EDGAR 10-K Filing

Company CIK: 1525287
Filing Year: 2022
Filename: 1525287_10-K_2022_0001525287-22-000013.json

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ITEM 1. BUSINESS
Item 1. Business
As used in this Annual Report, unless the context otherwise requires, prior to May 28, 2021, references to “Sprague Resources” and the “Partnership,” refer to Sprague Resources LP and its subsidiaries; references to the "General Partner" refer to Sprague Resources GP LLC; references to “Axel Johnson” or the "Sponsor" refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner; references to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of the General Partner.
Unless the context otherwise requires, effective May 28, 2021, references referring to "Sprague Resources" and the "Partnership" refer to Sprague Resources LP and its subsidiaries; references to the "General Partner" refer to Sprague Resources GP LLC; references to “Hartree” or the "Sponsor" refer to Hartree Partners, LP, and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner; references to “Sprague Holdings” refer to Sprague HP Holdings LLC, a wholly owned subsidiary of Hartree and the owner of the General Partner.
References to "our Predecessor" refer to Sprague Operating Resources LLC and its precursor Sprague Energy Corp.
Our Partnership
We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and provide storage and handling services for a broad range of materials. In October 2013, we became a publicly traded master limited partnership ("MLP") and our common units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP.”
Our company history began with the 1870 founding of the Charles H. Sprague Company in Boston, Massachusetts; and, in 1905, the company opened the Penobscot Coal and Wharf Company, a tidewater terminal located in Searsport, Maine. By World War II, the company was operating eleven terminals and a fleet of two dozen vessels transporting coal and other products throughout the world. As fuel needs diversified in the United States, the company expanded its product offerings and invested in terminals, tankers, and product handling activities. In 1959, the company expanded its oil marketing activities via entry into the distillate oil market. In 1970, the company was sold to Royal Dutch Shell’s Asiatic Petroleum subsidiary; and, in 1972, Royal Dutch Shell sold the company to Axel Johnson, a member of the Axel Johnson Group of Stockholm, Sweden.
On April 20, 2021, the Partnership announced that Sprague Holdings, an Axel Johnson subsidiary, entered into an agreement to sell to Sprague HP Holdings, LLC (a wholly-owned subsidiary of Hartree) Sprague Holdings' interest in the General Partner, the incentive distribution rights and all of the common units representing limited partner interests that Sprague Holdings owned in the Partnership (the "Transaction"). The Transaction was completed and effective on May 28, 2021 and the aggregate purchase price was $290.0 million, consisting of approximately $265.0 million attributable to the purchase of 16,058,484 common units and approximately $25.0 million attributable to the general partner interest and incentive distribution rights.
On January 11, 2022, the Partnership received an unsolicited non-binding proposal from Hartree pursuant to which Hartree would acquire all of the outstanding common units of the Partnership that Hartree and its affiliates do not already own in exchange for $16.50 in cash for each such common unit. The board of directors of the General Partner has delegated authority to evaluate and negotiate the proposal to its conflicts committee. The conflicts committee's evaluation process is currently ongoing.
We are one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of refined products and materials handling terminals and storage facilities predominantly located in the Northeast United States from New York to Maine and in Quebec, Canada that have a combined storage tank capacity of approximately 14.3 million barrels for refined products and other liquid materials, as well as approximately 2.0 million square feet of materials handling capacity. We also have access to approximately 48 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
We operate under four business segments: refined products, natural gas, materials handling and other operations. See Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations" for a discussion of financial results by segment and see Segment Reporting included under Note 17 to our Consolidated Financial Statements for a presentation of financial results by reportable segment.
