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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
 
FORM 10-K
 
 
(Mark one)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2018
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: 001-36137 
 
Sprague Resources LP
(Exact name of registrant as specified in its charter) 
 
 
Delaware
 
45-2637964
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
185 International Drive
Portsmouth, New Hampshire 03801
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: (800) 225-1560
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  x
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  x
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  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Registration S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
 
Accelerated filer
x
Non-accelerated filer
o
(Do not check if a smaller reporting company)
Smaller reporting company
o
 
 
 
Emerging growth company
o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.):    Yes  ¨    No  x
The aggregate market value of common units held by non-affiliates of the registrant was approximately $257 million as of June 29, 2018 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such units as quoted on the New York Stock Exchange. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
The registrant had 22,733,977 common units outstanding as of March 8, 2019.
Documents Incorporated by Reference: None

 

Table of Contents

SPRAGUE RESOURCES LP
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
 
 
Page
PART I
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
PART II
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
PART III
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
PART IV
 
 
Item 15.
Item 16.
 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“Annual Report”) and any information incorporated by reference, contains statements that we believe are “forward-looking statements”. Forward looking statements are statements that express our belief, expectations, estimates, or intentions, as well as those statements we make that are not statements of historical fact. Forward-looking statements provide our current expectations and contain projections of results of operations, or financial condition, and/ or forecasts of future events. Words such as “may”, “assume”, “forecast”, “position”, “seek”, “predict”, “strategy”, “expect”, “intend”, “plan”, “estimate”, “anticipate”, “believe”, “project”, “budget”, “outlook”, “potential”, “will”, “could”, “should”, or “continue”, and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties which could cause our actual results to differ materially from those contained in any forward-looking statement. Consequently, no forward-looking statements can be guaranteed. You are cautioned not to place undue reliance on any forward-looking statements.
Factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (i) changes in federal, state, local, and foreign laws or regulations including those that permit us to be treated as a partnership for federal income tax purposes, those that govern environmental protection and those that regulate the sale of our products to our customers; (ii) changes in the marketplace for our products or services resulting from events such as dramatic changes in commodity prices, increased competition, increased energy conservation, increased use of alternative fuels and new technologies, changes in local, domestic or international inventory levels, seasonality, changes in supply, weather and logistics disruptions, or general reductions in demand; (iii) security risks including terrorism and cyber-risk, (iv) adverse weather conditions, particularly warmer winter seasons and cooler summer seasons, climate change, environmental releases and natural disasters; (v) adverse local, regional, national, or international economic conditions, unfavorable capital market conditions and detrimental political developments such as the inability to move products between foreign locales and the United States; (vi) nonpayment or nonperformance by our customers or suppliers; (vii) shutdowns or interruptions at our terminals and storage assets or at the source points for the products we store or sell, disruptions in our labor force, as well as disruptions in our information technology systems; (viii) unanticipated capital expenditures in connection with the construction, repair, or replacement of our assets; (ix) our ability to integrate acquired assets with our existing assets and to realize anticipated cost savings and other efficiencies and benefits; and, (x) our ability to successfully complete our organic growth and acquisition projects and/or to realize the anticipated financial and operational benefits. These are not all of the important factors that could cause actual results to differ materially from those expressed in our forward-looking statements. Other known or unpredictable factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this Annual Report are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if realized, will have the expected consequences to or effect on us or our business or operations. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Annual Report may not occur.
When considering these forward-looking statements, please note that we provide additional cautionary discussion of risks and uncertainties in Part I, Item 1A “Risk Factors”, in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and in Part II Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of this Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Annual Report may not occur.
Forward-looking statements contained in this Annual Report speak only as of the date of this Annual Report (or other date as specified in this Annual Report) or as of the date given if provided in another filing with the U.S. Securities and Exchange Commission (“SEC”). We undertake no obligation, and disclaim any obligation, to publicly update, review or revise any forward-looking statements to reflect events or circumstances after the date of such statements. All forward looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this Annual Report and our other existing and future periodic reports filed with the SEC.


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PART I

Item 1.    Business
As used in this Annual Report, unless the context otherwise requires, references to “Sprague Resources,” the “Partnership,” “we,” “our,” “us,” or like terms, refer to Sprague Resources LP and its subsidiaries. References to our “General Partner” refer to Sprague Resources GP LLC. Our General Partner is a wholly-owned subsidiary of Axel Johnson Inc. Unless the context otherwise requires, references to “Axel Johnson” or the “Sponsor” refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner. In prior filings, our Sponsor was referred to as our "Parent". References to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of our General Partner.
Our Partnership
We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and provide storage and handling services for a broad range of materials. In October 2013, we became a publicly traded master limited partnership ("MLP") and our common units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP".
Our Predecessor was founded in 1870 as the Charles H. Sprague Company in Boston, Massachusetts; and, in 1905, the company opened the Penobscot Coal and Wharf Company, a tidewater terminal located in Searsport, Maine. By World War II, the company was operating eleven terminals and a fleet of two dozen vessels transporting coal and other products throughout the world. As fuel needs diversified in the United States, the company expanded its product offerings and invested in terminals, tankers, and product handling activities. In 1959, the company expanded its oil marketing activities via entry into the distillate oil market. In 1970, the company was sold to Royal Dutch Shell’s Asiatic Petroleum subsidiary; and, in 1972, Royal Dutch Shell sold the company to Axel Johnson Inc., a member of the Axel Johnson Group of Stockholm, Sweden.
We are one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of refined products and materials handling terminals strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage tank capacity of 14.7 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. We also have access to more than 40 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
We operate under four business segments: refined products, natural gas, materials handling and other operations. See Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operation—Results of Operation for a discussion of financial results by segment and see Segment Reporting included under Note 17 to our Consolidated and Combined Financial Statements for a presentation of financial results by reportable segment.
As of December 31, 2018, our Sponsor, through its ownership of Sprague Holdings, owned 12,106,348 common units, representing 53% of the limited partner interest in the Partnership. Sprague Holdings also owns our General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds all of our incentive distribution rights (“IDRs”), which entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from distributable cash flow in excess of $0.474375 per unit per quarter. The maximum IDR distribution of 50.0% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns.
We furnish or file with the SEC our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We make these documents available free of charge on our website as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. Our internet address is www.spragueenergy.com. Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.


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Business Strategies
Our primary business objective is to increase distributable cash flow per unit over time by executing the following strategies:
Increase our business with our existing assets and customers. We will make investments in our existing asset base to handle additional products and provide new services to customers. We also intend to win additional business by better serving customers' need for certainty of supply, reduced commodity price risk and high quality customer service.
Acquire additional terminals and marketing and distribution businesses that are accretive. We intend to grow our asset and customer base by acquiring additional marine and inland terminals (both refined products and materials handling) within and adjacent to the geographic markets we currently serve. We also intend to acquire additional refined products and natural gas marketing businesses that can leverage our existing investment in our logistics capabilities and customer service systems to further increase our cash flow.
Limit our exposure to commodity price risk and volatility. We take title to the products we sell in our refined products and natural gas segments, while our materials handling business does not take title to products and is operated predominantly under fixed-fee, multi-year contracts. We will continue to manage our exposure to commodity prices and seek to protect our sales margins by maintaining a balanced position in our purchases and sales through the use of derivatives and forward contracts. Our hedging activities are bounded by specific limits established by the board of directors of our General Partner, which are monitored and reported to senior management on a daily basis by our risk group.
Maintain our operational excellence. We intend to maintain our long history of safe, cost-effective operations and environmental stewardship by investing in the maintenance of our assets and providing training programs for our personnel. We will work diligently to meet environmental regulations and we will continue to enhance our safety programs as our business grows and operating conditions change.

2017 Acquisitions
Coen Energy
On October 1, 2017, we purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Coen Energy, located in Washington, PA, provides energy products to commercial and residential customers located in Pennsylvania, Ohio and West Virginia. The Coen Energy business also provides fuel and delivery services to customers that are engaged in Marcellus and Utica shale drilling operations. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees as of December 31, 2017.
Initial consideration paid was $35.3 million in cash, not including the purchase of inventory and other adjustments, which was financed with borrowings under our credit facility. Contingent consideration of up to $12 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020.
Carbo Terminals
On April 18, 2017, we acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under our credit facility, an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and 1,131,551 common units with a fair value of $31.4 million as of April 18, 2017. The Carbo terminals are primarily supplied by pipeline and have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels.
Capital Terminal
On February 10, 2017, we acquired the East Providence, Rhode Island refined product terminal business of Capital Properties Inc. (the “Capital Terminal”) for $22.0 million and we financed with borrowings under our credit facility. The terminal’s distillate storage capacity of 1.0 million barrels had been leased by us since April 2014 and was previously included in our total storage capacity.

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In conjunction with this acquisition, we undertook an expansion capital project to convert half of the terminal’s storage capacity to gasoline and ethanol service to support a new ten year fee-for-service gasoline storage and handling agreement with a major East Coast gasoline marketer and another project to optimize distillate storage between this newly acquired terminal and our existing terminal facility in Providence to allow for expanded materials handling capability. Both projects were completed in 2017 at a total cost of approximately $16 million.
Global Natural Gas & Power
On February 1, 2017, we purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative liabilities and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under our credit facility. The business markets natural gas and electricity to commercial, industrial, municipal and institutional customer locations in the Northeast United States.
L.E. Belcher Terminal
On February 1, 2017, we purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for $20.0 million in cash, not including the purchase of inventory and other adjustments.  Consideration paid was $20.7 million and was financed with borrowings under our credit facility. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses.

Refined Products
Overview
The products we sell in our refined products segment can be grouped into the following categories: distillates, gasoline and residual fuel oil and asphalt. Our refined products segment accounted for 89%, 86% and 83% of our total net sales for the years ended December 31, 2018, 2017 and 2016, respectively. Of our total volume sold in our refined products segment in 2018, distillates accounted for 78%, gasoline accounted for 10% and residual fuel oil and asphalt accounted for 12%.
Distillates. We sell four kinds of distillates: heating oil (both unbranded and our proprietary premium HeatForce® heating oil brand), diesel fuel (both unbranded and our proprietary premium RoadForce® diesel fuel brand), kerosene and jet fuel. In 2018, heating oil accounted for 61%, diesel fuel accounted for 36%, and other distillates accounted for 3% of the total volume of distillates we sold. We have the capability at several of our facilities to blend biodiesel with distillates in order to sell heating oil and diesel fuel with wide varieties of biodiesel content. In 2018, biofuel blended products accounted for 5% of the distillate fuel volumes sold. Distillate volumes accounted for 78%, 75%, and 73% of our total refined products sales for the years ended December 31, 2018, 2017 and 2016, respectively.
Gasoline. We also sell unbranded gasoline. Gasoline volumes accounted for 10%, 11% and 13% of our total refined products sales for the years ended December 31, 2018, 2017 and 2016, respectively.
Residual Fuel Oil and Asphalt. We sell various sulfur grades of residual fuel oil, blended to meet customer requirements. Additionally Kildair Service ULC ("Kildair"), our Canadian subsidiary, sold asphalt directly to Canadian customers through 2017. Residual fuel oil and asphalt volumes accounted for 12%, 14% and 14% of our total refined products sales for the years ended December 31, 2018, 2017 and 2016, respectively.
Customers, Contracts and Pricing
We sell heating oil, diesel fuel, kerosene, unbranded gasoline, jet fuel, and residual fuel oil to wholesalers, retailers and commercial customers. The majority of these sales are made free on board, or FOB, at the bulk terminal or inland storage facility we own and/or operate or at facilities with which we have storage and throughput arrangements. In a FOB sale, the price of products sold includes the cost of delivering such product to the FOB location and any further shipping expenses are borne by the purchaser.
Heating oil sales are made to approximately 900 wholesale distributors and retailers through the Sprague RealTime® pricing platform, under rack agreements based upon our posted price, contracts with index-based pricing provisions, and fixed price forward contracts. Diesel fuel sales are made to approximately 670 wholesalers and transportation fuel distributors. We also sell unbranded gasoline at Partnership owned and at third-party locations, primarily to resellers. Residual fuel oil is sold to approximately 140 commercial and industrial accounts under rack agreements and contracts with index-based pricing provisions.

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Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, natural gas resource development companies and educational institutions. Most of these sales are made on a delivered basis, whereby we either deliver the product with our own trucks and barges or arrange with third-party haulers to make deliveries. We also deliver distillate and residual fuel oil by truck to marine customers.
Public sector entities also purchase our heating oil, diesel fuel, unbranded gasoline and residual fuel oil through competitive bidding processes. We currently have contracts with the U.S. government as well as with numerous states, municipalities, agencies and educational institutions.
For the year ended December 31, 2018, no customer represented more than 10% of net sales for our refined products segment.

Natural Gas
Overview
We purchase, sell and distribute natural gas to approximately 14,000 commercial and industrial customer locations primarily located in the Northeast and Mid-Atlantic United States. Our natural gas segment accounted for 9%, 12% and 14% of our total net sales for the years ended December 31, 2018, 2017 and 2016, respectively. We deliver natural gas to customers through utility interconnections of pipelines and manage interactions with utilities on behalf of our customers. We sell natural gas pursuant to fixed price, floating price and other structured pricing contracts. We utilize physical purchase instruments as well as financial and derivative instruments both over the counter and through exchanges such as the Intercontinental Exchange Inc. (“ICE”) and the New York Mercantile Exchange ("NYMEX"), to manage our natural gas commodity price risk.
In order to manage our supply commitments to our customers and provide operational flexibility and logistic opportunities, we enter into supply contracts, commitments for pipeline transportation capacity, leases for storage space and other physical delivery services for various terms. We believe that entering into these types of arrangements provides us with potential opportunities to grow our existing customer relationships and to pursue additional relationships.
Customers
Our natural gas customers operate in the industrial and commercial sectors in the Northeast and Mid-Atlantic United States, with the highest concentration in New England and New York. Examples of customers include industrial users of varying sizes (e.g., pulp and paper, chemicals, pharmaceutical and metals plants) to various commercial customers (e.g., hospitals, universities, apartment buildings and retail establishments). The industrial customers have a high concentration of process load to support their manufacturing requirements, with the largest uses by the commercial customers typically for heating, cooling, lighting, cooking and drying.
For the year ended December 31, 2018, no customer represented more than 10% of net sales for our natural gas segment.
Contracts/Pricing
We use various types of contracts for the sale and delivery of natural gas to our customers, with terms ranging from month-to-month to over two years. We provide a wide range of pricing options to our customers, including daily pricing and long-term fixed pricing. For example, we may offer a contract that permits the customer to lock in a basis or location differential relative to the Henry Hub delivery location and then fix the price at a later date based on the prevailing market pricing. There are various other alternatives such as “capped” pricing (essentially setting a maximum) or daily pricing based on a differential to a published market index. Due to the commodity price risk associated with uncertain customer usage patterns, we limit the number of transactions that require a single price for all volumes delivered, with the pricing of the non-contractual volumes primarily based on prevailing market economics. For any transaction where the competitive dynamics require a single price for all volumes delivered, we seek to manage the risk by, for instance, including appropriate increases in the cost build-up to reflect higher hedging costs.

