Sprague Resources LP - Annual Report: 2014 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

For the Fiscal Year Ended December 31, 2014

or

For the transition period from                      to                     

Commission File Number: 001-36137

Sprague Resources LP

(Exact name of registrant as specified in its charter)

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:

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 and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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 $216,050,924 as of June 30, 2014 (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 10,995,377 common units and 10,071,970 subordinated units outstanding as of March 9, 2015.

Documents Incorporated by Reference: None

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SPRAGUE RESOURCES LP

ANNUAL REPORT ON FORM 10-K

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PART I

As used in this Annual Report on Form 10-K (“Annual Report”), unless the context otherwise requires, references to “Sprague Resources,” the “Partnership,” “we,” “our,” “us,” or like terms, when used in a historical context prior to October 30, 2013, the date on which we completed an initial public offering of common units representing limited partner interests in Sprague Resources LP, refer to Sprague Operating Resources LLC, our “Predecessor” for accounting purposes and the successor to Sprague Energy Corp., also referenced as “our Predecessor” or “the Predecessor” and when used in the present tense or prospectively, refer to Sprague Resources LP and its subsidiaries. Unless the context otherwise requires, references to “Axel Johnson” or the “Parent” refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its general partner. References to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of our general partner. References to our “general partner” refer to Sprague Resources GP LLC.

Our Partnership

We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our general partner to engage in the storage, distribution and sale of refined petroleum, what we refer to as refined products, and natural gas, and we also provide storage and handling services for a broad range of materials.

In October 2013, we completed an initial public offering of common units representing limited partner interests in the Partnership (the “IPO”). Our common units now trade on the New York Stock Exchange (the “NYSE”).

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 19 refined products and materials handling terminals strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage capacity of approximately 14.1 million barrels for refined products and other liquid materials, as well as approximately 1.5 million square feet of materials handling capacity. We also have an aggregate of approximately 2.3 million barrels of additional storage capacity attributable to 47 storage tanks not currently in service. These tanks are not necessary for the operation of our business at current levels. In the event that such additional capacity were desired, additional time and capital would be required to bring any of such storage tanks into service. Furthermore, we have access to approximately 60 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.

Our principal executive offices are located at 185 International Drive, Portsmouth, New Hampshire 03801. Our telephone number is (800) 225-1560. Our internet address is http://www.spragueenergy.com. We make available through our website 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, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission, or the SEC. The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

We operate under four business segments: refined products, natural gas, materials handling and other operations. Our refined products segment purchases a variety of refined products, such as heating oil, diesel, residual fuel oil, kerosene, jet fuel, gasoline and asphalt (primarily from refining companies, trading organizations and producers), and sells 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 we sell to them. Our wholesale customers consist of more than 1,100 home heating oil retailers and diesel fuel and gasoline

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resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, hospitals, educational institutions and asphalt paving companies. For the years ended December 31, 2014, 2013 and 2012, we sold approximately 1.7 billion, 1.5 billion and 1.3 billion gallons of refined products, respectively. For the years ended December 31, 2014, 2013 and 2012, our refined products segment accounted for 60%, 61% and 56% of our adjusted gross margin, respectively. See “Segment Reporting” included under Note 17 to our Consolidated and Combined Financial Statements for a presentation of financial results by reportable segment and see “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.

Our natural gas segment purchases, sells and distributes natural gas to more than 15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. We purchase the natural gas we sell from natural gas producers and trading companies. For the years ended December 31, 2014, 2013 and 2012, we sold 54.4 Bcf, 52.0 Bcf and 49.4 Bcf of natural gas, respectively. For the years ended December 31, 2014, 2013 and 2012, our natural gas segment accounted for 23%, 21% and 19% of our adjusted gross margin, respectively.

Our materials handling business 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. For the year ended December 31, 2014, we offloaded, stored and/or prepared for delivery, 2.7 million short tons of product and 309.8 million gallons of liquid materials. For the years ended December 31, 2013 and 2012 we offloaded, stored and/or prepared for delivery 2.1 million and 2.6 million short tons of products, and 246.7 million and 248.5 million gallons of liquid materials, respectively. For the years ended December 31, 2014, 2013 and 2012, our materials handling segment accounted for 15%, 15% and 23% of our adjusted gross margin, respectively.

Our other operations consist primarily of coal marketing and distribution and commercial trucking, and for the years ended December 31, 2014, 2013 and 2012, such activities accounted for 2%, 3% and 2% of our adjusted gross margin, respectively.

We take title to the products we sell in our refined products and natural gas segments. We do not take title to any of the products in our materials handling segment. 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.

Acquisitions

In December 2014, we completed the acquisition of all of the equity interests in Kildair Service Ltd. (“Kildair”) through the acquisition of the equity interests of Kildair’s parent, Sprague Canadian Properties LLC, for total consideration of $175.0 million, which included $10.0 million in unregistered common units of Sprague Resources LP. Kildair owns a terminal in Sorel-Tracy, Quebec, on the St. Lawrence River where it maintains 3.3 million barrels of residual fuel, asphalt, and crude oil storage. Kildair’s primary businesses include marketing of residual fuel both locally and for export, marketing of asphalt including polymer modified grades, and crude-by-rail handling services. Kildair’s terminal has blending infrastructure allowing the ability to process a wide range of varying quality blend components. The facility also includes an asphalt and residual fuel oil testing laboratory, 25 truck and railcar loading and offloading racks, 120 railcars of offload capacity, including 60 in the new crude oil rail offloading section, and a dock with the capability to load or receive ships with up to 450,000 barrels of capacity.

Our Predecessor owned a 50% equity interest in Kildair during the period from October 2007 through October 1, 2012 and had completed the purchase of the remaining 50% equity interest on October 1, 2012.

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Kildair was not included in the Partnership’s Consolidated and Combined Financial Statements effective October 30, 2013, the IPO date, at which time Kildair was distributed to an affiliate of the Parent. As the acquisition of Kildair by the Partnership represents a transfer of entities under common control, the Consolidated and Combined Financial Statements and related information presented herein have been recast to include the historical results of Kildair for all periods presented when Kildair was controlled by Axel Johnson.

In December 2014, we acquired substantially all of the assets of Castle Oil (“Castle”), including Castle’s Bronx terminal and its associated wholesale, commercial and retail fuel distribution business for $45.3 million in cash, an obligation to pay $5.0 million over a three year period (net present value of $4.6 million) and approximately $5.3 million in unregistered common units, plus payments for inventory and other current assets of approximately $37.0 million. Castle’s Bronx terminal is a large deepwater petroleum products terminal located in New York City, with a total storage capacity of 907,000 barrels, handling distillates, residual fuel, asphalt and biodiesel.

