UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended ~~June~~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: 001-36168

ARC LOGISTICS PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware		36-4767846
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

725 Fifth Avenue, 19^th Floor New York, New York		10022
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (212) 993-1290

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.

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).

Yes ☑ No ☐

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

Large accelerated filer	☐	Accelerated filer	☑

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 7(a)(2)(B) of the Securities Act. ☐

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

As of ~~August~~November 2, 2017, there were 19,~~545~~552,~~944~~611 common units.

ARC LOGISTICS PARTNERS LP

TABLE OF CONTENTS

			Page
GLOSSARY OF TERMS			3
PART I.	FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016	4
		Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	4
		Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2017 and 2016	5
		Condensed Consolidated Statements of Operations and Comprehensive Income for the Three and Nine Months Ended September 30, 2017 and 2016	5
		Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2017 and 2016	6
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	6
		Condensed Consolidated Statements of Partners’ Capital for the Six Months Ended June 30, 2017	7
		Condensed Consolidated Statements of Partners’ Capital for the Nine Months Ended September 30, 2017	7
		Notes to Condensed Consolidated Financial Statements	8
	Cautionary Statement Regarding Forward-Looking Statements		2831
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2932
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4450
	Item 4.	Controls and Procedures	4550
PART II.	OTHER INFORMATION
	Item 1.	Legal Proceedings	4550
	Item 1A.	Risk Factors	4652
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4652
	Item 6.	Exhibits	4652
SIGNATURES			47
EXHIBIT INDEX			53
EXHIBIT INDEX			48
SIGNATURES			55

GLOSSARY OF TERMS

Adjusted EBITDA: Represents net income before interest expense, income taxes and depreciation and amortization expense, as further adjusted for other non-cash charges and other charges that are not reflective of our ongoing operations. Adjusted EBITDA is not a presentation made in accordance with GAAP. Please see the reconciliation of Adjusted EBITDA to net income in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Results of Operations—Adjusted EBITDA.”

ancillary services fees: Fees associated with ancillary services, such as heating, blending and mixing our customers’ products that are stored in our tanks.

asphalts and industrial products: Category of petroleum products and liquids that includes various grades of asphalts, methanol, crude tall oil, black liquor soap and other related products.

barrel or bbl: One barrel of petroleum products equals 42 U.S. gallons.

bcf/d: One billion cubic feet per day (generally used as a measure of natural gas quantities).

bpd: Barrels per day.

crude tall oil: A by-product of paper pulp processing and derived from coniferous wood used for a component of adhesives, rubbers and inks, and as an emulsifier.

distillate: A liquid petroleum product used as an energy source which includes distillate fuel oil (No.1, No.2, No. 3 and No. 4).

Distributable Cash Flow: Represents Adjusted EBITDA less (i) cash interest expense paid; (ii) cash income taxes paid; (iii) maintenance capital expenditures paid; and (iv) equity earnings from the LNG Interest; plus (v) cash distributions from the LNG Interest. Distributable Cash Flow is not a presentation made in accordance with GAAP. Please see the reconciliation of Distributable Cash Flow to net income in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Results of Operations—Distributable Cash Flow.”

expansion capital expenditures: Capital expenditures that we expect will increase our operating capacity or operating income over the long term. Examples of expansion capital expenditures include the acquisition of equipment or the construction, development or acquisition of additional storage, terminalling or pipeline capacity to the extent such capital expenditures are expected to increase our long-term operating capacity or operating income.

GAAP: Generally accepted accounting principles in the United States.

LNG: Liquefied natural gas.

maintenance capital expenditures: Capital expenditures made to maintain our long-term operating capacity or operating income. Examples of maintenance capital expenditures include expenditures to repair, refurbish and replace storage, terminalling and pipeline infrastructure, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations to the extent such expenditures are made to maintain our long-term operating capacity or operating income.

mbpd: One thousand barrels per day.

M³: Cubic meters (generally used as a measure of liquefied natural gas quantities).

methanol: A light, volatile, colorless liquid used as, among other things, a solvent, a feedstock for derivative chemicals, fuel and antifreeze.

SEC: U.S. Securities and Exchange Commission.

storage and throughput services fees: Fees paid by our customers to reserve tank storage, throughput and transloading capacity at our facilities and to compensate us for the receipt, storage, throughput and transloading of crude oil, petroleum products and other liquids.

transloading: The transfer of goods or products from one mode of transportation to another (e.g., from railcar to truck).

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)

	June 30,		December 31,
	September 30,		December 31,
	2017		2016
Assets:
Current assets:
Cash and cash equivalents	$	12,~~463~~677	$	4,584
Trade accounts receivable		911,~~416~~501		8,257
Due from related parties		~~473~~480		1,321
Inventories		~~370~~368		397
Other current assets		2,~~406~~444		2,060
Total current assets		1417,~~128~~470		16,619
Property, plant and equipment, net		~~395~~396,~~172~~198		395,511
Investment in unconsolidated affiliate		77,~~036~~800		75,716
Intangible assets, net		~~110~~107,~~610~~140		117,716
Goodwill		39,871		39,871
Other assets		21,~~347~~935		2,980
Total assets	$	~~639~~640,~~164~~414	$	648,413
Liabilities and partners’ capital:
Current liabilities:
Accounts payable	$	36,~~473~~298	$	2,455
Accrued expenses		65,~~225~~689		5,684
Due to general partner		~~904~~2,762		2,082
Other liabilities		23,~~911~~523		2,961
Total current liabilities		1318,~~513~~272		13,182
Credit facility		~~252~~256,000		249,000
Other non-current liabilities		19,~~320~~272		19,805
Total liabilities		~~284~~293,~~833~~544		281,987
Commitments and contingencies
Partners’ capital:
General partner interest		-		-
Limited partners’ interest
Common units – (19,519,276 and 19,477,021 units issued and outstanding at June 30, 2017 and December 31, 2016, respectively)		271,578		282,228
Common units – (19,545,944 and 19,477,021 units issued and outstanding at September 30, 2017 and December 31, 2016, respectively)		263,421		282,228
Non-controlling interests		79,~~415~~636		81,541
Accumulated other comprehensive (loss) income		3,338		2,657
Accumulated other comprehensive income		3,813		2,657
Total partners’ capital		~~354~~346,~~331~~870		366,426
Total liabilities and partners’ capital	$	~~639~~640,~~164~~414	$	648,413

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

ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(In thousands, except per unit amounts)

(Unaudited)

	Three Months Ended						~~Six~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2017			2016			2017			2016
Revenues:
Third-party customers	$	25,~~113~~859		$	22,~~619~~933		$	4975,~~561~~420		$	4568,~~202~~136
Related parties		1,~~474~~431			3,~~625~~739			24,~~951~~382			710,~~108~~847
		26,587			26,244			52,512			52,310
		27,290			26,672			79,802			78,983
Expenses:
Operating expenses		8,~~873~~848			8,~~228~~192			1726,~~746~~595			1625,~~914~~107
Selling, general and administrative		24,~~712~~999			3,~~103~~141			510,~~951~~950			710,~~026~~168
Selling, general and administrative – affiliate		1,~~311~~368			1,~~302~~342			23,~~573~~941			23,~~624~~965
Depreciation		4,~~486~~623			3,~~720~~972			813,~~942~~565			711,~~372~~345
Amortization		3,~~589~~547			3,672			710,~~261~~808			711,~~370~~042
(Gain) Loss on revaluation of contingent consideration, net		~~613~~534			~~(659~~545	)		~~931~~1,465			(~~848~~303	)
Total expenses		2123,~~584~~919			1920,~~366~~864			4367,~~404~~324			4061,~~458~~324
Operating income (loss)		53,~~003~~371			65,~~878~~808			912,~~108~~478			1117,~~852~~659
Other income (expense):
Equity earnings from unconsolidated affiliate		2,~~441~~431			2,~~466~~512			47,~~812~~243			47,~~927~~439
Interest expense		(2,870	)		(2,386	)		(5,524	)		(4,753	)
Gain (Loss) on disposal of property and equipment		(1,484	)		-			(1,484	)		-
Total other income (loss), net		(429	)		80			(712	)		174
Other income		60			1			60			2
Income before income taxes		4,574			6,958			8,396			12,026
Interest expense		(3,132	)		(2,481	)		(8,656	)		(7,234	)
Income taxes		-			24			31			51
Total other income (expense)		(2,125	)		32			(2,837	)		207
Net income		4,574			6,934			8,365			11,975
Income before income taxes		1,246			5,840			9,641			17,866
Net income attributable to non-controlling interests		(1,346	)		(2,084	)		(2,674	)		(3,894	)
Income taxes		55			49			86			101
Net income attributable to partners' capital		3,228			4,850			5,691			8,081
Net income		1,191			5,791			9,555			17,765
Other comprehensive (loss) income		233			(19	)		681			(915	)
Net income attributable to non-controlling interests		(1,047	)		(1,659	)		(3,720	)		(5,553	)
Comprehensive income (loss) attributable to partners’ capital	$	3,461		$	4,831		$	6,372		$	7,166
Net income attributable to partners' capital		144			4,132			5,835			12,212
Other comprehensive (loss) income		475			831			1,156			(84	)
Comprehensive income (loss) attributable to partners’ capital	$	619		$	4,963		$	6,991		$	12,128
Earnings (loss) per limited partner unit:
Common units (basic and diluted)	$	0.1500		$	0.2420		$	0.27		$	0.3959
Subordinated units (basic and diluted)	$	-		$	0.2420		$	-		$	0.3959

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

ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2017			2016
Cash flow from operating activities:
Net income	$	89,~~365~~555		$	1117,~~975~~765
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation		813,~~942~~565			711,~~372~~345
Amortization		710,~~261~~808			711,~~370~~042
Equity earnings from unconsolidated affiliate, net of distributions		(~~786~~1,153	)		(~~168~~120	)
Amortization of deferred financing costs		~~822~~1,258			~~739~~1,145
Unit-based compensation		1,~~347~~847			23,~~296~~523
Net loss (gain) on revaluation of contingent consideration		~~931~~1,465			(~~848~~303	)
Net loss (gain) on disposal of property and equipment		1,484			-
Changes in operating assets and liabilities:
Trade accounts receivable		(13,~~160~~125	)		~~(398~~583	)
Due from related parties		~~849~~841			~~127~~(34	)
Inventories		2729			8480
Other current assets		(~~346~~384	)		~~214~~(442	)
Accounts payable		~~614~~952			~~1,353~~(573	)
Accrued expenses		~~(458~~295	)		(~~1,900~~227	)
Due to general partner		~~(1,178~~680	)		~~356~~1,347
Other liabilities		~~(235~~428	)		(~~943~~1,829	)
Net cash provided by operating activities		24,995			27,629
Net cash provided by (used in) operating activities		38,545			43,302
Cash flows from investing activities:
Capital expenditures		(612,~~879~~966	)		(1120,~~642~~902	)
Investment in unconsolidated affiliate		(6	)		-
Net cash paid for acquisitions		-			(8,000	)
Net cash used in investing activities		(6,885	)		(19,642	)
Net cash provided by (used in) investing activities		(12,972	)		(28,902	)
Cash flows from financing activities:
Distributions		(1725,~~158~~758	)		(1625,~~948~~438	)
Deferred financing costs		(~~189~~213	)		(~~583~~584	)
Repayments to credit facility		(1115,000	)		-(3,313	)
Proceeds from credit facility		1422,000			1723,250
Payments of earn-out liability		(1,554	)		(683	)
Equity contribution from non-controlling interests		1,575			-
Distributions paid to non-controlling interests		(4,800	)		(5,400	)
Payments of earn-out liability		(2,153	)		(1,028	)
Distributions paid to non-controlling interests		(7,200	)		(8,000	)
Net settlement withholding taxes related to stock based compensation		(202	)		-
Distribution equivalent rights paid on unissued units		(~~328~~529	)		(~~504~~763	)
Net cash provided by (used in) financing activities		(2127,~~231~~480	)		(615,~~868~~876	)
Net increase (decrease) in cash and cash equivalents		(31,~~121~~907	)		(1,~~119~~476	)
Cash and cash equivalents, beginning of period		4,584			5,870
Cash and cash equivalents, end of period	$	12,~~463~~677		$	64,~~989~~394
Supplemental disclosure of cash flow information:
Cash paid for interest	$	47,~~725~~390		$	46,~~320~~601
Cash paid for income taxes		3186			51100
Non-cash investing and financing activities:
Decrease (increase) in earn-out liability in accounts payable and accrued expenses		(~~323~~288	)		-
Increase (decrease) in purchases of property plant and equipment in accounts payable and accrued expenses		12,~~723~~890			(1,~~819~~365	)

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

ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

	Partners' Capital
	Limited Partner Common Interest			Non-Controlling Interests			Accumulated Other Comprehensive Income		Total Partners' Capital
Partners’ capital at December 31, 2016	$	282,228		$	81,541		$	2,657	$	366,426
Net income		5,~~691~~835			23,~~674~~720			-		89,~~365~~555
Other comprehensive income (loss)		-			-			~~681~~1,156		~~681~~1,156
Unit-based compensation		1,~~347~~847			-			-		1,~~347~~847
Net settlement of withholding taxes related to unit-based compensation		(202	)		-			-		(202	)
Distribution equivalent rights paid on unissued units		(328	)		-			-		(328	)
Contributions		-			1,575			-		1,575
Distributions		(17,158	)		(4,800	)		-		(21,958	)
Distribution equivalent rights paid on unissued units		(529	)		-			-		(529	)
Partners’ capital at June 30, 2017	$	271,578		$	79,415		$	3,338	$	354,331
Distributions		(25,758	)		(7,200	)		-		(32,958	)
Partners’ capital at September 30, 2017	$	263,421		$	79,636		$	3,813	$	346,870

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

ARC LOGISTICS PARTNERS LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Presentation

Defined Terms

Unless the context clearly indicates otherwise, references in these unaudited condensed consolidated financial statements (“interim statements”) to “Arc Logistics” or the “Partnership” refer to Arc Logistics Partners LP and its subsidiaries. Unless the context clearly indicates otherwise, references to our “General Partner” refer to Arc Logistics GP LLC, the general partner of Arc Logistics. References to “Sponsor” or “Lightfoot” or “Lightfoot Entities” refer to Lightfoot Capital Partners, LP (“LCP LP”) and its general partner, Lightfoot Capital Partners GP LLC (“LCP GP”). References to “Center Oil” refer to GP&W, Inc., d.b.a. Center Oil, and affiliates, including Center Terminal Company-Cleveland, which contributed its limited partner interests in Arc Terminals LP, predecessor to Arc Logistics, to the Partnership upon the consummation of the Partnership’s initial public offering in November 2013 (“IPO”). References to “Gulf LNG Holdings” refer to Gulf LNG Holdings Group, LLC and its subsidiaries, which own a liquefied natural gas regasification and storage facility in Pascagoula, MS, which is referred to herein as the “LNG Facility.” The Partnership owns a 10.3% limited liability company interest in Gulf LNG Holdings, which is referred to herein as the “LNG Interest.”

Organization and Description of Business

The Partnership is a fee-based, growth-oriented Delaware limited partnership formed by Lightfoot in 2007 to own, operate, develop and acquire a diversified portfolio of complementary energy logistics assets. The Partnership is principally engaged in the terminalling, storage, throughput and transloading of crude oil, petroleum products and other liquids. The Partnership is focused on growing its business through the optimization, organic development and acquisition of terminalling, storage, rail, pipeline and other energy logistics assets that generate stable cash flows.

In November 2013, the Partnership completed its IPO by selling 6,786,869 common units (which includes 786,869 common units issued pursuant to the exercise of the underwriters’ over-allotment option) representing limited partner interests in the Partnership at a price to the public of $19.00 per common unit. In connection with the IPO, the Partnership amended and restated its $40.0 million revolving credit facility.

The Partnership’s energy logistics assets are strategically located in the East Coast, Gulf Coast, Midwest, Rocky Mountains and West Coast regions of the United States and supply a diverse group of third-party customers, including major oil companies, independent refiners, petroleum product and other liquid marketers, distributors and various industrial manufacturers. Depending upon the location, the Partnership’s facilities possess pipeline, rail, marine and truck loading and unloading capabilities allowing customers to receive and deliver product throughout North America. The Partnership’s asset platform allows customers to meet the specialized handling requirements that may be required by particular products. The Partnership’s combination of diverse geographic locations and logistics platforms gives it the flexibility to meet the evolving demands of existing customers and address those of prospective customers.

As of ~~June~~September 30, 2017, the Partnership’s assets consisted of:

•

21 terminals in twelve states located in the East Coast, Gulf Coast, Midwest, Rocky Mountains and West Coast regions of the United States with approximately 7.8 million barrels of crude oil, petroleum product and other liquids storage capacity;

•

four rail transloading facilities with approximately 126,000 bpd of throughput capacity; and

•

the LNG Interest in connection with the LNG Facility, which has 320,000 M³ of LNG storage, 1.5 bcf/d natural gas sendout capacity and interconnects to major natural gas pipeline networks.

The Partnership interests included the following as of ~~June~~September 30, 2017:

19,~~519~~545,~~276~~944 common units representing limited partner interests (of which 5,242,775 common units are held by Lightfoot);

•

a non-economic general partner interest (which is held by our General Partner, which is owned by Lightfoot); and

•

incentive distribution rights (which are held by our General Partner, which is owned by Lightfoot).

Merger Transaction

On August 29, 2017, the Partnership, the General Partner (together with the Partnership, the “MLP Entities”), the Lightfoot Entities, Zenith Energy U.S., L.P., a Delaware limited partnership (“Parent”), Zenith Energy U.S. GP, LLC, a Delaware limited liability company and the general partner of Parent (“Parent GP”), Zenith Energy U.S. Logistics Holdings, LLC, a Delaware limited liability company and a subsidiary of Parent (“Holdings”), and Zenith Energy U.S. Logistics, LLC, a Delaware limited liability company and a subsidiary of Holdings (“Merger Sub” and, together with Parent, Parent GP and Holdings, the “Parent Entities”),

entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a subsidiary of Parent, and LCP GP will transfer to Holdings 100% of the issued and outstanding membership interests in the General Partner, including all rights and obligations relating thereto and all economic and capital interest therein (the “GP Equity Transfer”).

The conflicts committee (the “GP Conflicts Committee”), of the General Partner’s Board of Directors (the “Board”), after consultation with its independent legal and financial advisors, unanimously (i) determined that it is fair and reasonable and in the best interests of the Partnership and the holders of common units representing limited partner interests in the Partnership other than the Lightfoot Entities and their controlling affiliates to enter into the Merger Agreement and consummate the Merger, (ii) approved the Merger Agreement and the Merger, such approval constituting Special Approval pursuant to Section 7.9(d) of the Partnership’s partnership agreement, (iii) recommended approval of the Merger Agreement and the Merger by the Board, (iv) recommended that the Board direct the Merger Agreement to be submitted to a vote of the Partnership’s limited partners at a special meeting and (v) recommended that the Partnership’s limited partners approve the Merger Agreement and the Merger. The Board, acting based in part upon the recommendation of the GP Conflicts Committee, unanimously (i) determined that it is fair and reasonable and in the best interests of the Partnership and its common unitholders to enter into the Merger Agreement and consummate the Merger, (ii) approved the Merger Agreement and the Merger, (iii) directed the Merger Agreement to be submitted to a vote of the Partnership’s limited partners at a special meeting and (iv) determined to recommend that the Partnership’s limited partners approve the Merger Agreement and the Merger.

Upon the Merger and GP Equity Transfer becoming effective (the “Effective Time”), (a) each common unit representing a limited partner interest in the Partnership issued and outstanding immediately prior to the Effective Time (other than those common units owned by the Lightfoot Entities (the “Sponsor Units”)) will be converted into the right to receive an amount in cash equal to $16.50 per common unit, no longer be outstanding, automatically be cancelled and cease to exist, (b) each Sponsor Unit issued and outstanding immediately prior to the Effective Time will be converted into the right to receive an amount in cash equal to $14.50 per common unit, no longer be outstanding, automatically be cancelled and cease to exist, in each case, upon the terms and subject to the conditions set forth in the Merger Agreement and (c) Holdings will (or Parent will on Holdings’ behalf) pay to LCP GP $94,500,000 in cash in exchange for 100% of the membership interests in its General Partner acquired by Holdings in connection with the GP Equity Transfer.

Unless otherwise mutually agreed by the parties, including with the approval of the GP Conflicts Committee, the Merger will not be consummated earlier than November 30, 2017. The consummation of the Merger and the GP Equity Transfer is subject to the satisfaction or waiver of a number of conditions, including, among others: (i) receipt of the approval by the holders of a majority of the Partnership’s outstanding common units at a special meeting of its common unitholders of the Merger Agreement and the Merger (the “MLP Unitholder Approval”), (ii) expiration or termination of the waiting period applicable to the Transactions (as defined below) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (which termination was granted on September 22, 2017), (iii) the absence of certain legal impediments to the consummation of the Merger, (iv) the accuracy or waiver of the parties’ representations and warranties, (v) the performance of the parties’ obligations under the Merger Agreement, (vi) nothing has occurred (excluding, among other things, (a) developments generally affecting the prices of commodities, or (b) any changes in or effect upon the business or condition (financial or otherwise) of the MLP Entities and its subsidiaries or any adverse consequences upon or affecting Gulf LNG Holdings or its direct or indirect equityholders as a result of the outcome of that certain arbitration proceeding between Eni USA Gas Marketing L.L.C. and certain operating subsidiaries of Gulf LNG Holdings, as more fully described in Note 4 below) resulting in or reasonably expected to result in a material adverse effect on the business or financial results or condition of the MLP Entities, (vii) nothing has occurred that has a material adverse effect on the ability of the MLP Entities or the Lightfoot Entities to consummate the Transactions, (viii) the Partnership’s receipt of a legal opinion regarding certain tax matters, (ix) Holdings’ receipt of the written resignations of each member of the Board and each officer of the General Partner, dated to be effected as of the Effective Time, and (x) Parent GP’s receipt of the transition services agreement related thereto.

Additionally, the consummation of the Merger and the GP Equity Transfer is subject to the consummation or contemporaneous consummation of (a) the purchase by Holdings and the Lightfoot Entities of certain of the interests in Arc Terminals Joliet Holdings LLC, a Delaware limited liability company (“Joliet Holdings”), held by EFS Midstream Holdings LLC, a Delaware limited liability company (“GE EFS”) (such purchase, the “Joliet Purchase”), pursuant to the Purchase Agreement dated August 29, 2017, by and among Holdings, the Lightfoot Entities and GE EFS, and (b) the purchase by Holdings of a 5.51646% interest and, subject to certain conditions, an additional 4.16154% interest, in Gulf LNG Holdings from LCP LNG Holdings, LLC, a Delaware limited liability company and subsidiary of LCP LP (“LCP LNG”) (such purchase, the “Gulf LNG Purchase” and together with the Joliet Purchase, the Merger, the GP Equity Transfer and the other transactions contemplated by the Merger Agreement, the “Transactions”) pursuant to the Partially Conditional Purchase Agreement, dated August 29, 2017, by and among LCP LNG, the Lightfoot Entities, Parent, Parent GP, Holdings and, solely for the purposes of Section 1.1(d) of such agreement, the Partnership.

The Merger Agreement contains certain termination rights including, among others, (i) by mutual agreement of Parent GP and our General Partner, (ii) by either the General Partner or Parent GP, in the event that (a) a court issues a final, non-appealable order or injunction prohibiting the Merger, (b) after final adjournment of the special meeting of the Partnership’s limited partners, MLP Unitholder Approval has not been obtained, or (c) the Merger has not been consummated on or before February 7, 2018, subject to extension at Parent GP’s election to March 1, 2018, in certain circumstances as specified in the Merger Agreement (the “Outside

Date”), (iii) by the General Partner, in the event (a) the GP Conflicts Committee withdraws its recommendation that the Partnership’s limited partners approve the Merger and Merger Agreement due to a superior proposal, the Board authorizes the MLP Entities to enter into an agreement with respect to such superior proposal and, concurrently with the termination of the Merger Agreement, the MLP Entities enter into such agreement, (b) any Parent Entity has breached any of its representations or warranties or has failed to perform any of its covenants or agreements which such breach or failure would prevent the satisfaction of a condition to the consummation of the Merger or is incapable of being cured within a specified time or (c) the Parent Entities fail to close within a specified time after receiving notice from the MLP Entities that all conditions to closing have been satisfied or waived and the MLP Entities stand ready, willing and able to close and (iv) by Parent GP, in the event that (a) any MLP Entity or any Lightfoot Entity has breached the non-solicit obligations under the Merger Agreement, (b) any MLP Entity or any Lightfoot Entity has breached any of its representations or warranties or has failed to perform any of its covenants or agreements which such breach or failure would prevent the satisfaction of a condition to the consummation of the Merger or is incapable of being cured within a specified time or (c) prior to final adjournment of the special meeting the Partnership’s limited partners, the Board withdraws its recommendation that the Partnership’s limited partners approve the Merger and Merger Agreement. Upon termination of the Merger Agreement under specific circumstances, the Partnership will be required to pay Parent a termination fee of $11,487,696 (the “MLP Termination Fee”). If the Merger Agreement is terminated (A) (i) due to the passing of the Outside Date, (ii) failure to obtain MLP Unitholder Approval or (iii) due to any Lightfoot Entity or MLP Entity’s failure to perform any covenant or agreement or the failure of any of the representations and warranties of any Lightfoot Entity or MLP Entity to be true and correct as of the date of the Merger Agreement and (B) any MLP Entity or Lightfoot Entity or affiliate thereof enters into an alternative acquisition within 12 months of such termination, the MLP Termination Fee is payable. The MLP Termination Fee is also payable in the event, among other things, that Parent terminates the Merger Agreement due to any MLP Entity or Lightfoot Entity’s breach of the non-solicit provisions in the Merger Agreement, excluding breaches that do not adversely affect the Parent Entities or the Transactions in any material respect, or if the Board withdraws its recommendation that the Partnership’s limited partners approve the Merger and the Merger Agreement due to a superior proposal, the Board authorizes the MLP Entities to enter into an agreement with respect to such superior proposal and, concurrently with the termination of the Merger Agreement, the MLP Entities enter into such agreement. The Merger Agreement also provides that Parent will be required to pay the Partnership a termination fee of $24,616,491 if the Merger Agreement is terminated under certain circumstances.

From the date of the Merger Agreement until the Effective Time, the Partnership plans to declare and pay quarterly distributions in the ordinary course of business and consistent with past practices. Assuming that the Merger has not closed by January 26, 2018, the Partnership expects that it would declare a distribution associated with the quarter ended December 31, 2017 on or about January 26, 2018, to be paid on or about February 15, 2018 to the Partnership’s common unitholders of record as of February 8, 2018. If, as anticipated, the Merger closes prior to the record date for the distribution associated with the fourth quarter of 2017, then the holders of the Partnership’s common units as of immediately prior to the closing of the Merger will not receive any distribution associated with the fourth quarter of 2017. If, alternatively, the Merger does not close by the record date for the distribution associated with the fourth quarter of 2017, then the Partnership plans to pay the fourth quarter distribution, on or around February 15, 2018, to the Partnership’s common unitholders of record as of the record date applicable to such distribution, irrespective of whether the Merger closes thereafter or whether the General Partner or Parent GP terminates the Merger Agreement after the Outside Date.

The Merger is targeted to close on or about December 21, 2017 and is subject to the right that each of the General Partner and Parent GP has to terminate the Merger Agreement if the Merger has not been consummated on or before the Outside Date. Additional information regarding the proposed transaction and the terms and conditions of the Merger Agreement are set forth in the Partnership’s definitive proxy statement for the special meeting of the Partnership’s common unitholders to consider and vote on the Merger Agreement and the Merger, filed on October 30, 2017.

Note 2—Summary of Significant Accounting Policies

The Partnership has provided a discussion of significant accounting policies in its Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Partnership 10-K”). Certain items from that discussion are repeated or updated below as necessary to assist in the understanding of these interim statements.

Basis of Presentation

The accompanying interim statements of the Partnership have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments, consisting only of normal recurring adjustments and disclosures necessary for a fair statement of these interim statements have been included. The results reported in these interim statements are not necessarily indicative of the results that may be reported for the entire year or for any other period. These interim statements should be read in conjunction with the Partnership’s consolidated financial statements for the year ended December 31, 2016, which are included in the 2016 Partnership 10-K, as filed with the SEC. The year-end balance sheet data was derived from the audited financial statements, but does not include all disclosures required by GAAP.

Revision of Financial Statements

During the fourth quarter of 2016, the Partnership identified errors in the determination of the fair value of the earn-out liability related to the Joliet terminal acquisition for the first, second and third quarters of 2016. Such liabilities should have been revalued at each reporting period to estimated fair value with the offset to current earnings. The Partnership evaluated the materiality of the errors from qualitative and quantitative perspectives and concluded that the errors were not material, either individually or in the aggregate, to the Partnership’s previously issued interim financial statements. The Partnership has, however, revised its interim statements for the affected periods.

