Zenith Energy Logistics Partners (ARCX) 10-Q 2017 Q1 Quarterly report

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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 March 31, 2017

Or

☐ 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, 19th 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 May 2, 2017, there were 19,518,577 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 March 31, 2017 and December 31, 2016	4
		Condensed Consolidated Statements of Operations and Comprehensive Income for the Three Months Ended March 31, 2017 and 2016	5
		Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	6
		Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2017	7
		Notes to Condensed Consolidated Financial Statements	8
	Cautionary Statement Regarding Forward-Looking Statements		27
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
	Item 4.	Controls and Procedures	40
PART II.	OTHER INFORMATION
	Item 1.	Legal Proceedings	41
	Item 1A.	Risk Factors	41
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
	Item 6.	Exhibits	42
SIGNATURES			43
EXHIBIT INDEX			44

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).

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)

	March 31,		December 31,
	2017		2016
Assets:
Current assets:
Cash and cash equivalents	$	1,762	$	4,584
Trade accounts receivable		9,216		8,257
Due from related parties		549		1,321
Inventories		369		397
Other current assets		2,341		2,060
Total current assets		14,237		16,619
Property, plant and equipment, net		395,006		395,511
Investment in unconsolidated affiliate		76,807		75,716
Intangible assets, net		114,121		117,716
Goodwill		39,871		39,871
Other assets		2,599		2,980
Total assets	$	642,641	$	648,413
Liabilities and partners’ capital:
Current liabilities:
Accounts payable	$	4,609	$	2,455
Accrued expenses		4,741		5,684
Due to general partner		1,557		2,082
Other liabilities		2,855		2,961
Total current liabilities		13,762		13,182
Credit facility		249,500		249,000
Other non-current liabilities		19,391		19,805
Total liabilities		282,653		281,987
Commitments and contingencies
Partners’ capital:
General partner interest		-		-
Limited partners’ interest
Common units – (19,515,678 and 19,477,021 units issued and outstanding at March 31, 2017 and December 31, 2016, respectively)		276,614		282,228
Non-controlling interests		80,269		81,541
Accumulated other comprehensive (loss) income		3,105		2,657
Total partners’ capital		359,988		366,426
Total liabilities and partners’ capital	$	642,641	$	648,413

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

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ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(In thousands, except per unit amounts)

(Unaudited)

	Three Months Ended
	March 31,
	2017			2016
Revenues:
Third-party customers	$	24,448		$	22,584
Related parties		1,477			3,483
		25,925			26,067
Expenses:
Operating expenses		8,873			8,687
Selling, general and administrative		3,239			3,924
Selling, general and administrative – affiliate		1,262			1,322
Depreciation		4,456			3,652
Amortization		3,672			3,697
(Gain) Loss on revaluation of contingent consideration, net		318			(189	)
Total expenses		21,820			21,093
Operating income (loss)		4,105			4,974
Other income (expense):
Equity earnings from unconsolidated affiliate		2,371			2,461
Interest expense		(2,654	)		(2,367	)
Total other income (loss), net		(283	)		94
Income before income taxes		3,822			5,068
Income taxes		31			28
Net income		3,791			5,040
Net income attributable to non-controlling interests		(1,328	)		(1,811	)
Net income attributable to partners' capital		2,463			3,229
Other comprehensive (loss) income		448			(896	)
Comprehensive income (loss) attributable to partners’ capital	$	2,911		$	2,333
Earnings (loss) per limited partner unit:
Common units (basic and diluted)	$	0.12		$	0.15
Subordinated units (basic and diluted)	$	-		$	0.15

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

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ARC LOGISTICS PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2017			2016
Cash flow from operating activities:
Net income	$	3,791		$	5,040
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation		4,456			3,652
Amortization		3,672			3,697
Equity earnings from unconsolidated affiliate, net of distributions		(719	)		(282	)
Amortization of deferred financing costs		406			359
Unit-based compensation		839			1,095
Net loss (gain) on revaluation of contingent consideration		318			(189	)
Changes in operating assets and liabilities:
Trade accounts receivable		(960	)		(219	)
Due from related parties		772			195
Inventories		27			(101	)
Other current assets		(281	)		56
Accounts payable		415			(792	)
Accrued expenses		(448	)		(1,447	)
Due to general partner		(525	)		383
Other liabilities		(220	)		1,073
Net cash provided by operating activities		11,543			12,520
Cash flows from investing activities:
Capital expenditures		(2,557	)		(5,715	)
Net cash paid for acquisitions		-			(8,000	)
Net cash used in investing activities		(2,557	)		(13,715	)
Cash flows from financing activities:
Distributions		(8,570	)		(8,473	)
Deferred financing costs		(25	)		(192	)
Repayments to credit facility		(5,000	)		-
Proceeds from credit facility		5,500			14,250
Payments of earn-out liability		(951	)		(341	)
Distributions paid to non-controlling interests		(2,600	)		(2,800	)
Distribution equivalent rights paid on unissued units		(162	)		(231	)
Net cash provided by (used in) financing activities		(11,808	)		2,213
Net increase (decrease) in cash and cash equivalents		(2,822	)		1,018
Cash and cash equivalents, beginning of period		4,584			5,870
Cash and cash equivalents, end of period	$	1,762		$	6,888
Supplemental disclosure of cash flow information:
Cash paid for interest	$	2,273		$	2,138
Cash paid for income taxes		31			27
Non-cash investing and financing activities:
Decrease (increase) in earn-out liability in accounts payable     and accrued expenses		(333	)		-
Increase (decrease) in purchases of property plant and     equipment in accounts payable and accrued expenses		1,393			438