On October 1, 2014, the Partnership purchased Metromedia Gas & Power Inc.’s (“Metromedia Energy”) natural gas marketing and electricity brokerage business for $22.0 million, not including the purchase of natural gas inventory, utility security deposits, and other adjustments. Total consideration at closing was $32.8 million. Metromedia Energy markets natural gas and brokers electricity to commercial, industrial and municipal consumers in the Northeast and Mid-Atlantic United States. The acquisition was accounted for as a business combination and was financed with borrowings under the Partnership’s credit facility.

In July, 2013, our Predecessor purchased an oil terminal in Bridgeport, Connecticut for $20.7 million. This deep water facility includes 13 storage tanks with 1.3 million barrels of storage capacity for gasoline and distillate products with 11 storage tanks and 1.1 million barrels currently in service. The terminal provides throughput services to third-parties for branded gasoline sales in the Connecticut market.

Business Strategies

Our plan is to generate cash flows sufficient to enable us to maintain the current levels of quarterly distribution on each unit and to increase distributable cash flow per unit by executing the following strategies:

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Refined Products

Overview

The products we sell in our refined products segment can be grouped into three categories: distillates, gasoline, residual fuel oil and asphalt. Of our total volume sold in our refined products segment in 2014, distillates accounted for approximately 67%, gasoline accounted for approximately 14% and residual fuel oil and asphalt accounted for approximately 19%.

Distillates. We sell four kinds of distillates: heating oil (both unbranded and HeatForce^®, our proprietary premium heating oil product), diesel fuel (both unbranded and RoadForce ^®, our proprietary premium diesel fuel), kerosene and jet fuel. In 2014, heating oil accounted for approximately 58%, diesel fuel accounted for approximately 39%, and other distillates accounted for approximately 3% of the total volume of distillates we sold. Distillate volumes accounted for 67%, 64%, and 70% of our total refined products sales for the years ended December 31, 2014, 2013 and 2012, respectively.

We have the capability at several of our facilities to blend biodiesel with distillates in order to sell bio heating oil and biodiesel. In 2014, biofuel accounted for approximately 6% of the distillate fuel volumes we sold.

Gasoline. We sell unbranded gasoline in qualities that comply with seasonal and geographical requirements. Gasoline volumes accounted for 14%, 15% and 24% of our total refined products sales for the years ended December 31, 2014, 2013 and 2012, respectively.

Residual Fuel Oil and Asphalt. We sell various sulfur grades of residual fuel oil, blended to meet customer requirements, in our market areas. Residual fuel oil and asphalt volumes accounted for approximately 19%, 21% and 6% of our total refined products sales for the years ended December 31, 2014, 2013 and 2012, respectively.

In 2014, our refined products segment accounted for approximately 92% of our total net sales and 60% of our adjusted gross margin, as defined on page 46.

Customers, Contracts and Pricing

We sell heating oil, diesel fuel, kerosene, unbranded gasoline, jet fuel, residual fuel oil and asphalt 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 with which we have storage and throughput arrangements, which means the price of products sold includes the cost of delivering such product to that location and any further shipping expenses are borne by the purchaser.

In 2014, we sold heating oil, including HeatForce^®, to approximately 1,000 wholesale distributors and retailers. These sales are made through Sprague RealTime^® pricing platform, and under rack agreements based upon our posted price, contracts with index-based pricing provisions and fixed price forward contracts.

In 2014, we sold diesel fuel, including RoadForce^® premium diesel fuel, to approximately 640 wholesalers and transportation fuel distributors.

In 2014, we sold unbranded gasoline at 22 third-party locations primarily to resellers.

We sell residual fuel oil to approximately 1,900 commercial and industrial accounts. Sales were made under rack agreements and contracts with index-based pricing provisions.

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We also sell heating oil, diesel fuel, unbranded gasoline and residual fuel oil to public sector entities through competitive bidding processes as well as distillate and residual fuel oil by truck and barge to marine customers.

Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management 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 on our behalf.

Our sales contracts to commercial customers generally are for terms of one to five years. 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, 2014, no customer represented more than 10% of net sales for our refined products segment.

Natural Gas

Overview

We sell natural gas and related delivery services to customers primarily located in the Northeast and Mid-Atlantic United States. 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 trading as well as financial and derivative trading both over the counter and through exchanges such as the Intercontinental Exchange Inc. (“ICE”) and NYMEX, in order to manage our natural gas commodity price risk.

In order to manage our supply commitments to our customers and provide operational flexibility and arbitrage opportunities, we enter into supply contracts, leases 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.

For the year ended December 31, 2014, our natural gas segment accounted for approximately 7% of our total net sales, and 23% of our adjusted gross margin as defined on page 46.

Customers

Our natural gas customers operate in the industrial and commercial sectors in the Northeast United States, with the highest concentration in New England and New York. We acquired HESCO in 2006 and Metromedia Energy Inc. in 2014 as part of our strategy to target smaller to mid-size commercial and industrial customers as a key growth area. This strategy has led to a significant increase in the number of customers served and adjusted unit gross margin, with sales volumes remaining relatively stable. 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 stores). 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, 2014, 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,

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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 generally avoid transactions that require a single price for all volumes delivered, with the pricing of the non-contractual volumes based on prevailing market economics.

Materials Handling

Overview

Materials handling is 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 heavy lift services and provide other handling services to many of the same customers that we supply with refined products.

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. In all cases, we play the role of a distribution agent for our customers. Because the products we handle are generally owned by our customers, we have virtually no working capital requirements, commercial risk or inventory risk. Our materials handling contracts are typically long-term and predominately fee-based.

For the year ended December 31, 2014, our materials handling segment accounted for approximately 1% of our total net sales and 15% of our adjusted gross margin.

Major Types of Materials Handling and Services

The type of materials handling and services we provide can be divided into three major categories:

Liquid. Liquid products are moved to terminals via various types of ocean going vessels and offloaded into terminal tanks via pipelines on the dock of the facility. 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 transporting product to its final destination. In some cases the products need to remain heated in storage to be able to flow at ambient temperatures. Kildair’s operations include a materials handling contract involving transloading and storage of crude oil.

Bulk. Bulk materials are normally some type of aggregate materials moved in large vessels configured with multiple holds that store products on ships in piles with no other type of packaging. Examples of bulk material include salt, petroleum coke, gypsum, cement and coal. These vessels are normally offloaded via cranes that either reside 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.

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Customers

Our materials handling operations can service multiple customer types during any single operation, including: the ocean shippers, multiple logistics firms, trucking firms and the materials supplier or consumer. The materials we handle normally fall into two 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 hardwood, wood pulp for paper manufacture in Asia or Europe and tallow for biodiesel production in Europe.

For the year ended December 31, 2014, we had one customer who represented 12% of net sales for our materials handling segment, although no customer represented more than 1% of our total net sales.

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 (wood pulp) 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, 2014, the weighted-average life of our materials handling contracts was approximately eight years, with a weighted-average remaining life of approximately five years, each based on adjusted gross margin as defined on page 46, 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 will pay for more generic handling systems such as storage pads.

