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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2016

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 partner 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  

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  

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

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

Indicate by check mark 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

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  

As of June 30, 2016, 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 $170,466,296, based upon a closing price of $13.00 per common unit as reported on the New York Stock Exchange on such date.

As of March 6, 2017, there were 19,477,021 common 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

 

19

 

 

Item 1B.

 

Unresolved Staff Comments

 

41

 

 

Item 2.

 

Properties

 

41

 

 

Item 3.

 

Legal Proceedings

 

41

 

 

Item 4.

 

Mine Safety Disclosures

 

41

 

Part II

 

 

Item 5.

 

 

Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

 

42

 

 

Item 6.

 

Selected Financial Data

 

44

 

 

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

46

 

 

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

 

65

 

 

Item 8.

 

Financial Statements and Supplementary Data

 

65

 

 

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

65

 

 

Item 9A.

 

Controls and Procedures

 

65

 

 

Item 9B.

 

Other Information

 

66

 

Part III

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

 

66

 

 

Item 11.

 

Executive Compensation

 

72

 

 

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

 

78

 

 

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

 

79

 

 

Item 14.

 

Principal Accounting Fees and Services

 

83

 

Part IV

 

Item 15.

 

Exhibits, Financial Statement Schedules

 

85

 

 

Item 16.

 

10-K Summary

 

85

 

SIGNATURES

 

86

 

 

 


 

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.

 

 

 

 

1


 

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 heating, blending, lab inspection services, sampling and mixing associated with our customers’ products that are stored in our tanks.

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

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

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

bpd:    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; and (iv) equity earnings from the LNG Interest; plus (v) cash distributions from the LNG Interest. Distributable Cash Flow is not a presentation made in accordance with GAAP. Please see the reconciliation of Distributable Cash Flow to cash flows from operating activities 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.

 

2


 

PCAOB:    Public Company Accounting Oversight Board.

 

SEC:    U.S. Securities and Exchange Commission.

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

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


 

3


 

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

 

PART I

ITEM 1.

BUSINESS

Overview

We are a fee-based, growth-oriented Delaware limited partnership formed by our Sponsor 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.

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

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 by providing 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.   We characterize our storage and throughput services fees into two categories:

 

o

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

 

o

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

Storage and throughput services fees accounted for approximately 95%, 92% and 86% of our revenue for the years ended December 31, 2016, 2015 and 2014, respectively.

 

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’ needs and activity levels. Ancillary services fees accounted for approximately 5%, 8% and 14% of our revenue for the years ended December 31, 2016, 2015 and 2014, respectively.

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.

 

4


 

We also receive cash distributions from the LNG Interest, 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, 2016, the remaining term of each of these terminal use agreements is approximately 15 years.

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 has a significant interest in us through its ownership of a 27% limited partner interest in us, 100% of our General Partner and all of our incentive distribution rights.

Recent Developments

Conversion of Subordinated Units

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

Acquisitions

Pennsylvania Terminals Acquisition

In January 2016, we acquired four petroleum products terminals (the “Pennsylvania Terminals”) located in Altoona, Mechanicsburg, Pittston and South Williamsport, Pennsylvania from Gulf Oil Limited Partnership (“Gulf Oil”) for $8.0 million (the “Pennsylvania Terminals Acquisition”).  The acquisition, which expanded our operational footprint into the state of Pennsylvania increased our total shell capacity by approximately 12% to 7.7 million barrels across 21 terminals at the time of the acquisition.  In connection with this acquisition, we acquired an option (which must be exercised within a stated period of time) to purchase from Gulf Oil additional land with storage tanks located adjacent to one of the Pennsylvania Terminals for an agreed upon purchase price.  At closing, we also entered into a take-or-pay terminal services agreement with Gulf Oil with an initial term of two years.   We provide throughput and related terminalling services to Gulf Oil under the terminal services agreement at the Pennsylvania Terminals, as well as several of our other petroleum products terminals.  We financed the acquisition with a combination of available cash and borrowings under our Second Amended and Restated Revolving Credit Agreement (the “Credit Facility”).  We expect to invest additional capital over the next one to two years to support new customer initiatives at the Pennsylvania Terminals including bringing additional capacity on-line, improving renewable fuel capabilities, improving truck loading capabilities and other various terminal improvements.   

Other Recent Developments

LNG Facility Arbitration

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

 

Affiliates of Kinder Morgan, Inc., which control Gulf LNG Holdings and operate the LNG Facility, have expressed to us that they view the assertions by Eni USA to be without merit, and that they intend to vigorously contest the assertions set forth by Eni USA.  As contemplated by the terminal use agreement, disputes are meant to be resolved by final and binding arbitration.  Although we do not control Gulf LNG Holdings, we also are of the view that the assertions made by Eni USA are without merit. A three-member arbitration panel conducted an arbitration hearing in January, 2017.  We expect the arbitration panel will issue its decision within approximately six months.  Eni USA has indicated that it will continue to pay the amounts claimed to be due pending resolution of the dispute.

