactions and the issuance of AMID Common Units upon conversion of the AMID Preferred Units or the exercise of the Options issued in the SXE Contribution will dilute the ownership interests of existing unitholders.

While Holdings LP has agreed not to sell any AMID Common Units, or any other securities convertible into, or exercisable for, AMID Common Units, for a specified period set forth in the SXE Contribution Agreement, any sales, or expectation of sales, in the public market of AMID Common Units, including those issuable upon the conversion of the AMID Preferred Units or the exercise of the Options, after the expiration of such period could adversely affect prevailing market prices of AMID Common Units.

If the SXE Transactions are completed, we may not achieve the intended benefits and the SXE Transactions may disrupt our current plans or operations.

Table of Contents

There can be no assurance that we will be able to successfully integrate SXE’s assets or otherwise realize the expected benefits of the acquisition. We may not achieve the expected financial results or cost synergies and savings that we expect to achieve following the transaction. Many of the factors driving such results are beyond our control. In addition, our business may be negatively impacted following the SXE Transactions if we are unable to effectively manage our expanded operations and the risks associated therewith. Although SXE has agreed to indemnify us for certain risks to which we are exposed as a result of the acquisition of the SXE assets, including pending material litigation and arbitration, the recourse for such indemnification is limited to the equity consideration paid by us to SXE and subject to certain limitations. Resolution of any such liabilities could require material cash payments by us, which we may be required to finance with debt or equity issuances.

The integration will require significant time and focus from management following the completion of the SXE Transactions. Consummating the SXE Transactions could disrupt current plans and operations, which could delay the achievement of our strategic objectives. Failure to achieve results and benefits that we or the market expects us to achieve or the impact of liabilities and risks associated with the SXE assets could have a material adverse impact on the trading price of our common units and our ability to obtain future financing.

Item 6. Exhibits



Exhibit Number	Exhibit
3.1	Certificate of Limited Partnership of American Midstream Partners, LP (filed as Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.2	Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated April 25, 2016 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 29, 2016).
3.3	First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated June 21, 2016 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on June 22, 2016).
3.4	Amendment No. 2 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated October 31, 2016 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on November 4, 2016).
3.5	Amendment No. 3 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated March 8, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on March 8, 2017).
3.6	Amendment No. 4 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated May 25, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on May 31, 2017).
3.7	Composite Agreement of Limited Partnership of American Midstream Partners, LP (filed as Exhibit 3.19 to the Annual Report on Form 10-K (Commission File No. 001-35257) filed on March 28, 2017).
3.8	Amendment No. 5 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated June 30, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on July 14, 2017).
3.9	Amendment No. 6 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated September 7, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 11, 2017).
3.10	Amendment No 7 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated October 26, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on October 30, 2017).
3.11	Certificate of Formation of American Midstream GP, LLC (filed as Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.12	Fourth Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2017).
4.1	Second Supplemental Indenture, dated as of September 18, 2017, by and among American Midstream Partners, LP, American Midstream Finance Corporation, the Guarantors party thereto and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 19, 2017).
10.1	Amendment No. 1 to the Securities Purchase Agreement, dated as of October 31, 2016, by and between American Midstream Partners, LP and Magnolia Infrastructure Holdings, LLC, dated July 14, 2017 and effective as of June 30, 2017 (filed as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on July 14, 2017).

Table of Contents



10.2*	Membership Interest Purchase Agreement, dated July 21, 2017, by and between AMID Merger LP and SHV Energy N.V.
10.3	Amendment No. 2 to the Securities Purchase Agreement, dated as of October 31, 2016, by and between AMID and Magnolia Infrastructure Holdings, LLC, dated September 7, 2017 and effective as of August 31, 2017 (filed as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 11, 2017).
10.4*	Distribution, Sale and Contribution Agreement, dated September 29, 2017, by and among D-Day Offshore Holdings, LLC, Toga Offshore, LLC, Pinto Offshore Holdings, LLC and American Midstream Delta House, LLC.
31.1*	Certification of Lynn L. Bourdon III, President and Chief Executive Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Eric T. Kalamaras, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Lynn L. Bourdon III, President and Chief Executive Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Eric T. Kalamaras, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.
**	Furnished herewith.

Table of Contents

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 undersigned thereunto duly authorized.

Date: November 9, 2017




AMERICAN MIDSTREAM PARTNERS, LP

By:	American Midstream GP, LLC, its General Partner

By:	/s/ Lynn L. Bourdon III
	Lynn L. Bourdon III
	Chairman, President and Chief Executive Officer
	(Principal Executive Officer)

By:	/s/ Eric T. Kalamaras
	Eric T. Kalamaras
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer)

Table of Contents

Exhibit Index



Exhibit Number	Exhibit
3.1	Certificate of Limited Partnership of American Midstream Partners, LP (filed as Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.2	Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated April 25, 2016 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on April 29, 2016).
3.3	First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated June 21, 2016 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on June 22, 2016).
3.4	Amendment No. 2 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated October 31, 2016 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on November 4, 2016).
3.5	Amendment No. 3 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated March 8, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on March 8, 2017).
3.6	Amendment No. 4 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated May 25, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on May 31, 2017).
3.7	Composite Agreement of Limited Partnership of American Midstream Partners, LP (filed as Exhibit 3.19 to the Annual Report on Form 10-K (Commission File No. 001-35257) filed on March 28, 2017).
3.8	Amendment No. 5 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated June 30, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on July 14, 2017).
3.9	Amendment No. 6 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated September 7, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 11, 2017).
3.10	Amendment No 7 to Fifth Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP, dated October 26, 2017 (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on October 30, 2017).
3.11	Certificate of Formation of American Midstream GP, LLC (filed as Exhibit 3.4 to the Registration Statement on Form S-1 (Commission File No. 333-173191) filed on March 31, 2011).
3.12	Fourth Amended and Restated Limited Liability Company Agreement of American Midstream GP, LLC (filed as Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on August 15, 2017).
4.1	Second Supplemental Indenture, dated as of September 18, 2017, by and among American Midstream Partners, LP, American Midstream Finance Corporation, the Guarantors party thereto and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 19, 2017).
10.1	Amendment No. 1 to the Securities Purchase Agreement, dated as of October 31, 2016, by and between American Midstream Partners, LP and Magnolia Infrastructure Holdings, LLC, dated July 14, 2017 and effective as of June 30, 2017 (filed as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on July 14, 2017).
10.2*	Membership Interest Purchase Agreement, dated July 21, 2017, by and between AMID Merger LP and SHV Energy N.V.
10.3	Amendment No. 2 to the Securities Purchase Agreement, dated as of October 31, 2016, by and between AMID and Magnolia Infrastructure Holdings, LLC, dated September 7, 2017 and effective as of August 31, 2017 (filed as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-35257) filed on September 11, 2017).
10.4*	Distribution, Sale and Contribution Agreement, dated September 29, 2017, by and among D-Day Offshore Holdings, LLC, Toga Offshore, LLC, Pinto Offshore Holdings, LLC and American Midstream Delta House, LLC.
31.1*	Certification of Lynn L. Bourdon III, President and Chief Executive Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Table of Contents



31.2*	Certification of Eric T. Kalamaras, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Lynn L. Bourdon III, President and Chief Executive Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Eric T. Kalamaras, Senior Vice President & Chief Financial Officer of American Midstream GP, LLC, the General Partner of American Midstream Partners, LP, for the September 30, 2017 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.
**	Furnished herewith.

Attached files

Stock widget

Investing forum

American Midstream Partners, LP Reports