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. Those rates are subject to change depending on market conditions.

Other Operations

Our other operations segment includes the marketing and distribution of coal that is conducted in our South Portland and Portland, Maine terminals and commercial trucking activity in Kildair’s operations. For the year ended December 31, 2014, our other operations segment accounted for less than 1% of our total net sales and 2% of our adjusted gross margin.

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 unfavorable 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 then close out the related hedge as we sell the product for physical delivery to third parties. Products are

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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 policy 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 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 purchase and forward fixed price sales of refined products. Any hedge ineffectiveness is 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 as the derivatives 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 (meaning that these swaps do not include a delivery option).

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 significant trade credit to limit counterparty risk and margin requirements.

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.

Storage and Distribution Services

Marine terminals and inland storage facilities play a key role in the distribution of product to our customers. We own, operate and/or control a network of 19 refined products and materials handling terminals strategically located throughout the Northeast United States and Quebec, Canada that have a combined storage capacity of approximately 14.1 million barrels for refined products and other liquid materials, as well as approximately 1.5 million square feet of materials handling capacity. We also have an aggregate of approximately 2.3 million barrels of additional storage capacity attributable to 47 storage tanks not currently in service. These tanks are not necessary for the operation of our business at current levels. In the event that such additional capacity were

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desired, additional time and capital would be required to bring any of such storage tanks into service. Furthermore, we have access to approximately 60 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.

The marine terminals and inland storage facilities from which we distribute product are supplied by ship, barge, truck, pipeline or rail. The inland storage facilities, which we use exclusively to store distillates, are supplied with product delivered by truck from marine and other bulk terminals. 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 identification of customers. In addition, some of the marine and inland terminals at which we market 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 product at terminals owned by others. These arrangements permit our customers to load product at third-party terminals while we pay the owners of these terminals fees for services rendered in connection with the receipt, storage and handling of such product. Payments we make to the terminal owners may be fixed or 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. Other differentials that may occur in exchanges (and result in additional payments) include product value differentials.

Our Terminals

We own, operate, and/or control a network of 19 refined products and material handling terminals located along the coast of the Northeast United States from New York to Maine and Quebec, Canada. 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 majority of facilities additionally have demonstrated flexibility in their ability to handle liquid, dry bulk and break bulk products at the same terminal and in most cases across the same dock. This capability has offered us valuable flexibility to fully utilize each asset to meet a variety of fuel demands and third-party cargo handling demands as customer requirements have changed over the years.

We operate or control ten terminals that are capable of handling both liquid petroleum products and providing third-party materials handling services. Five terminals exclusively handle liquid petroleum products and four terminals are dedicated exclusively to materials handling services. Total liquid storage capacity throughout our owned and/or operated terminals is approximately 14.1 million barrels (which excludes approximately 2.3 million barrels of storage capacity not currently in service). Inside warehouse capacity at our owned and/or operated terminals totals approximately 316,000 square feet with approximately 1.2 million square feet of outside laydown space available.

For a more detailed description of our terminals, please read “Item 2. Properties.”

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Competition

We encounter varying degrees of competition based on product type and geographic location in the marketing of our refined products. 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 provide us with a competitive advantage in marketing refined products in the areas in which we operate.

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 sizeable market presence and strong customer service and offerings provide us with a competitive advantage 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 better than for the second and third calendar quarters. For example, over the 36-month period ended December 31, 2014, we generated an average of approximately 71% of our total heating oil and residual fuel oil net sales during the months of November through March.

Employees

Our general partner employs over 580 full-time employees who support our operations and also employs some “part-time” hourly workers who are on call during peak periods. Approximately 46 of the full-time employees are covered by collective bargaining agreements and we are in negotiations with two unions at the Bronx, NY terminal as part of the Castle acquisition for contracts to cover another 21 employees. Our subsidiary Kildair has approximately 100 employees, 36 of which are covered by collective bargaining agreements.

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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 pay 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 approximately $8.6 million per quarter, or approximately $34.5 million per year, based on the number of common and subordinated 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, which will fluctuate from quarter to quarter based on, among other things:

In addition, the actual amount of distributable cash flow that we distribute will depend on other factors such as:

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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 our 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 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 our 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, 2014, we generated an average of approximately 71% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States. 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 our unitholders. Any restrictions on our ability to borrow money could restrict our ability to make quarterly distributions to our 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 our 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 our net sales and, therefore, adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders. Factors that could lead to a decrease in market demand for refined products or natural gas include:

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;

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 our volumes stored, distributed and sold. As a result, we may experience declines in our operating margin if our volumes decrease.

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Our business, financial condition, results of operations and ability to make quarterly distributions to our 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 our 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 our primary source of financing 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 may be increased as they and/or their customers may attempt to not honor 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 our unitholders as well as the value of our common units.

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

Furthermore, our credit agreement contains covenants requiring us to maintain certain financial ratios. The provisions of our credit agreement may affect our ability to obtain future financing for and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our credit 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

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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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

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 service our debt will depend upon, among other things, our 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 our operating results are not sufficient to maintain our indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our 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 operations in Canada in the Canadian dollar, 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 our unitholders.

Weather conditions during winter have an impact on the demand for both 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 our unitholders.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes U.S. federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodities Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

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In October 2010, pursuant to its rulemaking under the Act, the CFTC issued rules to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception to the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, the Act requires that regulators establish margin rules for uncleared swaps. Rules that require end-users to post initial or variation margin could impact our liquidity and reduce cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules for uncleared swaps are not yet final and their impact on us is not yet clear.

The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivative contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have material adverse effect on our financial condition, results of operations and cash available for distributions to our unitholders.

In addition, other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

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 our 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 our 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

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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 heating oil contracts to hedge diesel fuel. 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 our 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.

We are exposed to risks of loss in the event of nonperformance by our customers, suppliers and counterparties.

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 our unitholders.

Additionally, 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.

We are exposed to performance risk in our supply chain.

We rely upon our suppliers to timely produce the volumes and types of refined products for which they contract with us. In the event one or more of our suppliers does not perform in accordance with its contractual obligations, we may be required to purchase product on the open market to satisfy forward contracts we have entered into with our customers in reliance upon such supply arrangements. We purchase refined products from a variety of suppliers under term contracts and on the spot market. In times of extreme market demand, we may be unable to satisfy our supply requirements. Furthermore, a portion of our supply comes from other countries, which could be disrupted by political events. In the event such supply becomes scarce, whether as a result of political events, natural disaster, logistical issues associated with delivery schedules or otherwise, we may not be able 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 our unitholders.

Some of our competitors have capital resources many times greater than ours and control greater supplies of refined products and natural gas. Competitors able to supply our customers with those products and services at a lower price could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our 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

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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 our unitholders could be adversely affected. We may not be able to compete successfully with these companies.

