Zenith Energy Logistics Partners (ARCX) 10-K 2014 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

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

Securities registered pursuant to Section 12(b) of the Act:

	Title of each class		Name of each exchange on which registered
Common units representing limited partnership interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes  ¨    No  þ

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  þ    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  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

(Check one):

Large accelerated filer	¨		Accelerated filer	þ
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of common units held by non-affiliates was approximately $167,808,000, based upon a closing price of $24.68 per common unit as reported on the New York Stock Exchange on such date.

As of March 6, 2015, there were 6,867,950 common units and 6,081,081 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

			Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			1
GLOSSARY OF TERMS			2
Part I	Item 1.	Business	4
	Item 1A.	Risk Factors	16
	Item 1B.	Unresolved Staff Comments	39
	Item 2.	Properties	39
	Item 3.	Legal Proceedings	39
	Item 4.	Mine Safety Disclosures	39
Part II	Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	40
	Item 6.	Selected Financial Data	42
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
	Item 8.	Financial Statements and Supplementary Data	60
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
	Item 9A.	Controls and Procedures	60
	Item 9B.	Other Information	61
Part III	Item 10.	Directors, Executive Officers and Corporate Governance	62
	Item 11.	Executive Compensation	68
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	74
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	76
	Item 14.	Principal Accounting Fees and Services	80
Part IV	Item 15.	Exhibits, Financial Statement Schedules	82
SIGNATURES			83

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K 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. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, Item 1A. “Risk Factors.”

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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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 II, Item 7. “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.

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:    One barrel 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; (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 II, Item 7. “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.

fuel oil:    A liquid petroleum product used as an energy source which includes residual fuel oil (No. 5 and No. 6).

GAAP:    Generally accepted accounting principles in the United States.

JOBS Act:    Jumpstart Our Business Startups Act.

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.

NYSE:     New York Stock Exchange.

PCAOB:    Public Company Accounting Oversight Board.

SEC:    U.S. Securities and Exchange Commission.

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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 and petroleum products.

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

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Unless the context clearly indicates otherwise, references in this Annual Report on Form 10-K to “Arc Terminals,” the “Partnership,” “we,” “our,” “us” or similar terms when used for periods prior to November 12, 2013, the closing date of the initial public offering of Arc Logistics Partners LP (the “IPO”), refer to Arc Terminals LP and its subsidiaries, which were contributed to Arc Logistics Partners LP in connection with the IPO, and references to “Arc Logistics,” the “Partnership,” “we,” “our,” “us” or similar terms when used for periods on or after the closing date of the IPO refer to Arc Logistics Partners LP and its subsidiaries. Unless the context clearly indicates otherwise, references to our “General Partner” for periods prior to the closing date of the IPO refer to Arc Terminals GP LLC which owned the general partner interest in Arc Terminals and references to our “General Partner” for periods on or after the closing date of the IPO 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 “GCAC” refer to Gulf Coast Asphalt Company, L.L.C., which contributed its preferred units in Arc Terminals to the Partnership upon the consummation of the IPO. 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 to the Partnership upon the consummation of the 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 used a portion of the proceeds from the IPO to acquire a 10.3% limited liability company interest in Gulf LNG Holdings, which is referred to herein as the “LNG Interest.”

PART I

ITEM 1. BUSINESS

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 and petroleum products. 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, the construction of new facilities in existing or new markets and strategic acquisitions from our Sponsor and third parties.

Our cash flows are primarily generated by fee-based terminalling, storage, throughput and transloading services that we perform under multi-year contracts. 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 and petroleum products. Many of our service agreements contain take-or-pay provisions whereby we generate revenue regardless of the customers’ use of the facility. Storage and throughput services fees accounted for approximately 86% of our revenue for each of the years ended December 31, 2014 and 2013 and approximately 83% of our revenue for the year ended December 31, 2012.

● Ancillary Services Fees. We generate revenues from ancillary services, such as heating, blending and mixing associated with our customers’ activity. The revenues we generate from ancillary services vary based upon customers’ activity levels. Ancillary services fees accounted for approximately 14% of our revenue for each of the years ended December 31, 2014 and 2013 and approximately 17% of our revenue for the year ended December 31, 2012.

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 minimal exposure to commodity price fluctuations, creates stable cash flow and lessens the exposure to market factors including supply and demand volatility.

We also receive cash distributions from the LNG Interest we acquired on November 12, 2013, which we account for using equity method accounting. These distributions are supported by two multi-year, firm reservation charge terminal use agreements with several integrated, multi-national oil and gas companies for all of the capacity of the LNG Facility that began commercial operation in October 2011. As of December 31, 2014, the remaining term of each of these terminal use agreements is approximately 17 years.

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Relationship with Lightfoot

Our Sponsor, Lightfoot, is a private investment vehicle that focuses on investing directly in master limited partnership-qualifying businesses and assets. Lightfoot investors include affiliates of, and funds under management by, GE Energy Financial Services (“GE EFS”), Atlas Energy Group, BlackRock Investment Management, LLC, Magnetar Financial LLC, CorEnergy Infrastructure Trust, Inc. (“CorEnergy”) and Triangle Peak Partners Private Equity, LP. Lightfoot intends to utilize us as a growth vehicle for its energy logistics business strategy to facilitate future organic expansion and acquisitions. Lightfoot has a significant interest in us through its ownership of a 40.3% limited partner interest in us, 100.0% of our General Partner and all of our incentive distribution rights.

Recent Developments

JBBR Acquisition

In February 2015, through a joint venture arrangement with GE EFS, we agreed to acquire, subject to the terms and conditions of a definitive acquisition agreement, all of the membership interests of Joliet Bulk, Barge & Rail LLC ("JBBR") from CenterPoint Properties Trust ("CenterPoint" or the "Seller") for $216 million. JBBR's principal assets consist of a crude oil unloading terminal and a 4-mile crude oil pipeline (collectively, the “Joliet Terminal”), which are in the final stages of construction in Joliet, IL and are expected to be complete in mid to late April 2015. The acquisition consideration also includes an earn-out payable by the JBBR joint venture company (referred to below) to CenterPoint based upon petroleum product throughput volumes at the Joliet Terminal (including minimum volumes paid under customer contracts irrespective of physical deliveries of product thereunder). JBBR joint venture company’s earn-out obligations to CenterPoint will terminate upon the payment, in the aggregate, of $27 million.

At the closing of the acquisition, we will manage ongoing operations of the Joliet Terminal and own a 60% interest in the JBBR joint venture company. GE EFS will own the remaining 40%. The Joliet Terminal is expected to begin commercial operations by mid to late April 2015, and the acquisition will not close until the Joliet Terminal becomes commercially operable. We or CenterPoint may terminate the definitive acquisition agreement if the closing of the JBBR acquisition does not occur by May 18, 2015.

We will finance our approximate $130 million portion of the purchase price with net proceeds from the sale of common units in a private placement and from borrowings under our revolving credit facility. Institutional investors have committed to acquire, concurrently with the closing of the acquisition, approximately 4.4 million of our common units in a private placement at a price of $17.00 per unit, resulting in gross proceeds (before fees and expenses) to us of $75 million.

Once completed, the Joliet Terminal will have the capability to unload approximately 85,000 barrels of crude oil per day, and will have approximately 300,000 barrels of storage and a 4-mile pipeline connection to a common carrier crude oil pipeline. The facility will have rail and marine access and capabilities as well as more than 80 acres of land available for future expansion. At closing, the Joliet Terminal will be supported by a terminal services agreement as well as a throughput and deficiency agreement with a major oil company, each with a term of three years based on minimum throughput volume commitments.

The JBBR acquisition continues our existing business strategy to expand our market position and support the expansion plans of new and existing customers, while generating stable cash flows for our unitholders from quality assets supported by long-term contracts.

Portland Terminal

In January 2014, we extended our operational footprint and customer relationships into the West Coast market by executing a 15-year triple-net operating lease on a petroleum products terminal in Portland, OR. The Portland terminal (“Portland Terminal”) is a rail/marine facility adjacent to the Willamette River in Portland, OR. The 39-acre site has 84 tanks with a total storage capacity of 1,466,000 barrels and is capable of receiving, storing and delivering heavy and light petroleum products. Products are received and/or delivered via railroad, marine (up to Panamax size vessels) and a truck loading rack. The marine facilities are accessed through a neighboring terminal facility via a pipeline. The Portland Terminal offers heating systems, emulsions and an on-site product testing laboratory as ancillary services.

In connection with the Portland Terminal operating lease, Arc Terminals Holdings LLC, a wholly owned subsidiary of ours (“Arc Terminals Holdings”), as borrower, and Arc Logistics and its other subsidiaries, as guarantors, entered into the first amendment (the “First Amendment”) to the Credit Facility (as defined below) agreement. The First Amendment principally modified certain provisions of the Credit Facility agreement to allow Arc Terminals Holdings to enter into a triple net operating lease agreement for the use of a petroleum products terminal located in Portland, OR together with a supplemental co-terminus triple net operating lease

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agreement for the use of certain pipeline infrastructure at the Portland Terminal, and such lease agreements, collectively, the “Lease Agreement”).

Assets and Operations

As of December 31, 2014, our energy logistics assets are strategically located in the East Coast, Gulf Coast, West Coast and Midwest regions of the United States and supply a diverse group of third-party customers, including major oil companies, independent refiners, crude oil and petroleum product marketers, distributors and various industrial manufacturers. Depending upon the location, our facilities possess pipeline, rail, marine and truck loading and unloading capabilities allowing customers to receive and deliver product throughout North America. Our asset platform allows customers to meet the specialized handling requirements that may be required by particular products. Our combination of diverse geographic locations and logistics platforms gives us the flexibility to meet the evolving demands of existing customers and address those of prospective customers.

Our assets consist of:

● 15 terminals in ten states located in the East Coast, Gulf Coast, West Coast and Midwest regions of the United States with approximately 6.4 million barrels of crude oil and petroleum product storage capacity;

● three rail transloading facilities with approximately 41,000 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 following table sets forth certain information regarding our assets:

Location	Principal Products	Shell Capacity	Supply & Delivery Modes
Terminals:
Baltimore, MD (1)	Gasoline; Distillates; Ethanol	442,000 bbls	Pipeline; Railroad; Marine; Truck
Blakeley, AL (2)	Crude Oil; Asphalt; Fuel Oil; Chemicals	708,000 bbls	Marine; Truck
Brooklyn, NY	Gasoline; Ethanol	63,000 bbls	Pipeline; Marine; Truck
Chickasaw, AL	Crude Oil; Distillates; Fuel Oil; Crude Tall Oil	609,000 bbls	Railroad; Marine; Truck
Chillicothe, IL	Gasoline; Distillates; Ethanol; Biodiesel	273,000 bbls	Truck
Cleveland, OH -North	Gasoline; Distillates; Ethanol; Biodiesel	426,000 bbls	Pipeline; Railroad; Marine; Truck
Cleveland, OH -South	Gasoline; Distillates; Ethanol; Biodiesel	191,000 bbls	Pipeline; Railroad; Marine; Truck
Madison, WI	Gasoline; Distillates; Ethanol; Biodiesel	150,000 bbls	Pipeline; Truck
Mobile, AL - Main	Crude Oil; Fuel Oil; Asphalt	1,093,000 bbls	Marine; Truck
Mobile, AL - Methanol	Methanol	294,000 bbls	Marine; Truck
Norfolk, VA (3)	Gasoline; Distillates; Ethanol	212,600 bbls	Pipeline; Marine; Truck
Portland, OR (4)	Crude Oil; Asphalt; Aviation Gas; Distillates	1,466,000 bbls	Railroad; Marine; Truck
Selma, NC	Gasoline; Distillates; Ethanol; Biodiesel	171,000 bbls	Pipeline; Truck
Spartanburg, SC (1)	Gasoline; Distillates; Ethanol	82,500 bbls	Pipeline; Truck
Toledo, OH	Gasoline; Distillates; Aviation Gas; Ethanol; Biodiesel	244,000 bbls	Pipeline; Railroad; Marine; Truck
Total Terminals		6,425,100 bbls
Rail/Transloading Facilities:
Chickasaw, AL	Crude Oil; Distillates; Fuel Oil; Crude Tall Oil; Chemicals	9,000 bpd
Portland, OR	Crude Oil	18,000 bpd
Saraland, AL	Crude Oil; Chemicals	14,000 bpd
Total Rail/Transloading Facilities		41,000 bpd
LNG Facility:
Pascagoula, MS (5)	LNG	320,000 M3	Pipeline; Marine

(1) The capacity represents our 50% share of the 884,000 barrels of available total shell storage capacity of the Baltimore, MD terminal and the 165,000 barrels of available total shell storage capacity of the Spartanburg, SC terminal. The terminals are co-owned with and operated by CITGO Petroleum Corporation (“CITGO”).

(2) The physical location of this terminal is in Mobile, AL.

(3) The physical location of this terminal is in Chesapeake, VA.

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(4) The Portland, OR terminal is leased to us from LCP Oregon Holdings LLC (“LCP Oregon”), an entity owned by CorEnergy.

(5) The capacity represents the full capacity of the LNG Facility. We own a 10.3% interest in Gulf LNG Holdings which owns the LNG Facility.

Terminals

Each of our terminals has unique operating characteristics that determine the available product and customer slate for that location. The following specific terminal descriptions provide details regarding each of our facilities:

Baltimore, Maryland. The Baltimore terminal is a pipeline/marine facility located on property adjoining the Chesapeake Bay in Baltimore, MD. We have co-owned the facility equally with CITGO since we acquired our 50% undivided ownership interest in the facility in February 2010. CITGO is the operator of the terminal under a long-term co-tenancy in common agreement. The 20-acre site has 22 storage tanks with a total shell storage capacity of 884,000 barrels, of which 442,000 barrels are available to our customers. The terminal receives, stores and delivers gasoline, distillates and ethanol. Products are received and/or delivered via pipeline, railroad, marine barge or truck loading rack. The terminal has unit train unloading capabilities from a neighboring rail facility, which offers our customers the ability to deliver unit trains of ethanol into the terminal. The terminal offers bunkering services, ethanol blending and additive systems as ancillary services to our customers.

Blakeley, Alabama. The Blakeley terminal is a marine facility located on property adjoining the Tensaw River in Mobile, AL. We have owned and operated the facility since we acquired the partially constructed facility in May 2010. The 14-acre site has eight tanks with a total shell storage capacity of 708,000 barrels. The terminal receives, stores and delivers asphalt, crude oil, fuel oil, recycled lube oils and sulfuric acid. Products are received and/or delivered via marine vessel (up to Aframax size vessels) or truck loading rack. The terminal offers both a steam and hot oil heating system, as well as blending, as ancillary services to its customers. The terminal is permitted for the construction of another 230,000 barrels of storage and has incremental land available to construct an additional 700,000 barrels of storage. The terminal is capable of connecting to a proprietary pipeline that feeds a major oil company refinery.

Brooklyn, New York. The Brooklyn terminal is a pipeline/marine facility on property adjoining Newtown Creek in Brooklyn, NY. We have owned and operated the facility since we acquired the facility in February 2013. The six-acre site has 10 tanks with a total shell storage capacity of 63,000 barrels. The terminal receives, stores and delivers gasoline and ethanol. Products are received via pipeline, marine barge or truck loading rack and delivered via truck. The terminal offers one generic and two proprietary gasoline additive systems as ancillary services to its customers.

Chickasaw, Alabama. The Chickasaw terminal is a rail/marine facility located on property adjoining the Tensaw River in Chickasaw, AL. We have owned and operated the facility since we acquired the facility in May 2010. The 16-acre site has 17 tanks with a total shell storage capacity of 609,000 barrels. The terminal receives, stores and delivers fuel oils, crude tall oil, marine diesel, and black liquor soap. Products are received and/or delivered via railroad, marine barge or truck loading rack. The terminal offers steam heating, blending and railcar unloading/management as ancillary services to our customers.

Chillicothe, Illinois. The Chillicothe terminal is an inland facility located in Chillicothe, IL. We have owned and operated the facility since we acquired the facility in July 2007. The 33-acre site has 13 tanks with a total shell storage capacity of 273,000 barrels. In the first quarter of 2013, the pipeline supplying the Chillicothe terminal was shut-in, and as a result, the terminal is only capable of receiving or delivering gasoline, distillates, ethanol and biodiesel via truck. The Chillicothe terminal is currently in a non-operational status but is being maintained for future opportunities, which include the development of rail and marine loading and unloading capabilities to support commercial opportunities with new customers.

Cleveland, Ohio—North. The Cleveland North terminal is a pipeline/marine facility located in Cleveland, OH adjoining to the Cuyahoga River and is connected by pipeline to the Cleveland, OH—South Terminal. We have owned and operated the facility since we acquired it in July 2007. The 10-acre site has 23 tanks with a total shell storage capacity of 426,000 barrels. The terminal receives, stores and delivers gasoline, distillates, ethanol and biodiesel. Products are received and/or delivered via pipeline, railroad, marine (up to Lake Tankers) or truck loading rack. The terminal offers railcar unloading, biodiesel blending, ethanol blending and proprietary and generic additive systems as ancillary services to our customers.

Cleveland, Ohio—South. The Cleveland South terminal is a pipeline/marine facility connected by pipeline to the Cleveland, OH-North Terminal. We have owned and operated the facility since we acquired it in July 2007. The three-acre site has seven tanks with a total shell storage capacity of 191,000 barrels. The terminal receives, stores and delivers gasoline, distillates, ethanol and biodiesel. Products are received and/or delivered via pipeline, railroad, marine or truck loading rack. The terminal offers railcar unloading, biodiesel blending, ethanol blending and additive systems as ancillary services to our customers.

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Madison, Wisconsin. The Madison terminal is a pipeline facility located in Madison, WI. We have owned and operated the facility since we acquired the facility in July 2007. The seven-acre site has five tanks with a total shell storage capacity of 150,000 barrels. The terminal receives, stores, and delivers gasoline, distillates, ethanol and biodiesel. Products are received and/or delivered via pipeline or truck loading rack. The terminal offers ethanol blending and additive systems as ancillary services to our customers.

Mobile, Alabama—Main. The Mobile–Main terminal is a marine facility on property adjoining the Tensaw River located in Mobile, AL. We have owned and operated the facility since we acquired the facility in February 2013. The 29-acre site has 63 tanks with a total shell storage capacity of 1,093,000 barrels and an additional 30 acres of undeveloped land available for expansion projects. The terminal receives, stores and delivers fuel oil, various grades of asphalts. Products are received and/or delivered via marine (up to Aframax size vessels) or truck loading rack. The terminal offers a steam heating system, emulsions and polymer mills and on-site product testing laboratory as ancillary services to our customers.

Mobile, Alabama—Methanol. The Mobile–Methanol terminal is a marine facility located in Mobile, AL connected by pipeline to the Mobile–Main terminal. We have owned and operated the facility since we acquired the facility in February 2013. The 11-acre site has two tanks with a total shell storage capacity of 294,000 barrels. The terminal receives, stores and delivers methanol. Product is received via ship (up to Aframax size vessels) and delivered via the truck loading rack.

Norfolk, Virginia. The Norfolk terminal is a pipeline/marine facility on property adjoining the Elizabeth River located in Chesapeake, VA. We have owned and operated the facility since we acquired the facility in July 2007. The 15-acre site has eight tanks with a total shell storage capacity of 212,600 barrels. The terminal receives, stores and delivers gasoline, distillates and ethanol. Products are received and/or delivered via pipeline, marine barge or truck loading rack. The terminal offers ethanol blending and additive systems as ancillary services to its customers.

Portland, Oregon. The Portland Terminal is a rail/marine facility adjacent to the Willamette River in Portland, OR. We operate the facility under a 15-year lease from LCP Oregon. The 39-acre site has 84 tanks with a total shell storage capacity of 1,466,000 barrels and is capable of receiving, storing and delivering crude oil, asphalt, aviation gasoline, jet fuel and distillates. Products are received and/or delivered via railroad, marine (up to Panamax size vessels) and a truck loading rack. The marine facilities are accessed through a neighboring terminal facility via pipelines. The Portland Terminal offers heating systems, emulsions and an on-site product testing laboratory as ancillary services.

Selma, North Carolina. The Selma terminal is a pipeline facility located in Selma, NC. We have owned and operated the facility since we acquired the facility in July 2007. The 21-acre site has five tanks with a total shell storage capacity of 171,000 barrels. The terminal receives, stores and delivers gasoline, distillates, ethanol and biodiesel. Products are received and/or delivered via pipeline or truck loading rack. The terminal offers ethanol blending and proprietary and generic additive systems as ancillary services to our customers.

Spartanburg, South Carolina. The Spartanburg terminal is a pipeline facility located in Spartanburg, SC. We have co-owned the facility equally with CITGO since we acquired our 50% ownership interest in the facility in October 2007. CITGO is the operator of the terminal under a long-term agreement. The nine-acre site has six tanks with a total storage capacity of 165,000, of which 82,500 barrels are available to our customers. The terminal currently receives, stores and delivers gasoline, distillates and ethanol. Products are received and/or delivered via pipeline or truck loading rack. The terminal offers ethanol blending and additive systems as ancillary services to our customers.

Toledo, Ohio. The Toledo terminal is a pipeline/marine facility adjoining the Maumee River in Toledo, OH. We have owned and operated the facility since we acquired the facility in July 2007. The seven-acre site has 10 tanks with a total storage capacity of 244,000 barrels. The terminal receives, stores, and delivers gasoline, aviation gasoline, distillates, and ethanol. Products are received and/or delivered via pipeline, railroad or truck loading rack. The terminal offers ethanol blending and additive systems as ancillary services to our customers.

Rail/Transloading Facilities

The following descriptions provide details regarding each of our transloading facilities:

Chickasaw, Alabama. The Chickasaw facility is a rail transloading/unloading facility located in Chickasaw, AL. We have owned and operated the facility since we acquired the facility in May 2010. The site has 18 railcar unloading spots, capable of servicing heated/non-heated petroleum product railcars. Products are received and/or delivered via railroad and delivered into tanks at the terminal or directly into trucks.

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Portland, Oregon. The Portland facility is a rail transloading/unloading facility located in Portland, OR. We operate the facility under a 15-year lease from LCP Oregon since January 2014. The site has 30 railcar unloading spots, capable of servicing heated/non-heated petroleum product railcars. Products are received and/or delivered via railroad and delivered into tanks at the terminal.

Saraland, Alabama. The Saraland facility is a rail transloading/unloading facility located in Saraland, AL. We have owned and operated the facility since we acquired the facility in February 2013. The site has 26 railcar unloading spots, all of which are currently capable of servicing heated/non-heated petroleum product or chemical railcars. Products are received and/or delivered via railroad and unloaded to the truck loading racks.

LNG Facility

The LNG Facility is a regasification facility adjoining the Gulf of Mexico in Pascagoula, MS. The state-of-the-art LNG Facility commenced commercial operations in October 2011. An affiliate of Kinder Morgan, Inc. (“Kinder Morgan”) owns 50% and is the operator of the terminal under a long-term management agreement. The 33-acre site has two tanks with a total storage capacity of 320,000 cubic meters and peak natural gas delivery rate of 1.5 billion cubic feet per day. The terminal has the ability to receive, store and regasify LNG. Products are received via marine vessel and delivered to third-party customers via pipeline. The facility has three primary interconnects to major pipeline networks including the Gulfstream Pipeline, Destin Pipeline, and the Pascagoula Supply Line. As of December 31, 2014, approximately 100% of the capacity was under contract through two multi-year terminal use agreements with remaining terms of approximately 17 years with firm reservation charges that commit payments regardless of product throughput. While the LNG Facility remains operationally ready to receive LNG, the customers of the LNG Facility are not currently shipping LNG cargoes to the LNG Facility for storage and regasification services due to global natural gas supply and demand economics. However, the customers of the LNG Facility continue to honor their contractual commitments under the terminal use agreements.

Customers and Competition

Customers

Our terminals collectively provide terminalling, storage, throughput and transloading services to 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.

As of December 31, 2014, our terminals had service agreements with 69 customers, with our top ten customers by revenue having been customers at our facilities for an average of more than seven years. The following table presents percentage of revenues associated with our top two and five customers, respectively, for the periods indicated:

	For the Year Ended December 31,
	2014			2013			2012
Chevron U.S.A. Inc.		19	%		3	%		2	%
Center Oil		13	%		16	%		42	%
Total percentage of top 5 customers		55	%		49	%		66	%

Outside of those customers listed above, no other customer accounted for 10% or more of our revenues during the years ended December 31, 2014, 2013 and 2012.

Contracts

We enter into services agreements with customers to provide terminalling, storage, throughput and transloading services, for which we charge storage and/or throughput fees and/or ancillary services fees. Due to our geographic diversity, certain customers utilize multiple facilities and may have multiple services agreements.

The services agreements we enter into with customers typically have terms of one month to ten years. Many customers initially enter into long-term contracts that contain evergreen provisions that automatically renew for terms of one month up to three years. The services agreements are customer specific and can provide a combination of terminalling, storage, throughput, transloading and ancillary services. As of December 31, 2014, approximately 70% of our services agreements are operating under evergreen provisions. As of December 31, 2014, the weighted-average remaining term for all of our services agreements was approximately three years. As of December 31, 2014, 71% of our capacity was under contract.

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The terminal use agreements associated with the LNG Facility are two multi-year terminal use agreements with a remaining term of approximately 17 years with firm reservation charges that obligate the customers to make payments regardless of throughput activity. The contracts began when the LNG Facility commenced operations in October 2011 and are for 100% of the rated capacity of the LNG Facility. The contracts consist of a firm reservation charge for the reserved capacity and an operating fee for the reserved capacity that adjusts annually for inflation based on the Producer Price Index. The contractual obligations under the terminal use agreement with ENI USA Gas Marketing are supported by a parent guarantee, and the contractual obligations under the terminal use agreement with Angola LNG Supply Services are supported by parent guarantees from the consortium members that each cover a portion of the obligations thereunder.

Competition

We compete with other independent terminal operators as well as major oil companies on the basis of terminal location, services provided, safety and price. Competition from terminal operators primarily comes from refiners and distribution companies with marketing and trading functions. These companies tend to prioritize movement of their own products over their third-party customers. Accordingly, we believe that we are able to compete successfully because of our dependable service and our experience in responding to customer needs without conflicts.

Many major oil companies own extensive terminal networks. Although such terminals often have the same capabilities as terminals owned by independent operators, their primary focus is not on providing terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation modes. Major energy and chemical companies also need independent terminal storage when their own storage facilities are inadequate, either because of availability, size constraints, optionality, the nature of the stored material or specialized handling requirements.

We believe that we are favorably positioned to compete in the industry due to the strategic location of our terminals, their access to various transportation modes, our independent strategy, our reputation, the prices we charge for our services and the quality, safety and versatility of our operations. The competitiveness of our service offerings, including the rates we charge for new contracts or contract renewals, is affected by the availability of storage, throughput and rail capacity relative to the overall demand for storage and throughput or rail capacity in a given market area and could be significantly impacted by the entry of new competitors into the markets in which we operate. However, we believe that significant barriers to entry exist in the terminalling, storage and logistics business. These barriers include capital costs, execution risk, a lengthy permitting and development cycle, financing challenges, shortage of personnel with the requisite expertise and a finite number of sites suitable for development.

Seasonality

The volume of throughput in our facilities is directly affected by the regional supply and demand for crude oil and petroleum products in the markets served directly or indirectly by our assets, which can fluctuate throughout the year. Certain of our facilities provide local markets with crude oil, fuel oil, gasoline, distillate products and asphalt products and the throughput activity can vary based on refining output, summer travel activity, winter heating requirements and construction-related activities. However, the impact of seasonality on our revenues will be substantially mitigated, as the significant majority of our revenues are generated through fixed monthly fees for storage and throughput services under multi-year take or pay contracts.

Employees

As of December 31, 2014, we employed 95 people who provide direct support to our operations. Only seven of our employees, or approximately 7%, are covered by a collective bargaining agreement (the “CB Agreement”) with the Petroleum Trades Employees Union, an affiliate of Atlantic Independent Union, affiliated with Teamsters Local #312, for the employees at the Brooklyn, NY terminal. The CB Agreement expires on April 30, 2016. We consider our employee relations to be good.

In connection with the IPO, we entered into a services agreement with our General Partner and our Sponsor, which provides, among other matters, that our Sponsor will make available to our General Partner the services of our Sponsor’s executive officers and employees who serve as our General Partner’s executive officers. Please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance.”

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Environmental and Occupational Safety and Health Regulation

General

The operation of terminals, pipelines, and associated facilities in connection with the receiving, handling storage and throughput of crude oil, petroleum products, chemicals and LNG is subject to extensive and frequently-changing federal, state and local laws, and regulations relating to the protection of the environment and our employees. Compliance with these laws and regulations may require the acquisition of permits to conduct regulated activities; restrict the type, quantities, and concentration of materials stored and transported; require new technologies to control pollutants that may be emitted or discharged into or onto to the land, air, and water; restrict the handling and disposal of solid and hazardous wastes; mandate the use of specific health and safety criteria addressing worker protection; and require remedial measures to mitigate pollution from former and ongoing operations. Compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe they do not affect our competitive position, as the operations of our competitors are similarly affected.

We believe our facilities are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change by regulatory authorities, and continued or future compliance with such laws and regulations, or changes in the interpretation of such laws and regulations, may require us to incur significant expenditures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of injunctions that may limit or prohibit some or all of our operations. Additionally, a discharge of crude oil, petroleum products, chemicals or LNG into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs of remediation activities to comply with applicable laws and regulations and to resolve claims made by third parties for claims for personal injury or property damage. These impacts could directly and indirectly affect our business, and have an adverse impact on our financial position, results of operations, and liquidity.

Hazardous Substances and Wastes

To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, air, and surface water, and include measures to control pollution of the environment. These laws and regulations generally govern the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed. For instance, the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws, impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, transported or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency (the “EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we have the potential to generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites where our materials were disposed.

We also have the potential to generate solid wastes, including hazardous wastes, which are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including crude oil and petroleum products wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could increase our maintenance capital expenditures and operating expenses.

We currently own or operate properties where hydrocarbons and other hazardous materials are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other waste have been spilled or released by prior owners and operators on or under our properties. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties, including property in the surrounding areas near the properties, and wastes disposed thereon may be

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subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination to the extent we are not indemnified for such matters.

Air Emissions and Climate Change

Our operations are subject to the federal Clean Air Act, its implementing regulations, and comparable state and local statutes. These laws and regulations govern emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction and/or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, and use specific emission control technologies to limit emissions. While we may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions, we do not believe that our operations will be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHG”) present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, effective January 2, 2011, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs, pursuant to which these permitting programs have been designed to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, as well as certain onshore oil and natural gas production, processing, transmission, storage, and distribution facilities on an annual basis. Our operations are currently not a major source of GHG emissions but future expansions or changes in operations or regulations may bring about substantial costs to bring our facilities in compliance with new regulations.

In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for oil and natural gas that is produced, which could decrease demand for our storage and throughput services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

In June 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Though the plan does not regulate refineries, it sets a national carbon pollution standard that is projected to cut emissions produced by United States power plants by 2030, by 30% from 2005 levels.  Although states can choose to rely on the four measures set by the EPA to meet this goal, the states themselves will ultimately decide the means to use.  States can develop individual plans, or they can collaborate with other states. These measures states may employ include: renewable energy standards, efficiency improvements at plants, switching to natural gas, transmission efficiency improvements, energy storage technology, and expanding renewables or nuclear, and energy conservation programs.  Under the proposed rule, states will have until June 2016 to submit final plans, although extensions may be allotted if needed.  The final rule is expected to be issued by mid-summer 2015 and the emission reductions are scheduled to commence in 2020.  An Ohio-based coal company has already filed a legal challenge to the proposed rulemaking in the D.C. Circuit, and nine states have joined as amici.  If this rule is promulgated along the lines proposed and were extended beyond the power sector to fuels-related sectors, it could have an adverse effect on the demand for petroleum products and our operations.