 

If the assertions by Eni USA to terminate or amend its payment obligations under the terminal use agreement prior to the expiration of its initial term are ultimately successful, our business, financial conditions and results of operations and our ability to make cash distributions to our unitholders would be (or in the event Eni USA’s payment obligations are amended, could be) materially

 

5


 

adversely affected.  For the year ended December 31, 2016, 17% and 24% of our Adjusted EBITDA and Distributable Cash Flow, respectively, were associated with our LNG Interest.  We are unable at this time to predict the amount of the legal fees in this matter that will be allocable to our LNG Interest.

Assets and Operations

As of March 6, 2017, our energy logistics assets are strategically located in the East Coast, Gulf Coast, Midwest, Rocky Mountains and West Coast regions of the United States and supply a diverse group of third-party customers, including major oil companies, independent refiners, 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 trained employees and specific assets allow 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:

 

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

 

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

 

the LNG Interest in connection with the LNG Facility, which has 320,000 M3 of LNG storage, 1.5 bcf/d natural gas sendout capacity and interconnects to major natural gas pipeline networks. The following table sets forth certain information regarding our terminal facilities:

 

6


 

 

 

 

 

 

 

Shell

 

 

 

 

 

 

 

 

 

Capacity

 

 

 

Name

 

Location

 

Principal Products

 

(bbls)

 

 

Supply & Delivery Modes

Altoona

 

Altoona, PA

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

163,500

 

 

Pipeline; Truck

Baltimore (1)

 

Baltimore, MD

 

Gasoline; Distillates; Ethanol

 

 

442,000

 

 

Pipeline; Railroad; Marine; Truck

Blakeley

 

Blakeley, AL

 

Distillates; Asphalt; Fuel Oil; Crude Tall Oil

 

 

708,000

 

 

Marine; Truck

Brooklyn

 

Brooklyn, NY

 

Gasoline; Ethanol

 

 

63,000

 

 

Pipeline; Marine; Truck

Chickasaw

 

Chickasaw, AL

 

Distillates; Fuel Oil; Crude Tall Oil

 

 

609,000

 

 

Railroad; Marine; Truck

Chillicothe

 

Chillicothe, IL

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

273,000

 

 

Truck

Cleveland - North

 

Cleveland, OH

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

426,000

 

 

Pipeline; Railroad; Marine; Truck

Cleveland - South

 

Cleveland, OH

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

191,000

 

 

Pipeline; Railroad; Marine; Truck

Dupont

 

Pittston, PA

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

138,500

 

 

Pipeline; Truck

Joliet (2)

 

Joliet, IL

 

Crude Oil: Dry Bulk

 

 

300,000

 

 

Marine; Railroad; Truck

Madison

 

Madison, WI

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

150,000

 

 

Pipeline; Truck

Mechanicsburg

 

Mechanicsburg, PA

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

378,500

 

 

Pipeline; Truck

Mobile - Main

 

Mobile, AL

 

Fuel Oil; Asphalt

 

 

1,093,000

 

 

Marine; Truck

Mobile - Methanol

 

Mobile, AL

 

Methanol

 

 

294,000

 

 

Marine; Truck

Norfolk

 

Chesapeake, VA

 

Gasoline; Distillates; Ethanol

 

 

212,600

 

 

Pipeline; Marine; Truck

Pawnee

 

Weld County, CO

 

Crude Oil

 

 

300,000

 

 

Pipeline; Truck

Portland (3)

 

Portland, OR

 

Crude Oil; Asphalt; Aviation Gas; Distillates

 

 

1,466,000

 

 

Railroad; Marine; Truck

Selma

 

Selma, NC

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

171,000

 

 

Pipeline; Truck

Spartanburg (1)

 

Spartanburg, SC

 

Gasoline; Distillates; Ethanol

 

 

82,500

 

 

Pipeline; Truck

Toledo

 

Toledo, OH

 

Gasoline; Distillates; Aviation Gas; Ethanol; Biodiesel

 

 

244,000

 

 

Pipeline; Railroad; Marine; Truck

Williamsport

 

Williamsport, PA

 

Gasoline; Distillates; Ethanol; Biodiesel

 

 

137,000

 

 

Pipeline; Truck

Total Terminals

 

 

 

 

 

 

7,842,600

 

 

 

 

 

(1)

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

(2)   Represents 100% of the Joliet terminal.

(3)

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

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:

Altoona. The Altoona terminal is a pipeline facility located in Altoona, PA. We have owned and operated the facility since we acquired the facility in January 2016. The fifteen-acre site has eight tanks with a total shell storage capacity of 163,500 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 biodiesel blending, ethanol blending and generic additive systems as services to our customers.

Baltimore. 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,

 

7


 

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 services to our customers.

Blakeley. 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 oils, distillates and crude tall oil. 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 and mixing, 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.

Brooklyn. 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 services to its customers.

Chickasaw. 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, distillates, crude tall oil and marine diesel. Products are received and/or delivered via railroad, marine vessel (up to general purpose tanker) or truck loading rack. The terminal offers steam heating, blending and railcar unloading/management as ancillary services to our customers.

Chillicothe. 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—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, butane blending, ethanol blending and proprietary and generic additive systems as services to our customers.

Cleveland—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 biodiesel blending, butane blending, ethanol blending and additive systems as services to our customers.