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

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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		2,463			1,328			-		3,791
Other comprehensive income (loss)		-			-			448		448
Unit-based compensation		839			-			-		839
Net settlement of withholding taxes related to unit-based compensation		(184	)		-			-		(184	)
Distribution equivalent rights paid on unissued units		(162	)		-			-		(162	)
Distributions		(8,570	)		(2,600	)		-		(11,170	)
Partners’ capital at March 31, 2017	$	276,614		$	80,269		$	3,105	$	359,988

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

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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” refer to Lightfoot Capital Partners, LP and its general partner, Lightfoot Capital Partners GP LLC. 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 March 31, 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 March 31, 2017:

19,515,678 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).

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

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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 our 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 months ended March 31, 2016, on the Condensed Consolidated Statement of Operations:

	Quarter to date March 31, 2016
	As previously
	reported			Adjustments			As revised
Gain (loss) on revaluation of contingent consideration (a)	$	-		$	189		$	189
Operating income		4,785			189			4,974
Income before income taxes		4,879			189			5,068
Net income (a)		4,851			189			5,040
Net income attributable to non-controlling interest		(1,735	)		(76	)		(1,811	)
Net income attributable to partners' capital		3,116			113			3,229
Comprehensive (loss) income attributable to partners' capital		2,220			113			2,333
Basic and diluted earnings per unit - common	$	0.15		$	-		$	0.15
Basic and diluted earnings per unit - subordinated	$	0.15		$	-		$	0.15

(a) The corresponding amounts have been revised within the statement of cash flows for the three months ended March 31, 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, 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 three months ended March 31, 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

9

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
	March 31,		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 March 31, 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 March 31, 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 $17.7 million and $18.0 million at March 31, 2017 and December 31, 2016, respectively, include discount rates ranging from 7.2% 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.

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.  

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There are many uncertainties associated with any legal proceeding and these actions or other third-party claims against us may cause us to incur costly litigation and/or substantial settlement charges. As a result, our 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 our 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 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”), Arc Terminals Joliet Holdings LLC (“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 March 31, 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 $17.7 million and $18.0 million at March 31, 2017 and December 31, 2016, respectively, include discount rates ranging from 7.2% 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 $0.3 million non-cash loss and a $0.2 million non-cash gain on the revaluation of the earn-out liability during the three months ended March 31, 2017 and 2016, respectively.  For the three months ended March 31, 2017 and 2016, Joliet Holdings paid $0.6 million and $0.3 million, respectively, related to the earn-out obligation. Since the closing of the JBBR Acquisition in May 2015 through March 31, 2017, Joliet Holdings has paid $3.4 million of the earn-out to CenterPoint.  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				Earn-out			Balance at
	December 31		Revaluation		payments			March 31,
	2016		Adjustments		paid			2017
Liabilities at fair value:
JBBR contingent consideration	$	18,000	$	318	$	(618	)	$	17,700
Total liabilities at fair value	$	18,000	$	318	$	(618	)	$	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.

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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, our 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 three months ended March 31, 2017 and 2016, $2.6 million and $2.8 million, respectively, of distributions have been made to 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 adoption optional but not before the original effective date of December 15, 2016.  In May and December 2016, the FASB issued certain narrow-scope improvements and practical expedients to the guidance.  The Partnership is currently evaluating the potential impact of this authoritative guidance on its financial condition, results of operations, cash flows and related disclosures.

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.

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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 our 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 its wholly owned subsidiary Arc Terminals Holdings LLC (“Arc Terminals Holdings”), 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.  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

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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 March 31, 2017 and December 31, 2016 are represented below (in thousands):

Balance at December 31, 2016	$	75,716
Equity earnings		2,371
Contributions		-
Distributions		(1,652	)
Amortization of premium		(76	)
Other comprehensive income (loss)		448
Balance at March 31, 2017	$	76,807

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 March 31, 2017 is as follows (in thousands):

	Total
2017	$	232
2018		309
2019		309
2020		309
2021		309
Thereafter		6,136
	$	7,604

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

	March 31,		December 31,
	2017		2016
Balance sheets
Current assets	$	6,486	$	7,474
Noncurrent assets		847,159		855,703
Total assets	$	853,645	$	863,177
Current liabilities	$	77,523	$	83,825
Long-term liabilities		607,250		621,802
Member’s equity		168,872		157,550
Total liabilities and member’s equity	$	853,645	$	863,177

	Three Months Ended
	March 31,
	2017		2016
Income statements
Revenues	$	46,497	$	46,484
Total operating costs and expenses		15,026		13,855
Operating income		31,471		32,629
Net income	$	22,977	$	23,845

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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 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.  Although we do not control Gulf LNG Holdings, we also are 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.  We expect the arbitration panel will issue its decision within approximately four months.  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.  