Some of our heating oil and residual fuel oil volumes are subject to customers switching or converting to natural gas, which could result in loss of customers and, in turn, could have an adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.

Our heating oil and residual fuel oil businesses compete for customers with suppliers of natural gas. During a period of increasing heating oil prices relative to natural gas prices, heating oil users may convert to natural gas. Similarly, during a period of increasing residual fuel oil prices relative to natural gas prices, customers who have the ability to switch from residual fuel oil to natural gas (dual-fuel customers), may switch and other end users may convert to natural gas.

Such switching and conversions could reduce our sales of heating oil and residual fuel oil and could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.

Energy efficiency, new technology and alternative energy sources could reduce demand for our products and adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.

Increased conservation, technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, fuel efficient motor vehicles and the availability of alternative energy sources have adversely affected the demand for some of our products, particularly home heating oil and residual fuel oil. Future conservation measures, technological advances in heating, conservation, energy generation or other devices, and increased availability and use of alternative energy sources, including as a result of government regulation, might reduce demand and adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.

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 our 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 our data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite our security measures, our 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 our operations and the services we provide to customers, and damage our reputation, cause a loss of confidence in our products and services, which could adversely affect our 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 acquisitions that result in an increase in the cash generated per unit from operations. If we are unable to make accretive acquisitions, either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (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:

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 our unitholders could be adversely affected.

Most of our contracts with our refined products customers are for a single season or on a spot basis, while most of our contracts with our 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 our 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 our 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.

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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 or weather and decreases in demand for refined products, could have a significantly greater impact on our results of operations and distributable cash flow than if we operated in more diverse locations.

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:

If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations.

We 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 have increased over the past four years and could 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 our 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.

The risk of substantial environmental costs and liabilities is inherent in terminalling and materials handling operations, and 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 product quality specifications and other environmental matters including the discharge of materials into the environment, or otherwise relating to the protection of the environment, operational safety and related matters. 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. 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 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. Moreover, the failure to comply with these requirements can expose our operations to fines, penalties, permit revocation and injunctive relief, including limits or prohibitions on some or all of our operations.

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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 is 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 our unitholders.

Increased regulation of greenhouse gas emissions 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 our unitholders.

Combustion of fossil fuels, such as the refined products we sell, results in the emission of carbon dioxide into the atmosphere. On December 15, 2009, the Environmental Protection Agency, or the EPA, published its findings that emissions of carbon dioxide and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes, and the EPA has begun to regulate greenhouse gases, or GHG, emissions pursuant to the Clean Air Act. Many states and regions have adopted GHG initiatives and it is possible that U.S. federal legislation could be adopted in the future to restrict GHG emissions.

There are many regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA. Future international, federal and state initiatives to control carbon dioxide emissions could result in increased costs associated with refined products consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such 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.

Per the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances, CQLR c Q-2, r.46.1, as of January 1, 2015, any person or municipality that distributes in Québec fossil fuels whose combustion meets or exceeds the established annual greenhouse gas (“GHG”) emission threshold is covered by the cap-and-trade (“C&T”) system. Emitters regulated by the C&T system are required to cover their GHG emissions until at least 2020 or until December 31 following their third consecutive GHG emission report that falls below the requisite emission threshold.

Kildair, as a distributor of fuels and combustibles covered by the C&T system, as of January 1st, 2015, does not qualify to receive free GHG emission units. Rather, Kildair is required to purchase all emission allowances needed to cover emissions attributable to the combustion of the fossil fuels they sell for consumption in Québec at government auctions or on the Western Climate Initiative (“WCI”) carbon market. Additionally, Kildair may purchase offset credits that comply with Quebec laws and regulations. To comply with these laws and regulations, Kildair must incur costs to purchase credits that allow Kildair to continue operations at their current

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level. Increased costs may result in increased prices for Kildair’s products or decreased profitability. Increased product price could result in a reduction of demand for Kildair’s product and therefore reduce our revenues. Additional risks include the inability to acquire the required amount of emission allowances or credits to offset GHG emissions which would subject Kildair to various fines.

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 product and require us to incur additional handling costs and capital expenditures. If we are unable to procure product or recover these costs through increased sales, we may not be able to meet our financial obligations.

We and our subsidiaries depend on unionized labor for our operations in Lawrence, Mt. Vernon; Albany, New York; Providence, Rhode Island; and Sorel-Tracy Quebec, Canada. We are also in negotiations with two additional unions for the Bronx, NY terminal as part of the Castle acquisition. 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 financial condition, results of operations and distributable cash flow. 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.

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 our 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 our unitholders.

Risks Inherent in an Investment in Us

It is our business strategy to distribute in increasing amounts our distributable cash flow, which could limit our ability to grow and make acquisitions.

We expect that we will distribute in increasing amounts our distributable cash flow to our unitholders and will 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 most 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

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additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our 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 impact the cash that we have available to distribute to our 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 9, 2015, Axel Johnson, through its ownership of Sprague Holdings, indirectly owns a 57.4% 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:

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

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 our 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:

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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.

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 will agree to provide certain general and administrative services and operational services to us, and we will agree to reimburse our general partner and its affiliates for all costs and expenses incurred in connection with providing such services to us, including salary, bonus, 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 and subordinated units voting together as a single class is required to remove our general partner. As of March 9, 2015, Sprague Holdings owns 57.4% of the common units and subordinated units. If our general partner is removed without cause during the subordination period and no units held by the holders of our subordinated units or their affiliates are voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests, and by eliminating existing arrangements, if any. Cause is narrowly defined to mean that a court of competent jurisdiction has

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entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of our business.

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.

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 our partnership agreement nor our 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:

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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 9, 2015, Sprague Holdings and its subsidiaries held 2,034,378 common units and 10,071,970 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period (which could occur as early as December 31, 2016) and may convert earlier under certain circumstances. Additionally, we have agreed to provide Sprague Holdings with certain registration rights (which may facilitate the sale by Sprague Holdings of its common and subordinated 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 by purchasing 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 the 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 the 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 a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.

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 9,2015, Sprague Holdings and its affiliates owned approximately 18.5% of our common units. At the end of the subordination period (which could occur as early as December 31, 2016), assuming no additional issuances of common units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own approximately 57.4% 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

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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:

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.

Our subordinated units will convert into common units 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.

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 there are no subordinated units outstanding and 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 our distributions at the time of the exercise of the reset election. 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

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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 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 then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for 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 on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. 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. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.

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, which is currently a maximum of 35% and would likely pay additional state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distributions 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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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.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our distributable cash flow.

We are currently subject to entity level taxes and fees in a number of states, and such taxes and fees will reduce the distributable cash flow. Changes in current state laws may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional taxes on us by other states in which we do business will further reduce the distributable cash flow available for distribution to unitholders.

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 could 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.