Dupont. The Dupont terminal is a pipeline facility located in Pittston, PA. We have owned and operated the facility since we acquired the facility in January 2016. The twenty-acre site has nine tanks with a total shell storage capacity of 138,500 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 services to our customers.

Joliet. The Joliet terminal is a unit-train facility with a 4-mile crude oil pipeline located in Joliet, IL.  We have owned and operated the facility since we acquired the facility in May 2015. The terminal commenced operations on May 17, 2015, and construction of the facility has been completed.  The 255-acre site has two tanks with a total shell capacity of 300,000 barrels. The terminal receives, stores and delivers crude oil to a refinery in the Chicago market. Crude oil is received via unit-train unloading facility to our tanks and delivered via a proprietary pipeline.  The terminal has the ability to expand its services to receive and/or deliver heavy and light petroleum products through railcar, marine vessels, and trucks or through its proprietary pipeline and potentially new connections to other pipelines in the vicinity of the facility.  In addition, the terminal can expand its storage capacity by an additional 1.0 million barrels. The terminal also has dry bulk capabilities that include the movement of salt and aggregates in/out of the facility.

Madison. 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 services to our customers.

 

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Mechanicsburg. The Mechanicsburg terminal is a pipeline facility located in Mechanicsburg, PA. We have owned and operated the facility since we acquired the facility in January 2016. The sixteen-acre site has eight tanks with a total shell storage capacity of 378,500 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 biodiesel blending, butane blending, ethanol blending and generic additive systems as services to our customers.

Mobile—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 and 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 services to our customers.

Mobile—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. 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 butane blending, ethanol blending and additive systems as services to its customers.

Pawnee. The Pawnee terminal is a truck to pipeline terminal located in northeastern Weld County, CO. We have owned and operated the facility since we acquired the facility in July 2015. We completed the construction of the terminal in 2016.  The 10-acre site has three tanks with a total shell capacity of 300,000 barrels (with room for additional storage). The terminal is capable of receiving 150,000 barrels per day of crude oil via truck unloading stations and connections to local crude oil gathering lines. The terminal serves as the primary injection point on the Northeast Colorado Lateral of the Pony Express Pipeline, providing the terminal customers with access to storage in Cushing, OK.

Portland. The Portland terminal is a rail/marine facility adjacent to the Willamette River in Portland, OR. We have operated the facility under a long-term lease with LCP Oregon since January 2014. 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, 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 services.

Selma. 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 butane blending, ethanol blending and proprietary and generic additive systems as services to our customers.

Spartanburg. 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 services to our customers.

Toledo. 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, marine, railroad or truck loading rack. The terminal offers butane blending, ethanol blending and additive systems as services to our customers.

Williamsport. The Williamsport terminal is a pipeline facility located in Williamsport, PA. We have owned and operated the facility since we acquired the facility in January 2016. The twenty-four-acre site has six tanks with a total shell storage capacity of 137,000 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 generic additive systems as services to our customers.

 

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Rail Transloading Facilities

The following table sets forth certain information regarding our rail transloading facilities:

  

 

 

 

 

 

(Un)loading

 

 

 

 

 

 

 

 

 

Capacity

 

 

 

Name

 

Location

 

Principal Products

 

(bpd)

 

 

Rail Service Provider

Chickasaw

 

Chickasaw, AL

 

Distillates; Fuel Oil; Crude Tall Oil

 

 

9,000

 

 

Terminal Railway Company

Joliet (1)

 

Joliet, IL

 

Crude Oil

 

 

85,000

 

 

CN Railway

Portland

 

Portland, OR

 

Crude Oil

 

 

18,000

 

 

BNSF

Saraland

 

Saraland, AL

 

Crude Oil; Chemicals

 

 

14,000

 

 

NS

Total Rail/Transloading Facilities

 

 

 

 

126,000

 

 

 

(1)

Represents 100% of the Joliet facility.

 

Chickasaw. 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.

Joliet.  The Joliet facility is a rail transloading/unloading facility located in Joliet, IL.  We have owned and operated the facility since we acquired the facility in May 2015.  The Joliet facility commenced operations on May 17, 2015, and construction of the facility has been completed.  The site has 120 railcar unloading spots (60 rail unloading spots capable of servicing heated products) and is capable of unloading 85,000 bbls per day.  Products are received and/or delivered via railroad and delivered into tanks at the terminal.  

Portland. 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. 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

 

Name

 

Location

 

Principal Products

 

Capacity

 

Supply & Delivery Modes

Pascagoula

 

Pascagoula, MS (1)

 

LNG

 

320,000 M3

 

Pipeline; Marine

 

(1)

The capacity represents the full capacity of the LNG facility.  We own a 10.3% interest in Gulf LNG Holdings, the entity which owns the 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, 2016, 100% of the capacity was under contract through two multi-year terminal use agreements with remaining terms of approximately 15 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.

 

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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.

For the year ended December 31, 2016, our terminals had service agreements with 82 customers, with our top fifteen customers by revenue having been customers at our facilities for a weighted average term of five years and, excluding those customers that are new as a result of the Joliet and Pawnee terminals acquisitions in 2015, a weighted average term of nine years. The following table presents percentage of revenues associated with our top three customers for the periods indicated:

 

 

For the Year Ended December 31,

 

 

2016

 

 

2015

 

 

2014

 

ExxonMobil Oil Corporation

 

33

%

 

 

27

%

 

 

2

%

Chevron U.S.A. Inc.