As of December 31, 2021, the Sponsor, through its ownership of Sprague Holdings, owned 19,548,849 common units. On October 31, 2021, Hartree Bulk Storage, LLC ("Bulk Storage") ceased to be managed by HP Bulk Storage Manager, LLC and became managed by HBS Acquisition Co., LLC a wholly owned subsidiary of the Sponsor, Hartree. As a result of this change, the Sponsor was deemed to beneficially own the 1,375,000 common units held by Bulk Storage in addition to the 18,173,849 units held by Sprague Holdings, for a total of 19,548,849 common units representing 74.5% of the limited partner interests in the Partnership. Subsequent to this change, on December 3, 2021, the 1,375,000 common units held by Bulk Storage were transferred to Sprague Holdings in a transfer between two wholly owned subsidiaries of the Sponsor. As a result of this transfer, Sprague Holdings directly owns 19,548,849 common units, which consists of all of the common units beneficially owned by Hartree. Sprague Holdings also owns the General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds incentive distribution rights (“IDRs”) that entitle it to receive increasing percentages of the cash the Partnership distributes from distributable cash flow in excess of $0.7676 per unit per quarter, up to a maximum of 50.0%. The maximum distribution of 50% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns.
We furnish or file with the SEC our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We make these documents available free of charge on our website as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. Our internet address is www.spragueenergy.com. Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.
Business Strategies
Our primary business objective is to increase distributable cash flow per unit over time by executing the following strategies:
•Increase our business with our existing assets and customers. We will make investments in our existing asset base to handle additional products and provide new services to customers. We also intend to win additional business by better serving customers' need for certainty of supply, reduced commodity price risk and high quality customer service.
•Target emerging opportunities in the energy transition, leveraging our asset base and customer franchise. As customers’ demand for lower carbon fuels increase, we will continue to source and provide energy products to meet that demand. We intend to expand our liquid renewable fuels offerings, such as biodiesel and renewable diesel, explore the generation and supply of renewable natural gas at our terminals, expand our program of installing solar panels on our infrastructure, and position for materials handling opportunities in the growing offshore wind market.
•Acquire additional terminals and marketing and distribution businesses that are accretive. We intend to grow our asset and customer base by acquiring additional marine and inland terminals (both refined products and materials handling) within and adjacent to the geographic markets we currently serve. We also intend to acquire additional refined products and natural gas marketing businesses that can leverage our existing investment in our logistics capabilities and customer service systems to further increase our cash flow.
•Limit our exposure to commodity price risk and volatility. We take title to the products we sell in our refined products and natural gas segments, while our materials handling business does not take title to products and is operated predominantly under fixed-fee, multi-year contracts. We will continue to manage our exposure to commodity prices and seek to protect our sales margins by maintaining a balanced position in our purchases and sales through the use of derivatives and forward contracts. Our hedging activities are bounded by specific limits established by the board of directors of our General Partner, which are monitored and reported to senior management on a daily basis by our risk group.
•Maintain our operational excellence. We intend to maintain our long history of safe, cost-effective operations and environmental stewardship by investing in the maintenance of our assets and providing training programs for our personnel. We will work diligently to meet environmental regulations and we will continue to enhance our safety programs as our business grows and operating conditions change.
Refined Products
Overview
The products we sell in our refined products segment can be grouped into the following categories: distillates, gasoline and residual fuel oil and asphalt. Our refined products segment accounted for 90%, 86% and 89% of our total net sales for the years ended December 31, 2021, 2020 and 2019, respectively. Of our total volume sold in our refined products segment in 2021, distillates accounted for 75%, gasoline accounted for 16% and residual fuel oil and asphalt accounted for 8%.
Distillates. We sell four kinds of distillates: heating oil (both unbranded and our proprietary premium HeatForce® heating oil brand), diesel fuel (both unbranded and our proprietary premium RoadForce® diesel fuel brand), kerosene and jet fuel. In 2021, heating oil accounted for 58%, diesel fuel accounted for 40%, and other distillates accounted for 2% of the total volume of distillates we sold. We have the capability at several of our facilities to blend biodiesel with distillates in order to sell heating oil and diesel fuel with wide varieties of biodiesel content. In 2021, biofuel blended products accounted for 6% of the distillate fuel volumes sold. Distillate volumes accounted for 75%, 78%, and 79% of our total refined products sales for the years ended December 31, 2021, 2020 and 2019, respectively.
Gasoline. We also sell unbranded gasoline. Gasoline volumes accounted for 16%, 13% and 10% of our total refined products sales for the years ended December 31, 2021, 2020 and 2019, respectively.