Materials Handling
Overview
Materials handling consists of the movement of raw materials and finished goods through our waterfront terminals. We utilize our terminal network to offload, store and/or prepare for delivery a large number of liquid products, bulk and break bulk materials and provide heavy lift services and other handling services to some of the same customers that we supply with refined products and natural gas. Our materials handling segment accounted for 2% of our total net sales for each of the years ended December 31, 2018, 2017 and 2016.

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We are capable of providing numerous types of materials handling services, including ship handling, crane operations, pile building, warehouse operations, scaling and, in some cases, transportation to the final customer. Because the products we handle are generally owned by our customers, we have minimal to no working capital requirements, commercial risk or inventory risk. Our materials handling activity is generally conducted under multi-year agreements as either fee-based activities or as leasing arrangements when the right to use an identified asset (such as storage tanks or storage locations) has been conveyed in the agreement.
Major Types of Materials Handling and Services
The type of materials handling and services we provide can be divided into three major categories:
Liquid. In a manner similar to our refined products operation our terminal network of marine docks, product pipelines and storage tanks are utilized to store and trans-load various other third party owned liquid products to and from ocean vessels, railcars and tanker trucks. Examples of liquid materials handled include crude oil, refined products, asphalt and clay slurry. Liquid handling activities include securing the vessel, attaching product lines from ship pipes to dock product lines, supervising discharge into tanks, measuring tank quantities, storing product, loading product into authorized trucks or railcars and in some cases transporting the product. Some products require heated storage allow for flow at ambient temperatures. The operations of Kildair Service ULC ("Kildiar") include materials handling contracts involving trans-loading and storage of various petroleum products including crude, liquid asphalt and vacuum gas oil ("VGO").
Bulk. Bulk materials are typically aggregate materials that are moved in large vessels configured with multiple holds that store unpackaged products. Examples of bulk material include salt, petroleum coke, gypsum, and coal. Bulk load vessels are normally offloaded using cranes that can reside either on the vessel or on the dock of the terminal. In a typical discharge, the services performed include: securing the vessel to the dock, operating the vessel cranes, transferring products to trucks via large dock hoppers, transporting the materials to a holding pad, building materials up into large storage piles, covering the piles with protective tarps, storing the product, loading the product into trucks or railcars, scaling the loaded trucks and sometimes transporting the product to its final destination.
Break bulk. Break bulk materials are shipped in less than bulk quantities, normally with some type of secondary packaging. Examples of break bulk materials include one-ton sacks of raw materials, pallets of stones, bales of raw wood pulp and rolls of paper. Another subcategory of break bulk materials is large construction project cargo such as windmill components, often referred to as heavy lift. Break bulk handling activities include securing vessels, unloading or loading vessels either with cranes or specialty fork trucks, transferring products into warehouses or onto pads for storage, reloading products onto trucks or railcars and sometimes transporting products to their final destinations.
Customers
Our materials handling operations can service multiple customer types during any single operation, including: ocean shippers, multiple logistics firms, trucking firms and the materials supplier or consumer. Materials we handle normally fall into three major categories. The first category involves raw materials or finished goods shipped by water into local markets to support local production, manufacturing or construction firms. Examples of these products include asphalt for road construction, gypsum rock for drywall manufacturing, road salt for local road treatment, petroleum coke or utility fuels for energy demand and clay slurry for finished paper treatment. The second category of materials we handle are materials manufactured locally for export via vessel to other countries. These materials include wood pulp for paper manufacture in Asia or Europe and tallow for biodiesel production in Europe. The third category of materials we handle are both crude oil and refined products sourced either in Canada, U.S. or internationally for a range of use in local refineries and/or for further export to the U.S. or elsewhere.
Contracts/Pricing
The typical contract term for our materials handling services varies depending on the frequency and type of service. For bulk and liquid services, the commodity is normally a raw materials input for industrial production (clay slurry) or construction of roads (asphalt) or wallboard (gypsum rock). As such, the demand is more ratable and the customer is normally in need of guaranteed space within a terminal. These customers typically enter into term contracts that can range from one to 20 years depending on the relative importance of the material to their production and the amount of any capital infrastructure that we need to develop for such customers. As of December 31, 2018, the weighted-average life of our materials handling contracts was nine years, with a weighted-average remaining term of four years, each calculated using adjusted gross margin as defined in Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations-How Management Evaluates Our Results of Operations-Adjusted Gross Margin and Adjusted EBITDA”, attributable to these contracts.
Historically, our customers have paid for terminal improvements for specialty handling systems such as a clay slurry screening plant, while we pay for more generic infrastructure improvements such as storage pads.

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For container and break bulk services, it is typical for the user of that material to contract on an individual shipment basis. For example, a typical pulp merchant may choose to sell its pulp domestically or to users in Europe or Asia depending on the highest delivered value it can yield. As such, its choice of delivery mode and terminal will be driven by the location of its final customer. Therefore, we normally maintain a published rate for most generic services, subject to change depending on market conditions.
Other Operations
Our other operations segment primarily includes the purchase, sale and distribution of coal out of our Portland, Maine terminal and certain commercial trucking activities in Kildair’s operations. For the years ended December 31, 2018, 2017 and 2016 our other operations segment accounted for less than 1% of our total net sales.
Commodity Risk Management
Because we take title to the refined products and natural gas that we sell, we are exposed to commodity risk. Our materials handling business is a fee-based business and, accordingly, our operations in that business segment have only limited exposure to commodity risk. Commodity risk is the risk of market fluctuations in the price of commodities such as refined products and natural gas. We endeavor to limit commodity price risk in connection with our daily operations. Generally, as we purchase and/or store refined products, we reduce commodity risk through hedging by selling futures contracts on regulated exchanges or using other derivatives, and close out the hedges as we sell the product for physical delivery to third parties. Products are generally purchased and sold at spot prices, fixed prices or indexed prices. While we seek to use these transactions to maintain a position that is substantially balanced between purchased volumes and sales volumes through regulated exchanges or derivatives, we may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules, as well as logistical issues associated with inclement weather conditions or infrastructure disruptions. Our general practice is to not hold refined products futures contracts or other derivative products and instruments for the sole purpose of speculating on price changes. While our policies are designed to limit market risk, some degree of exposure to unforeseen fluctuations in market conditions remains.
Our operating results are sensitive to a number of commodity risk factors. Such factors include commodity location, grades of product, individual customer demand for grades or location of product, localized market price structures, availability of transportation facilities, daily delivery volumes that vary from expected quantities and timing and costs to deliver the commodity to the customer. The term “basis risk” is used to describe the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of that commodity at a different time or place, including, without limitation, transportation costs and timing differentials. We attempt to reduce our exposure to basis risk by grouping our purchase and sale activities by geographical region and commodity quality in order to stay balanced within such designated region.
With respect to the pricing of commodities, we enter into derivative positions to limit or hedge the impact of market fluctuations on our purchases and forward fixed price sales of refined products and natural gas. All hedge positions are reflected in our results of operations.
With respect to refined products, we primarily use a combination of futures contracts, over-the-counter swaps and forward purchases and sales to hedge our price risk. For light oils (gasoline and distillates), we primarily utilize the actively traded futures contracts on the regulated NYMEX to hedge our positions. Heavy oils are typically hedged with fixed-for-floating price residual fuel oil swaps contracts, which are either balanced by offsetting positions or financially settled.
With respect to natural gas, we generally use fixed-for-floating price swaps contracts that trade on the ICE for hedging. As an alternative, we may use NYMEX natural gas futures for such purposes. In addition, we use natural gas basis swaps to hedge our basis risk.
For both refined products and natural gas, if we trade in any derivatives that are not cleared on an exchange, we strive to enter into derivative agreements with counterparties that we believe have a strong credit profile and/or provide us with trade credit to limit counterparty risk and margin requirements.
Our risk management policies, and the specific limits therein, are intended to prevent unauthorized trading and to maintain substantial balance between purchases and sales or future delivery obligations. However, these steps may not detect and/or prevent all violations of such risk management policies, processes and procedures, particularly if deception or other intentional misconduct is involved.
Storage and Distribution

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Marine terminals and inland storage facilities play a key role in the distribution of product to our customers. Our facilities are equipped to provide terminalling, storage and distribution of both solid and liquid products to serve our refined products and materials handling businesses. Each facility has capabilities that are unique to the local markets served. A number of facilities are used to handle liquid, dry bulk, break bulk and refined products at the same terminal and in most cases across the same dock, providing flexibility to fully utilize terminal assets to meet a variety of fuel and third-party cargo handling demands.
The marine terminals and inland storage facilities from which we distribute product are supplied by ship, barge, truck, pipeline or rail. Our customers receive product from our network of marine terminals and inland storage facilities via truck, barge, rail or pipeline.
Our marine terminals consist of multiple storage tanks and automated truck loading equipment. These automated systems monitor terminal access, volumetric allocations, credit control and carrier certification through the electronic identification of customers. In addition, some of the marine and inland terminals are equipped with truck loading racks capable of providing automated blending and additive packages that meet our customers’ specific requirements. Many of our marine and inland terminals operate 24 hours per day.
Throughput arrangements allow storage of our product at terminals owned by others. These arrangements permit our customers to receive product at third-party terminals while we pay terminal owners fees for services rendered in connection with the receipt, storage and handling of the product. Payments we make to terminal owners may be fixed or fluctuate based upon the volume of product that is delivered and sold at the terminal.
Exchange agreements allow our customers to take delivery of product at a terminal or facility that is not owned or leased by us. An exchange is a contractual agreement pursuant to which the parties exchange product at their respective terminals or facilities. For example, we (or our customers) receive product that is owned by the other party from such party’s facility or terminal and we deliver the same volume of product to such party (or to such party’s customers) out of one of the terminals in our terminal network. Generally, both parties to an exchange transaction pay a handling fee (similar to a throughput fee) and often one party also pays a location differential that covers any excess transportation costs incurred by the other party in supplying product to the location at which the first party receives product. Costs incurred in exchanges may also include product value differentials.

Our Terminals and Storage Facilities
As of December 31, 2018, we owned, operated, and/or controlled a network of refined products and material handling terminals and storage facilities located in the Northeast United States from New York to Maine and in Quebec, Canada that have a combined storage capacity of 14.7 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. We also have access to approximately 40 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
For a more detailed description of our terminals and storage facilities, please read Part I, Item 2 - "Properties.”
Competition
We encounter varying degrees of competition in the marketing of our refined products based on product type and geographic location. In our Northeast United States market, we compete in various product lines and for a range of customer types. The principal methods of competition in our refined products operations are pricing, service offerings to customers, credit support and certainty of supply. Our competitors include terminal companies, major integrated oil companies and their marketing affiliates and independent marketers of varying sizes, financial resources and experience. We believe that our being one of the largest independent wholesale distributors of refined products in the Northeast United States (based on aggregate terminal capacity), our ownership of various marine-based terminals and our reputation for reliability and strong customer service allows us to be competitive in marketing refined products in the areas in which we operate.

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Competitors of our natural gas sales operations generally include natural gas suppliers and distributors of varying sizes, financial resources and experience, including producers, pipeline companies, utilities and independent marketers. The principal methods of competition in our natural gas operations are in obtaining supply, pricing optionality for customers and effective support services, such as scheduling and risk management. We believe that our sizable market presence and strong customer service and offerings allows us to be competitive in marketing natural gas in the areas in which we operate.
In our materials handling operations, we primarily compete with public and private port operators. Although customer decisions are substantially based on location, additional points of competition include types of services provided and pricing. We believe that our ability to provide materials handling services at a number of our refined products terminals and our demonstrated ability to handle a wide range of products provides us a competitive advantage in competing for products-related handling services in the areas in which we operate.

Seasonality
Demand for natural gas and some refined products, specifically heating oil and residual fuel oil for space heating purposes, is generally higher during the period of November through March than during the period of April through October. Therefore, our results of operations for the first and fourth calendar quarters are generally stronger than for the second and third calendar quarters. For example, over the 36-month period ended December 31, 2018, we generated an average of 71% of our total heating oil and residual fuel oil net sales during the months of November through March.

Employees
As of December 31, 2018, our General Partner employed approximately 800 full-time employees who supported our operations, 60 of whom were covered by five collective bargaining agreements. One of these agreements, covering six employees is up for renewal in 2019. Our Canadian subsidiary had 101 employees as of December 31, 2018, 37 of whom were covered by one collective bargaining agreement that expires on March 18, 2021.

Environment
General
Our petroleum product terminal and supply operations are subject to extensive and stringent environmental laws. As part of our business, we own and operate petroleum storage and distribution facilities and a petroleum fleet of trucks, and must comply with environmental laws at the federal, state and local levels, which increase the cost of operating terminals and our business generally. These laws include statutes, such as the Clean Water Act and the Clean Air Act, and regulations, which are frequently modified or revised to impose new obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities limiting or preventing the release of materials from our facilities, managing wastes generated by our operations, the installation of pollution control equipment, responding to releases of process materials or wastes from our operations, and the risk of substantial liabilities for pollution resulting from our operations. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.
Our operations also utilize a number of petroleum storage facilities and distribution facilities that we do not own or operate, but at which refined products are stored. We utilize these facilities through several different contractual arrangements, including leases, throughput and terminalling services agreements. If facilities with whom we contract that are owned and operated by third parties fail to comply with environmental laws, they could be shut down, requiring us to incur costs to use alternative facilities.
Environmental laws and regulations can restrict or impact our business in several ways, such as:
  
Requiring capital expenditures to comply with environmental control requirements;
Requiring remedial action to mitigate releases of hydrocarbons, hazardous substances or wastes caused by our operations or attributable to former operators; and,
Curtailing the operations of facilities deemed in non-compliance with environmental laws and regulations.
Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hydrocarbons, hazardous substances or wastes have been released or disposed. Moreover, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the release of hydrocarbons, hazardous substances or other wastes into the environment.