 

12

%

 

 

16

%

 

 

19

%

Center Oil

 

6

%

 

 

8

%

 

 

13

%

Outside of those customers listed above, no other customer accounted for 10% or more of our revenues during the years ended December 31, 2016, 2015 and 2014.  For the years ended December 31, 2016, 2015 and 2014, our top five customers accounted for 61%, 61% and 55% of our revenues, respectively.  

We believe we have a diversified portfolio of financially reputable counterparties, with 61% of our 2016 revenue generated from our top five customers, of which 78% was generated by customers that are either investment grade counterparties or counterparties with investment grade parent entities.  In addition, for the year ended December 31, 2016, 61% of our total revenue was generated from investment grade counterparties or counterparties with investment grade parents.  

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 as short as one-month up to multiple years. The services agreements are customer specific and can provide a combination of terminalling, storage, throughput, transloading and ancillary services. As of December 31, 2016, approximately 66% of our services agreements are operating under evergreen provisions.  As of December 31, 2016, approximately 84% of our revenues were generated pursuant to take-or-pay provisions in our services agreements with a remaining weighted average term of two years.  As of December 31, 2016, approximately 80% of our capacity was under contract.

 

The terminal use agreements associated with the LNG Facility are two multi-year terminal use agreements with a remaining term of approximately 15 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 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. For information regarding the Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA that an affiliate of Gulf LNG Holdings received in relation to one of the above mentioned terminal use agreements, please see “Part I, Item 1.  Business—Recent Developments— Other Recent Developments—LNG Facility Arbitration” and “Part II, Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Other Recent Developments—LNG Facility Arbitration.”

Competition

We compete with other independent terminal operators, petroleum product marketers and distributors as well as major oil companies on the basis of terminal location, services provided, safety and price. Competition from terminal operators primarily comes from energy companies that either (1) possess marketing and trading functions or (2) require infrastructure to support their upstream and downstream operations. These companies tend to prioritize movement of their own products over their third-party customers.

 

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Accordingly, we believe that we are able to compete successfully because of our safe, dependable service and our experience in responding to customer needs without conflicting or competing with our customers’ core business strategies.  

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 may not be 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, our assets 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, 2016, we employed 111 people who provide direct support to our operations. Only six of our employees, or approximately 5%, 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, 2019.  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.”

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 compliance with applicable environmental laws and regulations, except for such non-compliance that would not have a material adverse impact on our financial position, results of operations, and cash available for distribution to our unitholders. 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 obtain new or amended permits and to incur significant expenditures. In addition, many environmental laws contain citizen suit provisions, allowing environmental groups to bring suits to enforce compliance with environmental laws. Failure to comply with these laws and

 

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regulations or obtain such new permits or amendments of existing permits 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 or such coverage is withheld or not adequate, 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 that are 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 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.

 

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In October 2015, the EPA also revised the existing National Ambient Air Quality Standards (“NAAQS”) for ground‑level ozone to update both the primary ozone standard and the secondary standard. Both standards are 8-hour concentration standards of 70 parts per billion.  These more stringent standards may affect the petroleum industry and transportation fuels because nitrogen oxides and volatile organic compounds are recognized as pre‑cursors of ozone. The EPA is expected to make final geographical attainment designations and issue final non-attainment area requirements pursuant to this NAAQS rule by late 2017, and states are also expected to implement their own rules, which could be more stringent than federal requirements. If any of our terminals are determined to be in areas that do not meet the new NAAQs for ground-level ozone, we may be required to install additional pollution controls and any efforts to expand operations at these terminals may be subject to more stringent permitting processes and emissions requirements. In the meantime, several legal challenges to the new standard are pending. We are not able to predict the outcome of the designations or the legal challenges, and we cannot assure you that these new requirements will not have a material impact on our operations and cost‑structure.

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. In addition, at the 2015 United Nations Framework Convention on Climate Change in Paris, the United States and nearly 200 other nations entered into an international climate agreement. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. The Paris Agreement entered into force in November 2016 and the United States is one of over 100 nations that have indicated an intent to comply with the agreement.  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 assets or operations.

In June 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Though the plan did not regulate refineries or transportation fuels directly, it proposed a national carbon pollution standard that is projected to cut emissions produced by United States power plants by 2030, by 30% from 2005 levels. In August 2015, the EPA issued its final Clean Power Plan (“CPP”) rules that establish carbon pollution standards for power plants. The CPP does not regulate fuels, but sets a national carbon pollution standard for emissions produced by United States power plants. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the CPP, and has also proposed a federal compliance plan to implement the CPP in the event that approvable state plans are not submitted. Judicial challenges have been filed, and on February 9, 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP before the United States Court of Appeals for the District of Columbia (“Circuit Court”) even issued a decision.  By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.   The stay suspends the rule, including the requirement that states submit their initial plans by September 2016.  The Supreme Court’s stay applies only to EPA’s regulations for CO2 emissions from existing power plants and will not affect EPA’s standards for new power plants.  We cannot predict how either the Circuit Court or the Supreme Court will rule on the legality of the CPP, or the manner in which any final changes might specifically impact our business.