Residual Fuel Oil and Asphalt. We sell various sulfur grades of residual fuel oil, blended to meet customer requirements. Residual fuel oil and asphalt volumes accounted for 8%, 9% and 11% of our total refined products sales for the years ended December 31, 2021, 2020 and 2019, respectively.
Customers, Contracts and Pricing
We sell heating oil, diesel fuel, kerosene, unbranded gasoline, jet fuel, and residual fuel oil to wholesalers, retailers and commercial customers. The majority of these sales are made free on board, or FOB, at the bulk terminal or inland storage facility we own and/or operate or at facilities with which we have storage and throughput arrangements. In a FOB sale, the price of products sold includes the cost of delivering such product to the FOB location and any further shipping expenses are borne by the purchaser.
Heating oil sales are made to approximately 1,000 wholesale distributors and retailers through the Sprague RealTime® pricing platform, under rack agreements based upon our posted price, contracts with index-based pricing provisions, and fixed price forward contracts. Diesel fuel sales are made to approximately 590 wholesalers and transportation fuel distributors. We also sell unbranded gasoline at Partnership-owned and at third-party locations, primarily to resellers. Residual fuel oil is sold to approximately 100 commercial and industrial accounts under rack agreements and contracts with index-based pricing provisions.
Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, natural gas resource development companies and educational institutions. Most of these sales are made on a delivered basis, whereby we either deliver the product with our own trucks and barges or arrange with third-party haulers to make deliveries. We also deliver distillate and residual fuel oil by truck to marine customers.
Public sector entities also purchase our heating oil, diesel fuel, unbranded gasoline and residual fuel oil through competitive bidding processes. We currently have contracts with the U.S. government as well as with numerous states, municipalities, agencies and educational institutions.
For the year ended December 31, 2021, no customer represented more than 10% of net sales for our refined products segment.
Natural Gas
Overview
We purchase, sell and distribute natural gas to approximately 15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. Our natural gas segment accounted for 8%, 11% and 9% of our total net sales for the years ended December 31, 2021, 2020 and 2019, respectively. We deliver natural gas to customers through utility interconnections of pipelines and manage interactions with utilities on behalf of our customers. We sell natural gas pursuant to fixed price, floating price and other structured pricing contracts. We utilize physical purchase instruments as well as
financial and derivative instruments both over the counter and through exchanges such as the Intercontinental Exchange Inc. ("ICE") and the New York Mercantile Exchange ("NYMEX"), to manage our natural gas commodity price risk.
In order to manage our supply commitments to our customers and provide operational flexibility and logistic opportunities, we enter into supply contracts, commitments for pipeline transportation capacity, leases for storage space and other physical delivery services for various terms. We believe that entering into these types of arrangements provides us with potential opportunities to grow our existing customer relationships and to pursue additional relationships.
Customers
Our natural gas customers operate in the industrial and commercial sectors in the Northeast and Mid-Atlantic United States, with the highest concentration in New England and New York. Examples of customers include industrial users of varying sizes (e.g., pulp and paper, chemicals, pharmaceutical and metals plants) to various commercial customers (e.g., hospitals, universities, apartment buildings and retail establishments). The industrial customers have a high concentration of process load to support their manufacturing requirements, with the largest uses by the commercial customers typically for heating, cooling, lighting, cooking and drying.
For the year ended December 31, 2021, no customer represented more than 10% of net sales for our natural gas segment.
Contracts/Pricing
We use various types of contracts for the sale and delivery of natural gas to our customers, with terms ranging from month-to-month to over two years. We provide a wide range of pricing options to our customers, including daily pricing and long-term fixed pricing. For example, we may offer a contract that permits the customer to lock in a basis or location differential relative to the Henry Hub delivery location and then fix the price at a later date based on the prevailing market pricing. There are various other alternatives such as “capped” pricing (essentially setting a maximum) or daily pricing based on a differential to a published market index. Due to the commodity price risk associated with uncertain customer usage patterns, we limit the number of transactions that require a single price for all volumes delivered, with the pricing of the non-contractual volumes primarily based on prevailing market economics. For any transaction where the competitive dynamics require a single price for all volumes delivered, we seek to manage the risk by, for instance, including appropriate increases in the cost build-up to reflect higher hedging costs.