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The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. However, we can provide no assurance that future events, such as changes in existing laws, changes in the interpretation of existing laws, promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs or will not have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.
 
Hazardous Substances and Releases
Our business is subject to laws relating to the release of hazardous substances into the water or soils, which include requirements to control pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for 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 or arranged for the disposal of the hazardous substances. Under the Superfund law, 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. The Superfund law also authorizes 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 persons the costs they incur. It is possible 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 may generate substances that fall within the Superfund law’s definition of a hazardous substance and, as a result, we may be jointly and severally liable under the Superfund law for all or part of the costs required to clean up sites at which those hazardous substances have been released into the environment.
We currently own, lease or use storage or distribution facilities where hydrocarbons are being or have been handled for many years. Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where we have contractual arrangements or where these wastes have been taken for disposal. In addition, many 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 and wastes disposed thereon may be subject to the Superfund law or other federal and 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 groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.
Our operations generate a variety of wastes, including some hazardous wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state laws. These regulations impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste. Our operations also generate solid wastes which are regulated under state law or the less stringent solid waste requirements of the federal Solid Waste Disposal Act. We believe that our operations are in substantial compliance with the existing requirements of RCRA, the Solid Waste Disposal Act and similar state and local laws, and the cost involved in complying with these requirements is not material. We are also incurring ongoing costs for monitoring groundwater at several facilities that we operate. We believe that these costs will not have a material impact on our financial condition or results of operations.
Above-Ground Storage Tanks
Above-ground tanks that contain petroleum and other hazardous substances are subject to comprehensive regulation under environmental laws. Generally, these laws impose liabilities for releases and require secondary containment systems for tanks or require the operators take alternative precautions to ensure that no contamination results from tank leaks or spills. We believe we are in substantial compliance with environmental laws and regulations applicable to above-ground storage tanks.

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The Oil Pollution Act of 1990, or OPA, addresses three principal areas of oil pollution-prevention, containment and cleanup. In order to handle, store or transport oil, we are required to file oil spill response plans with the United States Coast Guard (for marine facilities) and the EPA. States in which we operate have enacted laws similar to OPA. We maintain such plans, and when required have submitted plans and received federal and state approvals necessary to comply with the OPA, the Clean Water Act and related regulations. We believe we are in substantial compliance with regulations promulgated under OPA and similar state laws.
Under OPA and comparable state laws, responsible parties for a regulated facility from which oil is discharged may be subject to strict, joint and several liability for removal costs and certain other consequences of an oil spill such as natural resource damages, where the spill is into navigable waters or along shorelines. Under the authority of the federal Clean Water Act, the EPA imposes specific requirements for Spill Prevention, Control, and Countermeasure, or SPCC, plans that are designed to prevent, and minimize the impacts of, releases from above ground storage tanks. We believe we are in substantial compliance with regulations pursuant to OPA, the Clean Water Act and similar state laws.
From time to time, we experience spills and releases during various phases of our operations, and some of these releases can reach waters that applicable federal and state laws would define as navigable. As a result we may be responsible for fines and penalties as well as required capital expenditures and for implementation of compliance and maintenance programs.
Water Discharges
The federal Clean Water Act, or CWA, and analogous state laws impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. This law and comparable state laws prohibit the discharge of pollutants into regulated waters, except in accordance with the terms of a permit issued by the EPA or analogous state agency and impose substantial liabilities for noncompliance. The CWA also regulates the discharge of storm water runoff from certain industrial facilities. Accordingly, several of our facilities are required to obtain and maintain storm water discharge permits, which require monitoring and sampling of storm water runoff from such facilities. We believe we hold the required permits and operate in substantial compliance with those permits. While we have experienced permit discharge exceedances at some of our terminals, we do not expect any non-compliance with existing permits and foreseeable new permit requirements to have a material adverse effect on our financial position or results of operations.
Air Emissions
Our operations are subject to the federal Clean Air Act, or CAA, and comparable state and local laws. Under such laws, permits are typically required to emit pollutants into the atmosphere above certain thresholds. We believe we currently hold or have applied for all necessary air permits and that we are in substantial compliance with applicable air laws and regulations. Although we can give no assurances, we are aware of no changes to air quality regulations that will have a material adverse effect on our financial condition or results of operations.
Various federal, state and local agencies have the authority to prescribe product quality specifications for the refined products that we sell, largely in an effort to reduce air pollution. Failure to comply with these 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. Also, states in which we operate have either started or plan to limit the sulfur content of home heating oil, which could also increase our costs to purchase such oil or limit our ability to sell heating oil.
 
Changing sulfur regulations also impact the residual fuel oil business. Restrictions on certain grades of product and in certain cases, banning residual fuel oil in certain municipalities or regions, will force us to reconfigure existing tanks that are in residual fuel oil service.

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Climate Change
In response to the April 2007 United States Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate carbon dioxide emissions under the CAA, the EPA has taken several steps towards implementing regulations regarding the emission of greenhouse gases, or GHG. In 2009, the EPA issued a final rule declaring that six GHGs “endanger both the public health and the public welfare of current and future generations.” The issuance of this “endangerment finding” allows the EPA to begin regulating GHG emissions under existing provisions of the federal Clean Air Act. In addition, the EPA has issued rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, beginning in 2011 for emissions occurring in 2010. Certain state jurisdictions also have similar GHG reporting requirements. While our operations fall below the thresholds that would characterize large sources, we are required to implement systems to track certain purchases of product and we believe we are in material compliance with the regulations.
Overall, there has been a trend towards increased regulation of GHGs and initiatives, both domestically and internationally, to limit GHG emissions. Future efforts to limit emissions associated with transportation fuels and heating fuels could reduce the market for, or pricing of, our products, and thus adversely impact our business. In addition, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations.
Activists concerned about the potential effects of climate change have, in certain instances, directed their attention at sources of funding for fossil-fuel energy companies. This could make it more difficult to secure funding for projects.




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Item 1A.    Risk Factors
Common units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business.
If any of the following risks were actually to occur, our business, financial condition, results of operations and ability to pay distributions to our unitholders could be materially adversely affected. Additional risks and uncertainties not currently known to us or that we currently consider to be immaterial may also materially adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.
Risks Related to Our Business
We may not have sufficient distributable cash flow following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our General Partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.
In order to pay the minimum quarterly distribution of $0.4125 per unit per quarter, or $1.65 per unit on an annualized basis, we will require distributable cash flow of $9.4 million per quarter, or $37.5 million per year, based on the number of common units currently outstanding. We may not have sufficient distributable cash flow each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations and our borrowing capacity, which will fluctuate from quarter to quarter based on, among other things:
 
Competition from other companies that sell refined products, natural gas and/or renewable fuels in the Northeast United States and eastern Canada;
Competition from other companies in the materials handling business;
Demand for refined products, natural gas and our materials handling services in the markets we serve;
Absolute price levels, and volatility of prices, of refined products and natural gas in both the spot and futures markets;
Seasonal variation in temperature, which affects demand for natural gas and refined products such as heating oil and residual fuel oil (to the extent that it is used for space heating); and
Prevailing economic and regulatory conditions.
In addition, the actual amount of distributable cash flow that we distribute will depend on other factors such as:
 
The level of maintenance capital expenditures we make;
The level of operating and general and administrative expenses, including reimbursements to our General Partner and certain of its affiliates for services provided to us;
Fluctuations or changes in federal, state, local and foreign tax rates, including Canadian income and withholding tax rates;
The restrictions contained in our credit agreement, including borrowing base limitations and limitations on distributions;
Our debt service requirements;
The cost of acquisitions we make, if any;
Fluctuations in our working capital needs;
Our ability to access capital markets and to borrow under our credit agreement to make distributions to our unitholders; and
The amount of cash reserves established by our General Partner, if any.

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Our distributable cash flow depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
Our distributable cash flow depends primarily on cash flow, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.
Our business is seasonal and generally our financial results are lower in the second and third quarters of the calendar year which may result in an increased need to borrow money in order to make quarterly distributions to our unitholders during these quarters.
Demand for natural gas and some refined products, specifically home heating oil and residual fuel oil for space heating purposes, is generally higher during the period of November through March than during the period of April through October. Therefore, our results of operations for the first and fourth calendar quarters are generally better than for the second and third calendar quarters. For example, over the 36-month period ended December 31, 2018, we generated an average of 71% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States and Canada. With reduced cash flow during the second and third calendar quarters, we may be required to borrow money in order to pay the minimum quarterly distribution to unitholders. Any restrictions on our ability to borrow could restrict our ability to make quarterly distributions to unitholders.
A significant decrease in demand for refined products, natural gas or our materials handling services in the areas we serve would adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
A significant decrease in demand for refined products, natural gas or our materials handling services in the areas that we serve would significantly reduce net sales and, therefore, adversely affect our business, financial condition, results of operations, our ability to borrow and make quarterly distributions to our unitholders. Factors that could lead to a decrease in market demand for refined products or natural gas include:
 
Recession or other adverse economic conditions;

Unseasonably warm temperatures which would negatively impact demand for natural gas and refined products;
 
High prices caused by an increase in the market price of refined products or natural gas, higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products or natural gas;
Increased conservation, technological advances and the availability of alternative energy, whether as a result of industry changes, governmental or regulatory actions or otherwise. For example, energy efficiency measures, including the installation of improved insulation and the development of more efficient furnaces and other heating devices and increased use of fuel efficient motor vehicles, have adversely affected demand for some of our products, particularly home heating oil and residual fuel oil; and,
Conversion from consumption of heating oil or residual fuel oil to natural gas as such switching and conversions could reduce our sales of heating oil and residual fuel oil.
Factors that could lead to a decrease in demand for our materials handling services include weakness in the housing and construction industries and the economy generally.
Certain of our operating costs and expenses are fixed and do not vary with the volumes we store, distribute and sell. These costs and expenses may not decrease ratably, or at all, should we experience a reduction in volumes stored, distributed and sold. As a result, we may experience declines in operating margin if our volumes decrease.

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Our business, financial condition, results of operations and ability to make quarterly distributions to unitholders are influenced by changes in demand for, and therefore indirectly by changes in the prices of, refined products and natural gas, which could adversely affect our profit margins, our customers’ and suppliers’ financial condition, contract performance, trade credit and the amount and cost of borrowing under our credit agreement.
Financial and operating results from our purchasing, storing, terminalling and selling operations are influenced by price volatility in the markets for refined products and natural gas. When prices for refined products and natural gas rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs to our customers, resulting in lower margins for a period of time before margins expand to cover the incremental costs. Significant increases in the costs of refined products can materially increase our costs to carry inventory. We use the working capital facility in our credit agreement, which limits the amounts that we can borrow, as the primary source of financing for our working capital requirements. Lastly, higher prices for refined products or natural gas may (1) diminish our access to trade credit support or cause it to become more expensive and (2) decrease the amount of borrowings available for working capital as a result of total available commitments, borrowing base limitations and advance rates thereunder.
In addition, when prices for refined products or natural gas decline, the likelihood of nonperformance by our customers on forward contracts increases as they and/or their customers may attempt to not perform under their contracts and instead purchase refined products or natural gas at the then lower spot or retail market price.
Restrictions in our credit agreement could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders as well as the value of our common units.
We are dependent upon the earnings and cash flow generated by operations in order to meet our debt service obligations and to allow us to make cash distributions to unitholders. The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue business, which may, in turn, adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. For example, our credit agreement restricts our ability to, among other things:
 
Make cash distributions;
Incur indebtedness;
Create liens;
Make investments;
Engage in transactions with affiliates;
Make any material change to the nature of our business;
Dispose of assets; and
Merge with another company or sell all or substantially all of our assets.
Furthermore, our credit agreement contains covenants requiring us to maintain certain financial ratios. The provisions of the credit agreement may affect our ability to obtain future financing for and pursue attractive business opportunities and maintain flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the credit agreement could result in an event of default which could enable our lenders, subject to the terms and conditions of our credit agreement, to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. See Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.

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Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
 
Our ability to obtain additional financing, if necessary, for working capital, capital expenditures or other purposes may be impaired, or such financing may not be available on favorable terms;
Our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make required debt service payments;
We may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
Our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service debt will depend upon, among other things, future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If operating results are not sufficient to maintain our indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business, acquisitions, investments or capital expenditures, selling assets or issuing equity. We may not be able to affect any of these actions on satisfactory terms or at all.
Changes in currency exchange rates could adversely affect our operating results.
Because we are a U.S. dollar reporting company and also conduct a portion of our Canadian operations in Canadian dollars, we are exposed to currency fluctuations and exchange rate risks that may adversely affect the U.S. dollar value of our earnings, cash flow and partners’ capital under applicable accounting rules.
Warmer weather conditions during winter could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Weather conditions during winter have an impact on the demand for heating oil, residual fuel oil and natural gas. Because we supply distributors whose customers depend on heating oil, residual fuel oil and natural gas during the winter, warmer-than-normal temperatures during the first and fourth calendar quarters in one or more regions in which we operate can decrease the total volume we sell and the adjusted gross margin realized on those sales and, consequently, our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Our risk management policies, processes and procedures cannot eliminate all commodity price risk or basis risk, which could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. In addition, any noncompliance with our risk management policies, processes and procedures could result in significant financial losses.
While our risk management policies, processes and procedures are designed to limit commodity price risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, we change our hedged position daily in response to movements in our inventory. If we overestimate or underestimate sales from inventory, we may be unhedged for the amount of the overestimate or underestimate.
In general, basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Basis may reflect price differentiation associated with different time periods, qualities or grades, or locations and is typically calculated based on the price difference between the cash or spot price of a commodity and the prompt month futures or swaps contract price of the most comparable commodity. For example, if NYMEX heating oil, which is based on New York Harbor delivery, was used to hedge our commodity risk for heating oil purchases, we could have location basis risk if the deliveries were made in a different location such as in Boston. An example of quality or grade basis risk would be the use of diesel fuel contracts to hedge heating oil. The potential exposure from basis risk is in addition to any impact that market pricing structure may have on our results. Basis risk cannot be entirely eliminated and basis exposure can adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
We monitor policies, processes and procedures designed to prevent unauthorized trading and to maintain substantial balance between purchases and sales or future delivery obligations. We can provide no assurance, however, that these steps will detect and/or prevent all violations of such risk management policies, processes and procedures, particularly if deception or other intentional misconduct is involved.