The following table details the impact of these revisions for the three and ~~six~~nine months ended ~~June~~September 30, 2016, on the Condensed Consolidated Statement of Operations:

	Quarter to date June 30, 2016
	Quarter to date September 30, 2016
	As previously
	reported		Adjustments (a)			As revised
Gain (loss) on revaluation of contingent consideration	$	-	$	~~659~~(545	)	$	~~659~~(545	)
Operating income		6,~~219~~353		~~659~~(545	)		65,~~878~~808
Net income		6,~~275~~336		~~659~~(545	)		65,~~934~~791
Net income attributable to partners' capital		4,~~455~~458		~~395~~(326	)		4,~~850~~132
Basic and diluted earnings per unit - common	$	0.22	$	(0.02	)	$	0.2420
Basic and diluted earnings per unit - subordinated	$	0.22	$	(0.02	)	$	0.2420

	Year to date June 30, 2016
	Year to date September 30, 2016
	As previously
	reported		Adjustments (a)		As revised
Gain (loss) on revaluation of contingent consideration	$	-	$	~~848~~303	$	~~848~~303
Operating income		1117,~~004~~356		~~848~~303		1117,~~852~~659
Net income (a)		11,127		848		11,975
Net income		17,462		303		17,765
Net income attributable to partners' capital		712,~~572~~029		~~509~~183		812,~~081~~212
Basic and diluted earnings per unit - common	$	0.3758	$	0.0201	$	0.3959
Basic and diluted earnings per unit - subordinated	$	0.3658	$	0.0301	$	0.3959

(a) The corresponding amounts have been revised within the statement of cash flows for the ~~six~~nine months ended ~~June~~September 30, 2016, with no net impact to operating cash flow.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The most significant estimates relate to the valuation of acquired businesses, valuation of contingent consideration, goodwill and intangible assets, assessment for impairment of long-lived assets and the useful lives of intangible assets and property, plant and equipment. Actual results could differ from those estimates.

Impairment of Long-Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. Assets to be disposed of are separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and are no longer depreciated.

No impairment charges were recorded during the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016.

Goodwill

Goodwill represents the excess of consideration paid over the fair value of net assets acquired in a business combination. Goodwill is not amortized but instead is assessed for impairment at least annually or when facts and circumstances warrant. Goodwill impairment is determined using a two-step process. The first step of the goodwill impairment test is used to identify potential impairment by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test is performed. The second step compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. The Partnership determines the fair value of its single reporting unit by blending two valuation approaches: the income approach and a market value approach. The inputs included assumptions related to the future performance of the Partnership and assumptions related to discount rates, long-term growth rates and control premiums. Based on the results of the first step of the quantitative impairment assessment of its goodwill as of December 31, 2016, the fair value of the Partnership’s reporting unit exceeded its carrying value by approximately 11% and management concluded that no impairment was necessary. In the event that market conditions were to remain weak for an extended period of time, the Partnership may be required to record an impairment of goodwill in the future, and such impairment could be material.

A summary of the changes in the carrying amount of goodwill is as follows (in thousands):

	As of
	June 30,		December 31,
	September 30,		December 31,
	2017		2016
Beginning Balance	$	39,871	$	39,871
Goodwill acquired		-		-
Ending Balance	$	39,871	$	39,871

Deferred Rent

The Portland Lease Agreement (as defined in “Note 11—Related Party Transactions—Other Transactions with Related Persons—Operating Lease Agreement” below) contains certain rent escalation clauses, contingent rent provisions and lease termination payments. The Partnership recognizes rent expense for operating leases on a straight-line basis over the term of the lease, taking into consideration the items noted above. Contingent rental payments are generally recognized as rent expense as incurred. The deferred rent resulting from the recognition of rent expense on a straight-line basis related to the Portland Lease Agreement is included within “Other non-current liabilities” in the accompanying unaudited condensed consolidated balance sheets at ~~June~~September 30, 2017 and December 31, 2016.

Contingent Consideration

The Partnership records an estimate of the fair value of contingent consideration related to the earn-out obligations to CenterPoint Properties Trust (“CenterPoint”) as a part of the Joliet terminal acquisition, within “Other Liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets at ~~June~~September 30, 2017 and December 31, 2016. On a quarterly basis, the Partnership revalues the liability and records increases or decreases in the fair value of the recorded liability as an adjustment to earnings. Changes to the contingent consideration liability can result from adjustments to the discount rate or the estimated amount and timing of the future throughput activity at the Joliet terminal. The assumptions used to estimate fair value require significant judgment. The use of different assumptions and judgments could result in a materially different estimate of fair value. The key inputs in determining fair value of the Partnership’s contingent consideration obligations of $17.76 million and $18.0 million at ~~June~~September 30, 2017 and December 31, 2016, respectively, include discount rates ranging from 7.1% to 7.7% and changes in the assumed amount and timing of the future throughput activity which affects the amount and timing of payments on the earn-out obligation. For further information, see Note 2, “Summary of Significant Accounting Policies – Fair Value of Financial Instruments,” to the unaudited condensed consolidated financial statements included in this report for additional information about the Partnership’s contingent consideration obligations.

condensed consolidated financial statements included in this report for additional information about the Partnership’s contingent consideration obligations.

Contingencies

In the normal course of business, the Partnership may be subject to loss contingencies, such as legal proceedings and claims arising out of its business that cover a wide range of matters. An accrual for a loss contingency is recognized when it is probable that an asset had been impaired or a liability had been incurred and the amount of loss can be reasonably estimated. If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of the liability can be estimated, then the estimated liability would be accrued in the Partnership’s financial statements. If the assessment indicates that a potential material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, and an estimate of the range of possible losses, if determinable and material, would be disclosed. If the estimate of a probable loss is a range and no amount within the range is more likely, the Partnership will accrue the minimum amount of the range.

contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, and an estimate of the range of possible losses, if determinable and material, would be disclosed. If the estimate of a probable loss is a range and no amount within the range is more likely, the Partnership will accrue the minimum amount of the range.

There are many uncertainties associated with any legal proceeding and these actions or other third-party claims against the Partnership may cause the Partnership to incur costly litigation and/or substantial settlement charges. As a result, the Partnership’s business, financial condition, results of operations and cash flows could be adversely affected. The actual liability in any such matters may be materially different from the Partnership’s estimates, if any.

Revenue Recognition

Revenues from leased tank storage and delivery services are recognized as the services are performed, evidence of a contractual arrangement exists and collectability is reasonably assured. Revenues also include the sale of excess products and additives which are mixed with customer-owned liquid products. Revenues for the sale of excess products and additives are recognized when title and risk of loss pass to the customer.

Fair Value of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value measurements are derived using inputs and assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. GAAP establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This three-tier hierarchy classifies fair value amounts recognized or disclosed in the condensed consolidated financial statements based on the observability of inputs used to estimate such fair values. The classification within the hierarchy of a financial asset or liability is determined based on the lowest level input that is significant to the fair value measurement. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, the Partnership categorizes its financial assets and liabilities using this hierarchy.

The amounts reported in the balance sheet for cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair value because of the short-term maturities of these instruments (Level 1). Because the Credit Facility (as defined in “Note 7 – Debt – Credit Facility” below) has a market rate of interest, its carrying amount approximated fair value (Level 2).

In connection with the Partnership’s acquisition, through ~~Arc Terminals~~ Joliet Holdings ~~LLC (“Joliet Holdings)~~, a joint venture company formed with an affiliate of GE Energy Financial Services (“GE EFS”), of all of the memberships interests of Joliet Bulk, Barge & Rail LLC (“JBBR”) from CenterPoint for $216.0 million (the “JBBR Acquisition”), Joliet Holdings has an earn-out obligation to CenterPoint which was valued at the time of the JBBR Acquisition at $19.7 million. Joliet Holdings’ earn-out obligations to CenterPoint will terminate upon the payment, in the aggregate, of $27.0 million. The balance of the earn-out liability is included within “Other non-current liabilities” in the accompanying consolidated balance sheets at ~~June~~September 30, 2017 and December 31, 2016. Since the fair value of the contingent consideration obligation is based primarily upon unobservable inputs, it is classified as Level 3 in the fair value hierarchy. The contingent consideration obligation will be revalued at each reporting period and changes to the fair value will be recorded as a component of operating income. Increases or decreases in the fair value of the contingent consideration obligations can result from changes in the assumed throughput (contracted or uncontracted) and the long-term interest rates. Significant judgment is employed in determining the appropriateness of these assumptions as of the acquisition date and for each subsequent reporting period. Accordingly, future business and economic conditions can materially impact the amount of contingent consideration expense the Partnership records in any given period. The key inputs in determining fair value of the Partnership’s contingent consideration obligations of $17.76 million and $18.0 million at ~~June~~September 30, 2017 and December 31, 2016, respectively, include discount rates ranging from 7.1% to 7.7% and changes in the estimated amount and timing of the future throughput activity which affects the timing of payments on the earn-out obligation. The Partnership recorded a $0.65 million non-cash loss ~~and a $0.7 million non-cash gain~~ on the revaluation of the earn-out liability ~~during~~for each of the three months ended ~~June~~September 30, 2017 and 2016~~, respectively~~. The Partnership recorded a $01.95 million non-cash loss and a $0.83 million non-cash gain on the revaluation of the earn-out liability during the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, respectively. For the three and ~~six~~nine months ended ~~June~~September 30, 2017, Joliet Holdings reported earn-out payments of $0.6 million and $1.29 million, respectively, to Centerpoint related to the earn-out obligation. For the three and ~~six~~nine months ended ~~June~~September 30, 2016, Joliet Holdings reported earn-out payments of $0.3 million and $01.70 million, respectively, to Centerpoint related to the earn-out obligation. Since the closing of the JBBR Acquisition in May 2015 through September 30, 2017, Joliet Holdings has reported earn-out payments of $4.6 million related to the earn-out obligation. The following is a reconciliation of the beginning and ending amounts of the contingent consideration obligation related to the JBBR Acquisition (in thousands):

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through June 30, 2017, Joliet Holdings has reported earn-out payments of $4.0 million related to the earn-out obligation. The following is a reconciliation of the beginning and ending amounts of the contingent consideration obligation related to the JBBR Acquisition (in thousands):

	Balance at							Balance at
	December 31		Revaluation		Earn-out			September 30,
	2016		Adjustments		payments			2017
Liabilities at fair value:
JBBR contingent consideration	$	18,000	$	1,465	$	(1,865	)	$	17,600
Total liabilities at fair value	$	18,000	$	1,465	$	(1,865	)	$	17,600

	Balance at							Balance at
	December 31		Revaluation		Earn-out			June 30,
	2016		Adjustments		payments			2017
Liabilities at fair value:
JBBR contingent consideration	$	18,000	$	931	$	(1,231	)	$	17,700
Total liabilities at fair value	$	18,000	$	931	$	(1,231	)	$	17,700

The Partnership believes that its valuation methods are appropriate and consistent with the values that would be determined by other market participants. However, the use of different methodologies or assumptions to determine fair value of certain financial instruments could result in a different estimate of fair value at the reporting date.

Unit-Based Compensation

The Partnership recognizes all unit-based compensation to directors, officers, employees and other service providers in the consolidated financial statements based on the fair value of the awards. Fair value for unit-based awards classified as equity awards is determined on the grant date of the award, and this value is recognized as compensation expense ratably over the requisite service or performance period of the equity award. Fair value for equity awards is calculated at the closing price of the common units on the grant date. Fair value for unit-based awards classified as liability awards is calculated at the closing price of the common units on the grant date and is remeasured at each reporting period until the award is settled. Compensation expense related to unit-based awards is included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income.

For awards with performance conditions, the expense is accrued over the service period only if the performance condition is considered to be probable of occurring. When awards with performance conditions that were previously considered improbable become probable, the Partnership incurs additional expense in the period that the probability assessment changes (see “Note 9—Equity Plans”).

Net Income Per Unit

The Partnership uses the two-class method in the computation of earnings per unit since there is more than one participating class of securities. Earnings per common and subordinated unit are determined by dividing net income allocated to the common units and subordinated units, respectively, after deducting the amount allocated to the phantom units, if any, by the weighted average number of outstanding common and subordinated units, respectively, during the period. Following payment of the cash distribution for the third quarter of 2016, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, effective November 16, 2016, the 6,081,081 subordinated units, of which 5,146,264 were owned by Lightfoot, converted on a one-for-one basis into common units and thereafter participate on terms equal with all other common units in distributions of available cash. The overall computation, presentation and disclosure of the Partnership’s limited partners’ net income per unit are made in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 260 “Earnings per Share.”

Segment Reporting

The Partnership derives revenue from operating its terminal and transloading facilities. These facilities have been aggregated into one reportable segment because the facilities have similar long-term economic characteristics, products and types of customers.

Non-Controlling Interests

The Partnership applies the provisions of ASC 810 Consolidations, which were amended on January 1, 2009 by ASC 810-10-65 and ASC 810-10-45 (“ASC 810”). As required by ASC 810, the Partnership’s non-controlling ownership interests in consolidated subsidiaries are presented in the consolidated balance sheet within capital as a separate component from partners’ capital. In addition, consolidated net income includes earnings attributable to both the partners and the non-controlling interests. For the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, $47.82 million and $58.40 million, respectively, of distributions have been made to non-controlling interest holders of consolidated subsidiaries. For the nine months ended September 30, 2017 and 2016, $1.6 million and $0 million, respectively, of contributions have been made by non-controlling interest holders of consolidated subsidiaries.

Recently Issued Accounting Pronouncements

In May 2014, the FASB issued updated guidance on the reporting and disclosure of revenue recognition. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. In April 2015, the FASB proposed a one-year deferral of the effective date, and therefore, this guidance will be effective for the Partnership beginning in the first quarter of 2018, with early

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~~assets~~adoption ~~recognized~~optional ~~from~~but ~~costs~~not ~~incurred~~before tothe ~~obtain~~original oreffective ~~fulfill~~date aof ~~contract~~December 15, 2016. In ~~April~~May ~~2015~~and December 2016, the FASB ~~proposed~~issued acertain ~~one~~narrow-~~year~~scope ~~deferral~~improvements ofand practical expedients to the ~~effective~~guidance. The ~~date,~~Partnership ~~and~~plans ~~therefore,~~to adopt this guidance ~~will~~effective beJanuary ~~effective~~1, ~~for~~2018 using the ~~Partnership~~modified ~~beginning~~retrospective inmethod ~~the~~applied ~~first~~to ~~quarter~~contracts that are not completed as of ~~2018,~~that ~~with~~date. To ~~early~~date, ~~adoption~~the ~~optional~~Partnership ~~but~~has not ~~before~~identified ~~the~~changes ~~original~~to ~~effective~~its ~~date~~revenue ofrecognition ~~December~~policies ~~15,~~that ~~2016. In~~would ~~May~~result ~~and~~in ~~December~~a ~~2016,~~material ~~the~~adjustment ~~FASB~~to ~~issued~~the ~~certain~~opening ~~narrow-scope~~balance ~~improvements~~of ~~and~~partnership ~~practical~~capital ~~expedients~~on toJanuary ~~the~~1, ~~guidance. The~~2018; ~~Partnership~~however, it is ~~currently~~continuing ~~evaluating~~to evaluate the ~~potential~~effect, ~~impact~~if ofany, adopting this ~~authoritative~~ guidance will have on its financial ~~condition~~position, results of operations, cash flows and related disclosures. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue.

In February 2016, the FASB issued new guidance which amends various aspects of existing guidance for leases. The new guidance requires an entity to recognize assets and liabilities arising from a lease for both financing and operating leases, along with additional qualitative and quantitative disclosures. The main difference between previous GAAP and the amended standard is the recognition of lease assets and lease liabilities by lessees on the balance sheet for those leases classified as operating leases under previous GAAP. As a result, the Partnership will have to recognize a liability representing its lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the balance sheet. The new guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the effect this standard will have on its consolidated financial position or results of operations.

In August 2016, the FASB issued new guidance which makes eight targeted changes to how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update provides specific guidance on cash flow classification issues that are not currently addressed by GAAP and thereby reduces the current diversity in practice. The standard is effective for the Partnership’s financial statements issued for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted. The Partnership does not expect this requirement to have a significant impact on its financial condition, results of operations, cash flows and related disclosures.

In January 2017, the FASB issued new guidance which provides clarifications to evaluating when a set of transferred assets and activities (collectively, the "set") is a business and provides a screen to determine when a set is not a business. Under the new guidance, when substantially all of the fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset, or group of similar assets, the assets acquired would not represent a business. Also, to be considered a business, an acquisition would have to include an input and a substantive process that together significantly contribute to the ability to produce outputs. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and should be applied on a prospective basis to any transactions occurring within the period of adoption. Early adoption is permitted for interim or annual periods in which the financial statements have not been issued. The Partnership does not expect this requirement to have a significant impact on its financial condition, results of operations, cash flows and related disclosures.

In January 2017, the FASB issued new guidance which eliminates the requirement to determine the fair value of individual assets and liabilities of a reporting unit to measure goodwill impairment. Under the amendment, goodwill impairment testing will be performed by comparing the fair value of the reporting unit with its carrying amount and recognizing an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The new standard is effective for annual and interim goodwill impairment tests in fiscal years beginning after December 15, 2019, and should be applied on a prospective basis. Early adoption is permitted for annual or interim goodwill impairment testing performed after January 1, 2017. The Partnership does not expect this requirement to have a significant impact on its financial condition, results of operations, cash flows and related disclosures.

Note 3 – Acquisitions

Acquisitions

The following acquisition was accounted for under the acquisition method of accounting whereby management utilized the services of third-party valuation consultants, along with estimates and assumptions provided by management, to estimate the fair value of the net assets acquired. The third-party valuation consultant utilized several appraisal methodologies including income, market and cost approaches to estimate the fair value of the identifiable assets acquired.

Gulf Oil Terminals Acquisition

In January 2016, the Partnership, through a newly formed wholly owned subsidiary, acquired four petroleum products terminals (the “Pennsylvania Terminals”) located in Altoona, Mechanicsburg, Pittston and South Williamsport, Pennsylvania from Gulf Oil Limited Partnership (“Gulf Oil”) for $8.0 million (the “Gulf Oil Terminals Acquisition”). In connection with this acquisition, the Partnership also acquired an option to purchase from Gulf Oil at an agreed upon purchase price additional land with storage tanks located adjacent to one of the Pennsylvania Terminals. At closing, the Partnership entered into a take-or-pay terminal services agreement with Gulf Oil with an initial term of two years. The throughput and related services provided by the Partnership to Gulf Oil under the terminal services agreement are provided at the Pennsylvania Terminals, as well as several of the Partnership’s other petroleum products terminals. The acquisition was financed with a combination of available cash and borrowings under the Credit Facility.

The Gulf Oil Terminals Acquisition was accounted for as a business combination in accordance with ASC Topic 805, “Business Combinations” (“ASC 805”). The Gulf Oil Terminals Acquisition purchase price equaled the approximately $8.0 million fair value of the identifiable assets acquired and, accordingly, the Partnership did not recognize any goodwill as a part of the Gulf Oil Terminals Acquisition. Transaction costs incurred by the Partnership in connection with the acquisition, consisting primarily of legal and other professional fees, totaled approximately $0.6 million and were expensed as incurred in accordance with ASC 805.

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fair value of the identifiable assets acquired and, accordingly, the Partnership did not recognize any goodwill as a part of the Gulf Oil Terminals Acquisition. Transaction costs incurred by the Partnership in connection with the acquisition, consisting primarily of legal and other professional fees, totaled approximately $0.6 million and were expensed as incurred in accordance with ASC 805. Management has finalized the valuation of the net assets acquired in connection with the Gulf Oil Terminals Acquisition and the final purchase price allocation has been determined.

The total purchase price of $8.0 million was preliminarily allocated to the net assets acquired as follows (in thousands):

Consideration:
Cash paid to seller	$	8,000
Total consideration	$	8,000
Allocation of purchase price:
Inventories	$	163
Property and equipment		7,837
Net assets acquired	$	8,000

Note 4—Investment in Unconsolidated Affiliate

The Partnership accounts for investments in limited liability companies under the equity method of accounting unless the Partnership’s interest is deemed to be so minor that it may have virtually no influence over operating and financial policies. “Investment in unconsolidated affiliate” consisted of the LNG Interest, and its balances as of ~~June~~September 30, 2017 and December 31, 2016 are represented below (in thousands):

Balance at December 31, 2016	$	75,716
Equity earnings		47,~~812~~243
Contributions		6
Distributions		(46,~~026~~090	)
Amortization of premium		(~~153~~231	)
Other comprehensive income (loss)		~~681~~1,156
Balance at June 30, 2017	$	77,036
Balance at September 30, 2017	$	77,800

Investment in Gulf LNG Holdings

In November 2013, the Partnership purchased the LNG Interest from an affiliate of GE EFS for $72.7 million. The carrying value of the LNG Interest on the date of acquisition was $64.1 million and therefore the excess amount paid by the Partnership over the carrying value was $8.6 million. This excess can be attributed to the underlying long-lived assets of Gulf LNG Holdings and is therefore being amortized using the straight-line method over the remaining useful lives of the respective assets, which is 28 years. The estimated aggregate amortization of this premium for its remaining useful life from ~~June~~September 30, 2017 is as follows (in thousands):

	Total
2017	$	~~156~~78
2018		309
2019		309
2020		309
2021		309
Thereafter		6,136
	$	7,~~528~~450

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Summarized financial information for Gulf LNG Holdings is reported below (in thousands):

	June 30,		December 31,
	September 30,		December 31,
	2017		2016
Balance sheets
Current assets	$	67,~~190~~737	$	7,474
Noncurrent assets		~~838~~831,~~630~~662		855,703
Total assets	$	~~844~~839,~~820~~399	$	863,177
Current liabilities	$	7879,~~746~~893	$	83,825
Long-term liabilities		~~594~~579,~~233~~506		621,802
Member’s equity		~~171~~180,~~841~~000		157,550
Total liabilities and member’s equity	$	~~844~~839,~~820~~399	$	863,177

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2017

2016

2017

2016

Income statements

Revenues

46,548

46,484

93139,~~045~~593

92139,~~968~~452

Total operating costs and expenses

13,~~910~~965

14,~~103~~275

2842,~~936~~901

2742,~~958~~233

Operating income

32,~~638~~583

32,~~381~~209

6496,~~109~~692

6597,~~010~~219

Net income

23,~~649~~556

2324,~~891~~340

4670,~~626~~182

4772,~~736~~076

LNG Facility Arbitration

On March 1, 2016, an affiliate of Gulf LNG Holdings received a Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA Gas Marketing L.L.C. (“Eni USA”), one of the two companies that had entered into a terminal use agreement for capacity of the LNG Facility. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to the Notice of Arbitration, Eni USA seeks declaratory and monetary relief in respect of its terminal use agreement, asserting that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) the activities undertaken by affiliates of Gulf LNG Holdings “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the terminal use agreement.

Affiliates of Kinder Morgan, Inc., which control Gulf LNG Holdings and operate the LNG Facility, have expressed to the Partnership that they view the assertions by Eni USA to be without merit and that they will continue to vigorously contest the assertions set forth by Eni USA. Although the Partnership does not control Gulf LNG Holdings, the Partnership also is of the view that the assertions made by Eni USA are without merit. As contemplated by the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. The Partnership expects the arbitration panel will issue its decision before the end of the ~~third~~fourth quarter of 2017. If the arbitration panel has not issued its decision on or about December 4, 2017, the Partnership has been advised that the panel is expected, on or around such date, to advise the parties to the arbitration of the date that the panel expects to issue its decision. Eni USA has advised Gulf LNG Holdings’ affiliates that it will continue to pay the amounts claimed to be due under the terminal use agreement pending resolution of the dispute.

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Note 5—Property, Plant and Equipment

The Partnership’s property, plant and equipment consisted of (in thousands):

	As of
	June 30,			December 31,
	September 30,			December 31,
	2017			2016
Land	$	78,455		$	78,455
Buildings and site improvements		93,~~046~~186			84,976
Tanks and trim		~~129~~130,~~019~~445			124,438
Pipelines		20,507			20,507
Machinery and equipment		~~124~~123,~~747~~263			121,278
Office furniture and equipment		1,~~288~~291			1,152
Construction in progress		712,~~264~~547			14,917
		454,326			445,723
		459,694			445,723
Less: Accumulated depreciation		(5963,~~154~~496	)		(50,212	)
Property, plant and equipment, net	$	~~395~~396,~~172~~198		$	395,511

During the three months ended September 30, 2017, the Partnership recognized a non-cash loss of $1.5 million as a result of dismantling and selling salt unloading equipment at the Joliet terminal. The existing location of the salt unloading equipment interfered with the location of a new pipeline that is being constructed to support future commercial activities at the Joliet terminal and the Partnership opted to dismantle and sell the salt unloading equipment accordingly. The net impact of this disposal is reflected in “Loss on disposal of property and equipment” in the accompanying consolidated statement of operations and comprehensive income.

Note 6—Intangible Assets

The Partnership’s intangible assets consisted of (in thousands):

	Estimated	As of
	Useful Lives	~~June~~September 30,			December 31,
	in Years	2017			2016
Customer relationships	21	$	4,785		$	4,785
Acquired contracts	2-12		~~149~~148,342			149,342
Non-compete agreements	2-3		741			741
			154,868			154,868
			153,868			154,868
Less: Accumulated amortization			(4446,~~258~~728	)		(37,152	)
Intangible assets, net		$	~~110~~107,~~610~~140		$	117,716

The Partnership’s intangible assets are amortized on a straight-line basis over the expected life of each intangible asset. The estimated future amortization expense is approximately $63.95 million for the remainder of 2017, $12.8 million in 2018, $12.2 million in 2019, $12.2 million in 2020, $12.2 million in 2021 and $54.3 million thereafter.

Note 7—Debt

Credit Facility

Concurrent with the closing of the IPO, the Partnership entered into the Second Amended and Restated Revolving Credit Agreement (the “Credit Facility”) with a syndicate of lenders, under which Arc Terminals Holdings LLC (“Arc Terminals Holdings”) is the borrower. The Credit Facility matures in November 2018 and has up to $300.0 million of borrowing capacity. As of ~~June~~September 30, 2017, the Partnership had borrowings of $~~252~~256.0 million under the Credit Facility at an interest rate of 4.2325%. Based on the restrictions under the total leverage ratio covenant, as of ~~June~~September 30, 2017, the Partnership had $2925.20 million of available capacity under the Credit Facility.

The Credit Facility is available to fund working capital and to finance capital expenditures and other permitted payments and allows the Partnership to request that the maximum amount of the Credit Facility be increased by up to an aggregate principal amount of $100.0 million, subject to receiving increased commitments from lenders or commitments from other financial institutions. The Credit Facility is available for revolving loans, including a sublimit of $5.0 million for swing line loans and a sublimit of $20.0 million for letters of credit. The Partnership’s obligations under the Credit Facility are secured by a first priority lien on substantially all of the Partnership’s material assets other than the LNG Interest and the assets of the Partnership’s Joliet terminal (which is owned indirectly by Joliet Holdings, 40% of which is owned by an affiliate of GE EFS). The Partnership and each of the Partnership’s existing restricted subsidiaries (other than the borrower) guarantee, and each of the Partnership’s future restricted subsidiaries will also guarantee, the Credit Facility.

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by Joliet Holdings, 40% of which is owned by an affiliate of GE EFS). The Partnership and each of the Partnership’s existing restricted subsidiaries (other than the borrower) guarantee, and each of the Partnership’s future restricted subsidiaries will also guarantee, the Credit Facility.

Loans under the Credit Facility bear interest at a floating rate, based upon the Partnership’s total leverage ratio, equal to, at the Partnership’s option, either (a) a base rate plus a range from 100 to 225 basis points per annum or (b) a LIBOR rate, plus a range of 200 to 325 basis points. The base rate is established as the highest of (i) the rate which SunTrust Bank announces, from time to time, as its prime lending rate, (ii) the daily one-month LIBOR rate plus 100 basis points per annum and (iii) the federal funds rate plus 50 basis points per annum. The unused portion of the Credit Facility is subject to a commitment fee calculated based upon the Partnership’s total leverage ratio ranging from 0.375% to 0.50% per annum. Upon any event of default, the interest rate will, upon the request of the lenders holding a majority of the commitments, be increased by 2.0% on overdue amounts per annum for the period during which the event of default exists.

The Credit Facility contains certain customary representations and warranties, affirmative covenants, negative covenants and events of default. As of ~~June~~September 30, 2017, the Partnership was in compliance with such covenants. The negative covenants include restrictions on the Partnership’s ability to incur additional indebtedness, acquire and sell assets, create liens, enter into certain lease agreements, make investments and make distributions.

The Credit Facility requires the Partnership to maintain a total leverage ratio of not more than 4.50 to 1.00, which may increase to up to 5.00 to 1.00 during specified periods following a material permitted acquisition or issuance of over $200.0 million of senior notes, and a minimum interest coverage ratio of not less than 2.50 to 1.00. If the Partnership issues over $200.0 million of senior notes, the Partnership will be subject to an additional financial covenant pursuant to which the Partnership’s secured leverage ratio must not be more than 3.50 to 1.00. The Credit Facility places certain restrictions on the issuance of senior notes.