Materials Handling
Overview
Materials handling consists of the movement of raw materials and finished goods through our waterfront terminals. We utilize our terminal network to offload, store and/or prepare for delivery a large number of liquid products, bulk and break bulk materials and provide heavy lift services and other handling services to some of the same customers that we supply with refined products and natural gas. Our materials handling segment accounted for 1%, 2%, and 2% of our total net sales for the year ended December 31, 2021, 2020 and 2019, respectively.
We are capable of providing numerous types of materials handling services, including ship handling, crane operations, pile building, warehouse operations, scaling and, in some cases, transportation to the final customer. Because the products we handle are generally owned by our customers, we have minimal to no working capital requirements, commercial risk or inventory risk. Our materials handling activity is generally conducted under multi-year agreements as either fee-based activities or as leasing arrangements when the right to use an identified asset (such as storage tanks or storage locations) has been conveyed in the agreement.
Major Types of Materials Handling and Services
The type of materials handling and services we provide can be divided into three major categories:
Liquid. In a manner similar to our refined products operation our terminal network of marine docks, product pipelines and storage tanks are utilized to store and trans-load various other third party owned liquid products to and from ocean vessels, railcars and tanker trucks. Examples of liquid materials handled include crude oil, refined products, asphalt and clay slurry. Liquid handling activities include securing the vessel, attaching product lines from ship pipes to dock product lines, supervising discharge into tanks, measuring tank quantities, storing product, loading product into authorized trucks or railcars and in some cases transporting the product. Some products require heated storage allow for flow at ambient temperatures. The operations of Kildair Service ULC, our Canadian subsidiary ("Kildair"), include materials handling contracts involving trans-loading and storage of various petroleum products including crude, liquid asphalt and vacuum gas oil ("VGO").
Bulk. Bulk materials are typically aggregate materials that are moved in large vessels configured with multiple holds that store unpackaged products. Examples of bulk material include salt, petroleum coke, gypsum, and coal. Bulk load vessels are
normally offloaded using cranes that can reside either on the vessel or on the dock of the terminal. In a typical discharge, the services performed include: securing the vessel to the dock, operating the vessel cranes, transferring products to trucks via large dock hoppers, transporting the materials to a holding pad, building materials up into large storage piles, covering the piles with protective tarps, storing the product, loading the product into trucks or railcars, scaling the loaded trucks and sometimes transporting the product to its final destination.
Break bulk. Break bulk materials are shipped in less than bulk quantities, normally with some type of secondary packaging. Examples of break bulk materials include one-ton sacks of raw materials, pallets of stones, bales of raw wood pulp and rolls of paper. Another subcategory of break bulk materials is large construction project cargo such as windmill components, often referred to as heavy lift. Break bulk handling activities include securing vessels, unloading or loading vessels either with cranes or specialty fork trucks, transferring products into warehouses or onto pads for storage, reloading products onto trucks or railcars and sometimes transporting products to their final destinations.
Customers
Our materials handling operations can service multiple customer types during any single operation, including: ocean shippers, multiple logistics firms, trucking firms and the materials supplier or consumer. Materials we handle normally fall into three major categories. The first category involves raw materials or finished goods shipped by water into local markets to support local production, manufacturing or construction firms. Examples of these products include asphalt for road construction, gypsum rock for drywall manufacturing, road salt for local road treatment, petroleum coke or utility fuels for energy demand and clay slurry for finished paper treatment. The second category of materials we handle are materials manufactured locally for export via vessel to other countries. These materials include wood pulp for paper manufacture in Asia or Europe and tallow for biodiesel production in Europe. The third category of materials we handle are both crude oil and refined products sourced either in Canada, U.S. or internationally for a range of use in local refineries and/or for further export to the U.S. or elsewhere.