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Water

Many of our terminals are located adjacent to or near rivers, lakes and other navigable waters. The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws restrict the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Any unpermitted discharge of pollutants could result in penalties and significant remedial obligations. The transportation and storage of crude oil, petroleum products or chemicals over and adjacent to water involves risk and subjects us to the provisions of the Oil Pollution Act of 1990 (“OPA”) and related state requirements. These requirements subject owners of covered facilities to strict, joint, and potentially unlimited liability for containment and removal costs, natural resource damages, and certain other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In some cases, in the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us.

Regulations under the Clean Water Act, the OPA and state laws also impose additional regulatory requirements on our operations. Spill prevention control and countermeasure requirements of federal laws and some state laws require containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture, or leak. For example, the Clean Water Act requires us to maintain spill prevention control and countermeasure plans at our facilities. In addition, the OPA requires that most oil transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. We maintain such plans, and where required have submitted updated plans and received federal and state approvals necessary to comply with the OPA, the Clean Water Act and related regulations. We have trained employees who serve as company emergency responders and also contract with various spill-response specialists to ensure appropriate expertise is available for any contingency, including spills of crude oil or petroleum products, from our facilities. These employees receive annual refresher emergency responder training as well as annual and other periodic drills and training to ensure that they are able to mitigate spills or other releases, and control site response activities, either on their own or, if necessary, until various third-party spill-response specialists whom we engage are able to respond. Supporting our company emergency responders, as necessary, are various third-party spill-response specialists with whom we contract so that we may ensure appropriate expertise is available for any contingency from our facilities, including potential spills of crude oil, petroleum products or chemicals.

Stormwater runoff may come in contact with potential contamination and is required by both federal and state agencies to be permitted. Water sampling is required and if within acceptable limits, is allowed to be discharged. If future regulations require the capture and possible treatment of stormwater runoff, we may incur significant additional operating expenses for our operations.

The Clean Water Act imposes substantial potential liability for the violation of permits or permitting requirements and for the costs of removal, remediation, and damages resulting from such discharges. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

Endangered Species Act

The Endangered Species Act restricts activities that may affect endangered species or their habitats. We believe that we are in compliance with the Endangered Species Act. As a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered or threatened before completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations or the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

Occupational Safety and Health

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state, and local government authorities and citizens. We believe our operations are in substantial compliance with applicable OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Safety and Maintenance

We perform preventive and normal maintenance on all of our storage tanks, terminals, and ancillary systems and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of those assets in accordance with applicable regulation. At our terminals, the storage tanks are subject to periodic external and internal inspections in accordance with the requirements of the American Petroleum Institute standard. Storage tanks designed for products with a vapor pressure of 1.52

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pound-force per square inch absolute, or greater, are equipped with internal floating roofs to prevent potentially flammable vapor accumulation. In addition, in these facilities we have vapor combustion/recovery units to minimize regulated emissions.

Our terminal facilities have response plans, spill prevention and control plans, and other programs in place to respond to emergencies. Our truck loading racks are protected with fire protection systems in line with the rest of our facilities. We continually strive to maintain compliance with applicable air, solid waste, and wastewater regulations.

Our terminal facilities have a certain level of fire protection that is dictated by local, state and federal regulations. Our older facilities have been grandfathered in to comply with previous versions of some of these regulations. If fire protection regulations change, we may be required to incur substantial costs to change or construct new fire protection measures at our facilities.

On our pipelines, we use several methods to protect against corrosion including external coatings and cathodic protection systems. We conduct all cathodic protection work in accordance with the requirements of federal law and industry standards such as the National Association of Corrosion Engineers standards. We continually monitor the effectiveness of these corrosion inhibiting systems. We also monitor the structural integrity of selected segments of our pipelines through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing, which conforms to federal, state and local standards. We accompany these assessments with a review of the data and mitigate or repair anomalies, as required, to ensure the integrity of the pipeline. We have initiated a risk-based approach to prioritizing the pipeline segments for future integrity assessments to ensure that the highest risk segments receive the highest priority for scheduling internal inspections or pressure tests for integrity.

Through our regulated pipeline, we are subject to extensive laws and regulations related to ownership, operation, and maintenance of a hazardous liquids pipeline. Federal guidelines for the U.S. Department of Transportation require companies to comply with regulations governing all aspects of design, operation, and maintenance including training, education, communication, and integrity. These regulations require pipeline operators to develop integrity management programs to evaluate pipelines and take precautions to protect “High Consequence Areas,” such as rivers, and highly populated areas. Although we plan to continue our various programs including integrity management, future changes or interpretations to the regulations could significantly increase the costs of compliance. In the normal course of our operations, we may incur significant and unanticipated capital and operating expenditures to perform recommended or required repairs and/or upgrades to ensure the continued safe and reliable operation of our pipeline.

Title to Properties and Permits

We believe we have all of the assets needed, including leases, permits and licenses, to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.

We believe we have satisfactory title to all of our assets. Title to property may be subject to encumbrances. We believe that none of these encumbrances will materially detract from the value of our assets, nor will they materially interfere with the use of the assets in the operation of our business.

Insurance

Terminals, storage tanks and similar facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We are insured under our property, liability and business interruption policies, subject to the deductibles and limits under those policies, which we believe are reasonable and prudent under the circumstances to cover our operations and assets. However, such insurance does not cover every potential risk associated with our operating pipelines, terminals and other facilities, and we cannot ensure that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage, or that these levels of insurance will be available in the future at commercially reasonable prices. As we continue to grow, we will continue to monitor our policy limits and retentions as they relate to the overall cost and scope of our insurance program.

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Available Information

Our principal executive offices are located at 725 Fifth Avenue, 19th Floor, New York, NY 10022, and our phone number is (212) 993-1290. We file annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operations of the Public Reference Room by calling the SEC at (800) SEC-0330. In addition, the SEC maintains an Internet website at www.sec.gov that contains reports and other information regarding issuers that file electronically with the SEC.

We also make available free of charge our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, simultaneously with or as soon as reasonably practicable after filing such materials with, or furnishing such materials to, the SEC, on or through our Internet website at www.arcxlp.com. In addition to the reports we file or furnish with the SEC, we publicly disclose material information from time to time in our press releases, in publicly available conferences and investor presentations and through our website. The information on our website, or information about us on any other website, is not incorporated by reference into this Annual Report on Form 10-K.

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ITEM 1A. RISK FACTORS

There are many factors that may affect our business, financial condition and results of operations as well as investments in us. Unitholders and potential investors in our common units should carefully consider the risk factors set forth below, as well as the other information set forth elsewhere in this Annual Report on Form 10-K. If one or more of these risks were to materialize, our business, financial condition, results of operations and cash available for distribution could be materially and adversely affected. In that case, we may be unable to make distributions on our common units, the trading price of our common units may decline and you could lose all or a significant part of your investment. The following known material risks could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf. Further, the risk factors described below are not the only risks we face. Our business, financial condition and results of operations may also be affected by additional risks and uncertainties that are not currently known to us that we currently consider immaterial or that are not specific to us, such as general economic conditions.

Risks Inherent in Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our General Partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.3875 per unit, or $1.55 per unit per year. The amount of cash we can distribute on our common and subordinated units principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

● the volumes of crude oil, petroleum products and chemicals that we handle;

● the terminalling, storage, throughput, transloading and ancillary services fees with respect to volumes that we handle;

● the market fundamentals (including global pricing benchmarks) surrounding the supply of and demand for crude oil, petroleum products and chemicals in the markets served by our facilities;

● the production of crude oil both domestically and abroad could cause significant volatility in the pricing of crude oil;

● the volatility of crude oil prices could significantly alter refinery feedstock costs and create fluctuations in the pricing of refined petroleum products;

● pricing differentials in supplying certain geographic markets with crude oil, petroleum products and chemicals;

● competition from industry participants in our geographic markets;

● damage to pipelines, facilities, rail infrastructure, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions, and other natural disasters and acts of terrorism;

● leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

● planned or unplanned shutdowns of the facilities owned by or supplying our customers;

● prevailing economic and market conditions;

● the risk of contract non-renewal or failure to perform by our customers, and our ability to replace such contracts and/or customers;

● difficulties in collecting our receivables because of credit or financial problems of customers;

● the effects of new or expanded health, environmental, and safety regulations;

● governmental regulation, including changes in governmental regulation of the industries in which we operate;

● the level of our operating, maintenance and general and administrative expenses;

● changes in tax laws; and

● force majeure events.

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In addition, the actual amount of cash we have available for distribution depends on other factors, some of which are beyond our control, including:

● the level and financing of capital expenditures we make;

● the cost of acquisitions;

● our debt service requirements and other liabilities;

● fluctuations in our working capital needs;

● our ability to borrow funds and access capital markets;

● restrictions contained in debt agreements to which we are a party; and

● the amount of cash reserves established by our General Partner.

Other additional restrictions and factors may also affect our ability to pay cash distributions.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions in a given period even though we record net income.

The amount of cash available for distribution depends primarily on our cash flow from operations, including working capital borrowings, and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

Our business would be adversely affected if the operations of our customers experienced significant interruptions. In certain circumstances, the obligations of many of our key customers under their services agreements may be reduced or suspended, which would adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

We are dependent upon the uninterrupted operations of certain facilities owned, operated, managed or supplied by our customers, such as exploration sites, refineries and chemical production facilities. Operations at our facilities and at the facilities owned, operated, or supplied by our suppliers and customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

● catastrophic events, including hurricanes and floods;

● environmental remediation;

● labor difficulties; and

● disruptions in the supply of products to or from our facilities, including the failure of third-party pipelines or other facilities.

Additionally, terrorist attacks and acts of sabotage could target oil and gas production facilities, refineries, processing plants, terminals, and other infrastructure facilities.

Our services agreements with many of our key customers provide that if any of a number of events occur, including certain of those events described above, which we refer to as events of force majeure, and such event significantly delays or renders performance impossible with respect to one of our facilities, usually for a specified minimum period of days, our customer’s obligations would be temporarily suspended with respect to that facility. In that case, a significant customer’s minimum storage and throughput fees may be reduced or suspended, even if we are contractually restricted from recontracting out the storage space in question during such force majeure period, or the contract may be subject to termination. There can be no assurance that we are adequately insured against such risks. As a result, any significant interruption at one of our facilities or inability to transport products to or from these facilities or to or from our customers for any reason would adversely affect our results of operations, cash flow, and ability to make distributions to our unitholders.

Our ownership in each of the Baltimore, MD and Spartanburg, SC terminals represents a 50% ownership interest without the right to be the operator of the facilities, giving us limited influence on daily operating decisions.

We own a 50% undivided interest in each of the Baltimore, MD and Spartanburg, SC terminals whereby the co-owner and operator, CITGO, operates the terminals pursuant to an operating agreement, and in the future we may acquire interests in other terminals in which we do not serve as operator. In these situations, we are dependent upon the operator to operate the terminals

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efficiently and in compliance with applicable regulations. If the operator does not operate the terminals in a manner that minimizes operating expenses and prevents service interruptions, our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders could be materially and adversely affected.

Our ownership in the LNG Facility represents a minority interest in Gulf LNG Holdings and our rights are limited. A decision could be made at Gulf LNG Holdings without requiring our approval and could have a material adverse effect on the cash distributions we receive from the LNG Interest.

We own a 10.3% interest in Gulf LNG Holdings and our Sponsor owns a 9.7% interest. Gulf LNG Holdings indirectly owns the LNG Facility. An affiliate of Kinder Morgan is the manager and operator of the LNG Facility and has the authority to manage and control the affairs of Gulf LNG Holdings. The governing documents relating to Gulf LNG Holdings require a supermajority vote on certain matters including:

● the sale of substantially all the assets;

● any proposed merger;

● incurrence of additional indebtedness not already approved by the existing equity holders;

● amendment to the organizational documents; and

● the filing of a voluntary petition in bankruptcy.

The supermajority vote requires one or more of the members, which, in the aggregate, hold more than 70% of the ownership interests of Gulf LNG Holdings. Due to these provisions and our limited ownership interest, a decision could be made at Gulf LNG Holdings without our approval that could have a material adverse effect on the business, financial condition and results of operations of Gulf LNG Holdings and the cash distributions we receive from our LNG Interest.

Gulf LNG Holdings has been exploring the development of a liquefaction project adjacent to the LNG Facility. While there are many factors that could alter the future development of this project, our ownership interest and the cash distributions we receive could be materially and adversely affected if Gulf LNG Holdings continues to support the liquefaction project and we do not participate.

Our financial results depend on the market fundamentals surrounding the price volatility and supply of and demand for crude oil, petroleum products and chemicals that we store, throughput and transload, among other factors.

The market fundamentals surrounding the supply of and demand for crude oil, petroleum products and chemicals in the markets served by our facilities could result in a significant reduction in storage, throughput or transloading in our facilities, which would reduce our cash flow and our ability to make distributions to our unitholders.

Factors that could impact market fundamentals include:

● lower supply of crude oil in the United States and Canada could lead to a decline in drilling activity in these areas due to a decrease in the market prices for crude oil or for other reasons;

● oversupply of crude oil in the domestic or global market could lead to lower crude oil and refined petroleum product prices which could result in reduced production of crude oil;

● lower prices for crude oil and refined products could impact product flows into and out of certain markets;

● pricing differentials in supplying certain geographic markets with crude oil, petroleum products and chemicals;

● fluctuations in demand for crude oil, such as those caused by refinery downtime or shutdowns;

● lower demand by consumers for petroleum products as a result of recession or other adverse economic conditions or due to higher prices caused by an increase in the market price of crude oil;

● the impact of weather on demand for crude oil, petroleum products and chemicals;

● higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of motor fuels;

● an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers; and

● the increased use of alternative fuel sources, such as ethanol, biodiesel, fuel cells, and solar, electric and battery-powered engines.

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The ability of our LNG Interest to generate cash is substantially dependent upon two terminal use agreements, and we will be materially and adversely affected if either customer fails to perform its contract obligations for any reason.

The distributions that we receive from the LNG Interest are dependent on the future financial results of the LNG Facility. The LNG Facility generates revenues on firm contracted capacity from its two customers, ENI USA Gas Marketing L.L.C. and Angola LNG Supply Services, LLC (which is a joint venture of several integrated, multi-national oil and gas companies), each of which has entered into a terminal use agreement with Gulf LNG Holdings and agreed to pay firm reservation and operating fees regardless of whether LNG is delivered, stored or regasified. Our cash distributions from the LNG Interest are dependent upon the LNG Facility and each customer’s willingness to perform its contractual obligations under its respective terminal use agreement. The contractual obligations under the terminal use agreement with ENI USA Gas Marketing are supported by a parent guarantee, and the contractual obligations under the terminal use agreement with Angola LNG Supply Services are supported by parent guarantees from the consortium members that each cover a portion of the obligations thereunder. Each of the terminal use agreements contains various termination rights. For example, each customer may terminate its terminal use agreement as a result of breaches of customary commercial covenants or if the LNG Facility:

● experiences a force majeure delay for longer than 18 months;

● fails to redeliver a specified amount of natural gas in accordance with the customer’s redelivery nominations; or

● fails to accept and unload a specified number of the customer’s proposed LNG cargoes.

Gulf LNG Holdings may not be able to replace these terminal use agreements on desirable terms, or at all, if they are terminated.

Due to global LNG supply/demand economics, the customers of Gulf LNG Holdings are not shipping LNG to the LNG Facility for storage and regasification services. Due to lower natural gas prices in the United States, the customers have an economic advantage in redirecting LNG vessels to other locations around the world. However, the contractual obligations of the terminal use agreements require the customers to continue paying the firm reservation and operating fees. This dynamic could result in non-performance from the customers to pay the firm reservation and operating fees under the terminal use agreements. While Gulf LNG Holdings would seek recourse under the customers’ parent guarantees, our business, financial conditions and results of operations and our ability to make quarterly distributions to our unitholders could be materially and adversely affected.

Gulf LNG Holdings is also exposed to the credit risk of each customer’s parent guarantor in the event that Gulf LNG Holdings is required to seek recourse under a customer’s parent guarantee. If either customer or its parent guarantor fails to perform its financial obligations to Gulf LNG Holdings under the terminal use agreement or the parent guarantee, respectively, our business, financial condition and results of operations and our ability to make quarterly distributions to our unitholders could be materially and adversely affected.

We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any of our key customers could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

A significant portion of our revenue is attributable to a relatively limited number of customers. For the year ended December 31, 2014, our five largest customers accounted for approximately 55% of our revenues. During this period, Chevron U.S.A. Inc., our largest customer represented approximately 19% of our revenues. Some of our customers may have material financial and liquidity issues or operational incidents. We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. Any material nonpayment or nonperformance by any of our key customers and our inability to re-market or otherwise use the affected storage capacity could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively limited number of customers for a substantial portion of our revenue.

We periodically evaluate whether the carrying values of our terminals may be impaired and could be required to recognize non-cash charges in future periods.

Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our terminals as well as any other long-lived assets in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated future cash flows of a long-lived asset, the carrying value may not be recoverable and, therefore, would require a write-down. The future cash flow estimates are based on historical results, adjusted to reflect our best estimate of future market and operating conditions. Accordingly, estimated future cash flows for our terminals can be impacted by demand for the crude oil and

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petroleum products that we store for our customers, volatility and pricing of crude oil and its impact on petroleum products prices, the level of domestic oil production and potential future sources of cash flows. For example, the Buckeye Pipeline, which provided petroleum products through a common carrier pipeline to our Chillicothe, IL terminal (“Chillicothe Terminal”), ceased product deliveries during the first quarter of 2013, and due to this change in the Chillicothe Terminal’s operating logistics, the Partnership evaluated the long-lived assets at the Chillicothe Terminal for impairment as of December 31, 2013 and December 31, 2014.  Based upon a market strategy to repurpose the Chillicothe Terminal, the Partnership’s estimate of undiscounted cash flows as of December 31, 2013 indicated that such carrying amounts were expected to be recovered. The Partnership re-evaluated the Chillicothe Terminal and based upon the inability to enter into a contract with new or existing customers, the Partnership recognized a non-cash impairment loss of approximately $6.1 million as of December 31, 2014. The net impact of this impairment is reflected in “Long-lived asset impairment” in the accompanying consolidated statement of operations and comprehensive income. We may continue to incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and may impact our ability to borrow funds under our Credit Facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

Our operations are subject to operational hazards and unforeseen interruptions, including interruptions from hurricanes,  floods or earthquakes, for which we may not be adequately insured.

Our operations are subject to operational hazards and unforeseen interruptions, including interruptions from hurricanes, floods or earthquakes, which have historically impacted certain of the East, Gulf and West Coast regions where our operations are located with some regularity. We may also be affected by factors such as adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures, disruptions in supply infrastructure or logistics, and other events beyond our control. In addition, our operations are exposed to other potential natural disasters, including tornadoes and storms. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations.

We are not fully insured against all risks incident to our business. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub-limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

The LNG Facility is no longer in a cryogenic state, but remains fully operational to receive, unload and regasify LNG vessels on behalf of its customers. However, because the LNG Facility is no longer in a cryogenic state, the process and timing to receive and unload an LNG vessel could trigger certain provisions in the terminal use agreements, which could adversely affect the profitability of and the cash distributions we receive from our LNG Interest.

Since October 2012, the storage tanks and other equipment in the LNG Facility have not been in a cryogenic state. While the LNG Facility remains operationally ready to receive and process LNG vessels on behalf of its customers, the current status of the facility could increase the timing requirements to receive and process any LNG vessels as the LNG Facility returns to a cryogenic state. The terminal use agreements include provisions whereby the increased timing to receive and process LNG vessels could trigger demurrage and/or excess boil-off penalties. The amount of any such penalty will vary based upon the commencement of the unloading process, the actual time it takes to unload the vessel as it relates to the allotted unloading time and the size of the LNG vessel.

Volatility in energy prices, certain market conditions or new government regulations could discourage our storage customers from holding positions in crude oil, petroleum products or chemicals, which could adversely affect the demand for our storage and throughput services.

We have constructed and will continue to construct new facilities in response to increased customer demand for storage and throughput services. Many of our competitors have also built new facilities. The demand for new facilities has resulted in part from our customers’ desire to have the ability to take advantage of profit opportunities created by volatility in the prices of crude oil, petroleum products and chemicals and certain conditions in the futures markets for those commodities. A condition in which future prices of petroleum products and crude oil are higher than the then-current prices, also called market contango, is favorable to commercial strategies that are associated with storage capacity as it allows a party to simultaneously purchase petroleum products or crude oil at current prices for storage and sell at higher prices for future delivery. Wide contango spreads combined with price structure volatility generally have a favorable impact on our results. If the price of petroleum products and crude oil is lower in the future than the then-current price, also called market backwardation, there is little incentive to store these commodities as current prices are above future delivery prices. In either case, margins can be improved when prices are volatile. The periods between these

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two market structures are referred to as transition periods. If the market is in a backwardated to transitional structure, our results from operations may be less than those generated during the more favorable contango market conditions. If the prices of crude oil, petroleum products and chemicals become relatively stable, or if federal and/or state regulations are passed that discourage our customers from storing those commodities, demand for our storage and throughput services could decrease, in which case we may be unable to renew contracts for our storage and throughput services or be forced to reduce the fees we charge for our services, either of which would reduce the amount of cash we generate.

Some of our current services agreements are automatically renewing on a short-term basis and may be terminated at the end of the current renewal term upon requisite notice. If one or more of our current services agreements is terminated and we are unable to secure comparable alternative arrangements, our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders could be adversely affected.

Some of our services agreements currently in effect are operating in the automatic renewal phase of the contract that begins upon the expiration of the primary contract term. Our services agreements generally have primary contract terms that range from one month up to ten years. Upon expiration of the primary contract term, these agreements renew automatically for successive renewal terms that range from one month to three years unless earlier terminated by either party upon the giving of the requisite notice, generally ranging from two to six months prior to the expiration of the applicable renewal term. For the year ended December 31, 2014, approximately 73% of our revenue was generated pursuant to take-or-pay provisions in our services agreements with a weighted average term remaining of approximately three years. As of December 31, 2014, approximately 70% of our services agreements are operating under their evergreen portions in the services agreements. If any one or more of our services agreements is terminated and we are unable to secure comparable alternative arrangements, we may not be able to generate sufficient additional revenue from third parties to replace any shortfall in revenue or increase in costs. Additionally, we may incur substantial costs if modifications to our terminals are required by a new or renegotiated services agreement. The occurrence of any one or more of these events could have a material impact on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Competition from other terminals that are able to supply our customers with comparable logistics and storage capacity at a lower price could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

We face competition from other facilities that may be able to supply our customers with integrated services on a more competitive basis, including access to pipelines with lower transportation rates to various markets in which we have limited connections. We compete with national, regional, and local terminal and storage companies, including major oil companies, of widely varying sizes, financial resources and experience. Our ability to compete could be harmed by factors we cannot control, including:

● prices offered by our competitors;

● logical costs to deliver crude oil or petroleum products to our competitors facilities;

● our competitors’ construction of new assets or redeployment of existing assets in a manner that would result in more intense competition in the markets we serve;

● the perception that another company may provide better service; and

● the availability of alternative supply points or supply points located closer to our customers’ operations.

Any combination of these factors could result in our customers utilizing the assets and services of our competitors instead of our assets and services or us being required to lower our prices or increase our costs to retain our customers, either of which could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Our expansion of existing assets and construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

A portion of our strategy to grow and increase distributions to unitholders is dependent on our ability to expand existing assets and to construct additional assets. The construction of a new facility, or the expansion of an existing facility, such as increasing capacity or otherwise, involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. Moreover, we may not receive sufficient long-term contractual commitments from customers to provide the revenue needed to support such projects. As a result, we may construct new facilities that are not able to attract enough storage or throughput customers to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

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If we undertake these projects, they may not be completed on schedule, on budget, or at all. Even if we receive sufficient multi-year contractual commitments from customers to provide the revenue needed to support such projects and we complete our construction projects as planned, we may not realize an increase in revenue for an extended period of time. For example, if we build a new terminal, the construction will occur over an extended period of time and we will not receive any material increases in revenues until after completion of the project. Any of these circumstances could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

If the business of our customers is adversely impacted due to increased regulation affecting the transportation of crude by rail, demand for services at our terminals and facilities could be materially reduced, which could  adversely affect our business, financial condition, results of operations, and ability to make distributions to our unitholders.

Recent derailments of railcars carrying crude oil have led to increased legislative and regulatory scrutiny over the safety of delivering crude by rail. Various industry groups and government agencies have implemented and are considering additional new rail car standards, railroad operating procedures and other regulatory requirements. Changing operating practices, as well as potential new regulations on tank car standards and shipper classifications, could adversely affect the business of our customers by, among other things, rendering the delivery of crude by rail to our facilities or terminals less economic or uneconomic. If the delivery of crude by rail to our terminals or facilities is materially affected by any currently proposed or additional new regulations (including by reducing the demand for our services by our customers), such event could adversely affect our business, financial condition, results of operation, and ability to make distributions to our unit holders.

If we are unable to make acquisitions on economically acceptable terms, our future growth would be limited and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

A portion of our strategy is also dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit. If we are unable to make acquisitions because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase agreements, or we are unable to obtain financing for these acquisitions on economically acceptable terms or we are outbid by competitors, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:

● mistaken assumptions about revenues and costs, including synergies;

● an inability to integrate successfully the businesses we acquire;

● an inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;

● the assumption of unknown liabilities;

● limitations on rights to indemnity from the seller;

● mistaken assumptions about the overall costs of equity or debt;

● the diversion of management’s attention from other business concerns;

● unforeseen difficulties operating in new product areas or new geographic areas; and

● customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources.

Revenues we generate from storage and throughput services fees vary based upon the level of activity at our facilities by our customers. Any changes to the market fundamentals surrounding the supply and demand for crude oil, petroleum products or chemicals we handle or any interruptions to the operations of certain of our customers could reduce the amount of cash we generate and adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

A substantial portion of our revenues is based on the throughput activity levels of our customers. The revenues we generate from storage and throughput services fees vary based upon the underlying services agreements and the volumes of products handled at our facilities. Our customers may not be obligated to pay us any storage or throughput services fees unless we move volumes of products across our truck loading racks, marine facilities or rail assets on their behalf. If one or more of our customers were to slow or suspend its operations, have difficulty supplying their products to our terminals, experience a decrease in demand for its products or

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find a more profitable geographic market to sell its products, our services and revenues under our agreements with such customers would be reduced or suspended, resulting in a decrease in the revenues we generate.

Any reduction in the capability of our customers to utilize third-party pipelines and railroads that interconnect with our terminals or to continue utilizing them at current costs could cause a reduction of volumes transported through our terminals.

The customers of our facilities are dependent upon connections to third-party pipelines and railroads to receive and deliver crude oil, petroleum products and chemicals. Any interruptions or reduction in the capabilities of these interconnecting pipelines or railroads due to testing, line repair, reduced operating pressures, or other causes in the case of pipelines, or track repairs or congestion, in the case of railroads, could result in reduced volumes transported through our terminals. If additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers on these interconnecting pipelines could be reduced, which could reduce volumes transported through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. In addition, if the costs to our customers to access these third-party pipelines or railroads significantly increase, the activity of our customers could be reduced and therefore our profitability will be impacted accordingly. Similarly, if railroads prioritize other customer’s railcars due to the railroad pursuing more favorable economics (i.e., longer haul vs. short haul), this may result in a reduction of volumes that can be delivered to or from our terminals. Any such increases in cost, interruptions, or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Many of our facilities have been in service for several decades, which could result in increased maintenance expenditures or remediation projects, which could adversely affect our business, results of operations, financial condition, and ability to make cash distributions to our unitholders.

Our facilities are generally long-lived assets. As a result, some of those assets have been in service for many decades. While we have implemented inspection programs in accordance with the standards set forth by the American Petroleum Institute, the age and condition of these assets could result in increased maintenance expenditures or remediation projects, such as in the case where we acquire terminal storage assets that have not been maintained to that standard. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition, and ability to make cash distributions to our unitholders.

We may incur significant costs and liabilities in complying with environmental, health and safety laws and regulations, which are complex and frequently changing.

Our operations involve the storage and throughput of crude oil, petroleum products and chemicals and are subject to federal, state, and local laws and regulations governing, among other things, the gathering, storage, handling, and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, the generation, management and disposal of wastes, and other matters otherwise relating to the protection of the environment. Our operations are also subject to various laws and regulations relating to occupational health and safety. Compliance with this complex array of federal, state, and local laws and implementing regulations is difficult and may require significant capital expenditures and operating costs to mitigate or prevent an adverse effect on the environment. Moreover, our industry is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances into the environment and neighboring areas, for which we may incur substantial liabilities to investigate and remediate. Failure to comply with applicable environmental, health, and safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, and injunctions limiting or prohibiting some or all of our operations.

We cannot predict what additional environmental, health, and safety legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. These expenditures or costs for environmental, health, and safety compliance could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

We could incur significant costs and liabilities in responding to contamination that occurs at our facilities.

Our terminal facilities have been used for the storage and throughput of crude oil, petroleum products and chemicals for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes from time to time may have been spilled or released at the terminal properties. In addition, the terminal properties were previously owned and operated by other parties and those parties from time to time also may have spilled or released hydrocarbons or wastes. The terminal properties are subject to federal, state, and local laws that impose investigatory and remedial obligations, some of which are joint and several or strict liability obligations without regard to fault, to address and prevent environmental contamination.

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We may incur significant costs and liabilities to address soil and groundwater contamination that occurs on our properties, even if the contamination was caused by prior owners and operators of our facilities.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

Our operations require numerous permits and authorizations under various federal and state laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes or incremental capital investments to limit impacts or potential impacts on the environment and/or health and safety. A violation of permits or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions, and/or facility shutdowns. In addition, major modifications of our operations could require modifications to our existing permits or upgrades to our existing pollution control equipment. Any or all of these matters could have a negative effect on our business, results of operations and cash flows.

Increased regulation of GHG emissions could result in increased operating costs and reduced demand for petroleum products as a fuel source, which could in turn reduce demand for our services and adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Combustion of fossil fuels, such as the crude oil and petroleum products we store and distribute, results in the emission of carbon dioxide into the atmosphere. In December 2009, the EPA published its findings that emissions of carbon dioxide and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes, and the EPA has begun to regulate GHG emissions pursuant to the Clean Air Act. Many states and regions have adopted GHG initiatives and it is possible that federal legislation could be adopted in the future to restrict GHG emissions.

There are many regulatory approaches currently in effect or being considered to address GHG, including possible future U.S. treaty commitments, new federal or state legislation that does in the case of California, and may as to other states impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA including a proposal from June 2014 regarding GHG emissions from the electric power sector. Future international, federal, and state initiatives to control carbon dioxide emissions or reduce the use of fossil fuels could result in increased costs associated with crude oil and petroleum products consumption, such as restrictions on the production of crude oil or natural gas, or costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such restrictions or increased costs could result in reduced demand for crude oil and petroleum products and some customers switching to alternative sources of fuel which could have a material adverse effect on our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Our operations are subject to federal and state laws and regulations relating to product quality specifications, and we could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of products we distribute to meet certain quality specifications.