If an event of default occurs, the agent would be entitled to take various actions, including the acceleration of amounts due under the Credit Facility, termination of the commitments under the Credit Facility and all remedial actions available to a secured creditor. The events of default include customary events for a financing agreement of this type, including, without limitation, payment defaults, material inaccuracies of representations and warranties, defaults in the performance of affirmative or negative covenants (including financial covenants), bankruptcy or related defaults, defaults relating to judgments, nonpayment of other material indebtedness and the occurrence of a change in control. In connection with the Credit Facility, the Partnership and the Partnership’s subsidiaries have entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations and liabilities arising under or in connection with the Credit Facility are unconditionally guaranteed by the Partnership and each of the Partnership’s existing subsidiaries (other than the borrower and Joliet Holdings and the subsidiaries thereof) and each of the Partnership’s future restricted subsidiaries.

First Amendment

In January 2014, in connection with the lease agreement entered into at the Partnership’s Portland terminal, Arc Terminals Holdings, as borrower, together with the Partnership and certain of its other subsidiaries, as guarantors, entered into the first amendment to the Credit Facility (the “First Amendment”). The First Amendment principally modified certain provisions of the Credit Facility to allow Arc Terminals Holdings to enter into the Portland Lease Agreement relating to the use of petroleum products terminals and pipeline infrastructure located in Portland, Oregon.

Second Amendment

In May 2015, Arc Terminals Holdings, as borrower, together with the Partnership and certain of its other subsidiaries, as guarantors, entered into the second amendment to the Credit Facility as part of its financing for the JBBR Acquisition. Upon the closing of the JBBR Acquisition in May 2015, the aggregate commitments under the Credit Facility increased from $175 million to $275 million. In addition, the sublimit for letters of credit was increased from $10 million to $20 million.

Third Amendment

In July 2015, Arc Terminals Holdings, as borrower, together with the Partnership and certain of its other subsidiaries, as guarantors, entered into the third amendment to the Credit Facility as part of the financing for the Partnership’s purchase in July 2015 of all of the membership interests in UET Midstream, LLC (“UET Midstream”) from United Energy Trading, LLC (“UET”) and Hawkeye Midstream, LLC (together with UET, the “Pawnee Sellers”) for a purchase price, net of certain adjustments, of $76.6 million (the “Pawnee Terminal Acquisition”). Upon the consummation of the Pawnee Terminal Acquisition in July 2015, the aggregate commitments under the Credit Facility increased from $275 million to $300 million.

Fourth Amendment

In June 2016, Arc Terminals Holdings, as borrower, together with the Partnership and certain of its other subsidiaries, as guarantors, entered into the fourth amendment to the Credit Facility (the “Fourth Amendment”). The Fourth Amendment principally modifies certain provisions of the Credit Facility including (i) the circumstances whereby the Partnership may increase up to or ~~maintain a total leverage ratio of 5.00 to 1.00 and (ii) the interest rate pricing grid to include an additional pricing tier if the total leverage ratio is greater than or equal to 4.50 to 1.00.~~

maintain a total leverage ratio of 5.00 to 1.00 and (ii) the interest rate pricing grid to include an additional pricing tier if the total leverage ratio is greater than or equal to 4.50 to 1.00.

Fifth Amendment

In May 2017, Arc Terminals Holdings, as borrower, together with the Partnership and certain of its other subsidiaries, as guarantors, entered into the fifth amendment to the Credit Facility (the “Fifth Amendment”). The Fifth Amendment principally modifies a provision of the Credit Agreement whereby the Partnership may maintain a total leverage ratio of up to 5.00 to 1.00 for a stated period of time.

modifies a provision of the Credit Agreement whereby the Partnership may maintain a total leverage ratio of up to 5.00 to 1.00 for a stated period of time.

Note 8—Partners’ Capital and Distributions

Units Outstanding

As of ~~June~~September 30, 2017, the Partnership had 19,~~519~~545,~~276~~944 common units outstanding. Of that number, 5,242,775 were owned by Lightfoot. In addition, the General Partner, which is owned by Lightfoot, has a non-economic general partner interest in the Partnership along with incentive distribution rights.

Following payment of the cash distribution for the third quarter of 2016, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, effective November 16, 2016, the 6,081,081 subordinated units, of which 5,146,264 were owned by Lightfoot, converted on a one-for-one basis into common units and thereafter participate on terms equal with all other common units in distributions of available cash. The conversion did not impact the amount of cash distributions paid by the Partnership or the total units outstanding.

The table below summarizes the changes in the number of common units outstanding at December 31, 2016 through ~~June~~September 30, 2017:

	Limited Partner Common Units
Units outstanding at December 31, 2016		19,477,021
Vesting of equity-based compensation awards		4268,~~255~~923
Units outstanding at June 30, 2017		19,519,276
Units outstanding at September 30, 2017		19,545,944

Cash Distributions

The table below summarizes the quarterly distributions related to the Partnership’s quarterly financial results (in thousands, except per unit data):

	Total Quarterly		Total Cash		Date of	Unitholders
Quarter Ended	Distribution Per Unit		Distribution		Distribution	Record Date
September 30, 2017	$	0.4400	$	8,603	November 15, 2017	November 8, 2017
June 30, 2017	$	0.4400	$	8,600	August 15, 2017	August 8, 2017
March 31, 2017	$	0.4400	$	8,588	May 15, 2017	May 8, 2017
December 31, 2016	$	0.4400	$	8,570	February 15, 2017	February 8, 2017
September 30, 2016	$	0.4400	$	8,493	November 15, 2016	November 7, 2016
June 30, 2016	$	0.4400	$	8,490	August 12, 2016	August 8, 2016

Cash Distribution Policy

The Partnership’s partnership agreement provides that the General Partner will make a determination no less frequently than each quarter as to whether to make a distribution, but the partnership agreement does not require the Partnership to pay distributions at any time or in any amount. Instead, the ~~board of directors of the General Partner (the “~~Board”) has adopted a cash distribution policy that sets forth the General Partner’s intention with respect to the distributions to be made to unitholders. Pursuant to the cash distribution policy, within 60 days after the end of each quarter, the Partnership expects to distribute to the holders of common units on a quarterly basis at least the minimum quarterly distribution of $0.3875 per unit, or $1.55 per unit on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates.

The Board may change the foregoing distribution policy at any time and from time to time, and even if the cash distribution policy is not modified or revoked, the amount of distributions paid under the policy and the decision to make any distribution is determined solely by the General Partner. As a result, there is no guarantee that the Partnership will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, the partnership agreement contains provisions intended to motivate the General Partner to make steady, increasing and sustainable distributions over time.

The partnership agreement generally provides that the Partnership will distribute cash each quarter to all unitholders pro rata, until each has received a distribution of $0.4456. In connection with the entering into of the Merger Agreement, the Partnership

amended its distribution policy to provide that, from the date of the Merger Agreement through the date that the Merger is consummated, the Partnership will not declare or pay a distribution on its common units in excess of $0.44 per common unit.

If cash distributions to the Partnership’s unitholders exceed $0.4456 per unit in any quarter, the Partnership’s unitholders and the General Partner, as the initial holder of the incentive distribution rights, will receive distributions according to the following percentage allocations:

Total Quarterly Distribution Per Unit Target Amount	Marginal Percentage Interest in Distributions
Total Quarterly Distribution Per Unit Target Amount	Unitholders			General Partner
above $0.3875 up to $0.4456		100.0	%		0.0	%
above $0.4456 up to $0.4844		85.0	%		15.0	%
above $0.4844 up to $0.5813		75.0	%		25.0	%
above $0.5813		50.0	%		50.0	%

The Partnership refers to additional increasing distributions to the General Partner as “incentive distributions.”

Note 9—Equity Plans

2013 Long-Term Incentive Plan

The Board approved and adopted the Arc Logistics Long-Term Incentive Plan (as amended from time to time, the “2013 Plan”) in November 2013. In July 2014, the Board formed a Compensation Committee (the “Compensation Committee”) to administer the 2013 Plan. Effective as of March 2015, the Board dissolved the Compensation Committee and, on and after such date, the Board serves as the administrative committee (the “Committee”) under the 2013 Plan. The Board amended and restated the 2013 Plan in March 2016. Employees (including officers), consultants and directors of the General Partner, the Partnership and its affiliates (the “Partnership Entities”) are eligible to receive awards under the 2013 Plan. The 2013 Plan authorizes up to an aggregate of 2.0 million common units to be available for awards under the 2013 Plan, subject to adjustment as provided in the 2013 Plan. Awards available for grant under the 2013 Plan include, but are not limited to, restricted units, phantom units, unit options and unit appreciation rights, but only phantom units have been granted under the 2013 Plan to date. Distribution equivalent rights (“DER”) are also available for grant under the 2013 Plan, either alone or in tandem with other specific awards, which entitle the recipient to receive an amount equal to distributions paid on an outstanding common unit. Upon the occurrence of a “change of control” or an award recipient’s termination of service due to death or “disability” (each quoted term, as defined in the 2013 Plan), any outstanding unvested award will vest in full, except that, with respect to awards issued on or after March 9, 2016, the Committee may condition the automatic vesting of any such awards then outstanding upon a separation of employment for certain reasons (as established in an individual award agreement) following the occurrence of a “change of control”.

In July 2014, the Compensation Committee authorized the grant of an aggregate of 939,500 phantom units pursuant to the 2013 Plan to certain employees, consultants and non-employee directors of the Partnership Entities. Awards of phantom units are settled in common units, except that an award of less than 1,000 phantom units is settled in cash. If a phantom unit award recipient experiences a termination of service with the Partnership Entities other than (i) as a result of death or “disability” or (ii) due to certain circumstances in connection with a “change of control,” the Committee, at its sole discretion, may decide to vest all or any portion of the recipient’s unvested phantom units as of the date of such termination or may allow the unvested phantom units to remain outstanding and vest pursuant to the vesting schedule set forth in the applicable award agreement.

Of the July 2014 awards, a total of 100,000 phantom units were granted to certain non-employee directors of the Board and are classified as equity awards for accounting purposes (the “Director Grants”). Each Director Grant will be settled in common units and includes a DER. The Director Grants have an aggregate grant date fair value of $2.5 million and vest in equal annual installments over a three-year period starting from the date of grant. For the three and ~~six~~nine months ended ~~June~~September 30, 2017, the Partnership recorded approximately less than $0.21 million and $0.4 million, respectively, of unit-based compensation expense related to the Director Grants. For the three and ~~six~~nine months ended ~~June~~September 30, 2016, the Partnership recorded $0.2 million and $0.46 million, respectively, of unit-based compensation related to the Director Grants. As of ~~June~~September 30, 2017, ~~the~~100% ~~unrecognized~~of ~~unit-based~~the ~~compensation~~phantom ~~expense~~units ~~for~~granted under the Director Grants ishave ~~less~~vested ~~than~~and ~~$0.1~~all ~~million, which will be recognized ratably over the remaining term~~ of the ~~awards. Through~~related ~~June 30, 2017, two~~unit-~~thirds~~based ofcompensation ~~the~~expense ~~phantom~~has ~~units~~been ~~granted under the Director Grants have vested~~recognized.

Of the July 2014 awards, a total of 832,000 phantom units were granted to employees and certain consultants of the Partnership Entities and are classified as equity awards for accounting purposes (the “Employee Equity Grants”). Each Employee Equity Grant will be settled in common units and includes a DER. The Employee Equity Grants have an aggregate grant date fair value of $21.2 million and vest as follows: (i) 25% of the Employee Equity Grants vested on the day after the end of the Subordination Period (as defined in the partnership agreement); and (ii) the three remaining 25% installments of the Employee Equity Grants will vest based on the date on which the Partnership has paid, for three consecutive quarters, distributions to its common unitholders at or above a stated level, with (A) 25% of the award vesting after distributions are paid at or above $0.4457 per unit for the required period, (B) 25% of the award vesting after distributions are paid at or above $0.4845 per unit for the required period, and (C) the last 25% of the award vesting after distributions are paid at or above $0.5814 per unit for the required period. To the extent not previously vested, the Employee Equity Grants expire on the fifth anniversary of the date of grant, provided that the expiration date can be extended to the eighth anniversary of the date of grant or longer upon the satisfaction of certain conditions specified in the award agreement. For the three and six months ended June 30, 2017, the Partnership recorded $0.1 million and $0.3 million, respectively, of unit-based compensation expense related to the Employee Equity Grants. For the three and six months June 30, 2016, the Partnership recorded $0.8 million and $1.5 million, respectively, of unit-based compensation expense related to the Employee Equity Grants. As of June 30,

2017, the unrecognized unit-based compensation expense for the Employee Equity Grants was approximately $10.9 million, which may be recognized variably over the remaining term of the awards based on the probability of the achievement of the performance vesting requirements. Through June 30, 2017, one-fourth of the phantom units granted under the Employee Equity Grants have vested.

Of the July 2014 awards, a total of 7,500 phantom units were granted to certain employees of the Partnership Entities and are classified as liability awards for accounting purposes (the “Employee Liability Grants”). Each Employee Liability Grant will be settled in cash (as such award consists of less than 1,000 phantom units) and includes a DER. The Employee Liability Grants have an aggregate grant date fair value of $0.2 million and have the same term and vesting requirements as the Employee Equity Grants described in the preceding paragraph. For the three and six months ended June 30, 2017 and 2016, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period, with respect to the Employee Liability Grants. As of June 30, 2017, the unrecognized unit based compensation expense for the Employee Liability Grants was approximately less than $0.1 million, which may be recognized variably over the remaining term of the awards based on the probability of the achievement of the performance vesting requirements and is subject to remeasurement each reporting period until the awards settle. Through June 30, 2017, one-fourth of the phantom units granted under the Employee Liability Grants have vested.

In March 2015, the Board authorized the grant of an aggregate of 45,668 phantom units pursuant to the 2013 Plan to certain employees, consultants and non-employee directors of the Partnership Entities (“2015 Equity Grants”). Each 2015 Equity Grant will be settled in common units and includes a DER. The 2015 Equity Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $0.9 million and vest in equal annual installments over a three-year period starting from the date of grant. For the three and six months ended June 30, 2017, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation expense with respect to the 2015 Equity Grants. For the three and six months ended June 30, 2016, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation expense related to the 2015 Equity Grants. As of June 30, 2017, the unrecognized unit-based compensation expense for the 2015 Equity Grants is approximately $0.2 million, which will be recognized ratably over the remaining term of the awards. Through June 30, 2017, two-thirds of the phantom units granted under the 2015 Equity Grants have vested.

During the year ended December 31, 2015, the Board and Chief Executive Officer authorized the grant of an aggregate of 57,100 phantom units (in addition to the 45,668 phantom units granted in March 2015) pursuant to the 2013 Plan to certain employees of the Partnership Entities (“2015 Performance Grants”). Each 2015 Performance Grant will be settled in common units and includes a DER. The 2015 Performance Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $1.0 million and have the same term and vesting requirements as the Employee Equity Grants described above. For the three and six months ended June 30, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period with respect to the 2015 Performance Grants. For the three and six months ended June 30, 2016, the Partnership recorded $0.1 million of unit-based compensation expense during each period, with respect to the 2015 Performance Grants. As of June 30, 2017, the unrecognized unit-based compensation expense for the 2015 Performance Grants is approximately $0.6 million, which may be recognized variably over the remaining term of the awards based on the probability of the achievement of the performance vesting requirements. Through June 30, 2017, one-fourth of the phantom units granted under the 2015 Performance Grants have vested.

During the year ended December 31, 2016, the Board authorized the grant of an aggregate of 94,000 phantom units pursuant to the 2013 Plan to certain employees and consultants of the Partnership Entities (“2016 Equity Grants”). Each 2016 Equity Grant will be settled in common units and includes a DER. The 2016 Equity Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $1.1 million and vest in three equal annual installments over a three-year period starting from the date of grant. For the three and six months ended June 30, 2017, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation expense with respect to the 2016 Equity Grants. For the three and six months ended June 30, 2016, the Partnership recorded $0.1 million of unit-based compensation during each period, with respect to the 2016 Equity Grants. As of June 30, 2017, the unrecognized unit-based compensation expense for the 2016 Equity Grants is approximately $0.6 million, which will be recognized ratably over the remaining term of the awards. Through June 30, 2017, one-third of the phantom units granted under the 2016 Equity Grants have vested.

During the six months ended June 30, 2017, the Board authorized the grant of an aggregate of 127,561 phantom units pursuant to the 2013 Plan to certain employees and consultants of the Partnership Entities (“2017 Equity Grants”). Each 2017 Equity Grant will be settled in common units and includes a DER. The 2017 Equity Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $1.8 million, 109,111 of the 2017 Equity Grants vest in three equal annual installments over a three-year period starting from the date of grant, 16,450 of the 2017 Equity Grants vested immediately on the date of grant, and 2,000 of the 2017 Equity Grants had one-third of the phantom units vest on the date of grant while the remaining two-thirds will vest in two equal annual installments over a two-year period starting from the date of grant. For the three and six months ended June 30, 2017, the Partnership recorded $0.1 million and $0.4 million, respectively, of unit based compensation expense with respect to the 2017 Equity Grants. As of June 30, 2017, the unrecognized unit-based compensation expense for the 2017 Equity Grants is approximately $1.4 million, which will be recognized ratably over the remaining term of the awards.

During the six months ended June 30, 2017, the Board authorized the grant of an aggregate of 26,250 phantom units pursuant to the 2013 Plan to an employee of an affiliate of the Partnership Entities (“2017 Performance Grant”). The 2017 Performance Grant will be settled in common units and includes a DER. The 2017 Performance Grant is classified as an equity award for accounting purposes, has an aggregate grant date fair value of $0.4 million and will vest in three equal installments based on the date on which the Partnership has paid, for three consecutive quarters, distributions to its common unitholders at or above a stated level, with (A) one-third of the award vesting after distributions are paid at or above $0.4457 per unit for the required period, (B) one-third of the award

vesting after distributions are paid at or above $0.4845 per unit for the required period, and (C) the last one-third of the award vesting after distributions are paid at or above $0.5814 per unit for the required period. To the extent not previously vested, the 2017 Performance Grant expires on the fifth anniversary of the date of grant, provided that the expiration date can be extended to the eighth anniversary of the date of grant or longer upon the satisfaction of certain conditions specified in the award agreement. For the three and six months ended June 30, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period with respect to the 2017 Performance Grant. As of June 30, 2017, the unrecognized unit-based compensation expense for the 2017 Performance Grant is approximately $0.3 million which may be recognized variably over the remaining term of the award based on the probability of the achievement of the performance vesting requirements.

During the six months ended June 30, 2017, the Board authorized the grant of an aggregate of 10,475 phantom units pursuant to the 2013 Plan to employees of the Partnership Entities (“2017 Employee Liability Grants”). Each 2017 Employee Liability Grant will be settled in cash (as such award consists of less than 1,000 phantom units) and includes a DER. The 2017 Employee Liability Grants are classified as liability awards for accounting purposes, have an aggregate grant date fair value of $0.1 million and will vest in three equal installments over a three-year period starting from the date of grant. For the three and six months ended June 30, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period, with respect to the 2017 Employee Liability Grants. As of June 30, 2017, the unrecognized unit-based compensation expense for the 2017 Employee Liability Grants is approximately $0.1 million, which will be recognized ratably over the remaining term of the awards.

Subject to applicable earning criteria, the DER included in each phantom unit award described above entitles the award recipient to a cash payment (or, if applicable, payment of other property) equal to the cash distribution (or, if applicable, distribution of other property) paid on an outstanding common unit to unitholders generally based on the number of common units related to the portion of the award recipient’s phantom units that have not vested and been settled as of the record date for such distribution. Cash distributions paid during the vesting period on phantom units that are classified as equity awards for accounting purposes are reflected initially as a reduction of partners’ capital. Cash distributions paid on such equity awards that are not initially expected to vest or ultimately do not vest are classified as compensation expense. As the probability of vesting changes, these initial categorizations could change. Cash distributions paid during the vesting period on phantom units that are classified as liability awards for accounting purposes are reflected as compensation expense and included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. During the three and six months ended June 30, 2017, the Partnership paid approximately $0.4 million and $0.8 million, respectively, in DERs to phantom unit-holders. For the three and six months ended June 30, 2017, $0.2 million and $0.4 million, respectively, was reflected as a reduction of partners’ capital, and the other $0.2 million and $0.4 million, respectively, was reflected as compensation expense and included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. For the three and six months ended June 30, 2016, the Partnership paid approximately $0.5 million and $0.9 million, respectively, in DERs to phantom unit-holders. For the three months and six months ended June 30, 2016, $0.3 million and $0.5 million, respectively, was reflected as a reduction of partners’ capital, and the other $0.2 million and $0.4 million, respectively, was reflected as compensation expense and included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income.

The total compensation expense related to the 2013 Plan for the three and six months ended June 30, 2017 was $0.5 million and $1.4 million, respectively, which was included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. The total compensation expense related to the 2013 Plan for the three and six months ended June 30, 2016 was $1.2 million and $2.4 million, respectively, which was included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. The amount recorded as liabilities in “Other non-current liabilities” in the accompanying unaudited condensed consolidated balance sheet as of June 30, 2017 was less than $0.1 million.

The following table presents phantom units granted pursuant to the 2013 Plan:

	Equity Awards					Liability Awards
	Six Months Ended					Six Months Ended
	June 30, 2017					June 30, 2017
	Number			Weighted Avg.		Number			Weighted Avg.
	of Phantom			Grant Date		of Phantom			Grant Date		Fair Value at
	Units			Fair Value		Units			Fair Value		6/30/2017
Balance at December 31, 2016		804,818		$	23.29		4,125		$	25.46	$	15.19
Granted		153,811		$	14.30		10,475		$	14.01	$	-
Vested		(56,961	)	$	13.80		(500	)	$	14.01	$	-
Forfeited		(6,667	)	$	25.46		(775	)	$	19.55	$	-
Balance at June 30, 2017		895,001		$	22.33		13,325		$	17.23	$	15.19

vesting after distributions are paid at or above $0.5814 per unit for the required period. To the extent not previously vested, the Employee Equity Grants expire on the fifth anniversary of the date of grant, provided that the expiration date can be extended to the eighth anniversary of the date of grant or longer upon the satisfaction of certain conditions specified in the award agreement. For the three and nine months ended September 30, 2017, the Partnership recorded $0.2 million and $0.5 million, respectively, of unit-based compensation expense related to the Employee Equity Grants. For the three and nine months ended September 30, 2016, the Partnership recorded $0.8 million and $2.3 million, respectively, of unit-based compensation expense related to the Employee Equity Grants. As of September 30, 2017, the unrecognized unit-based compensation expense for the Employee Equity Grants was approximately $10.6 million, which may be recognized variably over the remaining term of the awards based on the probability of the achievement of the performance vesting requirements. Through September 30, 2017, one-fourth of the phantom units granted under the Employee Equity Grants have vested.

Of the July 2014 awards, a total of 7,500 phantom units were granted to certain employees of the Partnership Entities and are classified as liability awards for accounting purposes (the “Employee Liability Grants”). Each Employee Liability Grant will be settled in cash (as such award consists of less than 1,000 phantom units) and includes a DER. The Employee Liability Grants have an aggregate grant date fair value of $0.2 million and have the same term and vesting requirements as the Employee Equity Grants described in the preceding paragraph. For the three and nine months ended September 30, 2017 and 2016, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period, with respect to the Employee Liability Grants. As of September 30, 2017, the unrecognized unit based compensation expense for the Employee Liability Grants was approximately less than $0.1 million, which may be recognized variably over the remaining term of the awards based on the probability of the achievement of the performance vesting requirements and is subject to remeasurement each reporting period until the awards settle. Through September 30, 2017, one-fourth of the phantom units granted under the Employee Liability Grants have vested.

In March 2015, the Board authorized the grant of an aggregate of 45,668 phantom units pursuant to the 2013 Plan to certain employees, consultants and non-employee directors of the Partnership Entities (“2015 Equity Grants”). Each 2015 Equity Grant will be settled in common units and includes a DER. The 2015 Equity Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $0.9 million and vest in equal annual installments over a three-year period starting from the date of grant. For the three and nine months ended September 30, 2017, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation expense with respect to the 2015 Equity Grants. For the three and nine months ended September 30, 2016, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation expense with respect to the 2015 Equity Grants. As of September 30, 2017, the unrecognized unit-based compensation expense for the 2015 Equity Grants is approximately $0.1 million, which will be recognized ratably over the remaining term of the awards. Through September 30, 2017, two-thirds of the phantom units granted under the 2015 Equity Grants have vested.

During the year ended December 31, 2015, the Board and Chief Executive Officer authorized the grant of an aggregate of 57,100 phantom units (in addition to the 45,668 phantom units granted in March 2015) pursuant to the 2013 Plan to certain employees of the Partnership Entities (“2015 Performance Grants”). Each 2015 Performance Grant will be settled in common units and includes a DER. The 2015 Performance Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $1.0 million and have the same term and vesting requirements as the Employee Equity Grants described above. For the three and nine months ended September 30, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period with respect to the 2015 Performance Grants. For the three and nine months ended September 30, 2016, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation expense with respect to the 2015 Performance Grants. As of September 30, 2017, the unrecognized unit-based compensation expense for the 2015 Performance Grants is approximately $0.6 million, which may be recognized variably over the remaining term of the awards based on the probability of the achievement of the performance vesting requirements. Through September 30, 2017, one-fourth of the phantom units granted under the 2015 Performance Grants have vested.

During the year ended December 31, 2016, the Board authorized the grant of an aggregate of 94,000 phantom units pursuant to the 2013 Plan to certain employees and consultants of the Partnership Entities (“2016 Equity Grants”). Each 2016 Equity Grant will be settled in common units and includes a DER. The 2016 Equity Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $1.1 million and vest in three equal annual installments over a three-year period starting from the date of grant. For the three and nine months ended September 30, 2017, the Partnership recorded $0.1 million and $0.3 million, respectively, of unit-based compensation expense with respect to the 2016 Equity Grants. For the three and nine months ended September 30, 2016, the Partnership recorded $0.1 million and $0.2 million, respectively, of unit-based compensation with respect to the 2016 Equity Grants. As of September 30, 2017, the unrecognized unit-based compensation expense for the 2016 Equity Grants is approximately $0.6 million, which will be recognized ratably over the remaining term of the awards. Through September 30, 2017, one-third of the phantom units granted under the 2016 Equity Grants have vested.

During the nine months ended September 30, 2017, the Board authorized the grant of an aggregate of 227,561 phantom units pursuant to the 2013 Plan to certain employees, directors and consultants of the Partnership Entities (“2017 Equity Grants”). Each 2017 Equity Grant will be settled in common units and includes a DER. The 2017 Equity Grants are classified as equity awards for accounting purposes and have an aggregate grant date fair value of $3.4 million, 209,111 of the 2017 Equity Grants vest in three equal annual installments over a three-year period starting from the date of grant, 16,450 of the 2017 Equity Grants vested immediately on the date of grant, and 2,000 of the 2017 Equity Grants had one-third of the phantom units vest on the date of grant while the remaining two-thirds will vest in two equal annual installments over a two-year period starting from the date of grant. For the three and nine months ended September 30, 2017, the Partnership recorded $0.2 million and $0.6 million, respectively, of unit based compensation

expense with respect to the 2017 Equity Grants. As of September 30, 2017, the unrecognized unit-based compensation expense for the 2017 Equity Grants is approximately $2.7 million, which will be recognized ratably over the remaining term of the awards.

During the nine months ended September 30, 2017, the Board authorized the grant of an aggregate of 26,250 phantom units pursuant to the 2013 Plan to an employee of an affiliate of the Partnership Entities (“2017 Performance Grant”). The 2017 Performance Grant will be settled in common units and includes a DER. The 2017 Performance Grant is classified as an equity award for accounting purposes, has an aggregate grant date fair value of $0.4 million and will vest in three equal installments based on the date on which the Partnership has paid, for three consecutive quarters, distributions to its common unitholders at or above a stated level, with (A) one-third of the award vesting after distributions are paid at or above $0.4457 per unit for the required period, (B) one-third of the award vesting after distributions are paid at or above $0.4845 per unit for the required period, and (C) the last one-third of the award vesting after distributions are paid at or above $0.5814 per unit for the required period. To the extent not previously vested, the 2017 Performance Grant expires on the fifth anniversary of the date of grant, provided that the expiration date can be extended to the eighth anniversary of the date of grant or longer upon the satisfaction of certain conditions specified in the award agreement. For the three and nine months ended September 30, 2017, the Partnership recorded less than $0.1 million and $0.1 million, respectively, of unit-based compensation expense with respect to the 2017 Performance Grant. As of September 30, 2017, the unrecognized unit-based compensation expense for the 2017 Performance Grant is approximately $0.3 million which may be recognized variably over the remaining term of the award based on the probability of the achievement of the performance vesting requirements.

During the nine months ended September 30, 2017, the Board authorized the grant of an aggregate of 10,475 phantom units pursuant to the 2013 Plan to employees of the Partnership Entities (“2017 Employee Liability Grants”). Each 2017 Employee Liability Grant will be settled in cash (as such award consists of less than 1,000 phantom units) and includes a DER. The 2017 Employee Liability Grants are classified as liability awards for accounting purposes, have an aggregate grant date fair value of $0.1 million and will vest in three equal installments over a three-year period starting from the date of grant. For the three and nine months ended September 30, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense during each period, with respect to the 2017 Employee Liability Grants. As of September 30, 2017, the unrecognized unit-based compensation expense for the 2017 Employee Liability Grants is approximately $0.1 million, which will be recognized ratably over the remaining term of the awards.