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

In addition, the IRS has been considering changes to its private letter ruling policy concerning which activities give rise to qualifying income within the meaning of section 7704 of the Code. The implementation of changes to this policy could include the modification or revocation of existing rulings, including ours.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as

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partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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. 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.

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

We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.

Sprague Holdings currently directly and indirectly owns more than 50% of the total interests in our capital and profits interests. Therefore, a transfer by Sprague Holdings of all or a portion of its interests in us, along with transfers by other unitholders, could result in a termination of our partnership for U.S. income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

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

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. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. 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.

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

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

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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 will reduce our distributable cash flow.

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.

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 depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the 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.

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

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

A unitholder whose common units are the subject of a securities loan (e.g. a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, 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 be required to recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, 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 should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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Unitholders may be subject to state and local taxes and 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 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. 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 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.

Item 2. Properties

The following tables set forth information with respect to our 19 owned, operated and/or controlled terminals.

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Item 3. Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our consolidated financial condition or results of operations.

Item 4. Mine Safety Disclosures

Not applicable.

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Part II

Item 5. Market for Our 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. Prior to that time, there was no public market for our securities. As of March 9, 2015, Sprague Holdings and its subsidiaries owned 2,034,378 common units and 10,071,970 subordinated units, which together constitute a 57.4% ownership interest in us. During the year ended December 31, 2013, we issued 8,500,000 common units to the public in connection with our IPO and 6,666 restricted units in accordance with the 2013 Long Term Incentive Plan for Director compensation. During the year ended December 31, 2014, we issued 706,263 common units in connection with business acquisitions and 27,401 common units in connection with the 2013 Long Term Incentive Plan for Employee and Director compensation. As of March 9, 2015, the closing market price for our common units was $24.69 per unit and there were approximately 6 unitholders of record of our common units. The actual number of unitholders is greater than the number of holders of record.

The following table sets forth the range of the high and low closing prices of our common units and cash distributions to common unitholders for the period from October 25, 2013, the date our shares began trading.

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:

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See “Item 1A. Risk Factors—Risk Related to our Business.”

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

Sprague Holdings owns, directly or indirectly, all of our subordinated units. The principal difference between our common units and subordinated units is that during the period referred to in our partnership agreement as the “subordination period”, the common units have the right to receive distributions of cash from distributable cash flow each quarter in an amount equal to $0.4125 per common unit, which is the amount defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from distributable cash flow may be made on the subordinated units. Furthermore, no arrearages will accrue or be paid on the subordinated units.

Upon expiration of the subordination period, any outstanding arrearages in payment of the minimum quarterly distribution on the common units will be extinguished (not paid), each outstanding subordinated unit will immediately convert into one common unit and will thereafter participate pro rata with the other common units in distributions.

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 distribution of 50.0% does not include any distributions that our sponsor may receive on any limited partner units that it owns.

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Item 6. Selected Financial Data

The following table presents selected historical consolidated financial and operating data of the Partnership and our predecessor, Sprague Operating Resources LLC, as of the dates and for the periods indicated. The selected historical financial data as of and for the year ended December 31, 2014 are derived from the Partnership’s 2014 audited Consolidated and Combined Financial Statements. The selected historical financial data as of and for the year ended December 31, 2013 includes the combined results of the Predecessor through October 29, 2013 and the Partnership for the period from October 30, 2013 through December 31, 2013, all derived from the Partnership’s 2013 audited Consolidated and Combined Financial Statements. The selected historical consolidated financial data presented as of and for the years ended December 31, 2012, 2011 and 2010 are derived from the audited consolidated financial statements of Sprague Operating Resources LLC.

On December 9, 2014, the Partnership acquired all of the equity interests in Kildair through the acquisition of the equity interests of Kildair’s parent, Sprague Canadian Properties LLC. As this transaction represented a transfer of entities under common control, the Consolidated and Combined Financial Statements and related information presented herein have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson.

The following table presents the non-GAAP financial measure adjusted EBITDA, which we use in our business as an important supplemental measure of our performance. We define and explain this measure under “—Non-GAAP Financial Measures” on page 46 and reconcile it to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP.

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EDITDA and Adjusted EBITDA

We present the non-GAAP financial measures EBITDA and adjusted EBITDA in this Annual Report. We define EBITDA as net income(loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory and natural gas transportation contracts, decreased by gains on acquisition of business, increased by the write-off of deferred offering costs and adjusted for the net impact of bio-fuel excise tax credits in 2013/2012. Adjusted EBITDA is used as a supplemental financial measure by our management, and 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:

For a discussion of how our management uses adjusted EBITDA, please read “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.”

The GAAP measure most directly comparable to EBITDA and adjusted EBITDA is net income (loss). The non-GAAP financial measures of EBITDA and adjusted EBITDA should not be considered as an alternative to net income (loss), 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. You should not consider EBITDA or adjusted EBITDA 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 is defined differently by different companies, our definitions of EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies.

We recognize that the usefulness of EBITDA and adjusted EBITDA as an evaluative tool may have certain limitations, including:

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The following table presents a reconciliation of EBITDA and adjusted EBITDA to net income (loss), the most directly comparable GAAP financial measure, on a historical basis, as applicable, for each of the years indicated:

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

On October 30, 2013, we completed an initial public offering of 8,500,000 common units, representing a 42.2% limited partnership interest in us, at an initial public offering price of $18.00 per unit. Total proceeds of the sale of the common units were $140.3 million after deducting underwriting discounts and commissions, the structuring fee and offering expenses.

On December 9, 2014, the Partnership acquired all of the equity interests in Kildair through the acquisition of the equity interests of Kildair’s parent, Sprague Canadian Properties LLC. As this transaction represented a transfer of entities under common control, the Consolidated and Combined Financial Statements and related information presented herein have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson, which commenced on October 1, 2012.

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.

EBITDA and Adjusted EBITDA are non-GAAP financial measures of performance that have limitations and should not be considered as a substitute for net income (loss) or cash provided by (used in) operating activities. Please see Item 6 above for a discussion of our use of EBITDA and Adjusted EBITDA and a reconciliation to net income (loss) for the periods presented.

Cautionary Statements Concerning Forward-Looking Statements

This Annual Report, including without limitation, our discussion and analysis of our financial condition and results of operations, and any information incorporated by reference, contains statements that we believe are “forward-looking statements”. Forward-looking statements give our current expectations and contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may”, “assume”, “forecast”, “position”, “predict”, “strategy”, “expect”, “intend”, “plan”, “estimate”, “anticipate”, “believe”, “project”, “budget”, “potential”, 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. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors included in Part I, Item 1A “Risk Factors” of this Annual Report as well as the following risks and uncertainties:

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The risk factors and other factors noted throughout this Annual Report could cause our actual results to differ materially from those contained in any forward-looking statement, and you are cautioned not to place undue reliance on any forward-looking statements.

Forward-looking statements 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 SEC. We undertake no obligation, and disclaim any obligation, to publicly update or review any forward-looking statements to reflect events or circumstances after the date of such statements.