Contracts/Pricing
The typical contract term for our materials handling services varies depending on the frequency and type of service. For bulk and liquid services, the commodity is normally a raw materials input for industrial production (clay slurry) or construction of roads (asphalt) or wallboard (gypsum rock). As such, the demand is more ratable and the customer is normally in need of guaranteed space within a terminal. These customers typically enter into term contracts that can range from one to 20 years depending on the relative importance of the material to their production and the amount of any capital infrastructure that we need to develop for such customers. As of December 31, 2021, the weighted-average life of our materials handling contracts was eight years, with a weighted-average remaining term of four years, each calculated using adjusted gross margin as defined in Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations-How Management Evaluates Our Results of Operations-Adjusted Gross Margin and Adjusted EBITDA,” attributable to these contracts.
Historically, our customers have paid for terminal improvements for specialty handling systems such as a clay slurry screening plant, while we pay for more generic infrastructure improvements such as storage pads.
For container and break bulk services, it is typical for the user of that material to contract on an individual shipment basis. For example, a typical pulp merchant may choose to sell its pulp domestically or to users in Europe or Asia depending on the highest delivered value it can yield. As such, its choice of delivery mode and terminal will be driven by the location of its final customer. Therefore, we normally maintain a published rate for most generic services, subject to change depending on market conditions.
Other Operations
Our other operations segment primarily includes the marketing and distribution of coal out of our Portland, Maine terminal and certain commercial trucking activities conducted by Kildair. For the years ended December 31, 2021, 2020 and 2019 our other operations segment accounted for less than 1% of our total net sales.
Commodity Risk Management
Because we take title to the refined products and natural gas that we sell, we are exposed to commodity risk. Our materials handling business is a fee-based business and, accordingly, our operations in that business segment have only limited exposure to commodity risk. Commodity risk is the risk of market fluctuations in the price of commodities such as refined products and natural gas. We endeavor to limit commodity price risk in connection with our daily operations. Generally, as we purchase and/or store refined products, we reduce commodity risk through hedging by selling futures contracts on regulated exchanges or using other derivatives, and close out the hedges as we sell the product for physical delivery to third parties. Products are generally purchased and sold at spot prices, fixed prices or indexed prices. While we seek to use these transactions
to maintain a position that is substantially balanced between purchased volumes and sales volumes through regulated exchanges or derivatives, we may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules, as well as logistical issues associated with inclement weather conditions or infrastructure disruptions. Our general practice is to not hold refined products futures contracts or other derivative products and instruments for the sole purpose of speculating on price changes. While our policies are designed to limit market risk, some degree of exposure to unforeseen fluctuations in market conditions remains.
Our operating results are sensitive to a number of commodity risk factors. Such factors include commodity location, grades of product, individual customer demand for grades or location of product, localized market price structures, availability of transportation facilities, daily delivery volumes that vary from expected quantities and timing and costs to deliver the commodity to the customer. The term “basis risk” is used to describe the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of that commodity at a different time or place, including, without limitation, transportation costs and timing differentials. We attempt to reduce our exposure to basis risk by grouping our purchase and sale activities by geographical region and commodity quality in order to stay balanced within such designated region.
With respect to the pricing of commodities, we enter into derivative positions to limit or hedge the impact of market fluctuations on our purchases and forward fixed price sales of refined products and natural gas. All hedge positions are reflected in our results of operations.
With respect to refined products, we primarily use a combination of futures contracts, over-the-counter swaps and forward purchases and sales to hedge our price risk. For light oils (gasoline and distillates), we primarily utilize the actively traded futures contracts on the regulated NYMEX to hedge our positions. Heavy oils are typically hedged with fixed-for-floating price residual fuel oil swaps contracts, which are either balanced by offsetting positions or financially settled.
With respect to natural gas, we generally use fixed-for-floating price swaps contracts that trade on the Intercontinental Exchange ("ICE") for hedging. As an alternative, we may use NYMEX natural gas futures for such purposes. In addition, we use natural gas basis swaps to hedge our basis risk.
For both refined products and natural gas, if we trade in any derivatives that are not cleared on an exchange, we strive to enter into derivative agreements with counterparties that we believe have a strong credit profile and/or provide us with trade credit to limit counterparty risk and margin requirements.