Various federal, state and local agencies have the authority to prescribe product quality specifications for the petroleum products and renewable fuels that we store, throughput and transload, largely in an effort to reduce air pollution. Failure to comply with these

 

14


 

regulations can result in substantial penalties. Although we can give no assurances, we believe we are currently in substantial compliance with these regulations.  Changes in product quality specifications could require us to incur additional handling costs or reduce our throughput volume. For instance, different product specifications for different markets could require the construction of additional storage.

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. In September 2015, the EPA and U.S. Army Corps of Engineers issued a rule defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the United States. To the extent the rule expands the scope of jurisdiction of the Clean Water Act, we could face additional permitting obligations and increased costs of compliance. Alternatively, the rule could restrict exploration and production efforts by producers whose crude oil, petroleum products and chemicals we store, throughput and transload. That restriction of supply could adversely affect our financial position, results of operations or cash available for distribution to our unitholders.  The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge.  On January 13, 2017, the Supreme Court agreed to address the question of whether the Sixth Circuit Court of Appeals has jurisdiction to address the consolidated challenges to the rule.

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.

 

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Hazardous Materials Transportation

The trend in hazardous material transportation has been increased oversight and regulation.  For example, in recent years, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and other federal agencies have reviewed the adequacy of transporting Bakken crude oil by rail transport and, as necessary have pursued rules to better assure the safe transport of Bakken crude oil by rail.  For example, in May 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standard for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, and a requirement that older DOT-111 tank cars be phased out by as early as October 1, 2017 if they are not already retrofitted to comply with new tank car design standards.  The rule also includes a new braking standard for certain trains, designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing analyses, speed restrictions and information for local government agencies, and provides new sampling and testing requirements to improve classification of energy products placed into transport.  In addition to action taken or proposed by federal agencies, a number of states proposed or enacted laws in recent years that encourage safer rail operations or urge the federal government to strengthen requirements for these operations.

We do not believe that compliance with federal, state or local hazardous materials transportation regulations will have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders. However, these, and future statutes, regulatory changes, or initiatives regarding hazardous material transportation, could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with standards and regulations emerging from these and future rulemakings will not be material to our business, financial condition or results of operations. Furthermore, we can provide no assurance that future events, such as changes in existing laws (including changes in the interpretation of existing laws), the promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil, or, or the development or discovery of new facts or conditions will not cause us to incur significant costs. Any such requirements would apply to the industry as a whole.

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 compliance with applicable OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances, except for such non-compliance that would not have a material adverse impact on our financial position, results of operations, or cash available for distribution to our unitholders.

Pipeline Regulation

The Joliet terminal includes a 4-mile crude oil pipeline that is a common carrier pipeline and subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the October 1, 1977, version of the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992.  The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier liquids pipelines and generally require the rates and practices of interstate liquids pipelines to be just and reasonable and nondiscriminatory.  The ICA also requires these pipelines to keep tariffs on file with FERC that set forth the rates the pipeline charges for providing transportation services and the rules and regulations governing these services; a tariff applicable to movements on our FERC-regulated liquids pipeline is on file with FERC.

Security Regulation

Since the September 11, 2001 terrorist attacks on the United States, the U.S. government has issued warnings that energy infrastructure assets may be future targets of terrorist organizations. These developments have subjected our operations to increased risks. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Where required by federal or local laws, we have prepared security plans for the storage and distribution facilities we operate. Terrorist attacks aimed at our facilities and any global and domestic economic repercussions from terrorist activities could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.  For instance, terrorist activity could lead to increased volatility in prices for the crude oil, petroleum products and chemicals that we store, throughput and transload.

Safety and Maintenance

We perform preventive and normal maintenance on all of our storage tanks, terminals, marine facilities, 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

 

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accordance with the requirements of the American Petroleum Institute standard.  Depending on the location and the products stored in a storage tank, some tanks may need to be equipped with internal floating roofs to prevent potentially flammable vapor accumulation.

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 and administered by the PHMSA 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. Additionally, the adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could cause us to incur increased capital and operating costs as well as operational delays and have a significant adverse effect on our results of operations.  

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. In addition, we are required from time to time to renew existing permits and licenses, and the failure to renew any material permit or license could have a 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.

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

 

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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 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 surrounding the supply of and demand for crude oil, petroleum products and chemicals in the markets served by our facilities;

 

the global pricing benchmarks and the associated transportation differentials surrounding crude oil and petroleum products;

 

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 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 weather events such as 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.

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. 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 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.

On March 1, 2016, Gulf LNG Holdings received a Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA with respect to the terminal use agreement to which Eni USA is a party, pursuant to which Eni USA seeks declaratory and monetary relief in respect of such terminal use agreement, including the right to terminate such terminal use agreement.  If Eni USA were to prevail on its claim to terminate such agreement or to amend its payment obligations, such termination would (or such amendment could) have a material adverse effect on our business, financial condition and results of operations and our ability to make quarterly distributions to our unitholders.  Please see “Part I, Item 1.  Business—Recent Developments—LNG Facility Arbitration” and “Part II, Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Other Recent Developments—LNG Facility Arbitration.”

 

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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 or an effort by customers to terminate 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.