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We are exposed to risks of loss in the event of nonperformance by our customers, suppliers and counterparties.
We are subject to risk of nonperformance by our customers, suppliers and counterparties. We purchase products from a variety of natural gas and refined product suppliers under term contracts and on the spot market. In times of extreme market demand or during market disruptions due to political events, natural disaster, logistical/delivery issues or otherwise, these suppliers may be unable to satisfy our supply requirements. If any of these events were to occur, we may be required to pay more for product that we purchase on the open market, which could result in financial losses and adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Additionally, some of our customers, suppliers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. A tightening of credit in the financial markets or an increase in interest rates may make it more difficult for our customers, suppliers and counterparties to obtain financing and, depending on the degree to which it occurs, there may be a material increase in the nonpayment or other nonperformance by our customers, suppliers and counterparties. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with these third parties. A material increase in the nonpayment or other nonperformance by our customers, suppliers and/or counterparties could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Furthermore, our access to trade credit support could diminish or become more expensive. Our ability to continue to receive sufficient trade credit on commercially acceptable terms could be adversely affected by, among other things, fluctuations in refined product, natural gas and renewable fuel prices or disruptions in the credit markets.
Some of our refined products and natural gas competitors have capital resources many times greater than ours and control greater supplies. Competitors able to supply customers with products and services at a lower price could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Our competitors include terminal companies, major integrated oil companies and their marketing affiliates and independent marketers of varying size, financial resources and experience. Some of our competitors are substantially larger than us, have capital resources many times greater than ours, control greater supplies of refined products and natural gas than us and/or control substantially greater storage capacity than us. If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers, which could have a material adverse effect on our business, financial condition, results of operations and distributable cash flow. For example, if a competitor attempts to increase market share by reducing prices or offering alternative energy sources, our business, financial condition, results of operations and ability to make quarterly distributions to unitholders could be adversely affected. We may not be able to compete successfully with such companies.
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our customers and employees, in data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite our security measures, information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disrupt operations and the services we provide to customers, damage our reputation, and cause a loss of confidence in our products and services, which could adversely affect business/operating margins, revenues and competitive position.

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A principal focus of our business strategy is to grow and expand our business through acquisitions. If we do not make acquisitions on economically acceptable terms, our future growth may be limited and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.
A principal focus of our business strategy is to grow and expand our business through acquisitions. Our ability to grow depends, in part, on our ability to make accretive acquisitions that result in an increase in cash from operations generated per unit. If we are unable to make accretive acquisitions, either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, such acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.
Any acquisition involves potential risks, including, among other things:
 
Mistaken assumptions about volumes, cash flows, net sales and costs, including synergies;
An inability to successfully integrate the businesses we acquire;
An inability to hire, train or retain qualified personnel to manage and operate our 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 used to finance an acquisition;
The diversion of management’s and employees’ 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.
A portion of our net sales is generated under contracts that must be renegotiated or replaced periodically. If we are unable to successfully renegotiate or replace these contracts, our business, financial condition, results of operations and ability to make quarterly distributions to unitholders could be adversely affected.
Most of our contracts with refined products customers are for a single season or on a spot basis, while most of our contracts with natural gas customers are for a term of one year or less. As these contracts and our materials handling contracts expire from time to time, they must be renegotiated or replaced. We may be unable to renegotiate or replace these contracts when they expire, and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. Whether these contracts are successfully renegotiated or replaced is often subject to factors beyond our control. Such factors include fluctuations in refined product and natural gas prices, counterparty ability to pay for or accept the contracted volumes and a competitive marketplace for the services we offer. While our materials handling contracts are generally long-term, they are also subject to periodic renegotiation or replacement. If we cannot successfully renegotiate or replace any of our contracts, or if we renegotiate or replace them on less favorable terms, net sales and margins from these contracts could decline and our business, financial condition, results of operations and ability to make quarterly distributions to unitholders could be adversely affected.
Due to our lack of geographic diversification, adverse developments in the terminals we use or in our operating areas would adversely affect results of operations and distributable cash flow.
We rely primarily on sales generated from products distributed from the terminals we own, control or operate to which we have access. Furthermore, our operations are largely located in the Northeast United States and eastern Canada.
Due to our lack of geographic diversification, an adverse development in the businesses or areas in which we operate, including adverse developments due to catastrophic events, weather or decreases in demand for refined products or materials handling services, could have a significantly greater impact on our results of operations and distributable cash flow than if we operated in more diverse locations.

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Our operations are subject to operational hazards and unforeseen interruptions for which we may not be able to maintain adequate insurance coverage.
We are not fully insured against all risks incident to our business. Our operations are subject to many operational hazards and unforeseen interruptions inherent in our business, including:
 
Damage to storage facilities and other assets caused by tornadoes, hurricanes, floods, earthquakes, fires, explosions, extreme weather conditions and other natural disasters;
Acts or threats of terrorism;
Unanticipated equipment and mechanical failures at our facilities;
Disruptions in supply infrastructure or logistics and other events beyond our control;
Operator error; and
Environmental pollution or other environmental issues.
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 related operations.
We may be unable to maintain or obtain insurance of the type and amount we believe to be appropriate for our business at reasonable rates or at all. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase or escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Certain types of risks, such as fines and penalties, or remediation or damages claims from environmental pollution, are either not covered by insurance or applicable insurance may be unavailable for particular claims based on exclusions or limitations in the policies. If we were to incur a significant liability for which we were not fully insured, it could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Our terminalling and materials handling operations are subject to federal, state and local laws and regulations relating to environmental protection and operational safety that require us to incur substantial costs and that may become more stringent over time.
A fundamental risk inherent in terminalling and materials handling operations is that we may incur substantial environmental costs and liabilities. In particular, our terminalling operations involve the receipt, storage and redelivery of refined products and are subject to stringent federal, state and local laws and regulations regulating environmental matters including the discharge of materials into the environment, or otherwise relating to the protection of the environment, operational safety and related matters. We also face laws and regulations that impact product quality specifications that could have a material adverse effect on our business.
Compliance with these laws and regulations increases our overall cost of business, including our capital costs to maintain and upgrade equipment and facilities. Further, we may incur increased costs because of stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.
We utilize a number of terminals that are owned and operated by third parties who are also subject to these stringent federal, state and local environmental laws in their operations. Compliance with these requirements by such third parties could increase the cost of doing business with these facilities and there can be no assurances as to the timing and type of such changes or what the ultimate costs might be. If such third parties fail to comply with environmental laws, they could be shut down, requiring us to incur costs to use alternative facilities.

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The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment over time. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our financial position. However, 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, or the development or discovery of new facts or conditions will not cause us to incur significant costs or have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.
The risks of spills and releases and the associated liabilities for investigation, remediation and third-party claims, if any, are inherent in terminalling operations, and the liabilities that we incur may be substantial.
Our operation of refined products terminals and storage facilities as well as our transportation and logistics activities are inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or other hazardous substances. If any of these events have previously occurred or occur in the future, whether in connection with any of our storage facilities or terminals, any other facility to which we send or have sent wastes or by-products for treatment or disposal or on any property which we own or have owned, we could be liable for all costs, jointly and severally, and administrative, civil and criminal penalties associated with the investigation and remediation of such facilities under federal, state and local environmental laws or the common law. We may also be held liable for damages to natural resources, personal injury or property damage claims from third parties, including the owners of properties located near our terminals and those with whom we do business, alleging contamination from spills or releases from our facilities or operations. Even if we are insured against certain or all of such risks, we may be responsible for all such costs to the extent our insurers or indemnitors do not fulfill their obligations to us. The payment of such costs or penalties could be significant and have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Increased physical damage and regulation related to climate change could result in increased operating costs and reduced demand for refined products as a fuel source, which could in turn reduce demand for our products and adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Risks related to climate change include both physical and regulatory risks. Physical risks from climate change may include direct damage to our assets and from the increased frequency and severity of extreme weather events and/or chronic impacts to our operations from longer-term shifts in precipitation patterns and extreme variability in weather patterns. These effects could adversely affect the financial performance of our assets and operations.
Regulatory actions around climate change also continue to evolve and are particularly relevant for our products and business. We may become subject to more stringent legislation and regulation regarding climate change and compliance with any new rules could be difficult and costly. Foreign, federal, state and local regulatory and legislative bodies have proposed various legislative and regulatory measures relating to climate change, regulating GHG emissions and energy policies. If such legislation is enacted, we could incur increased energy, environmental and other costs and capital expenditures to comply with regulations and limitations. Due to the uncertainty in the regulatory and legislative processes, as well as the scope of such requirements and initiatives, we cannot currently determine the effect such legislation and regulation may have on our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. Additionally, we could face increased costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our operations on climate change.
The Environmental Protection Agency, or EPA, took the first steps toward regulating existing oil and gas operations by issuing an Information Collection Request seeking a broad range of information, including the types of technologies that could be used to reduce emissions from existing sources and their associated costs; however; the EPA rescinded this request in March 2017. To the extent that our operations become subject to or affected by the EPA’s GHG regulations, we may face increased capital and operating costs associated with new or expanded facilities.

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Kildair is subject to both Canadian federal and Quebec provincial environmental regulations relating to climate change, GHG emissions, fuel content requirements, and energy policies, including, without limitation, regulations that require the purchase of emission allowances, credits and/or compliance units needed to cover emissions attributable to the combustion of some fossil fuels it sells for consumption or otherwise related to the renewable fuel content of such fuels. These laws and regulations are currently under review by the federal and provincial authorities and, as a result, modifications to the regulatory framework is expected in the near future, notably involving the imposition of a carbon levy on products sold by Kildair as well as carbon intensity reduction requirements on such products. To comply with these laws and regulations, Kildair must, and will, incur costs such as, for example, the cost to purchase allowances, credits and compliance units, that allow Kildair to continue operations at its current or increased levels. Increased costs may result in increased prices for Kildair’s products or decreased profitability. Increased product price as well as the laws and regulations applicable to Kildair's customers, who are themselves subject to laws and regulations relating to climate change, GHG emissions, and energy policies, could result in a reduction of demand for Kildair’s product and therefore reduce our revenues. Additional risks include the inability of Kildair to acquire the required amount of emission allowances, credits or compliance units to offset emissions and/or meet the renewable fuel content which would subject Kildair to various fines.
Overall, there has been a trend at the federal and state level towards increased regulation of GHGs and carbon pollution, both domestically and internationally, to limit emissions. A number of states including, but not limited to Connecticut, Maine, New Hampshire, New York and Pennsylvania, have introduced legislation to establish taxes or assessments on the carbon content of fuels. Future efforts to limit emissions associated with transportation fuels and heating fuels could increase costs, reduce the market for, or impact the pricing of, our products, and thus adversely impact our business. Increased costs could result in reduced demand for refined 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.
Additionally, activists concerned about the potential effects of climate change have recently directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as our terminal facilities.
We are subject to federal, state and local laws and regulations that govern the product quality specifications of the refined products we purchase, store, transport and sell.
Various federal, state and local government agencies have the authority to prescribe specific product quality specifications to the sale of commodities. Changes in product quality specifications, such as reduced sulfur content in refined products, or other more stringent requirements for fuels, could reduce our ability to procure or create products of various specifications and limit purchase and storage opportunities associated with market dislocations and discrepancies. Changes in product specifications may require us to incur additional handling costs and capital expenditures. If we are unable to procure product or recover these costs through increased sales, our business would be negatively impacted and we may not be able to meet our financial obligations.
We depend on unionized labor for our operations in Bronx, Lawrence, Mt. Vernon, and Albany, New York; Providence, Rhode Island; and Sorel-Tracy Quebec, Canada. Work stoppages or labor disturbances at these facilities could disrupt our business.
Work stoppages or labor disturbances by our unionized labor force could have an adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. In addition, employees who are not currently represented by labor unions may seek representation in the future, and renegotiation of collective bargaining agreements may result in agreements with terms that are less favorable to us than our current agreements.

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We rely on our information technology systems to manage numerous aspects of our business, and a disruption of these systems could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
We depend on our information technology, or IT, systems to manage numerous aspects of our business and to provide analytical information to management. Our IT systems are an essential component of our business and growth strategies, and a serious disruption to our IT systems could limit our ability to manage and operate our business efficiently. These systems are vulnerable to, among other things, damage and interruption from power loss or natural disasters, computer system and network failures, loss of telecommunication services, physical and electronic loss of data, security breaches and computer viruses. We employ back-up IT facilities and have disaster recovery plans; however, these safeguards may not entirely prevent delays or other complications that could arise from an IT systems failure, a natural disaster or a security breach. Significant failure or interruption in our IT systems could cause our business and competitive position to suffer and damage our reputation, which would adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.