Subject to applicable earning criteria, the DER included in each phantom unit award described above entitles the award recipient to a cash payment (or, if applicable, payment of other property) equal to the cash distribution (or, if applicable, distribution of other property) paid on an outstanding common unit to unitholders generally based on the number of common units related to the portion of the award recipient’s phantom units that have not vested and been settled as of the record date for such distribution. Cash distributions paid during the vesting period on phantom units that are classified as equity awards for accounting purposes are reflected initially as a reduction of partners’ capital. Cash distributions paid on such equity awards that are not initially expected to vest or ultimately do not vest are classified as compensation expense. As the probability of vesting changes, these initial categorizations could change. Cash distributions paid during the vesting period on phantom units that are classified as liability awards for accounting purposes are reflected as compensation expense and included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. During the three and nine months ended September 30, 2017, the Partnership paid approximately $0.4 million and $1.2 million, respectively, in DERs to phantom unit-holders. For the three and nine months ended September 30, 2017, $0.2 million and $0.6 million, respectively, was reflected as a reduction of partners’ capital, and the other $0.2 million and $0.6 million, respectively, was reflected as compensation expense and included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. For the three and nine months ended September 30, 2016, the Partnership paid approximately $0.5 million and $1.4 million, respectively, in DERs to phantom unit-holders. For the three months and nine months ended September 30, 2016, $0.3 million and $0.8 million, respectively, was reflected as a reduction of partners’ capital, and the other $0.2 million and $0.6 million, respectively, was reflected as compensation expense and included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income.

The total compensation expense related to the 2013 Plan for the three and nine months ended September 30, 2017 was $0.5 million and $1.9 million, respectively, which was included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. The total compensation expense related to the 2013 Plan for the three and nine months ended September 30, 2016 was $1.2 million and $3.6 million, respectively, which was included in the “Selling, general and administrative” line item in the accompanying unaudited condensed consolidated statements of operations and comprehensive income. The amount recorded as liabilities in “Other non-current liabilities” in the accompanying unaudited condensed consolidated balance sheet as of September 30, 2017 was less than $0.1 million.

The following table presents phantom units granted pursuant to the 2013 Plan:

	Equity Awards					Liability Awards
	Nine Months Ended					Nine Months Ended
	September 30, 2017					September 30, 2017
	Number			Weighted Avg.		Number			Weighted Avg.
	of Phantom			Grant Date		of Phantom			Grant Date		Fair Value at
	Units			Fair Value		Units			Fair Value		9/30/2017
Balance at December 31, 2016		804,818		$	23.29		4,125		$	25.46	$	16.70
Granted		253,811		$	14.72		10,475		$	14.01	$	-
Vested		(83,629	)	$	17.52		(500	)	$	14.01	$	-
Forfeited		(30,271	)	$	19.36		(775	)	$	19.55	$	-
Balance at September 30, 2017		944,729		$	21.62		13,325		$	17.23	$	16.70

Note 10—Earnings Per Unit

The Partnership uses the two-class method when calculating the net income per unit applicable to limited partners. The two-class method is based on the weighted-average number of common and subordinated units outstanding during the period. Basic net income per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income, after deducting distributions, if any, by the weighted-average number of outstanding common and subordinated units. Payments made to the Partnership’s unitholders are determined in relation to actual distributions paid and are not based on the net income allocations used in the calculation of net income per unit.

Diluted net income per unit applicable to limited partners includes the effects of potentially dilutive units on the Partnership’s units. For the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, the only potentially dilutive units outstanding consisted of the phantom units (see “Note 9—Equity Plans”) as they are considered to be participating securities. For the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, none of the phantom units are included in the calculation of diluted earnings per share due to the Partnership having declared distributions in excess of reported net income attributable to partners’ capital.

The following table sets forth the calculation of basic and diluted earnings per limited partner unit for the periods indicated (in thousands, except per unit data):

	Three Months Ended					~~Six~~Nine Months Ended
	June 30,					June 30,
	September 30,					September 30,
	2017			2016		2017		2016
Net Income attributable to partners' capital	$	~~3,228~~144		$	4,~~850~~132	$	5,~~691~~835	$	812,~~081~~212
Less:
Distribution equivalent rights for unissued units		~~227~~216			~~260~~257		~~422~~638		~~534~~791
Net income available to limited partners	$	3,001		$	4,590	$	5,269	$	7,547
Net income (loss) available to limited partners	$	(72	)	$	3,875	$	5,197	$	11,421
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income among limited partner interests:
Net income allocated to common unitholders	$	3,001		$	3,141	$	5,269	$	5,169
Net income (loss) allocated to common unitholders	$	(72	)	$	2,655	$	5,197	$	7,824
Net income (loss) allocated to subordinated unitholders	$	-		$	1,~~449~~220	$	-	$	23,~~377~~597
Net income allocated to limited partners:	$	3,001		$	4,590	$	5,269	$	7,546
Net income (loss) allocated to limited partners:	$	(72	)	$	3,875	$	5,197	$	11,421
Denominator for basic and diluted earnings per limited partner unit:
Common units - (basic and diluted)		19,~~519~~541			13,~~181~~209		19,~~503~~516		13,~~179~~189
Subordinated units - (basic and diluted)		-			6,081		-		6,081
Earnings (loss) per limited partner unit:
Common - (basic and diluted)	$	0.1500		$	0.2420	$	0.27	$	0.3959
Subordinated - (basic and diluted)	$	-		$	0.2420	$	-	$	0.3959

Note 11—Related Party Transactions

Agreements with Affiliates

Payments to the General Partner and its Affiliates

The General Partner conducts, directs and manages all activities of the Partnership. The General Partner is reimbursed on a monthly basis, or such other basis as may be determined, for: (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership and its subsidiaries; and (ii) all other expenses allocable to the Partnership and its subsidiaries or otherwise incurred by the General Partner in connection with operating the Partnership and its subsidiaries’ businesses (including expenses allocated to the General Partner by its affiliates).

For the three months ended ~~June~~September 30, 2017 and 2016, the General Partner incurred expenses of $1.34 million and $1.3 million, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, the General Partner incurred expenses of $23.69 million and $24.60 million, respectively. Such expenses are reimbursable from the Partnership and are reflected in the “Selling, general and administrative – affiliate” line on the accompanying unaudited condensed consolidated statements of operations and comprehensive income. As of ~~June~~September 30, 2017 and December 31, 2016, the Partnership had a payable of approximately $02.98 million and $2.1 million, respectively, to the General Partner, which is reflected as “Due to general partner” in the accompanying unaudited condensed consolidated balance sheets.

Registration Rights Agreement

In connection with the IPO, the Partnership entered into a registration rights agreement with the Sponsor. Pursuant to the registration rights agreement, the Partnership is required to file, upon request of the Sponsor, a registration statement to register the common units issued to the Sponsor and the common units issuable upon the conversion of the subordinated units held by the Sponsor. In addition, the registration rights agreement gives the Sponsor piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates and, in certain circumstances, to third parties.

Other Transactions with Related Persons

Storage and Throughput Agreements with Center Oil

During 2007, the Partnership acquired seven terminals from Center Oil for $35.0 million in cash and 750,000 subordinated units in the Partnership. In connection with this purchase, the Partnership entered into a storage and throughput agreement with Center Oil whereby the Partnership provides storage and throughput services for various petroleum products to Center Oil at the terminals acquired by the Partnership in return for a fixed per barrel fee for each outbound barrel of Center Oil product shipped or committed to be shipped. The throughput fee is calculated and due monthly based on the terms and conditions as set forth in the storage and throughput agreement. In addition to the monthly throughput fee, Center Oil is required to pay the Partnership a fixed per barrel fee for any additives added into Center Oil’s product.

In December 2015, the Partnership extended the term of the storage and throughput agreement with Center Oil to June 2020. The agreement will automatically renew for a period of three years at the expiration of the current term at an inflation adjusted rate (subject to a cap), as determined in accordance with the agreement, unless a party delivers a written notice of its election to terminate the storage and throughput agreement at least eighteen months prior to the expiration of the current term.

In February 2010, the Partnership acquired a 50% undivided interest in the Baltimore, MD terminal. In connection with the acquisition, the Partnership acquired an existing agreement with Center Oil whereby the Partnership provides ethanol storage and throughput services to Center Oil. The Partnership charges Center Oil a fixed fee for storage and a fee based upon ethanol throughput at the Baltimore, MD terminal. The storage and throughput fees are calculated monthly based on the terms and conditions of the storage and throughput agreement. This agreement was renewed under the one-year evergreen provision and has been extended to May 2018.

In May 2013, the Partnership entered into an agreement to provide gasoline storage and throughput services to Center Oil at the Brooklyn terminal. The Partnership charges Center Oil a fixed per barrel fee for each inbound delivery of ethanol and every outbound barrel of product shipped and a fee for any ethanol blending and additives added to Center Oil’s product. The storage and throughput fees are calculated monthly based on the terms and conditions of the storage and throughput agreement. This agreement was renewed under the one-year evergreen provision and has been extended to May 2018.

Throughput Agreements with UET

In connection with the Pawnee Terminals Acquisition, the Partnership acquired two terminalling services agreements with UET (each, a “UET Throughput Agreement”). Each UET Throughput Agreement requires UET Midstream to make available to UET a minimum volume of throughput capacity on a monthly basis at the Pawnee terminal in exchange for payment by UET of a fixed, per barrel monthly fee for such capacity regardless of whether UET utilizes any or all such throughput capacity, in each case subject to certain exceptions. The minimum monthly contract throughput capacity increases each year during the initial five-year term under one of the UET Throughput Agreements. The initial term of each UET Throughput Agreement (which expire in May 2020) will automatically extend under certain circumstances. Each UET Throughput Agreement requires UET to deliver crude oil that meets certain specifications and to pay certain other fees, including fees for the use of excess throughput capacity and certain other ancillary services. The UET Throughput Agreements contain certain other customary insurance, indemnification, default and termination provisions, including the right of a party to terminate the applicable UET Throughput Agreement following an event of default and the expiration of all applicable cure periods.

one of the UET Throughput Agreements. The initial term of each UET Throughput Agreement (which expire in May 2020) will automatically extend under certain circumstances. Each UET Throughput Agreement requires UET to deliver crude oil that meets certain specifications and to pay certain other fees, including fees for the use of excess throughput capacity and certain other ancillary services. The UET Throughput Agreements contain certain other customary insurance, indemnification, default and termination provisions, including the right of a party to terminate the applicable UET Throughput Agreement following an event of default and the expiration of all applicable cure periods.

Revenues – Related Parties

The total revenues associated with the storage and throughput agreements for Center Oil, UET and Gulf Coast Asphalt Company (“GCAC”) reflected in the “Revenues – Related parties” line on the accompanying unaudited condensed consolidated statements of operations and comprehensive income are as follows (in thousands):

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2017

2016

2017

2016

Center Oil

1,~~474~~431

1,~~470~~447

24,~~951~~382

24,~~931~~378

UET (a)

N/A

1,~~706~~837

N/A

35,~~281~~118

GCAC (a)

N/A

~~449~~455

N/A

~~896~~1,351

Total

1,~~474~~431

3,~~625~~739

24,~~951~~382

710,~~108~~847

(a)

GCAC and UET are no longer considered related parties of the Partnership

The total receivables associated with the storage and throughput agreements for Center Oil, UET and GCAC reflected in the “Due from related parties” line on the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):

	As of
	June 30,		December 31,
	September 30,		December 31,
	2017		2016
Center Oil	$	~~473~~480	$	676
UET (a)	N/A			645
GCAC (a)	N/A		N/A
Total	$	~~473~~480	$	1,321

(a)

GCAC and UET are no longer considered related parties of the Partnership

Natural Gas Supply Agreement

In March 2016, the Partnership, through its wholly owned subsidiary, Arc Terminals Holdings, entered into a natural gas supply agreement with UET to supply the Portland terminal with natural gas. UET charges the Partnership for the actual amount of natural gas supplied on a monthly basis plus a transportation fee. The agreement expires on March 31, 2018, unless mutually extended for an additional year by both UET and the Partnership.

Joliet LLC Agreement

In connection with the JBBR Acquisition in May 2015, the Partnership and an affiliate of GE EFS entered into an amended and restated limited liability company agreement of Joliet Holdings governing their respective interests in Joliet Holdings (the “Joliet LLC Agreement”). An affiliate of GE EFS owns 40% of Joliet Holdings, while the remaining 60% is owned by the Partnership. GE EFS indirectly owns interests in Lightfoot. Lightfoot has a significant interest in the Partnership through its ownership of a 27% limited partner interest in the Partnership, 100% of the limited liability company interests in the General Partner and all of the Partnership’s incentive distribution rights. As of April 2017, John Pugh serves on the board of managers of Lightfoot Capital Partners GP LLC and on the Board of the General Partner and is a Managing Director at GE EFS, which is an affiliate of General Electric Company. In addition, Arc Terminals Holdings entered into a Management Services Agreement (the “MSA”) with Joliet Holdings to manage and operate the Joliet terminal. Arc Terminals Holdings receives a fixed monthly management fee and reimbursements for out-of-pocket expenses. In addition, Arc Terminals Holdings may receive additional monthly management fees based upon the throughput activity at the Joliet terminal. During the three months ended ~~June~~September 30, 2017 and 2016, the Partnership was paid $0.45 million and $0.3 million, respectively, in fees and reimbursements by Joliet Holdings under the MSA. During the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, the Partnership was paid $01.81 million and $01.60 million, respectively, in fees and reimbursements by Joliet Holdings under the MSA.

PIPE Transaction

Registration Rights Agreement with PIPE Investors

Pursuant to a Unit Purchase Agreement dated as of February 19, 2015 (the “PIPE Purchase Agreement”) among the Partnership and the purchasers named therein (the “PIPE Purchasers”), the Partnership sold 4,520,795 common units at a price of $16.59 per common unit in a private placement (the “PIPE Transaction”) on May 14, 2015 for proceeds totaling $72.7 million after placement agent commissions and expenses, which were used to partially finance the Partnership’s portion of the purchase price of the JBBR Acquisition. As a part of the PIPE Transaction, the Partnership entered into a registration rights agreement (the “PIPE Registration Rights Agreement”), dated May 14, 2015, with the PIPE Purchasers. The issuance of the common units pursuant to the PIPE Purchase Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) pursuant to Section 4(a)(2) thereof.

common unit in a private placement (the “PIPE Transaction”) on May 14, 2015 for proceeds totaling $72.7 million after placement agent commissions and expenses, which were used to partially finance the Partnership’s portion of the purchase price of the JBBR Acquisition. As a part of the PIPE Transaction, the Partnership entered into a registration rights agreement (the “PIPE Registration Rights Agreement”), dated May 14, 2015, with the PIPE Purchasers. The issuance of the common units pursuant to the PIPE Purchase Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) pursuant to Section 4(a)(2) thereof.

Pursuant to the PIPE Registration Rights Agreement, the Partnership filed, and the SEC declared effective, a shelf registration statement registering the common units of the PIPE Purchasers. In addition, the PIPE Registration Rights Agreement gives the PIPE Purchasers piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the PIPE Purchasers.

Material Relationships Relating to PIPE Transaction

MTP Energy Master Fund Ltd. (“Magnetar PIPE Investor”), one of the PIPE Purchasers, purchased 572,635 common units for approximately $9.5 million in the PIPE Transaction. Magnetar Financial LLC controls the investment manager of the Magnetar PIPE Investor, and an affiliate of Magnetar Financial LLC also owns interests in Lightfoot, which is the sole owner of the General Partner. Eric Scheyer, the Head of the Energy Group of Magnetar Financial LLC, also serves on the Board.

UET Contribution Agreement

In July 2015, the Partnership, through its wholly owned subsidiary, Arc Terminals Holdings, entered into a contribution agreement (the “Contribution Agreement”) with the Pawnee Sellers, pursuant to which it acquired all of the limited liability company interests of UET Midstream from the Pawnee Sellers for total consideration, net of certain adjustments, of $76.6 million, consisting of $44.3 million in cash and $32.3 million of common units of the Partnership. The number of common units issued to the Pawnee Sellers at the closing of the Pawnee Terminal Acquisition was based upon an issuance price of $18.50 per unit, which resulted in the issuance of 1,745,669 of the Partnership’s common units.

interests of UET Midstream from the Pawnee Sellers for total consideration, net of certain adjustments, of $76.6 million, consisting of $44.3 million in cash and $32.3 million of common units of the Partnership. The number of common units issued to the Pawnee Sellers at the closing of the Pawnee Terminal Acquisition was based upon an issuance price of $18.50 per unit, which resulted in the issuance of 1,745,669 of the Partnership’s common units.

Registration Rights Agreement with Pawnee Sellers

In connection with the issuance of the Partnership’s common units to the Pawnee Sellers (the “Initial Pawnee Holders”) pursuant to the Contribution Agreement as partial consideration for the Pawnee Terminal Acquisition, the Partnership entered into a Registration Rights Agreement (the “Pawnee Registration Rights Agreement”), dated as of July 14, 2015, with the Initial Pawnee Holders. The issuance of the Partnership’s common units pursuant to the Contribution Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof.

Pursuant to the Pawnee Registration Rights Agreement, the Partnership filed, and the SEC declared effective, a shelf registration statement registering the common units of the Pawnee Sellers. In July 2016, the Partnership deregistered the common units of the Pawnee Sellers that remained unsold under the shelf registration statement because it no longer had an obligation to keep the shelf registration statement effective pursuant to the terms of the Pawnee Registration Rights Agreement.

Note 12—Major Customers

The following table presents the percentage of revenues and receivables associated with the Partnership’s significant customers (those that have accounted for 10% or more of the Partnership’s revenues in a given period) for the periods indicated:

	% of Revenues						% of Revenues
	Three Months Ended						~~Six~~Nine Months Ended						% of Receivables
	June 30,						June 30,						June 30,			December 31,
	September 30,						September 30,						September 30,			December 31,
	2017			2016			2017			2016			2017			2016
Customer A		34	%		33	%		34	%		33	%		3227	%		32	%
Customer B		11	%		11	%		11	%		12	%		1016	%		11	%
Total		45	%		44	%		45	%		45	%		4243	%		43	%

Note 13—Commitments and Contingencies

Environmental Matters

The Partnership may experience releases of crude oil, petroleum products and fuels or other contaminants into the environment or discover past releases that were previously unidentified. Although the Partnership maintains preventative maintenance and compliance programs designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from the Partnership’s assets may affect its business. As a result, the Partnership may accrue for losses associated with environmental remediation obligations, when such losses are probable and reasonably estimable. Estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Loss accruals are adjusted as further information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. The Partnership is not a party to any material pending legal proceedings relating to environmental remediation or other environmental matters and is not aware of any claims or events relating to environmental remediation or other environmental matters that, either individually or in the aggregate, could have a material adverse effect on the Partnership’s business, financial condition, results of operations and ability to make quarterly distributions to its unitholders. As of September 30, 2017 and December 31, 2016, the Partnership had not experienced any releases of crude oil, petroleum products and fuels or other contaminants into the environment or discovered past releases that were previously unidentified that would give rise to evaluating an estimate of possible losses or a range of losses. Accordingly, the Partnership had not accrued for any loss contingencies in 2017 and 2016.

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feasibility study. Loss accruals are adjusted as further information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. The Partnership is not a party to any material pending legal proceedings relating to environmental remediation or other environmental matters and is not aware of any claims or events relating to environmental remediation or other environmental matters that, either individually or in the aggregate, could have a material adverse effect on the Partnership’s business, financial condition, results of operations and ability to make quarterly distributions to its unitholders. As of June 30, 2017 and December 31, 2016, the Partnership had not experienced any releases of crude oil, petroleum products and fuels or other contaminants into the environment or discovered past releases that were previously unidentified that would give rise to evaluating an estimate of possible losses or a range of losses. Accordingly, the Partnership had not accrued for any loss contingencies in 2017 and 2016.

Commitments and Contractual Obligations

Future non-cancelable commitments related to certain contractual obligations as of ~~June~~September 30, 2017 are presented below (in thousands):

	Payments Due by Period
	Total		2017		2018		2019		2020		2021		Thereafter
Long-term debt obligations	$	~~252~~256,000	$	-	$	~~252~~256,000	$	-	$	-	$	-	$	-
Operating lease obligations		1412,~~290~~702		31,~~243~~622		6,~~381~~414		4,665		1		-		-
Earn-out obligations		2322,~~026~~391		~~1,051~~416		2,281		2,281		2,281		2,281		12,851
Settlement obligations		~~750~~625		~~250~~125		500		-		-		-		-
Total	$	~~290~~291,~~066~~718	$	42,~~544~~163	$	~~261~~265,~~162~~195	$	6,946	$	2,282	$	2,281	$	12,851

Operating Lease Agreement

In January 2014, the Partnership, through its wholly owned subsidiary, Arc Terminals Holdings, entered into a triple net operating lease agreement relating to the Portland terminal together with a supplemental co-terminus triple net operating lease agreement for the use of certain pipeline infrastructure at such terminal (such lease agreements, collectively, the “Portland Lease Agreement”), pursuant to which Arc Terminals Holdings leased the Portland terminal from a wholly owned subsidiary of CorEnergy Infrastructure Trust, Inc. (“CorEnergy”). Arc Logistics guaranteed Arc Terminals Holdings’ obligations under the Portland Lease Agreement. CorEnergy owns a 6.6% direct investment in Lightfoot Capital Partners, LP and a 1.5% direct investment in Lightfoot Capital Partners GP LLC, the general partner of Lightfoot Capital Partners, LP. The Portland Lease Agreement has a 15-year initial term and may be extended for additional five-year terms at the sole discretion of Arc Terminals Holdings, subject to renegotiated rental payment terms. During the term of the Portland Lease Agreement, Arc Terminals Holdings will make base monthly rental payments and variable rent payments based on the volume of liquid hydrocarbons that flowed through the Portland terminal in the prior month. The base rent in the initial years of the Portland Lease Agreement was $230,000 per month through July 2014 (prorated for the partial month of January 2014) and is $417,522 for each month thereafter until the end of year five. The base rent also increased each month starting with the month of August 2014 by a factor of 0.00958 of the specified construction costs incurred by LCP Oregon Holdings LLC at the Portland terminal. During 2015, spending on terminal-related projects by CorEnergy since the commencement of the Portland Lease Agreement totaled $10.0 million and, as a result, the base rent has increased by approximately $95,800 per month. Accordingly, any additional terminal-related projects will be funded by the Partnership. The base rent will be increased in February 2019 by the change in the consumer price index for the prior five years, and every year thereafter by the greater of two percent or the change in the consumer price index. The base rent is not influenced by the flow of hydrocarbons. Variable rent will result from the flow of hydrocarbons through the Portland terminal in excess of a designated threshold of 12,500 barrels per day of oil equivalent. Variable rent is capped at 30% of base rent payments regardless of the level of hydrocarbon throughput. During the three months ended ~~June~~September 30, 2017 and 2016, the rent expense associated with the Portland Lease Agreement was $1.6 million, during each period. During the ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, the rent expense associated with the Portland Lease Agreement was $34.28 million, during each period. During the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016, there was no variable rent associated with the Portland Lease Agreement. So long as Arc Terminals Holdings is not in default under the Portland Lease Agreement, it shall have the right to purchase the Portland terminal at the end of any month thereafter by delivery of 90 days’ notice (“Purchase Option”). The purchase price shall be the greater of (i) nine times the total of base rent and variable rent for the 12 months immediately preceding the notice and (ii) $65.7 million. If the Purchase Option is not exercised, the Portland Lease Agreement shall remain in place and Arc Terminals Holdings shall continue to pay rent as provided above. Arc Terminals Holdings also has the option to terminate the Portland Lease Agreement on the fifth and tenth anniversaries, by providing written notice 12 months in advance, for a termination fee of $4 million and $6 million, respectively.

CenterPoint Earnout

In connection with the JBBR Acquisition, CenterPoint is entitled to receive up to an additional $27.0 million in cash earn-out payments. As a part of the purchase price allocation related to the JBBR Acquisition, Joliet Holdings recorded a liability of $19.7 million, as of the date of the JBBR Acquisition, in connection with this potential CenterPoint earn-out payment. From the date of acquisition through September 30, 2017, Joliet Holdings has reported earn-out payment amounts of $4.6 million related to the earn-out obligation. The Partnership will continue to evaluate this liability each quarter for any changes in the estimated fair value.

acquisition through June 30, 2017, Joliet Holdings has reported earn-out amounts of $4.0 million related to the earn-out obligation. The Partnership will continue to evaluate this liability each quarter for any changes in the estimated fair value.

Settlement Obligation

In February 2016, Arc Terminals Holdings entered into a settlement agreement with its customer at the Blakeley, AL facility (the “Blakeley Customer”) pursuant to which the parties agreed to terminate the terminal services agreement entered into by the parties for the storage and throughputting of the Blakeley Customer’s sulfuric acid at the Blakeley, AL facility and to, among other things, release each party from all potential claims arising out of any non-performance of or non-compliance with the representations, warranties and covenants made thereunder. Pursuant to the settlement agreement, Arc Terminals Holdings agreed to pay to the Blakeley Customer an aggregate amount of $2.0 million in certain increments over a three-year period commencing with the first quarter of 2016, except that Arc Terminals Holdings’ payment obligations thereunder shall be reduced by $0.5 million in the event that Arc Terminals Holdings and the Blakeley Customer enter into a new terminal services agreement for the storage and throughputting of such customer’s sulfuric acid at the Blakeley, AL facility commencing no later than January 1, 2018. Neither Arc Terminals Holdings nor the Blakeley Customer has any obligation to enter into such new terminal services agreement. During the year ended December 31, 2015, the Partnership had established an accrual of $2.0 million with respect to its obligations under such settlement agreement. Through June 30, 2017, the Partnership has paid $1.3 million related to the settlement agreement.

quarter of 2016, except that Arc Terminals Holdings’ payment obligations thereunder shall be reduced by $0.5 million in the event that Arc Terminals Holdings and the Blakeley Customer enter into a new terminal services agreement for the storage and throughputting of such customer’s sulfuric acid at the Blakeley, AL facility commencing no later than January 1, 2018. Neither Arc Terminals Holdings nor the Blakeley Customer has any obligation to enter into such new terminal services agreement. During the year ended December 31, 2015, the Partnership had established an accrual of $2.0 million with respect to its obligations under such settlement agreement. Through September 30, 2017, the Partnership has paid $1.4 million related to the settlement agreement.

Note 14—Subsequent Events

Cash Distributions

In ~~July~~October 2017, the Partnership declared a quarterly cash distribution of $0.44 per unit ($1.76 per unit on an annualized basis) totaling approximately $8.6 million for all common units outstanding. The distribution is for the period from ~~April~~July 1, 2017 through ~~June~~September 30, 2017. The distribution is payable on ~~August~~November 15, 2017 to unitholders of record on ~~August~~November 8, 2017.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•

adverse regional, national or international economic conditions, adverse capital market conditions or adverse political developments;

•

changes in the marketplace for our services, such as increased competition, better energy efficiency, or general reductions in demand;

•

changes in the prices and long-term supply and demand of crude oil and petroleum products in the geographic regions in which we operate;

•

actions taken by our customers, competitors and third party operators;

•

nonrenewal, nonpayment or nonperformance by our customers and our ability to replace such contracts and/or customers;

•

changes in the availability and cost of capital;

•

unanticipated capital expenditures in connection with the construction, repair, or replacement of our assets;

•

operating hazards, natural disasters, terrorism, weather-related delays, adverse weather conditions, including hurricanes, natural disasters, environmental releases, casualty losses and other matters beyond our control;

•

inability to consummate acquisitions, pending or otherwise, on acceptable terms and successfully integrate such businesses into our operations;

• the effects of existing and future laws and governmental regulations to which we are subject, including those that permit the treatment of us as a partnership for federal income tax purposes; ~~and~~

• the effects of pending and future litigation.; and

•

our ability to complete the previously announced transaction with Zenith Energy U.S., L.P. and its affiliates (the “Proposed Transaction”).

There can be no guarantee that the Proposed Transaction will be completed, or if it is completed, the time frame in which it will be completed. The Proposed Transaction is subject to the satisfaction of certain conditions contained in the merger agreement related thereto. The failure to complete the Proposed Transaction could disrupt certain of our plans, operations, business and employee relationships.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read together with our unaudited condensed consolidated financial statements (“interim statements”), including the notes thereto, set forth herein. The following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the audited consolidated financial statements and related notes, together with our discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Partnership 10-K”), as filed with the SEC. This discussion may contain forward-looking statements that are based on the views and beliefs of our management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this Quarterly Report on Form 10-Q, particularly under “Cautionary Statement Regarding Forward-Looking Statements.”