Various federal and state agencies prescribe specific product quality specifications for petroleum products, including vapor pressure, sulfur content, ethanol content and biodiesel content. Depending upon the services agreement, changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions to our unitholders could be adversely affected. Violations of product quality laws attributable to our operations could subject us to significant fines and penalties as well as negative publicity.

Our executive officers and certain key personnel are critical to our business, and these officers and key personnel may not remain with us in the future.

Our future success depends upon the continued service of our executive officers and other key personnel. If we lose the services of one or more of our executive officers or key employees, our business, operating results and financial condition could be harmed.

Mergers among our customers and competitors could result in lower levels of activity at our terminals, thereby reducing the amount of cash we generate.

Mergers between our existing customers and our competitors could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the activity and associated revenues from these customers, and we could experience difficulty in replacing those lost volumes

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and revenues. Because most of our operating costs are fixed, a reduction in activity would result not only in less revenue but also a decline in cash flow of a similar magnitude, which would adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Restrictions in our credit facility agreement could adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders as well as the value of our common units.

We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to allow us to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our credit facility agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or expand or pursue our business, which may, in turn, adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders. For example, our credit facility agreement restricts our ability to, among other things:

● make cash distributions;

● incur indebtedness;

● create liens;

● make investments;

● engage in transactions with affiliates;

● make any material change to the nature of our business;

● enter into material leases;

● dispose of assets; and

● merge with another company or sell all or substantially all of our assets.

Furthermore, our credit facility agreement contains covenants requiring us to maintain certain financial ratios.

The provisions of our credit facility agreement may affect our ability to obtain future financing for and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit facility agreement could result in an event of default which could enable our lenders, subject to the terms and conditions of our credit facility agreement, to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates under our Credit Facility agreement or future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.

As of December 31, 2014, we had no derivatives outstanding. Although we have not historically entered into hedging transactions, from time to time we may use interest rate derivatives to hedge interest obligations on specific debt. In addition, interest rates on future debt offerings could be higher, causing our financing costs to increase accordingly. Our results of operations, cash flows and financial position could be adversely affected by significant increases in interest rates above current levels.

Terrorist attacks aimed at our facilities or surrounding areas could adversely affect our business.

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline, rail and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases,

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those of other pipelines, refineries, or terminals could materially and adversely affect our business, financial condition, results of operations, and ability to make quarterly distributions to our unitholders.

Cyber security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to, or otherwise disrupt, our pipeline control systems, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, including our pipeline control systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Risks Relating to Our Pending Acquisition of JBBR

We may not be able to consummate our pending acquisition of JBBR, which could adversely affect our business, financial condition, results of operations and ability to make distributions to our unitholders.

We have, through Arc Terminals Joliet Holdings LLC (“Arc Terminals Joliet Holdings” or the “Buyer”), our wholly-owned subsidiary that will, upon the closing of the acquisition of JBBR, be owned jointly by us and an affiliate of GE EFS, entered into a membership interest purchase agreement (the “JBBR Purchase Agreement”) to acquire from CenterPoint all of the membership interests of JBBR (the “JBBR Acquisition”). The JBBR Purchase Agreement contains customary closing conditions. It is possible that one or more closing conditions may not be satisfied or, if not satisfied, that such condition may not be waived by the other party to the JBBR Purchase Agreement. In addition, the Buyer’s obligation to consummate the closing of the JBBR Acquisition (the “JBBR Closing”) is not conditioned on the completion of our related debt or equity financing, and Buyer may fail to satisfy its obligation to consummate the JBBR Acquisition after all conditions precedent to such obligation have been satisfied.

Pursuant to the requirements of the JBBR Purchase Agreement and on behalf of Buyer, we furnished to CenterPoint a letter of credit issued by SunTrust Bank in the amount of $10 million (the “Letter of Credit”). Subject to CenterPoint’s right under the JBBR Purchase Agreement to seek specific performance, CenterPoint may draw down on the Letter of Credit as liquidated damages as its sole and exclusive remedy if the JBBR Purchase Agreement is terminated due to (i) Buyer’s material uncured breach of the JBBR Purchase Agreement that results in a failure of the Seller’s conditions to the JBBR Closing or (ii) Buyer’s failure to close the JBBR Acquisition within three business days after the date on which it is obligated to close pursuant to the terms of the JBBR Purchase Agreement. In the event Buyer fails to complete the JBBR Closing by the date the JBBR Closing is required to have occurred under the JBBR Purchase Agreement, the Seller may seek specific performance of Buyer’s obligation to enforce the Arc Equity Commitment Letter (as defined below), as well as the equity commitment letter delivered to Buyer by an affiliate of GE EFS, and fund the purchase price payable Buyer under the JBBR Purchase Agreement (the “JBBR Purchase Price”) if (i) all of the conditions to the JBBR Closing are satisfied, (ii) the JBBR Debt Financing (as defined below) has been funded or the parties providing the JBBR Debt Financing have confirmed in writing that the JBBR Debt Financing will be funded at the JBBR Closing and (iii) the Seller has confirmed in writing that if specific performance is granted and Buyer funds the JBBR Purchase Price, the Seller will take such actions within its control to cause the JBBR Closing to occur.

If we do not consummate the JBBR Acquisition for the reasons described above, or otherwise, and the Seller exercises the remedies described above (whether by drawing down on the Letter of Credit or exercising rights of specific performance), our business, financial condition, results of operations and ability to make distributions to our unitholders could be adversely affected.

The JBBR Acquisition is subject to substantial risks that could adversely affect our business, financial condition, results of operations and our ability to make distributions to our unitholders. The JBBR Acquisition involves potential risks, including, among other things:

● the validity of our assumptions about revenues, operating costs and capital expenditures of the Joliet Terminal;

● the validity of our assessment of environmental and other liabilities of JBBR;

● the costs associated with additional debt or equity capital, which may result in a significant increase in our interest expense and financial leverage resulting from the additional debt incurred to finance the JBBR Acquisition, or the issuance of the common units on which we will make distributions, either of which could offset the expected accretion to our unitholders from the JBBR Acquisition and could be exacerbated by volatility in the equity or debt capital markets;

● a failure to realize anticipated benefits arising out of the JBBR Acquisition, such as increased distributions, enhanced competitive position or new customer relationships;

● the incurrence of other significant charges arising out of the JBBR Acquisition, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

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● the limitations of the representations, warranties and indemnifications by the Seller in the JBBR Purchase Agreement, and our diligence into the business of JBBR;

● operating a significantly larger combined organization and adding new or expanded operations;

● difficulties in the assimilation of JBBR and the Joliet Terminal;

● our inability to replace the third-party terminal operator selected by CenterPoint to provide operating services to JBBR at the Joliet Terminal, or our inability to hire, train or retain qualified personnel to manage and operate the Joliet Terminal should the services of such third-party operator terminate;

● the potential impact of the announcement or consummation of the pending JBBR Acquisition on relationships, including with employees, suppliers, customers and competitors;

● coordinating geographically disparate organizations, systems and facilities; and

● the diversion of our management’s and employees’ attention from other business concerns.

If any of these risks materialize, the JBBR Acquisition may adversely affect our business, financial condition, results of operations and ability to make distributions to our unitholders.

The representations, warranties, and indemnifications by CenterPoint are limited in the JBBR Purchase Agreement, and our diligence into JBBR and the Joliet Terminal has been limited; as a result, the assumptions upon which our estimates of future results of the JBBR Acquisition have been based may prove to be incorrect in a number of material ways, resulting in us not realizing the expected benefits of the JBBR Acquisition.

The representations and warranties by the Seller are limited in the JBBR Purchase Agreement, and our diligence into the JBBR and Joliet Terminal has been limited. In addition, the JBBR Purchase Agreement does not provide any indemnities other than those specifically set forth in the JBBR Purchase Agreement, which are subject to the limitations set forth therein. As a result, the assumptions on which our estimates of future results of the Joliet Terminal have been based may prove to be incorrect in a number of material ways, resulting in us not realizing our expected benefits of the JBBR Acquisition, including anticipated increased cash flow.

Financing the JBBR Acquisition will materially increase our indebtedness.

Concurrent with entering into the JBBR Purchase Agreement, we delivered an equity commitment letter (the “Arc Equity Commitment Letter”) to the Buyer with respect to our ratable share (60%, or approximately $130 million) of the JBBR Purchase Price. We intend to finance a portion of our commitment under the Arc Equity Commitment Letter with the proceeds from the issuance of up to $75 million of our common units in a private placement pursuant to a unit purchase agreement that we entered into concurrent with our entering into of the JBBR Purchase Agreement. We expect that the remaining portion of our commitment under the Arc Equity Commitment Letter (or approximately $55 million), along with related fees and expenses, will be funded with borrowings under our revolving credit agreement, which we expect to be amended subject to the terms of a debt commitment letter (the “Debt Commitment Letter”) that our subsidiary, Arc Terminals Holdings, entered into with SunTrust Bank and an affiliate thereof concurrent with our entering into of the JBBR Purchase Agreement (the financing contemplated thereby, the “JBBR Debt Financing”). The increase in our indebtedness in connection with the JBBR Debt Financing may increase our interest expense and reduce our flexibility to respond to changing business and economic conditions or to fund capital expenditures or working capital needs.

The pendency of the JBBR Acquisition could adversely affect our and JBBR’s business and operations.

In connection with the pending JBBR Acquisition, some employees, suppliers, customers and competitors of us and of JBBR may delay or defer decisions, which could negatively impact the revenues, earnings, cash flows and expenses of us or JBBR, regardless of whether the JBBR Acquisition is completed. In addition, due to operating covenants in the JBBR Purchase Agreement, JBBR may be unable, during the pendency of the JBBR Acquisition, to pursue certain strategic transactions, undertake certain significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business.

The ability of JBBR to generate cash is substantially dependent upon two service agreements with a major oil company, and if the customer fails to perform its contract obligations for any reason, our business, financial condition and results of operations and ability to make distributions to our unitholders may be materially and adversely affected.

The Joliet Terminal will generate substantially all of its revenues from its major oil company customer, which has entered into a terminal services agreement and a throughput and deficiency agreement with JBBR. We may not be able to replace the terminal

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services agreement or the throughput and deficiency agreement on desirable terms, or at all, if either agreement is terminated. Furthermore, there is no guarantee that we will be able to attract and retain additional customers or develop additional sources of revenue for the Joliet Terminal. If the sole customer fails to perform its financial obligations to JBBR under the terminal services agreement and the throughput and deficiency agreement, our business, financial condition, results of operations and ability to make distributions to our unitholders could be materially and adversely affected.

The Joliet Terminal is under construction and has not commenced operations and may not perform as expected. The Joliet Terminal may fail to operate efficiently or reliably or as we expect, which could adversely affect our business, financial condition, results of operations and ability to make distributions to our unitholders.

Although the closing of the JBBR Acquisition is conditioned upon, among other things, the Joliet Terminal being commercially operable, the Joliet Terminal remains under construction. Our expectations of the operating performance of the Joliet Terminal are based on assumptions and estimates that we made without the benefit of any operating history of JBBR. The ability of the Joliet Terminal to meet our performance expectations is subject to the risks inherent in newly constructed crude-by-rail terminal and pipeline facilities and the construction of such facilities. The Joliet Terminal will be JBBR’s only operating asset and will initially generate all of its operating cash flow. It is possible that we will discover issues that adversely impact efficient and reliable operations, and the failure of the Joliet Terminal to perform as we expect could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Once construction is completed, the Joliet Terminal is subject to interruptions of supply as a result of its reliance on railroads for transportation of domestic crude oil.

Rail transportation serves as a critical link in the supply of crude oil to the Joliet Terminal. If the ability to transport crude oil by rail is disrupted because of accidents, weather interruptions, governmental regulation, congestion on rail lines, terrorism, other third-party action or casualty or other events, then JBBR could experience an interruption of supply or delivery, an increased cost of receiving crude oil or a decline in volumes unloaded at the Joliet Terminal. Recent railcar accidents have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by rail. Various industry groups and government agencies have implemented and are considering additional new rail car standards, railroad operating procedures and other regulatory requirements. Changing operating practices, as well as potential new regulations on tank car standards and shipper classifications, could increase time required to move crude oil to and from the Joliet Terminal, increase the cost of rail transportation and decrease the efficiency of JBBR’s receipts of crude oil by rail, any of which could materially reduce the volume of crude oil delivered by rail to the Joliet Terminal and adversely affect our financial condition, results of operations and cash flows.

We will not own 100% of the equity interests in JBBR, which may not be as effective in providing operational control as 100% ownership, and we may have conflicts of interests with our joint venture partner.

We have entered into a joint venture arrangement with an affiliate of GE EFS to own and manage JBBR and its business, including the Joliet Terminal. The Partnership will own (indirectly through its holdings in Buyer) 60% of JBBR following the JBBR Closing, and the consent of GE EFS or its affiliate (which will own, indirectly through its holdings in Buyer, 40% of JBBR following the JBBR Closing) will be required with respect to certain business decisions relative to the operation, ownership and governance of JBBR (and its subsidiaries) as well as with respect to the governance of Buyer, which is the entity that will ultimately be responsible for making distributions to us in respect of any distributions that it receives from JBBR. If there are disagreements between us and GE EFS regarding the business and operations of JBBR, we cannot assure you that we will be able to resolve such differences in a manner that will be in the best interests of JBBR. In addition, GE EFS, our joint venture partner with respect to the JBBR Acquisition and who owns an interest in our Sponsor and has the right to appoint a member to the Board of our General Partner, may (i) have economic or business interests or goals that are inconsistent with our interests, (ii) take actions contrary to our instructions, requests, policies or objectives, (iii) be unable or unwilling to fulfill its obligations with respect to JBBR, (iv) have financial difficulties or (v) have disputes with us as to the scope of its responsibilities and obligations. Any of these and other factors may materially and adversely affect the performance of JBBR, which may in turn materially and adversely affect our financial condition and results of operations.

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Risks Inherent in an Investment in Us

Our Sponsor owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations. Our General Partner and its affiliates, including our Sponsor, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Our Sponsor, Lightfoot, owns and controls our General Partner and appoints all of the directors of our General Partner. Although our General Partner has a duty to manage us in a manner that it believes is not adverse to our interests, the executive officers and directors of our General Partner also have a duty to manage our General Partner in a manner beneficial to our Sponsor. Therefore, conflicts of interest may arise between our Sponsor or any of its affiliates, including our General Partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates, including our Sponsor and its owners, over the interests of our common unitholders. These conflicts include the following situations, among others:

● our General Partner is allowed to take into account the interests of parties other than us, such as our Sponsor, in exercising certain rights under our partnership agreement, which has the effect of limiting its duty to our unitholders;

● neither our partnership agreement nor any other agreement requires our Sponsor to pursue a business strategy that favors us;

● our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limits our General Partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

● except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;

● our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

● our General Partner determines the amount and timing of any capital expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders, which, in turn, may affect the ability of the subordinated units to convert.

● our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

● our partnership agreement permits us to distribute up to $12.2 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

● our General Partner determines which costs incurred by it and its affiliates are reimbursable by us;

● our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

● our General Partner intends to limit its liability regarding our contractual and other obligations;

● our General Partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

● our General Partner controls the enforcement of obligations that it and its affiliates owe to us;

● our General Partner decides whether to retain separate counsel, accountants or others to perform services for us; and

● our General Partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our General Partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, our Sponsor, its owners and entities in which they have an interest may compete with us. Please read “—Our Sponsor, its owners and other affiliates of our General Partner may compete with us.”

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Our partnership agreement does not require us to pay any distributions at all. The board of directors of our General Partner may modify or revoke our cash distribution policy at any time at its discretion.

Our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our General Partner has adopted a cash distribution policy pursuant to which we intend to distribute quarterly at least $0.3875 per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our General Partner and its affiliates. However, the board may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters.

Investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all is determined by the board of directors of our General Partner, whose interests may differ from those of our common unitholders. Our General Partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our Sponsor or its affiliates to the detriment of our common unitholders.

Our General Partner intends to limit its liability regarding our obligations.

Our General Partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our partnership agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

It is our policy to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.

Our partnership agreement replaces our General Partner’s fiduciary duties to holders of our units.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:

● how to allocate business opportunities among us and its affiliates;

● whether to exercise its call right;

● how to exercise its voting rights with respect to the units it owns;

● whether to elect to reset target distribution levels; and

● whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

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Our partnership agreement restricts the remedies available to holders of our units for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

● whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

● our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith, meaning that it believed that the decision was not adverse to the interests of the partnership;

● our General Partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our General Partner or its officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

● our General Partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

(1) approved by the conflicts committee of the board of directors of our General Partner, although our General Partner is not obligated to seek such approval; or

(2) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our Sponsor, its owners and other affiliates of our General Partner may compete with us.

Our partnership agreement provides that our General Partner is restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership interest in us. However, affiliates of our General Partner, including our Sponsor and its owners, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Any investments or acquisitions by affiliates of our General Partner, including our Sponsor and its owners, may include entities or assets that we would have been interested in acquiring. In addition, our Sponsor and its owners may acquire interests in other publicly traded partnerships. Therefore, our Sponsor and its affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including its executive officers and directors, our Sponsor and its owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner, including our Sponsor and its owners, and result in less than favorable treatment of us and our unitholders.

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Our General Partner and, following a transfer, a majority of the holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our General Partner has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our General Partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. In the event of a reset of target distribution levels, it will be entitled to receive the number of common units equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution for the prior two quarters equal to the average of the distributions to our General Partner on the incentive distribution rights in the prior two quarters. We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our General Partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our General Partner in connection with resetting the target distribution levels.

Our General Partner may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels.

The incentive distribution rights held by our General Partner, or indirectly held by our Sponsor, may be transferred to a third party without unitholder consent.

Our General Partner or our Sponsor may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our Sponsor transfers the incentive distribution rights to a third party but retains its ownership interest in our General Partner, our General Partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if our Sponsor had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by our Sponsor could reduce the likelihood of our Sponsor accepting offers made by us relating to assets owned by it, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors, which could reduce the price at which our common units trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our General Partner or its board of directors. The board of directors of our General Partner, including the independent directors, is chosen entirely by our Sponsor, as a result of it owning our General Partner, and not by our unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot currently remove our General Partner without its consent.

If our unitholders are dissatisfied with the performance of our General Partner, they will have limited ability to remove our General Partner. Unitholders are currently unable to remove our General Partner without its consent because our General Partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 ²/₃% of all outstanding common and subordinated units voting together as a single class is required to remove our General Partner. As of December 31, 2014, our Sponsor owns an aggregate of 40.3% of our common and subordinated units. Also, if our General Partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of

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that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our General Partner liable for actual fraud or willful or wanton misconduct in its capacity as our General Partner. Cause does not include most cases of charges of poor management of the business.

We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

● our existing unitholders’ proportionate ownership interest in us will decrease;

● the amount of cash available for distribution on each unit may decrease;

● because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

● the ratio of taxable income to distributions may increase;

● the relative voting strength of each previously outstanding unit may be diminished; and

● the market price of the common units may decline.

Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of our Sponsor as the sole member of our General Partner to transfer its membership interests in our General Partner to a third party. After any such transfer, the new member or members of our General Partner would then be in a position to replace the board of directors and executive officers of our General Partner with their own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our General Partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

Our General Partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of the common units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our General Partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our General Partner from issuing additional common units and exercising its call right. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. As of December 31, 2014, our Sponsor owned 40.3% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our Sponsor will own 40.3% of our common units.

Our General Partner may amend our partnership agreement, as it determines necessary or advisable, to permit the General Partner to redeem the units of certain unitholders.

Our General Partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our General Partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

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There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.

As of December 31, 2014, we had 6,867,950 common units and 6,081,081 subordinated units outstanding. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period.  Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to our Sponsor.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our General Partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.

Cost reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to making any distribution on the common units, we will reimburse our General Partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. Our partnership agreement provides that our General Partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our General Partner and its affiliates will reduce the amount of cash available for distribution to our unitholders.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

● our quarterly distributions;

● our quarterly or annual earnings or those of other companies in our industry;

● announcements by us or our competitors of significant contracts or acquisitions;

● changes in accounting standards, policies, guidance, interpretations or principles;

● general economic conditions;

● the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

● future sales of our common units; and

● the other factors described in these “Risk Factors.”

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Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A General Partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a General Partner if a court or government agency were to determine that:

● we were conducting business in a state but had not complied with that particular state’s partnership statute; or

● your right to act with other unitholders to remove or replace the General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, the JOBS Act was signed into law. The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Our first annual assessment of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 is being made in this Annual Report on Form 10-K.  To comply with the requirements of being a publicly traded partnership, we have implemented and will continue to implement additional internal controls, reporting systems and procedures and have hired and will continue to hire additional accounting, finance and legal staff. These hires may be partnership employees, third party consultants or a combination of both. Furthermore, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act of 1933. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the year ending December 31, 2018. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to

35

maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our General Partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Our management team has limited experience managing our business as a stand-alone publicly traded partnership, and if they are unable to effectively manage our business as a publicly traded partnership our business may be affected.

Our management team has limited experience managing our business as a publicly traded partnership. Unlike private companies, publicly traded entities are subject to substantial rules and regulations, including rules and regulations promulgated by the SEC and rules governing listed entities on the NYSE. If we are unable to manage and operate our partnership as a publicly traded partnership, our business and results of operations may be adversely affected.

We have and will continue to incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we have and will continue to incur significant legal, accounting and other expenses that we did not incur prior to our IPO. In addition, the Sarbanes-Oxley Act of 2002 as well as rules implemented by the SEC and the NYSE require publicly traded entities to maintain various corporate governance practices that further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

We also incur significant expense with respect to director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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Gulf LNG Holdings may change its business or operations in a way that does not generate qualifying income without our consent. In that event, we would likely elect to hold the LNG Interest in a subsidiary treated as a corporation for federal income tax purposes, which would reduce cash available for distribution to our unitholders from the assets and operations of the LNG Facility.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly traded partnership such as ours to be treated as a corporation for federal income tax purposes. In order to maintain our status as a partnership for U.S. federal income tax purposes, 90% or more of our gross income in each tax year must be qualifying income under Section 7704 of the Internal Revenue Code.

Because we have a minority interest in Gulf LNG Holdings, without our consent, Gulf LNG Holdings may change their existing business or conduct other businesses in the future in a manner that does not generate qualifying income. If we determine such a change is likely or has occurred, we may elect to hold the LNG Interest in a subsidiary treated as a corporation for federal income tax purposes. In such case, this corporate subsidiary would be subject to corporate-level tax on its taxable income at the applicable federal corporate income tax rate, currently 35%, as well as any applicable state income tax rates. Imposition of a corporate level tax would significantly reduce the anticipated cash available for distribution from the Gulf LNG Holdings assets and operations to us and, in turn, would reduce our cash available for distribution to our unitholders. For a more thorough discussion of the risks related to our minority interest in Gulf LNG, please read “Risks Inherent in Our Business—Our ownership in the LNG Facility represents a minority interest in Gulf LNG Holdings and our rights are limited. A decision could be made at Gulf LNG Holdings without requiring our approval and could have a material adverse effect on the cash distributions we receive from the LNG Interest.”

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

You are required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute, you are required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. As of December 31, 2014, affiliates of our Sponsor directly and indirectly owned 40.3% of the total interests in our capital and profits. Therefore, a transfer by affiliates of our Sponsor of all or a portion of their interests in us, along with transfers by other unitholders, could result in a termination of us as a partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

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Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and amortization deductions and certain other items. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal income tax returns and pay tax on its share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS, and the outcome of any IRS contest, may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, he may

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no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We own assets and conduct business in several states, each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information required to be disclosed in this Item 2. is incorporated herein by reference to Part I, Item 1. “Business—Assets and Operations.”

ITEM 3. LEGAL PROCEEDINGS

Although we may, from time to time, be 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 will have a material adverse impact on our financial condition or results of operations.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common units, representing limited partner interests, are traded on the NYSE under the symbol “ARCX.” Initial trading of our common units commenced on November 6, 2013. Accordingly, no market for our units existed prior to that date. On November 12, 2013, we closed the IPO at a price to the public of $19.00 per common unit.

The following table sets forth the range of high and low sales prices per unit for our common units, as reported by the NYSE, and the quarterly cash distributions for the indicated periods:

	Price Range
Year ended December 31, 2014:	High	Low	Cash Distributions (1)	Record Date	Payment Date
Fourth Quarter	$25.40	$17.05	$0.4100	February 9, 2015	February 17, 2015
Third Quarter	$26.59	$22.25	$0.4100	November 10, 2014	November 17, 2014
Second Quarter	$26.89	$21.00	$0.4000	August 11, 2014	August 18, 2014
First Quarter	$22.08	$18.77	$0.3875	May 9, 2014	May 16, 2014

	Price Range
Year ended December 31, 2013:	High	Low	Cash Distributions (1)	Record Date	Payment Date
Fourth quarter (from November 6, 2013)	$22.27	$18.69	$0.2064 (2)	February 10, 2014	February 18, 2014

(1) Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.

(2) Represents the initial pro rata distribution of our minimum quarterly distribution for the period from November 13, 2013 through December 31, 2013.

As of March 6, 2015, there were 6,867,950 common units outstanding held by four unitholders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these unitholders of record. As of March 6, 2015, we had also outstanding 6,081,081 subordinated units. There is no established public market in which the subordinated units are traded. As of March 6, 2015, our Sponsor held approximately 1.0% of the common units and 84.6% of the subordinated units.

Cash Distribution Policy

Our partnership agreement provides that our General Partner will make a determination no less frequently than every quarter as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our General Partner has adopted a cash distribution policy that sets forth our General Partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, we expect to distribute to the holders of common and subordinated 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 we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner and its affiliates.

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

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Our partnership agreement generally provides that we will distribute cash each quarter in the following manner:

● first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.3875 plus any arrearages from prior quarters;

● second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.3875; and

● third, to all unitholders pro rata, until each has received a distribution of $0.4456.

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

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

We refer to additional increasing distributions to our General Partner as “incentive distributions.”

The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

The subordination period will end on the first business day after we have earned and paid at least (1) $1.55 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four quarter periods ending on or after September 30, 2016 or (2) $2.325 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distribution on the incentive distribution rights for a four-quarter period ending immediately preceding such date, in each case provided there are no arrearages on our common units at that time.

The subordination period will also end upon the removal of our General Partner other than for cause if no subordinated units or common units held by holder(s) of subordinated units or their affiliates are voted in favor of that removal. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

Securities Authorized for Issuance under Equity Compensation Plans

See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plan as of December 31, 2014.

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ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth the selected historical consolidated financial data of the Partnership for each of the last four years. The consolidated financial data presented as of and for the years ended December 31, 2014, 2013, 2012 and 2011 are derived from our audited historical consolidated financial statements. Our financial statements have been prepared in accordance with GAAP. The following table should be read in conjunction with the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K (in thousands, except operating data and per unit amounts).

	Year Ended December 31,
	2014			2013			2012			2011
Revenues:
Third-party customers	$	45,676		$	39,662		$	13,201		$	10,588
Related parties		9,230			8,179			9,663			10,441
		54,906			47,841			22,864			21,029
Expenses:
Operating expenses		27,591			19,291			7,266			6,957
Selling, general and administrative		9,396			7,116			2,283			2,179
Selling, general and administrative - affiliate		3,990			2,484			2,592			2,614
Depreciation		7,261			5,836			3,317			2,749
Amortization		5,427			4,756			624			649
Long-lived asset impairment		6,114			-			-			-
Total expenses		59,779			39,483			16,082			15,148
Operating income		(4,873	)		8,358			6,782			5,881
Other income (expense):
Gain on bargain purchase of business		-			11,777			-			-
Equity earnings from unconsolidated affiliate		9,895			1,307			-			-
Other income		17			48			4			1
Interest expense		(3,706	)		(8,639	)		(1,320	)		(491	)
Total other income (expenses), net		6,206			4,493			(1,316	)		(490	)
Income before income taxes		1,333			12,851			5,466			5,391
Income taxes		58			20			43			25
Net Income		1,275			12,831			5,423			5,366
Less: Net income attributable to preferred units		-			1,770			-			-
Net income attributable to partners' capital	$	1,275		$	11,061		$	5,423		$	5,366

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	Year Ended December 31,
	2014			2013			2012			2011
Earnings per limited partner unit, basic:
Common units	$	0.05		$	0.23		$	0.89		$	0.88
Subordinated units	$	0.05		$	1.56		$	0.89		$	0.88
Earnings per limited partner unit, diluted:
Common units	$	0.05		$	0.10		$	0.89		$	0.88
Subordinated units	$	0.05		$	1.56		$	0.89		$	0.88
Cash Distributions Declared Per Unit:	$	1.6075		$	0.2064
Statement of Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	23,566		$	14,388		$	10,010		$	7,850
Investing activities		(7,808	)		(167,704	)		(13,796	)		(11,055	)
Financing activities		(13,613	)		156,341			3,267			3,755
Other Financial Data:
Adjusted EBITDA (a)	$	30,177		$	23,978		$	10,862		$	9,280
Distributable Cash Flow (a)		24,131
Maintenance capital expenditures		2,522			2,583			917			635
Expansion capital expenditures		5,261			166,678			11,784			11,176
Balance Sheet Data (at period end):
Cash and cash equivalents	$	6,599		$	4,454		$	1,429		$	1,948
Total assets		331,588			339,366			131,764			122,895
Long-term debt (including current portion)		111,063			105,563			30,500			20,000
Total liabilities		118,522			111,974			34,221			24,694
Partners' capital		213,066			227,392			97,543			98,201
Operating Data:
Storage capacity (bbls)		6,425,100			4,959,100			3,509,100			3,119,100
Throughput (bpd)		69,543			70,683			40,942			30,716

(a) Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. For additional information regarding our calculation of Adjusted EBITDA and Distributable Cash Flow as well as a reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow, please see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Results of Operations—Adjusted EBITDA” and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Results of Operations—Distributable Cash Flow.”

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our historical performance and financial condition together with Part II, Item 6. “Selected Financial Data,” the description of the business appearing in Part I, Item 1. “Business,” and the consolidated financial statements and the related notes in Part II, Item 8. of this Annual Report on Form 10-K. 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 report, particularly in Part I, Item 1A. “Risk Factors” and under “Cautionary Statement Regarding Forward-Looking Statements.”

We have disclosed consolidated figures of the Partnership as if the Partnership had operated since the inception of Arc Terminals. The contribution of Arc Terminals to Arc Logistics in connection with the IPO was not considered a business combination accounted for under the purchase method as it was a transfer of assets under common control and, accordingly, balances have been transferred at their historical cost. The combined financial statements for the periods prior to the contribution on November 12, 2013 have been prepared using Arc Terminals’ historical basis in the assets and liabilities, and includes all revenues, costs, assets and liabilities attributed to Arc Terminals.

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 and petroleum products. 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, the construction of new facilities in existing or new markets and strategic acquisitions from our Sponsor and third parties.

Recent Developments

JBBR Acquisition

Through a joint venture arrangement with GE EFS, we agreed to acquire, subject to the terms and conditions of a definitive acquisition agreement, all of the membership interests of JBBR from CenterPoint for $216 million. JBBR's principal assets consist of a crude oil unloading terminal and a 4-mile crude oil pipeline, which are in the final stages of construction in Joliet, IL and are expected to be complete in mid to late April 2015. The acquisition consideration also includes an earn-out payable by the JBBR joint venture company (referred to below) to CenterPoint based upon petroleum product throughput volumes at the Joliet Terminal (including minimum volumes paid under customer contracts irrespective of physical deliveries of product thereunder). JBBR joint venture company’s earn-out obligations to CenterPoint will terminate upon the payment, in the aggregate, of $27 million.