Risks Inherent in an Investment in Us
We distribute significant portions of our distributable cash flow, which could limit our ability to grow and make acquisitions.
We rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute a significant portion of our distributable cash flow, our growth may not be as fast as that of businesses that reinvest their available 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 the partnership agreement or credit 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 adversely impact the cash that we have available to distribute to unitholders.
Axel Johnson indirectly controls our General Partner, which has sole responsibility for conducting our business and managing our operations. Our General Partner and its affiliates, including Axel Johnson, may have conflicts of interest with us and have limited duties to us and our common unitholders, and they may favor their own interests to the detriment of us and our common unitholders.
As of March 8, 2019, Axel Johnson, through its ownership of Sprague Holdings, indirectly owns a 53% limited partner interest in us and indirectly owns and controls our General Partner. Although our General Partner has a fiduciary duty to manage us in good faith, the directors and officers of our General Partner have a fiduciary duty to manage our General Partner in a manner that is beneficial to its owner, Sprague Holdings, which is a wholly owned subsidiary of Axel Johnson. Furthermore, certain directors and officers of our General Partner are directors and/or officers of affiliates of our General Partner. Conflicts of interest may arise between our General Partner and its affiliates, including Axel Johnson, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our General Partner may favor its own interests and the interests of its affiliates, including Axel Johnson, over the interests of our common unitholders. These conflicts include, among others, the following situations:
 
Our General Partner is allowed to take into account the interests of parties other than us, such as its affiliates, including Axel Johnson, in resolving conflicts of interest, which has the effect of limiting its duty to our unitholders.
Affiliates of our General Partner, including Axel Johnson and Sprague Holdings, may engage in competition with us.
Neither our partnership agreement nor any other agreement requires Axel Johnson or Sprague Holdings to pursue a business strategy that favors us. Axel Johnson’s directors and officers have a fiduciary duty to make decisions in the best interests of the stockholders of Axel Johnson.
Some officers of our General Partner who provide services to us devote time to affiliates of our General Partner.
Our partnership agreement limits the liability of and reduces the duties owed by our General Partner to us and our common unitholders, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

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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 creation, reductions or increases of cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders and to the holders of the incentive distribution rights.
Our General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces distributable cash flow. Such determination can affect the amount of distributable cash flow available to the holders of our common units and to the holders of the incentive distribution rights. Our partnership agreement does not limit the amount of maintenance capital expenditures that our General Partner can cause us to make.
Our partnership agreement and the services agreement allow our General Partner to determine, in good faith, the expenses that are allocable to us. Our partnership agreement and the services agreement do not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, incentive compensation and other amounts paid to persons, including affiliates of our General Partner, who perform services for us or on our behalf.
Our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, including incentive distributions.
Our partnership agreement permits us to distribute up to $25.0 million as distributable cash flow, even if it is generated from sources that would otherwise constitute capital surplus, and this cash may be used to fund the incentive distributions.
Our partnership agreement does not restrict our General Partner from entering into additional contractual arrangements with any of 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 all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of all outstanding common units.
Our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates.
Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Sprague Holdings, or any transferee holding a majority of the 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 the incentive distribution rights without the approval of the conflicts committee of the board of directors of our General Partner or unitholders. This election may result in lower distributions to common unitholders in certain situations.
Under 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 their executive officers, directors and owners. Other than as provided in our omnibus agreement, 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 and result in less than favorable treatment of us and our unitholders.
Our General Partner intends to limit its liability regarding our obligations.
Other than under our credit agreement, our General Partner intends to limit its liability under contractual arrangements 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 duty to act in good faith, 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 distributable cash flow otherwise available for distribution to unitholders.

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Our partnership agreement limits our General Partner’s duties to our unitholders.
Our partnership agreement contains provisions that modify and reduce the standards to which our General Partner would otherwise be held under 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 other affiliates;
Whether to exercise its limited call right;
How to exercise its voting rights with respect to any units it owns;
Whether to exercise its registration rights with respect to any units it owns; and
Whether 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 our unitholders 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;
Provides that a determination, other action or failure to act by our General Partner, the board of directors of our General Partner or any committee thereof (including the conflicts committee) will be deemed to be in good faith unless our General Partner, the board of directors of our General Partner or any committee thereof believed such determination, other action or failure to act was adverse to the interests of the partnership;
Provides that 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;
Provides that our General Partner and its officers and directors will not be liable for monetary damages 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 our General Partner or its officers and directors, as the case may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
Provides that 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.

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Cost reimbursements and fees due to our General Partner and its affiliates for services provided to us or on our behalf, which may be determined in our General Partner’s sole discretion, may be substantial and will reduce our distributable cash flow.
Under our partnership agreement, prior to making any distribution on the common units, our General Partner and its affiliates shall be reimbursed for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Pursuant to the terms of the services agreement, our General Partner has agreed to provide certain general and administrative services and operational services to us, and we have agreed to reimburse our General Partner and its affiliates for all costs and expenses incurred in connection with providing such services to us, including salary, incentive compensation, insurance premiums and other amounts allocable to the employees and directors of our General Partner or its affiliates that perform services on our behalf. Our General Partner and its affiliates also may provide us other services for which we may be charged fees as determined by our General Partner. Our partnership agreement and the services agreement do not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. Payments to our General Partner and its affiliates may be substantial and will reduce the amount of distributable cash flow.
Unitholders have limited voting rights and, even if they are dissatisfied, cannot remove our General Partner without its consent.
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 did not elect our General Partner or the board of directors of our General Partner and will have no right to elect our General Partner or the board of directors of our General Partner on an annual or other continuing basis. The board of directors of our General Partner is chosen by Sprague Holdings, a wholly-owned subsidiary of Axel Johnson and the sole member of our General Partner. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
The unitholders will be unable to remove our General Partner without its consent because our General Partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2⁄3% of all outstanding common units is required to remove our General Partner. As of March 8, 2019, Sprague Holdings owned 53% of our common units.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units resulting in ownership of at or in excess of such levels with the prior approval of the board of directors of our General Partner, cannot vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
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 the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Sprague Holdings to transfer its membership interest in our General Partner to a third party. The new members of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with their own choices and to control the decisions taken by the board of directors and officers.

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The incentive distribution rights held by Sprague Holdings may be transferred to a third party without unitholder consent.
Sprague Holdings may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If Sprague Holdings 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 Sprague Holdings had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by Sprague Holdings could reduce the likelihood of Axel Johnson accepting offers made by us relating to assets owned by it, as Axel Johnson would have less of an economic incentive to grow our business, which in turn may impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, neither the partnership agreement nor the credit agreement prohibits the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
 
Our unitholders’ proportionate ownership interest in us will decrease;
The amount of distributable cash flow 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 our common units may decline.
Sprague Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of March 8, 2019, Sprague Holdings held 12,106,348 common units. We have agreed to provide Sprague Holdings with certain registration rights (which may facilitate the sale by Sprague Holdings of its common units into the public markets). The sale of these units in the public or private markets, or the perception that such sales might occur, could have an adverse impact on the price of the common units or on any trading market that may develop.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return on government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
Our General Partner’s discretion in establishing cash reserves may reduce the amount of distributable cash flow that we distribute.
The partnership agreement permits our General Partner to reduce the amount of distributable cash flow distributed to our unitholders by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners.
Our General Partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our General Partner or its affiliates.
In some instances, our General Partner may cause us to borrow funds from its affiliates, including Axel Johnson, or from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make incentive distributions.

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Our General Partner has a limited call right that may require you to sell your common units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our 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. As a result, you may be required to sell your common units at an undesirable time or price, including at a price below the then-current market price, and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of March 8, 2019, Sprague Holdings and its affiliates owned 53% of our common units.
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 constitutes “control” of our business.
A restatement of net income or a reversal or change of estimates affecting net income made after the end of the subordination period but affecting net income during the subordination period will not retroactively affect the conversion of the subordinated units even if we would not have had sufficient distributable cash flow based on such restated or adjusted net income to permit conversion.
All of our outstanding subordinated units converted into common units on a one-for-one basis on February 16, 2017, upon the satisfaction of certain tests involving the calculation of distributable cash flow on a historical basis. Distributable cash flow is calculated based on net income, which is a GAAP measure. If net income for a period during the subordination period is restated after the end of the subordination period or if estimates affecting net income made during the subordination period are reversed or changed after the end of the subordination period, it will not retroactively affect the conversion of subordinated units even if we would not have had sufficient distributable cash flow during the subordination period based on such restated or adjusted net income to permit conversion.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
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, or the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.


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Sprague Holdings, or any transferee holding a majority of the 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 the incentive distribution rights, without the approval of the conflicts committee of the board of directors of our General Partner or the holders of our common units. This could result in lower distributions to our unitholders.
The holder or holders of a majority of the incentive distribution rights (currently Sprague Holdings) have the right, in their discretion and without the approval of the conflicts committee of the board of directors of our General Partner or the holders of our common units, at any time when the holders received distributions on their incentive distribution rights at the highest level to which they are entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on distributions at the time of the exercise of the reset election. At December 31, 2018, Sprague Holdings had the right to reset the initial target distribution levels. Following a reset election, 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. Sprague Holdings has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as Sprague Holdings relative to resetting target distributions.
In the event of a reset of target distribution levels, the holders of the incentive distribution rights will be entitled to receive a number of common units equal to the number of common units that would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. We anticipate that Sprague Holdings 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 Sprague Holdings or a transferee 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 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 they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels.
The New York Stock Exchange (NYSE) does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
As a limited partnership, we are not required 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, as is required for other NYSE-listed entities. Accordingly, unitholders do not have the same protections afforded to certain entities, including most corporations that are subject to all of the NYSE corporate governance requirements.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. 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 U.S. federal income tax purposes, or we become subject to entity level taxation for state tax purposes, our cash available for distribution would be substantially reduced. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for U.S. federal income tax purposes unless it satisfies 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 U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely pay additional state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distributions to our unitholders 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 our unitholders, likely causing a substantial reduction in the value of our common units.

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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 have proposed and considered substantive changes to the existing U.S. federal income tax laws that would 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.
Any modification to the U.S. federal income tax laws or other applicable 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. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative
developments and proposals and their potential effect on your investment in our common units.
In addition to U.S. federal income tax, we are currently subject to entity level taxes and fees in a number of states and such taxes and fees reduce our distributable cash flow. Changes in current state and local laws may subject us to additional entity-level taxation by individual states and local governments. Additionally, unitholders may be subject to other state and local taxes that are imposed by various jurisdictions in which the unitholder resides or in which we conduct business or own property.
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 non-U.S. income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
Notwithstanding our treatment for U.S. federal income tax purposes, we are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, our distributable cash flow would be further reduced.
A material amount of our business operations and subsidiaries are subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of our distributable cash flow. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions, the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional tax being imposed on us. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income. Any such increases in tax imposed on us would further reduce our distributable cash flow. Although these taxes may be properly characterized as foreign income taxes, unitholders may not be able to credit them against their liability for U.S. federal income taxes on their share of our earnings.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholders may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase.  Similarly, 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” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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Tax gain or loss on the disposition of our common units could be more or less than our unitholders expect.
If a unitholder sells common units, such unitholder will recognize gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease its tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units being sold will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price received is less than the unitholder’s original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells units, such unitholder may incur a tax liability in excess of the amount of cash received from the sale.
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. 
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for "business interest" is limited to the sum of our business interest income and 30% of our "adjusted taxable income." For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.
Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts ("IRAs"), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trades or businesses) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. If you are a tax exempt entity, you should consult your tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ("effectively connected income"). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

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The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder's sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. If you are a non-U.S. person, you should consult your tax adviser before investing in our common units.
If a tax authority contests the tax positions we take, the market for our common units may be adversely affected and the cost of any such contest would reduce our distributable cash flow.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. Tax authorities may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with a tax authority may materially and adversely affect the market for our common units and the price at which they trade. Our costs of any contest with a tax authority will be borne indirectly by our unitholders and our General Partner because the costs will reduce our distributable cash flow.

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 adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.

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 adjustments 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 information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) 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 and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing our publicly traded units to have different capital accounts, unless the IRS issues further guidance.

In the event the IRS makes an audit adjustment to our income tax return and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Due to a number of factors including our inability to match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

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We generally 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 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, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and could 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 to the short seller may be considered to have disposed of the loaned units. In that case, such unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may be required to 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 consult a tax advisor to determine whether it is advisable 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 recognized 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.
Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including foreign, 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 they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business and own property in numerous states, in the United States most of which impose a personal income tax as well as an income tax on corporations and other entities. We may own property or conduct business in other U.S. states or non-U.S. countries that impose a personal income tax in the future. It is the unitholder’s responsibility to file all U.S. federal, state, local and non-U.S. tax returns.
Item 1B. Unresolved Staff Comments
None.

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Item 2. Properties
The following tables set forth information with respect to our owned, operated and/or controlled terminals as of December 31, 2018.
 
Liquids Storage Terminals
Number of
Storage Tanks
 
Storage Tank
Capacity (Bbls)
 
Principal Products and Materials
**
Sorel-Tracy Quebec, Canada
27

 
3,282,600

 
refined products; asphalt, crude oil
**
Newington, NH: River Road
29

 
1,157,300

 
refined products; asphalt; tallow
**
Searsport, ME
17

 
1,140,700

 
refined products; caustic soda; asphalt
*
Bridgeport, CT
11

 
1,120,600

 
refined products
*
Albany, NY
9

 
1,103,600

 
refined products
**
South Portland, ME
25

 
1,021,000

 
refined products; asphalt; clay slurry
*
East Providence, RI
9

 
970,400

 
refined products
**
Bronx, NY
18

 
907,500

 
refined products; asphalt
**
Newington, NH: Avery Lane
12

 
722,000

 
refined products, asphalt
*
New Haven, CT (1)
15

 
683,300

 
refined products
*
Quincy, MA
9

 
657,000

 
refined products
**
Providence, RI
4

 
484,000

 
refined products; asphalt
***
Everett, MA
4

 
317,600

 
asphalt
*
Quincy, MA: TRT (2)
4

 
304,200

 
refined products
*
Springfield, MA
10

 
268,200

 
refined products
***
Oswego, NY
3

 
209,800

 
asphalt
*
Lawrence, NY and Inwood NY
10

 
174,000

 
refined products
*
New Bedford, MA (3)
2

 
85,900

 
refined products
*
Mount Vernon, NY
7

 
72,100

 
refined products
*
Stamford, CT
3

 
46,600

 
refined products
*
Washington, PA area - four locations
20

 
9,100

 
refined products
 
Total
248

 
14,737,500

 
 
 
Dry Storage Terminals
Number of Storage
Pads and Warehouses
 
Storage Capacity
(Square Feet)
 
Principal Products and Materials
**
Searsport, ME
2 warehouses;
 
90,000

 
break bulk; salt; petroleum coke;
 
 
15 pads
 
872,000

 
heavy lift
**
Newington, NH: River Road
3 pads
 
390,000

 
salt; gypsum
***
Portland, ME (4)
7 warehouses;
 
215,000

 
break bulk; dry bulk; coal;
 
 
3 pads
 
95,000

 
salt
**
South Portland, ME
3 pads
 
230,000

 
salt; coal
**
Providence, RI
1 pad
 
75,000

 
salt
 
 
9 warehouses;
 
 
 
 
 
Total
25 pads
 
1,967,000

 
 

*Refined Product activities; **Refined Products and Materials Handling activities; *** Materials Handling activities

(1)
These tanks are controlled via a storage and thruput agreement with an initial term through July 2, 2019.
(2)
Operating assets and real estate are leased from an unaffiliated third party through April 30, 2025.
(3)
Operating assets and real estate are leased from a subsidiary of Sprague Holdings through October 30, 2023.
(4)
One storage warehouse is leased from an unaffiliated third party and the balance of the property is owned by us.