Unless the context clearly indicates otherwise, references in this Quarterly Report on Form 10-Q to “Arc Logistics,” the “Partnership,” “we,” “our,” “us” or similar terms refer to Arc Logistics Partners LP and its subsidiaries. Unless the context clearly indicates otherwise, references to our “General Partner” refer to Arc Logistics GP LLC, the general partner of Arc Logistics, and references to our “Board” refer to the Board of Directors of our General Partner. References to our “Sponsor” or “Lightfoot” or “Lightfoot Entities” refer to Lightfoot Capital Partners, LP (“LCP LP”) and its general partner, Lightfoot Capital Partners GP LLC (“LCP GP”). References to “Center Oil” refer to GP&W, Inc., d.b.a. Center Oil, and affiliates, including Center Terminal Company-Cleveland, which contributed its limited partner interests in Arc Terminals, LP, predecessor to Arc Logistics, to the Partnership upon the consummation of the initial public offering (“IPO”). References to “Gulf LNG Holdings” refer to Gulf LNG Holdings Group, LLC and its subsidiaries, which own a liquefied natural gas regasification and storage facility in Pascagoula, MS, which is referred to herein as the “LNG Facility.” The Partnership owns a 10.3% limited liability company interest in Gulf LNG Holdings, which is referred to herein as the “LNG Interest.”

Overview

We are a fee-based, growth-oriented Delaware limited partnership formed by Lightfoot to own, operate, develop and acquire a diversified portfolio of complementary energy logistics assets. We are principally engaged in the terminalling, storage, throughput and transloading of crude oil, petroleum products and other liquids. We are focused on growing our business through the optimization, organic development and acquisition of terminalling, storage, rail, pipeline and other energy logistics assets that generate stable cash flows.

Our primary business objective is to generate stable cash flows that enable us to pay quarterly cash distributions to unitholders and, over time, increase quarterly cash distributions. We intend to achieve this objective by evaluating long-term infrastructure needs in the areas we serve and by growing our network of energy logistics assets through expansion of existing facilities, constructing new facilities in existing or new markets and completing strategic acquisitions.

Recent Developments

Merger Transaction

On August 29, 2017, we, and our General Partner (together with the Partnership, the “MLP Entities”), the Lightfoot Entities, Zenith Energy U.S., L.P., a Delaware limited partnership (“Parent”), Zenith Energy U.S. GP, LLC, a Delaware limited liability company and the general partner of Parent (“Parent GP”), Zenith Energy U.S. Logistics Holdings, LLC, a Delaware limited liability company and a subsidiary of Parent (“Holdings”), and Zenith Energy U.S. Logistics, LLC, a Delaware limited liability company and a subsidiary of Holdings (“Merger Sub” and, together with Parent, Parent GP and Holdings, the “Parent Entities”), entered into a Purchase Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which Merger Sub will, upon the terms and subject to the conditions thereof, merge with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a subsidiary of Parent, and LCP GP will transfer to Holdings 100% of the issued and outstanding membership interests in our General Partner, including all rights and obligations relating thereto and all economic and capital interest therein (the “GP Equity Transfer”).

The conflicts committee of our Board (the “GP Conflicts Committee”), after consultation with its independent legal and financial advisors, unanimously (i) determined that it is fair and reasonable and in the best interests of the Partnership and the holders of common units representing limited partner interests in the Partnership other than the Lightfoot Entities and their controlling affiliates to enter into the Merger Agreement and consummate the Merger, (ii) approved the Merger Agreement and the Merger, such approval constituting Special Approval pursuant to Section 7.9(d) of our partnership agreement, (iii) recommended approval of the Merger Agreement and the Merger by our Board, (iv) recommended that our Board direct the Merger Agreement to be submitted to a vote of our limited partners at a special meeting and (v) recommended that our limited partners approve the Merger Agreement and the Merger. Our Board, acting based in part upon the recommendation of the GP Conflicts Committee, unanimously (i) determined that it is fair and reasonable and in the best interests of the Partnership and our common unitholders to enter into the Merger Agreement and consummate the Merger, (ii) approved the Merger Agreement and the Merger, (iii) directed the Merger Agreement to

be submitted to a vote of our limited partners at a special meeting and (iv) determined to recommend that our limited partners approve the Merger Agreement and the Merger.

Upon the Merger and GP Equity Transfer becoming effective (the “Effective Time”), (a) each common unit representing a limited partner interest in the Partnership issued and outstanding immediately prior to the Effective Time (other than those common units owned by the Lightfoot Entities (the “Sponsor Units”)) will be converted into the right to receive an amount in cash equal to $16.50 per common unit, no longer be outstanding, automatically be cancelled and cease to exist, (b) each Sponsor Unit issued and outstanding immediately prior to the Effective Time will be converted into the right to receive an amount in cash equal to $14.50 per common unit, no longer be outstanding, automatically be cancelled and cease to exist, in each case, upon the terms and subject to the conditions set forth in the Merger Agreement and (c) Holdings will (or Parent will on Holdings’ behalf) pay to LCP GP $94,500,000 in cash in exchange for 100% of the membership interests in our General Partner acquired by Holdings in connection with the GP Equity Transfer.

Unless otherwise mutually agreed by the parties, including with the approval of the GP Conflicts Committee, the Merger will not be consummated earlier than November 30, 2017. The consummation of the Merger and the GP Equity Transfer is subject to the satisfaction or waiver of a number of conditions, including, among others: (i) receipt of the approval by the holders of a majority of our outstanding common units at a special meeting of our common unitholders of the Merger Agreement and the Merger (the “MLP Unitholder Approval”), (ii) expiration or termination of the waiting period applicable to the Transactions (as defined below) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (which termination was granted on September 22, 2017), (iii) the absence of certain legal impediments to the consummation of the Merger, (iv) the accuracy or waiver of the parties’ representations and warranties, (v) the performance of the parties’ obligations under the Merger Agreement, (vi) nothing has occurred (excluding, among other things, (a) developments generally affecting the prices of commodities, or (b) any changes in or effect upon the business or condition (financial or otherwise) of the MLP Entities and its subsidiaries or any adverse consequences upon or affecting Gulf LNG Holdings or its direct or indirect equityholders as a result of that certain proceeding between Eni USA Gas Marketing L.L.C. and certain operating subsidiaries of Gulf LNG Holdings relating to the LNG Facility (as more fully described below)) resulting in or reasonably expected to result in a material adverse effect on the business or financial results or condition of the MLP Entities, (vii) nothing has occurred that has a material adverse effect on the ability of the MLP Entities or the Lightfoot Entities to consummate the Transactions, (viii) our receipt of a legal opinion regarding certain tax matters, (ix) Holdings’ receipt of the written resignations of each member of our Board and each officer of our General Partner, dated to be effected as of the Effective Time, and (x) Parent GP’s receipt of the transition services agreement related thereto.

Additionally, the consummation of the Merger and the GP Equity Transfer is subject to the consummation or contemporaneous consummation of (a) the purchase by Holdings and the Lightfoot Entities of certain of the interests in Arc Terminals Joliet Holdings LLC, a Delaware limited liability company (“Joliet Holdings”), held by EFS Midstream Holdings LLC, a Delaware limited liability company (“GE EFS”) (such purchase, the “Joliet Purchase”), pursuant to the Purchase Agreement, dated August 29, 2017, by and among Holdings, the Lightfoot Entities and GE EFS, and (b) the purchase by Holdings of a 5.51646% interest and, subject to certain conditions, an additional 4.16154% interest, in Gulf LNG Holdings from LCP LNG Holdings, LLC, a Delaware limited liability company and subsidiary of LCP LP (“LCP LNG”) (such purchase, the “Gulf LNG Purchase” and together with the Joliet Purchase, the Merger, the GP Equity Transfer and the other transactions contemplated by the Merger Agreement, the “Transactions”) pursuant to the Partially Conditional Purchase Agreement, dated August 29, 2017, by and among LCP LNG, the Lightfoot Entities, Parent, Parent GP, Holdings and, solely for the purposes of Section 1.1(d) of such agreement, the Partnership.

The Merger Agreement contains certain termination rights including, among others, (i) by mutual agreement of Parent GP and our General Partner, (ii) by either our General Partner or Parent GP, in the event that (a) a court issues a final, non-appealable order or injunction prohibiting the Merger, (b) after final adjournment of the special meeting of our limited partners, MLP Unitholder Approval has not been obtained, or (c) the Merger has not been consummated on or before February 7, 2018, subject to extension at Parent GP’s election to March 1, 2018, in certain circumstances as specified in the Merger Agreement (the “Outside Date”), (iii) by our General Partner, in the event (a) the GP Conflicts Committee withdraws its recommendation that our limited partners approve the Merger and Merger Agreement due to a superior proposal, our Board authorizes the MLP Entities to enter into an agreement with respect to such superior proposal and, concurrently with the termination of the Merger Agreement, the MLP Entities enter into such agreement, (b) any Parent Entity has breached any of its representations or warranties or has failed to perform any of its covenants or agreements which such breach or failure would prevent the satisfaction of a condition to the consummation of the Merger or is incapable of being cured within a specified time or (c) the Parent Entities fail to close within a specified time after receiving notice from the MLP Entities that all conditions to closing have been satisfied or waived and the MLP Entities stand ready, willing and able to close and (iv) by Parent GP, in the event that (a) any MLP Entity or any Lightfoot Entity has breached the non-solicit obligations under the Merger Agreement, (b) any MLP Entity or any Lightfoot Entity has breached any of its representations or warranties or has failed to perform any of its covenants or agreements which such breach or failure would prevent the satisfaction of a condition to the consummation of the Merger or is incapable of being cured within a specified time or (c) prior to final adjournment of the special meeting of our limited partners, our Board withdraws its recommendation that our limited partners approve the Merger and Merger Agreement. Upon termination of the Merger Agreement under specific circumstances, we will be required to pay Parent a termination fee of $11,487,696 (the “MLP Termination Fee”). If the Merger Agreement is terminated (A) (i) due to the passing of the Outside Date, (ii) failure to obtain MLP Unitholder Approval or (iii) due to any Lightfoot Entity or MLP Entity’s failure to perform any covenant or agreement or

the failure of any of the representations and warranties of any Lightfoot Entity or MLP Entity to be true and correct as of the date of the Merger Agreement and (B) any MLP Entity or Lightfoot Entity or affiliate thereof enters into an alternative acquisition within 12 months of such termination, the MLP Termination Fee is payable. The MLP Termination Fee is also payable in the event, among other things, that Parent terminates the Merger Agreement due to any MLP Entity or Lightfoot Entity’s breach of the non-solicit provisions in the Merger Agreement, excluding breaches that do not adversely affect the Parent Entities or the Transactions in any material respect, or if our Board withdraws its recommendation that our limited partners approve the Merger and the Merger Agreement due to a superior proposal, our Board authorizes the MLP Entities to enter into an agreement with respect to such superior proposal and, concurrently with the termination of the Merger Agreement, the MLP Entities enter into such agreement. The Merger Agreement also provides that Parent will be required to pay us a termination fee of $24,616,491 if the Merger Agreement is terminated under certain circumstances.

From the date of the Merger Agreement until the Effective Time, we plan to declare and pay quarterly distributions in the ordinary course of business and consistent with past practices. Assuming that the Merger has not closed by January 26, 2018, we expect that we would declare a distribution associated with the quarter ended December 31, 2017 on or about January 26, 2018, to be paid on or about February 15, 2018 to our common unitholders of record as of February 8, 2018. If, as anticipated, the Merger closes prior to the record date for the distribution associated with the fourth quarter of 2017, then the holders of our common units as of immediately prior to the closing of the Merger will not receive any distribution associated with the fourth quarter of 2017. If, alternatively, the Merger does not close by the record date for the distribution associated with the fourth quarter of 2017, then we plan to pay the fourth quarter distribution, on or around February 15, 2018, to our common unitholders of record as of the record date applicable to such distribution, irrespective of whether the Merger closes thereafter or whether our General Partner or Parent GP terminates the Merger Agreement after the Outside Date.

The Merger is targeted to close on or about December 21, 2017 and is subject to the right that each of our General Partner and Parent GP has to terminate the Merger Agreement if the Merger has not been consummated on or before the Outside Date. Additional information regarding the proposed transaction and the terms and conditions of the Merger Agreement are set forth in our definitive proxy statement for the special meeting of our common unitholders to consider and vote on the Merger Agreement and the Merger, filed on October 30, 2017.

Conversion of Subordinated Units

Following payment of the cash distribution for the third quarter of 2016, the requirements for the conversion of all subordinated units were satisfied under our partnership agreement. As a result, on November 16, 2016, the 6,081,081 subordinated units, of which 5,146,264 were owned by our Sponsor, converted into common units on a one-for-one basis.

LNG Facility Arbitration

Affiliates of Kinder Morgan, Inc., which control Gulf LNG Holdings and operate the LNG Facility, have expressed to us that they view the assertions by Eni USA to be without merit, and that they will continue to vigorously contest the assertions set forth by Eni USA. As contemplated by the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. Although we do not control Gulf LNG Holdings, we also are of the view that the assertions made by Eni USA are without merit. A three-member arbitration panel conducted an arbitration hearing in January 2017. We expect the arbitration panel will issue its decision before the end of the ~~third~~fourth quarter of 2017. If the arbitration panel has not issued its decision on or about December 4, 2017, we have been advised that the panel is expected, on or around such date, to advise the parties to the arbitration of the date that the panel expects to issue its decision. Eni USA has advised Gulf LNG Holdings’ affiliates that it will continue to pay the amounts claimed to be due under the terminal use agreement pending resolution of the dispute.

29If the assertions by Eni USA to terminate or amend its payment obligations under the terminal use agreement prior to the expiration of its initial term are ultimately successful, our business, financial conditions and results of operations and our ability to make cash distributions to our unitholders would be (or in the event Eni USA’s payment obligations are amended, could be) materially adversely affected. For the nine months ended September 30, 2017, 17% and 20% of our Adjusted EBITDA and Distributable Cash Flow, respectively, were associated with our LNG Interest. For the nine months ended September 30, 2016, 17% and 25% of our Adjusted EBITDA and Distributable Cash Flow, respectively, were associated with our LNG Interest.

If the assertions by Eni USA to terminate or amend its payment obligations under the terminal use agreement prior to the expiration of its initial term are ultimately successful, our business, financial conditions and results of operations and our ability to make cash distributions to our unitholders would be (or in the event Eni USA’s payment obligations are amended, could be) materially adversely affected. For the six months ended June 30, 2017, 18% and 20% of our Adjusted EBITDA and Distributable Cash Flow, respectively, were associated with our LNG Interest. For the six months ended June 30, 2016, 18% and 25% of our Adjusted EBITDA and Distributable Cash Flow, respectively, were associated with our LNG Interest. 34

Factors That Impact Our Business

The revenues generated by our logistics assets are generally driven by the storage, throughput and transloading capacity under contract. The regional demand for our customers’ products being shipped through our facilities drives the physical utilization of facilities and ultimately the revenues we receive for our services. Though substantially all of our services agreements require customers to enter into take-or-pay arrangements for committed terminalling services, our revenues can be affected by: (1) the incremental fees that we charge customers to receive and deliver product; (2) the length of any underlying back-to-back supply agreements that our customers have with their respective customers; (3) commodity pricing fluctuations; (4) fluctuations in product volumes to the extent revenues under the contracts are a function of the amount of product transported; (5) inflation adjustments in services agreements; and (6) changes in the demand for ancillary services, such as heating, blending, and mixing our customers’ products between our tanks, railcars and marine operations.

We believe key factors that influence our business are: (1) the short-term and long-term demand for and supply of crude oil and petroleum products; (2) the indirect impact of crude oil and petroleum product pricing including regional pricing differentials on the demand and supply of logistics assets; (3) the needs of our customers together with the competitiveness of our service offerings with respect to location, price, reliability and flexibility; (4) current and future economic conditions; (5) changes to local, state and federal laws and regulations and (6) our ability and the ability of our competitors to capitalize on growth opportunities and changing market dynamics.

Supply and Demand for Crude Oil and Petroleum Products

Our results of operations are dependent upon the volumes of crude oil and petroleum products we have contracted to store, throughput and transload. An important factor in such contracting is the amount of supply and demand for crude oil and petroleum products. The supply of and demand for crude oil and petroleum products are driven by many factors, including technological innovations, capital investment, delivery costs, the price for crude oil and petroleum products, local and regional price differentials, refining and manufacturing processes, weather/seasonal changes and general economic conditions. A significant increase or decrease in the demand for crude oil and petroleum products, which can be the result of fluctuations in production, market prices or a combination of both, in the areas served by our facilities will have a corresponding effect on (1) the volumes we actually store, throughput and transload on behalf of our customers; (2) our customers’ decision to renew existing services agreements; and (3) our ability to execute contracts with new customers.

Prices of Crude Oil and Petroleum Products

Because we do not take title to any of the crude oil and petroleum products that we handle for our customers and do not engage in the marketing of crude oil and petroleum products, we have minimal direct exposure to risks associated with fluctuating commodity prices. However, extended periods of depressed or elevated crude oil and petroleum product prices or significant volatility in the pricing of crude oil or petroleum products in a short period of time can lead producers and refiners to increase or decrease production of crude oil and petroleum products, which can impact supply and demand dynamics resulting in changes in our customers’ product movements and the associated use of our facilities.

If the future prices of crude oil and petroleum products are substantially higher than the then-current prices, also called market contango, our customers’ demand for excess storage generally increases as they purchase products at today’s prices to take advantage of potential increasing product margins. If the future prices of crude oil and petroleum products are lower than the then-current prices, also called market backwardation, our customers’ demand for excess storage capacity generally decreases as they reduce their exposure to potential decreasing product margins. In general, demand for our throughput services increases and decreases as pricing differentials in favor of our customers’ increases or decreases, respectively.

In most cases, as the market price of crude oil and petroleum products sold by our customers in local markets increases over the price charged by producers to supply our customers for such crude oil and petroleum products, our customers’ demand for crude oil and/or petroleum products increases. As the market price for crude oil and petroleum products sold by our customers in local markets decreases as compared to the price charged by producers to supply our customers for such crude oil and petroleum products, our customers’ demand for crude oil and petroleum products decreases. In general, demand for our throughput services increases and decreases as pricing differentials in favor of our customers’ increase or decrease, respectively.

Diversity of Receipt and Delivery Modes

Access to terminal facilities includes marine, rail, pipeline and truck. Depending on the type of commodity our customers are storing or throughputting, each product receipt/delivery mode may offer a significant advantage to that customer at any one time or under a certain situation. In order for our customers to optimize product pricing differentials, they generally prefer as many receipt/delivery modes as possible to access our facilities whether it be for crude oil, petroleum products, ethanol and/or biodiesel. An important factor in potential customers deciding whether to execute a new contract with us is the availability of these receipt/delivery modes versus our competition. If we are not able to offer a customer their preferred receipt/delivery mode that a competitor is able to offer, we will most likely not be successful in executing an agreement with that customer.

receipt/delivery modes as possible to access our facilities whether it be for crude oil, petroleum products, ethanol and/or biodiesel. An important factor in potential customers deciding whether to execute a new contract with us is the availability of these receipt/delivery modes versus our competition. If we are not able to offer a customer their preferred receipt/delivery mode that a competitor is able to offer, we will most likely not be successful in executing an agreement with that customer.

If market conditions change and a current customer is able to receive/deliver product through a competitor’s assets at a cost that is lower than our facility, we will generally see volumes decrease by that customer. If we are able to offer receipt/delivery modes and access to our assets that allows that customer to utilize our facility at a cost that it is less than our competitors, we would expect the utilization of our asset by that customer to increase.

Customers and Competition

We provide terminalling, storage, throughput and transloading services for a broad mix of third-party customers, including major oil companies, independent refiners, crude oil and petroleum product marketers, distributors, chemical companies and various manufacturers. In general, the mix of services we provide to our customers varies with the business strategies of our customers, regional economies, market conditions, expectations for future market conditions and the overall competitiveness of our service offerings.

The level of competition varies in the markets in which we operate. We compete with other terminal operators and logistics providers on the basis of rates, terms of service, types of service, supply and market access and flexibility and reliability of service. The competitiveness of our service offerings, including the rates we charge for new contracts or contract renewals, is affected by the availability of storage and rail capacity relative to the overall demand for storage or rail capacity in a given market area and could be significantly impacted by the entry of new competitors into a market in which one of our facilities operates. We believe that significant barriers to entry exist in the crude oil and petroleum products logistics business.

Our Joliet terminal is currently supported by a terminal services agreement and a pipeline throughput and deficiency agreement with ExxonMobil Oil Corporation (“Exxon”), each with an initial three-year term that is currently scheduled to expire in May 2018. ~~Based on conversations with representatives of~~ Exxon, wedid do not ~~expect Exxon to~~ exercise in August 2017 its option to renew the term of the Exxon agreements on the current terms and conditions. Although Exxon has expressed interest in using the services of the Joliet terminal past the currently scheduled contract expiry date of May 2018, and we intend to continue discussions with Exxon regarding such services, there can be no assurances that any such arrangement will occur. If we are unable to enter into a new arrangement with Exxon on terms that are similar to the current terms, our business, financial conditions, results of operations and ability to make cash distributions to our unitholders could be materially adversely affected. Further, the carrying value of our goodwill and Joliet terminal assets are sensitive to the outcome of the Exxon contract renewal and could also be at risk of impairment. The carrying value of goodwill and the Joliet terminal assets as of September 30, 2017 were $39.9 million and $151.1 million, respectively. For the ~~six~~nine months ended ~~June~~September 30, 2017, Exxon, our largest customer, accounted for 2930% and 3839% of our Adjusted EBITDA and Distributable Cash Flow, respectively, in each case after removing the non-controlling interest portion related to our co-investor’s ownership interest in ~~Arc Terminals~~ Joliet Holdings ~~LLC (“Joliet Holdings”)~~.

Economic Conditions and Energy Industry

In the recent past, world financial markets experienced a severe reduction in the availability of credit. The condition of credit markets may adversely affect our liquidity and the availability of credit. In addition, given the number of parties involved in the exploration, transportation, storage and throughput of crude oil and petroleum products, we could experience a tightening of trade credit as a result of our customers’ inability to access their own credit.

Economic conditions worldwide periodically contribute to slowdowns in the energy industry, as well as in the specific segments and markets in which we operate, resulting in reduced production, reduced supply or demand and increased price competition for our services. In addition, economic conditions could result in a loss of customers because their access to the capital necessary to fund their supply and distribution business is limited. Our operating results may also be affected by uncertain or changing economic conditions in certain regions of the United States. If global economic and market conditions (including volatility or sustained weakness in commodity markets) or economic conditions in the United States remain uncertain or persist, spread or deteriorate further, we may experience material adverse effects on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Regulatory Environment

The movement and storage of crude oil and petroleum products in the United States is highly regulated by local, state and federal governments and governmental agencies. As an energy logistics service provider, in order to remain in compliance with these laws, we could be required to spend incremental capital expenditures or incur additional operating expenses to service our customer commitments, which could impact our business.

Organic Growth Opportunities

Regional crude oil and petroleum products supply and demand dynamics shift over time, which can lead to rapid and significant changes in demand for logistics services. At such times, we believe the companies that have positioned themselves to provide a complementary suite of logistics assets with organic growth opportunities will have a competitive advantage in capitalizing on the shifting market dynamics. Where feasible, we have designed the infrastructure at our facilities to allow for future expansion. As of September 30, 2017, we had an aggregate of over 250 acres of available land, across our facilities, to increase our rail, marine, truck and/or terminal capacity should either the crude oil or petroleum products market warrant incremental growth opportunities.

June 30, 2017, we had an aggregate of over 250 acres of available land, across our facilities, to increase our rail, marine, truck and/or terminal capacity should either the crude oil or petroleum products market warrant incremental growth opportunities.

Overview of Our Results of Operations

Our management uses a variety of financial measurements to analyze our performance, including the following key measures: (1) revenues derived from (a) storage and throughput services fees and (b) ancillary services fees; (2) our operating and selling, general and administrative (“SG&A”) expenses; (3) Adjusted EBITDA; and (4) Distributable Cash Flow.

We do not utilize non-cash depreciation and amortization expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives. In our period-to-period comparisons of our revenues and expenses set forth below, we analyze the following revenue and expense components:

Revenues

Our cash flows are primarily generated by fee-based terminalling, storage, throughput and transloading services that we perform under multi-year contracts. A portion of our services agreements are operating under automatic renewal terms that began upon the expiration of the primary contract term. While a portion of our capacity is subject to a one-year commitment, historically these customers have continued to renew or expand their business. We generate revenues through the following fee-based services to our customers:

•

Storage and Throughput Services Fees. We generate revenues from customers who reserve storage, throughput and transloading capacity at our facilities. Our service agreements typically allow us to charge customers a number of activity fees, including for the receipt, storage, throughput and transloading of crude oil, petroleum products and other liquids. Many of our service agreements contain take-or-pay provisions whereby we generate revenue regardless of customers’ use of the facility. We characterize our storage and throughput services fees into two categories:

Minimum Storage and Throughput Services Fees: Minimum monthly fees charged to our customers for the right to use dedicated storage, throughput, and transloading capacity. Our customers are required to pay these fees irrespective of the level of use of their contractual capacity. In the event a customer’s monthly activity exceeds its dedicated capacity, our service agreements include provisions to charge excess throughput fees. Any handling fees in excess of the minimum storage and throughput services fees are reflected in the excess throughput and handling fees.

Excess Throughput and Handling Fees: Fees charged to customers for the use of storage, throughput and transloading capacity used in excess of their minimum reserved storage, throughput and transloading capacity. These fees are charged to our customers based on their actual monthly activity levels. In addition, our service agreements typically include handling services fees which include additive injection fees, ethanol blending fees, biodiesel blending fees and fees for the receipt and delivery of product through rail, marine or truck infrastructure.

•

Ancillary Services Fees. We generate revenues from ancillary services, such as heating, blending, lab inspection services, sampling and mixing associated with our customers’ activity. The revenues we generate from ancillary services vary based upon customers’ activity levels. In addition, our ancillary services fees also include real property rents (or lease revenue) for the use of dedicated property at various terminal locations.

We believe that the high percentage of take-or-pay storage and throughput services fees generated from a diverse portfolio of multi-year contracts, coupled with little exposure to commodity price fluctuations, creates stable cash flow and substantially mitigates our exposure to volatility in supply and demand and other market factors.

We also receive cash distributions from the LNG Interest we acquired in November 2013, which is accounted for using equity method accounting. These distributions are supported by two multi-year, firm reservation charge terminal use agreements for all of the capacity of the LNG Facility that went into commercial operation in October 2011 with several integrated, multi-national oil and gas companies. As of ~~June~~September 30, 2017, the remaining term of each terminal use agreement is approximately 14 years.

While our financial statements separately present revenue from third parties and related parties, we evaluate our business and characterize our revenues as derived from storage and throughput services fees and ancillary services fees.

Operating Expenses

Our management seeks to maximize the profitability of our operations by effectively managing operating expenses. These expenses are comprised primarily of labor expenses, utility costs, additive expenses, insurance premiums, repair and maintenance expenses, health, safety and environmental compliance and property taxes. These expenses generally remain relatively stable across broad ranges of activity levels at our facilities but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We incorporate preventative maintenance programs by scheduling maintenance over time to avoid significant variability in maintenance expenses and minimize their impact on our cash flow.

Selling, General and Administrative Expenses

While our financial statements separately present SG&A expenses and SG&A–affiliate expenses, we evaluate our SG&A expenses as a whole, which primarily consist of compensation of non-operating personnel, employee benefits, transaction costs, reimbursements to our General Partner and its affiliates of SG&A expenses incurred in connection with our operations and expenses of overall administration.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess: (i) the performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets; (ii) the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities; (iii) our ability to make distributions; (iv) our ability to incur and service debt; (v) our ability to fund capital expenditures; and (vi) our ability to incur additional expenses. We define Adjusted EBITDA as net income before interest expense, income taxes and depreciation and amortization expense, as further adjusted for other non-cash charges and other charges that are not reflective of our ongoing operations.

We believe that the presentation of Adjusted EBITDA provides useful information to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income. Adjusted EBITDA should not be considered as an alternative to net income. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Distributable Cash Flow

Distributable Cash Flow is a non-GAAP financial measure that management and external users of our consolidated financial statements may use to evaluate whether we are generating sufficient cash flow to support distributions to our unitholders as well as measure the ability of our assets to generate cash sufficient to support our indebtedness and maintain our operations. We define Distributable Cash Flow as Adjusted EBITDA less (i) cash interest expense paid; (ii) cash income taxes paid; (iii) maintenance capital expenditures paid; and (iv) equity earnings from the LNG Interest; plus (v) cash distributions from the LNG Interest.