At the closing of the acquisition, we will manage ongoing operations of the Joliet Terminal and own a 60% interest in the JBBR joint venture company. GE EFS will own the remaining 40%. The Joliet Terminal is expected to begin commercial operations by mid to late April 2015, and the acquisition will not close until the Joliet Terminal becomes commercially operable. Either we or Centerpoint may terminate the definitive acquisition agreement if the closing of the JBBR acquisition does not occur by May 18, 2015.

We will finance our approximate $130 million portion of the purchase price with net proceeds from the sale of common units in a private placement and from borrowings under its revolving credit facility. Institutional investors have committed to acquire, concurrently with the closing of the acquisition, approximately 4.4 million of our common units in a private placement at a price of $17.00 per unit, resulting in gross proceeds (before fees and expenses) to us of $75 million.

Once completed, the Joliet Terminal will have the capability to unload approximately 85,000 barrels of crude oil per day and will have approximately 300,000 barrels of storage and a 4-mile pipeline connection to a common carrier crude oil pipeline. The facility will have rail and marine access and capabilities as well as more than 80 acres of land available for future expansion. At closing, the Joliet Terminal will be supported by a terminal services agreement as well as a throughput and deficiency agreement with a major oil company, each with a term of three years based on minimum throughput volume commitments.

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The JBBR acquisition continues our existing business strategy to expand our market position and support the expansion plans of new and existing customers, while generating stable cash flows for our unit holders from quality assets supported by long-term contracts.

Portland Terminal

In January 2014, we extended our operational footprint and customer relationships into the West Coast market by executing a 15-year triple-net operating lease on a petroleum products terminal in Portland, OR. The Portland Terminal is a rail/marine facility adjacent to the Willamette River in Portland, OR. The 39-acre site has 84 tanks with a total storage capacity of 1,466,000 barrels and is capable of receiving, storing and delivering heavy and light petroleum products. Products are received and/or delivered via railroad, marine (up to Panamax size vessels) and a truck loading rack. The marine facilities are accessed through a neighboring terminal facility via a pipeline. The Portland Terminal offers heating systems, emulsions and an on-site product testing laboratory as ancillary services.

In connection with the Portland Terminal operating lease, Arc Terminals Holdings, as borrower, and Arc Logistics and its other subsidiaries, as guarantors, entered into the First Amendment. The First Amendment principally modified certain provisions of the Credit Facility agreement to allow Arc Terminals Holdings’ to enter into the Lease Agreement.

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 storage or throughput capacity, 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 when the existing contracted capacity is recontracted; (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 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) potential regulatory implications and/or changes to local, state and federal laws; 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 production and demand for crude oil and petroleum products. The production of and demand for crude oil and petroleum products are driven by many factors, including delivery costs, the price for crude oil and petroleum products, local and regional price dislocations, 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 and (2) the volumes we contract to store, throughput and transload if we are not able to extend or replace our existing customer contracts.

Prices of Crude Oil and Petroleum Products

Because we do not own any of the crude oil and petroleum products that we handle 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 changes 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. Extended periods of depressed or elevated pricing for crude oil and petroleum products can impact our customers’ product movements.

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. If the future prices of crude oil and petroleum products are

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lower than the then-current prices, also called market backwardation, our customers’ demand for excess storage capacity generally decreases.

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.

Economic Conditions

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, petroleum products and chemicals, we could experience a tightening of trade credit as a result of our customers’ inability to access their own credit.

Regulatory Environment

The movement and storage of crude oil, petroleum products and chemicals 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 December 31, 2014, we had an aggregate of over 120 acres of available land in Blakeley, AL, Mobile, AL, Chillicothe, IL, Baltimore, MD, Selma, NC, Brooklyn, NY, Toledo, OH, Portland, OR and Madison, WI that allows us to increase our rail, marine, truck and/or terminal capacity should either the crude oil or petroleum products market warrant incremental growth opportunities.

Factors Impacting the Comparability of Our Financial Results

Our future results of operations may not be comparable to our historical results of operations for the following reasons:

● We have incurred and anticipate continuing to incur incremental selling, general and administrative (“SG&A”) expenses as a result of being a publicly traded partnership, consisting of expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, NYSE listing, independent auditor fees, legal fees, investor relations activities, transfer agent fees, director and officer insurance and director compensation.

● Prior to the November 12, 2013 closing of the IPO, the historical consolidated financial statements do not include earnings from the LNG Interest acquired with proceeds from the IPO. We account for the LNG Interest under the equity accounting method.

● The acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY terminals closed in February 2013 and the historical consolidated financial statements do not reflect the full year impact of these acquisitions on earnings.

● We completed the construction of the Blakeley, AL truck rack and marine expansion projects in the fourth quarter of 2012 and the historical consolidated financial statements do not reflect the full impact of customer contracts that were executed as a result of these projects on earnings.

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● We completed the construction of the Chickasaw, AL and Saraland, AL crude-by-rail transloading expansion projects in the first quarter of 2013 and the historical condensed consolidated financial statements do not reflect the full impact of these earnings.

● In January 2014, we entered into the Lease Agreement.  The historical consolidated financial statements do not reflect the impact of these revenues and expenses in 2013.

● In July 2014, phantom unit awards were granted under separate phantom unit award agreements (each, a “Phantom Unit Agreement”) under our Long-Term Incentive Plan (the “2013 Plan”)and the historical consolidated financial statements do not reflect the impact of this expense in 2013 and the full year impact in 2014.

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 (i) storage and throughput services fees and (ii) ancillary services fees; (2) our operating and 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. As of December 31, 2014, the weighted average term remaining on our customer contracts was approximately three years, and our top ten customers by revenue have been customers at our facilities for an average of more than seven years. 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 and petroleum products. Many of our service agreements contain take-or-pay provisions whereby we generate revenue regardless of customers’ use of the facility. Storage and throughput services fees accounted for approximately 86% of our revenues for each of the years ended December 31, 2014 and 2013 and 83% of our revenues for the year ended December 31, 2012.

● Ancillary Services Fees. We generate revenues from ancillary services, such as heating, blending and mixing associated with our customers’ activity. The revenues we generate from ancillary services vary based upon customers’ activity levels. Ancillary services fees accounted for approximately 14% of our revenues for each of the years ended December 31, 2014 and 2013 and approximately 17% of our revenue for the year ended December 31, 2012.

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 on November 12, 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 December 31, 2014, the remaining term of each terminal use agreement is approximately 17 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

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during that period and the timing of these expenses. We incorporate preventative maintenance programs by scheduling maintenance over time to avoid significant variability in maintenance expenses and minimize their impact on our cash flow.

Selling, General and Administrative Expenses

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

Adjusted EBITDA

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

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

Distributable Cash Flow

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

The GAAP measure most directly comparable to Distributable Cash Flow is net income. Distributable Cash Flow should not be considered as an alternative to net income. 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.

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

	Year Ended December 31,
	2014			2013			2012
Net Income	$	1,275		$	12,831		$	5,423
Income taxes		58			20			43
Interest expense		3,706			8,639			1,320
Gain on bargain purchase of business		-			(11,777	)		-
Depreciation		7,261			5,836			3,317
Amortization		5,427			4,756			624
Long-lived asset impairment		6,114			-			-
One-time transaction expenses (a)		451			3,673			135
Non-cash unit-based compensation		3,154			-			-
Non-cash deferred rent expense (b)		2,731			-			-
Adjusted EBITDA	$	30,177		$	23,978		$	10,862
Cash interest expense		(3,398	)
Cash income taxes		(58	)
Maintenance capital expenditures		(2,522	)
Equity earnings from the LNG Interest		(9,895	)
Cash distributions received from the LNG Interest		9,827
Distributable Cash Flow	$	24,131

(a) The one-time transaction expenses for 2013 relate to the due diligence and transaction expenses associated with the purchase of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities; for 2014, such expenses relate to the execution of the Lease Agreement.

(b) The non-cash deferred rent expense relates to the accounting treatment for the Portland Terminal lease transaction.

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Results of Operations

The following table and discussion is a summary of our results of operations for the years ended December 31, 2014, 2013 and 2012 (in thousands, except operating data):

	Year Ended December 31,
	2014			2013			2012
Revenues:
Third-party customers	$	45,676		$	39,662		$	13,201
Related parties		9,230			8,179			9,663
		54,906			47,841			22,864
Expenses:
Operating expenses		27,591			19,291			7,266
Selling, general and administrative		9,396			7,116			2,283
Selling, general and administrative - affiliate		3,990			2,484			2,592
Depreciation		7,261			5,836			3,317
Amortization		5,427			4,756			624
Long-lived asset impairment		6,114			-			-
Total expenses		59,779			39,483			16,082
Operating income		(4,873	)		8,358			6,782
Other income (expense):
Gain on bargain purchase of business		-			11,777			-
Equity earnings from unconsolidated affiliate		9,895			1,307			-
Other income		17			48			4
Interest expense		(3,706	)		(8,639	)		(1,320	)
Total other income (expenses), net		6,206			4,493			(1,316	)
Income before income taxes		1,333			12,851			5,466
Income taxes		58			20			43
Net Income		1,275			12,831			5,423
Less: Net income attributable to preferred units		-			1,770			-
Net income attributable to partners' capital	$	1,275		$	11,061		$	5,423
Other Financial Data:
Adjusted EBITDA	$	30,177		$	23,978		$	10,862
Distributable Cash Flow	$	24,131
Operating Data:
Storage capacity (bbls)		6,425,100			4,959,100			3,509,100
Throughput (bpd)		69,543			70,683			40,942

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Storage Capacity. Storage capacity for the year ended December 31, 2014 increased by 1.5 million bbls, or 30%, compared to the year ended December 31, 2013. The increase was due to the storage capacity associated with the Portland Terminal lease transaction in January 2014.

Throughput Activity. Throughput activity for the year ended December 31, 2014 decreased by 1.1 mbpd, or 2%, compared to the year ended December 31, 2013. The decrease was due to reduced customer activity in Baltimore, MD, Blakeley, AL, Chickasaw, AL and Saraland, AL offset by the acquisition of the Mobile, AL and Brooklyn, NY terminals in February 2013 and additional customer activity from the Portland Terminal lease transaction in January 2014.

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Revenues. The following table details the types and amounts of revenues generated during the years ended December 31, 2014 and 2013 (in thousands, except percentages).

	Year Ended December 31,
	2014		2013		$ Change		% Change
Storage and throughput services fees	$	47,175	$	41,365	$	5,810		14	%
Ancillary services fees		7,731		6,476		1,255		19	%
Total revenues	$	54,906	$	47,841	$	7,065		15	%

Revenues for the year ended December 31, 2014 increased by $7.1 million, or 15%, compared to the year ended December 31, 2013. The $5.8 million, or 14%, increase in storage and throughput services fees was the result of the acquisition of the Mobile, AL and Brooklyn, NY terminals in February 2013, the addition of storage contracts at the Portland Terminal in January 2014, and the execution of new contracts in Brooklyn, NY, Cleveland, OH and Selma, NC, offset by reduced customer activity and the expiration of customer agreements in Baltimore, MD, Blakeley, AL, Chickasaw, AL and Saraland, AL. The $1.3 million, or 19%, increase in ancillary services fees was driven by the acquisition of the Brooklyn, NY, Mobile, AL and Saraland, AL facilities in February 2013, additional services provided to our customers in the Blakeley, AL, Saraland, AL and Portland, OR facilities and other ancillary services provided to customers at both our refined and heavy products terminals.

Operating Expenses. Operating expenses for the year ended December 31, 2014 increased by $8.3 million, or 43%, compared to the year ended December 31, 2013. The $8.3 million increase in operating expenses was the result of $9.5 million of operating expenses in Portland, OR, $1.1 million of operating expenses due to the acquisition of the Mobile, AL and Brooklyn NY terminals in February 2013 and $1.0 million of insurance expense partially offset by a $2.3 million reduction in contract labor in Blakeley, AL, Chickasaw, AL and Saraland, AL and the elimination of $0.3 million in tank rental expense for a customer in Mobile, AL. The $9.5 million of operating expenses associated with Portland, OR includes $6.5 million in expenses associated with a lease agreement, of which $2.7 million is related to deferred rent expense.

Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2014 increased by $3.9 million, or 41%, compared to the year ended December 31, 2013. The increase in SG&A expense was related to an increase in public company expenses including professional fees and allocations from our General Partner of $1.5 million and $3.2 million of unit-based compensation relating to the 2013 Plan, offset by a reduction in one-time transaction and due diligence related expenses of $2.3 million.

Depreciation and Amortization Expense. Depreciation expense for the year ended December 31, 2014 increased by $1.4 million, or 24%, compared to the year ended December 31, 2013, primarily due to the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 and the impact of the 2013 capital expenditures program.  Amortization expense for the year ended December 31, 2014 increased by $0.6 million, compared to the year ended December 31, 2013, primarily due to the acquisition of the Mobile, AL and Brooklyn, NY terminals in February 2013 and the amortization of the LNG Interest, partially offset by the elimination of amortization expense associated with contracts acquired in 2010.

Long-Lived Asset Impairment. The Partnership re-evaluated the Chillicothe, IL terminal and based upon the inability to enter into contracts with new or existing customers the Partnership recognized a non-cash impairment loss of approximately $6.1 million as of December 31, 2014.

Gain on Bargain Purchase of Business. As part of the purchase price allocation for the Brooklyn, NY terminal acquisition in 2013, it was determined that the fair value of the assets acquired exceeded the purchase price resulting in a one-time gain of approximately $11.8 million.

Equity Earnings from Unconsolidated Affiliate. At the closing of the IPO in November 2013, we acquired the LNG Interest. We account for the LNG Interest under the equity method of accounting. We have recorded four full quarters of equity earnings of $9.9 million for the year ended December 31, 2014, as compared to one partial quarter in 2013.

Interest Expense. Interest expense for the year ended December 31, 2014 decreased by $4.9 million, or 57%, compared to the year ended December 31, 2013.  The reduction in interest expense was related to the write-off of deferred financing fees associated with the Terminal Credit Facility (defined below) amendments in 2013 (as defined below, see “—Liquidity and Capital Resources—Credit Facility”) and the impact of lower interest rates due to the amendment and restatement of the Terminal Credit Facility in November 2013.

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Net Income. Net income for the year ended December 31, 2014 decreased by $11.6 million, or 90%, compared to the year ended December 31, 2013, primarily related to a non-cash long-lived asset impairment related to our Chillicothe, IL terminal of $6.1 million, the $6.5 million of rent expense associated with the Portland Terminal lease, a decrease in gain on bargain purchase of business of $11.8 million and $3.2 million of unit-based compensation associated with the 2013 Plan, offset by a reduction in one-time transaction and due diligence related expenses of $2.4 million, new customer activity in Portland, OR, a full period of operating results for the Mobile, AL, Saraland, AL and Brooklyn, NY acquisitions completed in February 2013, an increase in equity earnings from the LNG Interest of $8.6 million and a decrease in interest expense of $4.9 million.

Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2014 increased by $6.2 million, or 26%, compared to the year ended December 31, 2013. The increase in Adjusted EBITDA was primarily attributable to four full quarters of operating results for the Mobile, AL, Saraland, AL and Brooklyn, NY acquisitions completed in February 2013, new commercial activity in Portland, OR, the impact of the expansion projects completed in 2013 and the execution of customer agreements in Blakeley, AL, Brooklyn, NY, Cleveland, OH and Selma, NC.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Storage Capacity. Storage capacity for the year ended December 31, 2013 increased by 1.5 million bbls, or 41%, compared to the year ended December 31, 2012. The increase was due to the acquisition of the Mobile, AL and Brooklyn, NY terminals in February 2013 and the construction of 150,000 barrels of new storage capacity for a customer in Mobile, AL.

Throughput Activity. Throughput activity for the year ended December 31, 2013 increased by 29.7 mbpd, or 73%, compared to the year ended December 31, 2012. The increase was due to the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 and increased transloading and throughput activity in the East Coast and Gulf Coast facilities.

Revenues. The following table details the types and amounts of revenues generated during the years ended December 31, 2013 and 2012 (in thousands, except percentages).

	Year Ended December 31,
	2013		2012		$ Change		% Change
Storage and throughput services fees	$	41,365	$	19,064	$	22,301		117	%
Ancillary services fees		6,476		3,800		2,676		70	%
Total revenues	$	47,841	$	22,864	$	24,977		109	%

Revenues for the year ended December 31, 2013 increased by $25.0 million, or 109%, compared to the year ended December 31, 2012. The $22.3 million, or 117%, increase in storage and throughput services fees was the result of the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013, the execution of new customer agreements and increased customer activity. The $2.7 million, or 70%, increase in ancillary services fees was driven by the acquisition of the Mobile, AL and Saraland, AL facilities and increased activity as it relates to heating and blending in the Gulf Coast facilities.

Operating Expenses. Operating expenses for the year ended December 31, 2013 increased by $12.0 million, or 165%, compared to the year ended December 31, 2012. The increase in operating expenses was primary related to the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 as well as increased transloading and throughput activity in the Chickasaw, AL and Blakeley, AL terminals. The acquisitions and incremental activity led to an increase in contract labor of $3.2 million, salaries and wages of $2.9 million, utilities of $2.0 million, insurance expense of $1.3 million, property taxes of $0.5 million and regulatory compliance expense of $0.2 million.

Selling, General and Administrative Expenses. SG&A expenses for the year ended December 31, 2013 increased by $4.7 million, or 97%, compared to the year ended December 31, 2012. The increase in SG&A expense was related to an increase in non-recurring acquisition and IPO expenses of $3.8 million, professional fees of $0.4 million and salaries and wages of $0.3 million.

Depreciation and Amortization Expense. Depreciation expense for the year ended December 31, 2013 increased by $2.5 million, or 76%, compared to the year ended December 31, 2012, primarily due to the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013. Amortization expense for the year ended December 31, 2013 increased by $4.1 million, compared to the year ended December 31, 2012, primarily due to the acquisition of the Mobile, AL and Brooklyn, NY terminals in February 2013.

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Interest Expense. Interest expense for the year ended December 31, 2013 increased by $7.3 million, compared to the year ended December 31, 2012, primarily due to higher outstanding borrowings under our Credit Facility as a result of the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 as well as a write off of approximately $3.5 million in unamortized debt issuance cost related to prior debt financings.

Gain on Bargain Purchase of Business. As part of the purchase price allocation for the Brooklyn, NY terminal acquisition in 2013, it was determined that the fair value of the assets acquired exceeded the purchase price resulting in a one-time gain of approximately $11.8 million.

Equity Earnings from Unconsolidated Affiliate. At the closing of the IPO in November 2013, we acquired the LNG Interest. We account for the LNG Interest under the equity method of accounting. For the period since the IPO, we have recorded equity earnings of $1.3 million.

Net Income. Net income for the year ended December 31, 2013 increased by $7.4 million, or 137%, compared to the year ended December 31, 2012, primarily related to an increase in revenue of $25.0 million, the gain on bargain purchase of a business of $11.8 million and an increase in equity earnings from our LNG Interest of $1.3 million, offset by an increase in operating expenses of $12.0 million, an increase in SG&A expenses of $4.7 million primarily related to the transaction and IPO related expenses, and an increase in interest expense of $7.3 million, which includes a write off of approximately $3.5 million in unamortized debt issuance costs.

Adjusted EBITDA. Adjusted EBITDA for the year ended December 31, 2013 increased by $13.1 million, or 121%, compared to the year ended December 31, 2012. The increase in Adjusted EBITDA was primarily attributable to the acquisition activity in February 2013 (as explained above), as well as new service agreements and increased transloading and throughput activity, which resulted in an increase in revenues by $25.0 million offset by an increase in operating expenses of $12.0 million.

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 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.

On February 17, 2015, we paid a quarterly distribution of $0.41 per common unit and subordinated unit, which equates to $5.3 million per quarter, or $21.2 million per year, based on the number of common and subordinated units outstanding as of the record date. 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 any distribution.

Credit Facility

In January 2012, we entered into a $40.0 million revolving credit facility (the “Terminal Credit Facility”). The Terminal Credit Facility had an initial three-year term and bore interest based upon the London Interbank Offered Rate (“LIBOR”). In February 2013, concurrent with the financing of the acquisitions of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities, we amended the Terminal Credit Facility to include a $65.0 million term loan and a $65.0 million revolving line of credit.  As amended, the Terminal Credit Facility had an initial three-year term and bore interest based upon either the base rate or LIBOR, in each case, plus an applicable margin. Prior to the closing of the IPO, the outstanding balance on the amended Terminal Credit Facility was $112.6 million at an interest rate of 4.17%.

Concurrent with the closing of the IPO, we amended and restated the Terminal Credit Facility (the “Credit Facility”) with a syndicate of lenders, under which Arc Terminals Holdings is the borrower. The Credit Facility matures on November 12, 2018 and has up to $175.0 million of borrowing capacity.  As of December 31, 2014, we had borrowings of $111.1 million under the Credit Facility at an interest rate of 2.92%.  Based on the restrictions under our total leverage ratio covenant, as of December 31, 2014, we had $23.4 million of available capacity under the Credit Facility.

The Credit Facility is available to refinance existing indebtedness, 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 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

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of $10.0 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. We and each of our existing 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 leverage ratio, equal to, at our option, either (a) a base rate plus a range from 100 to 200 basis points per annum or (b) a LIBOR rate, plus a range of 200 to 300 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 plus 100 basis points per annum and (iii) the federal funds rate plus 0.50% per annum. The unused portion of the Credit Facility is subject to a commitment fee calculated based upon our 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 December 31, 2014, the Partnership was in compliance with such covenants. The negative covenants include restrictions on our ability to incur additional indebtedness, acquire and sell assets, create liens, enter into certain lease agreements, make investments and make distributions.

The Credit Facility requires us to maintain a 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 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 facility are unconditionally guaranteed by us and each of our existing subsidiaries (other than the borrower) and each of our future restricted subsidiaries.

Amendment to Credit Agreement

In January 2014, in connection with the Lease Agreement, Arc Terminals Holdings, a wholly owned subsidiary of us, as borrower, and Arc Logistics and its other subsidiaries, as guarantors, entered into the First Amendment to the Credit Facility agreement. The First Amendment principally modified certain provisions of the Credit Facility agreement to allow Arc Terminals Holdings to enter into the Lease Agreement relating to the use of the Portland Terminal.

Financing of the Partnership Equity Commitment

Debt Financing

In February 2015, our operating subsidiary, Arc Terminals Holdings, entered into the Debt Commitment Letter with SunTrust Bank and SunTrust Robinson Humphrey, Inc. (together, “SunTrust” and such letter, the “Debt Commitment Letter”) that (i) sets forth the terms and conditions of an incremental senior secured credit facility (the “Incremental Facility”) consisting of an increase to the revolving Credit Facility set forth in the Second Amended and Restated Revolving Credit Agreement, dated as of November 12, 2013 (as amended, the “Existing Credit Agreement”), in an amount such that the aggregate amount of all outstanding loans and commitments under the Existing Credit Agreement will not exceed $275 million and the effectiveness of which remains subject to the receipt of consents from the necessary lenders under the Existing Credit Agreement and (ii) pursuant to which SunTrust agreed to provide 100% of a backstop senior secured credit facility of up to $275 million (the “Backstop Commitment” and, together with the Incremental Facility, the “Debt Financing”) in order to refinance the Existing Credit Agreement in the event that consents are not received from the necessary lenders to approve the Incremental Facility.

PIPE Transaction

In February 2015, we entered into a Unit Purchase Agreement (the “PIPE Purchase Agreement”) with the purchasers named therein (the “PIPE Purchasers”) to sell 4,411,765 common units at a price of $17.00 per unit (the “Common Unit Purchase Price”) in a

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private placement (the “PIPE Transaction”). The Common Unit Purchase Price will be reduced by our first quarter 2015 distribution in respect of our Common Units if the closing of the PIPE Transaction is after the record date for such distribution. We will use the proceeds from the private placement (totaling $75 million before placement agent commissions and expenses) to fund a portion of our obligations under the Arc Equity Commitment Letter. If the PIPE Purchase Agreement is terminated pursuant to its terms, including on account of the termination of the JBBR Purchase Agreement or if the closing under the PIPE Purchase Agreement fails to occur by May 18, 2015, we shall pay to each PIPE Purchaser a commitment fee of 1% of such PIPE Purchaser’s commitment amount under the PIPE Purchase Agreement. During the period commencing on the date of execution of the PIPE Purchase Agreement and ending 90 days following the date of the closing of the PIPE Transaction, we are restricted under the PIPE Purchase Agreement from issuing, without the consent of the PIPE Purchasers holding a majority of the purchased Common Units (or, prior to closing, the PIPE Purchasers entitled to acquire at closing a majority of such Common Units), any of our equity securities except for, in general, our common units issued at or above a stated issuance price in (or to fund) an acquisition that is determined by the Board of Directors of our General Partner to result in an increase in our distributable cash flow over the first full four quarters following such acquisition. The issuance of the Common Units pursuant to the PIPE Purchase Agreement is being made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof.

Cash Flows

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

A summary of the changes in cash flow data for the years ended December 31, 2014 and 2013 are set forth in the following table (in thousands, except percentages):

	Year Ended December 31,
	2014			2013			$ Change			% Change
Net cash flows provided by (used in):
Operating activities	$	23,566		$	14,388		$	9,178			64	%
Investing activities		(7,808	)		(167,704	)		159,896		N/M
Financing activities		(13,613	)		156,341			(169,954	)	N/M

N/M indicates the metric is not meaningful.

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 $23.6 million for the year ended December 31, 2014 compared to $14.4 million for the year ended December 31, 2013.  This $9.2 million increase across periods was primarily attributable to a $7.4 million increase in distributions from our LNG Interest and a $1.6 million increase of cash provided by working capital.  Cash provided by changes in working capital of $1.6 million across the comparable periods was primarily due to the changes of cash provided by accounts receivable, other assets, amounts due to our General Partner and other liabilities of $4.1 million, $0.2 million, $0.4 million and $2.8 million, respectively, partially offset by cash used in changes due from related parties, accounts payable and accrued expenses of $0.3 million, $4.9 million and $0.7 million, respectively.

Cash Flow from Investing Activities. Investing activities consist primarily of capital expenditures for maintenance and expansion as well as property and equipment divestitures. Net cash used in investing activities was $7.8 million for the year ended December 31, 2014, of which $1.2 million related to the capital calls by Gulf LNG Holdings for its development of a natural gas liquefaction and export terminal at the LNG Facility. Net cash used in investing activities was $167.7 million for the year ended December 31, 2013, primarily for the purchase of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 in addition to capital spending related to the construction and improvements of our Blakeley, AL, Chickasaw, AL and Saraland, AL facilities.

Cash Flow from Financing Activities. Financing activities consist primarily of borrowings and repayments related to the Terminal Credit Facility and Credit Facility, the related deferred financing costs and distributions to our investors. Net cash flows used in financing activities was $13.6 million for the year ended December 31, 2014, compared to net cash provided by financing activities of $156.3 million for the year ended December 31, 2013. This $170.0 million decrease across periods was primarily attributable to a net decrease in borrowings of $69.6 million during the year ended December 31, 2014 and an increase in distributions to our investors of $16.4 million, offset by a decrease in deferred financing costs of $4.7 million. During the year ended December 31, 2013, we received net proceeds of $117.3 million in connection with our IPO and made a cash distribution to GCAC as partial consideration for the contribution of its preferred units in Arc Terminals to us of $29.0 million.

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Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

A summary of the changes in cash flow data for the years ended December 31, 2013 and 2012 are set forth in the following table (in thousands, except percentages):

	Year Ended December 31,
	2013			2012			$ Change			% Change
Net cash flows provided by (used in):
Operating activities	$	14,388		$	10,010		$	4,378			44	%
Investing activities		(167,704	)		(13,796	)		(153,908	)	N/M
Financing activities		156,341			3,267			153,074		N/M

N/M indicates the metric is not meaningful.

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 $14.4 million for the year ended December 31, 2013 compared to $10.0 million for the year ended December 31, 2012. This $4.4 million increase was primarily attributable to a $7.4 million increase and a $10.6 million increase in cash provided by net income and depreciation and amortization, respectively, partially offset by cash used in working capital of $1.8 million and the gain from a bargain purchase of a business of $11.8 million. Cash used in working capital of $1.8 million during the year ended December 31, 2013 was primarily due to increases in trade accounts receivable and other assets of $3.3 million and $0.7 million, respectively, partially offset by a $1.3 million decrease in amounts due to our General Partner and an increase in accrued expenses of $0.9 million.

Cash Flow from Investing Activities. Investing activities consist primarily of capital expenditures for maintenance and expansion as well as property and equipment divestitures. Net cash used in investing activities was $167.7 million for the year ended December 31, 2013. This cash was primarily used for the purchase of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 in addition to capital spending related to the construction and improvements of our Blakeley, AL, Chickasaw, AL and Saraland, AL facilities. Net cash used in investing activities was $13.8 million for the year ended December 31, 2012. This cash was primarily used for capital spending related to construction and improvements at our Blakeley, AL terminal.

Cash Flow from Financing Activities. Financing activities consist primarily of borrowings and repayments related to the Terminal Credit Facility and Credit Facility, the related deferred financing costs and distributions to our investors. Net cash flows provided by financing activities was $156.3 million for the year ended December 31, 2013, compared to $3.3 million for the year ended December 31, 2012. This $153.1 million increase was primarily attributable to the net proceeds of $117.3 million we received from the issuance of 6,786,869 common units in connection with our IPO, an increase in borrowings of $94.0 million related to the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities in February 2013 and a decrease in the distributions to our investors of $4.3 million offset by an increase in debt repayments of $29.4 million, an increase in deferred financing costs of $4.1 million and the cash distribution to GCAC as partial consideration for the contribution of its preferred units in Arc Terminals to the Partnership of $29.0 million.

Contractual Obligations

We have contractual obligations that are required to be settled in cash. Our contractual obligations as of December 31, 2014 were as follows:

	Payments Due by Period
			Less than		1-3		3-5		More than
	Total		1 year		years		years		5 years
Long-term debt obligations	$	111,063	$	-	$	-	$	111,063	$	-
Operating lease obligations		30,251		6,346		12,893		11,012		-
Total	$	141,314	$	6,346	$	12,893	$	122,075	$	-

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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 years ended December 31, 2014, 2013 and 2012 as set forth in the following table (in thousands):

	Year Ended December 31,
	2014		2013		2012
Maintenance capital expenditures	$	2,522	$	2,583	$	917
Expansion capital expenditures		5,261		166,678		11,784
Total capital expenditures	$	7,783	$	169,261	$	12,701

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) upgrade fire protection systems; (v) evaluate certain facilities regulatory programs; (vi) inspect and repair cathodic protection systems; (vii) inspect and repair tank infrastructure; and (viii) make other general facility repairs as required. Due to the nature of these projects we will incur additional capital expenditures in some years as compared to others. The significant increase in 2014 and 2013 as compared to 2012 was related to the acquisition of the Mobile, AL, Saraland, AL and Brooklyn, NY facilities.

Expansion Capital Expenditures.