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Item 3. Legal Proceedings
From time to time, we are a party to various legal proceedings or claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the captions Legal, Environmental and Other Proceedings in Note 19 - Commitments and Contingencies to our consolidated financial statements included in Part II, Item 8 of this Annual Report, which information is incorporated by reference into this Item 3.
Item 4. Mine Safety Disclosures
Not applicable.

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Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our public common units began trading on the NYSE under the symbol “SRLP” on October 25, 2013. As of March 8, 2019, Sprague Holdings owned 12,106,348 common units, which represents 53% of the limited partner interest in us. We have gathered tax information for our known unitholders and from brokers/nominees and, based on the information collected, we have estimated that the number of our beneficial common unitholders was 4,600 at December 31, 2018 and was 4,260 at December 31, 2017.
Certain Information from Our Partnership Agreement
Set forth below is a summary of certain provisions of our partnership agreement that relate to cash distributions and incentive distribution rights.
Our Cash Distribution Policy
It is our intent to distribute, within 45 days after the end of each fiscal quarter, the minimum quarterly distribution of $0.4125 per unit on all our units ($1.65 per unit on an annualized basis) to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of our expenses. The board of directors of our General Partner will determine the amount of our quarterly distributions and may change our distribution policy at any time. The board of directors of our General Partner may determine to reserve or reinvest excess cash in order to permit gradual or consistent increases in quarterly distributions and may borrow to fund distributions in quarters when we generate less distributable cash flow than necessary to sustain or grow our cash distributions per unit.
There is no guarantee that unitholders will receive quarterly cash distributions from us. We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate. Uncertainties regarding future cash distributions to our unitholders include, among other things, the following factors:
 
Our cash distribution policy may be affected by restrictions on distributions under our credit agreement as well as by restrictions in future debt agreements that we enter into. Specifically, our credit agreement contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit agreement, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.

Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy.
Under Section 17-607 of the Delaware Act we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
We may lack sufficient cash to make distributions to our unitholders due to a number of operational, commercial and other factors or increases in our operating costs, general and administrative expenses, principal and interest payments on our outstanding debt and working capital requirements.
If we make distributions out of capital surplus, as opposed to distributable cash flow, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. We do not anticipate that we will make any distributions from capital surplus.
Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership, limited liability company and corporate laws and other laws and regulations.
See Part I, Item 1A - Risk Factors - Risk Related to our Business.

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General Partner Interest
Our General Partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our General Partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interest.
Subordinated Units
Conversion of Subordinated Units
Pursuant to the terms of our partnership agreement, upon payment of the cash distribution on February 14, 2017, and meeting certain distribution and performance tests, the subordination period for our subordinated units expired on February 16, 2017. At the expiration of the subordination period, all 10,071,970 subordinated units converted into common units on a one-for-one basis.
Incentive Distribution Rights
Sprague Holdings currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from distributable cash flow in excess of $0.61875 per unit per quarter. The maximum IDR distribution of 50.0% does not include any distributions that our sponsor may receive on any limited partner units that it owns.
Issuer Purchases of Equity Securities
None.

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Item 6. Selected Financial Data
The following table presents selected historical financial and operating data of the Partnership as of the dates and for the periods indicated. The selected historical financial data is derived from the historical consolidated financial statements of the Partnership. This table should be read in conjunction with Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements of the Partnership and the notes thereto included in Part II, Item 8 of this Annual Report.
The following table presents the non-GAAP financial measure of adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. We define and explain this measure in Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations—How Management Evaluates Our Results of Operations—Adjusted Gross Margin and Adjusted EBITDA” and reconcile EBITDA and Adjusted EBITDA to net income (loss), their most directly comparable financial measure calculated and presented in accordance with GAAP.
 
Years Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in thousands, except unit data and operating data)
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
Net sales
$
3,771,133

 
$
2,854,996

 
$
2,389,998

 
$
3,481,914

 
$
5,069,762

Cost of products sold (exclusive of depreciation and amortization)
3,445,385

 
2,602,788

 
2,179,089

 
3,188,924

 
4,755,031

Operating expenses
88,659

 
72,284

 
65,882

 
71,468

 
62,993

Selling, general and administrative
80,799

 
87,582

 
84,257

 
94,403

 
76,420

Depreciation and amortization
33,378

 
28,125

 
21,237

 
20,342

 
17,625

Total operating costs and expenses
3,648,221

 
2,790,779

 
2,350,465

 
3,375,137

 
4,912,069

Operating income
122,912

 
64,217

 
39,533

 
106,777

 
157,693

Other income (expense)
293

 
108

 
(114
)
 
298

 
(288
)
Interest income
577

 
339

 
388

 
456

 
569

Interest expense
(38,931
)
 
(31,345
)
 
(27,533
)
 
(27,367
)
 
(29,651
)
Income before income taxes
84,851

 
33,319

 
12,274

 
80,164

 
128,323

Income tax provision (1)
(5,032
)
 
(3,822
)
 
(2,108
)
 
(1,816
)
 
(5,509
)
Net income
$
79,819

 
$
29,497

 
$
10,166

 
$
78,348

 
$
122,814

Income attributable to Kildair through December 8, 2014

 

 

 

 
(4,080
)
Incentive distributions declared
(7,879
)
 
(3,993
)
 
(1,742
)
 
(321
)
 

Limited partners’ interest in net income
$
71,940

 
$
25,504

 
$
8,424

 
$
78,027

 
$
118,734

Net income per limited partner unit:
 
 
 
 
 
 
 
 
 
Common—basic
$
3.17

 
$
1.15

 
$
0.40

 
$
3.71

 
$
5.88

Common—diluted
$
3.16

 
$
1.13

 
$
0.38

 
$
3.65

 
$
5.84

Weighted-average units used to compute net income per limited partner unit:
 
 
 
 
 
 
 
 
 
Common—basic
22,728,218

 
22,208,964

 
11,202,427

 
10,975,941

 
10,131,928

Common—diluted
22,737,404

 
22,474,872

 
11,560,617

 
11,141,333

 
10,195,566

Subordinated—basic and diluted
N/A

 
N/A

 
10,071,970

 
10,071,970

 
10,071,970

Distributions declared per unit
$
2.66

 
$
2.46

 
$
2.22

 
$
1.98

 
$
1.74

Adjusted EBITDA (2)
$
102,005

 
$
109,230

 
$
110,197

 
$
113,348

 
$
108,283


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Years Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in thousands, except operating data)
Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
158,979

 
$
57,042

 
$
131,744

 
$
287,613

 
$
15,564

Investing activities
(16,855
)
 
(153,269
)
 
(44,897
)
 
(14,565
)
 
(132,492
)
Financing activities
(141,315
)
 
100,286

 
(115,129
)
 
(245,965
)
 
118,390

Other Financial and Operating Data (unaudited):
 
 
 
 
 
 
 
 
 
Capital expenditures
$
17,249

 
$
46,955

 
$
15,986

 
$
14,899

 
$
18,580

Ten Year Average Heating Degree Days (3)
4,907

 
4,944

 
4,923

 
4,946

 
4,945

Heating Degree Days (3)
5,020

 
4,807

 
4,717

 
5,059

 
5,291

Variance from average heating degree days
2
 %
 
(3
)%
 
(4
)%
 
2
 %
 
7
%
Variance from prior period heating degree days
4
 %
 
2
 %
 
(7
)%
 
(4
)%
 
4
%
Total refined products volumes sold (barrels)
37,639

 
33,720

 
33,240

 
40,099

 
39,720

Variance from refined products volume from prior period
12
 %
 
1
 %
 
(17
)%
 
1
 %
 
13
%
Total natural gas volumes sold (MMBtus)
60,385

 
61,883

 
61,732

 
56,894

 
54,430

Variance from natural gas volume from prior period
(2
)%
 
 %
 
9
 %
 
5
 %
 
5
%
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
7,530

 
$
6,815

 
$
2,682

 
$
30,974

 
$
4,080

Property, plant and equipment, net
349,846

 
350,059

 
251,101

 
250,909

 
250,126

Total assets
1,245,240

 
1,362,985

 
1,012,474

 
1,000,332

 
1,339,840

Total debt (including capital lease obligations)
667,415

 
728,666

 
561,259

 
621,100

 
822,307

Total liabilities
1,108,264

 
1,231,151

 
887,037

 
842,847

 
1,223,946

Total unitholders’ equity
136,976

 
131,834

 
125,437

 
157,485

 
115,894


(1)
The Partnership is treated as a pass through entity for U.S. federal income tax purposes. For pass through entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in our financial statements. The Partnership’s Canadian entities are subject to Canadian income tax.
(2)
We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA adjusted for changes in unrealized gains (losses) with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts, adjusted for changes in the fair value of contingent consideration, adjusted for the impact of acquisition related expenses, and adjusted for the impact of biofuel excise tax credits resulting from retroactive tax legislation changes that occurred in 2018. For a discussion of the non-GAAP financial measure EBITDA and adjusted EBITDA, please read “Non-GAAP Financial Measures” in Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
(3)
We use heating degree day amounts as reported by the NOAA Regional Climate Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2010. Commencing April 1, 2018, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same locations over the previous ten-year period. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day amounts in this document have been revised to conform to this presentation.

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Reconciliation of Net Income to EBITDA and Adjusted EBITDA
The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA, on a historical basis, as applicable, for each of the years indicated:
 
Years Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in thousands)
Net income
$
79,819

 
$
29,497

 
$
10,166

 
$
78,348

 
$
122,814

Add/(deduct):
 
 
 
 
 
 
 
 
 
Interest expense, net
38,354

 
31,006

 
27,145

 
26,911

 
29,082

Tax expense (benefit)
5,032

 
3,822

 
2,108

 
1,816

 
5,509

Depreciation and amortization
33,378

 
28,125

 
21,237

 
20,342

 
17,625

EBITDA
$
156,583

 
$
92,450

 
$
60,656

 
$
127,417

 
$
175,030

Add/(deduct):
 
 
 
 
 
 
 
 
 
Change in unrealized gain on inventory (1)
(32,960
)
 
124

 
31,304

 
2,079

 
(11,070
)
Change in unrealized value on prepaid forward contracts (2)

 
(1,076
)
 
(1,552
)
 
2,628

 

Change in unrealized value on natural gas transportation contracts (3)
(19,114
)
 
10,441

 
18,612

 
(21,695
)
 
(58,694
)
Other adjustments (4)
771

 
231

 

 

 

Biofuel excise tax credits (5)
(4,022
)
 
4,022

 

 

 

Acquisition related expenses (6)
747

 
3,038

 
1,177

 
2,919

 
3,017

Adjusted EBITDA
$
102,005

 
$
109,230

 
$
110,197

 
$
113,348

 
$
108,283


(1)
Inventory is valued at the lower of cost or net realizable value. The adjustment related to unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values. The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income (loss).
(2)
Represents our estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income (loss) until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income (loss). The fair value of the derivatives we use to economically hedge our prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines in value.
(3)
Represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized gains (losses).
(4)
Represents the change in the fair value of the contingent consideration related to the 2017 Coen Energy acquisition and accretion expense.
(5)
On February 9, 2018, the U.S. federal government enacted legislation that reinstated an excise tax credit program available for certain of our biofuel blending activities and in both cases the program was reinstated retroactively to January 1st of the previously expired year. During the year ended December 31, 2018, we recorded excise tax credits of approximately $4.0 million that relate to blending activities that occurred during the year ended December 31, 2017. We record these credits in the period the legislation was enacted as a reduction of cost of products sold (exclusive of depreciation and amortization) resulting in an increase in adjusted gross margin. This adjustment reflects the effect on our adjusted EBITDA had these credits been recorded in the period in which the blending activity took place.
(6)
We incur expenses in connection with acquisitions and given the nature, variability of amounts, and the fact that these expenses would not have otherwise been incurred as part of our continuing operations, adjusted EBITDA excludes the impact of acquisition related expenses. 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated and Combined Financial Statements and notes to the Consolidated and Combined Financial Statements included elsewhere in this report, as well as the other financial information appearing elsewhere in this Annual Report.
A reference to a “Note” herein refers to the accompanying Notes to Consolidated and Combined Financial Statements contained in Part IV, Item 15 - “Exhibits and Financial Statement Schedules” of this Annual Report.
Overview
We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and to provide storage and handling services for a broad range of materials.
We are one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of refined products and materials handling terminals strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage capacity of 14.7 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. Furthermore, we have access to more than 40 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
We operate under four business segments: refined products, natural gas, materials handling and other operations.
In our refined products segment we purchase a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel, gasoline and asphalt (primarily from refining companies, trading organizations and producers), and sell them to our customers. We have wholesale customers who resell the refined products we sell to them and commercial customers who consume the refined products directly. Our wholesale customers consist of more than 1,200 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, hospitals, educational institutions, asphalt paving companies and customers engaged in the development of natural gas resources in Pennsylvania and surrounding states.
In our natural gas segment we purchase, sell and distribute natural gas to approximately 14,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. We purchase the natural gas from natural gas producers and trading companies.
Our materials handling segment is a fee-based business and is generally conducted under multi-year agreements. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, crude oil, clay slurry, salt, gypsum, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment.
Our other operations segment includes the marketing and distribution of coal conducted in our Portland, Maine terminal, commercial trucking activity conducted by our Canadian subsidiary and our heating equipment service business.
We take title to the products we sell in our refined products and natural gas segments. In order to manage our exposure to commodity price fluctuations, we use derivatives and forward contracts to maintain a position that is substantially balanced between product purchases and product sales. We do not take title to any of the products in our materials handling segment.