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.

Note 5—Property, Plant and Equipment

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

	As of
	March 31,			December 31,
	2017			2016
Land	$	78,455		$	78,455
Buildings and site improvements		85,336			84,976
Tanks and trim		127,470			124,438
Pipelines		20,507			20,507
Machinery and equipment		122,022			121,278
Office furniture and equipment		1,225			1,152
Construction in progress		14,659			14,917
		449,674			445,723
Less:  Accumulated depreciation		(54,668	)		(50,212	)
Property, plant and equipment, net	$	395,006		$	395,511

Note 6—Intangible Assets

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

	Estimated	As of
	Useful Lives	March 31,			December 31,
	in Years	2017			2016
Customer relationships	21	$	4,785		$	4,785
Acquired contracts	2-12		149,342			149,342
Non-compete agreements	2-3		741			741
			154,868			154,868
Less:  Accumulated amortization			(40,747	)		(37,152	)
Intangible assets, net		$	114,121		$	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 $10.5 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.

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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 is the borrower. The Credit Facility matures in November 2018 and has up to $300.0 million of borrowing capacity. As of March 31, 2017, the Partnership had borrowings of $249.5 million under the Credit Facility at an interest rate of 3.99%.  Based on the restrictions under the total leverage ratio covenant, as of March 31, 2017, the Partnership had $29.0 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.

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 March 31, 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 (the “Portland Terminal”).

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.  

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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 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.  

Note 8—Partners’ Capital and Distributions

Units Outstanding

As of March 31, 2017, the Partnership had 19,515,678 common units outstanding.  Of that number, 5,242,775 were owned by Lightfoot.  In addition, our 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 March 31, 2017:

	Limited Partner Common Units
Units outstanding at December 31, 2016		19,477,021
Vesting of equity-based compensation awards		38,657
Units outstanding at March 31, 2017		19,515,678

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
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
March 31, 2016	$	0.4400	$	8,475	May 13, 2016	May 9, 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.

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The board of directors of the General Partner 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.

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
	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 months ended March 31, 2017 and 2016, the Partnership recorded approximately $0.2 million during each period, of unit-based compensation expense with respect to the Director Grants.  As of March 31, 2017, the unrecognized unit-based compensation expense for the Director Grants is approximately $0.3 million, which will be recognized ratably over the remaining term of the awards.  Through March 31, 2017, two-thirds of the phantom units granted under the Director Grants have vested.  

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

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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 months ended March 31, 2017 and 2016, the Partnership recorded approximately $0.2 million and $0.8 million, respectively, of unit-based compensation expense with respect to the Employee Equity Grants.  As of March 31, 2017, the unrecognized unit-based compensation expense for the Employee Equity Grants was approximately $11.0 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 March 31, 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 ended March 31, 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 March 31, 2017, the unrecognized unit based compensation expense for the Employee Liability Grants was less than approximately $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 March 31, 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 months ended March 31, 2017 and 2016, the Partnership recorded $0.1 million and $0.1 million, respectively, of unit-based compensation expense with respect to the 2015 Equity Grants.  As of March 31, 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 March 31, 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 months ended March 31, 2017 and 2016, the Partnership recorded less than $0.1 million and $0.1 million, respectively, of unit-based compensation expense with respect to the 2015 Performance Grants.  As of March 31, 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 March 31, 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 months ended March 31, 2017 and 2016, the Partnership recorded $0.1 million and less than $0.1 million, respectively, of unit-based compensation expense with respect to the 2016 Equity Grants.  As of March 31, 2017, the unrecognized unit-based compensation expense for the 2016 Equity Grants is approximately $0.7 million, which will be recognized ratably over the remaining term of the awards.  Through March 31, 2017, one-third of the phantom units granted under the 2016 Equity Grants have vested.  

During the three months ended March 31, 2017, the Board authorized the grant of an aggregate of 125,561 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, and 16,450 of the 2017 Equity Grants vested immediately on the date of grant.  For the three months ended March 31, 2017, the Partnership recorded $0.3 million of unit based compensation expense with respect to the 2017 Equity Grants.  As of March 31, 2017, the unrecognized unit-based compensation expense for the 2017 Equity Grants is approximately $1.5 million, which will be recognized ratably over the remaining term of the awards.