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:

 

the supply and corresponding demand of crude oil in the domestic or global markets could lead to either a reduction or an increase in drilling activity, which could adversely impact the pricing for crude oil;

 

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

 

insufficient demand of crude oil and petroleum products in the domestic or global market could lead to lower crude oil and refined petroleum product prices;

 

lower prices for crude oil and petroleum 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.

Changes in petroleum demand and distribution and weakness in the United States economy may adversely affect our business.

 Demand for the services we provide depends upon the demand for the products we handle in the regions we serve and the supply of the products in the regions connected to our facilities or from which our customers source products handled by our facilities.  Prevailing economic conditions, petroleum product and crude oil price levels and weather affect the demand for petroleum products and crude oil.  Changes in transportation and industrial activity in the areas served by our facilities also affect the demand for petroleum products and crude oil because a substantial portion of the petroleum products and crude oil throughput at our terminals is ultimately used as feedstock for industrial activity and fuel for consumer consumption. If these factors result in a decline in demand for petroleum products and crude oil, our business would be particularly susceptible to adverse effects. 

In recent years, the federal government has enacted renewable fuel or energy efficiency statutory mandates that may have the impact over time of reducing the demand for fuel oil or clean petroleum products, particularly with respect to gasoline, in certain

 

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markets.  Other legislative changes may similarly alter the expected demand and supply projections for petroleum products in ways that cannot be predicted. 

Energy conservation, changing sources of supply, structural changes in the energy industry and new energy technologies also could adversely affect our business.  We cannot predict or control the effect of these factors on us. 

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

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, 2016, our five largest customers accounted for approximately 61% of our revenues. We may be unable to negotiate extensions or replacements of contracts with key customers on favorable terms.  In addition, 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. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code, which could result in a reduction of or loss of revenue under such contracts. 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.  

Our Joliet terminal is currently supported by a terminal services agreement and a pipeline throughput and deficiency agreement with ExxonMobil Oil Corporation (“Exxon”), each with an initial three-year term that is currently scheduled to expire in May 2018. While discussions with Exxon are ongoing, contract renewal decisions are not required until August 2017.  If we are unable to renew our agreements with Exxon upon the expiration thereof, our business, financial conditions, results of operations and ability to make cash distributions to our unitholders would be material adversely affected.  If we renew the Exxon agreements on terms that are not similar to the current terms, our business, financial conditions, results of operations and ability to make cash distributions to our unitholders could be materially adversely affected. For the year ended December 31, 2016, Exxon, our largest customer, accounted for 30% and 41% of our Adjusted EBITDA and Distributable Cash Flow, respectively, in each case after removing the non-controlling interest portion related to our co-investor’s ownership interest in Arc Terminals Joliet Holdings LLC (“Joliet Holdings”).  Please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors That Impact Our Business—Customers and Competition.”

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 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, due to a change in the Chillicothe terminal’s product receipt logistics, we evaluated the long-lived assets at the Chillicothe terminal for impairment as of December 31, 2014, and recognized a non-cash impairment loss of approximately $6.1 million during the year ended 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, which in turn may adversely affect our ability to make cash distributions to our unitholders.

 

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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 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,

 

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generally ranging from two to six months prior to the expiration of the applicable renewal term. For the year ended December 31, 2016, approximately 84% of our revenue was generated pursuant to take-or-pay provisions in our services agreements with a weighted average term remaining of approximately two years. As of December 31, 2016, (i) approximately 66% of our services agreements were operating under evergreen provisions; and (ii) the services agreements of our top three customers represented approximately 51% of our gross revenues and had a weighted average remaining term of approximately two years. 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. Delays, litigation, local concerns and difficulty in obtaining approvals for projects requiring federal, state or local permits could impact our ability to build, expand and operate strategic facilities and infrastructure, which could adversely impact growth and operational efficiency.  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.

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.

 

Our interstate liquids pipeline is subject to regulation by FERC, which could adversely affect our business, financial condition, results of operations, and ability to make distributions to our unitholders.

 

Our interstate liquids pipeline is a common carrier and is subject to regulation by FERC under the ICA, the Energy Policy Act of 1992, and related rules and orders.  FERC regulation requires that common carrier liquid pipeline rates and interstate natural gas pipeline rates be filed with FERC and that these rates be “just and reasonable” and not unduly discriminatory. Interested persons

 

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may challenge proposed new or changed rates, and FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a jurisdictional liquids pipeline to change its rates prospectively. Accordingly, action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return on the FERC-jurisdictional pipeline asset. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to our unitholders.

If the business of our customers is adversely impacted due to increased regulation affecting the transportation of crude oil 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 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 adversely affect the business of our customers by, among other things, rendering the delivery of crude oil by rail to our facilities or terminals less economic or uneconomic. If the delivery of crude oil 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.    Please read Part I, Item 1. “Business— Environmental and Occupational Safety and Health Regulation — Hazardous Materials Transportation.”

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. Please read Part I, Item 1. “Business— Environmental and Occupational Safety and Health Regulation.”

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.

In addition, our operations could be adversely affected if shippers of the crude oil, petroleum products and chemicals that we store, throughput and transload incur additional costs or liabilities associated with environmental regulations. Relatedly, many of our customers face a trend of increasing environmental regulation, which could restrict their ability to produce crude oil or fuels, or increase their costs of production, and thus impact the price of, and/or their ability to deliver, these products.