In 2014, we invested capital to: (i) complete the fuel oil tank system and asphalt tank system in Mobile, AL for customer expansion opportunities; (ii) install a permanent boiler system in the Chickasaw, AL terminal; (iii) upgrade the marine infrastructure and truck rack in Cleveland, OH in connection with a new customer agreement; (iv) upgrade a tank in Blakeley, AL and Chickasaw, AL for new and existing customer agreements; and (v) complete carryover projects from 2013.

In 2013, we invested capital to: (i) acquire the Mobile, AL, Saraland, AL and Brooklyn, NY facilities and the LNG Interest (ii) construct 150,000 bbls of storage capacity in Mobile, AL; (iii) expand rail infrastructure in Chickasaw, AL and Saraland, AL; (iv) expand the Blakeley, AL dock to service Aframax capable vessels; (v) enhance the Blakeley, AL tank infrastructure to handle heated petroleum products; (vi) upgrade the Norfolk, VA truck unloading rack; and (vii) install new proprietary additive systems and unloading system upgrades at a number of facilities.

In 2012, we invested capital to: (i) purchase additional land in Blakeley, AL; (ii) construct a new truck unloading rack and associated tank infrastructure in Blakeley, AL; (iii) begin the installation of the new dock in Blakeley, AL; (iv) upgrade the dock in Norfolk, VA; and (v) bring an out of service tank in Norfolk, VA into service.

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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Recently Issued Accounting Pronouncements

For a discussion of recently issued accounting pronouncements that will affect us, see “Note 2—Summary of Significant Accounting Policies—Recently Issued Accounting Pronouncements” to our accompanying consolidated financial statements for the fiscal year ended December 31, 2014.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the reporting periods. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.

Listed below are the accounting policies we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.

Revenue Recognition. Revenues from leased tank storage and delivery services are recognized as the services are performed. Revenues also include the sale of excess products and additives that are mixed with customer-owned liquid products. Revenues for the sale of excess products and additives are recognized when title and risk of loss passes to the customer.

Depreciation. We calculate depreciation expense using the straight-line method, based on the estimated useful life of each asset. We assign asset lives based on reasonable estimates when an asset is placed into service. We periodically evaluate the estimated useful lives of our property, plant and equipment and revise our estimates.

The determination of an asset’s estimated useful life takes a number of factors into consideration, including technological change, normal depreciation and actual physical usage. If any of these assumptions subsequently change, the estimated useful life of the asset could change and result in an increase or decrease in depreciation expense. Subsequent events could cause us to change our estimates, which would impact the future calculation of depreciation expense.

Impairment of Long-Lived Assets. In accordance with Accounting Standards Codification No. 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we continually evaluate whether events or circumstances have occurred that indicate the carrying value of our long-lived assets, including property and equipment, may be impaired. In determining whether the carrying value of our long-lived assets is impaired, we make a number of subjective assumptions, including whether there is an indication of impairment and the extent of any such impairment. Factors we consider as indicators of impairment may include, but are not limited to, our assessment of the market value of the asset, operating or cash flow losses and any significant change in the asset’s physical condition or use. We evaluate the potential impairment of long-lived assets by comparison of estimated undiscounted cash flows for the related asset to the asset’s carrying value. Impairment is indicated when the estimated undiscounted cash flows to be generated by the asset are less than the asset’s carrying value. If the long-lived asset is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, calculated using a discounted future cash flow analysis.

These future cash flow estimates (both undiscounted and discounted) are based on historical results, adjusted to reflect our best estimate of future market and operating conditions. Uncertainty associated with these cash flow estimates include assumptions regarding demand for the crude oil and petroleum products that we store for our customers, volatility and pricing of crude oil and its impact on petroleum products prices, the level of domestic oil production, discount rates (for discounted cash flows) and potential future sources of cash flows. Although the resolution of these uncertainties historically has not had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

No impairment charges were recorded during the years ended December 31, 2014, 2013 and 2012 except as discussed in “Note 5—Property, Plant and Equipment” in our accompanying consolidated financial statements for the year ended December 31, 2014.

Unit-Based Compensation.  We recognize 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

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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.

Environmental and Other Contingent Liabilities. Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration, environmental remediation, cleanup or other obligations are either known or considered probable and can be reasonably estimated. At December 31, 2014 and 2013, we had no accruals for environmental obligations. Accruals for contingent liabilities are recorded when our assessment indicates that it is probable that a liability has been incurred and the amount of liability can be reasonably estimated. Such accruals may include estimates and are based on all known facts at the time and our assessment of the ultimate outcome. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. Presently, there are no material accruals in these areas. Although the resolution of these uncertainties historically has not had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Among the many uncertainties that impact our estimates of environmental and other contingent liabilities are the potential involvement in lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters, as well as the uncertainties that exist in operating our storage facilities and related facilities. Our insurance does not cover every potential risk associated with operating our storage facilities and related facilities, including the potential loss of significant revenues. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 and petroleum products that we handle and store. We do not intend to hedge our indirect exposure to commodity risk.

Interest Rate Risk

We will have exposure to changes in interest rates on our indebtedness. At December 31, 2014, we had $111.1 million of outstanding borrowings under the Credit Facility, bearing interest at variable rates. The weighted average interest rate incurred on the indebtedness as of December 31, 2014 was 2.50% per annum. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an estimated $1.4 million increase in interest expense for the year ended December 31, 2014, 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 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-29 of this Annual Report on Form 10-K and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under 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 Annual Report on Form 10-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 accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our General Partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2014 at the reasonable assurance level.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed under the supervision of our General Partner’s Chief Executive Officer and Chief Financial Officer, and effected by our General Partner’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with GAAP.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.  Also, projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of December 31, 2014, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013.  Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2014, based on those criteria.

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Attestation Report of the Registered Public Accounting Firm

Our independent registered public accounting firm is not required to formally attest to the effectiveness of our internal control over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2014 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of Arc Logistics

We are managed and operated by the board of directors and executive officers of our General Partner. As a result of owning our General Partner, our Sponsor has the right to appoint all members of the board of directors of our General Partner, including the independent directors. Our unitholders are not entitled to elect our General Partner or its directors or otherwise directly participate in our management or operations. Our General Partner owes certain contractual duties to our unitholders as well as to its owners.

Our General Partner has eight directors, three of whom, Jeffrey R. Armstrong, Sidney L. Tassin and Gary G. White, are independent as defined under the independence standards established by the NYSE and under Rule 10A-3 promulgated under the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our General Partner or to establish a compensation committee or a nominating committee. However, our General Partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act.

All of the executive officers of our General Partner listed below allocate their time between managing our business and affairs and the business and affairs of our Sponsor. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. While the amount of time that our executive officers devote to our business and the business of our Sponsor varies in any given year based on a variety of factors, we currently estimate that each of our executive officers spend substantially all of their time on the management of our business.

In evaluating director candidates, our Sponsor assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board of directors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board of directors to fulfill their duties.

Executive Officers and Directors of our General Partner

The following table shows information for the executive officers and directors of our General Partner, as of March 6, 2015. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board of directors of our General Partner. There are no family relationships among any of our directors or executive officers. Some of our directors and our executive officers also serve as executive officers of our Sponsor.

Name	Age (as of March 6, 2015)	Position with our General Partner
Vincent T. Cubbage	50	Chief Executive Officer, Chairman and Director
Michael H. Hart	51	Executive Vice President–Corporate Development
John S. Blanchard	43	Senior Vice President, President–Arc Terminals
Bradley K. Oswald	32	Senior Vice President, Chief Financial Officer and Treasurer
Steven C. Schnitzer	52	Senior Vice President, General Counsel
Darrell Brock, Jr.	49	Vice President, Business Development
Dennis Courtney	47	Vice President, Business Development
Stephen J. Pilatzke	36	Vice President, Chief Accounting Officer
Jeffrey R. Armstrong	45	Director
Daniel R. Castagnola	48	Director
Edward P. Russell	51	Director
Eric J. Scheyer	50	Director
Sidney L. Tassin	58	Director
Gary G. White	65	Director
Barry L. Zubrow	62	Director

Set forth below is a description of the backgrounds of our executive officers and directors.

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Vincent T. Cubbage. Mr. Cubbage has served as Chief Executive Officer, Chairman and a Director of our General Partner since September 2013. He has served as the Chief Executive Officer of, and held an ownership interest in, Lightfoot Capital Partners GP LLC since 2006. Prior to founding Lightfoot Capital Partners GP LLC, Mr. Cubbage was a Senior Managing Director and Head of the Midstream sector in the Investment Banking Division of Banc of America Securities from 1998 to 2006. Before joining Banc of America Securities, Mr. Cubbage was a Vice President at Salomon Smith Barney in the Global Energy and Power Group from 1994 to 1998. Mr. Cubbage received an MBA from the American Graduate School of International Management and a BA from Eastern Washington University.

Mr. Cubbage brings valuable expertise to the board of directors due to his extensive executive experience at the highest levels, including more than eight years of experience as the chief executive officer of our Sponsor and more than 20 years of transactional experience in the energy industry.

Michael H. Hart. Mr. Hart has served as Executive Vice President–Corporate Development of our General Partner since October 2013. He has served as a Partner of Lightfoot Capital Partners GP LLC since 2006 and has served as Chief Operating Officer since 2010. Prior to founding Lightfoot Capital Partners GP LLC, Mr. Hart was a senior member in the Banc of America Securities Natural Resources Investment Banking Group, focusing on mergers and acquisitions transactions in the midstream and coal sectors from 2001 to 2006. Before joining Banc of America Securities, Mr. Hart worked in the Mergers & Acquisitions Group at JPMorgan Securities from 1993 to 2001. Mr. Hart received an MBA from the Yale University School of Management and an AB from Harvard College.

John S. Blanchard. Mr. Blanchard has served as Senior Vice President of our General Partner since March 2014, Vice President, President—Arc Terminals since October 2013 and as President of Arc Terminals since 2009. He has served as Vice President of Lightfoot Capital Partners GP LLC since 2011 after beginning as an Associate in 2007. Prior to joining Lightfoot Capital Partners GP LLC, Mr. Blanchard was a Senior Associate with vFinance, Inc., a New York boutique investment banking firm, responsible for leading the execution of financial diligence, business valuation, market analysis, mergers and acquisitions, and capital raising assignments, from 2002 to 2007. Prior to vFinance, Inc., Mr. Blanchard worked as a Project Manager in the environmental engineering field for Day Environmental, Inc. from 1997 to 2002. During this time, he led teams of technicians and field personnel in implementing field investigations, subsurface studies, site remediation, and geologic analysis on projects throughout the northeastern United States. Mr. Blanchard received an MBA from the University of Rochester William E. Simon Graduate School of Business Administration, an MS in Hydrogeology from Clemson University and a BS from SUNY Buffalo.

Bradley K. Oswald. Mr. Oswald has served as Senior Vice President of our General Partner since March 2014 and Vice President, Chief Financial Officer and Treasurer of our General Partner since October 2013. He has served as Vice President of Lightfoot Capital Partners GP LLC since 2011 after beginning as an Associate in 2007. Prior to joining Lightfoot Capital Partners GP LLC, Mr. Oswald was an Analyst in the Financial Advisory Services Group at Jefferies & Company, Inc. focusing on balance sheet restructurings, equity and debt financings and both buy-side and sell-side advisory assignments, from 2005 to 2007. Mr. Oswald received a BS in Business Administration, Finance and Leadership from the University of Richmond.

Steven C. Schnitzer. Mr. Schnitzer has served as Senior Vice President, General Counsel and Secretary of our General Partner since February 2014. Prior to February 2014, Mr. Schnitzer practiced law with the firm of Katten Muchin Rosenman LLP, where he served as the Chair of the Corporate Group of the firm’s Washington, DC office from 2001 to January 2014 and specialized in corporate law, including mergers and acquisitions, corporate finance and securities matters. Prior to joining Katten Muchin Rosenman LLP, Mr. Schnitzer was an Associate from 1994 and a Partner from 1997 to 2000 in the Corporate Group of Crowell & Moring LLP in Washington, DC. Prior to joining Crowell & Moring LLP, Mr. Schnitzer was an Associate from 1988 to 1994 in the Corporate Finance Department of Debevoise & Plimpton LLP in New York City. Mr. Schnitzer received a Bachelor of Arts from the University of Maryland and a Juris Doctor degree from Touro College Jacob D. Fuchsberg Law Center, where he graduated cum laude and served as Editor-in-Chief of the law review.

Darrell Brock, Jr. Mr. Brock was promoted in July 2014 to the position of Vice President – Business Development for our General Partner with a focus on North American crude oil markets. Prior to that, Mr. Brock served as a consultant to our General Partner and Lightfoot Capital Partners GP LLC since 2010, with a similar focus on crude oil markets and logistics. Prior to joining Arc Logistics, Mr. Brock was a Managing Partner from 2009 to 2014 at The Cumberland Group, a Washington, D.C. based government relations firm specializing in national energy policy.  From 2007 to 2009, Mr. Brock was President and Chief Executive Officer of a Houston based energy group, DTX Midstream. Mr. Brock previously served as Commissioner of the Kentucky Governor’s Office of Development from 2003 to 2005, where he oversaw state infrastructure and development. During this time, he also served as Senior Policy Advisor to the Governor on a range of issues including energy.  Previously, Mr. Brock was employed with the Toyota Group Company and Johnson Controls, where he was responsible for various business development endeavors and global government

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relations. Mr. Brock received an MBA from Eastern Kentucky University and a BBA in accounting from Eastern Kentucky University.

Dennis Courtney. Mr. Courtney has served as Vice President – Business Development of our General Partner since January 2015.  Mr. Courtney focuses on the North American heavy and light product markets.  From 2013 to 2014, Mr. Courtney was in charge of all global sales of petroleum coke and coal for Oxbow Carbon and Minerals, a Florida based marketer and producer of fuel grade and calcined petroleum coke, sulfur, coal and other resources.  Prior to his tenure at Oxbow, Mr. Courtney served in various downstream and midstream management positions at Exxon and Exxon Mobile from 1991 to 2013.  During his 22 year career at Exxon and ExxonMobil, he gained increasing responsibilities in Retail Fuels Marketing, Finished Lubricants Marketing and Sales, Heavy and Clean Products Trading before managing ExxonMobil Pipeline Company’s commercial business as Vice President of Business Development and Joint Ventures. Mr. Courtney received a BS in Civil Engineering from Duke University.

Stephen J. Pilatzke. Mr. Pilatzke has served as Vice President and Chief Accounting Officer of our General Partner since October 2013. He has served as the Controller of Lightfoot Capital Partners GP LLC since 2010. Prior to joining Lightfoot Capital Partners GP LLC, Mr. Pilatzke served as Chief Financial Officer and Controller of Paramount BioSciences LLC, a venture capital firm specializing in the pharmaceutical and biotechnology sector and was responsible for all of the accounting and reporting functions of the company and related portfolio companies, from 2005 to 2010. Prior to Paramount BioSciences LLC, Mr. Pilatzke worked as an auditor at Eisner LLP, an accounting and advisory firm, from 2001 to 2005. Mr. Pilatzke is a Certified Public Accountant and received his BS in Accounting from Binghamton University.

Jeffrey R. Armstrong. Mr. Armstrong has served as a Director of our General Partner since January 2014. Mr. Armstrong is the Founder and CEO of Zenith Energy, an internationally focused terminal and logistics company, and Chairman of MID-SHIP Group LLC, an international shipping and logistics firm. He has also served as an independent director of Tallgrass Energy Partners since April 2014. Mr. Armstrong was formerly the Vice President of Corporate Strategy of Kinder Morgan, the largest midstream and the third largest energy company (based on combined enterprise value) in North America, from March 2013 to December 2013, where he was responsible for identifying new business ventures and asset optimization among the Kinder Morgan business groups. From July 2003 to March 2013, as former President of Terminals for Kinder Morgan, Mr. Armstrong oversaw the largest independent network of liquids and bulk terminals in North America.

Mr. Armstrong joined Kinder Morgan in 2001, following Kinder Morgan Energy Partners, L.P.’s purchase of the U.S. pipeline and terminal assets of the GATX Corporation, where he spent seven years working in various commercial and operational roles including General Manager of the company’s East Coast Operations. He previously worked in the marine tanker industry for Maritime Overseas Corp. Mr. Armstrong holds a bachelor’s degree in Marine Transportation from the U.S. Merchant Marine Academy and a master’s degree in business administration from the University of Notre Dame.

Mr. Armstrong’s extensive knowledge of the oil and gas industry, his prior experiences in the terminalling and storage business and his strategic and transaction experiences at Kinder Morgan allow him to add significant value to the board of directors of our General Partner.

Daniel R. Castagnola. Mr. Castagnola has served as a Director of our General Partner since October 2013 and Director for our Sponsor since October 2011. Mr. Castagnola is a Managing Director at GE EFS and Group Leader for a team of professionals investing in oil and gas infrastructure in North America. Additionally, Mr. Castagnola leads all equity origination efforts for GE EFS in Latin America. He joined GE EFS in 2002. Prior to joining GE EFS, Mr. Castagnola worked for nine years at Enron Corp. in its international division and three years at KPMG LLP. Mr. Castagnola serves as Director on the Board of a number of private portfolio companies. He served as a Director of Regency GP LLC, the General Partner of Regency Energy Partners LP, from June 2007 to May 2010. Mr. Castagnola received a BA and an MBA from the University of Houston.

Mr. Castagnola’s extensive knowledge of the oil and gas industry, his prior board experience with Regency GP LLC and his strategic and transaction experiences as a Managing Director at GE EFS allows him to provide critical insights to the board of directors of our General Partner.

Edward P. Russell. Mr. Russell has served as a Director of our General Partner since November 2013. Mr. Russell is currently a Director at Tortoise Capital Advisors, one of the largest energy investors in the United States with over $13 billion in assets under management and has held executive positions with Tortoise, including serving as President of Tortoise Capital Resources Corp from 2007 to 2012. Prior to joining Tortoise, Mr. Russell was a Managing Director and Head of the Energy and Power Group at Stifel, Nicolaus & Company, Inc. from 1999 to 2007. Mr. Russell has served as a Director of Abraxas Petroleum Corporation since October 2009 and received a BS from Maryville University.

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Mr. Russell’s strategic and transactional expertise, his experience on the board of Abraxas Petroleum Corporation and position as Director at Tortoise Capital Advisors allow him to bring valuable knowledge of the energy and natural resources industry to the board of directors of our General Partner.

Eric J. Scheyer. Mr. Scheyer has served as a Director of our General Partner since October 2013 and Director for our Sponsor since 2006. Mr. Scheyer is a partner of Magnetar Capital Partners LP and Head of the Energy Group of Magnetar Financial LLC, where he leads a team of investment professionals focused on the energy and natural resource sector. Prior to joining Magnetar at its inception in 2005, Mr. Scheyer was a consultant for two years at Caxton Associates in their Strategic Quantitative Investment Division. From 1989 to 1995, Mr. Scheyer was a principal of Decorel Incorporated, where he served as President of Decorel S.A. de C.V. and Executive Vice President of Decorel Inc. From 1987 to 1989, Mr. Scheyer worked in the Oil and Gas and Natural Gas Pipeline sectors in the Equity Research Department of Donaldson, Lufkin & Jenrette in New York City. Mr. Scheyer earned a B.A. in History from Trinity College (CT) and is a member of the Board of Fellows.

Mr. Scheyer’s extensive knowledge of the oil and gas industry, his management, strategic and investment experiences as well as his tenure as a partner of Magnetar Capital Partners LP make him a valuable asset to the board of directors of our General Partner.

Sidney L. Tassin. Mr. Tassin has served as a Director of our General Partner since November 2013. Mr. Tassin is founder and President of Carta Energy LLC, a firm that originates private equity investments in the energy field. Prior to forming Carta Energy in 2006, Mr. Tassin was President and a founding partner of Energy Spectrum Capital LP from inception in 1996 until 2006. During this period, Energy Spectrum managed four private equity funds that principally invested in the midstream and services sectors of the energy industry. Prior to Energy Spectrum Capital LP, Mr. Tassin held executive financial positions with MESA Inc. and predecessor companies from 1980 to 1994, including serving as chief financial officer from 1988 to 1994. Prior to joining MESA Inc., Mr. Tassin was with Arthur Andersen & Co. in Houston where he worked in the Audit Division, specializing in energy companies from 1977 to 1980. Mr. Tassin served as a director of Clipper Windpower Plc from 2002 to 2011 and was a member of the audit committee. In addition, Mr. Tassin served as a director of Bayard Drilling Technologies, Inc. from 1998 to 2000 and was a member of the audit committee. Mr. Tassin holds a BA with a major in Accounting from Northeast Louisiana University and earned his CPA certification in 1979.

As the former financial executive of Mesa Inc. and its predecessors, and in his role as a director on boards of numerous Energy Spectrum portfolio companies, Mr. Tassin has substantial experience and knowledge regarding financial issues related to energy companies and the energy industry. Additionally, Mr. Tassin’s experiences on audit committees and as an accountant allow him to add significant value to the board of directors of our General Partner.

Gary G. White. Mr. White has served as a Director of our General Partner since October 2014. Effective January 1, 2015, Mr. White was appointed Interim President of Marshall University by its Board of Governors and, as a result of this appointment, serves as Chairman of the Marshall University Research Corporation. Mr. White has served as an officer of Blackhawk Mining, LLC, a privately held coal mining company which owns and operates certain of the coal mining assets acquired from James River Coal Company in August 2014, since October 2014.  Prior to joining Blackhawk Mining, LLC, Mr. White was employed by James River Coal Company from April 2011 to September 2014.  While at James River Coal Company, Mr. White assisted senior management in connection with mergers and acquisitions and the sale of non-core assets, government and lessor relations, and regulatory affairs, and also served as President of International Resources, LLC and President and Chief Operating Officer of each of International Resources Holdings I, LLC, International Resources Holdings II, LLC, IRP WV Corp. and International Resource Partners LP, all of which were subsidiaries of James River Coal Company.    From June 2007 to April 2011, Mr. White served as President and Chief Operating Officer of IRP Administrative Services, LLC, an affiliate of our sponsor, Lightfoot Capital Partners, LP, where he was responsible for overseeing the operations and growth of International Resource Partners LP and its operating subsidiaries prior to the sale of International Resource Partners LP and such subsidiaries to James River Coal Company in April 2011.  Mr. White has also served as Chairman of the Board of the West Virginia Coal Association and is a member of the Board of Directors of United Bankshares, Inc. and the Marshall University Foundation.  He is also a former member and Chairman of the Marshall University Board of Governors.  Mr. White also served as Transition Director for former West Virginia Governor, Cecil Underwood, and he has been inducted to the Business Hall of Fame by both Marshall and West Virginia Universities.  In both 2006 and 2008, Mr. White was named one of the most influential business individuals in West Virginia by The West Virginia Executive Magazine. Mr. White received his BA degree from Marshall University.

Mr. White’s extensive experience in the natural resources industry, together with his management, operating-company and board of directors experience at various private and public companies, make him a valuable asset to the board of directors of our General Partner.

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Barry L. Zubrow. Mr. Zubrow has served as a Director of our General Partner since December 2013. Since 2003, Mr. Zubrow has served as president of ITB LLC, an investment-management company, and is a lecturer at the University of Chicago Law School. From January 2012 to January 2013, Mr. Zubrow was head of Corporate and Regulatory Affairs at JP Morgan Chase & Co. Prior to that position, from December 2007 to January 2012, he served as Chief Risk Officer at JP Morgan Chase & Co. From 1978 to 2004, Mr. Zubrow served as a partner, chief credit officer and chief administrative officer until his retirement from Goldman Sachs. From October 2010 to October 2012, Mr. Zubrow served on the board of JP Morgan Chase Bank NA. Mr. Zubrow received his bachelor’s degree from Haverford College in 1975. He earned an MBA in 1979 from the University of Chicago Graduate School of Business and a J.D. in 1980 from the University of Chicago Law School.

Mr. Zubrow’s strategic and transactional expertise at Goldman Sachs and ITB LLC in addition to his roles at JP Morgan Chase & Co. and his prior board experience allow him to provide critical and valuable insights to the board of directors of our General Partner.

Director Independence

Our board of directors has determined that Mr. Armstrong, Mr. Tassin and Mr. White are independent as defined by the rules of the NYSE and under Rule 10A-3 promulgated under the Exchange Act. In determining that Gary White constituted an independent director of the board of directors of our General Partner under the applicable rules of the NYSE and the Exchange Act, the board of directors considered the following historical relationship between Mr. White and an affiliate of our Sponsor, IRP GP LLC (“IRP General Partner”), which served as the general partner of International Resource Partners LP (“IRP”).  IRP was sold by our Sponsor in April 2011.  As the chief executive officer of a subsidiary of IRP General Partner, Mr. White was entitled to incentive compensation that became due in connection with the sale of IRP, part of which was deferred and paid on a post-closing basis.  Receipt by Mr. White of his deferred incentive compensation was not contingent on Mr. White’s continued employment relationship with IRP General Partner, which employment relationship terminated contemporaneously with the sale of IRP.

Committees of the Board of Directors

The board of directors of our General Partner has a standing audit committee.  In July 2014, the board of directors formed a compensation committee, which has since been dissolved as of March 2015. The board of directors will appoint a conflicts committee as needed. The audit committee has a written charter approved by the board of directors of our General Partner.  The written charter is available on our web site at www.arcxlp.com under the “Corporate Governance” section.  The current members of the audit and the former members of the compensation committees of the board and a brief description of the functions performed by each committee are set forth below.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and Rule 10A-3 promulgated under the Exchange Act. Messrs. Armstrong, Tassin (chairman) and White currently comprise the audit committee of the board of directors of our General Partner. The board of directors of our General Partner has determined that Mr. Tassin qualifies as an “audit committee financial expert,” as such term is defined under SEC rules.

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Compensation Committee

Although not required by NYSE rules, in July 2014, the board of directors formed a compensation committee, which has since been dissolved as of March 2015.  All of its members meet the independence standards established by the NYSE. The members of the compensation committee were Messrs. Armstrong (chairman) and Tassin.  

The compensation committee reviewed and made recommendations to the board of directors regarding the compensation for the executive officers and administered our equity compensation plans for officers and key employees.  

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Conflicts Committee

At least one independent member of the board of directors of our General Partner will serve on a conflicts committee, as necessary, to review specific matters that the board of directors believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is adverse to the interest of the Partnership. The members of the conflicts committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliates, including our Sponsor, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders.

Executive Sessions of Non-Management Directors

The board of directors of our General Partner holds regular executive sessions in which the non-management directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. In the event that the non-management directors include directors who are not independent under the listing requirements of the NYSE, then at least once a year, there may be an executive session including only independent directors and at least one executive session of independent directors was held for the year ended December 31, 2014. The director who will preside at these meetings, the lead director, will be chosen by the board of directors. As of March 2015, the board of directors of our General Partner has selected Sidney L. Tassin, the Chairman of the Audit Committee, and, in his absence, any other independent director selected by a majority of the directors present at such meeting, to serve as the lead director to preside at these meetings.

Communication with the Board of Directors

A holder of our units or other interested party who wishes to communicate with the directors of our General Partner may do so by sending communications to the board of directors, any committee of the board of directors, the Chairman of the board or any other director to the address or phone number appearing on the front page of this Annual Report on Form 10-K by marking the envelope containing each communication as “Unitholder Communication with Directors” and clearly identifying the intended recipient(s) of the communication. Communications will be relayed to the intended recipient of the board of directors of our General Partner except in instances where it is deemed unnecessary or inappropriate to do so pursuant to our guidelines, which are available on our website at www.arcxlp.com in the “Corporate Governance Guidelines” section. Any communications withheld under those guidelines will nonetheless be retained and available for any director who wishes to review them.

Corporate Governance Matters

We have a Code of Business Conduct and Ethics that applies to our directors, officers and employees as well as a Financial Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, controller and the other senior financial officers, each as required by SEC and NYSE rules. Furthermore, we have Corporate Governance Guidelines and a charter for our Audit Committee. Each of the foregoing is available on our website at www.arcxlp.com in the “Corporate Governance” section. We will provide copies, free of charge, of any of the foregoing upon receipt of a written request to Arc Logistics Partners LP, 725 Fifth Avenue, 19^th Floor, New York, NY 10022, Attn: Investor Relations. We intend to disclose amendments to and waivers, if any, from our Code of Business Conduct and Ethics and Financial Code of Ethics, as required, on our website, www.arcxlp.com, promptly following the date of any such amendment or waiver.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the directors and executive officers of our General Partner, and persons who own more than 10% of a registered class of our equity securities, to file reports of beneficial ownership on Form 3 and reports of changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that all filings by such persons, were made on a timely basis during the fiscal year ended December 31, 2014, except that one Section 16(a) report was not timely filed by Vincent Cubbage, which report was filed to reflect that, upon the expiration of the lock-up period relating to the  initial public offering of our common units, Vincent Cubbage may be deemed to be the beneficial owner of certain of the common and subordinated units of the Partnership that are held by Lightfoot Capital Partners LP by virtue of his ownership interests in the general partner of Lightfoot Capital Partners LP.  The late Section 16(a) report was filed within six days of the due date for such filing.

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ITEM 11. EXECUTIVE COMPENSATION

Our General Partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. The executive officers of our General Partner are employed by our Sponsor and manage the day-to-day affairs of our business. References to “our executive officers” and “our directors” refer to the executive officers and directors of our General Partner.

Our executive officers allocate their time between managing our business and affairs and the business and affairs of our Sponsor. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. While the amount of time that our executive officers devote to our business and the business of our Sponsor varies in any given year based on a variety of factors, we currently estimate that, since the completion of our IPO, each of our executive officers has spent substantially all of his time on the management of our business.

Because our executive officers are employees of our Sponsor, their compensation is determined and paid by our Sponsor and reimbursed by us to our Sponsor with respect to time spent managing our business in accordance with the terms of the services agreement. Please see Part III, Item 13. “Certain Relationships and Related Transactions and Director Independence—Agreements with Affiliates—Services Agreement.”

As we are currently considered an emerging growth company under the JOBS Act, the compensation-related sections of this document are intended to comply with the reduced compensation disclosure requirements applicable to emerging growth companies.

In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures. Further our reporting obligations extend only to our Chief Executive Officer and our two most highly compensated executive officers (other than our Chief Executive Officer) determined by reference to total compensation for 2014 as reported in the Summary Compensation Table below (our “Named Executive Officers”).

Summary Compensation Table

The following table summarizes the total compensation for our Named Executive Officers for services rendered to us during the fiscal year ended December 31, 2014 and the fiscal year ended December 31, 2013 (with respect to the period beginning on November 12, 2013, the date of the closing of our IPO, and ending on December 31, 2013). Further, other than with respect to equity incentive awards granted to our Named Executive Officers under the 2013 Plan for which we bear the entire cost, the amounts reported in the table below reflect only the compensation reimbursable by us to our Sponsor under the services agreement with respect to our Named Executive Officers for the periods presented. For the avoidance of doubt, the amounts reported in the table below do not reflect the aggregate compensation received by these individuals for all services to the Sponsor and its affiliates, including us and our General Partner. The amounts reported in the table are intended only to represent the compensation received by our Named Executive Officers during the stated period for services rendered to us.