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 to 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

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of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of 19 refined products and materials handling terminals strategically located throughout the Northeast United States and in Quebec, Canada that have a combined storage capacity of approximately 14.1 million barrels for refined products and other liquid materials, as well as approximately 1.5 million square feet of materials handling capacity. We also have an aggregate of approximately 2.3 million barrels of additional storage capacity attributable to 47 storage tanks not currently in service. These tanks are not necessary for the operation of our business at current levels. In the event that such additional capacity were desired, additional time and capital would be required to bring any of such storage tanks into service. Furthermore, we have access to more than 60 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. We evaluate the performance of our segments using adjusted gross margin, which is a non-GAAP financial measure used by management and external users of our Consolidated and Combined Financial Statements to assess the economic results of operations. For a description of how we define adjusted gross margin, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Adjusted Gross Margin and Adjusted EBITDA.” For a reconciliation of adjusted gross margin to the GAAP measure most directly comparable thereto, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.”

On October 1, 2012, our Predecessor acquired control of Kildair, a Canadian distributor of residual fuel oil and asphalt and a commercial trucking business, by purchasing the remaining 50% equity interest. Prior to October 1, 2012, the results of operations of Kildair were recorded as equity in earnings of foreign affiliate. From October 1, 2012 and through the date of our IPO on October 30, 2013, the assets, liabilities and results of operations of Kildair have been consolidated into our financial statements, including our adjusted gross margin. Kildair was not part of our net assets following the completion of the IPO. On December 9, 2014, the Partnership acquired all of the equity interest in Kildair through the acquisition of the equity interests of Kildair’s parent, Sprague Canadian Properties, LLC. As this transaction represents a transfer of entities under common control, the Consolidated and Combined Financial Statements and related information presented herein have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson. We record Kildair’s residual fuel oil and asphalt business in our refined products segment and their commercial trucking business in our other operations segment.

Our refined products segment purchases 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 sells 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 we sell to them. Our wholesale customers consist of more than 1,100 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 and asphalt paving companies. For the years ended December 31, 2014 and 2013, we sold approximately 1.7 billion and 1.5 billion gallons of refined products, respectively. For the years ended December 31, 2014 and 2013, our refined products segment accounted for 60% and 61% of our adjusted gross margin, respectively.

We also purchase, sell and distribute natural gas to more than 15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. We purchase the natural gas we sell from natural gas producers and trading companies. For the years ended December 31, 2014 and 2013, we sold 54.4 Bcf and 52.0 Bcf of natural gas, respectively. For the years ended December 31, 2014 and 2013, our natural gas segment accounted for 23% and 21% of our adjusted gross margin, respectively.

Our materials handling business 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, clay slurry, salt, gypsum, coal, petroleum coke, crude oil, caustic soda, tallow, pulp and heavy equipment. For the year ended December 31, 2014, we offloaded, stored and/or prepared for delivery 2.7 million

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short tons of products and 309.8 million gallons of liquid materials. For the year ended December 31, 2013, we offloaded, stored and/or prepared for delivery 2.1 million short tons of products and 246.7 million gallons of liquid materials. For the years ended December 31, 2014 and 2013, our materials handling segment accounted for 15% of our adjusted gross margin for both periods.

Our other operations segment includes the marketing and distribution of coal conducted in our Portland, Maine terminal and commercial trucking. For the years ended December 31, 2014 and 2013, our other operations segment accounted for approximately 2% and 3% of our adjusted gross margin, respectively.

We take title to the products we sell in our refined products, natural gas and other operations segments. We do not take title to any of the products in our materials handling segment. 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.

Non-GAAP Financial Measures

We present the non-GAAP financial measures EBITDA and adjusted EBITDA and adjusted gross margin in this Annual Report.

For a description of how we define EBITDA, and adjusted EBITDA see Part I, Item 6—“Selected Financial Data” above . A reconciliation of EBITDA and adjusted EBITDA is presented on page 41. For a description of how we define adjusted gross margin see below. A reconciliation of adjusted gross margin is presented on page 50.

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 gross margin and adjusted EBITDA, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.

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. Commencing on October 30, 2013, 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. Operating expenses have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson

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. Commencing on October 30, 2013, 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. We believe that our SG&A expenses will increase as a result of our becoming a publicly traded partnership. SG&A expenses have been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson

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

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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. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2011.

EBITDA

We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by external users of our financial statements, such as investors, trade suppliers, research analysts and commercial banks to assess:

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

EBITDA is not prepared in accordance with GAAP. EBITDA should not be considered an alternative to net income (loss), operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income (loss) and operating income.

Adjusted Gross Margin and Adjusted EBITDA

Management utilizes adjusted gross margin and adjusted EBITDA to assist it in reviewing our financial results and managing our business segments. 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 and natural gas transportation contracts. We define adjusted EBITDA as EBITDA increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory and natural gas transportation contracts, decreased by gains on acquisition of businesses, increased by the write-off of deferred offering costs and adjusted for the net impact of bio-fuel excise tax credits. Management believes that adjusted gross margin and adjusted EBITDA provide information that reflects our market or economic performance. We trade, purchase and sell energy commodities with market values that are constantly changing, which makes it important for management to evaluate our performance, as well as our physical and derivative positions, on a daily basis. Management reviews the daily operational performance of our supply activities, as well as our monthly financial results, on an adjusted gross margin and adjusted EBITDA basis. Adjusted gross margin and adjusted EBITDA have no impact on reported volumes or net sales.

Adjusted gross margin and adjusted EBITDA are 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:

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Adjusted gross margin and adjusted EBITDA are not prepared in accordance with GAAP. Adjusted gross margin and adjusted EBITDA should not be considered as alternatives to net income (loss), income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

Hedging Activities

We economically hedge our inventory within the guidelines set in our risk management policy. 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 market, or LCM. 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 daily using independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are primarily based in New York Harbor, or NYH, with our inventory values determined after adjusting the NYH prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to a NYH supply source. 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.

Similarly, we can economically 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 increase. If the market value of the transportation asset exceeds costs, we can 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). As 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 adjust those numbers to show only the impact of hedging gains and losses actually realized in the period being reviewed. 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.

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Recent Trends and Outlook

This section identifies certain trends and outlook that may affect our financial performance and results of operations in the future. Our economic and industry-wide trends and outlook include the following:

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Factors that Impact our Business

Our results of operations and financial condition, as well as those of our competitors, will depend in part upon certain economic or industry-wide factors, including the following:

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Results of Operations

The following table presents our volume, net sales and adjusted gross margin by segment, as well as our adjusted EBITDA and information on weather conditions, for the years ended December 31, 2014, 2013 and 2012.

Our acquisition of Kildair on December 9, 2014 represents a transfer of entities under common control. The information presented herein has been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson, which commenced on October 1, 2012.