During the three months ended March 31, 2017, the Board authorized the grant of an aggregate of 26,250 phantom units pursuant to the 2013 Plan to an employee of the Partnership Entities (“2017 Performance Grant”).  The 2017 Performance Grant will

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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 months ended March 31, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense with respect to the 2017 Performance Grant.  As of March 31, 2017, the unrecognized unit-based compensation expense for the 2017 Performance Grant is approximately $0.4 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 three months ended March 31, 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 months ended March 31, 2017, the Partnership recorded less than $0.1 million of unit-based compensation expense with respect to the 2017 Employee Liability Grants.  As of March 31, 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 months ended March 31, 2017, the Partnership paid approximately $0.4 million in DERs to phantom unit-holders. For the three months ended March 31, 2017, $0.2 million was reflected as a reduction of partners’ capital, and the other $0.2 million 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 months ended March 31, 2016, the Partnership paid approximately $0.4 million in DERs to phantom unit-holders.  For the three months ended March 31, 2016, $0.2 million was reflected as a reduction of partners’ capital, and the other $0.2 million 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 months ended March 31, 2017 and 2016 was $0.8 million and $1.1 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 March 31, 2017 was less than $0.1 million.

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

	Equity Awards					Liability Awards
	Three Months Ended					Three Months Ended
	March 31, 2017					March 31, 2017
	Number			Weighted Avg.		Number			Weighted Avg.
	of Phantom			Grant Date		of Phantom			Grant Date		Fair Value at
	Units			Fair Value		Units			Fair Value		3/31/2017
Balance at December 31, 2016		804,818		$	23.29		4,125		$	25.46	$	14.25
Granted		151,811		$	14.30		10,475		$	14.01	$	-
Vested		(51,837	)	$	13.79		-		$	-	$	-
Forfeited		-		$	-		(225	)	$	25.46	$	-
Balance at March 31, 2017		904,792		$	22.33		14,375		$	17.12	$	14.25

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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.

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.  Following the conversion, the Partnership is no longer utilizing the two-class method when calculating the net income per unit applicable to limited partners.  

Diluted net income per unit applicable to limited partners includes the effects of potentially dilutive units on the Partnership’s units. For the three months ended March 31, 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 months ended March 31, 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
	March 31,
	2017		2016
Net Income attributable to partners' capital	$	2,463	$	3,229
Less:
Distribution equivalent rights for unissued units		198		274
Net income available to limited partners	$	2,265	$	2,955
Numerator for basic and diluted earnings per limited partner unit:
Allocation of net income among limited partner interests:
Net income allocated to common unitholders	$	2,265	$	2,022
Net income (loss) allocated to subordinated unitholders	$	-	$	933
Net income allocated to limited partners:	$	2,265	$	2,955
Denominator for basic and diluted earnings per limited partner unit:
Common units - (basic and diluted)		19,487		13,176
Subordinated units - (basic and diluted)		-		6,081
Earnings (loss) per limited partner unit:
Common - (basic and diluted)	$	0.12	$	0.15
Subordinated - (basic and diluted)	$	-	$	0.15

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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 March 31, 2017 and 2016, the General Partner incurred expenses of $1.3 million and $1.3 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 March 31, 2017 and December 31, 2016, the Partnership had a payable of approximately $1.6 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

During July 2015, the Partnership acquired UET Midstream and its Pawnee terminal from the Pawnee Sellers for $44.3 million in cash and 1,745,669 in unregistered common units in the Partnership.  In connection with such 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

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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 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
	March 31,
	2017		2016
Center Oil	$	1,477	$	1,460
UET (a)	N/A			1,575
GCAC (a)	N/A			448
Total	$	1,477	$	3,483

(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
	March 31,		December 31,
	2017		2016
Center Oil	$	549	$	676
UET (a)	N/A			645
GCAC (a)	N/A		N/A
Total	$	549	$	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 Capital Corporation.  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 March 31, 2017 and 2016, the Partnership was paid $0.4 million and $0.3 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

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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 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.

Registration Rights Agreement with Pawnee Sellers

In connection with the issuance of the Pawnee Transaction 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 Pawnee Transaction 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
	Three Months Ended						% of Receivables
	March 31,						March 31,			December 31,
	2017			2016			2017			2016
Customer A		33	%		33	%		31	%		32	%
Customer B		11	%		13	%		11	%		11	%
Total		44	%		46	%		42	%		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

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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 March 31, 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 March 31, 2017 are presented below (in thousands):

	Payments Due by Period
	Total		2017		2018		2019		2020		2021		Thereafter
Long-term debt obligations	$	249,500	$	-	$	249,500	$	-	$	-	$	-	$	-
Operating lease obligations		15,873		4,864		6,346		4,663		-		-		-
Earn-out obligations		23,638		1,663		2,281		2,281		2,281		2,281		12,851
Settlement obligations		875		375		500		-		-		-		-
Total	$	289,886	$	6,902	$	258,627	$	6,944	$	2,281	$	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 (“LCP Oregon”) 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 March 31, 2017 and 2016, the rent expense associated with the Portland Lease Agreement was $1.6 million, during each period. During the three months ended March 31, 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 March 31, 2017, Joliet Holdings has paid $3.4 million related to the earn-out payment.  The Partnership will continue to evaluate this liability each quarter for any changes in the estimated fair value.  