Name and Principal Position	Year	Salary (1)		Bonus (1)		Unit Awards (2)		All Other Compensation (3)		Total
Vincent T. Cubbage	2014	$	326,721	$	163,020	$	2,864,250	$	7,706	$	3,361,697
Chief Executive Officer, Chairman and Director	2013	$	32,558	$	-	$	-	$	1,285	$	33,843
Michael H. Hart	2014	$	213,827	$	148,200	$	1,273,000	$	7,706	$	1,642,733
Executive Vice President, Corporate Development	2013	$	25,419	$	-	$	-	$	1,011	$	26,430
Bradley K. Oswald	2014	$	186,174	$	148,200	$	1,273,000	$	7,706	$	1,615,080
Senior Vice President, Chief Financial Officer and Treasurer	2013	$	17,519	$	-	$	-	$	1,397	$	18,916

(1) Represents the portion of the base salary-or bonus paid to our Named Executive Officers by our Sponsor that was reimbursable by us under the services agreement for fiscal years 2014 and 2013. The amount for fiscal year 2013 reflects the time period beginning on November 12, 2013, the date of the closing of our IPO, and ending on December 31, 2013.  

(2) Reflects the aggregate grant date fair value computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”), determined without regard to forfeitures, of the phantom unit awards subject to performance-based vesting conditions granted to our Named Executive Officers under the 2013 Plan in July 2014 based upon probable achievement of the performance conditions and does not reflect the actual value that may be recognized by our Named Executive Officers. Assuming that the highest level of performance is achieved with respect to the

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performance conditions for such phantom units, the aggregate grant date fair value computed in accordance with FASB ASC Topic 718 of the phantom unit awards granted to Mr. Cubbage, Mr. Hart and Mr. Oswald is $5,728,500, $2,546,000 and $2,546,000, respectively.  See Note 10 to our accompanying consolidated financial statements for the fiscal year ended December 31, 2014, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.

(3) Reflects the portion of the 401(k) matching contributions made on behalf of our Named Executive Officers that was reimbursable by us under the services agreement for fiscal years 2014 and 2013. The amount for fiscal year 2013 reflects the time period beginning on November 12, 2013, the date of the closing or our IPO, and ending on December 31, 2013.

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Narrative Disclosure to Summary Compensation Table

Phantom Unit Awards

In July 2014, the board of directors authorized the grant of phantom unit awards pursuant to a phantom unit award agreement (the “Phantom Unit Agreement”) under the 2013 Plan to our executive officers (among others), including to our Named Executive Officers.  The phantom units awarded to our Named Executive Officers are subject to performance-based vesting, and each such award vests as follows: (1) 25% of the award vests the day after the end of the Subordination Period (as defined in our limited partnership agreement); and (2) the three (3) remaining 25% installments of the award vest based on the date on which we have paid, for three consecutive quarters, distributions to our common and subordinated 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, (b) 25% of the award vesting after distributions are paid at or above $0.4845 per unit, and (c) the last 25% of the award vesting after distributions are paid at or above $0.5814 per unit. Upon vesting, phantom units will be settled in our common units, except that an award of less than 1,000 phantom units will be settled in cash. The phantom unit awards confer upon our Named Executive Officers the right to receive distribution equivalent rights, which entitle each Named Executive Officer to receive distributions on the phantom units equivalent to the distributions paid on our common units until such time as our Named Executive Officer’s phantom units vest, are forfeited, or expire.

In the event of a Change of Control (as defined under the 2013 Plan), all unvested phantom units subject to the award immediately become vested upon the occurrence of the Change of Control or upon a Named Executive Officer’s termination of employment with the General Partner, the Partnership and its affiliates (the “Partnership Entities”) prior to and in connection with such Change of Control (subject to consummation of the Change of Control). Upon a Named Executive Officer’s termination of employment with the Partnership Entities due to death or Disability (as defined in the 2013 Plan), all unvested phantom units subject to the award immediately become vested as of the date of such termination. In the event of a Named Executive Officer’s termination for any other reason, all unvested phantom units shall become null and void as of the date of such termination; provided, however, that the Committee (as defined under the 2013 Plan), in its sole discretion, may elect to vest all or any portion of such unvested phantom units or allow such phantom units to remain outstanding and continue to vest according to the vesting schedule specified in the Phantom Unit Agreement or pursuant to such other terms and conditions established by the Committee.

Subject to certain exceptions, any phantom units granted under the Phantom Unit Agreement will lapse and be forfeited in the event that such units do not vest by the expiration date of the award.  Generally, unvested phantom units granted under the Phantom Unit Agreement will expire five years after the date the award is granted unless prior to the end of such five-year period, we have paid to our unitholders at least one quarterly distribution (but less than three consecutive quarterly distributions) at or above $0.4845 per unit, in which case, any unvested phantom units will expire eight years following the date the award is granted.  If we pay at least one distribution (but less than three consecutive distributions) to our unitholders at certain other distribution levels prior to the end of the five-year or eight-year expiration period, then such five-year or eight-year expiration period (as applicable) shall be extended to the second day following the day the we have paid distributions to our unitholders for the three consecutive distribution quarters commencing immediately following the end of the five-year or eight-year expiration period (as applicable).

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Outstanding Equity Awards at Fiscal Year-End Table

The following table sets forth information regarding the unvested phantom units held by each Named Executive Officer as of December 31, 2014.

	Unit Awards
Name and Principal Position	Equity Incentive Plan Awards: Number of Unearned Units That Have Not Vested (1)		Equity Incentive Plan Awards: Market Value of Unearned Units That Have Not Vested (2)
Vincent T. Cubbage Chief Executive Officer, Chairman and Director		225,000	$	3,838,500
Michael H. Hart Executive Vice President, Corporate Development		100,000	$	1,706,000
Bradley K. Oswald Senior Vice President, Chief Financial Officer and Treasurer		100,000	$	1,706,000

(1) Reflects the phantom unit awards subject to performance-based vesting granted to our Named Executive Officers in July 2014. Each phantom unit award vests as follows: (1) 25% of the award vests the day after the end of the Subordination Period (as defined in our limited partnership agreement); and (2) the three (3) remaining 25% installments of the award vest based on the date on which we have paid, for three consecutive quarters, distributions to our common and subordinated 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, (b) 25% of the award vesting after distributions are paid at or above $0.4845 per unit, and (c) the last 25% of the award vesting after distributions are paid at or above $0.5814 per unit. The number of phantom units reported is based upon the number of units that could become vested and settled under the award assuming achievement of the performance goals applicable to 100% of the phantom units subject to each award. See the section titled “Executive Compensation—Narrative Disclosure to Summary Compensation Table—Phantom Unit Awards” for further details.

(2) The value of the phantom unit awards was calculated based on a price of $17.06 per unit, the closing price of our common units on December 31, 2014.

Additional Narrative Disclosure

Retirement and Other Benefits

Our Sponsor does not, and does not intend to, maintain a defined benefit pension plan for its employees because it believes such plans primarily reward longevity rather than performance. Instead, our Sponsor provides a basic benefits package generally to all employees, including our Named Executive Officers, which includes a 401(k) plan and health, disability and life insurance.

Potential Payments upon Termination or Change in Control

Other than the phantom unit awards, we do not currently have in place any other arrangements with any of our Named Executive Officers that would provide payments or benefits to such individuals upon termination of their service relationship with us or upon the occurrence of a change in control of us or our General Partner For a discussion of the termination and change in control provisions applicable to the phantom unit awards, please see the section above titled “Executive Compensation—Narrative Disclosure to Summary Compensation Table—Phantom Unit Awards.”

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Director Compensation

Officers or employees of our General Partner or our Sponsor or its owners or any designees of the foregoing, who also serve as directors of our General Partner, do not receive additional compensation for such service. The table below sets forth the compensation of the non-employee directors of our General Partner for the fiscal year ended December 31, 2014.

Name	Fees Earned or Paid in Cash		Unit Awards (1)		Total
Jeffrey R. Armstrong	$	29,000	$	509,200	$	538,200
Daniel R. Castagnola		—		—		—
Edward P. Russell		—	$	509,200	$	509,200
Eric J. Scheyer		—	$	509,200	$	509,200
Sidney L. Tassin	$	34,000	$	509,200	$	543,200
Gary G. White (2)	$	7,000		—	$	7,000
Barry L. Zubrow		—	$	509,200	$	509,200

1) Reflects the aggregate grant date fair value of the phantom units granted to non-employee directors in July 2014, computed in accordance with FASB ASC Topic 718, determined without regard to forfeitures.  See Note 10 to our accompanying consolidated financial statements for the fiscal year ended December 31, 2014, for a discussion of the assumptions used in determining the FASB ASC Topic 718 grant date fair value of these awards.  Each of the non-employee directors received an award of 20,000 phantom units under the 2013 Plan in July 2014, other than Mr. Castagnola, whose units were declined. The phantom units vest in substantially equal annual installments over a three year period beginning on the date of grant. As of December 31, 2014, each non-employee director, other than Mr. Castagnola and Mr. White, held 20,000 outstanding unvested phantom units. Messrs. Castagnola, Russell, Scheyer and Zubrow are designees of our Sponsor and therefore do not receive additional compensation for their services as directors of our General Partner.

2) Mr. White joined the board of directors in October 2014 and did not receive a phantom unit grant during the year ended December 31, 2014.  Mr. White will receive his one-time grant of 20,000 phantom units effective March 2015.

Narrative Disclosure to Director Compensation Table

Non-employee directors receive a one-time grant of 20,000 phantom units, other than Mr. Castagnola, whose units were declined. In addition, non-employee directors of our General Partner who are independent generally receive an annual cash retainer in the amount of $20,000, and the chair of the audit committee of our General Partner’s board of directors receives an additional annual cash retainer in the amount of $5,000. Further, for each meeting of our General Partner’s board of directors that a non-employee independent director attends, such non-employee independent director will receive $1,000.

Non-employee directors will be reimbursed for all out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

Phantom Unit Awards

The phantom unit awards made to non-employee directors of our General Partner are made pursuant to a phantom unit award agreement under the 2013 Plan (the “Director Award Agreement”) and provide for time-based vesting in three substantially equal annual installments over a three year period beginning on the date of grant. Upon vesting, phantom units will be settled in our common units. The phantom unit awards confer upon the non-employee directors the right to receive distribution equivalent rights, which entitle each non-employee director to receive distributions on the phantom units equivalent to the distributions paid on our common units until such time as the non-employee director’s phantom units vest, are forfeited, or expire.

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In the event of a Change of Control (as defined under the 2013 Plan), all unvested phantom units subject to the non-employee director’s award immediately become vested upon the occurrence of the Change of Control or upon the termination of a non-employee director’s service relationship with the Partnership Entities prior to and in connection with such Change of Control (subject to consummation of the Change of Control). Upon the termination of a non-employee director’s service relationship with the Partnership Entities due to death or Disability (as defined in the 2013 Plan), all unvested phantom units subject to the non-employee director’s award immediately become vested as of the date of such termination. In the event of the termination of a non-employee director’s service relationship with the Partnership Entities for any other reason, all unvested phantom units shall become null and void as of the date of such termination; provided, however, that the Committee (as defined in the 2013 Plan), in its sole discretion, may elect to vest all or any portion of such unvested phantom units or allow such phantom units to remain outstanding and continue to vest according to the vesting schedule specified in the Director Award Agreement or pursuant to such other terms and conditions established by the Committee.

Subject to certain exceptions, any unvested phantom units granted under the Director Award Agreement will lapse and be forfeited in the event that such units do not vest by the expiration date of the award. Generally, unvested phantom units granted under the Director Award Agreement will expire on the third anniversary of the last vesting date to occur.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth the beneficial ownership of our common units and subordinated units as of March 6, 2015 held by our General Partner, by each person known by us to own more than 5% of such units, by each director and Named Executive Officer of our General Partner, and by all directors and executive officers of our General Partner as a group. Unless otherwise noted, (i) the address for each beneficial owner listed below is 725 Fifth Avenue, 19^th Floor, New York, NY 10022 and (ii) the persons named in the table have sole voting and investment power with respect to all shares beneficially owned by them.

Name of Beneficial Owner, Named Executive Officer and Director	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned			Subordinated Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned			Percentage of Common and Subordinated Units Beneficially Owned (8)
Arc Logistics GP LLC		—		—	%		—		—	%		—	%
Lightfoot (1)		68,617		1.0	%		5,146,264		84.6	%		40.3	%
Center Oil (2)		211,685		3.1	%		876,391		14.4	%		8.4	%
Advisory Research, Inc. Managed Accounts (3)		374,902		5.5	%		—		—	%		2.9	%
Kayne Anderson Capital Advisors, L.P. (4)		1,785,776		26.0	%		—		—	%		13.8	%
Oppenheimer SteelPath MLP Income Fund (5)		1,620,901		23.6	%		—		—	%		12.5	%
Salient Capital Advisors, LLC (6)		610,307		8.9	%		—		—	%		4.7	%
Vincent T. Cubbage (7)		621	*				46,568	*			*
Michael H. Hart		—		—	%		—		—	%		—	%
Bradley K. Oswald		—		—	%		—		—	%		—	%
Jeffrey R. Armstrong		—		—	%		—		—	%		—	%
Daniel R. Castagnola		—		—	%		—		—	%		—	%
Edward P. Russell		—		—	%		—		—	%		—	%
Eric J. Scheyer		—		—	%		—		—	%		—	%
Sidney L. Tassin		—		—	%		—		—	%		—	%
Gary G. White		—		—	%		—		—	%		—	%
Barry L. Zubrow		—		—	%		—		—	%		—	%
All named executive officers and directors as a group (10 persons)		—		—	%		—		—	%		—	%

* Less than 1%

(1) Voting and investment determinations with regard to securities held by Lightfoot Capital Partners, LP are made by its general partner, Lightfoot Capital Partners GP LLC, through its board of managers consisting of Jonathan Cohen, Vincent Cubbage, Eric Scheyer, Paul Tice, Daniel Castagnola and Alec Litowitz.

(2) The address for Center Oil is 600 Mason Ridge Center Drive, 2^nd Floor, St. Louis, Missouri 63141.

(3) Based solely on Schedule 13G/A filed with the SEC on February 17, 2015. Advisory Research, Inc. is a subsidiary of Piper Jaffray Companies. The address for Piper Jaffray Companies is 800 Nicollet Mall, Suite 800, Minneapolis, MN 55402.

(4) Based solely on Schedule 13G/A filed with the SEC on January 12, 2015. The address for Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Third Floor, Los Angeles, CA 90067. Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne have shared voting power and shared dispositive power with respect to the reported units shown above.

(5) Based solely on Schedule 13G/A filed with the SEC on February 4, 2015. OppenheimerFunds, Inc. is an investment adviser to Oppenheimer SteelPath MLP Income Fund. The address for Oppenheimer SteelPath MLP Income Fund is 6803 S. Tucson Way, Centennial, CO 80112. OppenheimerFunds, Inc. and Oppenheimer SteelPath MLP Income Fund have shared voting power and shared dispositive power with respect to the reported units shown above.

(6) Based solely on Schedule 13G/A filed with the SEC on February 10, 2015. The address for Salient Capital Advisors, LLC is 4265 San Felipe, 8^th Floor, Houston, Texas 77027.

(7) Upon the expiration of the lock-up period relating to the Partnership’s initial public offering of its common units, Vincent Cubbage may be deemed to be the beneficial owner of certain of the common and subordinated units of the Partnership that are held by Lightfoot Capital Partners LP by virtue of his ownership interests in the general partner of Lightfoot Capital Partners LP.

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(8) This beneficial ownership table is computed without taking into account any common units that would be issued by us pursuant to the PIPE Purchase Agreement, which provides for the issuance of 4,411,765 common units to the PIPE Purchasers subject to the satisfaction of the conditions precedent set forth therein. Please see Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing of the Partnership Equity Commitment.” The PIPE Transaction is expected to close on or before May 18, 2015, and this beneficial ownership table does not reflect the beneficial ownership of any PIPE Purchaser after giving effect to such closing, including common units that would be beneficially owned or are deemed to be beneficially owned by Goldman Sachs Asset Management as reflected in a Schedule 13G filed by it with the SEC on March 10, 2015.

Equity Compensation Plan Information

The following table sets forth information as of December 31, 2014 with respect to equity compensation plans under which our common units are authorized for issuance.

	(a)			(b)		(c)
	Number of Units to be Issued Upon Exercise of Outstanding Unit Options and Rights			Weighted Average Exercise Price Of Outstanding Unit Options and Rights		Number of Units Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Plan Category
Equity compensation plans approved by unitholders:		—			—		—
Equity compensation plans not approved by unitholders:
Long-Term Incentive Plan (1)		939,500	(2)		—		1,060,500
Total		939,500			—		1,060,500

1) The 2013 Plan was adopted by our General Partner in November 2013 prior to and in connection with our IPO and, therefore, did not require approval by our unitholders. The 2013 Plan contemplates the issuance or delivery of up to 2,000,000 common units to satisfy awards under the 2013 Plan. The material features of the 2013 Plan are described in “Note 10—Equity Plans—2013 Long-Term Incentive Plan” to our accompanying consolidated financial statements for the fiscal year ended December 31, 2014.

2) Represents the aggregate number of phantom units granted to certain executive officers, employees and non-employee directors under the 2013 Plan assuming vesting of 100% of the phantom units, which represents the maximum possible. There were no other types of equity awards outstanding under the 2013 Plan as of December 31, 2014.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of December 31, 2014, our Sponsor owned 68,617 common units and 5,146,264 subordinated units representing a 40.3% limited partner interest in us. Our Sponsor also owns and controls our General Partner. Our Sponsor also appoints all of the directors of our General Partner, which maintains a non-economic general partner interest in us and owns the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Distributions and Payments to Our General Partner and Its Affiliates

The following discussion summarizes the distributions and payments made or to be made by us to our General Partner and its affiliates in connection with our ongoing operation and any liquidation.

Operational Stage

Cash available for distribution to our General Partner and its affiliates. We generally make cash distributions 100% to our unitholders, including affiliates of our General Partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our General Partner is entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our Sponsor will receive an annual distribution of approximately $8.1 million on its units. For the year ended December 31, 2014, we paid our Sponsor $7.3 million in cash distributions.

Payments to our General Partner and its affiliates. Our General Partner does not receive a management fee or other compensation for its management of our Partnership, but we reimburse our General Partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. Our partnership agreement provides that our General Partner will determine the expenses that are allocable to us. For the year ended December 31, 2014, we paid our General Partner $4.0 million, pursuant to the partnership agreement.

Withdrawal or removal of our General Partner. If our General Partner withdraws or is removed, its non-economic General Partner interest and its incentive distribution rights will either be sold to the new General Partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage

Upon our liquidation, the partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements with Affiliates

We have entered into certain agreements with our Sponsor, as described in more detail below.

Contribution Agreement

In connection with the IPO, the following transactions, among others, occurred in connection with or pursuant to the contribution agreement by and among us, our General Partner, our Sponsor, Center Oil, GCAC, Arc Terminals GP, Arc Terminals, Arc Terminals Holdings and Arc Terminals Mississippi Holdings LLC:

● The redemption of Lightfoot’s initial limited partner interest in us and the issuance of the incentive distribution rights to our General Partner pursuant to a right to such conferred to our General Partner;

● Lightfoot and Center Oil contributed all of their limited partner interests in Arc Terminals and all of the limited liability company interests in Arc Terminals GP to us in exchange for common units and subordinated units, representing limited partner interests in us;

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● GCAC contributed its preferred units in Arc Terminals to us in exchange for common units and subordinated units and the right to receive a cash distribution on the closing of the IPO; and

● Arc Terminals merged with and into Arc Terminals GP, with Arc Terminals GP surviving and changing its name to Arc Logistics LLC.

Services Agreement

In connection with the IPO, we entered into a services agreement with our General Partner and our Sponsor, which provides, among other matters, that our Sponsor will make available to our General Partner the services of its executive officers and employees who serve as our General Partner’s executive officers, and that we, our General Partner and our subsidiaries, as the case may be, are obligated to reimburse our Sponsor for any allocated portion of the costs that our Sponsor incurs in providing services to us, including compensation and benefits to such employees of our Sponsor, with the exception of costs attributable to our Sponsor’s share-based compensation.

Registration Rights Agreement

In connection with the IPO, we entered into a registration rights agreement with our Sponsor. Pursuant to the registration rights agreement, we are required to file a registration statement to register the common units issued to our Sponsor and the common units issuable upon the conversion of the subordinated units upon request of our Sponsor. In addition, the registration rights agreement gives our 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.

Assignment and Equity Purchase Agreement with GE EFS

In connection with the IPO, we entered into an assignment and equity purchase agreement with an affiliate of GE EFS that enabled us to acquire a 10.3% interest in Gulf LNG Holdings. Approximately $72.7 million of the proceeds from the IPO were used to acquire the LNG Interest on the closing date of the IPO.

Other Transactions with Related Persons

GCAC guarantees up to $20 million of our Credit Facility. Under certain circumstances, the lenders may release GCAC from such guarantee.

Storage and Throughput Agreements with Center Oil

During 2007, we 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, we entered into a storage and throughput agreement with Center Oil whereby we provide 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 us a fixed per barrel fee for any additives added into Center Oil’s product.

The term of the storage and throughput agreement extends through June 2017. 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, we acquired a 50% undivided interest in the Baltimore, MD terminal. In connection with the acquisition, we acquired an existing agreement with Center Oil whereby we provide ethanol storage and throughput services to Center Oil. We charge 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. The agreement has a one-year term and comes up for renewal in May 2015.

In May 2011, we entered into an agreement to provide refined products storage and throughput services to Center Oil at the Baltimore, MD terminal. We charge Center Oil a fixed fee for storage and a fee for ethanol blending and any 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. The agreement has a one-year term and comes up for renewal in May 2015.

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In May 2013, we entered into an agreement to provide gasoline storage and throughput services to Center Oil at the Brooklyn, NY terminal. We charge Center Oil a fixed per bbl fee for each inbound delivery of ethanol and every outbound barrel of product shipped or committed to be 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. The agreement has a one-year term and comes up for renewal in May 2015.

Storage and Throughput Agreement with GCAC

In February 2013, and in connection with our acquisition of Arc Terminals Mobile Holdings, LLC from GCAC, we entered into a storage and throughput agreement (the “GCAC Agreement 1”) with GCAC whereby we provide storage and throughput services for various petroleum products to GCAC at the existing terminals acquired by us in return for a fixed per barrel storage fee in addition to a fixed per barrel fee for related throughput and other ancillary services. In addition, we entered into a second storage and throughput agreement with GCAC (the “GCAC Agreement 2”) whereby we built an additional 150,000 barrels of storage tanks for GCAC to store and throughput various petroleum products in return for similar economic terms of GCAC Agreement 1.

The initial term of GCAC Agreements 1 and 2 is approximately five years. These agreements can be mutually extended by both parties as long as the extension is agreed to 180 days prior to the end of the initial termination date; otherwise we have the right to lease the storage capacity to any third party.

The total revenues associated with the storage and throughput agreements for Center Oil and GCAC that are reflected in the “Revenues – Related parties” line on the consolidated statements of operations and comprehensive income are as follows (in thousands):

	For the Year Ended December 31,
	2014		2013		2012
Center Oil	$	7,382	$	7,587	$	9,663
GCAC		1,848		592		-
Total	$	9,230	$	8,179	$	9,663

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

	As of December 31,
	2014		2013
Center Oil	$	594	$	536
GCAC		306		186
Total	$	900	$	722

Operating Lease Agreement

In January 2014, we, through our wholly owned subsidiary, Arc Terminals Holdings, entered into the Lease Agreement, pursuant to which Arc Terminals Holdings leased the Portland Terminal from LCP Oregon, a wholly owned subsidiary of CorEnergy.  We guaranteed Arc Terminals Holdings’ obligations under the 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.  The 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 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 rents in the initial years of the Lease Agreement were $230,000 per month through July 2014 (prorated for the partial month of January 2014) and are $417,522 for each month thereafter until the end of year five.  The base rents 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 at the Portland Terminal, estimated at $10 million.  Assuming such improvements are completed, the base rent will increase by approximately $95,800 per month.  As of December 31, 2014, spending on terminal-related projects totaled approximately $5.6 million. The base rents will be increased at the end of year five 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

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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 year ended December 31, 2014, the expense associated with the Lease Agreement was $6.5 million. During the year ended December 31, 2014, there was no variable rent associated with the Lease Agreement.

So long as Arc Terminals Holdings is not in default under the Lease Agreement, it shall have the right to purchase the Portland Terminal at the end of the third year of the Lease Agreement and at the end of any month thereafter by delivery of 90 days’ notice. 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 right is not exercised, the 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 Lease Agreement on the fifth and tenth anniversaries, by providing written notice 12 months in advance, for a termination fee of approximately $4 million and $6 million, respectively.

JBBR Acquisition

JBBR Purchase Agreement

In February 2015, Arc Terminals Joliet Holdings, our wholly owned subsidiary that will be owned jointly by us and an affiliate of GE EFS, entered into the JBBR Purchase Agreement pursuant to which Arc Terminals Joliet Holdings has agreed, subject to the terms and conditions thereof, to acquire from CenterPoint, for a base cash purchase price of $216 million, all of the issued and outstanding membership interests in JBBR, which among other things owns the Joliet Terminal. In connection with the JBBR Acquisition, we have entered into a joint venture arrangement with GE EFS. Upon the JBBR Closing, an affiliate of GE EFS will own 40% of Arc Terminals Joliet Holdings, with the remaining 60% owned by us. We will manage the ongoing operations of Arc Terminals Joliet Holdings and its subsidiaries, including JBBR.

Equity Commitment Letter and Interim Investors Agreement

In February 2015, Aircraft Services Corporation (the “GE Equity Provider”), an affiliate of GE EFS, entered into an equity commitment letter with Arc Terminals Joliet Holdings under which GE Equity Provider agreed to contribute to Arc Terminals Joliet Holdings forty percent (40%) of the JBBR Purchase Price to enable Arc Terminals Joliet Holdings to consummate the JBBR Acquisition. GE Equity Provider’s obligations to make such funding available to Arc Terminals Joliet Holdings at the JBBR Closing are subject to customary funding conditions, including the satisfaction (or waiver by Arc Terminals Joliet Holdings) of all conditions to Arc Terminals Joliet Holdings’ obligation to consummate the JBBR Acquisition pursuant to the JBBR Purchase Agreement, as more fully set forth in the equity commitment letter provided by GE Equity Provider.

In February 2015, we and EFS-S LLC (and an affiliate of GE EFS and, as such, “GE JV Partner”) entered into an interim investors agreement (the “Interim Investors Agreement”), which governs the actions of Arc Terminals Joliet Holdings and the relationship between us and GE JV Partner as it relates to Arc Terminals Joliet Holdings until the earlier of the JBBR Closing and the termination of the JBBR Purchase Agreement. We and GE JV Partner have agreed to enter into an amended and restated limited liability company agreement of Arc Terminals Joliet Holdings concurrently with the JBBR Closing on terms consistent with terms set forth in the Interim Investors Agreement.

GE EFS owns, indirectly, interests in Lightfoot. Lightfoot has a significant interest in us through its ownership of a 42.9% limited partner interest in us (prior to giving effect to the issuance by us of common units in the PIPE Transaction described below), 100% of the limited liability company interests in our General Partner, and all of our incentive distribution rights. Daniel Castagnola, Managing Director of GE EFS, which is an affiliate of General Electric Capital Corporation, serves on the board of directors of our General Partner.

Financing of the Partnership Equity Commitment

PIPE Transaction

In February 2015, we entered into the PIPE Purchase Agreement with the PIPE Purchasers to sell 4,411,765 common units at a price of $17.00 per unit in a private placement. The Common Unit Purchase Price will be reduced by our first quarter 2015 distribution in respect of our common units if the closing of the PIPE Transaction is after the record date for such distribution. We will use the proceeds from the private placement (totaling $75 million before placement agent commissions and expenses) to fund a portion of our obligations under the Arc Equity Commitment Letter. If the PIPE Purchase Agreement is terminated pursuant to its terms, including on account of the termination of the JBBR Purchase Agreement or if the closing under the PIPE Purchase Agreement fails to occur by May 18, 2015, we will pay to each PIPE Purchaser a commitment fee of 1% of such PIPE Purchaser’s commitment amount under the PIPE Purchase Agreement. During the period commencing on the date of execution of the PIPE Purchase

79

Agreement and ending 90 days following the date of the closing of the PIPE Transaction, we are restricted under the PIPE Purchase Agreement from issuing, without the consent of the PIPE Purchasers holding a majority of the purchased common units (or, prior to closing, the PIPE Purchasers entitled to acquire at closing a majority of such common units), our equity securities except for, in general, our common units issued at or above a stated issuance price in (or to fund) an acquisition that is determined by the board of directors of our General Partner to result in an increase in our distributable cash flow over the first full four quarters following such acquisition. The issuance of the common units pursuant to the PIPE Purchase Agreement is being made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof.

MTP Energy Master Fund Ltd. (“Magnetar PIPE Investor”), one of the PIPE Purchasers, has committed $9.5 million to the purchase of common units 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 Capital Partners, LP and in its general partner, Lightfoot Capital Partners GP LLC, which is the sole owner of our General Partner. Eric Scheyer, the Head of the Energy Group of Magnetar Financial LLC, also serves on the board of directors of our General Partner.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

Under our code of business conduct and ethics, a director or officer is expected to bring to the attention of our compliance officer, who shall promptly disclose the possible conflict of interest to the board of directors at the earliest time practicable under the circumstances, any conflict or potential conflict of interest that may arise between the director or executive officer or any affiliate thereof, on the one hand, and us or our General Partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board of directors in light of the circumstances, be determined by a majority of the disinterested directors or the board of directors, as the case may be.

If a conflict or potential conflict of interest arises between our General Partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict will be addressed by the board of directors of our General Partner in accordance with the provisions of our partnership agreement. At the discretion of the board of directors in light of the circumstances, the resolution may be determined by the board of directors in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Director Independence

Information required by this Item is incorporated by reference from Item 10.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

We have engaged PricewaterhouseCoopers LLP (“PwC”) as our independent registered public accounting firm and principal accountants. The aggregate fees for professional services rendered by PwC were as follows for the periods indicated (in thousands):

	Year Ended December 31,
	2014		2013
Audit Fees (1)	$	532	$	1,302
Audit-Related Fees (2)		-		-
Tax Fees (3)		-		116
All Other Fees (4)		-		-
Total Fees		532		1,418

(1) Audit fees represent fees for professional services rendered in connection with (i) the audit of our annual financial statements, (ii) the review of our quarterly financial statements and (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. During the year ended December 31, 2013, fees associated with our IPO totaled approximately $1.0 million.

(2) Audit-related fees represent fees for assurance and related services.

(3) Tax fees represent fees for professional services rendered in connection with tax compliance.

(4) All other fees represent fees for services not classifiable under the other categories listed in the table above.

80

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accountant

As outlined in its charter, the Audit Committee of the board of directors of our General Partner is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. PwC’s engagement to conduct our 2014 audit was pre-approved by the Audit Committee. Additionally, since the formation of the Audit Committee, PwC has not performed any non-audit services.

81

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this Report:

(1) Financial Statements—See “Index to Consolidated Financial Statements” set forth on Page F-1.

(2) Financial Statement Schedules—None.

(3) Exhibits—Exhibits required to be filed by Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Annual Report and are incorporated herein by reference.