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

Our results of operations for the year ended December 31, 2014 reflect increasing sales volume, net sales and adjusted unit gross margin in our refined products segment, increasing volume, net sales and adjusted unit gross margin in our natural gas segment and increasing volumes, net sales and adjusted gross margin in our materials handling segment.

Adjusted gross margin for the year ended December 31, 2014 reflects increasing adjusted gross margin for refined products and natural gas.

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Refined Products

Refined products net sales were $4.7 billion and $4.3 billion for the years ended December 31, 2014 and 2013, respectively. Refined products net sales increased $319.5 million, or 7%, which was driven primarily by higher refined products sales volumes. Refined products sales volumes were 1.7 billion gallons and 1.5 billion gallons for the years ended December 31, 2014 and 2013, respectively. Distillate sales volumes increased 186.6 million gallons, or 20%, period over period, with substantial increases in both diesel and heating oil. The largest volume increases were in diesel fuel due to the contracts acquired from Hess Corporation at the end of 2013 and higher sales to power plant customers to meet power generation requirements as the colder weather conditions in the first quarter led to natural gas curtailments. Heating oil volumes were also up sharply, driven by sustained colder weather conditions during the winter and increased share in key markets due to enhanced asset positions, including the Bridgeport, Connecticut terminal that was purchased in the second half of 2013. The purchase of Castle in early December 2014 also contributed to the distillate volume gains.

Gasoline sales volumes increased by approximately 2.0 million gallons, or 1%, period over period. Residual fuel oil and asphalt sales volumes increased 7.5 million gallons, or 2%, period over period, with the volume increases a result of natural gas curtailments primarily due to the colder weather. The average refined products selling price per gallon was 5% lower for the year ended December 31, 2014 as compared to the same period in 2013, with a significant decline in the fourth quarter offsetting the higher prices earlier in the year driven by declining world crude oil prices.

Refined products adjusted gross margin, was $146.0 million and $114.7 million for the years ended December 31, 2014 and 2013, respectively. The refined products adjusted gross margin increase of $31.3 million, or 27%, was driven by improved returns in distillate fuels, with both heating oil and diesel fuel providing substantial increases. The increase in heating oil adjusted gross margin was due to a combination of higher volumes and unit margins. The improvement in diesel margin generation was largely due to higher volumes, though unit margins also improved. The additional volumes included increases from sales to the former Hess Corporation customers as well as the incremental power generation requirements resulting from natural gas curtailments. Gasoline volumes improved modestly and margins increased as well, supported by proceeds from the sale of RINs and higher gasoline throughput revenues compared to the previous year. Higher residual fuel sales volumes and improved unit margins led to the increase in adjusted gross margin for heavy fuel oil.

In January 2013 a previously expired bio-fuel excise tax credit was retroactively reinstated to include all applicable 2012 activity. As a result, the refined products adjusted gross margin results for the year ended December 31, 2013 includes a $5.0 million benefit. There was no comparable adjustment for the year ended December 31, 2014.

Natural Gas

Natural gas net sales were $360.0 million and $304.8 million for the years ended December 31, 2014 and 2013, respectively. The natural gas sales increase of $55.2 million, or 18%, was driven by higher commodity prices as the average natural gas price per MMBtu was approximately 13% higher during the year ended December 31, 2014 as compared to the same period in 2013. The stronger natural gas price environment was due in part to the higher demand driven by colder weather during 2014, in particular during the first quarter. Natural gas sales volumes increased by nearly 5% for the year due primarily to a combination of strong sales volumes in the first quarter due to colder weather and the addition of the Metromedia volumes at the beginning of the fourth quarter.

Natural gas adjusted gross margin was $55.5 million and $40.4 million for the years ended December 31, 2014 and 2013, respectively. In addition to adjusted gross margin generated from the inclusion of Metromedia sales beginning in the fourth quarter, the natural gas adjusted gross margin increase of $15.1 million, or 38%, was due primarily to higher demand supported by colder weather conditions during the first quarter, the continuing transition of our customer base towards smaller commercial and industrial end users with higher unit

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margins, and additional margin generation from optimization of transportation assets and storage utilization, particularly during volatile pricing periods. In connection with the acquisition of Metromedia Energy we recorded an asset of $39.4 million and a liability of $1.5 million, representing the fair value of natural gas transportation contracts acquired which will be amortized into cost of products sold over the life of the underlying agreements. During the year ended December 31, 2014, we recorded a charge to cost of products sold of $21.9 million which included $13.6 million due to a decline in value as a result of decreasing natural gas spreads.

Materials Handling

Materials handling net sales were $37.8 million and $28.4 million for the years ended December 31, 2014 and 2013, respectively. The materials handling net sales increase of $9.4 million, or 33%, was primarily due to the start-up of the crude handling project at Kildair which increased liquids handling revenue substantially, and an increase in dry bulk handling volumes at other Sprague facilities.

The materials handling adjusted gross margin increase of $9.4 million, or 33%, was primarily due to the initiation of Kildair’s crude handling activities and an increase in dry bulk handling volumes of salt, petroleum coke, and gypsum. The dry bulk increase was driven by a combination of low activity in 2013 due to higher bulk product inventories as a result of warm weather (e.g., salt) and timing differences in deliveries (i.e., a shipment in early 2014 versus late 2013). Some other gains such as improved break bulk returns, particularly for newsprint, also contributed to the overall margin increase in 2014.

Other Operations

Sales from our other operations were $21.1 million and $18.7 million for the years ended December 31, 2014 and 2013, respectively, representing an increase of $2.4 million. This was primarily due to increased sales of coal partially offset by a decrease in commercial trucking activities of Kildair.

Adjusted gross margin from our other operations remain relatively unchanged at $5.6 million for the year ended December 31, 2014, as compared to $5.5 million for the year ended December 31, 2013.

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

Our results of operations for the year ended December 31, 2013 reflect increasing sales volume, net sales and adjusted unit gross margin in our refined products segment, increasing volume, net sales and adjusted unit gross margin in our natural gas segment and decreasing volumes, net sales and adjusted gross margin in our materials handling segment.

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Adjusted gross margin for the year ended December 31, 2013 reflects increasing adjusted gross margin for refined products and natural gas.

Refined Products

Refined products net sales were $4.3 billion and $3.8 billion for the years ended December 31, 2013 and 2012, respectively. Refined products net sales increased $573.6 million, or 15%, which was driven primarily by higher refined products sales volumes. Refined products sales volumes were 1.5 billion gallons and 1.3 billion gallons for the years ended December 31, 2013 and 2012, respectively. Distillate sales volumes increased 118.2 million gallons, or 14%, period over period, with higher volumes in all four quarters during 2013. The percentage increases were highest in the three months ending March 31, 2013 compared to the same period in 2012, with a key factor being the unseasonably warm weather during that time period in 2012. Gasoline sales volumes decreased by approximately 32.1 million gallons, or 12%, for the year ended December 31, 2013 as compared to the same period in 2012. This decrease occurred primarily due to aggressive pricing by our competitors. Residual fuel oil and asphalt sales volumes increased 134.2 million gallons, or 77%, for the year ended December 31, 2013 as compared to the same period in 2012. Of this increase, approximately 130.6 million gallons was due to Kildair, which was acquired on October 1, 2012. The average refined products selling price per gallon was 2% lower for the year ended December 31, 2013 as compared to the same period in 2012.