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, including prior to our ownership of such facilities. Although we have utilized and continue to utilize operating and disposal

 

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practices that are standard in the industry, we may experience releases of crude oil, petroleum products and fuels or other contaminants into the environment or discover past releases that were previously unidentified, which could give rise to a material liability. 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. We may incur significant costs and liabilities to address any environmental contamination that occurs on our properties, even if the contamination was caused by prior owners and operators of our facilities. We may not be able to recover some or any of these costs from insurance or other sources of contractual indemnity. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for by insurance, there could be a material adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.

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. From time to time, we may not be able to renew existing governmental permits or authorizations on the same terms and any new or revised terms may require us to install new pollution controls or to modify our operations.  Any or all of these matters could have a material adverse 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 emissions.  Please read Part I. Item 1. “Business— Environmental and Occupational Safety and Health Regulation — Air Emissions and Climate Change.”  

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 do not have employment agreements and 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.

 

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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 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 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 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 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 contains covenants requiring us to maintain certain financial ratios.

The provisions of our Credit Facility 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 could result in an event of default which could enable our lenders, subject to the terms and conditions of our Credit Facility, 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 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, 2016, 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.

 

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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, 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 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;

 

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 incentive distributions;

 

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 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;

 

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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.”

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

 

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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.

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 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 the consent of the holders of at least 66 2/3% of the outstanding units (including units held by our Sponsor).

If our unitholders are dissatisfied with the performance of our General Partner, they will have limited ability to remove our General Partner. The vote of the holders of at least 66 2/3% of all outstanding common units (including units held by our Sponsor) is required to remove our General Partner. As of December 31, 2016, our Sponsor owns an aggregate of 27% of our common units.

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

 

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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;

 

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, 2016, our Sponsor owned 27% 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.

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.

 

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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, 2016, we had 19,477,021 common units outstanding.  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.”

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, we may not make a distribution to our unitholders if the

 

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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.

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 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.  Management has determined that there was a material weakness in internal control over financial reporting related to the revaluation of the earn-out obligation associated with business combinations. Please see Part II, Item 9A. “Controls and Procedures.”  We are actively engaged in developing and implementing a remediation plan designed to address this material weakness.  If remedial measures are insufficient to address the material weakness, or if additional material weaknesses or significant deficiencies in internal control are discovered or occur in the future, our consolidated financial statements may contain material misstatements, and we could be required to restate our financial results.

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.

 

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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 would 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, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. 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 U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions 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.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Specifically, we currently own assets and conduct business in several states, each of which imposes income taxes on corporations and other entities. In the future, we may expand our operations. Imposition of such taxes on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to you. 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 U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

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.

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, 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.”

 

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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. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated 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.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

However, 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 similar or future legislative changes could negatively impact the value of an investment in our common units.

Even if you do not receive any cash distributions from us, you are required to pay taxes on your share of our taxable income, including your share of income from the cancellation of debt.

As unitholders, 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 due from you with respect to that income.

In response to current market conditions, we may engage in transactions to delever the Partnership and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt, could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. You may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on your individual tax position with respect to your units. You are encouraged to consult your tax advisors with respect to the consequences of COD 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 terminated our 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, 2016, affiliates of our Sponsor directly and indirectly owned 27% 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 our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.  

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant 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 unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. 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. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

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

 

38


 

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. 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.

Furthermore, a substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture.  Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units.  Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

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 raise 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.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take in the future. 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. The 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.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our General Partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

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.

 

39


 

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 (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of our General Partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations are do not specifically authorize all aspects of our proration method. If the IRS were to 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 U.S. 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 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 are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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

In addition to U.S. 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 currently own assets and conduct business in several states, each of which currently imposes a personal income tax on individuals, 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.

 

40


 

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

From time to time, we are involved in various legal claims arising out of our operations in the normal course of business. It is the opinion of management that the ultimate resolution of our pending litigation matters will not have a material adverse effect on our financial condition or results of operations.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

 


 

 

41


 

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.” As of March 6, 2017, there were 19,477,021 common units outstanding held by six 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, 2017, our Sponsor held approximately 27% of the common units outstanding.

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 on our common units for the indicated periods:

 

 

Price Range

 

 

 

 

 

 

 

 

 

Year ended December 31, 2016:

 

High

 

 

Low

 

 

Cash Distributions (1)

 

 

Record Date

 

Payment Date

Fourth Quarter

 

$

15.93

 

 

$

13.03

 

 

$

0.4400

 

 

February 8, 2017

 

February 15, 2017

Third Quarter

 

$

16.07

 

 

$

12.60

 

 

$

0.4400

 

 

November 7, 2016

 

November 15, 2016

Second Quarter

 

$

13.40

 

 

$

9.63

 

 

$

0.4400

 

 

August 8, 2016

 

August 12, 2016

First Quarter

 

$

13.72

 

 

$

9.45

 

 

$

0.4400

 

 

May 9, 2016

 

May 13, 2016

 

 

 

Price Range

 

 

 

 

 

 

 

 

 