82

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: March 12, 2015	ARC LOGISTICS PARTNERS LP
	By:	ARC LOGISTICS GP LLC, its General Partner
	By:	/s/ VINCENT T. CUBBAGE
		Vincent T. Cubbage
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ VINCENT T. CUBBAGE Vincent T. Cubbage	Chief Executive Officer, Chairman and Director (Principal Executive Officer)	March 12, 2015
/s/ BRADLEY K. OSWALD Bradley K. Oswald	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)	March 12, 2015
/s/ STEPHEN J. PILATZKE Stephen J. Pilatzke	Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 12, 2015
/s/ JEFFREY R. ARMSTRONG Jeffrey R. Armstrong	Director	March 12, 2015
/s/ DANIEL R. CASTAGNOLA Daniel R. Castagnola	Director	March 12, 2015
/s/ EDWARD P. RUSSELL Edward P. Russell	Director	March 12, 2015
/s/ ERIC J. SCHEYER Eric J. Scheyer	Director	March 12, 2015
/s/ SIDNEY L. TASSIN Sidney L. Tassin	Director	March 12, 2015
/s/ GARY G. WHITE Gary G. White	Director	March 12, 2015
/s/ BARRY L. ZUBROW Barry L. Zubrow	Director	March 12, 2015

83

EXHIBIT INDEX

Exhibit No.	Description
2.1	Membership Interests Purchase Agreement, dated January 14, 2014, by and among Lightfoot Capital Partners, L.P., CorEnergy Infrastructure Trust, Inc. and Arc Terminals Holdings LLC (incorporated herein by reference to Exhibit 2.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on January 14, 2014 (SEC File No. 001-36168)).
3.1	Certificate of Limited Partnership of Arc Logistics Partners LP (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Arc Logistics Partners LP’s Registration Statement on Form S-1 filed on October 21, 2013 (SEC File No. 333-191534)).
3.2	First Amended and Restated Agreement of Limited Partnership of Arc Logistics Partners LP, dated November 12, 2013, by and among Arc Logistics GP LLC, Lightfoot Capital Partners, LP and Lightfoot Capital Partners GP LLC. (incorporated herein by reference to Exhibit 3.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on November 12, 2013 (SEC File No. 001-36168)).
4.1	Registration Rights Agreement, dated November 12, 2013, by and among Arc Logistics Partners LP and Lightfoot Capital Partners, LP (incorporated herein by reference to Exhibit 10.5 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on November 12, 2013 (SEC File No. 001-36168)).
10.1	Contribution Agreement, dated October 25, 2013, by and among Arc Logistics Partners LP, Arc Logistics GP LLC, Lightfoot Capital Partners, LP, Center Terminal Company-Cleveland, Gulf Coast Asphalt Company, L.L.C., Arc Terminals GP LLC, Arc Terminals LP, Arc Terminals Holdings LLC and Arc Terminals Mississippi Holdings LLC (incorporated herein by reference to Exhibit 10.1 to Amendment No. 2 to Arc Logistics Partners LP’s Registration Statement on Form S-1 filed on October 28, 2013 (SEC File No. 333-191534)).
10.2	Second Amended and Restated Revolving Credit Agreement, dated November 12, 2013, by and among Arc Logistics Partners LP, Arc Logistics LLC, Arc Terminals Holdings LLC, as Borrower, the Lenders thereto and SunTrust Bank, as Administrative Agent (incorporated herein by reference to Exhibit 10.2 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on November 12, 2013 (SEC File No. 001-36168)).
10.3	First Amendment, dated January 21, 2014, to the Second Amended and Restated Revolving Credit Agreement, dated November 12, 2013, by and among Arc Logistics Partners LP, Arc Logistics LLC, Arc Terminals Holdings LLC, as Borrower, the Lenders thereto and SunTrust Bank, as Administrative Agent, and the Amended and Restated Guaranty and Security Agreement, dated November 12, 2013, by and among Arc Terminals Holdings LLC, as Borrower, and the Guarantors in favor of the Administrative Agent, for the benefit of the Secured Parties (incorporated herein by reference to Exhibit 10.3 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on January 24, 2014 (SEC File No. 001-36168).
10.4†	Arc Logistics GP LLC Long-Term Incentive Plan, effective November 5, 2013 (incorporated herein by reference to Exhibit 10.3 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on November 12, 2013 (SEC File No. 001-36168)).
10.5	Services Agreement, dated November 12, 2013, by and among Arc Logistics Partners LP, Arc Logistics GP LLC and Lightfoot Capital Partners GP LLC (incorporated herein by reference to Exhibit 10.4 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on November 12, 2013 (SEC File No. 001-36168)).
10.6	Storage and Throughput Agreement by and between Arc Terminals LP and G.P. & W., Inc., d/b/a Center Oil Company and d/b/a Center Marketing Company, dated as of July 1, 2007, as amended (incorporated herein by reference to Exhibit 10.6 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)).
10.7	Assignment and Equity Purchase Agreement with GE EFS, dated October 24, 2013, by and among Arc LNG Holdings, LLC, Arc Terminals Mississippi Holdings LLC, Lightfoot Capital Partners, LP and EFS LNG Holdings, LLC (incorporated herein by reference to Exhibit 10.7 to the Amendment No. 2 to Arc Logistics Partners LP’s Registration Statement on Form S-1 filed on October 28, 2013 (SEC File No. 333-191534)).
10.8	Lease, dated January 21, 2014, by and between Arc Terminals Holdings LLC, as Lessee, and LCP Oregon Holdings, LLC, as Lessor (incorporated herein by reference to Exhibit 10.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on January 24, 2014 (SEC File No. 001-36168)).

84

Exhibit No.	Description
10.9	Guaranty of Lease, dated January 21, 2014, by Arc Logistics Partners LP, as Guarantor (incorporated herein by reference to Exhibit 10.2 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on January 24, 2014 (SEC File No. 001-36168)).
10.10†	Form of Phantom Unit Award Agreement (Employees) under the Arc Logistics Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on July 21, 2014 (SEC File No. 001-36168)).
10.11†	Form of Phantom Unit Award Agreement (Directors) under the Arc Logistics Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 of Arc Logistics Partners LP’s Current Report on Form 8-K filed on July 21, 2014 (SEC File No. 001-36168)).
21.1*	List of Subsidiaries of Arc Logistics Partners LP.
23.1*	Consent of PricewaterhouseCoopers, LLP.
23.2*	Consent of PricewaterhouseCoopers, LLP.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Gulf LNG Holdings Group, LLC and Subsidiaries Consolidated Financial Statements as of and for the years ended December 31, 2014 and 2013.
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.

† Management contract or compensatory plan or arrangement.

* Filed herewith.

** Furnished herewith.

85

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

ARC LOGISTICS PARTNERS LP
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2014 and 2013	F-2
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	F-3
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	F-4
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2014, 2013 and 2012	F-5
Notes to Consolidated Financial Statements	F-6

ARC LOGISTICS PARTNERS LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of Arc Logistics GP LLC and Unitholders of Arc Logistics Partners LP

In our opinion, the consolidated balance sheets and the related consolidated statements of operations and comprehensive income, partners’ capital and cash flows present fairly, in all material respects, the financial position of Arc Logistics Partners LP and its subsidiaries at December 31, 2014 and 2013, and the results of its operations and its cash flows for the years ended December 31, 2014, 2013 and 2012, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 12, 2015

F-1

ARC LOGISTICS PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,
	2014		2013
Assets:
Current assets:
Cash and cash equivalents	$	6,599	$	4,454
Trade accounts receivable		3,746		4,403
Due from related parties		900		722
Inventories		285		302
Other current assets		1,226		777
Total current assets		12,756		10,658
Property, plant and equipment, net		195,886		201,477
Investment in unconsolidated affiliate		72,858		72,046
Intangible assets, net		33,189		38,307
Goodwill		15,162		15,162
Other assets		1,737		1,716
Total assets	$	331,588	$	339,366
Liabilities and partners’ capital:
Current liabilities:
Accounts payable	$	2,136	$	4,115
Accrued expenses		2,133		2,144
Due to general partner		409		127
Other liabilities		34		25
Total current liabilities		4,712		6,411
Credit facility		111,063		105,563
Other non-current liabilities		2,747		-
Commitments and contingencies
Partners’ capital:
General partner interest		-		-
Limited partners’ interest
Common units – (6,867,950 units issued and outstanding      at December 31, 2014 and 2013)		119,130		125,375
Subordinated units – (6,081,081 units issued and outstanding      at December 31, 2014 and 2013)		93,588		101,525
Accumulated other comprehensive income		348		492
Total partners’ capital		213,066		227,392
Total liabilities and partners’ capital	$	331,588	$	339,366

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

F-2

ARC LOGISTICS PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(In thousands, except per unit amounts)

	Year Ended December 31,
	2014			2013			2012
Revenues:
Third-party customers	$	45,676		$	39,662		$	13,201
Related parties		9,230			8,179			9,663
		54,906			47,841			22,864
Expenses:
Operating expenses		27,591			19,291			7,266
Selling, general and administrative		9,396			7,116			2,283
Selling, general and administrative – affiliate		3,990			2,484			2,592
Depreciation		7,261			5,836			3,317
Amortization		5,427			4,756			624
Long-lived asset impairment		6,114			-			-
Total expenses		59,779			39,483			16,082
Operating income		(4,873	)		8,358			6,782
Other income (expense):
Gain on bargain purchase of business		-			11,777			-
Equity earnings from unconsolidated affiliate		9,895			1,307			-
Other income		17			48			4
Interest expense		(3,706	)		(8,639	)		(1,320	)
Total other income (expenses), net		6,206			4,493			(1,316	)
Income before income taxes		1,333			12,851			5,466
Income taxes		58			20			43
Net Income		1,275			12,831			5,423
Less: Net income attributable to preferred units		-			1,770			-
Net income attributable to partners’ capital		1,275			11,061			5,423
Other comprehensive income		(144	)		492			-
Comprehensive income attributable to partners’ capital	$	1,131		$	11,553		$	5,423
Earnings per limited partner unit, basic:
Common units	$	0.05		$	0.23		$	0.89
Subordinated units	$	0.05		$	1.56		$	0.89
Earnings per limited partner unit, diluted:
Common units	$	0.05		$	0.10		$	0.89
Subordinated units	$	0.05		$	1.56		$	0.89

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

F-3

ARC LOGISTICS PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2014			2013			2012
Cash flow from operating activities:
Net income	$	1,275		$	12,831		$	5,423
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation		7,261			5,836			3,317
Amortization		5,427			4,756			624
Gain on bargain purchase of business		-			(11,777	)		-
Long-lived asset impairment		6,114			-			-
Equity earnings from unconsolidated affiliate, net of distributions		(68	)		-			-
Amortization of deferred financing costs		496			4,428			432
Unit-based compensation		3,138			-			-
Changes in operating assets and liabilities
Trade accounts receivable		658			(3,430	)		(31	)
Due from related parties		(179	)		120			24
Inventories		17			(47	)		(6	)
Other current assets		(449	)		(606	)		105
Accounts payable		(3,151	)		1,765			1,931
Accrued expenses		(10	)		680			(176	)
Due to general partner		281			(88	)		(1,383	)
Other liabilities		2,756			(80	)		(250	)
Net cash provided by operating activities		23,566			14,388			10,010
Cash flows from investing activities:
Capital expenditures		(6,611	)		(14,108	)		(13,796	)
Investment in unconsolidated affiliate		(1,197	)		(72,740	)		-
Distributions from unconsolidated affiliate, net of equity earnings		-			1,144			-
Net cash paid for acquisitions		-			(82,000	)		-
Net cash used in investing activities		(7,808	)		(167,704	)		(13,796	)
Cash flows from financing activities:
Distributions		(18,179	)		(1,770	)		(6,081	)
Deferred financing costs		(518	)		(5,248	)		(1,152	)
Repayments to credit facility		(25,000	)		(50,937	)		(21,500	)
Proceeds from credit facility		30,500			126,000			32,000
Proceeds from initial public offering, net		-			117,296			-
Redemption of preferred units		-			(29,000	)		-
Distribution equivalent rights paid on unissued units		(416	)		-			-
Net cash (used in) provided by financing activities		(13,613	)		156,341			3,267
Net increase (decrease) in cash and cash equivalents		2,145			3,025			(519	)
Cash and cash equivalents, beginning of period		4,454			1,429			1,948
Cash and cash equivalents, end of period	$	6,599		$	4,454		$	1,429
Supplemental disclosure of cash flow information:
Cash paid for interest	$	3,398		$	4,586		$	1,184
Cash paid for income taxes		58			20			43
Non-cash investing and financing activities:
Issuance of preferred units		-			30,000			-
Deemed distributions to preferred units		-			1,770			-
Contribution of preferred units		-			1,000			-
Deferred financing costs in accrued expenses		-			-			11
(Decrease) Increase in purchases of property plant and equipment    in accounts payable and accrued expenses		1,173			414			(1,095	)

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

F-4

ARC LOGISTICS PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

				Partners' Capital
	Preferred Interest			Limited Partner Common Interest			Limited Partner Subordinated Interest			Limited Partners			General Partners			Accumulated Other Comprehensive Income			Total Partners' Capital
Partners’ (deficit) capital at December 31, 2011	$	-		$	-		$	-		$	98,286		$	(85	)	$	-		$	98,201
Net income		-			-			-			5,314			109			-			5,423
Cash distributions		-			-			-			(5,959	)		(122	)		-			(6,081	)
Partners’ (deficit) capital at December 31, 2012	$	-		$	-		$	-		$	97,641		$	(98	)	$	-		$	97,543
Issuance of preferred units		30,000			-			-			-			-			-			-
Net income		-			6,805			6,026			-			-			-			12,831
Other comprehensive income		-			-			-			-			-			492			492
Deemed distributions		1,770			(23	)		(1,747	)		-			-			-			(1,770	)
Cash distributions		(1,770	)		-			-			-			-			-			-
Recapitalization		(30,000	)		1,297			97,246			(97,641	)		98			-			1,000
Issuance of common units, net of offering costs		-			117,296			-			-			-			-			117,296
Partners’ capital at December 31, 2013	$	-		$	125,375		$	101,525		$	-		$	-		$	492		$	227,392
Net income		-			675			600			-			-			-			1,275
Other comprehensive income		-			-			-			-			-			(144	)		(144	)
Unit-based compensation		-			3,138			-			-			-			-			3,138
Distribution equivalent rights paid on unissued units		-			(416	)		-			-			-			-			(416	)
Distributions		-			(9,642	)		(8,537	)		-			-			-			(18,179	)
Partners’ capital at December 31, 2014	$	-		$	119,130		$	93,588		$	-		$	-		$	348		$	213,066

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

F-5

ARC LOGISTICS PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Presentation

Defined Terms

Unless the context clearly indicates otherwise, references in these consolidated financial statements to “Arc Terminals,” or the “Partnership” when used for periods prior to November 12, 2013, the closing date of the initial public offering of Arc Logistics Partners LP (the “IPO”), refer to Arc Terminals LP and its subsidiaries, which were contributed to Arc Logistics Partners LP in connection with the IPO, and references to “Arc Logistics,” or the “Partnership” when used for periods on or after the closing date of the IPO refer to Arc Logistics Partners LP and its subsidiaries. Unless the context clearly indicates otherwise, references to our “General Partner” for periods prior to the closing date of the IPO refer to Arc Terminals GP LLC which owned the general partner interest in Arc Terminals and references to our “General Partner” for periods on or after the closing date of the IPO 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 “GCAC” refer to Gulf Coast Asphalt Company, L.L.C., which contributed its preferred units in Arc Terminals to the Partnership upon the consummation of the IPO. 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 to the Partnership upon the consummation of the 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 used a portion of the proceeds from the IPO to acquire a 10.3% limited liability company interest in Gulf LNG Holdings, which is referred to herein as the “LNG Interest.”

Organization and Initial Public Offering

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 and petroleum products. 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 the Terminal Credit Facility (as defined below, see “Note 7—Debt”).

The $120.2 million of net proceeds from the IPO (including the underwriters’ option to purchase additional common units and after deducting the underwriting discount and structuring fee) were used to: (i) fund the purchase of the LNG Interest from an affiliate of GE EFS for approximately $72.7 million; (ii) make a cash distribution to GCAC as partial consideration for the contribution of its preferred units in Arc Terminals  to the Partnership of approximately $29.8 million; (iii) repay intercompany payables owed to the Sponsor of approximately $6.6 million; and (iv) reduce amounts outstanding under the Partnership’s Credit Facility (as defined below, see “Note 7—Debt”) by $6.0 million. The remaining funds were used for general partnership purposes, including the payment of transaction expenses related to the IPO and the Credit Facility.

Note 2—Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements were prepared in accordance with GAAP and under the rules and regulations of the SEC. The accompanying consolidated financial statements include the accounts of the Partnership and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

The Partnership has disclosed consolidated figures of the Partnership as if the Partnership had operated since the inception of Arc Terminals. The contribution of Arc Terminals to Arc Logistics in connection with the IPO was not considered a business combination accounted for under the purchase method as it was a transfer of assets under common control and, accordingly, balances have been transferred at their historical cost. The combined financial statements for the periods prior to the contribution on November 12, 2013 have been prepared using Arc Terminals’ historical basis in the assets and liabilities, and include all revenues, costs, assets and liabilities attributed to Arc Terminals.

F-6

During the first quarter of 2014, the Partnership identified a classification error in the Consolidated Statement of Cash Flows for the year ended December 31, 2013 associated with the distributions received from an unconsolidated affiliate for which a portion was incorrectly classified within net cash used in investing activities. The misclassification resulted in an understatement of “net cash used in investing activities” and “net cash provided by operating activities” of approximately $1.3 million. The misclassification had no impact on the Consolidated Balance Sheet or on the Consolidated Statement of Operations nor did it affect the net increase in cash and cash equivalents on the Consolidated Statement of Cash Flows as of or for the period ended December 31, 2013.

The Partnership evaluated the effect of the misclassification on its previously issued financial statements for the year ended December 31, 2013 and concluded the impact was not material. The Partnership recognized the impact of this misclassification in this Annual Report on Form 10-K by increasing cash flow used in investing activities and cash flows provided by operating activities by $1.3 million for the year ended December 31, 2013 as compared to what was previously reported in the 2013 Form 10-K.

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.

Cash and Cash Equivalents

The Partnership includes demand deposits with banks and all highly liquid investments with original maturities of three months or less in cash and cash equivalents. These balances are valued at cost, which approximates fair value.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Partnership reserves for specific trade accounts receivable when it is probable that all or a part of an outstanding balance will not be collected. The Partnership regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts as of December 31, 2014 and 2013. During the year ended December 31, 2013, the Partnership wrote off less than $0.1 million of uncollectible receivables. No other amounts have been deemed uncollectible in the periods presented in the consolidated statements of operations and comprehensive income.

Inventories

Inventories consist of additives which are sold to customers and mixed with the various customer-owned liquid products stored in the Partnership’s terminals. Inventories are stated at the lower of cost or estimated net realizable value. Inventory costs are determined using the first-in, first-out method.

Other Current Assets

Other current assets consist primarily of prepaid expenses and deposits.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost, less accumulated depreciation. The Partnership owns a 50% undivided interest in the property, plant and equipment at two terminal locations. At the time of acquisition, these assets were recorded at 50% of the aggregate fair value of the related property, plant and equipment. Expenditures for routine maintenance and repairs are charged to expense as incurred. Major improvements or expenditures that extend the useful life or productive capacity of assets are capitalized. Depreciation is recorded over the estimated useful lives of the applicable assets, using the straight-line method. The estimated useful lives are as follows:

Building and site improvements	1–40 years
Tanks and trim	1–40 years
Machinery and equipment	1–40 years
Office furniture and equipment	1–15 years

F-7

Capitalized costs incurred by the Partnership during the year for major improvements and capital projects that are not completed as of year-end are recorded as construction in progress. Construction in progress is not depreciated until the related assets or improvements are ready for intended use. Additionally, the Partnership capitalizes interest costs as a part of the historical cost of constructing certain assets and includes such interest in the property, plant and equipment line on the balance sheet. Capitalized interest for the years ended December 31, 2014 and 2013 was $0.2 million and $0.4 million, respectively.

Intangible Assets

Intangible assets primarily consist of customer relationships, acquired contracts and a covenant not to compete which are amortized on a straight-line basis over the expected life of each intangible asset.

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 years ended December 31, 2014, 2013 and 2012 except as discussed in “Note 5—Property, Plant and Equipment”.  

Goodwill

Goodwill represents the excess of consideration paid over the fair value of net assets acquired in a business combination. Goodwill is not amortized but instead is assessed for impairment at least annually or when facts and circumstances warrant. Goodwill impairment is determined using a two-step process. The first step of the goodwill impairment test is used to identify potential impairment by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test is performed. The second step compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. The Partnership determines the fair value of its single reporting unit by blending two valuation approaches: the income approach and a market value approach. The Partnership determined at December 31, 2014, there were no impairment charges and no event indicating an impairment has occurred.

No impairments were recorded against goodwill through December 31, 2014 and 2013.

	As of December 31,
	2014		2013
Beginning Balance	$	15,162	$	6,730
Goodwill acquired		-		8,432
Impairment		-		-
Ending Balance	$	15,162	$	15,162

Other Assets

Other assets consist primarily of debt issuance costs related to the Credit Facility amendment entered into in November 2013 (see “Note 7—Debt”). Debt issuance costs are capitalized and amortized over the term of the related debt using straight line amortization, which approximates the effective interest rate method. As of December 31, 2014, these costs were approximately $1.5 million.

Investment in Unconsolidated Affiliate

In connection with the IPO, the Partnership purchased the LNG Interest from an affiliate of GE EFS for approximately $72.7 million. The Partnership accounts for the LNG Interest using the equity method of accounting.

F-8

Deferred Rent

The Lease Agreement (as defined in “Note 13—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 Lease Agreement is included within “Other non-current liabilities” in the accompanying consolidated balance sheets at December 31, 2014.

Revenue Recognition

Revenues from leased tank storage and delivery services are recognized as the services are performed. 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 passes to the customer.

Income Taxes

Taxable income or loss of the Partnership generally is required to be reported on the income tax returns of the limited partners in accordance with the terms of the partnership agreement. Accordingly, no provision has been made in the accompanying consolidated financial statements for the limited partners’ federal income taxes. There are certain entity level state income taxes that are incurred at the Partnership level and have been recorded during the years ended December 31, 2014, 2013 and 2012.

Tax returns for the years ended December 31, 2014, 2013, 2012, 2011 and 2010 are open to IRS and state audits. The Partnership is not aware of any uncertain tax positions as of December 31, 2014 and 2013.

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 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 (Level 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). The carrying amount of the Terminal Credit Facility as well as the Partnership’s Credit Facility approximated fair value due to its short-term nature and market rate of interest (Level 2).

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

Unit-Based Compensation

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

For awards with performance conditions, the expense is accrued over the service period only if the performance condition is considered to be probable of occurring. When awards with performance conditions that were previously considered improbable become probable, the Partnership incurs additional expense in the period that the probability assessment changes (see “Note 10—Equity Plans”).

F-9

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 and preferred unitholders, if any, by the weighted average number of outstanding common and subordinated units, respectively, during the period. 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.”

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. The Partnership is currently evaluating the potential impact of this authoritative guidance on its financial condition, results of operations, cash flows and related disclosures.  This guidance will be effective for the Partnership beginning in the first quarter of 2017.

In June 2014, the FASB issued new guidance related to stock compensation.  The new standard requires that a performance target that affects vesting, and that could be achieved after the requisite service period, be treated as a performance condition.  As such, the performance target should not be reflected in estimating the grant date fair value of the award.  This update further clarifies that compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the periods for which the requisite service has already been rendered.  The Partnership does not expect this requirement to have a significant impact on its financial condition, results of operations, cash flows and related disclosures.  This guidance will be effective for the Partnership beginning in the first quarter of 2016, with early adoption optional.

F-10

Note 3—Acquisitions

Acquisitions

The following acquisitions were 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 consultants utilized several appraisal methodologies including income, market and cost approaches to estimate the fair value of the identifiable assets acquired.

Gulf Coast Asphalt Company, L.L.C. Asset Acquisition

In February 2013, the Partnership acquired substantially all of the Mobile, AL and Saraland, AL operating assets (the “GCAC Asset Acquisition”) related to the terminalling business of GCAC for approximately $85.0 million (“GCAC Purchase Price”) consisting of approximately $25.0 million in cash, $30.0 million in new preferred units (see “Note 8—Preferred Units”) in the Partnership and $30.0 million of assumed debt which was simultaneously extinguished at the acquisition closing by the Partnership.

The transaction was accounted for as a business combination in accordance with ASC Topic 805, “Business Combinations” (“ASC 805”). The GCAC Purchase Price exceeded the approximately $76.6 million fair value of the identifiable assets acquired and accordingly, the Partnership recognized goodwill of approximately $8.4 million. The Partnership believes the primary items that generated goodwill are both the value of the synergies created between the acquired assets and its existing assets, and its expected ability to grow the business acquired by leveraging its existing customer relationships. Furthermore, the Partnership expects that the entire amount of its recorded goodwill will be deductible for tax purposes. Transaction costs incurred in connection with the acquisition, consisting primarily of legal and other professional fees, totaled approximately $1.9 million and were expensed as incurred in accordance with ASC 805 and included in the ”Selling, general and administrative” line item in the accompanying consolidated statement of operations and comprehensive income. GCAC is also able to receive up to an additional $5.0 million in cash earnout payments based upon the throughput activity of one customer through December 31, 2016. As of December 31, 2014, no additional amounts have been paid or are owed to GCAC.

The following table summarizes the consideration paid and the amounts of assets acquired at the acquisition date (in thousands):

Consideration:
Cash paid to seller	$	25,000
Debt assumed		30,000
Preferred units issued		30,000
Total consideration	$	85,000
Allocation of purchase price:
Property and equipment	$	39,242
Intangible assets		37,326
Goodwill		8,432
Net assets acquired	$	85,000

Since the acquisition date in February 2013 through December 31, 2013, the acquired GCAC assets earned approximately $18.1 million in revenue and $9.7 million of operating income.

F-11

The following unaudited pro forma financial results for the years ended December 31, 2013 and 2012 are presented for comparative purposes only and assume the GCAC acquisition had occurred on January 1, 2012. The effects of the GCAC Asset Acquisition are included in the accompanying consolidated statement of operations and comprehensive income for the year ended December 31, 2014. The unaudited pro forma results reflect certain adjustments to the acquisition, such as increased depreciation and amortization expense on the fair value of the assets acquired. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed at the beginning of the periods presented, nor are they indicative of future results of operations (in thousands, except per unit amounts):

	Year Ended
	December 31,
	2013		2012
	(Unaudited proforma)
Total revenues	$	49,442	$	34,469
Operating income		11,822		5,627
Net Income	$	15,759	$	2,847
Less: Net income attributable to preferred units	$	2,023	$	2,400
Net income attributable to partners' capital	$	13,736	$	447
Earnings per unit - Basic:
Common and Subordinated	$	1.92	$	0.07
Earnings per unit - Diluted:
Common and Subordinated	$	1.86	$	0.07

Motiva Enterprises LLC Asset Acquisition

In February 2013, the Partnership acquired substantially all of the operating assets related to the Brooklyn, NY terminal (the “Brooklyn Terminal”) from Motiva Enterprises LLC (“Motiva”) for approximately $27.0 million (“Brooklyn Purchase Price”) in cash.

The transaction was accounted for as a business combination in accordance with ASC 805. The fair value of the identifiable assets acquired of approximately $38.8 million exceeded the Brooklyn Purchase Price. Accordingly, the acquisition has been accounted for as a bargain purchase and, as a result, the Partnership recognized a gain of approximately $11.8 million associated with the acquisition. The gain is included in the line item “Gain on bargain purchase of business” in the accompanying consolidated statements of operations and comprehensive income. Transaction costs incurred in connection with the acquisition, consisting primarily of legal and other professional fees, totaled approximately $1.5 million and were expensed as incurred in accordance with ASC 805 and included in the ”Selling, general and administrative” line item in the accompanying consolidated statements of operations and comprehensive income.

The following table summarizes the consideration paid and the amounts of assets acquired at the acquisition date (in thousands):

Consideration:
Cash paid to seller	$	27,000
Allocation of purchase price:
Property and equipment	$	36,749
Inventory		19
Intangible assets		2,009
Bargain purchase gain		(11,777	)
Net assets acquired	$	27,000

Since the acquisition date in February 2013 through December 31, 2013, the Brooklyn Terminal earned approximately $6.0 million in revenue and $3.5 million of operating income.

The unaudited pro forma results related to the Motiva acquisition have been excluded as the nature of the revenue-producing activities previously associated with the Brooklyn Terminal have changed substantially post-acquisition from intercompany revenue to third-party generated revenue. In addition, historical financial information for the Brooklyn Terminal prior to the acquisition is not indicative of how the Brooklyn Terminal is being operated since the Partnership’s acquisition and would be of no comparative value in understanding the future operations of the Brooklyn Terminal.

F-12

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 December 31, 2014 and, 2013 are represented below (in thousands):

Balance at December 31, 2012	$	-
Investment in Gulf LNG Holdings, LLC		72,739
Equity earnings		1,307
Distributions		(2,451	)
Amortization of premium		(41	)
Other comprehensive income		492
Balance at December 31, 2013	$	72,046
Equity earnings		9,895
Contributions		1,197
Distributions		(9,827	)
Amortization of premium		(309	)
Other comprehensive income		(144	)
Balance at December 31, 2014	$	72,858

Gulf LNG Holdings Acquisition

In connection with the IPO, in November 2013 the Partnership purchased the LNG Interest from an affiliate of GE EFS for approximately $72.7 million. The carrying value of the LNG Interest on the date of acquisition was approximately $64.1 million with a purchase price of approximately $72.7 million and the excess paid over the carrying value of approximately $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 asset, which is 28 years. The estimated aggregate amortization of this premium for its remaining useful life from December 31, 2014 is as follows (in thousands):

	Total
2015	$	309
2016		309
2017		309
2018		309
2019		309
Thereafter		6,753
	$	8,298

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

	As of December 31,
	2014		2013
Balance sheets
Current assets	$	12,537	$	8,694
Noncurrent assets		926,980		952,630
Total assets	$	939,517	$	961,324
Current liabilities	$	85,818	$	81,173
Long-term liabilities		733,401		773,115
Member’s equity		120,298		107,036
Total liabilities and member’s equity	$	939,517	$	961,324

F-13

	Year Ended December 31,
	2014		2013
Income statements
Revenues	$	186,243	$	186,090
Total operating costs and expenses		56,743		56,146
Operating income		129,500		129,944
Net income	$	96,062	$	94,895

For the year ended December 31, 2013, the Partnership calculated its equity earnings in the LNG Interest as shown in the table below (in thousands):

Gulf LNG Holdings net income for the year ended December 31, 2013	$	94,895
Percentage of Net Income attributable to the Partnership       from November 12, 2013 through December 31, 2013		13	%
Net Income attributable to the Partnership       from November 12, 2013 through December 31, 2013	$	12,689
Percentage of ownership in Gulf LNG Holdings		10.3	%
Equity earnings from unconsolidated affiliate	$	1,307

Note 5—Property, Plant and Equipment

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

	As of December 31,
	2014			2013
Land	$	49,615		$	51,175
Buildings and site improvements		36,298			34,660
Tanks and trim		91,463			92,337
Machinery and equipment		32,815			32,819
Office furniture and equipment		2,348			2,334
Construction in progress		6,175			5,003
		218,714			218,328
Less:  Accumulated depreciation		(22,828	)		(16,851	)
Property, plant and equipment, net	$	195,886		$	201,477

Due to a change in the operating logistics at the Partnership’s Chillicothe, IL terminal (the “Chillicothe Terminal”) in April 2013, the Partnership evaluated the long-lived assets at the Chillicothe Terminal for impairment as of December 31, 2013 and December 31, 2014. Based upon a market strategy to repurpose the Chillicothe Terminal, the Partnership’s estimate of undiscounted cash flows as of December 31, 2013 indicated that such carrying amounts were expected to be recovered. The Partnership re-evaluated the Chillicothe Terminal and based upon the inability to enter into a service agreement with a new or existing customer, the Partnership recognized a non-cash impairment loss of approximately $6.1 million as of December 31, 2014. The net impact of this impairment is reflected in “Long-lived asset impairment” in the accompanying consolidated statement of operations and comprehensive income.  