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Our foreign sales, primarily sales of refined products and natural gas to customers in Canada, were $290.4 million, $265.7 million and $196.4 million for the years ended December 31, 2018, 2017 and 2016, respectively. Long-lived assets (exclusive of intangible and other assets, net, and goodwill) classified by geographic location were as follows: 
 
As of December 31,
 
2018
 
2017
United States
$
277,405

 
$
273,374

Canada
72,441

 
76,685

Total
$
349,846

 
$
350,059

How Management Evaluates Our Results of Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) adjusted EBITDA and adjusted gross margin, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.
EBITDA, adjusted EBITDA and adjusted gross margin used in this Annual Report are non-GAAP financial measures. We also present maintenance capital expenditures and expansion capital expenditures, additional non-GAAP financial measures, as described in "Liquidity and Capital Resources - Capital Expenditures" of this Annual Report.
EBITDA and Adjusted EBITDA
Management believes that adjusted EBITDA is an aid in assessing repeatable operating performance that is not distorted by non-recurring items or market volatility and the ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our unitholders.
We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA adjusted for the change in unrealized hedging gains (losses) with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts, adjusted for changes in the fair value of contingent consideration, adjusted for the impact of acquisition related expenses, and adjusted for the impact of biofuel excise tax credits resulting from retroactive tax legislation changes that occurred in 2018.
EBITDA and adjusted EBITDA are used as supplemental financial measures by external users of our financial statements, such as investors, trade suppliers, research analysts and commercial banks to assess:
 
The financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;

The ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our equity holders;

Repeatable operating performance that is not distorted by non-recurring items or market volatility; and

The viability of acquisitions and capital expenditure projects.
EBITDA and adjusted EBITDA are not prepared in accordance with GAAP and should not be considered alternatives to net income (loss) or operating income, or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income (loss) and operating income (loss).
The GAAP measure most directly comparable to EBITDA and adjusted EBITDA is net income (loss). EBITDA and adjusted EBITDA should not be considered as alternatives to net income (loss) or cash provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and adjusted EBITDA are not presentations made in accordance with GAAP and have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Because EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income (loss) and are defined differently by different companies, our definitions of EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies.

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We recognize that the usefulness of EBITDA and adjusted EBITDA as evaluative tools may have certain limitations, including:
 
EBITDA and adjusted EBITDA do not include interest expense. Because we have borrowed money in order to finance our operations, interest expense is a necessary element of our costs and impacts our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations;
EBITDA and adjusted EBITDA do not include depreciation and amortization expense. Because capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits, any measure that excludes depreciation and amortization expense may have material limitations;
EBITDA and adjusted EBITDA do not include provision for income taxes. Because the payment of income taxes is a necessary element of our costs, any measure that excludes income tax expense may have material limitations;
EBITDA and adjusted EBITDA do not reflect capital expenditures or future requirements for capital expenditures or contractual commitments;
EBITDA and adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and
EBITDA and adjusted EBITDA do not allow us to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss.
Adjusted Gross Margin
Management trades, purchases, stores and sells energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes adjusted gross margin. In determining adjusted gross margin, management adjusts its segment results for the impact of unrealized gains and losses with regard to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income (loss). These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory, prepaid fixed forwards and the utilization of transportation contracts relating to those hedges is realized in net income (loss). Adjusted gross margin is also used by external users of our consolidated financial statements to assess our economic results of operations and its commodity market value reporting to lenders.
We define adjusted gross margin as net sales less cost of products sold (exclusive of depreciation and amortization) and decreased by total commodity derivative gains and losses included in net income (loss) and increased by realized commodity derivative gains and losses included in net income (loss), in each case with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts. Adjusted gross margin has no impact on reported volumes or net sales.
Adjusted gross margin is used as supplemental financial measures by management to describe our operations and economic performance to investors, trade suppliers, research analysts and commercial banks to assess:
 
The economic results of our operations;

The market value of our inventory and natural gas transportation contracts for financial reporting to our lenders, as well as for borrowing base purposes; and

Repeatable operating performance that is not distorted by non-recurring items or market volatility.
Adjusted gross margin is not prepared in accordance with GAAP and should not be considered as an alternative to net income (loss) or operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
We define adjusted unit gross margin as adjusted gross margin divided by units sold, as expressed in gallons for refined products, and in MMBtus for natural gas.
For a reconciliation of adjusted gross margin and adjusted EBITDA to the GAAP measures most directly comparable, see the reconciliation tables included in Results of Operations. See Segment Reporting included under Note 17 to our Consolidated Financial Statements for a presentation of our financial results by reportable segment.
Management evaluates our segment performance based on adjusted gross margin. Based on the way we manage our business, it is not reasonably possible for us to allocate the components of operating expenses, selling, general and administrative expenses and depreciation and amortization among the operating segments.

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Operating Expenses
Operating expenses are costs associated with the operation of the terminals and truck fleet used in our business. Employee wages, pension and 401(k) plan expenses, boiler fuel, repairs and maintenance, utilities, insurance, property taxes, services and lease payments comprise the most significant portions of our operating expenses. Employee wages and related employee expenses included in our operating expenses are incurred on our behalf by our General Partner and reimbursed by us. These expenses remain relatively stable independent of the volumes through our system but can fluctuate depending on the activities performed during a specific period.
Selling, General and Administrative Expenses
Selling, general and administrative expenses (“SG&A”) include employee salaries and benefits, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Employee wages, related employee expenses and certain rental costs included in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us.
Heating Degree Days
A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated over the course of a year and can be compared to a monthly or a long-term average (“normal”) to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and archived by the National Climatic Data Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2010. Commencing April 1, 2018, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same locations over the previous ten-year period. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day amounts in this document have been revised to conform to this presentation.
Hedging Activities
We hedge our inventory within the guidelines set in our risk management policies. In a rising commodity price environment, the market value of our inventory will generally be higher than the cost of our inventory. For GAAP purposes, we are required to value our inventory at the lower of cost or net realizable value. The hedges on this inventory will lose value as the value of the underlying commodity rises, creating hedging losses. Because we do not utilize hedge accounting, GAAP requires us to record those hedging losses in our statement of operations. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP requires us to record those hedging gains in our statement of operations.
The refined products inventory market valuation is calculated using daily independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are primarily based in large, liquid trading hubs including but not limited to, New York Harbor (NYH) or US Gulf Coast (USGC), with our inventory values determined after adjusting these prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to one of these supply sources. Our natural gas inventory is limited, with the valuation updated monthly based on the volume and prices at the corresponding inventory locations. The prices are based on the most applicable monthly Inside FERC, or IFERC, assessments published by Platts near the beginning of the following month.

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Similarly, we can hedge our natural gas transportation assets (i.e., pipeline capacity) within the guidelines set in our risk management policy. Although we do not own any natural gas pipelines, we secure the use of pipeline capacity to support our natural gas requirements by either leasing capacity over a pipeline for a defined time period or by being assigned capacity from a local distribution company for supplying our customers. As the spread between the price of gas between the origin and delivery point widens (assuming the value exceeds the fixed charge of the transportation), the market value of the natural gas transportation contracts assets will typically increase. If the market value of the transportation asset exceeds costs, we may seek to hedge or “lock in” the value of the transportation asset for future periods using available financial instruments. For GAAP purposes, the increase in value of the natural gas transportation assets is not recorded as income in the statement of operations until the transportation is utilized in the future (i.e., when natural gas is delivered to our customer). If the value of the natural gas transportation assets increase, the hedges on the natural gas transportation assets lose value, creating hedging losses in our statement of operations. The natural gas transportation assets market value is calculated daily based on the volume and prices at the corresponding pipeline locations. The daily prices are based on trader assessed quotes which represent observable transactions in the market place, with the end-month valuations primarily based on Platts prices where available or adding a location differential to the price assessment of a more liquid location.
As described above, pursuant to GAAP, we value our commodity derivative hedges at the end of each reporting period based on current commodity prices and record hedging gains or losses, as appropriate. Also as described above, and pursuant to GAAP, our refined products and natural gas inventory and natural gas transportation contract rights, to which the commodity derivative hedges relate, are not marked to market for the purpose of recording gains or losses. In measuring our operating performance, we rely on our GAAP financial results, but we also find it useful to adjusts our results for the impact of unrealized gains and losses with regard to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts. By making such adjustments, as reflected in adjusted gross margin and adjusted EBITDA, we believe that we are able to align more closely hedging gains and losses to the period in which the revenue from the sale of inventory and income from transportation contracts relating to those hedges is realized.
Trends and Factors that Impact our Business
This section identifies certain factors and industry-wide trends that may affect our financial performance and results of operations.
 
New, stricter environmental laws and regulations are increasing the compliance cost of terminal operations, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state, local and foreign laws and regulations regulating product quality specifications, emissions in the air, discharges to land and water, and the generation, handling, treatment, and disposal of hazardous waste and other materials. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Compliance with laws and regulations may increase our overall cost of business including our capital cost to maintain and upgrade equipment and facilities.
Seasonality and weather conditions. Our financial results are impacted by seasonality in our businesses and are generally better during the winter months, primarily because a material part of our business consists of supplying heating oil, residual fuel oil and natural gas for space heating purposes during the winter. For example, over the 36-month period ended December 31, 2018, we generated an average of 71% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States. In addition, weather conditions, particularly during these five months, have a significant impact on the demand for our products. Warmer-than-normal temperatures during these months in our areas of operations can decrease the total volume of heating oil, residual fuel oil and natural gas we sell and the adjusted gross margins realized on those sales, whereas colder-than-normal temperatures increase demand for those products and the associated adjusted gross margins.
Growth in exploration and production of shale gas has led to expanded use of natural gas in our marketing area and provided further downstream refined products sales opportunities to support the resource development activity. Supplies of natural gas from shale formations have grown both in the Northeastern region (e.g., Marcellus and Utica Shale) and the other parts of the United States. Further expansion of domestic natural gas supplies is expected. In conjunction with the production gains, natural gas usage in the Northeast United States has increased substantially with the growth trajectory expected to continue over the next few years. A possible outgrowth of this trend could be to reduce consumption of other fuels. However, significant refined products supply and supporting service requirements are expected to continue in support of the equipment used to develop this expanded production.

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Absolute price increase or decreases can impact demand and credit risk. Commodity prices in both our refined products and natural gas segments can vary sharply due to market conditions. As commodity product prices rise, we can experience reduced demand as customers engage in conservation efforts, are exposed to a higher level of credit risk to meet customer requirements, and incur increased working capital costs for holding inventory and accounts receivable. In a lower commodity price environment our customers are generally less prone to engage in conservation efforts, we experience lower credit risk, and working capital costs to hold inventory and finance accounts receivable.
The impact of the market structure on our hedging strategy. We typically hedge our exposure to commodity price moves with NYMEX futures contracts and "over the counter" or "OTC" swaps. In markets where futures prices are higher than spot prices (typically referred to as contango), we generate positive margins when rolling our inventory hedges to successive months. In markets where futures prices are lower than spot prices (typically referred to as backwardation), we realize losses when rolling our inventory hedges to successive months. In backwardated markets, we operate with lower inventory levels and, as a result, have reduced hedging and financing requirements, thereby limiting losses.
Energy efficiency, new technology and alternative fuels could reduce demand for our products. Increased conservation and technological advances have adversely affected the demand for heating oil and residual fuel oil. Consumption of residual fuel oil, in particular, has steadily declined in recent years, primarily due to customers converting from other fuels to natural gas, weak industrial demand and tightening of environmental regulations. Use of natural gas is expected to continue to displace other fuels, which we believe will favorably impact our natural gas volumes and margins.
Interest rates could continue to rise. Since mid-2018, the credit markets have been experiencing increasing interest rates as compared to the near-record lows in interest rates that existed since mid-2009. Further increases in interest rates could affect our ability to access the debt capital markets on favorable terms. In addition, interest rates could be higher than current levels, causing our financing costs to increase accordingly. During the 24 months ended December 31, 2018, we hedged approximately 43% of our floating-rate debt with fixed-for-floating interest rate swaps. Although higher interest rates could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related 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 common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.






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Table of Contents

Results of Operations

Overview
Our current and future results of operations may not be comparable to our historical results of operations. Our results of operations may be impacted by, among other things, swings in commodity prices, primarily in refined products and natural gas, and acquisitions or dispositions. We use economic hedges to minimize the impact of changing prices on refined products and natural gas inventory. As a result, commodity price increases at the end of a year can create lower gross margins as the economic hedges, or derivatives, for such inventory may lose value, whereas an increase in the value of such inventory is disregarded for GAAP financial reporting purposes and recorded at the lower of cost or net realizable value. Please read “How Management Evaluates Our Results of Operations.” For a description of acquisition activity during the periods presented, please read Part I, Item 1. "Business - 2017 Acquisitions.”
The following tables set forth information regarding our results of operations for the periods presented:
 
Years Ended December 31,
 
Increase/(Decrease)
 
2018
 
2017
 
$        
 
%
 
($ in thousands)
Net sales
$
3,771,133

 
$
2,854,996

 
$
916,137

 
32
 %
Cost of products sold (exclusive of depreciation and amortization)
3,445,385

 
2,602,788

 
842,597

 
32
 %
Operating expenses
88,659

 
72,284

 
16,375

 
23
 %
Selling, general and administrative
80,799

 
87,582

 
(6,783
)
 
(8
)%
Depreciation and amortization
33,378

 
28,125

 
5,253

 
19
 %
Total operating costs and expenses
3,648,221

 
2,790,779

 
857,442

 
31
 %
Operating income
122,912

 
64,217

 
58,695

 
91
 %
Other (expense) income
293

 
108

 
185

 
171
 %
Interest income
577

 
339

 
238

 
70
 %
Interest expense
(38,931
)
 
(31,345
)
 
(7,586
)
 
24
 %
Income before income taxes
$
84,851

 
$
33,319

 
$
51,532

 
155
 %
Income tax provision
(5,032
)
 
(3,822
)
 
(1,210
)
 
32
 %
Net income
$
79,819

 
$
29,497

 
$
50,322

 
171
 %
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
Increase/(Decrease)
 
2017
 
2016
 
$        
 
%
 
($ in thousands)
Net sales
$
2,854,996

 
$
2,389,998

 
$
464,998

 
19
 %
Cost of products sold (exclusive of depreciation and amortization)
2,602,788

 
2,179,089

 
423,699

 
19
 %
Operating expenses
72,284

 
65,882

 
6,402

 
10
 %
Selling, general and administrative
87,582

 
84,257

 
3,325

 
4
 %
Depreciation and amortization
28,125

 
21,237

 
6,888

 
32
 %
Total operating costs and expenses
2,790,779

 
2,350,465

 
440,314

 
19
 %
Operating income
64,217

 
39,533

 
24,684

 
62
 %
Other income (expense)
108

 
(114
)
 
222

 
(195
)%
Interest income
339

 
388

 
(49
)
 
(13
)%
Interest expense
(31,345
)
 
(27,533
)
 
(3,812
)
 
14
 %
Income before income taxes
$
33,319

 
$
12,274

 
$
21,045

 
171
 %
Income tax provision
(3,822
)
 
(2,108
)
 
(1,714
)
 
81
 %
Net income
$
29,497

 
$
10,166

 
$
19,331

 
190
 %


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Reconciliation to Adjusted Gross Margin, EBITDA and Adjusted EBITDA
The following table sets forth a reconciliation of our operating income to our total adjusted gross margin, a non-GAAP measure, and a reconciliation of our net income to EBITDA and Adjusted EBITDA, non-GAAP measures, for the periods presented. See above Management’s Discussion and Analysis of Financial Condition and Results of Operations-Non-GAAP Financial Measures and How Management Evaluates Our Results of Operations of this report. The table below also presents information on weather conditions for the periods presented.
 