Settlement Obligation

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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 March 31, 2017, the Partnership has paid $1.1 million related to the settlement agreement.  

Note 14—Subsequent Events

Cash Distributions

In April 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 January 1, 2017 through March 31, 2017.  The distribution is payable on May 15, 2017 to unitholders of record on May 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.

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. References to our “Sponsor” or “Lightfoot” refer to Lightfoot Capital Partners, LP and its general partner, Lightfoot Capital Partners GP LLC. 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

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

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 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 within approximately four months.  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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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 three months ended March 31, 2017, 18% and 18% of our Adjusted EBITDA and Distributable Cash Flow, respectively, were associated with our LNG Interest.  

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

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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 modes 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. While discussions with Exxon are ongoing, contract renewal decisions are not required until August 2017.  If we are unable to renew our agreements with Exxon upon the expiration thereof, our business, financial conditions, results of operations and ability to make cash distributions to our unitholders would be material adversely affected.  If we renew the Exxon agreements on terms that are not 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. For the three months ended March 31, 2017, Exxon, our largest customer, accounted for 30% and 39% 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 March 31, 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.

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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:

o 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.

o 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 March 31, 2017, the remaining term of each terminal use agreement is approximately 15 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,

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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.

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
	March 31,
	2017			2016
Net income attributable to partners' capital	$	2,463		$	3,229
Income taxes		31			28
Interest expense		2,654			2,367
Depreciation (a)		3,978			3,202
Amortization (a)		3,055			3,081
One-time non-recurring expenses (b)		-			559
Non-cash unit-based compensation		840			1,088
Non-cash loss (gain) on revaluation of contingent consideration, net (a)(c)		191			(113	)
Non-cash deferred rent expense (d)		65			65
Adjusted EBITDA	$	13,277		$	13,506
Cash interest expense		(2,273	)		(2,138	)
Cash income taxes		(31	)		(27	)
Maintenance capital expenditures		(1,096	)		(2,080	)
Equity earnings from the LNG Interest		(2,371	)		(2,461	)
Cash distributions received from the LNG Interest		1,652			2,179
Distributable Cash Flow	$	9,158		$	8,979
Maintenance capital expenditures		1,096			2,080
Distributable cash flow attributable to non-controlling interests		2,423			2,803
Changes in operating assets and liabilities		(1,220	)		(852	)
One-time non-recurring expenses (b)		-			(559	)
Other non-cash adjustments		86			69
Net cash provided by operating activities	$	11,543		$	12,520

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(a) The revaluation of contingent consideration, 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 months ended March 31, 2017 and 2016 (in thousands, except operating data):

	Three Months Ended
	March 31,
	2017			2016
Revenues:
Third-party customers	$	24,448		$	22,584
Related parties		1,477			3,483
		25,925			26,067
Expenses:
Operating expenses		8,873			8,687
Selling, general and administrative		3,239			3,924
Selling, general and administrative - affiliate		1,262			1,322
Depreciation		4,456			3,652
Amortization		3,672			3,697
(Gain) Loss on revaluation of contingent consideration, net		318			(189	)
Total expenses		21,820			21,093
Operating (loss) income		4,105			4,974
Other income (expense):
Equity earnings from unconsolidated affiliate		2,371			2,461
Interest expense		(2,654	)		(2,367	)
Total other income, net		(283	)		94
Income before income taxes		3,822			5,068
Income taxes		31			28
Net income		3,791			5,040
Net income attributable to non-controlling interests		(1,328	)		(1,811	)
Net income attributable to partners' capital	$	2,463		$	3,229
Other Financial Data:
Adjusted EBITDA	$	13,277		$	13,506
Distributable Cash Flow	$	9,158		$	8,979
Operating Data:
Storage capacity (bbls)		7,842,600			7,741,100
Throughput (bpd)		159,476			144,980
% Take or pay revenue		82	%		86	%

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

Storage Capacity. Storage capacity for the three months ended March 31, 2017 increased by 101,500 barrels, or 1%, compared to the three months ended March 31, 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.  

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Throughput Activity. The following table details the types and amounts of throughput generated during the three months ended March 31, 2017 and 2016 (in thousands of barrels per day, except percentages):

	Three Months Ended
	March 31,
	2017		2016		Change in bpd			% Change
Asphalts and industrial products		17,324		14,452		2,872			20	%
Crude oil		69,714		70,195		(481	)		-1	%
Distillates		24,206		19,183		5,023			26	%
Gasoline		48,232		41,150		7,082			17	%
Total		159,476		144,980		14,496			10	%