Refined products adjusted gross margin, was $114.7 million and $77.5 million for the years ended December 31, 2013 and 2012, respectively. Refined products adjusted gross margin increased $37.2 million, or 48%. Of this increase, approximately $23.3 million was due to Kildair, which was acquired on October 1, 2012. In addition to Kildair, returns in distillates improved, in particular heating oil. Heating oil volumes and unit margins both improved substantially, partly due to the colder weather conditions in 2013. The reinstatement of the U.S. federal bio-fuel excise tax credits in January 2013 contributed $5.0 million to the increase.

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Natural Gas

Natural gas net sales were $304.8 million and $242.0 million for the years ended December 31, 2013 and 2012, respectively. The natural gas sales increase of $62.8 million, or 26%, was driven by higher commodity prices as the average natural gas marketing price per MMBtu was approximately 20% higher during the year ended December 31, 2013 as compared to the same period in 2012. The stronger natural gas price environment was due in part to the higher weather-driven demand during 2013. Natural gas sales volumes increased 5% for the year ended December 31, 2013 as compared to the same period in 2012, with the colder weather being a contributing factor.

Natural gas adjusted gross margin was $40.4 million and $26.8 million for the years ended December 31, 2013 and 2012, respectively. The natural gas adjusted gross margin increase of $13.5 million, or 50%, was due to a number of factors including higher sales volumes partly driven by the colder weather conditions, the continuing transition of our customer base towards smaller commercial and industrial end users, and additional margin generation due to optimization of transportation assets and storage utilization. The transportation/storage optimization opportunities were most notable during the volatile pricing periods observed during the winter months.

Materials Handling

Materials handling net sales were $28.4 million and $32.5 million for the years ended December 31, 2013 and 2012, respectively. The materials handling net sales decrease of $4.1 million, or 13%, was primarily due to a decrease in dry bulk activities including salt, gypsum and petcoke. In addition, windmill component handling activities were substantially lower in the year ended December 31, 2013 compared to the same period in 2012.

The materials handling adjusted gross margin decrease of $3.9 million, or 12%, was primarily due to a reduction in dry bulk activities including salt, gypsum, windmill component handling, and petcoke, generally reflecting the timing requirements of our customers. These decreases were partially offset by increased asphalt handling revenues over the same time periods due primarily to increased volumes by a major customer.

Other Operations

Sales from our other operations were $18.7 million and $11.5 million for the years ended December 31, 2013 and 2012, respectively, representing an increase of $7.1 million. Of this increase, approximately $7.8 million was due to the commercial trucking activities of Kildair, which was acquired on October 1, 2012.

Adjusted gross margins from our other operations were $5.5 million and $2.8 million for the years ended December 31, 2013 and 2012, respectively, representing an increase of $2.7 million. Of this increase, substantially all was due to the commercial trucking activities of Kildair, which was acquired on October 1, 2012.

Operating Costs and Expenses

Our acquisition of Kildair on December 9, 2014 represents a transfer of entities under common control. The information presented herein has been recast to include the historical results of Kildair for all periods presented where Kildair was controlled by Axel Johnson, which commenced on October 1, 2012.

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The following table presents our operating expenses and selling, general and administrative expenses for the years ended December 31, 2014, 2013, and 2012.

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

Operating Expenses. Operating expenses for the year ended December 31, 2014 increased $9.7 million, or 18%, as to the year ended December 31, 2013. Of this increase, $3.8 million was due to increased maintenance, insurance and utility expenses, $2.7 million was due to increased dry bulk handling volumes, $2.4 million was due to terminal operating expenses related to our Bridgeport terminal which was acquired on July 31, 2013 and $0.6 million was due to terminal operating expenses related to our Bronx terminal which was acquired on December 8, 2014.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the year ended December 31, 2014 increased $21.2 million, or 38%, as compared to the year ended December 31, 2013. Of this increase $12.6 million was due to higher employee related expenses primarily attributed to increased incentive compensation and sales commissions as a result of higher earnings performance, $3.3 million related to increased professional fees associated with public company reporting and compliance requirements, $2.8 million was related to expenses associated with mergers and acquisition activities, and $2.6 million was due to selling, general and administrative expenses related to the Metromedia Energy and Castle Oil acquisitions.

Depreciation and Amortization. Depreciation and amortization for the year ended December 31, 2014 increased $1.1 million, or 7%, as compared to the year ended December 31, 2013. This increase was predominantly driven by the amortization of intangible assets arising from the Metromedia Energy acquisition in the fourth quarter.

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

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Operating Expenses. Operating expenses for the year ended December 31, 2013 increased $6.2 million, or 13%, as compared to the year ended December 31, 2012, primarily due to the inclusion of $10.2 million and $3.3 million of Kildair’s operating expenses for the years ended December 31, 2013 and 2012, respectively, representing an increase of $6.9 million. The remaining operating expenses decrease of $0.7 million was driven by a decrease of $1.7 million due to lower costs associated with materials handling operations, offset by an increase of $1.2 million due to the operating expenses of our Bridgeport terminal, which was acquired on July 31, 2013.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for the year ended December 31, 2013 increased $8.8 million, or 19%, as compared to the year ended December 31, 2012. Selling, general and administrative expenses include Kildair’s expenses of $5.9 million and $1.2 million for the years ended December 31, 2013 and 2012, respectively, representing an increase of $4.7 million. The remaining increase in selling, general and administrative expenses was primarily due to incentive compensation as a result of higher earnings performance.

Write-off of Deferred Offering Costs. During the year ended December 31, 2012, deferred offering costs of $8.9 million were charged against earnings due to an extended delay in the timing of our IPO. The total charge included $6.5 million of offering costs previously deferred as of December 31, 2011 and $2.4 million of deferred offering costs incurred during the year ended December 31, 2012.

Depreciation and Amortization. Depreciation and amortization for the year ended December 31, 2013 increased $4.9 million, or 42%, as compared to the year ended December 31, 2012. Kildair’s depreciation and amortization expense was $6.9 million and $1.8 million for the years ended December 31, 2013 and 2012, respectively, representing an increase of $5.1 million.

Interest Expense, Net, Equity in Net Loss of Foreign Affiliate and Gain on Acquisition of Business

The following table presents our interest expense, net, equity in net loss of foreign affiliate and gain on acquisition of business for the years ended December 31, 2014, 2013, and 2012.

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