The GAAP measures most directly comparable to Distributable Cash Flow is cash flows from operating activities. Distributable Cash Flow should not be considered as an alternative to cash flows from operating activities. You should not consider Distributable Cash Flow in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Distributable Cash Flow may be defined differently by other companies in our industry, our definition of Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

3338

The following table presents a reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow to cash flows from operating activities for each of the periods indicated (in thousands):

	Three Months Ended						~~Six~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2017			2016			2017			2016
Net income attributable to partners' capital	$	~~3,228~~144		$	4,~~850~~132		$	5,~~691~~835		$	812,~~081~~212
Income taxes		-55			2449			3186			51101
Interest expense		23,~~870~~132			2,~~386~~481			58,~~524~~656			47,~~753~~234
Depreciation (a)		4,~~007~~143			3,~~265~~512			712,~~985~~128			69,~~466~~979
Amortization (a)		32,~~005~~980			3,055			69,~~061~~041			69,~~136~~192
One-time non-recurring expenses (b)		-			42			-			601
Loss on disposal of property and equipment (a)		891			-			891			-
Non-cash unit-based compensation		529			1,207			1,368			2,294
One-time non-recurring expenses (b)		2,437			15			2,437			616
Non-cash loss (gain) on revaluation of contingent consideration, net (a)(c)		368			(395	)		558			(509	)
Non-cash unit-based compensation		518			1,233			1,886			3,528
Non-cash deferred rent expense (d)		65			65			131			131
Non-cash loss (gain) on revaluation of contingent consideration, net (a)(c)		320			326			879			(183	)
Adjusted EBITDA	$	14,072		$	14,499		$	27,349		$	28,004
Non-cash deferred rent expense (d)		65			65			196			196
Cash interest expense		(2,452	)		(2,182	)		(4,725	)		(4,320	)
Adjusted EBITDA	$	14,685		$	14,868		$	42,035		$	42,875
Cash income taxes		-			(24	)		(31	)		(51	)
Cash interest expense		(2,665	)		(2,280	)		(7,390	)		(6,601	)
Maintenance capital expenditures		(853	)		(2,296	)		(1,949	)		(4,402	)
Cash income taxes		(55	)		(49	)		(86	)		(100	)
Equity earnings from the LNG Interest		(2,441	)		(2,466	)		(4,812	)		(4,927	)
Maintenance capital expenditures		(1,366	)		(2,583	)		(3,314	)		(6,985	)
Cash distributions received from the LNG Interest		2,374			2,581			4,026			4,759
Equity earnings from the LNG Interest		(2,431	)		(2,512	)		(7,243	)		(7,439	)
Distributable Cash Flow	$	10,700		$	10,112		$	19,858		$	19,063
Cash distributions received from the LNG Interest		2,064			2,560			6,090			7,319
Maintenance capital expenditures		853			2,296			1,949			4,402
Distributable Cash Flow	$	10,232		$	10,004		$	30,092		$	29,069
Distributable cash flow attributable to non-controlling interests		2,408			2,627			4,831			5,355
Maintenance capital expenditures		1,366			2,583			3,314			6,985
Changes in operating assets and liabilities		(667	)		(255	)		(1,885	)		(1,106	)
Distributable cash flow attributable to non-controlling interests		2,093			2,737			6,924			8,770
One-time non-recurring expenses (b)		-			(42	)		-			(601	)
Changes in operating assets and liabilities		1,601			11			(285	)		(1,095	)
Other non-cash adjustments		157			369			242			516
One-time non-recurring expenses (b)		(2,437	)		(15	)		(2,437	)		(616	)
Net cash provided by operating activities	$	13,451		$	15,107		$	24,995		$	27,629
Other non-cash adjustments		693			352			937			189
Net cash provided by operating activities	$	13,548		$	15,672		$	38,545		$	43,302

(a) The revaluation of contingent consideration, loss on disposal of property and equipment, depreciation and amortization have been adjusted to remove the non-controlling interest portion related to the GE ~~Energy Financial Services (“GE~~ EFS”) affiliate’s ownership interest in Joliet Holdings.

(b)

The one-time non-recurring expenses relate to amounts incurred as due diligence expenses from acquisitions and other infrequent or unusual expenses incurred.

(c)

The non-cash loss on revaluation of contingent consideration is related to the earn-out obligations incurred as a part of the Joliet terminal acquisition.

(d) The non-cash deferred rent expense relates to the accounting treatment for the Portland terminal lease transaction termination fees.

Results of Operations

The following table and discussion is a summary of our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 (in thousands, except operating data):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Revenues:
Third-party customers	$	25,113		$	22,619		$	49,561		$	45,202
Related parties		1,474			3,625			2,951			7,108
		26,587			26,244			52,512			52,310
Expenses:
Operating expenses		8,873			8,228			17,746			16,914
Selling, general and administrative		2,712			3,103			5,951			7,026
Selling, general and administrative - affiliate		1,311			1,302			2,573			2,624
Depreciation		4,486			3,720			8,942			7,372
Amortization		3,589			3,672			7,261			7,370
(Gain) Loss on revaluation of contingent consideration, net		613			(659	)		931			(848	)
Total expenses		21,584			19,366			43,404			40,458
Operating (loss) income		5,003			6,878			9,108			11,852
Other income (expense):
Equity earnings from unconsolidated affiliate		2,441			2,466			4,812			4,927
Interest expense		(2,870	)		(2,386	)		(5,524	)		(4,753	)
Total other income, net		(429	)		80			(712	)		174
Income before income taxes		4,574			6,958			8,396			12,026
Income taxes		-			24			31			51
Net income		4,574			6,934			8,365			11,975
Net income attributable to non-controlling interests		(1,346	)		(2,084	)		(2,674	)		(3,894	)
Net income attributable to partners' capital	$	3,228		$	4,850		$	5,691		$	8,081
Other Financial Data:
Adjusted EBITDA	$	14,072		$	14,499		$	27,349		$	28,004
Distributable Cash Flow	$	10,700		$	10,112		$	19,858		$	19,063
Operating Data:
Storage capacity (bbls)		7,842,600			7,741,100			7,842,600			7,741,100
Throughput (bpd)		174,418			162,480			166,988			153,778
% Take or pay revenue		82	%		84	%		82	%		85	%

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

Storage Capacity. Storage capacity for the three months ended June 30, 2017 increased by 101,500 barrels, or 1%, compared to the three months ended June 30, 2016. The increase in storage capacity is related to the completion of the third 100,000 barrel tank at the Pawnee terminal and the completion of three new 500 barrel bio-diesel tanks at our Altoona, Dupont and Mechanicsburg terminals.

Throughput Activity. The following table details the types and amounts of throughput generated during the three months ended June 30, 2017 and 2016 (in thousands of barrels per day, except percentages):

	Three Months Ended
	June 30,
	2017		2016		Change in bpd		% Change
Asphalts and industrial products		20,204		18,485		1,719		9	%
Crude oil		76,238		75,237		1,001		1	%
Distillates		28,055		25,450		2,605		10	%
Gasoline		49,921		43,308		6,613		15	%
Total		174,418		162,480		11,938		7	%

Throughput activity for the three months ended June 30, 2017 increased by 11.9 mbpd or 7% compared to the three months ended June 30, 2016.

The 1.7 mbpd or 9% increase in asphalt and industrial products throughput is related to an increase in existing customer activity at our Blakeley and Mobile terminals, and new customer activity at our Blakeley and Chickasaw terminals offset by customer non-renewals and reduced activity at our Blakeley, Chickasaw and Mobile terminals.

The 1.0 mbpd or 1% increase in crude oil throughput is the result of an increase of 11.3 mbpd of throughput at our Joliet terminal offset by a decrease of 10.3 mbpd of throughput at our Pawnee and Portland terminals.

The 2.6 mbpd or 10% increase in distillates throughput is the result of (i) a 3.0 mbpd increase of throughput associated with recently executed new customer agreements at our Chickasaw, Cleveland, Toledo and Pennsylvania terminals; (ii) a net increase in existing customer activity of 4.1 mbpd at our Baltimore, Chickasaw, Cleveland, Madison, Selma and the Pennsylvania terminals; and (iii) a 7.4 mbpd increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by an 8.6 mbpd of reduced customer activity at our Mobile, Norfolk, Portland, Spartanburg and Toledo terminals and a 2.5 mbpd decrease related to amending existing agreements and customer non-renewals of short-term agreements in the Gulf Coast and at the Pennsylvania terminals.

The 6.6 mbpd or 15% increase in gasoline throughput is the result of (i) a 1.5 mbpd of increased throughput associated with recently executed agreements at our Baltimore terminal; (ii) a net increase in existing commercial activity of 7.5 mbpd at our Altoona, Cleveland, Madison, Mechanicsburg, Norfolk, Selma and Toledo terminals; and (iii) a 2.4 mbpd increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by a net reduction in customer activity of 2.1 mbpd at our Altoona, Brooklyn, Dupont, Norfolk, Selma, Toledo and Williamsport terminals and a 2.7 mbpd decrease related to amending existing agreements at the Pennsylvania terminals.

Revenues. The following table details the types and amounts of revenues generated during the three months ended June 30, 2017 and 2016 (in thousands, except percentages).

	Three Months Ended
	June 30,
	2017		2016		$ Change			% Change
Minimum storage & throughput services fees	$	21,495	$	21,806	$	(311	)		-1	%
Excess throughput & handling fees		3,559		2,995		564			19	%
Total storage & throughput services fees	$	25,054	$	24,801	$	253			1	%
Ancillary services fees		1,533		1,443		90			6	%
Total revenues	$	26,587	$	26,244	$	343			1	%

Revenues for the quarter ended June 30, 2017 increased by $0.3 million, or 1%, compared to the quarter ended June 30, 2016. Total storage and throughput services fees increased by $0.3 million, or 1%, compared to the three months ended June 30, 2016. Minimum storage and throughput services fees decreased by $0.3 million, or 1%, as compared to the same period in 2016, due to the following:

• Increase of $0.8 million related to the execution of new customer agreements or the execution of new agreements with existing customers at our Altoona, Blakeley, Brooklyn, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile and Toledo terminals;

• Increase of $0.6 million from customers who increased their long-term and short-term storage capacity requirements or whose contracts included automatic step-up provisions at our Blakeley, Brooklyn, Chickasaw, Cleveland, Joliet, Madison, Pawnee and Toledo terminals;

• Decrease of $1.0 million from customer non-renewals at our Brooklyn, Norfolk and Selma terminals and taking tanks out of service for inspections and repairs at our Blakeley and Chickasaw terminals; we then recontracted the majority of this capacity to new or existing customers under long-term agreements, and the revenue will commence upon the completion of tank inspections and infrastructure upgrades; and

• Decrease of $0.8 million from customers who reduced their short-term storage capacity needs and/or reduced their total minimum take-or-pay volume requirements or rates at our Altoona, Baltimore, Dupont, Mechanicsburg, Mobile, Norfolk, Portland and Williamsport terminals.

Excess throughput and handling fees increased by $0.6 million, or 19%, as compared to the same period in 2016, due to the following:

• Increase of $0.4 million from the execution of new customer agreements or agreements with existing customers at terminals in our network including at our Altoona, Baltimore, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile, Selma, Toledo and Williamsport terminals;

• Increase of $0.6 million from incremental existing customer throughput and handling fees at our Baltimore, Blakeley, Cleveland, Madison, Mechanicsburg, Mobile, Pawnee, Selma and Toledo terminals;

• Increase of less than $0.1 million from either contract amendments or contractual rate adjustments at our Altoona, Baltimore, Dupont, Mechanicsburg, Selma, Toledo and Williamsport terminals;

• Decrease of $0.1 million from customer non-renewals at our Baltimore, Blakeley, Chickasaw and Norfolk terminals; and

• Decrease of $0.5 million from reduced customer activity or contract amendments resulting in reduced activity at our Altoona, Blakeley, Brooklyn, Chickasaw, Dupont, Joliet, Mobile, Mobile-Methanol, Norfolk, Spartanburg, Toledo and Williamsport terminals.

Ancillary services fees increased by $0.1 million, or 6%, as compared to the same period in 2016, due to the following:

• Increase of less than $0.1 million from services provided for new customer agreements or agreements with existing customers at our Blakeley, Chickasaw and Mobile terminals;

• Increase of $0.3 million from the services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services in our Brooklyn, Joliet, Mobile and Norfolk terminals;

• Decrease of $0.2 million from services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services at our Baltimore, Blakeley, Chickasaw, Cleveland, Mobile-Methanol, Pawnee, Portland, Selma and Toledo terminals; and

• Decrease of less than $0.1 million from services provided to customers at our Blakeley, Chickasaw and Mobile terminals for customers who elected not to renew their existing agreements.

Operating Expenses. Operating expenses for the three months ended June 30, 2017 increased by $0.6 million, or 8%, compared to the three months ended June 30, 2016. The increase was related to: (i) $0.1 million attributable to higher expenses incurred as result of increased throughput activity, including additive, utility and supply expenses; (ii) $0.1 million related to an increase in repair and maintenance expense; (iii) $0.1 million due to an increase in contract labor in support of customer activities at the Joliet terminal; (iv) an increase in property taxes of $0.4 million; and (v) a less than $0.1 million related to increased compliance expenses. The increase in operating expenses was partially offset by reduced payroll expenses of $0.1 million.

Selling, General and Administrative Expenses. SG&A expenses for the three months ended June 30, 2017 decreased by $0.4 million, or 9%, compared to the three months ended June 30, 2016. The decrease in SG&A expenses was related to a less than $0.1 million decrease in professional fees, a less than $0.1 million decrease in due diligence related expenses and a $0.3 million decrease related to a reduction in stock based compensation expenses.

Depreciation and Amortization Expense. Depreciation expense for the three months ended June 30, 2017 increased by $0.8 million, or 21%, compared to the three months ended June 30, 2017, primarily due to the impact of the expansion projects at our Pennsylvania terminals which were acquired in 2016, customer expansion activities and incremental maintenance projects. Amortization expense for the three months ended June 30, 2017 decreased $0.1 million, or 2%, compared to the three months ended June 30, 2016, primarily due to an intangible asset related to the Mobile terminal acquisition becoming fully amortized in the first quarter of 2016.

Equity Earnings from Unconsolidated Affiliate. Equity earnings from unconsolidated affiliate for the three months ended June 30, 2017 decreased by less than $0.1 million compared to the three months ended June 30, 2016. This decrease is attributable to the increase in legal fees at Gulf LNG related to the on-going Eni USA arbitration.

Interest Expense. Interest expense for the three months ended June 30, 2017 increased by $0.5 million, or 20%, compared to the three months ended June 30, 2016. The increase in interest expense was the result of higher outstanding indebtedness and interest rates during the three months ended June 30, 2017 compared to the three months ended June 30, 2016. The increase in indebtedness was primarily related to the amounts drawn from our credit facility to fund expansion capital projects.

Net Income. Net income for the three months ended June 30, 2017 decreased by $2.4 million, or 34%, compared to the three months ended June 30, 2016. The decrease was primarily related to: (i) a $0.6 million increase in operating expenses primarily related to an increase in property taxes and increased throughput related activity; (ii) a $0.8 million increase in depreciation expense related to the depreciation of our recent capital expenditures; (iii) a $1.3 million increase on the revaluation of the contingent consideration; and (iv) a $0.5 million increase in interest expense due to higher outstanding indebtedness and an increase in interest rates. These decreases to net income were partially offset by a decrease in SG&A expense principally attributable to a decrease in professional fees, due diligence expense and employee compensation expense of $0.4 million and an increase in revenue of $0.3 million.

Adjusted EBITDA. Adjusted EBITDA for the three months ended June 30, 2017 decreased by $0.4 million, or 3%, compared to the three months ended June 30, 2016. The decrease in Adjusted EBITDA for the three months ended June 30, 2017 was primarily attributable to an increase in operating expenses and a reduction in the income from our investment in Gulf LNG offset by reduced SG&A expense.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Storage Capacity. Storage capacity for the six months ended June 30, 2017 increased by 101,500 barrels, or 1%, compared to the six months ended June 30, 2016. The increase in storage capacity is related to the completion of the third 100,000 barrel tank at the Pawnee terminal and the completion of three new 500 barrel bio-diesel tanks at our Altoona, Dupont and Mechanicsburg terminals.

Throughput Activity. The following table details the types and amounts of throughput generated during the six months ended June 30, 2017 and 2016 (in thousands of barrels per day, except percentages):

	Six Months Ended
	June 30,
	2017		2016		Change in bpd		% Change
Asphalts and industrial products		18,772		16,468		2,304		14	%
Crude oil		72,994		72,716		278		0	%
Distillates		26,141		22,311		3,830		17	%
Gasoline		49,081		42,283		6,798		16	%
Total		166,988		153,778		13,210		9	%

Throughput activity for the six months ended June 30, 2017 increased by 13.2 mbpd, or 9%, compared to the six months ended June 30, 2016.

The 2.3 mbpd, or 14%, increase in asphalt and industrial products throughput is related to a net increase in existing customer activity and new customer additions in the Gulf Coast.

The 0.3 mbpd, or less than 1%, increase in crude oil throughput is the result of a decrease of 16.9 mbpd of throughput at our Pawnee and Portland terminals offset by an increase of 17.2 mbpd of throughput at our Joliet terminal.

The 3.8 mbpd, or 17%, increase in distillates throughput is the result of (i) a 2.8 mbpd of increased throughput associated with recently executed agreements at our Altoona, Chickasaw, Cleveland, Dupont, Mechanicsburg and Toledo terminals; (ii) a net increase in existing customer activity of 4.8 mbpd at our Altoona, Baltimore, Chickasaw, Dupont, Mechanicsburg, Selma and Williamsport terminals; and (iii) a 5.7 mbpd of increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by a 6.1 mbpd decrease in customer activity at our Cleveland, Madison, Mobile, Norfolk, Mobile, Portland and Toledo terminals and a 3.6 mbpd decrease related to amending existing agreements and customer non-renewals of short-term agreements at our Altoona, Blakeley, Chickasaw, Dupont, Mechanicsburg, Norfolk and Selma terminals..

The 6.8 mbpd, or 16%, increase in gasoline throughput is the result of (i) a 0.1 mbpd of increased throughput associated with recently executed agreements at our Mechanicsburg terminal; (ii) a net increase in existing commercial activity of 7.0 mbpd at our Altoona, Cleveland, Madison, Mechanicsburg, Norfolk, Portland, Selma and Toledo terminals; and (iii) a 2.9 mbpd increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by a net reduction in customer activity of 0.6 mbpd at our Baltimore, Brooklyn and Williamsport terminals and a 2.5 mbpd decrease related to amending existing agreements at our Altoona, Dupont and Mechanicsburg terminals.

Revenues. The following table details the types and amounts of revenues generated during the six months ended June 30, 2017 and 2016 (in thousands, except percentages).

	Six Months Ended
	June 30,
	2017		2016		$ Change			% Change
Minimum storage & throughput services fees	$	42,414	$	43,824	$	(1,410	)		-3	%
Excess throughput & handling fees		6,876		5,650		1,226			22	%
Total storage & throughput services fees	$	49,290	$	49,474	$	(184	)		0	%
Ancillary services fees		3,222		2,836		386			14	%
Total revenues	$	52,512	$	52,310	$	202			0	%

Revenues for the six months ended June 30, 2017 increased by $0.2 million, or less than 1%, compared to the six months ended June 30, 2016. Total storage and throughput services fees decreased by $0.2 million, or less than 1%, compared to the six months ended June 30, 2016. Minimum storage and throughput services fees decreased by $1.4 million, or 3%, as compared to the same period in 2016, due to the following:

• Increase of $1.0 million related to the execution of new customer agreements or the execution of new agreements with existing customers at our Altoona, Blakeley, Brooklyn, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile and Toledo terminals;

• Increase of $1.3 million from customers who increased their long-term and short-term storage capacity requirements or whose contracts included automatic step-up provisions at our Blakeley, Brooklyn, Chickasaw, Cleveland, Joliet, Madison, Pawnee and Toledo terminals;

• Decrease of $1.7 million from customer non-renewals at our Blakeley, Brooklyn, Chickasaw, Norfolk and Selma terminals; we then recontracted the majority of this capacity to new or existing customers under long-term agreements, and the revenue will commence upon the completion of tank inspections and infrastructure upgrades; and

• Decrease of $2.0 million from customers who reduced their short-term storage capacity needs and/or reduced their total minimum take-or-pay volume requirements or rates at our Altoona, Baltimore, Dupont, Mechanicsburg, Mobile, Norfolk, Portland, Selma and Williamsport terminals.

Excess throughput and handling fees increased by $1.2 million, or 22%, as compared to the same period in 2016, due to the following:

• Increase of $0.7 million from the execution of new customer agreements or agreements with existing customers at other terminals in our network including at our Altoona, Baltimore, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile, Selma, Toledo and Williamsport terminals;

• Increase of $1.1 million from incremental existing customer throughput and handling fees at our Baltimore, Blakeley, Cleveland, Madison, Mechanicsburg, Norfolk, Pawnee and Selma terminals;

• Increase of $0.1 million from either contract amendments or contractual rate adjustments in Altoona, Baltimore, Dupont, Selma, Toledo and Williamsport terminals;

• Decrease of $0.2 million from customer non-renewals at our Baltimore, Blakeley, Chickasaw, Norfolk and Selma terminals; and

• Decrease of less than $0.6 million from reduced customer activity or contract amendments resulting in reduced activity in Altoona, Blakeley, Brooklyn, Chickasaw, Dupont, Joliet, Mobile, Mobile-Methanol, Mechanicsburg, Norfolk, Spartanburg, Toledo and Williamsport terminals.

Ancillary services fees increased by $0.4 million, or 14%, as compared to the same period in 2016, due to the following:

• Increase of less than $0.1 million from services provided pursuant to new customer agreements or agreements with existing customers at our Blakeley, Chickasaw and Mobile terminals;

• Increase of $0.9 million from the services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services in our Brooklyn, Cleveland, Dupont, Joliet, Mechanicsburg, Mobile, Norfolk, Selma and Spartanburg terminals;

• Decrease of $0.4 million from services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services in our Baltimore, Blakeley, Chickasaw, Pawnee, Portland, and Toledo terminals; and

• Decrease of less than $0.2 million from services provided to customers at our Blakeley, Chickasaw, Joliet and Mobile terminals for customers who elected not to renew existing agreements.

Operating Expenses. Operating expenses for the six months ended June 30, 2017 increased by $0.8 million, or 5%, compared to the six months ended June 30, 2016. The increase was related to: (i) $0.2 million attributable to expenses incurred as result of increased throughput activity including additive, utility and supply expenses; (ii) $0.1 million related to an increase in repair and maintenance expense; (iii) $0.3 million due to an increase in contract labor in support of customer activities at the Joliet terminal; (iv) an increase in property taxes of $0.3 million; and (v) $0.1 million related to increased compliance expense. The increase in operating expenses was offset by reduced payroll expenses of less than $0.2 million due to a realignment and optimization of our workforce and a reduction in our insurance premiums of less $0.1 million.

Selling, General and Administrative Expenses. SG&A expenses for the six months ended June 30, 2017 decreased by $1.1 million, or 12%, compared to the six months ended June 30, 2016. The decrease in SG&A expenses was related to a $0.3 million decrease in professional fees, a $0.3 million decrease of due diligence related expenses and a $0.5 million reduction in stock based compensation expenses.

Depreciation and Amortization Expense. Depreciation expense for the six months ended June 30, 2017 increased by $1.6 million, or 21%, compared to the six months ended June 30, 2016, primarily due to the impact of the expansion projects at our Pennsylvania terminals which were acquired in 2016, customer expansion activities and incremental maintenance projects. Amortization expense for the six months ended June 30, 2017 decreased by $0.1 million, or 1%, compared to the six months ended June 30, 2016, primarily due to an intangible asset related to the Mobile terminal acquisition becoming fully amortized in the first quarter of 2016.

Equity Earnings from Unconsolidated Affiliate. Equity earnings from unconsolidated affiliate for the six months ended June 30, 2017 decreased by $0.1 million compared to the six months ended June 30, 2016. This decrease is attributable to the increase in legal fees at Gulf LNG related to the on-going Eni USA arbitration.

Interest Expense. Interest expense for the six months ended June 30, 2017 increased by $0.8 million, or 16%, compared to the six months ended June 30, 2016. The increase in interest expense was the result of higher outstanding indebtedness and interest rates during the six months ended June 30, 2017 compared to the six months ended June 30, 2016. The increase in indebtedness was primarily related to the amounts drawn from our credit facility to fund expansion capital projects.

Net Income. Net income for the six months ended June 30, 2017 decreased by $3.6 million, or 30%, compared to the six months ended June 30, 2016. The decrease was primarily related to: (i) a $0.8 million increase in operating expenses primarily related to an increase in property taxes and increased throughput related activity, (ii) a $1.6 million increase in depreciation expense related to the depreciation of our recent capital expenditures, (iii) a $1.8 million increase on the revaluation of the contingent consideration, and (iv) a $0.8 million increase in interest expense due to higher outstanding indebtedness and an increase in interest rates. These decreases to net income were partially offset by a decrease in SG&A expense principally attributable to a decrease in professional fees, due diligence expense and employee compensation expense of $1.1 million.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenues:
Third-party customers	$	25,859		$	22,933		$	75,420		$	68,136
Related parties		1,431			3,739			4,382			10,847
		27,290			26,672			79,802			78,983
Expenses:
Operating expenses		8,848			8,192			26,595			25,107
Selling, general and administrative		4,999			3,141			10,950			10,168
Selling, general and administrative - affiliate		1,368			1,342			3,941			3,965
Depreciation		4,623			3,972			13,565			11,345
Amortization		3,547			3,672			10,808			11,042
(Gain) Loss on revaluation of contingent consideration, net		534			545			1,465			(303	)
Total expenses		23,919			20,864			67,324			61,324
Operating (loss) income		3,371			5,808			12,478			17,659
Other income (expense):
Equity earnings from unconsolidated affiliate		2,431			2,512			7,243			7,439
Gain (Loss) on disposal of property and equipment		(1,484	)		-			(1,484	)		-
Other income		60			1			60			2
Interest expense		(3,132	)		(2,481	)		(8,656	)		(7,234	)
Total other income (expense)		(2,125	)		32			(2,837	)		207
Income before income taxes		1,246			5,840			9,641			17,866
Income taxes		55			49			86			101
Net income		1,191			5,791			9,555			17,765
Net income attributable to non-controlling interests		(1,047	)		(1,659	)		(3,720	)		(5,553	)
Net income attributable to partners' capital	$	144		$	4,132		$	5,835		$	12,212
Other Financial Data:
Adjusted EBITDA	$	14,685		$	14,868		$	42,035		$	42,875
Distributable Cash Flow	$	10,232		$	10,004		$	30,092		$	29,069
Operating Data:
Storage capacity (bbls)		7,842,600			7,841,100			7,842,600			7,841,100
Throughput (bpd)		181,387			171,170			171,841			159,689
% Take or pay revenue		81	%		84	%		81	%		85	%

~~Adjusted~~Three ~~EBITDA.~~Months ~~Adjusted~~Ended ~~EBITDA~~September ~~for the six months ended June~~ 30, 2017 ~~decreased~~Compared ~~by $0.7 million, or 2%, compared~~ to ~~the~~Three ~~six~~Months ~~months~~Ended ~~ended~~September ~~June~~ 30, 2016. The decrease in Adjusted EBITDA for the six months ended June 30, 2017 was primarily attributable to an increase in operating expenses and a reduction in the income from our investment in Gulf LNG offset by reduced SG&A expense.

Storage Capacity. Storage capacity for the three months ended September 30, 2017 increased by 1,500 barrels compared to the three months ended September 30, 2016. The increase in storage capacity is related to the completion of three new 500-barrel bio-diesel tanks at our Altoona, Dupont and Mechanicsburg terminals.

Throughput Activity. The following table details the types and amounts of throughput generated during the three months ended September 30, 2017 and 2016 (in thousands of barrels per day, except percentages):

	Three Months Ended
	September 30,
	2017		2016		Change in bpd			% Change
Asphalts and industrial products		17,570		14,879		2,691			18	%
Crude oil		87,379		87,877		(498	)		-1	%
Distillates		26,423		19,717		6,706			34	%
Gasoline		50,015		48,697		1,318			3	%
Total		181,387		171,170		10,217			6	%

Throughput activity for the three months ended September 30, 2017 increased by 10.2 mbpd, or 6%, compared to the three months ended September 30, 2016.

The 2.7 mbpd, or 18%, increase in asphalt and industrial products throughput is related to an increase in existing customer activity at our Mobile and Mobile-Methanol terminals, and new customer activity at our Blakeley and Chickasaw terminals offset by customer non-renewals and reduced activity at our Blakeley and Chickasaw terminals.

The 0.5 mbpd, or 1%, decrease in crude oil throughput is the result of a decrease of 6.2 mbpd of throughput at our Pawnee terminal offset by an increase of 5.7 mbpd of throughput at our Joliet terminal.

The 6.7 mbpd, or 34%, increase in distillates throughput is the result of (i) a 3.6 mbpd increase of throughput associated with recently executed new customer agreements at our Altoona, Baltimore, Chickasaw, Cleveland, Dupont, Mechanicsburg, Norfolk, Selma and Toledo terminals; (ii) an increase in existing customer activity of 4.1 mbpd at our Altoona, Chickasaw, Cleveland, Madison, Mechanicsburg, Norfolk, Spartanburg and Williamsport terminals; and (iii) a 3.7 mbpd increase from existing customers executing new or amending existing agreements to throughput product at our Baltimore, Mobile, Norfolk, Selma and Pennsylvania terminals partially offset by a 4.7 mbpd decrease related to customer non-renewals or reduced customer activity at our Baltimore, Dupont, Gulf Coast, Selma and Toledo terminals.