Our risk management policies, and the specific limits therein, are intended to prevent unauthorized trading and to maintain substantial balance between purchases and sales or future delivery obligations. However, these steps may not detect and/or prevent all violations of such risk management policies, processes and procedures, particularly if deception or other intentional misconduct is involved.
Storage and Distribution
Marine terminals and inland storage facilities play a key role in the distribution of product to our customers. Our facilities are equipped to provide terminalling, storage and distribution of both solid and liquid products to serve our refined products and materials handling businesses. Each facility has capabilities that are unique to the local markets served. A number of facilities are used to handle liquid, dry bulk, break bulk and refined products at the same terminal and in most cases across the same dock, providing flexibility to fully utilize terminal assets to meet a variety of fuel and third-party cargo handling demands.
The marine terminals and inland storage facilities from which we distribute product are supplied by ship, barge, truck, pipeline or rail. Our customers receive product from our network of marine terminals and inland storage facilities via truck, barge, rail or pipeline.
Our marine terminals consist of multiple storage tanks and automated truck loading equipment. These automated systems monitor terminal access, volumetric allocations, credit control and carrier certification through the electronic identification of customers. In addition, some of the marine and inland terminals are equipped with truck loading racks capable of providing automated blending and additive packages that meet our customers’ specific requirements. Many of our marine and inland terminals operate 24 hours per day.
Throughput arrangements allow storage of our product at terminals owned by others. These arrangements permit our customers to receive product at third-party terminals while we pay terminal owners fees for services rendered in connection with the receipt, storage and handling of the product. Payments we make to terminal owners may be fixed or fluctuate based upon the volume of product that is delivered and sold at the terminal.
Exchange agreements allow our customers to take delivery of product at a terminal or facility that is not owned or leased by us. An exchange is a contractual agreement pursuant to which the parties exchange product at their respective terminals or facilities. For example, we (or our customers) receive product that is owned by the other party from such party’s facility or terminal and we deliver the same volume of product to such party (or to such party’s customers) out of one of the terminals in our terminal network. Generally, both parties to an exchange transaction pay a handling fee (similar to a throughput fee) and often one party also pays a location differential that covers any excess transportation costs incurred by the other party in supplying product to the location at which the first party receives product. Costs incurred in exchanges may also include product value differentials.
Our Terminals and Storage Facilities
As of December 31, 2021, we owned, operated, and/or controlled a network of refined products and material handling terminals and storage facilities predominantly located in the Northeast United States from New York to Maine and in Quebec, Canada that have a combined storage tank capacity of approximately 14.3 million barrels for refined products and other liquid materials, as well as approximately 2.0 million square feet of materials handling capacity. We also have access to approximately 48 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
On April 29, 2021, we sold the Oswego terminal to an unaffiliated buyer. In connection with the sale, the Partnership recorded a net gain of $9.0 million which is included within other operating income in the consolidated statements of operations for the year ended December 31, 2021. The remaining $0.7 million of other operating income for the year ended December 31, 2021 relates to a gain associated with a parcel of land sold at the Bronx terminal on April 29, 2021.
For a more detailed description of our terminals and storage facilities, please read Part I, Item 2 - "Properties.”
Competition
We encounter varying degrees of competition in the marketing of our refined products based on product type and geographic location. In our primary 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 allow us to be competitive 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 sizable market presence and strong customer service and offerings allow us to be competitive in marketing natural gas in the areas in which we operate.
In our materials handling operations, we primarily compete with public and private port operators. Although customer decisions are substantially based on location, additional points of competition include types of services provided and pricing. We believe that our ability to provide materials handling services at a number of our refined products terminals and our demonstrated ability to handle a wide range of products provides us a competitive advantage in competing for products-related handling services in the areas in which we operate.
Seasonality
Demand for natural gas and some refined products, specifically heating oil and residual fuel oil for space heating purposes, is generally higher during the period of November through March than during the period of April through October. Therefore, our results of operations for the first and fourth calendar quarters are generally stronger than for the second and third calendar quarters. For example, over the 36-month period ended December 31, 2021, we generated an average of 76% of our total heating oil and residual fuel oil net sales during the months of November through March.