Throughput activity for the three months ended March 31, 2017 increased by 14.5 mbpd or 10% compared to the three months ended March 31, 2016.  The 2.9 mbpd or 20% increase in asphalt and industrial products throughput is related to an increase in existing customer activity in the Gulf Coast. The 0.5 mbpd or 1% decrease in crude oil throughput is the result of a decrease of 23.4 mbpd of throughput at our Pawnee and Portland terminals offset by an increase of 23.0 mbpd of throughput at our Joliet terminal. The 5.0 mbpd or 26% increase in distillates throughput is the result of (i) 9.2 mbpd of throughput associated with recently executed agreements in the Baltimore, Cleveland and the Pennsylvania terminals and (ii) 1.7 mbpd related to an increase in existing customer activity in the Gulf Coast partially offset by (iii) 3.0 mbpd of reduced customer activity in our Madison, Mobile, Portland, Selma and Toledo terminals and (iv) 2.8 mbpd decrease related to a customer non-renewal of a short-term agreement in the Gulf Coast. The 7.1 mbpd or 17% increase in gasoline throughput is the result of 8.3 mbpd of throughput associated with recently executed agreements and increased commercial activity across the entire network providing gasoline service offset by 1.2 mbpd of reduced customer activity in our Dupont and Selma terminals.

Revenues. The following table details the types and amounts of revenues generated during the three months ended March 31, 2017 and 2016 (in thousands, except percentages).

	Three Months Ended
	March 31,
	2017		2016		$ Change			% Change
Minimum storage & throughput services fees	$	20,919	$	22,018	$	(1,099	)		-5	%
Excess throughput & handling fees		3,316		2,656		660			25	%
Total storage & throughput services fees	$	24,235	$	24,674	$	(439	)		-2	%
Ancillary services fees		1,690		1,393		297			21	%
Total revenues	$	25,925	$	26,067	$	(142	)		-1	%

Revenues for the quarter ended March 31, 2017 decreased by $0.1 million, or less than 1%, compared to the quarter ended March 31, 2016. Total storage and throughput services fees decreased by $0.4 million, or 2%, compared to the three months March 31, 2016. Minimum storage and throughput services fees decreased by $1.1 million, or 5%, as compared to the same period in 2016, due to the following:

• Increase of $0.2 million related to the execution of new customer agreements at our Altoona, Baltimore, Chickasaw, Cleveland, Dupont, Mechanicsburg and Toledo terminals;

• Increase of $0.8 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, Pawnee and Toledo terminals;

• Decrease of $0.9 million from customer non-renewals at our Blakeley and Chickasaw terminals; the Partnership 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 $1.2 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, Dupont, Mechanicsburg, Mobile, Portland and Williamsport terminals.

Excess throughput and handling fees increased by $0.7 million, or 25%, as compared to the same period in 2016, due to the following:

• Increase of $0.8 million from the execution of new customer agreements at our Altoona, Baltimore, Cleveland, Dupont, Mechanicsburg, Norfolk, Selma, Toledo and Williamsport terminals;

• Increase of $0.2 million from incremental existing customer throughput and handling fees at our Baltimore, Chickasaw, Cleveland, Mobile, Norfolk and Pawnee terminals;

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• Decrease of $0.2 million from reduced existing customer throughput and handling fees in Blakeley, Dupont, Joliet, Mechanicsburg, Selma, Toledo and Williamsport;

• Decrease of less than $0.1 million from customer non-renewals at our Baltimore and Blakeley terminals; and

• Decrease of less than $0.1 million from inactive existing customer throughput at our Norfolk and Selma terminals.

Ancillary services fees increased by $0.3 million, or 21%, as compared to the same period in 2016, due to the following:

• Increase of $0.3 million from the services provided to our customers at our Baltimore, Brooklyn, Dupont, Mechanicsburg, Norfolk, Pawnee, Selma and Spartanburg terminals due to increased activity;

• Decrease of $0.1 million from customer non-renewals of certain real property parking and equipment leases; and

• Increase of $0.1 million from heat reimbursement fees, lab services, railcar storage fees, railcar sampling fees and truck sampling fees at our Blakeley, Chickasaw, Joliet, Mobile and Portland terminals.

Operating Expenses. Operating expenses for the three months ended March 31, 2017 increased by $0.2 million, or 2%, compared to the three months ended March 31, 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) $0.2 million due to an increase in contract labor in support of customer activities at the Joliet terminal and (iv) an increase in compliance expense of $0.1 million. The increase in operating expenses was offset by reduced payroll expenses of $0.1 million due to a realignment and optimization of our workforce, $0.1 million related to a reduction in office expenses, $0.1 million related to prior period tank cleaning projects and $0.1 million related to a reduction in estimated property taxes related to prior year acquisitions.

Selling, General and Administrative Expenses.  SG&A expenses for the three months ended March 31, 2017 decreased by $0.7 million, or 14%, compared to the three months ended March 31, 2016.  The decrease in SG&A expenses was a result of a $0.3 million decrease in due diligence expenses, a $0.2 million decrease in professional fees, $0.2 million related to a reduction in compensation expense under the Arc Logistics Long-Term Incentive Plan (as amended from time to time, our “2013 Plan”) and a less than $0.1 million related to a reduction in allocation of expenses from our General Partner.