The 1.3 mbpd, or 3%, increase in gasoline throughput is the result of (i) a 0.1 mbpd of increased throughput associated with a recently executed agreement at our Selma terminal; (ii) an increase in existing commercial activity of 5.6 mbpd at our Baltimore, Cleveland, Madison, Mechanicsburg, Portland, and Toledo terminals; and (iii) a 3.8 mbpd increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by an 8.2 mbpd decrease related to customer non-renewals or reduced customer activity at our Altoona, Brooklyn, Dupont, Norfolk, Selma, Spartanburg and Williamsport terminals.

Revenues. The following table details the types and amounts of revenues generated during the three months ended September 30, 2017 and 2016 (in thousands, except percentages).

	Three Months Ended
	September 30,
	2017		2016		$ Change			% Change
Minimum storage & throughput services fees	$	21,848	$	21,908	$	(60	)		0	%
Excess throughput & handling fees		3,641		3,299		342			10	%
Total storage & throughput services fees	$	25,489	$	25,207	$	282			1	%
Ancillary services fees		1,801		1,465		336			23	%
Total revenues	$	27,290	$	26,672	$	618			2	%

Revenues for the quarter ended September 30, 2017 increased by $0.6 million, or 2%, compared to the quarter ended September 30, 2016. Total storage and throughput services fees increased by $0.3 million, or 1%, compared to the three months ended September 30, 2016. Minimum storage and throughput services fees decreased by less than $0.1 million, as compared to the same period in 2016, due to the following:

•

Increase of $1.0 million related to the execution of new customer agreements or the execution of new agreements with existing customers at our Altoona, Blakeley, Chickasaw, Cleveland, Mechanicsburg, Mobile and Toledo terminals;

•

Increase of $0.6 million from customers who increased their long-term and short-term storage capacity requirements or whose contracts included automatic step-up provisions at our Chickasaw, Cleveland, Joliet, Mobile, Mobile – Methanol, Norfolk, Pawnee and Toledo terminals;

•

Decrease of $1.0 million from customer non-renewals at our Blakeley, Brooklyn, Chickasaw and Cleveland terminals and taking tanks out of service for inspections and repairs at our Blakeley and Chickasaw terminals; we then re-contracted the majority of this capacity to new or existing customers under long-term agreements, and the revenue will commence upon the completion of tank inspections and infrastructure upgrades; and

•

Decrease of $0.6 million from customers who reduced their short-term storage capacity needs and/or reduced their total minimum take-or-pay volume requirements or rates at our Altoona, Blakeley Baltimore, Brooklyn, Dupont, Madison, Mechanicsburg, Mobile, Pawnee, Portland, Selma, Spartanburg, Toledo and Williamsport terminals.

Excess throughput and handling fees increased by $0.3 million, or 10%, as compared to the same period in 2016, due to the following:

•

Increase of $0.4 million from the execution of new customer agreements or agreements with existing customers at terminals in our network including our Altoona, Baltimore, Blakeley, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile, Norfolk, Pawnee, Selma, Toledo and Williamsport terminals;

•

Increase of $0.7 million from incremental existing customer throughput and handling fees at our Chickasaw, Cleveland, Joliet, Madison, Mechanicsburg, Mobile, Mobile-Methanol, Toledo and Williamsport terminals;

•

Increase of less than $0.1 million from either contract amendments or contractual rate adjustments at our Altoona, Baltimore, Dupont, Mechanicsburg and Williamsport terminals;

•

Decrease of $0.5 million from customer non-renewals at our Blakeley, Brooklyn, Chickasaw and Joliet terminals; and

•

Decrease of $0.3 million from reduced customer activity or contract amendments resulting in reduced activity at our Altoona, Baltimore, Blakeley, Brooklyn, Dupont, Norfolk, Selma, Pawnee and Spartanburg terminals.

Ancillary services fees increased by $0.3 million, or 23%, as compared to the same period in 2016, due to the following:

•

Increase of less than $0.1 million from services provided for new customer agreements or agreements with existing customers at our Blakeley, Mechanicsburg and Mobile terminals;

•

Increase of $0.6 million from the services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services in our Baltimore, Brooklyn, Dupont, Joliet, Madison, Mechanicsburg, Mobile, Mobile-Methanol, Norfolk, Portland, Selma, Toledo and Williamsport terminals;

•

Decrease of $0.3 million from services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services at our Altoona, Brooklyn, Chickasaw, Cleveland, Mechanicsburg, Pawnee, Selma, Spartanburg and Toledo terminals; and

•

Decrease of less than $0.1 million from services provided to customers at our Blakeley and Chickasaw terminals for customers who elected not to renew their existing agreements.

Operating Expenses. Operating expenses for the three months ended September 30, 2017 increased by $0.7 million, or 8%, compared to the three months ended September 30, 2016. The increase was related to: (i) $0.1 million attributable to higher expenses incurred as result of increased throughput activity, including additive, contract labor, utility and supply expenses; (ii) $0.5 million related to an increase in repair and maintenance expense; and (iii) an increase in property taxes of $0.3 million. The increase in operating expenses was partially offset by reduced insurance expense of $0.2 million.

Selling, General and Administrative Expenses. SG&A expenses for the three months ended September 30, 2017 increased by $1.9 million, or 42%, compared to the three months ended September 30, 2016. The increase in SG&A expenses was related to a $2.4 million increase in due diligence and transaction related expenses associated with the transactions contemplated by the Merger Agreement offset by a $0.5 million decrease related to a reduction in unit based compensation expenses due to some phantom units becoming fully vested in July 2017 and November 2016.

Depreciation and Amortization Expense. Depreciation expense for the three months ended September 30, 2017 increased by $0.7 million, or 16%, compared to the three months ended September 30, 2016, primarily due to the impact of the expansion projects at our Pennsylvania terminals which were acquired in 2016, customer expansion activities and incremental maintenance projects. Amortization expense for the three months ended September 30, 2017 decreased $0.1 million, or 3%, compared to the three months ended September 30, 2016, primarily due to an intangible asset related to the Mobile terminal acquisition becoming fully amortized in the first quarter of 2016.

Equity Earnings from Unconsolidated Affiliate. Equity earnings from unconsolidated affiliate for the three months ended September 30, 2017 decreased by $0.1 million compared to the three months ended September 30, 2016. This decrease is attributable to the increase in legal fees at Gulf LNG related to the on-going Eni USA arbitration.

Interest Expense. Interest expense for the three months ended September 30, 2017 increased by $0.7 million, or 26%, compared to the three months ended September 30, 2016. The increase in interest expense was the result of higher outstanding indebtedness and interest rates during the three months ended September 30, 2017 compared to the three months ended September 30, 2016. The increase in indebtedness was primarily related to the amounts drawn from our credit facility to fund expansion capital projects.

Net Income. Net income for the three months ended September 30, 2017 decreased by $4.6 million, or 79%, compared to the three months ended September 30, 2016. The decrease was primarily related to: (i) a $0.7 million increase in operating expenses primarily related to an increase in property taxes, repair and maintenance expenses and increased throughput related activity; (ii) a $1.9 million increase in SG&A related to an increase in due diligence and transaction related expenses; (iii) a $0.7 million increase in depreciation expense related to the depreciation of our recent capital expenditures; (iv) a $1.5 million increase in losses related to a disposal of property and equipment at our Joliet terminal; and (v) a $0.7 million increase in interest expense due to higher outstanding indebtedness and an increase in interest rates. These decreases to net income were partially offset by a $0.1 million decrease in amortization expense and a $0.6 million increase in revenue.

Adjusted EBITDA. Adjusted EBITDA for the three months ended September 30, 2017 decreased by $0.2 million, or 1%, compared to the three months ended September 30, 2016. The decrease in Adjusted EBITDA for the three months ended September 30, 2017 was primarily attributable to an increase in operating expenses and a reduction in the income from our investment in Gulf LNG offset by an increase in revenue.

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

Storage Capacity. Storage capacity for the nine months ended September 30, 2017 increased by 1,500 barrels compared to the nine months ended September 30, 2016. The increase in storage capacity is related to the completion of three new 500-barrel bio-diesel tanks at our Altoona, Dupont and Mechanicsburg terminals.

Throughput Activity. The following table details the types and amounts of throughput generated during the nine months ended September 30, 2017 and 2016 (in thousands of barrels per day, except percentages):

	Nine Months Ended
	September 30,
	2017		2016		Change in bpd		% Change
Asphalts and industrial products		18,367		15,935		2,432		15	%
Crude oil		77,842		77,806		36		0	%
Distillates		26,236		21,465		4,771		22	%
Gasoline		49,396		44,483		4,913		11	%
Total		171,841		159,689		12,152		8	%

Throughput activity for the nine months ended September 30, 2017 increased by 12.2 mbpd, or 8%, compared to the nine months ended September 30, 2016.

The 2.4 mbpd, or 15%, increase in asphalt and industrial products throughput is related to a net increase in existing customer activity, contract amendments and the execution of new customer agreements at our Gulf Coast terminals.

The less than 0.1 mbpd increase in crude oil throughput is the result of a decrease of 13.3 mbpd of throughput at our Pawnee and Portland terminals offset by an increase of 13.3 mbpd of throughput at our Joliet terminal.

The 4.8 mbpd, or 22%, increase in distillates throughput is the result of (i) a 3.1 mbpd of increased throughput associated with recently executed agreements at our Altoona, Baltimore, Chickasaw, Cleveland, Dupont, Mechanicsburg, Norfolk, Selma, and Toledo terminals; (ii) a 5.1 mbpd increase in existing customer activity at our Baltimore, Chickasaw, Cleveland, Dupont, Madison, Mechanicsburg, Spartanburg and Williamsport terminals; and (iii) a 3.5 mbpd increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by a 7.0 mbpd decrease in customer non-renewals or reduced customer activity at our Altoona, Blakeley, Chickasaw, Mobile, Norfolk, Portland, Selma and Toledo terminals.

The 4.9 mbpd, or 11%, increase in gasoline throughput is the result of (i) less than 0.1 mbpd of increased throughput associated with recently executed agreements at our Selma terminal; (ii) a 6.7 mbpd increase in existing commercial activity at our Baltimore, Cleveland, Madison, Mechanicsburg, Portland and Toledo terminals; and (iii) a 2.6 mbpd increase from existing customers executing new or amending existing agreements to throughput product in additional terminals within our terminal network partially offset by 4.4 mbpd related to customer non-renewals or reduced activity at our Altoona, Brooklyn, Dupont, Norfolk, Selma, Spartanburg and Williamsport terminals.

Revenues. The following table details the types and amounts of revenues generated during the nine months ended September 30, 2017 and 2016 (in thousands, except percentages).

	Nine Months Ended
	September 30,
	2017		2016		$ Change			% Change
Minimum storage & throughput services fees	$	64,262	$	65,733	$	(1,471	)		-2	%
Excess throughput & handling fees		10,517		8,949		1,568			18	%
Total storage & throughput services fees	$	74,779	$	74,682	$	97			0	%
Ancillary services fees		5,023		4,301		722			17	%
Total revenues	$	79,802	$	78,983	$	819			1	%

Revenues for the nine months ended September 30, 2017 increased by $0.8 million, or 1%, compared to the nine months ended September 30, 2016. Total storage and throughput services fees increased by $0.1 million compared to the nine months ended September 30, 2016. Minimum storage and throughput services fees decreased by $1.5 million, or 2%, as compared to the same period in 2016, due to the following:

•

Increase of $2.1 million related to the execution of new customer agreements or the execution of new agreements with existing customers at our Altoona, Blakeley, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile and Toledo terminals;

•

Increase of $1.7 million from customers who increased their long-term and short-term storage capacity requirements or whose contracts included automatic step-up provisions at our Baltimore, Blakeley, Brooklyn, Cleveland, Joliet, Madison, Mobile, Mobile – Methanol, Pawnee and Toledo terminals;

•

Decrease of $2.7 million from customer non-renewals at our Baltimore, Blakeley, Brooklyn, Chickasaw, Cleveland, Norfolk and Selma terminals; we then re-contracted the majority of the capacity associated with the customer non-renewals in Blakeley and Chickasaw under long-term agreements, and the revenue will commence upon the completion of tank inspections and infrastructure upgrades; and

•

Decrease of $2.5 million from customers who reduced their short-term storage capacity needs and/or reduced their total minimum take-or-pay volume requirements or rates at our Altoona, Baltimore, Brooklyn, Chickasaw, Dupont, Mechanicsburg, Mobile, Mobile – Methanol, Norfolk, Pawnee, Portland, Selma, Spartanburg and Williamsport terminals.

Excess throughput and handling fees increased by $1.6 million, or 18%, as compared to the same period in 2016, due to the following:

•

Increase of $1.0 million from the execution of new customer agreements or agreements with existing customers at other terminals in our network including at our Altoona, Baltimore, Chickasaw, Cleveland, Dupont, Mechanicsburg, Mobile, Norfolk, Selma, Toledo and Williamsport terminals;

•

Increase of $1.6 million from incremental existing customer throughput and handling fees at our Baltimore, Cleveland, Madison, Mechanicsburg, Mobile, Pawnee and Selma terminals;

•

Increase of $0.2 million from either contract amendments or contractual rate adjustments in Altoona, Baltimore, Chickasaw, Dupont, Mechanicsburg and Williamsport terminals;

•

Decrease of $0.3 million from customer non-renewals at our Blakeley, Brooklyn, Chickasaw, Norfolk and Selma terminals; and

•

Decrease of less than $0.9 million from reduced customer activity or contract amendments resulting in reduced activity in Altoona, Blakeley, Brooklyn, Chickasaw, Dupont, Joliet, Mobile-Methanol, Norfolk, Spartanburg, Toledo and Williamsport terminals.

Ancillary services fees increased by $0.7 million, or 17%, as compared to the same period in 2016, due to the following:

•

Increase of less than $0.1 million from services provided pursuant to new customer agreements or agreements with existing customers at our Blakeley, Chickasaw, Mechanicsburg and Mobile terminals;

•

Increase of $1.4 million from the services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services in our Altoona, Baltimore, Brooklyn, Cleveland, Dupont, Joliet, Madison, Mechanicsburg, Mobile, Norfolk, Selma, Spartanburg, Toledo and Williamsport terminals;

•

Decrease of $0.6 million from services provided to our customers including lab fees, natural gas reimbursement, railcar storage, blending and other services in our Altoona, Baltimore, Blakeley, Chickasaw, Cleveland, Joliet, Madison, Mobile-Methanol, Norfolk, Pawnee, Portland, Selma, Spartanburg and Toledo terminals; and

•

Decrease of less than $0.2 million from services provided to customers at our Altoona, Blakeley, Chickasaw, Mechanicsburg and Mobile terminals for customers who elected not to renew existing agreements.

Operating Expenses. Operating expenses for the nine months ended September 30, 2017 increased by $1.5 million, or 6%, compared to the nine months ended September 30, 2016. The increase was related to: (i) $0.3 million attributable to expenses incurred as result of increased throughput activity including additive, utility and supply expenses; (ii) $0.6 million related to an increase in repair and maintenance expense; (iii) $0.3 million due to an increase in contract labor in support of customer activities at the Joliet terminal; and (iv) an increase in property taxes of $0.6 million. The increase in operating expenses was partially offset by reduced payroll expenses of $0.2 million due to a realignment and optimization of our workforce and a reduction in our insurance premiums of $0.2 million.

Selling, General and Administrative Expenses. SG&A expenses for the nine months ended September 30, 2017 increased by $0.8 million, or 5%, compared to the nine months ended September 30, 2016. The increase in SG&A expenses was related to a $2.1 million increase of due diligence related expenses associated with the transactions contemplated by the Merger Agreement partially offset by a $1.5 million reduction in unit based compensation expenses due to some phantom units becoming fully vested in July 2017 and November 2016.

Depreciation and Amortization Expense. Depreciation expense for the nine months ended September 30, 2017 increased by $2.2 million, or 20%, compared to the nine months ended September 30, 2016, primarily due to the impact of the expansion projects at our Pennsylvania terminals which were acquired in 2016, customer expansion activities and incremental maintenance projects. Amortization expense for the nine months ended September 30, 2017 decreased by $0.3 million, or 3%, compared to the nine months

ended September 30, 2016, primarily due to an intangible asset related to the Mobile terminal acquisition becoming fully amortized in the first quarter of 2016.

Equity Earnings from Unconsolidated Affiliate. Equity earnings from unconsolidated affiliate for the nine months ended September 30, 2017 decreased by $0.2 million, or 3%, compared to the nine months ended September 30, 2016. This decrease is attributable to the increase in legal fees at Gulf LNG related to the on-going Eni USA arbitration.

Interest Expense. Interest expense for the nine months ended September 30, 2017 increased by $1.4 million, or 20%, compared to the nine months ended September 30, 2016. The increase in interest expense was the result of higher outstanding indebtedness and interest rates during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. The increase in indebtedness was primarily related to the amounts drawn from our credit facility to fund expansion capital projects.

Net Income. Net income for the nine months ended September 30, 2017 decreased by $8.2 million, or 46%, compared to the nine months ended September 30, 2016. The decrease was primarily related to: (i) a $1.5 million increase in operating expenses primarily related to an increase in property taxes, repairs and maintenance, contract labor and increased throughput related activity, (ii) a $0.8 million increase in SG&A due to an increase in professional fees and due diligence related expenses; (iii) a $2.2 million increase in depreciation expense related to the depreciation of our recent capital expenditures, (iv) a $1.8 million increase on the revaluation of the contingent consideration; (v) a $1.5 million loss on disposal of property and equipment at our Joliet terminal; and (vi) a $1.4 million increase in interest expense due to higher outstanding indebtedness and an increase in interest rates. These decreases to net income were partially offset by a $0.2 million decrease in amortization expenses and a $0.8 million increase in revenue.

Adjusted EBITDA. Adjusted EBITDA for the nine months ended September 30, 2017 decreased by $0.8 million, or 2%, compared to the nine months ended September 30, 2016. The decrease in Adjusted EBITDA for the nine months ended September 30, 2017 was primarily attributable to an increase in operating expenses and a reduction in the income from our investment in Gulf LNG offset by an increase in revenue.

Liquidity and Capital Resources

Liquidity

Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay distributions to our partners. Our sources of liquidity include cash generated by our operations, borrowings under our Second Amended and Restated Revolving Credit Agreement (the “Credit Facility”) and issuances of equity and debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements. Please read “—Cash Flows” and “—Capital Expenditures” for a further discussion of the impact on liquidity.

In ~~July~~October 2017, we declared a quarterly distribution of $0.44 per common unit, which equates to approximately $8.6 million per quarter, or $34.4 million on an annualized basis, based on the number of common units outstanding as of ~~August~~November 2, 2017. The distribution is payable on ~~August~~November 15, 2017 to unitholders of record on ~~August~~November 8, 2017. Maintaining this level of distribution is dependent on our ability to generate sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner and its affiliates. We do not have a legal obligation to pay this distribution.

Our Joliet terminal is currently supported by a terminal services agreement and a pipeline throughput and deficiency agreement with Exxon, each with an initial three-year term that is currently scheduled to expire in May 2018. WeExxon dodid not ~~expect Exxon to~~ exercise in August 2017 its option to renew the agreements on their current terms and conditions. Although Exxon has expressed interest in using the services of the Joliet Terminal past the currently scheduled contract expiry date of May 2018, and we intend to continue discussions with Exxon regarding such services, there can be no assurances that any such arrangement will occur. For more information, please see “—Factors that Impact Our Business—Customers and Competition” discussed above.

We have identified certain deficiencies with the steam and condensate system and the thermal fluid system at our Joliet terminal owned and operated by Joliet Bulk, Barge & Rail LLC (“JBBR”), which is a wholly-owned subsidiary of Joliet Holdings, 40% of which is owned by an affiliate of GE EFS. The steam and condensate system and the thermal fluid system are used by JBBR to unload railcars and maintain the petroleum products at a certain temperature, if necessary, during cold weather operating activities. We believe the identified deficiencies are attributable to the design, engineering and construction of the Joliet terminal. Pursuant to a contract between JBBR and Ragnar Benson LLC (“Ragnar Benson”), Ragnar Benson agreed to provide certain engineering, procurement and construction services in connection with the development and construction of our Joliet terminal (the “Ragnar Benson EPC Contract”). JBBR believes that Ragnar Benson has not reached final completion under the Ragnar Benson EPC Contract due to its failure to comply with its obligations thereunder, and JBBR is pursuing its rights and remedies against Ragnar Benson to remediate, or to reimburse JBBR for the costs of remediating, such deficiencies. We have also investigated the potential liability of Wilson & Company, Inc. Engineers & Architects (“Wilson”), the engineering firm that (along with Ragnar Benson) designed the Joliet terminal. We ~~are~~believe ~~also~~that ~~pursuing~~Wilson ~~our~~breached ~~rights~~its standard of care and ~~remedies~~other ~~against~~obligations ~~Wilson~~with ~~under~~respect to the ~~master~~design ~~services~~and ~~agreement~~engineering ~~between~~of ~~JBBR~~the steam and ~~Wilson. For~~condensate ~~more~~system ~~information,~~and ~~please~~the ~~see~~thermal ~~Part~~fluid ~~II,~~system ~~Item~~under 1.the ~~“Legal~~master ~~Proceedings.”~~ services agreement between Wilson and JBBR, and

we are pursuing our rights and remedies against Wilson pursuant thereto. For more information, please see Part II, Item 1. “Legal Proceedings.”

The Joliet terminal remains operational and is currently unloading unit trains for our customer. We believe that we can implement remediation measures in sufficient time to meet certain performance requirements under our customer contract that are required to be met under certain circumstances during cold weather operations. The costs associated with any such remediation measures could be material. If the remediation measures that are implemented fail to successfully remediate the deficiencies, or if the remediation measures are not implemented in sufficient time for cold weather operations, we may not be able to meet our obligations under our customer contract at the Joliet terminal, and our business, financial condition, results of operations and ability to make distributions to our unitholders could be materially adversely affected.

Credit Facility

Concurrent with the closing of the IPO, we entered into the Credit Facility with a syndicate of lenders, under which Arc Terminals Holdings LLC (“Arc Terminals Holdings”) is the borrower. The Credit Facility, as subsequently amended, matures in November 2018 and has up to $300.0 million of borrowing capacity. As of ~~June~~September 30, 2017, we had borrowings of $~~252~~256.0 million under the Credit Facility at an interest rate of 4.25%. Based on the restrictions under our total leverage ratio covenant, as of September 30, 2017, we had $25.0 million of available capacity under the Credit Facility.

40The Credit Facility is available to fund working capital and to finance capital expenditures and other permitted payments and allows us to request that the maximum amount of the Credit Facility be increased by up to an aggregate principal amount of $100.0 million, subject to receiving increased commitments from lenders or commitments from other financial institutions. The Credit Facility is available for revolving loans, including a sublimit of $5.0 million for swing line loans and a sublimit of $20.0 million for letters of credit. Our obligations under the Credit Facility are secured by a first priority lien on substantially all of our material assets other than the LNG Interest and the assets owned by Joliet Holdings and its subsidiaries. We and each of our existing restricted subsidiaries (other than the borrower) guarantee, and each of our future restricted subsidiaries will also guarantee, the Credit Facility.

the Credit Facility at an interest rate of 4.23%. Based on the restrictions under our total leverage ratio covenant, as of June 30, 2017, we had $29.2 million of available capacity under the Credit Facility.

The Credit Facility is available to fund working capital and to finance capital expenditures and other permitted payments and allows us to request that the maximum amount of the Credit Facility be increased by up to an aggregate principal amount of $100.0 million, subject to receiving increased commitments from lenders or commitments from other financial institutions. The Credit Facility is available for revolving loans, including a sublimit of $5.0 million for swing line loans and a sublimit of $20.0 million for letters of credit. Our obligations under the Credit Facility are secured by a first priority lien on substantially all of our material assets other than the LNG Interest and the assets owned by Arc Terminals Joliet Holdings LLC and its subsidiaries. We and each of our existing restricted subsidiaries (other than the borrower) guarantee, and each of our future restricted subsidiaries will also guarantee, the Credit Facility.

Loans under the Credit Facility bear interest at a floating rate, based upon our total leverage ratio, equal to, at our option, either (a) a base rate plus a range from 100 to 225 basis points per annum or (b) a LIBOR rate, plus a range of 200 to 325 basis points. The base rate is established as the highest of (i) the rate which SunTrust Bank announces, from time to time, as its prime lending rate, (ii) the daily one-month LIBOR rate plus 100 basis points per annum and (iii) the federal funds rate plus 50 basis points per annum. The unused portion of the Credit Facility is subject to a commitment fee calculated based upon our total leverage ratio ranging from 0.375% to 0.50% per annum. Upon any event of default, the interest rate will, upon the request of the lenders holding a majority of the commitments, be increased by 2.0% on overdue amounts per annum for the period during which the event of default exists.

The Credit Facility contains certain customary representations and warranties, affirmative covenants, negative covenants and events of default. As of ~~June~~September 30, 2017, we were in compliance with such covenants. The negative covenants include restrictions on our ability to incur additional indebtedness, acquire and sell assets, create liens, enter into certain lease agreements, make investments and make distributions.

The Credit Facility requires us to maintain a total leverage ratio of not more than 4.50 to 1.00, which may increase to up to 5.00 to 1.00 during specified periods following a material permitted acquisition or issuance of over $200.0 million of senior notes, and a minimum interest coverage ratio of not less than 2.50 to 1.00. If we issue over $200.0 million of senior notes, we will be subject to an additional financial covenant pursuant to which our secured leverage ratio must not be more than 3.50 to 1.00. The Credit Facility places certain restrictions on the issuance of senior notes.

If an event of default occurs, the agent would be entitled to take various actions, including the acceleration of amounts due under the Credit Facility, termination of the commitments under the Credit Facility and all remedial actions available to a secured creditor. The events of default include customary events for a financing agreement of this type, including, without limitation, payment defaults, material inaccuracies of representations and warranties, defaults in the performance of affirmative or negative covenants (including financial covenants), bankruptcy or related defaults, defaults relating to judgments, nonpayment of other material indebtedness and the occurrence of a change in control. In connection with the Credit Facility, we and our subsidiaries have entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations and liabilities arising under or in connection with the Credit Facility are unconditionally guaranteed by us and each of our existing subsidiaries (other than the borrower and Joliet Holdings and the subsidiaries thereof) and each of our future restricted subsidiaries.

First Amendment to Credit Agreement

In January 2014, in connection with the lease agreement at our Portland terminal, Arc Terminals Holdings, as borrower, together with us and certain of our other subsidiaries, as guarantors, entered into the first amendment to the Credit Facility (the “First Amendment”). The First Amendment principally modified certain provisions of the Credit Facility to allow Arc Terminals Holdings to enter into the lease agreement relating to the use of the Portland terminal.

Second Amendment to Credit Agreement

In May 2015, Arc Terminals Holdings, as borrower, together with us and certain of our other subsidiaries, as guarantors, entered into the second amendment to the Credit Facility as part of its financing for the acquisition of the Joliet terminal. Upon the closing of the acquisition of the Joliet terminal in May 2015, the aggregate commitments under the Credit Facility increased from $175 million to $275 million. In addition, the sublimit for letters of credit was increased from $10 million to $20 million.

Third Amendment to Credit Agreement

In July 2015, Arc Terminals Holdings, as borrower, together with us and certain of our other subsidiaries, as guarantors, entered into the third amendment to the Credit Facility as part of its financing for the acquisition of the Pawnee terminal. Upon the consummation of the acquisition of the Pawnee terminal in July 2015, the aggregate commitments under the Credit Facility increased from $275 million to $300 million.

Fourth Amendment to Credit Agreement

In June 2016, Arc Terminals Holdings, as borrower, together with us and certain of our other subsidiaries, as guarantors, entered into the fourth amendment to the Credit Facility (the “Fourth Amendment”). The Fourth Amendment principally modifies certain provisions of the Credit Facility including (i) the circumstances whereby we may increase up to or maintain a total leverage ratio of 5.00 to 1.00 and (ii) the interest rate pricing grid to include an additional pricing tier if the total leverage ratio is greater than or equal to 4.50 to 1.00.

Fifth Amendment to Credit Agreement

In May 2017, Arc Terminals Holdings, as borrower, together with us and certain of our other subsidiaries, as guarantors, entered into the fifth amendment to the Credit Facility (the “Fifth Amendment”). The Fifth Amendment principally modifies a provision of the Credit Agreement whereby we may maintain a total leverage ratio of up to 5.00 to 1.00 for a stated period of time.

CenterPoint Earn-Out Obligation

In connection with our acquisition, through a joint venture company formed with an affiliate of GE EFS, of all the membership interests of JBBR from CenterPoint Properties Trust (“CenterPoint”) for $216.0 million, Joliet Holdings agreed to pay CenterPoint earn-out payments for each barrel of crude oil that is either delivered to or received by the Joliet terminal (without duplication) or for which JBBR receives payment under minimum volume commitments regardless of actual throughput activity. Joliet Holdings’ earn-out obligations to CenterPoint will terminate upon the payment, in the aggregate, of $27.0 million, $4.06 million of which has been recorded as of ~~June~~September 30, 2017.