Year ended December 31, 2015:

 

High

 

 

Low

 

 

Cash Distributions (1)

 

 

Record Date

 

Payment Date

Fourth Quarter

 

$

17.23

 

 

$

11.32

 

 

$

0.4400

 

 

February 8, 2016

 

February 12, 2016

Third Quarter

 

$

18.97

 

 

$

13.16

 

 

$

0.4400

 

 

November 9, 2015

 

November 13, 2015

Second Quarter

 

$

20.34

 

 

$

16.81

 

 

$

0.4250

 

 

August 10, 2015

 

August 14, 2015

First Quarter

 

$

19.82

 

 

$

16.43

 

 

$

0.4100

 

 

May 11, 2015

 

May 15, 2015

 

 

(1)

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

 

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth our purchases of our common units during the three months ended December 31, 2016.

 

 

Purchases of Common Units

 

 

 

 

 

Period

 

Total Number of Common Units Purchased (a)

 

 

Aggregate Price Paid Per Unit

 

 

Total Number of Common Units Purchased as Part of Publicly Annouced Plans or Programs

 

Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs

October 1 - October 31, 2016

 

 

 

 

 

 

November 1 - November 30, 2016

 

 

43,372

 

 

$

14.50

 

 

 

December 1, - December 31, 2016

 

 

 

 

 

 

 

(a)

Represents units withheld to satisfy tax withholding obligations upon settlement of phantom units subject to performance-based vesting that were award under our 2013 Plan.  

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.

 

42


 

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 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.

Our partnership agreement generally provides that we will distribute cash each quarter 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.”

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, 2016.

 

 

 

 

43


 

ITEM 6.

SELECTED FINANCIAL DATA

The following tables set forth the selected historical consolidated financial data of the Partnership for each of the last five years. The consolidated financial data presented as of and for the years ended December 31, 2016, 2015, 2014, 2013 and 2012 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,

 

 

 

2016

 

 

2015

 

 

2014

 

 

2013

 

 

2012

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Third-party customers

 

$

92,342

 

 

$

70,497

 

 

$

45,676

 

 

$

39,662

 

 

$

13,201

 

Related parties

 

 

13,039

 

 

 

11,292

 

 

 

9,230

 

 

 

8,179

 

 

 

9,663

 

 

 

 

105,381

 

 

 

81,789

 

 

 

54,906

 

 

 

47,841

 

 

 

22,864

 

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

33,749

 

 

 

28,973

 

 

 

27,591

 

 

 

19,291

 

 

 

7,266

 

Selling, general and administrative

 

 

12,895

 

 

 

17,891

 

 

 

9,396

 

 

 

7,116

 

 

 

2,283

 

Selling, general and administrative - affiliate

 

 

5,288

 

 

 

4,729

 

 

 

3,990

 

 

 

2,484

 

 

 

2,592

 

Depreciation

 

 

15,704

 

 

 

11,680

 

 

 

7,261

 

 

 

5,836

 

 

 

3,317

 

Amortization

 

 

14,714

 

 

 

10,819

 

 

 

5,427

 

 

 

4,756

 

 

 

624

 

Loss on revaluation of contingent consideration, net

 

 

1,043

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Long-lived asset impairment

 

 

-

 

 

 

-

 

 

 

6,114

 

 

 

-

 

 

 

-

 

Total expenses

 

 

83,393

 

 

 

74,092

 

 

 

59,779

 

 

 

39,483

 

 

 

16,082

 

Operating income (loss)

 

 

21,988

 

 

 

7,697

 

 

 

(4,873

)

 

 

8,358

 

 

 

6,782

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gain on bargain purchase of business

 

 

-

 

 

 

-

 

 

 

-

 

 

 

11,777

 

 

 

-

 

Equity earnings from unconsolidated affiliate

 

 

9,852

 

 

 

10,030

 

 

 

9,895

 

 

 

1,307

 

 

 

-

 

Other income

 

 

3

 

 

 

9

 

 

 

17

 

 

 

48

 

 

 

4

 

Interest expense

 

 

(9,811

)

 

 

(6,873

)

 

 

(3,706

)

 

 

(8,639

)

 

 

(1,320

)

Total other income (expenses), net

 

 

44

 

 

 

3,166

 

 

 

6,206

 

 

 

4,493

 

 

 

(1,316

)

Income (loss) before income taxes

 

 

22,032

 

 

 

10,863

 

 

 

1,333

 

 

 

12,851

 

 

 

5,466

 

Income taxes

 

 

124

 

 

 

119

 

 

 

58

 

 

 

20

 

 

 

43

 

Net income (loss)

 

 

21,908

 

 

 

10,744

 

 

 

1,275

 

 

 

12,831

 

 

 

5,423

 

Net income attributable to non-controlling interests

 

 

(6,866

)

 

 

(4,315

)

 

 

-

 

 

 

-

 

 

 

-

 

Net income attributable to preferred units

 

 

-

 

 

 

-

 

 

 

-

 

 

 

(1,770

)

 

 

-

 

Net income (loss) attributable to partners' capital

 

$

15,042

 

 

$

6,429

 

 

$

1,275

 

 

$

11,061

 

 

$

5,423

 

 


 

44


 

 

 

 

Year Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014