Depreciation and Amortization Expense. Depreciation expense for the three months ended March 31, 2017 increased by $0.8 million, or 22%, compared to the three months ended March 31, 2016, primarily due to the impact of the expansion projects at our Gulf Oil terminals which were acquired in 2016, customer expansion activities and incremental maintenance projects.  Amortization expense for the three months ended March 31, 2017 decreased by less than $0.1 million, or 1%, compared to the three months ended March 31, 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 March 31, 2017 decreased by $0.1 million compared to the three months ended March 31, 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 March 31, 2017 increased by $0.3 million, or 12%, compared to the three months ended March 31, 2016. The increase in interest expense was the result of higher outstanding indebtedness during the three months ended March 31, 2017 compared to the three months ended March 31, 2016.  The increase in indebtedness was primarily related to the amounts drawn from the Credit Facility to fund expansion capital projects.    

Net Income. Net income for the three months ended March 31, 2017 decreased by $1.2 million, or 25%, compared to the three months ended March 31, 2016.  The decrease was primarily related to (i) $0.1 million decreased revenue due to reductions in contracted minimum storage and throughput revenue and customer non-renewals partially offset by new customer agreements and increased throughput and ancillary service fees; (ii) $0.2 million increase in operating expenses; (iii) $0.8 million increase in depreciation expense related to the depreciation of our recent capital expenditures; (iv) $0.5 million increase on the revaluation of the contingent consideration; and (v) $0.3 million increase in interest expense due to higher outstanding indebtedness. 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 $0.7 million.

Adjusted EBITDA. Adjusted EBITDA for the three months ended March 31, 2017 decreased by $0.2 million, or 2%, compared to the three months ended March 31, 2016.  The decrease in Adjusted EBITDA for the three months ended March 31, 2017 was primarily attributable to a reduction in revenues, an increase in operating expenses and a reduction in the income allocation from investment in Gulf LNG offset by reduced SG&A expense.

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 Credit Facility and issuances of equity and debt securities. We believe that cash generated from these sources

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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 April 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 May 2, 2017.  The distribution is payable on May 15, 2017 to unitholders of record on May 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. While discussions with Exxon are ongoing, contract renewal decisions are not required until August 2017. 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.  Based on that investigation, we intend to pursue remedies against Wilson under the master services agreement between JBBR and Wilson.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 March 31, 2017, we had borrowings of $249.5 million under the Credit Facility at an interest rate of 3.99%.  Based on the restrictions under our total leverage ratio covenant, as of March 31, 2017, we had $29.0 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 March 31, 2017, we were in compliance with such covenants. The negative covenants include restrictions on

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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 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.

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, $3.4 million of which has been paid as of March 31, 2017.

Settlement

In February 2016, Arc Terminals Holdings entered into a settlement agreement with the Blakeley Customer pursuant to which the parties agreed to terminate the terminal services agreement for the storage and throughputting of 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.  

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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 March 31, 2017, we have paid approximately $1.1 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

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

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

	Three Months Ended
	March 31,
	2017			2016			$ Change			% Change
Net cash flows provided by (used in):
Operating activities	$	11,543		$	12,520		$	(977	)		-8	%
Investing activities		(2,557	)		(13,715	)		11,158		N/M
Financing activities		(11,808	)		2,213			(14,021	)	N/M

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 $11.5 million for the three months ended March 31, 2017 compared to $12.5 million for the three months ended March 31, 2016. The decrease in net cash provided by operating activities was primarily the result of a decrease in net income of approximately $1.2 million for the three months ended March 31, 2017 compared to the three months ended March 31, 2016.  Our operating cash flows for the three months ended March 31, 2017 also included changes to certain non-cash charges such as an increase to depreciation of $0.8 million offset by a decrease in unit-based compensation and equity earnings from unconsolidated affiliate, net of distributions of $0.3 million and $0.4 million, respectively.  This net increase was offset by a decrease in working capital of $0.3 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.  

Cash 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 $2.6 million for the three months ended March 31, 2017, which was used for expansion and maintenance capital expenditures.  Net cash used in investing activities was $13.7 million for the three months ended March 31, 2016, of which $8.0 million was used for the Gulf Oil Terminals Acquisition and $5.7 million was used for expansion and maintenance capital expenditures.

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 $11.8 million for the three months ended March 31, 2017, compared to net cash flows provided by financing activities of $2.2 million for the three months ended March 31, 2016. This $14.0 million decrease was primarily attributable to a decrease in proceeds from borrowings from our credit facility related to the Pennsylvania terminal acquisitions in 2016 of $8.0 million and an increase in repayments to our credit facility in 2017 of $5.0 million.  

Contractual Obligations

We have contractual obligations that are required to be settled in cash. Our contractual obligations as of March 31, 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	$	249,500	$	-	$	249,500	$	-	$	-
Operating lease obligations		15,873		6,453		9,420		-		-
Earn-out obligations		23,638		2,281		4,563		4,563		12,231
Settlement obligations		875		500		375		-		-
Total	$	289,886	$	9,234	$	263,858	$	4,563	$	12,231

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.