Employees and Human Capital
As of December 31, 2021, our General Partner employed approximately 654 full-time employees who supported our operations, 75 of whom were covered by five collective bargaining agreements. One of these agreements, covering 9
employees, is up for renewal on May 31, 2022. Our Canadian subsidiary had 103 employees as of December 31, 2021, 40 of whom were covered by one collective bargaining agreement which expires on March 18, 2024. Overall, we believe that our relationships with full-time employees and labor unions are generally good.
Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our four pillars of people, integrity, safety, and innovation. These four pillars guide our values in a manner that respects all people with a commitment to safety and the environments where we operate.
Health and Safety
We maintain a culture of safety grounded on the premise of eliminating workplace incidents, risks and hazards. We have a Health, Safety, Environment and Sustainability department ("HSE") to implement processes to help eliminate high-risk actions and identified safety hazards. We strive to provide all employees with a safe work environment and the necessary skills, training, knowledge, equipment, and management to perform their responsibilities in the healthiest and safest manner possible. We track safety performance using industry standard metrics and work continuously to improve safety across our businesses. In 2021, Sprague’s company-wide Recordable Injury Frequency ("RIF") was calculated to be 2.65, up from 1.68 in 2020. Approximately 40% of the Partnership's 2021 recordable injuries were COVID-19 related. Our 2022 goal is to reduce recordable incidents, as defined by Occupational Safety and Health Administration ("OSHA"), by 50% year over year.
During the second year of the global novel coronavirus pandemic ("COVID-19"), we have continued to prioritize employee safety through maintaining necessary safety measures in all our facilities. We have relied on and followed the guidance from health officials and regulatory bodies and implemented various masking and social distancing standards throughout the workplace. The ongoing COVID-19 pandemic has led to unique challenges, and we are striving to ensure the health, safety and general well-being of our employees. We continue to evolve our programs to meet our employees’ health and wellness needs, which we believe is essential to attract and retain employees of the highest level, and we offer a competitive benefits package focused on fostering work/life integration. We have taken steps to embrace a hybrid model for a portion of our workforce, providing flexibility for employees going forward.
Inclusion, Equity and Diversity
We make it a priority to embrace diversity and collaboration in our workforce, our ways of thinking, and our business experiences. Our goal is to create a culture where we value, respect, and provide fair treatment and equal opportunities for all employees. We encourage employees to consider all points of view to help deliver better results. Inclusion, equity and diversity ("IE&D") is vital to our business as whole, not strictly a human resources initiative. We continue to build IE&D into our culture with a focus on continuous improvement, and have identified several key objectives that guide our effort and by which we will demonstrate our commitment to fostering inclusion, equity and diversity, including:
•Promoting a work environment that enables employees to feel safe to express their ideas and perspectives and feel they belong to our team; and,
•Recruiting, developing and retaining diverse top talent.
Corporate social and environmental responsibility
Our values, rooted in trust, integrity, and collaboration, lay the foundation for our commitment to corporate social and environmental responsibility. We are committed to conducting business in an environmentally sensitive manner and we seek to comply with all applicable local, state, provincial, and federal environmental regulatory requirements. Beyond providing energy solutions that solve our customers' current energy challenges, we believe that to be truly successful, it's crucial that we do our part to adapt to the ever changing energy landscape by seeking out opportunities that reduce our environmental footprint, which would help to improve the world for current and future generations. For example, we are pursuing opportunities to help our customers reduce their carbon footprint by offering the ability to blend biofuels into both transportation and heating oil products. In addition, we have piloted new solar storage tanks at our South Portland Terminal and anticipate deploying additional solar storage tanks at other facilities in the near future.
For us, that means we are committed to: conducting business in a manner that considers and, as appropriate, implements processes to minimize the environmental impact associated with our operations; striving to contribute our time, talent and resources to strengthen the communities where we live and work; and, engaging in ethical practices. Nonetheless, we may not be able to adequately identify or manage the related risks or appropriate opportunities and also cannot assure that we will be able to implement such opportunities because of potential costs or technical or operational obstacles.