Years Ended December 31,
 
2018
 
2017
 
2016
 
($ in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:
 
 
 
 
Operating income
$
122,912

 
$
64,217

 
$
39,533

Operating costs and expenses not allocated to operating segments:
 
 
 
 
Operating expenses
88,659

 
72,284

 
65,882

Selling, general and administrative
80,799

 
87,582

 
84,257

Depreciation and amortization
33,378

 
28,125

 
21,237

Add/(deduct):
 
 
 
 
 
  Change in unrealized gain on inventory (1)
(32,960
)
 
124

 
31,304

  Change in unrealized value on prepaid forward contracts (2)

 
(1,076
)
 
(1,552
)
  Change in unrealized value on natural gas transportation contracts(3)
(19,114
)
 
10,441

 
18,612

Total adjusted gross margin (4):
$
273,674

 
$
261,697

 
$
259,273

Adjusted Gross Margin by Segment:
 
 
 
 
 
Refined products
$
150,965

 
$
142,467

 
$
142,581

Natural gas
57,875

 
65,060

 
62,435

Materials handling
57,515

 
46,512

 
45,712

Other operations
7,319

 
7,658

 
8,545

Total adjusted gross margin
$
273,674

 
$
261,697

 
$
259,273

Reconciliation of Net Income to Adjusted EBITDA
 
 
 
 
 
Net income
$
79,819

 
$
29,497

 
$
10,166

Add:
 
 
 
 
 
Interest expense, net
38,354

 
31,006

 
27,145

Tax provision
5,032

 
3,822

 
2,108

Depreciation and amortization
33,378

 
28,125

 
21,237

EBITDA (4):
$
156,583

 
$
92,450

 
$
60,656

Add/(deduct):
 
 
 
 
 
  Change in unrealized gain on inventory (1)
(32,960
)
 
124

 
31,304

  Change in unrealized value on prepaid forward contracts (2)

 
(1,076
)
 
(1,552
)
  Change in unrealized value on natural gas transportation contracts(3)
(19,114
)
 
10,441

 
18,612

  Biofuel tax credit (5)
(4,022
)
 
4,022

 

  Acquisition related expenses (6)
747

 
3,038

 
1,177

    Other adjustments (7)
771

 
231

 

Adjusted EBITDA (5)
$
102,005

 
$
109,230

 
$
110,197

Other Data:
 
 
 
 
 
Ten Year Average Heating Degree Days (8)
4,907

 
4,944

 
4,923

Heating Degree Days (8)
5,020

 
4,807

 
4,717

Variance from average heating degree days
2
%
 
(3
)%
 
(4
)%
Variance from prior period heating degree days
4
%
 
2
 %
 
(7
)%

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Table of Contents

(1)
Inventory is valued at the lower of cost or net realizable value. The adjustment related to unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values.The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income (loss).
(2)
Represents our estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income (loss) until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income (loss). The fair value of the derivatives we use to economically hedge our prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines in value.
(3)
Represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized gains (losses).
(4)
For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “How Management Evaluates Our Results of Operations.”
(5)
On February 9, 2018, the U.S. federal government enacted legislation that reinstated an excise tax credit program available for certain of our biofuel blending activities. The program had expired on December 31, 2016 and was reinstated retroactively to January 1, 2017. During the year ended December 31, 2018, we recorded excise tax credits of approximately $4.0 million that relate to blending activities that occurred during the year ended December 31, 2017. We record the credit in the period the legislation was enacted as a reduction of cost of products sold (exclusive of depreciation and amortization) resulting in an increase in adjusted gross margin. This adjustment reflects the effect on our adjusted EBITDA had these credits been recorded in the period in which the blending activity took place.
(6)
We incur expenses in connection with acquisitions and given the nature, variability of amounts, and the fact that these expenses would not have otherwise been incurred as part of our continuing operations, adjusted EBITDA excludes the impact of acquisition related expenses. 
(7)
Represents the change in the fair value of contingent consideration related to the 2017 Coen Energy acquisition and other expense.
(8)
We use heating degree day amounts as reported by the NOAA Regional Climate Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2010. Commencing April 1, 2018, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same locations over the previous ten-year period. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day amounts in this document have been revised to conform to this presentation.

Analysis of Consolidated Operating Results
For the years ended December 31, 2018 our operating income increased $58.7 million, or 91%, to $122.9 million, as compared to $64.2 million for the year ended December 31, 2017. For the years ended December 31, 2018 and 2017, our operating income includes unrealized commodity derivative gains and (losses) with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts of $52.1 million and $(9.5) million, respectively, which favorably impacted operating income for the year ended December 31, 2018 by $61.6 million. Operating income for the year ended December 31, 2018 was also impacted by higher operating costs and depreciation and amortization as a result of five business acquisitions completed in 2017, which were partially offset by lower SG&A expenses, primarily due to lower incentive related employee costs.
For the years ended December 31, 2017 our operating income increased $24.7 million, or 62%, to $64.2 million, as compared to $39.5 million for the year ended December 31, 2016. For the years ended December 31, 2017 and 2016 our operating income included unrealized commodity derivative gains and (losses) with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts of $(9.5) million and $(48.4) million, respectively, which favorably impacted operating income for the year ended December 21, 2017 by $38.9 million. Operating income for the year ended December 31, 2017 was also impacted by higher operating costs, SG&A expenses and depreciation and amortization, all primarily as a result of five business acquisitions completed in 2017.
See Analysis of Operating Segments and Liquidity and Capital Resources below for additional details on changes in our operating results.

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Analysis of Operating Segments

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
 
Years Ended December 31,
 
Increase/(Decrease)
 
2018
 
2017
 
$        
 
%
 
($ and volumes in thousands, except adjusted unit gross margin)
Volumes:
 
 
 
 
 
 
 
Refined products (gallons)
1,580,838

 
1,416,240

 
164,598

 
12
 %
Natural gas (MMBtus)
60,385

 
61,883

 
(1,498
)
 
(2
)%
Materials handling (short tons)
2,627

 
2,366

 
261

 
11
 %
Materials handling (gallons)
488,972

 
385,896

 
103,076

 
27
 %
Net Sales:
 
 
 
 
 
 
 
Refined products
$
3,357,769

 
$
2,455,577

 
$
902,192

 
37
 %
Natural gas
332,038

 
331,669

 
369

 
 %
Materials handling
57,509

 
46,513

 
10,996

 
24
 %
Other operations
23,817

 
21,237

 
2,580

 
12
 %
Total net sales
$
3,771,133

 
$
2,854,996

 
$
916,137

 
32
 %
Adjusted Gross Margin:
 
 
 
 
 
 
 
Refined products
$
150,965

 
$
142,467

 
$
8,498

 
6
 %
Natural gas
57,875

 
65,060

 
(7,185
)
 
(11
)%
Materials handling
57,515

 
46,512

 
11,003

 
24
 %
Other operations
7,319

 
7,658

 
(339
)
 
(4
)%
Total adjusted gross margin
$
273,674

 
$
261,697

 
$
11,977

 
5
 %
Adjusted Unit Gross Margin:
 
 
 
 
 
 
 
Refined products
$
0.095

 
$
0.101

 
$
(0.006
)
 
(6
)%
Natural gas
$
0.958

 
$
1.051

 
$
(0.093
)
 
(9
)%

Refined Products
Refined products net sales increased $0.9 billion, or 37%, due to a combination of a 23% increase in the average sales price and a 12% gain in product volume.
Refined products adjusted gross margin increased $8.5 million due to the higher volumes. The volume increase was a result of higher discretionary sales, as well as the impact of a full year of acquisitions, in particular the Coen Energy transaction completed in October 2017. Other significant factors included the transition of Kildair's asphalt marketing to material handling and the retroactive reinstatement of the biofuel excise tax credit which largely offset each other. The majority of the volume gain occurred in the first quarter of the year, with a period of severe weather conditions early in the quarter leading to competitor supply outages in some key markets. The volume gains were principally in distillates, with higher heavy oil volumes also a contributor.
Adjusted unit margins declined by 6%, due primarily to a combination of less attractive market conditions to purchase and store inventory along with fewer blending opportunities.
Natural Gas
Natural gas net sales were consistent with the same period last year, with the higher average price offsetting the 2% decline in volume. The volume reduction was primarily due to the loss of certain higher volume, lower adjusted unit gross margin accounts.
Natural gas adjusted gross margin decreased $7.2 million, or 11%, principally due to a 9% decline in average adjusted unit gross margin. The lower unit margin resulted from a combination of fewer optimization opportunities for pipeline capacity particularly in the fourth quarter of 2018, and increased competitive intensity in some key markets.

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Table of Contents

Materials Handling
Materials handling net sales and adjusted gross margin both increased approximately $11.0 million, or 24%, compared to the same period last year. The primary factor was increased asphalt handling revenues from new agreements at the Kildair facility and two other U.S. terminals.  Materials handling adjusted gross margin also benefited from additional revenue at Kildair due to expanded HFO/VGO tank rental revenue and in the U.S. to increased salt handling and heavy lift activity.
Other Operations
Net sales from other operations increased by $2.6 million, or 12%, with adjusted gross margin $0.3 million, or 4% lower. The decline in adjusted gross margin was a combination of a volume reduction in coal due to decreased customer requirements as well as lower trucking activity at Kildair and fuel burner service.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
 
Years Ended December 31,
 
Increase/(Decrease)
 
2017
 
2016
 
$        
 
%
 
($ and volumes in thousands, except adjusted unit gross margin)
Volumes:
 
 
 
 
 
 
 
Refined products (gallons)
1,416,240

 
1,396,080

 
20,160

 
1
 %
Natural gas (MMBtus)
61,883

 
61,732

 
151

 
 %
Materials handling (short tons)
2,366

 
2,523

 
(157
)
 
(6
)%
Materials handling (gallons)
385,896

 
276,402

 
109,494

 
40
 %
Net Sales:
 
 
 
 
 
 
 
Refined products
$
2,455,577

 
$
1,988,597

 
$
466,980

 
23
 %
Natural gas
331,669

 
334,003

 
(2,334
)
 
(1
)%
Materials handling
46,513

 
45,734

 
779

 
2
 %
Other operations
21,237

 
21,664

 
(427
)
 
(2
)%
Total net sales
$
2,854,996

 
$
2,389,998

 
$
464,998

 
19
 %
Adjusted Gross Margin:
 
 
 
 
 
 
 
Refined products
$
142,467

 
$
142,581

 
$
(114
)
 
 %
Natural gas
65,060

 
62,435

 
2,625

 
4
 %
Materials handling
46,512

 
45,712

 
800

 
2
 %
Other operations
7,658

 
8,545

 
(887
)
 
(10
)%
Total adjusted gross margin
$
261,697

 
$
259,273

 
$
2,424

 
1
 %
Adjusted Unit Gross Margin:
 
 
 
 
 
 
 
Refined products
$
0.101

 
$
0.102

 
$
(0.001
)
 
(1
)%
Natural gas
$
1.051

 
$
1.011

 
$
0.040

 
4
 %

Refined Products
Refined products net sales increased $0.5 billion, or 23%, principally due to a 22% increase in the average sales price in the higher oil price environment. The 1% gain in product volume was a minor contributor to the higher sales.
Refined products adjusted gross margin decreased $0.1 million due to the lower adjusted unit gross margin. The volume increase was a result of acquisitions during the year, in particular L.E. Belcher and Coen Energy. The acquisition-led volume gains more than offset other reductions resulting from lower activity in the early part of the year with the milder winter weather.
The volume gains were due to growth in distillates, with lower gasoline and to a lesser extent heavy oil volumes offsetting part of this increase. The lower gasoline volume was primarily a result of the highly competitive market for discretionary volumes along with the loss of a municipal bid contract. The reduction in heavy oil volume was primarily the result of decreased weather-driven demand during the mild winter weather in the first quarter of the year.
Overall unit margins were consistent with 2016 results despite the high competitive pressure in the early part of the year with the milder weather conditions.

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Table of Contents

Natural Gas
Natural gas net sales decreased $2.3 million, due to a 1% decrease in average unit sales price. The lower sales price was partially offset by a modest gain in volume, with the impact of the Global Natural Gas & Power acquisition completed at the beginning of February more than compensating for the volume decline in the rest of the business. This volume reduction was primarily due to the loss of certain higher volume, lower adjusted unit gross margin accounts.
Natural gas adjusted gross margin increased $2.6 million, or 4%, due to a 4% gain in adjusted unit gross margin. The higher unit margins resulted primarily from improved margin opportunities on customer sales partially offset by fewer pipeline capacity optimization opportunities.
Materials Handling
Materials handling net sales and adjusted gross margin both increased $0.8 million, or 2%, compared to last year. The gain was principally the result of a $3.0 million increase in asphalt revenue primarily due to new agreements at two terminals. Other increases included higher bulk handling (principally salt) and, to a lesser degree, increased activity at Kildair. These gains more than offset the $2.7 million decline in wind energy component handling driven by uncertainty regarding the level of government support of the renewable fuels production tax credit.
Other Operations
Net sales from other operations declined by $0.4 million, or 2%, with adjusted gross margin $0.9 million lower, a 10% decline. The decline in adjusted gross margin was a combination of volume reductions in coal due to decreased customer requirements and to a lesser extent trucking activity at Kildair and fuel burner service.

Operating Costs and Expenses
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
 
Years Ended December 31,
 
Increase/(Decrease)
 
2018
 
2017
 
$    
 
%    
 
($ in thousands)
 
 
Operating expenses
$
88,659

 
$
72,284

 
$
16,375

 
23
 %
Selling, general and administrative expenses
$
80,799

 
$
87,582

 
$
(6,783
)
 
(8
)%
Depreciation and amortization
$
33,378

 
$
28,125

 
$
5,253