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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 months ended March 31, 2017 and 2016 as set forth in the following table (in thousands):

	Three Months Ended
	March 31,
	2017		2016
Maintenance capital expenditures	$	1,096	$	2,080
Expansion capital expenditures		2,854		4,177
Total capital expenditures	$	3,950	$	6,257

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) invest capital to support various regulatory programs; (vi) inspect and repair cathodic protection systems; (vii) inspect and repair tank infrastructure; and (vi) 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 decrease of $1.0 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 was due to maintenance dredging at our Mobile and Blakeley terminals and major repairs on the Chickasaw terminal dock.  

Expansion Capital Expenditures

During the three months ended March 31, 2017, we invested capital to (i) upgrade our Blakeley and Mobile terminals to support two new, long-term customer agreements, (ii) upgrade our Blakeley and Toledo terminals to support amendments to existing customer agreements, (iii) upgrade our Chickasaw infrastructure to support new, long-term customer agreements, (iv) upgrade the Pennsylvania terminals to support increased customer demand, and (v) complete 2016 projects to upgrade infrastructure in Chickasaw, Joliet, Mobile, Pawnee and Portland.

During the three months ended March 31, 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 and (iv) expand the marine infrastructure and capabilities of our Chickasaw terminal.

Following the closing of the Pawnee Terminal Acquisition, 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 in support of 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 March 31, 2017, of the $10 million described above, we deployed approximately $2.4 million to such identified growth projects.

In addition to the projects identified above, we are also evaluating upwards of $40.0 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) the design, development and construction of storage tanks and associated truck rack infrastructure to support potential new customers at the Joliet terminal, (iii) new tankage to support storage and throughput opportunities in a number of terminalling markets, (iv) butane blending infrastructure at certain terminals, and (v) 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

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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 March 31, 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 March 31, 2017, we had $249.5 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 months ended March 31, 2017 was approximately 4.2%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an estimated $0.6 million increase in interest expense for the three months ended March 31, 2017 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.

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. The Company had previously reported a material weakness in internal control over financial reporting related to the revaluation of the earn-out obligation associated with business combinations. Specifically, we did not properly design and maintain controls to revalue, either on a quarterly or annual basis, the fair value of such earn-out obligation and record the related gain or loss in the fair value as an adjustment to earnings, as applicable. This material weakness was described in Item 9A in the Management’s Report on Internal Control Over Financial Reporting in our 2016 Partnership10-K. 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 recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information 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. Based upon that evaluation, our General Partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of March 31, 2017 because of the material weakness in internal control over financial reporting described in our 2016 Partnership 10-K.

Management’s Remediation Activities

We are committed to remediating the control deficiency that constitutes the material weakness described above by implementing changes to our internal control over financial reporting. Our Chief Financial Officer and Chief Accounting Officer are responsible for implementing changes and improvements in the internal control over financial reporting and for remediating the control deficiency that gave rise to the material weakness.

Actions to be taken or in process consist of testing our internal controls that have been implemented to revalue, on a quarterly and on an annual basis, the fair value of the earn-out obligations.

While significant progress has been made to enhance our internal control over financial reporting relating to the material weakness, additional time will be required to assess and ensure the sustainability of these processes and procedures. We expect to complete the planned remedial actions during 2017, however, we cannot make any assurances that such actions will be effective during 2017. Until the remediation steps set forth above are fully tested and concluded to be operating effectively, the material weakness described above will continue to exist.

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Changes in Internal Control over Financial Reporting

Except as otherwise discussed above under “Management’s Remediation Activities,” there were no changes in our internal control over financial reporting during the quarter ended March 31, 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 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 has engaged the services of an expert engineering firm and is in the preliminary stages of evaluating recommended measures to remediate the deficiencies with the steam and condensate system and the thermal fluid system as well as the costs thereof. We have also investigated the potential liability of Wilson, the engineering firm that (along with Ragnar Benson) designed the Joliet terminal.  Based on that investigation, we intend to pursue remedies against Wilson under the master services agreement between JBBR and Wilson.

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

The following table sets forth our purchases of our common units during the three months ended March 31, 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
January 1 - January 31, 2017	—		—		—	—
February 1 - February 28, 2017		13,180	$	14.14	—	—
March 1 - March 31, 2017	—		—		—	—

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(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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ARC LOGISTICS PARTNERS LP
	By:	ARC LOGISTICS GP LLC, its General Partner
Date: May 5, 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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EXHIBIT INDEX

Exhibit No.	Description
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*	Form of Phantom Unit Award Agreement (Employees – 2017 Performance Vesting) under the Arc Logistics Amended and Restated Long Term Incentive Plan.
10.2*	Form of Phantom Unit Award Agreement (Employees – 2017 Time Vesting) under the Arc Logistics Amended and Restated Long Term Incentive Plan.
10.3*	Form of Phantom Unit Award Agreement (Employees – 2017 Immediate Vesting) under the Arc Logistics Amended and Restated Long Term Incentive Plan.
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.
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

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