F-14

Note 6—Intangible Assets

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

	Estimated
	Useful Lives	As of December 31,
	in Years	2014			2013
Customer relationships	21	$	4,785		$	4,785
Acquired contracts	2-10		39,900			39,900
Noncompete agreements	2-3		741			741
			45,426			45,426
Less:  Accumulated amortization			(12,237	)		(7,119	)
Intangible assets, net		$	33,189		$	38,307

The estimated future amortization expense is approximately $4.3 million in 2015, $3.9 million in 2016, $3.9 million in 2017, $3.9 million in 2018, $3.9 million in 2019 and $13.3 million thereafter.

Note 7—Debt

Credit Facility

In January 2012, the Partnership entered into a $40.0 million credit facility (the “Terminal Credit Facility”). On November 12, 2013, concurrent with the closing of the IPO, the Partnership amended and restated the Terminal Credit Facility (the “Credit Facility”) with a syndicate of lenders, under which Arc Terminals Holdings LLC, a wholly owned subsidiary of the Partnership (“Arc Terminals Holdings”) is the borrower. The Credit Facility has up to $175.0 million of borrowing capacity (see “Note 2—Summary of Significant Accounting Policies—Other Assets” for discussion regarding deferred financing costs). As of December 31, 2014, the Partnership had borrowings of $111.1 million under the Credit Facility at an interest rate of 2.92%. Based on the restrictions under the total leverage ratio covenant, as of December 31, 2014, the Partnership had $23.4 million of available capacity under the Credit Facility.

The Credit Facility is available to refinance existing indebtedness, to fund working capital and to finance capital expenditures and other permitted payments and for other lawful corporate purposes and allows the Partnership to request that the maximum amount of the Credit Facility be increased by up to an aggregate 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 $10.0 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). The Partnership and each of the Partnership’s existing subsidiaries (other than the borrower) guarantee and each of the Partnership’s future restricted subsidiaries will also guarantee the Credit Facility. The Credit Facility matures on November 12, 2018.

Loans under the Credit Facility bear interest at a floating rate based upon the leverage ratio, equal to, at the Partnership’s option, either (a) a base rate plus a range from 100 to 200 basis points per annum or (b) a London Interbank Offer Rate (“LIBOR”) rate, plus a range of 200 to 300 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 plus 100 basis points per annum and (iii) the federal funds rate plus 0.50% per annum. The unused portion of the Credit Facility is subject to a commitment fee calculated based upon the Partnership’s 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 December 31, 2014 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 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 permitted acquisition or issuance of over $200 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.

F-15

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 facility are unconditionally guaranteed by the Partnership and each of the Partnership’s existing subsidiaries (other than the borrower) and each of the Partnership’s future restricted subsidiaries.

In January 2014, Arc Terminals Holdings, as borrower, and Arc Logistics and its other subsidiaries, as guarantors, entered into the first amendment (the “First Amendment”) to the Credit Facility agreement. The First Amendment principally modified certain provisions of the Credit Facility agreement to allow Arc Terminals Holdings to enter into the Lease Agreement relating to the petroleum products terminals and pipeline infrastructure located in Portland, OR (the “Portland Terminal”).

Terminal Credit Facility

The Terminal Credit Facility bore interest based upon LIBOR plus an applicable margin. The applicable margin was based on the leverage ratio as defined by the Terminal Credit Facility agreement, calculated at the beginning of each interest period. At the time of closing, the Partnership borrowed $22.0 million on the Terminal Credit Facility, applying $20.0 million to extinguish the Partnership’s prior revolving line of credit and the balance was used to pay transaction fees and fund operations. The Terminal Credit Facility agreement required the Partnership to maintain a leverage ratio of not more than 3.75 to 1.00, which decreased to 3.50 to 1.00 on or after March 31, 2013 and a minimum fixed charge ratio of not less than 1.25 to 1.00.

In February 2013, the Partnership amended the Terminal Credit Facility to include a $65.0 million term loan and a $65.0 million revolving line of credit. The amended Terminal Credit Facility had an initial three year term and bore interest based upon LIBOR plus an applicable margin. The applicable margin was based on the leverage ratio as defined in the Terminal Credit Facility agreement, calculated at the beginning of each interest period. At the time of the closing, the Partnership borrowed an additional $55.0 million which was used to satisfy the cash portion of the GCAC Purchase Price and to extinguish the debt acquired as a part of the GCAC Purchase Price. Also in February 2013, the Partnership borrowed an additional $27.0 million to complete the Motiva acquisition. The amended Terminal Credit Facility agreement required the Partnership to maintain an initial leverage ratio of not more than 5.00 to 1.00, which decreased to 4.00 to 1.00 by December 31, 2013 and a minimum fixed charge ratio of not less than 1.25 to 1.00.

Line of Credit

In October 2007, the Partnership entered into a revolving line of credit in the amount of $10.0 million. The collateral for the line of credit included the Partnership’s terminal assets. The revolving line of credit had a term of 12 months, with interest calculated monthly at the one month LIBOR plus 2.75%. In addition, there was an interest rate floor of 5.50% and a nonusage fee of 1.0%. The nonusage fee was calculated and payable quarterly and was waived if the average funded balance of any fiscal quarter exceeded a certain threshold. The nonusage fee was included as interest expense in the consolidated financial statements.

In August 2010, the Partnership amended its existing revolving line of credit to increase the amount available to $20.0 million and extend the maturity to August 1, 2011. In addition, the amendment required the Partnership to maintain a 1:1 ratio of EBITDA to designated expenses, which included mandatory principal payments of indebtedness, interest expense, taxes, distributions in excess of $5.0 million and capital expenditures less capital contributions, gains on the sale of assets and the amount of any new indebtedness.

In March 2011, the Partnership executed a commitment letter from the lender to extend the term of the revolving line of credit to March 2012 under the same interest rate and nonusage fee terms as previously disclosed.

This revolving line of credit was extinguished as a part of a new credit facility that the Partnership entered into in January 2012. At the time of extinguishment, the balance outstanding on the revolving line of credit was $20.0 million.

Note 8—Preferred Units

In February 2013, the Partnership, as a part of the GCAC Purchase Price (see “Note 3—Acquisitions”), issued 1,500,000 preferred units to GCAC with a value of $30.0 million. The preferred units ranked senior in liquidation preference and distributions to all existing and outstanding common and subordinated units. The preferred units were entitled to 8% annual distributions, paid 45 days following each calendar quarter, assuming the Partnership remained in compliance with all related covenants in the Terminal

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Credit Facility. If for any reason the Partnership were to be unable to pay the quarterly distributions on time to the preferred unitholders, the distribution amount would have compounded at an 8% annual interest rate until paid. At the time of the IPO the Partnership issued 779 common units and 58,426 subordinated units and made a cash distribution of approximately $29.0 million to GCAC for the contribution of its preferred units in Arc Terminals to the Partnership. Prior to the IPO, the Partnership recorded the preferred units as mezzanine equity in accordance with ASC Topic 480 Distinguishing Liabilities from Equity due to the redeemable nature, at the option of the holders, of the preferred units at a fixed and determinable price based upon certain redemption events which were outside the control of the Partnership. During the year ended December 31, 2013, the Partnership paid $1.8 million in cash distributions to the preferred unitholders. No other amounts have been distributed in the periods presented in the consolidated statements of operations and comprehensive income.

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Note 9—Partners’ Capital and Distributions

Initial Public Offering

On November 6, 2013, Arc Logistics’ common units began trading on the New York Stock Exchange under the symbol “ARCX.” On November 12, 2013, the Partnership closed the IPO by selling 6,000,000 common units representing limited partner interests in us at a price to the public of $19.00 per common unit. On November 18, 2013, the Partnership completed the sale of 786,869 additional common units pursuant to the partial exercise of the underwriters’ over-allotment option at a price to the public of $19.00 per unit.

In connection with the closing of the IPO and the recapitalization, the following transactions occurred:

● Lightfoot contributed all of its limited partner interests in Arc Terminals and all of its limited liability company interests in Arc Terminals GP LLC in exchange for 68,617 common units and 5,146,264 subordinated units in the Partnership;

● Center Oil contributed all of its limited partner interests in Arc Terminals in exchange for 11,685 common units and 876,391 subordinated units in the Partnership;

● GCAC contributed its preferred units in Arc Terminals in exchange for 779 common units and 58,426 subordinated units in the Partnership and $29.8 million in cash;

● Arc Terminals GP LLC and Arc Terminals merged with Arc Terminals GP LLC surviving the merger and then changing its name to Arc Logistics LLC;

● The public, through the underwriters, contributed $120.2 million of net proceeds in exchange for the issuance of 6,786,869 common units by the Partnership; and

● The General Partner maintained its non-economic general partner interest in the Partnership, and was issued 100.0% of the incentive distribution rights of the Partnership.

As a result of the recapitalization in connection with the IPO, the number of units outstanding was adjusted on a retroactive basis, which is reflected in the table below:

				Limited Partner		Limited Partner
	Preferred Units			Common Units		Subordinated Units
Units outstanding at December 31, 2012		-			80,302		6,022,655
Issuance of preferred units		1,500,000			-		-
Contribution of preferred units (1)		(1,500,000	)		779		58,426
Issuance of common units		-			6,786,869		-
Units outstanding at December 31, 2013		-			6,867,950		6,081,081
Units outstanding at December 31, 2014		-			6,867,950		6,081,081

(1) GCAC contributed its preferred units in Arc Terminals in exchange for 779 common units and 58,426 subordinated units in the Partnership and $29.8 million in cash.

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Cash Distributions

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

Quarter Ended	Total Quarterly Distribution Per Unit		Total Cash Distribution		Date of Distribution	Unitholders Record Date
December 31, 2014	$	0.4100	$	5,309	February 17, 2015	February 9, 2015
September 30, 2014	$	0.4100	$	5,309	November 17, 2014	November 10, 2014
June 30, 2014	$	0.4000	$	5,180	August 18, 2014	August 11, 2014
March 31, 2014	$	0.3875	$	5,018	May 16, 2014	May 9, 2014
December 31, 2014 (1)	$	0.2064	$	2,673	February 18, 2014	February 10, 2014

(1) Initial pro rata cash distribution, prorated for the period from November 13, 2013 to December 31, 2013.

Cash Distribution Policy

The 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 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 and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3875 per unit, or $1.55 per unit on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates.

The board 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 in the following manner:

● first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.3875 plus any arrearages from prior quarters;

● second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.3875; and

● third, 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.”

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The principal difference between the Partnership’s common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

The subordination period will end on the first business day after the Partnership has earned and paid at least (1) $1.55 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four quarter periods ending on or after September 30, 2016 or (2) $2.325 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distribution on the incentive distribution rights for a four-quarter period ending immediately preceding such date, in each case provided there are no arrearages on the Partnership’s common units at that time.

The subordination period will also end upon the removal of the General Partner other than for cause if no subordinated units or common units held by holder(s) of subordinated units or their affiliates are voted in favor of that removal. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

Note 10—Equity Plans

2013 Long-Term Incentive Plan

The Board of Directors of the General Partner (the “Board”) approved and adopted the Arc Logistics Long-Term Incentive Plan (the “2013 Plan”) in November 2013.  In July 2014, the Board formed a Compensation Committee (the “Compensation Committee”) to administer and serve as the Committee under the 2013 Plan.  Effective as of March 2015, the Board dissolved the Compensation Committee. On and after such date, the Board shall serve as the Committee under the 2013 Plan (the “Committee”). 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. The Committee also has the ability to grant distribution equivalent rights (“DER”) 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.  

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 (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 year ended December 31, 2014, the Partnership recorded approximately $0.4 million of unit-based compensation expense with respect to the Director Grants. As of December 31, 2014, the unrecognized unit-based compensation expense for the Director Grants is approximately $2.2 million, which will be recognized ratably over the remaining term of the awards.

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 (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 will vest the day after the end of the Subordination Period (as defined in the Partnership’s limited 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 and subordinated 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

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the eighth anniversary of the date of grant or longer upon the satisfaction of certain conditions specified in the award agreement.  For the year ended December 31, 2014, the Partnership recorded approximately $2.8 million of unit-based compensation expense with respect to the Employee Equity Grants. As of December 31, 2014, the unrecognized unit-based compensation expense for the Employee Equity Grants was approximately $18.3 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.  

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 year ended December 31, 2014, the Partnership recorded less than $0.1 million of unit-based compensation expense with respect to the Employee Liability Grants.  As of December 31, 2014, the unrecognized unit based compensation expense for the Employee Liability Grants was 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.

Subject to applicable earning criteria, the DER included in each Director Grant, Employee Equity Grant and Employee Liability Grant 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 consolidated statements of operations and comprehensive income. During the year ended December 31, 2014, the Partnership paid approximately $0.8 million in DERs to phantom unitholders, $0.4 million of which was reflected as a reduction of partners’ capital and $0.3 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 compensation expense related to the 2013 Plan for the year ended December 31, 2014 was $3.2 million, which was included in the “Selling, general and administrative” line item in the accompanying consolidated statements of operations and comprehensive income. The amount recorded as liabilities in “Other non-current liabilities” in the accompanying consolidated balance sheets as of December 31, 2014 was less than $0.1 million.

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

	Equity Awards					Liability Awards
	Year Ended					Year Ended
	December 31, 2014					December 31, 2014
	Number			Weighted Avg.		Number		Weighted Avg.
	of Phantom			Grant Date		of Phantom		Grant Date		Fair Value at
	Units			Fair Value		Units		Fair Value		12/31/2014
Balance at December 31, 2013		-		$	-		-	$	-	$	-
Granted		932,000		$	25.46		7,500	$	25.46	$	17.06
Vested		-		$	-		-	$	-	$	-
Forfeited		(3,500	)	$	25.46		-	$	-	$	-
Balance at December 31, 2014		928,500		$	25.46		7,500	$	25.46	$	17.06

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Note 11—Earnings Per Unit

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

Diluted net income per unit applicable to limited partners includes the effects of potentially dilutive units on the Partnership’s units. For the year ended December 31, 2014, the only potentially dilutive units outstanding consisted of the phantom units (see “Note 10—Equity Plans”). For the year ended December 31, 2013 the only potentially dilutive units outstanding consisted of GCAC’s preferred units (see “Note 8—Preferred Units”).

As a result of the recapitalization in connection with the IPO, earnings per unit was adjusted on a retroactive basis, which is reflected in the calculation below (in thousands, except per unit data):

	Years Ended December 31,
	2014		2013		2012
Net Income	$	1,275	$	12,831	$	5,423
Less:
Distribution equivalent rights for unissued units	$	627	$	-	$	-
Preferred unit distributions	$	-	$	1,770	$	-
Earnings attributable to preferred units	$	-	$	1,423	$	-
Net income available to limited partners	$	648	$	9,638	$	5,423
Numerator for basic earnings per limited partner unit:
Allocation of net income among limited partner interests:
Net income allocated to common unitholders	$	343	$	247	$	71
Net income allocated to subordinated unitholders	$	305	$	9,391	$	5,352
Net income allocated to limited partners:	$	648	$	9,638	$	5,423
Denominator for basic earnings per limited partner unit:
Common units		6,868		1,069		80
Subordinated units		6,081		6,031		6,023
Total basic units outstanding		12,949		7,100		6,103
Earnings per limited partner unit, basic:
Common units	$	0.05	$	0.23	$	0.89
Subordinated units	$	0.05	$	1.56	$	0.89
Numerator for diluted earnings per limited partner unit:
Allocation of net income among limited partner interests:
Net income allocated to common unitholders	$	343	$	247	$	71
Net income allocated to subordinated unitholders	$	305	$	9,391	$	5,352
Net income allocated to limited partners:	$	648	$	9,638	$	5,423
Denominator for diluted earnings per limited partner unit:
Common units		6,868		2,583		80
Subordinated units		6,081		6,031		6,023
Total diluted units outstanding		12,949		8,614		6,103
Earnings per limited partner unit, diluted:
Common units	$	0.05	$	0.10	$	0.89
Subordinated units	$	0.05	$	1.56	$	0.89

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Note 12—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.

Note 13—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 years ended December 31, 2014, 2013 and 2012 the General Partner incurred expenses of $4.0 million, $2.5 million and $2.6 million, respectively. Such expenses are reimbursable from the Partnership and are reflected in the “Selling, general and administrative—affiliate” line on the accompanying consolidated statements of operations and comprehensive income. These expenses approximate what would be incurred by the Partnership on a stand-alone basis. As of December 31, 2014 and December 31, 2013, the Partnership had a payable of approximately $0.4 million and $0.1 million, respectively, to the General Partner which is reflected as “Due to general partner” in the accompanying 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 a registration statement to register the common units issued to our Sponsor and the common units issuable upon the conversion of the subordinated units upon request of 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.

Assignment and Equity Purchase Agreement with GE EFS

In connection with the IPO, the Partnership entered into an assignment and equity purchase agreement with an affiliate of GE EFS that enabled the Partnership to acquire the LNG Interest. Approximately $72.7 million of the proceeds from the IPO were used to acquire the LNG Interest on the closing date of the IPO.

Other Transactions with Related Persons

GCAC Guarantee

GCAC guarantees up to $20 million of the Partnership’s Credit Facility. Under certain circumstances, the lenders may release GCAC from such guarantee.

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.

The term of the storage and throughput agreement extends through June 2017. 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

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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. The agreement has a one-year term and comes up for renewal in May 2015.

In May 2011, the Partnership entered into an agreement to provide refined products storage and throughput services to Center Oil at the Baltimore, MD terminal. The Partnership charges Center Oil a fixed fee for storage and a fee for ethanol blending and any 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. The agreement has a one-year term and comes up for renewal in May 2015.

In May 2013, the Partnership entered into an agreement to provide gasoline storage and throughput services to Center Oil at the Brooklyn, NY terminal. The Partnership charges Center Oil a fixed per barrel fee for each inbound delivery of ethanol and every outbound barrel of product shipped or committed to be 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. The agreement has a one-year term and comes up for renewal in May 2015.

Storage and Throughput Agreements with GCAC

In February 2013, and in connection with the GCAC Asset Acquisition, the Partnership entered into a storage and throughput agreement (the “GCAC Agreement 1”) with GCAC whereby the Partnership provides storage and throughput services for various petroleum products to GCAC at the acquired storage tanks existing at the time of the GCAC Asset Acquisition, in return for a fixed per barrel storage fee plus a fixed per barrel fee for related throughput and other ancillary services. In addition, the Partnership entered into a second storage and throughput agreement with GCAC (the “GCAC Agreement 2”) whereby the Partnership built an additional 150,000 barrels of storage tanks for GCAC to store and throughput various petroleum products in return for similar economic terms of GCAC Agreement 1.

The initial term of GCAC Agreements 1 and 2 is approximately five years. These agreements can be mutually extended by both parties as long as the extension is agreed to 180 days prior to the end of the initial termination date, otherwise the Partnership has the right to lease the storage capacity to any third party.

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

	For the Year Ended December 31,
	2014		2013		2012
Center Oil	$	7,382	$	7,587	$	9,663
GCAC		1,848		592		-
Total	$	9,230	$	8,179	$	9,663

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

	As of December 31,
	2014		2013
Center Oil	$	594	$	536
GCAC		306		186
Total	$	900	$	722

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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 “Lease Agreement”), pursuant to which Arc Terminals Holdings leased the Portland Terminal from LCP Oregon Holdings LLC (“LCP Oregon”), a wholly owned subsidiary of CorEnergy Infrastructure Trust, Inc. (“CorEnergy”).  Arc Logistics guaranteed Arc Terminals Holdings’ obligations under the 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.  The 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 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 rents in the initial years of the Lease Agreement were $230,000 per month through July 2014 (prorated for the partial month of January 2014) and are $417,522 for each month thereafter until the end of year five.  The base rents also increase each month starting with the month of August 2014 by a factor of 0.00958 of the specified construction costs incurred by LCP Oregon at the Portland Terminal, estimated at $10 million.  Assuming such improvements are completed, the base rent will increase by approximately $95,800 per month.  As of December 31, 2014, spending on terminal-related projects totaled approximately $5.6 million. The base rents will increase at the end of year five 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 year ended December 31, 2014, the expense associated with the Lease Agreement was $6.5 million. During the year ended December 31, 2014, there was no variable rent associated with the Lease Agreement.

So long as Arc Terminals Holdings is not in default under the Lease Agreement, it shall have the right to purchase the Portland Terminal at the end of the third year of the Lease Agreement and 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 right is not exercised, the 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 Lease Agreement on the fifth and tenth anniversaries, by providing written notice 12 months in advance, for a termination fee of approximately $4 million and $6 million, respectively.

Note 14—Major Customers

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

	% of Revenues									% of Receivables
	For the Year Ended December 31,									As of December 31,
	2014			2013			2012			2014			2013
Chevron U.S.A. Inc.		19	%		3	%		2	%		26	%		7	%
Center Oil		13	%		16	%		42	%		13	%		10	%
Total percentages associated with    significant customers		32	%		19	%		44	%		39	%		17	%

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Note 15—Commitments and Contingencies

Environmental matters

The Partnership may have environmental liabilities that arise from time to time in the ordinary course of business and provides 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. There were no accruals recorded for environmental losses as of December 31, 2014 and 2013.

Commitments and contractual obligations

Future non-cancelable commitments related to certain contractual obligations as of December 31, 2014 are presented below (in thousands):

	Payments Due by Period
	Total		2015		2016		2017		2018		2019		Thereafter
Long-term debt obligations	$	111,063	$	-	$	-	$	-	$	-	$	111,063	$	-
Operating lease obligations		30,251		6,346		6,511		6,382		10,906		106		-
Total	$	141,314	$	6,346	$	6,511	$	6,382	$	10,906	$	111,169	$	-

The schedule above assumes the Partnership will either exercise its Purchase Option or its right to terminate the Lease Agreement.

During the year ended December 31, 2014, the members of Gulf LNG Holdings approved spending up to approximately $14.6 million towards the development of a potential natural gas liquefaction and export terminal at the LNG Facility. For the year ended December 31, 2014, capital calls totaling $11.6 million were issued to all members of Gulf LNG Holdings, for which the Partnership’s pro rata share was approximately $1.2 million. As of December 31, 2014, the Partnership’s pro rata share of the remaining capital commitment was approximately $0.3 million.

In addition to the above, GCAC is able to receive up to an additional $5.0 million in cash earnout payments based upon  the throughput activity of one customer through December 31, 2016. As of December 31, 2014, no additional amounts have been paid or are owed to GCAC.

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Note 16— Quarterly Financial Data (Unaudited)

(in thousands, except per unit data)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2014:
Revenues	$	13,213	$	14,727	$	13,690	$	13,275
Operating income	$	384	$	1,185	$	39	$	(6,481	)
Net income (loss)	$	1,861	$	2,742	$	1,636	$	(4,964	)
Net income (loss) per limited partner unit:
Common units (basic and diluted)	$	0.14	$	0.21	$	0.11	$	(0.40	)
Subordinated units (basic and diluted)	$	0.14	$	0.21	$	0.11	$	(0.40	)
Weighted average number of limited partners units outstanding:
Common units (basic and diluted)		6,868		6,868		6,868		6,868
Subordinated units (basic and diluted)		6,081		6,081		6,081		6,081

(in thousands, except per unit data)	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
2013:
Revenues	$	9,608		$	13,096	$	12,625	$	12,512
Operating (loss) income	$	(17	)	$	2,837	$	2,733	$	2,804
Net income	$	9,857		$	1,338	$	1,274	$	361
Less: Net income attributable to preferred units	$	347		$	600	$	600	$	223
Net income attributable to partners' capital	$	9,511		$	738	$	674	$	138
Net income per limited partner unit, basic:
Common units	$	1.37		$	0.10	$	0.09	$	0.03
Subordinated units	$	1.37		$	0.10	$	0.09	$	0.00
Net income per limited partner unit, diluted:
Common units	$	1.37		$	0.10	$	0.09	$	0.01
Subordinated units	$	1.37		$	0.10	$	0.09	$	0.00
Weighted average number of limited partners units outstanding, basic:
Common units		80			80		80		4,035
Subordinated units		6,023			6,023		6,023		6,058
Weighted average number of limited partners units outstanding, diluted:
Common units		80			80		80		10,093
Subordinated units		6,023			6,023		6,023		-

Note 17—Subsequent Events

Cash Distribution

In January 2015, the Partnership declared a quarterly cash distribution of $0.41 per unit ($1.64 per unit on an annualized basis) totaling approximately $5.3 million for all common and subordinated units outstanding. The distribution is for the period from October 1, 2014 through December 31, 2014. This distribution was paid on February 17, 2015 to unitholders of record on February 9, 2015.

JBBR Acquisition

JBBR Purchase Agreement

In February 2015, Arc Terminals Joliet Holdings LLC, a Delaware limited liability company (“Buyer”) and a wholly owned subsidiary of the Partnership that will be, upon the closing of the JBBR Acquisition referred to below, owned jointly by the Partnership and an affiliate of GE Energy Financial Services (“GE EFS”), entered into a Membership Interest Purchase Agreement (the “JBBR Purchase Agreement”) pursuant to which Buyer has agreed, subject to the terms and conditions thereof, to acquire from CenterPoint Properties Trust (the “Seller”), for a base cash purchase price of $216 million, all of the issued and outstanding membership interests in Joliet Bulk, Barge & Rail LLC (“JBBR”; and such acquisition, the “JBBR Acquisition”), which among other

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things owns a terminal and a 4-mile crude oil pipeline that are in the final stages of construction in Joliet, Illinois (the “Facility”). In connection with the JBBR Acquisition, the Partnership has entered into a joint venture arrangement with GE EFS. Upon the closing of the JBBR Acquisition (the “Closing”), an affiliate of GE EFS will own 40% of Buyer, with the remaining 60% owned by the Partnership. The Partnership will manage the ongoing operations of Buyer and its subsidiaries, including JBBR.

Equity Commitment Letters

In February 2015, each of the Partnership and Aircraft Services Corporation (the “GE Equity Provider”), an affiliate of GE EFS, entered into separate equity commitment letters with Buyer under which the Partnership and GE Equity Provider agreed to contribute to Buyer sixty percent (60%) and forty percent (40%), respectively, of the JBBR Purchase Price to enable the Buyer to consummate the acquisition of JBBR. The obligations of the Partnership and GE Equity Provider to make such funding available to the Buyer at the Closing are subject to customary funding conditions, including the satisfaction (or waiver by Buyer) of all conditions to Buyer’s obligation to consummate the JBBR Acquisition pursuant to the JBBR Purchase Agreement, as more fully set forth in the respective equity commitment letters provided by the Partnership and GE Equity Provider. Following the Closing, the Partnership and GE EFS will indirectly own sixty percent (60%) and forty percent (40%), respectively, of the Buyer.

Interim Investors Agreement

In February 2015, the Partnership and EFS-S LLC (and an affiliate of GE EFS and, as such, “GE JV Partner”) entered into an interim investors agreement (the “Interim Investors Agreement”), which governs the actions of Buyer and the relationship between the Partnership and GE JV Partner as it relates to Buyer until the earlier of the Closing or the termination of the JBBR Purchase Agreement. The Partnership and GE JV Partner have agreed to enter into an amended and restated limited liability company agreement of Buyer concurrently with the Closing on terms consistent with terms set forth in the Interim Investors Agreement.

Material Relationships Relating to Interim Investors Agreement

GE EFS owns, indirectly, interests in Lightfoot. Lightfoot has a significant interest in the Partnership through its ownership of a 42.9% limited partner interest in the Partnership (prior to giving effect to the issuance by the Partnership of common units in the PIPE Transaction described below), 100% of the limited liability company interests in the General Partner, and all of the Partnership’s incentive distribution rights. Daniel Castagnola, Managing Director of GE EFS, which is an affiliate of General Electric Capital Corporation, serves on the board of directors of the General Partner.

Financing of the Partnership Equity Commitment

PIPE Transaction

In February 2015, the Partnership entered into a Unit Purchase Agreement (the “PIPE Purchase Agreement”) with the purchasers named therein (the “PIPE Purchasers”) to sell 4,411,765 common units at a price of $17.00 per unit (the “Common Unit Purchase Price”) in a private placement (the “PIPE Transaction”). The Common Unit Purchase Price will be reduced by the Partnership’s first quarter 2015 distribution in respect of its common units if the closing of the PIPE Transaction is after the record date for such distribution. The Partnership will use the proceeds from the private placement (totaling $75 million before placement agent commissions and expenses) to fund a portion of the Partnership’s obligations (the “Partnership Equity Commitment”) under the Partnership Equity Commitment Letter. If the PIPE Purchase Agreement is terminated pursuant to its terms, including on account of the termination of the JBBR Purchase Agreement or if the closing under the PIPE Purchase Agreement fails to occur by May 18, 2015, the Partnership shall pay to each PIPE Purchaser a commitment fee of 1% of such PIPE Purchaser’s commitment amount under the PIPE Purchase Agreement. During the period commencing on the date of execution of the PIPE Purchase Agreement and ending 90 days following the date of the closing of the PIPE Transaction, the Partnership is restricted under the PIPE Purchase Agreement from issuing, without the consent of the PIPE Purchasers holding a majority of the purchased common units (or, prior to closing, the PIPE Purchasers entitled to acquire at closing a majority of such common units), equity securities of the Partnership except for, in general, common units of the Partnership issued at or above a stated issuance price in (or to fund) an acquisition that is determined by the Board of Directors of the general partner of the Partnership to result in an increase in the Partnership’s distributable cash flow over the first full four quarters following such acquisition. The issuance of the common units pursuant to the PIPE Purchase Agreement is being made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof.

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Material Relationships Relating to PIPE Transaction

MTP Energy Master Fund Ltd. (“Magnetar PIPE Investor”), one of the PIPE Purchasers, has committed $9.5 million to the purchase of Common Units 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. Eric Scheyer, the Head of the Energy Group of Magnetar Financial LLC, also serves on the board of directors of the General Partner.

Debt Financing

In February 2015, the Partnership’s operating subsidiary, Arc Terminals Holdings, entered into a commitment letter with SunTrust Bank and SunTrust Robinson Humphrey, Inc. (together, “ SunTrust ” and such letter, the “Debt Commitment Letter”) that (i) sets forth the terms and conditions of an incremental senior secured credit facility (the “Incremental Facility”) consisting of an increase to the revolving Credit Facility set forth in the Second Amended and Restated Revolving Credit Agreement, dated as of November 12, 2013 (as amended, the “ Existing Credit Agreement ”), in an amount such that the aggregate amount of all outstanding loans and commitments under the Existing Credit Agreement will not exceed $275 million and the effectiveness of which remains subject to the receipt of consents from the necessary lenders under the Existing Credit Agreement and (ii) pursuant to which SunTrust agreed to provide 100% of a backstop senior secured credit facility of up to $275 million (the “ Backstop Commitment ” and, together with the Incremental Facility, the “Debt Financing”) in order to refinance the Existing Credit Agreement in the event that consents are not received from the necessary lenders to approve the Incremental Facility.

Long-Term Incentive Plan

In March 2015, the Board approved the grant of approximately 45,668 additional phantom units pursuant to the 2013 Plan to certain employees, consultants and a non-employee director of the Partnership Entities.  Each grant will have time based vesting, will be settled in common units and include a DER.

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