Settlement

In February 2016, Arc Terminals Holdings entered into a settlement agreement with its customer at the Blakeley, AL facility (the “Blakeley Customer”) pursuant to which the parties agreed to terminate the terminal services agreement for the storage and throughputting of the Blakeley Customer’s sulfuric acid at the Blakeley terminal and to, among other things, release each party from all potential claims arising out of any non-performance of or non-compliance with the representations, warranties and covenants made thereunder. Pursuant to the settlement agreement, Arc Terminals Holdings agreed to pay to the Blakeley Customer an aggregate of $2.0 million in certain increments over a three-year period commencing with the first quarter of 2016, except that Arc Terminals Holdings’ payment obligations thereunder shall be reduced by $0.5 million in the event that Arc Terminals Holdings and the Blakeley Customer enter into a new terminal services agreement for the storage and throughputting of such customer’s sulfuric acid at the Blakeley, AL facility commencing no later than January 1, 2018. Neither Arc Terminals Holdings nor the Blakeley Customer has any obligation to enter into such new terminal services agreement. As of December 31, 2015, we had established an accrual of $2.0 million with respect to our obligations under the settlement agreement. Through ~~June~~September 30, 2017, we have paid approximately $1.34 million towards our obligations under the settlement agreement. The terminal services agreement that has been terminated provided for an amount of minimum take or pay revenue, on a quarterly basis over the remaining term of such terminal services agreement, that would have represented less than 1% of our total revenue for the year ended December 31, 2016.

Cash Flows

~~Six~~Nine Months Ended ~~June~~September 30, 2017 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2016

A summary of the changes in cash flow data is provided as follows (in thousands, except percentages):

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2017			2016			$ Change			% Change
Net cash flows provided by (used in):
Operating activities	$	2438,~~995~~545		$	2743,~~629~~302		$	(24,~~634~~757	)		-1011	%
Investing activities		(612,~~885~~972	)		(1928,~~642~~902	)		1215,~~757~~930			-6555	%
Financing activities		(2127,~~231~~480	)		(615,~~868~~876	)		(1411,~~363~~604	)	~~N/M~~	73	%

Cash Flow from Operating Activities. Operating activities primarily consist of net income adjusted for non-cash items, including depreciation and amortization and the effect of working capital changes. Net cash provided by operating activities was $2538.05 million for the ~~six~~nine months ended ~~June~~September 30, 2017 compared to $2743.63 million for the ~~six~~nine months ended ~~June~~September 30, 2016. The decrease in net cash provided by operating activities was primarily the result of a decrease in net income of approximately $38.62 million for the ~~six~~nine months ended ~~June~~September 30, 2017 compared to the ~~six~~nine months ended ~~June~~September 30, 2016. Our operating cash flows for the ~~six~~nine months ended ~~June~~September 30, 2017 also included changes to certain non-cash charges such as an increase to depreciation and the revaluation of the contingent consideration of $2.2 million and $1.68 million, respectively, offset by a decrease in unit-based compensation and equity earnings from unconsolidated affiliate, net of distributions of $01.97 million and $01.60 million, respectively. In addition, the operating cash flows had aan ~~decrease~~increase in working capital of $0.38 million. The net changes in working capital were primarily driven by the timing of collection of accounts receivables and the timing of payments of accounts payables and accrued expenses.

42Cash Flow from Investing Activities. Investing activities consist primarily of capital expenditures for expansion and maintenance as well as property and equipment divestitures. Net cash used in investing activities was $13.0 million for the nine months ended September 30, 2017, which was used for expansion and maintenance capital expenditures. Net cash used in investing activities was $28.9 million for the nine months ended September 30, 2016, of which $8.0 million was used for the acquisition of our Pennsylvania terminals and $20.9 million was used for expansion and maintenance capital expenditures.

Cash Flow from ~~Investing~~Financing Activities. ~~Investing~~Financing activities consist primarily of ~~capital~~borrowings ~~expenditures~~and ~~for~~repayments ~~expansion~~related ~~and~~to ~~maintenance~~the asCredit ~~well~~Facility, asthe ~~property~~related deferred financing costs and ~~equipment~~distributions ~~divestitures~~to our investors. Net cash flows used in ~~investing~~financing activities was $627.95 million for the ~~six~~nine months ended ~~June~~September 30, 2017, ~~which~~compared ~~was~~to ~~used~~net ~~for expansion and maintenance capital expenditures. Net~~ cash flows used inby ~~investing~~financing activities ~~was~~of $1915.69 million for the ~~six~~nine months ended ~~June~~September 30, 2016,. This $11.6 million decrease was primarily attributable to a decrease in the net proceeds of ~~which~~borrowings from the Credit Facility of $812.09 million ~~was~~primarily ~~used~~related ~~for~~to the acquisition of ~~our~~the Pennsylvania terminals, which occurred in 2016, and ~~$11.6~~a ~~million~~decrease ~~was~~in ~~used~~borrowings ~~for~~related to expansion ~~and~~projects ~~maintenance~~in ~~capital~~2017 ~~expenditures~~compared to 2016.

Cash Flow from Financing Activities. Financing activities consist primarily of borrowings and repayments related to the Credit Facility, the related deferred financing costs and distributions to our investors. Net cash flows used in financing activities was $21.2 million for the six months ended June 30, 2017, compared to net cash flows used by financing activities of $6.9 million for the six months ended June 30, 2016. This $14.4 million decrease was primarily attributable to a decrease in proceeds from borrowings from the Credit Facility related to the Pennsylvania terminal acquisition in 2016 of $8.0 million and a decrease in expansion and maintenance capital expenditures during the six months ended June 30, 2017 compared to the same period in 2016.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. Our contractual obligations as of ~~June~~September 30, 2017 were as follows (in thousands):

	Payments Due by Period
			Less than		1-3		3-5		More than
	Total		1 year		years		years		5 years
Long-term debt obligations	$	~~252~~256,000	$	-	$	~~252~~256,000	$	-	$	-
Operating lease obligations		1412,~~290~~702		6,~~452~~450		76,~~838~~252		-		-
Earn-out obligations		2322,~~026~~391		2,281		4,563		4,563		1110,~~619~~984
Settlement obligations		~~750~~625		500		~~250~~125		-		-
Total	$	~~290~~291,~~066~~718	$	9,~~233~~231	$	~~264~~266,~~651~~940	$	4,563	$	1110,~~619~~984

The schedule above assumes we will either exercise our option to purchase the Portland terminal for a purchase price of $65.7 million or exercise our right to terminate the lease agreement at the Portland terminal by notifying our lessor 12 months in advance of the expiration of the initial term, in which case we would be required to make a one-time payment to our lessor of $4.0 million.

Capital Expenditures

The terminalling and storage business is capital-intensive, requiring significant investment for the maintenance of existing assets and the acquisition or development of new facilities. We categorize our capital expenditures as either:

●

maintenance capital expenditures, which are cash expenditures made to maintain our long-term operating capacity or operating income; or

●

expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating capacity or operating income over the long term.

We incurred maintenance and expansion capital expenditures for the three and ~~six~~nine months ended ~~June~~September 30, 2017 and 2016 as set forth in the following table (in thousands):

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2017

2016

2017

2016

Maintenance capital expenditures

~~853~~1,366

2,~~296~~583

13,~~949~~314

46,~~402~~985

Expansion capital expenditures

35,~~800~~888

43,~~850~~493

612,~~654~~542

912,~~059~~552

Total capital expenditures

47,~~653~~254

76,~~146~~076

815,~~603~~856

1319,~~461~~537

Maintenance Capital Expenditures

Maintenance capital typically consists of capital invested to: (i) clean, inspect and repair storage tanks; (ii) clean and paint tank exteriors; (iii) inspect and upgrade vapor recovery/combustion units; (iv) maintain and/or upgrade fire protection systems; (v) support various regulatory programs; (vi) inspect and repair cathodic protection systems; (vii) inspect and repair tank infrastructure; and (viii) make other general facility repairs as required. Due to the nature of these projects, we will incur additional capital expenditures in some years as compared to others. The decreases of $1.41 million and $23.57 million for the three and ~~six~~nine months ended ~~June~~September 30, 2017, respectively, as compared to the three and ~~six~~nine months ended ~~June~~September 30, 2016 were due to maintenance dredging at our Mobile and Blakeley terminals, ~~and~~ major repairs on the Chickasaw terminal dock, ~~which~~and ~~were~~planned ~~non-recurring~~tank ~~maintenance~~inspections ~~expenses~~repairs that occurred ~~during~~in 2016.

Expansion Capital Expenditures

During the three and ~~six~~nine months ended ~~June~~September 30, 2017, we invested capital to: (i) upgrade our Blakeley and Mobile terminals to support two new, long-term customer agreements; (ii) upgrade our Blakeley terminal to support amendments to existing customer agreements; (iii) upgrade our Chickasaw terminal infrastructure to support two new, long-term customer agreements; (iv) upgrade the Pennsylvania terminals to support increased customer demand; (v) design, develop and construct a new infrastructure project at our Joliet terminal in connection with a new customer services agreement to commence, subject to the satisfaction of certain conditions, during the first quarter of 2018; and (vi) upgrade infrastructure in our Portland terminal to support new, potential commercial opportunities.

During the three and ~~six~~nine months ended ~~June~~September 30, 2016, we invested capital to: (i) upgrade our Blakeley terminal in connection with a new long-term customer agreement; (ii) upgrade our Joliet and Portland terminals to support existing customer agreements; (iii) construct a new tank at our Pawnee terminal to support an existing customer contract; (iv) expand the marine infrastructure and capabilities of our Chickasaw terminal; and (v) upgrade the Pennsylvania terminals to support increased customer demand.

Following the closing of the acquisition of the Pawnee terminal, we expended approximately $11.0 million to complete in 2016 the construction of the Pawnee terminal.

During 2017, as previously disclosed in our 2016 Partnership 10-K, we plan to deploy approximately $10 million to support certain identified growth projects, including the following: (i) to upgrade tanks and associated infrastructure at the Pennsylvania terminals, (ii) to upgrade the Blakeley terminal to support a new, long-term asphalt customer, (iii) to upgrade the Mobile terminal to support a new, long-term fuel oil customer and (iv) to rehabilitate certain tanks for operational readiness for potential future customers. As of ~~June~~September 30, 2017, of the $10 million described above, we had deployed approximately $36.32 million to such identified growth projects.

In addition, we have committed to deploy (i) approximately $815.90 million, 40% of which to be funded by our joint venture partner, for the design, development and construction of storage tanks and associated ~~truck~~marine ~~rack~~ infrastructure at our Joliet terminal in connection with a new customer services agreement to commence, subject to the satisfaction of certain conditions, during the first quarter of 2018 (and if such conditions are not satisfied, by January 1, 2019 or such earlier date as the parties may agree), (ii) up to $1 million to demolish a building at our Brooklyn terminal to potentially construct an ultra-low sulfur diesel tank and associated infrastructure and (iii) up to $3.0 million to expand our gasoline storage capacity and associated infrastructure at our Selma terminal.

In addition to the projects identified above, we are also evaluating upwards of approximately $27.1 million of projects across a number of terminals. These potential projects include (i) the design, development and construction of a liquids dock at our Joliet terminal with associated pipeline infrastructure, (ii) new tankage to support storage and throughput opportunities in a number of terminalling markets, (iii) butane blending infrastructure at certain terminals, and (iv) upgrades to existing rail infrastructure at certain terminals. The success and outcome of these projects will depend upon a variety of factors, including market conditions, regulatory limitations, customer demand, commercial contract terms and our access to available capital.49

quarter of 2018, (ii) approximately $8.9 million, 40% of which to be funded by our joint venture partner, for the design, development and construction of storage tanks and associated truck rack infrastructure at our Joliet terminal in connection with a new customer services agreement to commence, subject to the satisfaction of certain conditions, during the first quarter of 2018 (and if such conditions are not satisfied, by January 1, 2019 or such earlier date as the parties may agree), (iii) up to $1 million to demolish a building at our Brooklyn terminal to potentially construct an ultra-low sulfur diesel tank and associated infrastructure, and (iv) up to $3.0 million to expand our gasoline storage capacity and associated infrastructure at our Selma terminal.

In addition to the projects identified above, we are also evaluating upwards of approximately $12.1 million of projects across a number of terminals. These potential projects include (i) new tankage to support storage and throughput opportunities in a number of terminalling markets and (ii) upgrades to existing rail infrastructure at certain terminals. The success and outcome of these projects will depend upon a variety of factors, including market conditions, regulatory limitations, customer demand, commercial contract terms and our access to available capital.

Our capital funding requirements were funded from borrowings under the Credit Facility and cash from operations. We anticipate that maintenance capital expenditures will be funded primarily with cash from operations or with borrowings under our Credit Facility. We generally intend to fund the capital required for expansion capital expenditures through borrowings under our Credit Facility and the issuance of equity and debt securities.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

As of ~~June~~September 30, 2017, there have been no significant changes to our critical accounting policies and estimates disclosed in our 2016 Partnership 10-K, as filed with the SEC.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2016 Partnership 10-K, as filed with the SEC. Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to the crude oil, petroleum products and other liquids that we handle and store. We do not intend to hedge our indirect exposure to commodity risk.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. As of ~~June~~September 30, 2017, we had $~~252~~256.0 million of outstanding borrowings under the Credit Facility, bearing interest at variable rates. The weighted average interest rate incurred on the indebtedness during the three and ~~six~~nine months ended ~~June~~September 30, 2017 was approximately 4.23% and 4.12%, respectively. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an estimated $0.6 million and $1.39 million increase in interest expense for the three and ~~six~~nine months ended ~~June~~September 30, 2017, respectively, assuming that our indebtedness remained constant throughout the year. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have in place any hedges.

We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have in place any hedges.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our General Partner, including our General Partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our General Partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of ~~June~~September 30, 2017 at the reasonable assurance level.

Remediation of Previously Reported Material Weakness in our Internal Control Over Financial Reporting

As of June 30, 2017, we have remediated the previously reported material weakness in our internal control over financial reporting by enhancing the design of our existing controls and procedures such that management considers forward looking throughput data, long-term interest rates and forecasted budgets on a quarterly basis to ensure proper oversight and revaluation of the estimated fair market value, and any related adjustment to earnings resulting from a gain or loss in the fair value, for earn-out obligations associated with business combinations.

We have completed the documentation, implementation and testing of the remediation actions described above and, as of June 30, 2017, concluded that the steps taken have remediated the previously reported material weakness in our internal control over financial reporting.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended ~~June~~September 30, 2017 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Although we are, from time to time, involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters, including the matters described below, will have a material adverse impact on our financial condition or results of operations. Additionally, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any claim or proceeding would not have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.

On March 23, 2017, JBBR filed a counterclaim under seal against Ragnar Benson in the Circuit Court of the Twelfth Judicial Circuit, Will County, Illinois (the “Will County Circuit Court”) for breach of the Ragnar Benson EPC Contract between JBBR (which is a wholly-owned subsidiary of our joint venture company, Joliet Holdings, 40% of which is owned by an affiliate of GE EFS) and Ragnar Benson, pursuant to which Ragnar Benson agreed to provide certain engineering, procurement and construction services in connection with the development and construction of our Joliet terminal. JBBR is seeking an unspecified amount of damages, including attorneys’ fees and liquidated damages, in connection with JBBR’s claim that Ragnar Benson failed to achieve final completion of its work by the date required therefor under the Ragnar Benson EPC Contract and that certain deficiencies exist with respect to Ragnar Benson’s work in respect of the engineering and construction of a steam and condensate system and a thermal fluid system, which systems are used by JBBR under certain circumstances during cold weather operating activities. JBBR asserted its counterclaim in connection with litigation initiated by Ragnar Benson by the filing of a complaint (the “Ragnar Benson Complaint”) against JBBR on January 23, 2017 in the Will County Circuit Court, pursuant to which Ragnar Benson alleged that it has achieved final completion under the Ragnar Benson EPC Contract and, as a result, is owed $992,000, which represents the remaining amounts claimed to be due to Ragnar Benson for its services thereunder, plus accrued interest. We believe that Ragnar Benson has not reached final completion under the Ragnar Benson EPC Contract due to its failure to comply with its obligations thereunder, and JBBR intends to vigorously defend the allegations made by Ragnar Benson in the Ragnar Benson Complaint and to pursue its counterclaim against Ragnar Benson. In addition, the relief sought by JBBR in connection with its counterclaim is substantially in excess of the amount asserted by Ragnar Benson. We also believe that any amounts owed to Ragnar Benson under the Ragnar Benson EPC Contract for the purpose of achieving final completion thereunder are required to be paid by CenterPoint pursuant to the express terms of the Membership Interest Purchase Agreement entered into by CenterPoint and Joliet Holdings in May 2015 in connection with the acquisition of JBBR by Joliet Holdings. JBBR engaged the services of an expert engineering firm, who has completed a preliminary evaluation of the deficiencies with the steam and condensate system and the thermal fluid system and has recommended measures for the remediation of such deficiencies. Certain of those recommended remediation activities are currently being performed at the facility. We have also investigated the potential liability of Wilson, the engineering firm that (along with Ragnar Benson) designed the Joliet terminal. On July 31, 2017, the Will County Circuit Court Judge presiding over the Ragnar Benson Complaint granted JBBR leave to add Wilson as a party to the pending litigation. Thereafter, JBBR filed a complaint against Wilson in the Will County Circuit Court, seeking damages in an amount yet to be determined, but in excess of several millions of dollars, as a result of the breach by Wilson of its standard of care and other obligations with respect to the design and engineering of the steam and condensate system and the thermal fluid system under the master services agreement between Wilson and JBBR, pursuant to which Wilson agreed to conduct certain design, engineering and construction oversight services in connection with the development of the Joliet terminal. On November 7, 2017, Wilson filed its answer and affirmative defenses to JBBR’s complaint. We cannot provide assurances that we will be successful in our counterclaims against Ragnar Benson and our claims against Wilson and, if successful, that the amount of any award will reimburse us for all of the costs we have or will incur to remediate the deficiencies with the steam and condensate system and the thermal fluid system at the Joliet terminal.

45On October 3, 2017, David Spicer, a purported common unitholder, filed a complaint against us and our Board in the U.S. District Court for the Southern District of New York. The case is captioned David Spicer v. Arc Logistics Partners LP, et al., Case No. 1:17-cv-07555 (S.D.N.Y.). The complaint alleges that (1) we and our Board violated Section 14(a) of the Exchange Act, and Rule 14a-9 promulgated thereunder, by allegedly failing to disclose material information in the preliminary version of our proxy statement filed on September 26, 2017 (the “Preliminary Proxy Statement”), and (2) our Board, as alleged control persons of the Partnership, violated Section 20(a) of the Exchange Act in connection with the filing of the allegedly materially deficient Preliminary Proxy Statement. Mr. Spicer has asked the court to, among other things, (i) enjoin us and our Board from proceeding with or consummating the Merger and the GP Equity Transfer, (ii) alternatively, if the Merger and the GP Equity Transfer are consummated, rescind the Merger and the GP Equity Transfer or award rescissory damages, (iii) direct our Board to disclose the material information allegedly omitted from the Preliminary Proxy Statement, (iv) declare that we and our Board violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder, and/or Section 20(a) of the Exchange Act, and (v) award Mr. Spicer attorneys’ and experts’ fees.

~~evaluation~~On ofOctober ~~the~~4, ~~deficiencies~~2017, ~~with~~Hakeem ~~the~~Jacobs, ~~steam~~a ~~and~~purported ~~condensate~~common ~~system~~unitholder, ~~and~~filed ~~the~~a ~~thermal~~putative ~~fluid~~class ~~system~~action ~~and~~complaint ~~has~~against ~~recommended~~us ~~measures~~and ~~for~~our ~~the~~Board ~~remediation~~on behalf of ~~such~~a ~~deficiencies. We~~class ~~have~~of ~~also~~common ~~investigated~~unitholders ~~the~~other ~~potential~~than ~~liability~~us, ofour ~~Wilson~~Board, ~~the~~and ~~engineering~~our ~~firm~~respective ~~that~~affiliates ~~(along~~in ~~with Ragnar Benson) designed~~ the ~~Joliet terminal~~U. OnS. ~~July~~District ~~31, 2017, the Will County Circuit~~ Court ~~Judge~~for ~~presiding over~~ the ~~Ragnar~~Southern ~~Benson~~District ~~Complaint~~of ~~granted~~New ~~JBBR~~York. ~~leave~~The tocase ~~add~~is ~~Wilson~~captioned asHakeem aJacobs ~~party~~v. toArc ~~the~~Logistics ~~pending~~Partners ~~litigation. Thereafter~~LP, ~~JBBR~~et ~~filed a complaint against Wilson in the Will County Circuit Court~~al., ~~seeking~~Case ~~damages~~No. in1:17-cv-07579 an(S.D.N.Y.). ~~amount~~The ~~yet~~complaint toalleges bethat ~~determined,~~(1) ~~but~~we inand ~~excess~~our ofBoard ~~several~~violated ~~millions~~Section ~~of dollars, as~~ 14(a) ~~result~~ of the ~~breach~~Exchange byAct, ~~Wilson~~and ofRule ~~its~~14a-9 ~~standard~~promulgated ofthereunder, ~~care~~by ~~and~~allegedly ~~other~~failing ~~obligations with respect~~ to ~~the~~disclose ~~design~~material ~~and~~information ~~engineering~~about of the ~~steam~~Merger and ~~condensate system and~~ the ~~thermal~~GP ~~fluid~~Equity ~~system~~Transfer ~~under~~in the ~~master~~Preliminary ~~services~~Proxy ~~agreement~~Statement, ~~between Wilson~~ and ~~JBBR,~~(2) ~~pursuant~~our ~~to which Wilson agreed to conduct certain design~~Board, ~~engineering~~as ~~and~~alleged ~~construction~~control ~~oversight~~persons ~~services in connection with the development~~ of the ~~Joliet terminal. We cannot provide assurances that we will be successful in our counterclaims against Ragnar Benson and our claims against Wilson and~~Partnership, ifviolated ~~successful,~~Section ~~that~~20(a) ~~the amount~~ of ~~any award will reimburse us for all of~~ the ~~costs~~Exchange weAct ~~have~~in ~~or will incur to remediate the deficiencies with the steam and condensate system and the thermal fluid system at the Joliet terminal.~~

connection with the filing of the allegedly materially deficient Preliminary Proxy Statement. Mr. Jacobs has asked the court to, among other things, (i) certify the case as a class action, (ii) enjoin us and our Board from proceeding with the special meeting of our common unitholders or consummating the Merger and the GP Equity Transfer until we disclose the material information allegedly omitted from the Preliminary Proxy Statement, (iii) direct us and our Board to account for any alleged damages sustained by Mr. Jacobs and the purported class and (iv) award Mr. Jacobs attorneys’ and experts’ fees. On October 23, 2017, Mr. Jacobs’ counsel sent a letter to counsel for us and our Board that repeated allegations in the Jacobs complaint concerning certain information allegedly omitted from the Preliminary Proxy Statement, and threatened that if we and our Board did not disclose such information, Mr. Jacobs would ask the court for a preliminary injunction to prevent us and our Board from proceeding with the special meeting of our common unitholders or consummating the Merger and the GP Equity Transfer.

On October 4, 2017, Anthony Franchi, a purported common unitholder, filed a putative class action complaint against the MLP Entities, our Board, the Lightfoot Entities and the Parent Entities (collectively, “Defendants”) on behalf of a class of common unitholders other than Defendants and their respective affiliates in the U.S. District Court for the Southern District of New York. The case is captioned Anthony Franchi v. Arc Logistics Partners LP, et al., Case No. 1:17-cv-07602 (S.D.N.Y.). The complaint alleges that (1) Defendants violated Section 14(a) of the Exchange Act, and Rule 14a-9 promulgated thereunder, by allegedly failing to disclose material information about the Merger and the GP Equity Transfer in the Preliminary Proxy Statement, and (2) our Board and the Parent Entities, as alleged control persons of the Partnership, violated Section 20(a) of the Exchange Act in connection with the filing of the allegedly materially deficient Preliminary Proxy Statement. Mr. Franchi has asked the court to, among other things, (i) enjoin Defendants from proceeding with or consummating the Merger and the GP Equity Transfer; (ii) alternatively, if the Merger and the GP Equity Transfer are consummated, rescind the Merger and the GP Equity Transfer or award rescissory damages, (iii) direct our Board to disclose the material information allegedly omitted from the Preliminary Proxy Statement, (iv) declare that Defendants violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder, and/or Section 20(a) of the Exchange Act, and (v) award Mr. Franchi attorneys’ and experts’ fees.

We believe that the Spicer, Jacobs and Franchi complaints are without merit. We cannot predict the outcome of or estimate the possible loss or range of loss from these matters.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risks under the heading “Risk Factors” in our 2016 Partnership 10-K. There has been no material change in our risk factors from those described in the 2016 Partnership 10-K. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

~~Purchases of Equity Securities by the Issuer and Affiliated Purchasers~~None.

The following table sets forth our purchases of our common units during the three months ended June 30, 2017.

	Purchases of Common Units
Period	Total Number of Common Units Purchased (a)		Aggregate Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
April 1 - April 30, 2017		1,100	$	14.41	—	—
May 1 - May 31, 2017		426	$	14.44	—	—
June 1 - June 30, 2017	—		—		—	—

(a) Represents units withheld to satisfy tax withholding obligations upon settlement of phantom units subject to time-based vesting that were awarded under our 2013 Plan.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and is incorporated herein by reference.

4652

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.

	ARC LOGISTICS PARTNERS LP
	By:	ARC LOGISTICS GP LLC, its General Partner
Date: August 9, 2017	By:	/s/ BRADLEY K. OSWALD
		Bradley K. Oswald
		Senior Vice President, Chief Financial Officer and Treasurer(Principal Financial Officer and Duly Authorized Officer)

EXHIBIT INDEX

Exhibit No.		Description
2.1^		Purchase Agreement and Plan of Merger, dated August 29, 2017, by and among Arc Logistics Partners LP, Arc Logistics GP LLC, Lightfoot Capital Partners, LP, Lightfoot Capital Partners GP LLC, Zenith Energy U.S., L.P., Zenith Energy U.S. GP, LLC, Zenith Energy U.S. Logistics, LLC and Zenith Energy U.S. Logistics Holdings, LLC. (incorporated herein by reference to Exhibit 2.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on August 29, 2017 (SEC File No. 001-36168)).
3.1		Certificate of Limited Partnership of Arc Logistics Partners LP (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Arc Logistics Partners LP’s Registration Statement on Form S-1 filed on October 21, 2013 (SEC File No. 333-191534)).
3.2		First Amended and Restated Agreement of Limited Partnership of Arc Logistics Partners LP, dated November 12, 2013, by and among Arc Logistics GP LLC, Lightfoot Capital Partners, LP and Lightfoot Capital Partners GP LLC. (incorporated herein by reference to Exhibit 3.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on November 12, 2013 (SEC File No. 001-36168)).
10.1		Fifth Amendment, dated May 26, 2017, to the Second Amended and Restated Revolving Credit Agreement, dated November 12, 2013, by and among Arc Logistics Partners LP, Arc Logistics LLC, Arc Terminals Holdings LLC, as Borrower, Arc Terminals New York Holdings, LLC, Arc Terminals Mobile Holdings, LLC, Arc Terminals Mississippi Holdings LLC, Arc Terminals Colorado Holdings LLC and Arc Terminals Pennsylvania Holdings LLC, the Lenders party thereto and SunTrust Bank, as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on June 2, 2017 (SEC File No. 001-36168)).
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1		Purchase Agreement, dated as of August 29, 2017 by and among EFS Midstream Holdings LLC, as Seller, and Lightfoot Capital Partners, LP, Lightfoot Capital Partners GP LLC and Zenith Energy U.S. Logistics Holdings, LLC, as Buyers (incorporated herein by reference to Exhibit 99.2 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on August 29, 2017 (SEC File No. 001-36168)).
99.2		Partially Conditional Purchase Agreement, dated as of August 29, 2017 by and among LCP LNG Holdings, LLC, Lightfoot Capital Partners GP LLC and Lightfoot Capital Partners, LP, Zenith Energy U.S., L.P., Zenith Energy U.S. GP, LLC, Zenith Energy U.S. Logistics Holdings, LLC and (solely for purposes of Section 1.1(d) of such agreement), Arc Logistics Partners LP (incorporated herein by reference to Exhibit 99.3 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on August 29, 2017 (SEC File No. 001-36168)).
99.3		Support Agreement, dated as of August 29, 2017, by and among Lightfoot Capital Partners GP LLC, Lightfoot Capital Partners, LP, Zenith Energy U.S. GP LLC, Zenith Energy U.S., L.P., Zenith Energy U.S. Logistics, LLC and Zenith Energy U.S. Logistics Holdings, LLC (incorporated herein by reference to Exhibit 99.4 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on August 29, 2017 (SEC File No. 001-36168)).
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

4853

^	Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership agrees to furnish a supplemental copy of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.

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.

	ARC LOGISTICS PARTNERS LP

	By:	ARC LOGISTICS GP LLC, its General Partner

Date: November 8, 2017	By:	/s/ BRADLEY K. OSWALD
		Bradley K. Oswald
		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer and Duly Authorized Officer)

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