Compensation programs and employee benefits
The main objective of our compensation program is to provide a compensation package that will attract, retain, motivate and reward employees. In addition to competitive base salaries, we accomplish this compensation objective through our Thrift
401(k) plan match program and contributions to a Defined Contribution plan. Employees are also eligible for annual bonus amounts tied to our incentive plan metrics and objectives.
We are committed to providing comprehensive benefit options and it is our intention to offer benefits that will allow our employees and their families to live healthier and more secure lives. Some examples of the wide ranging benefits we offer are: medical insurance, prescription drug benefits, dental insurance, vision insurance, parental leave, short-term disability, long-term disability, health rewards, employee assistance programs, health savings accounts and flexible spending accounts.
Environment
General
Our petroleum product terminal and supply operations are subject to extensive and stringent environmental laws. As part of our business, we own and operate petroleum storage and distribution facilities and a fleet of petroleum trucks, and must comply with environmental laws at the federal, state and local levels, which increase the cost of operating terminals and our business generally. These laws include statutes, such as the federal Clean Water Act ("CWA") and the federal Clean Air Act ("CAA"), and their implementing regulations, which can be modified or revised to impose new obligations that are applicable to our operations, including the need to acquire permits to conduct certain activities limiting or preventing the release of materials from our facilities into the environment, managing, transporting and disposing of wastes generated by our operations, the installation of pollution control equipment, responding to releases of process materials or wastes from our operations, and the risk of substantial liabilities for pollution resulting from our operations. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.
Our operations also utilize a number of petroleum storage facilities and distribution facilities that we do not own or operate, but at which refined products are stored. We utilize these facilities through several different contractual arrangements, including leases, throughput and terminalling services agreements. If facilities with which we contract that are owned and operated by third parties fail to comply with environmental laws, they could be shut down, requiring us to incur costs to use alternative facilities.
Environmental laws and regulations can restrict or impact our business in several ways, such as:
•Requiring capital expenditures to comply with environmental control requirements;
•Requiring investigatory, remedial and corrective actions to mitigate releases of hydrocarbons, hazardous substances or wastes caused by our operations or attributable to former operators; and,
•Delaying, restricting or ceasing the operations of facilities deemed in non-compliance with environmental laws and regulations.
Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory, remedial and curative requirements or the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining future operations in affected areas. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hydrocarbons, hazardous substances or wastes have been released or disposed. Moreover, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the release of hydrocarbons, hazardous substances or other wastes into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. For example, President Biden has made the combat of climate change a priority under his administration and has issued a series of executive orders designed to address climate change including potentially the restriction of greenhouse gas (“GHG”) emissions. President Biden may issue additional executive orders and agencies under his administration may issue new or amending regulations that could impose more stringent requirements in respect of protection of the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
Historically, our compliance costs with environmental laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations but there can be no assurance that such costs will not be material in the future as a result of such existing laws and regulations, changes in the interpretation of existing laws and regulations, promulgation of new laws and regulations or will not have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.
Hazardous Substances and Releases
Our business is subject to laws relating to the release of hazardous substances into the water or soils, which include requirements to control pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under the Superfund law, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. The Superfund law also authorizes the EPA, and in some instances third parties, to act in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs they incur. It is possible for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate substances that fall within the Superfund law’s definition of a hazardous substance and, as a result, we may be jointly and severally liable under the Superfund law for all or part of the costs required to clean up sites at which those hazardous substances have been released into the environment.
We currently own, lease or use storage or distribution facilities where hydrocarbons are being or have been handled for many years. Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where we have contractual arrangements or where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to the Superfund law or other federal and state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by prior owners or operators, to clean up contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.
Our operations generate a variety of wastes, including some hazardous wastes that are subject to the federal Resource Conservation and Recovery Act, as amended ("RCRA") and comparable state laws. These regulations impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste. Our operations also generate solid wastes which are regulated under state law or the potentially less stringent solid waste requirements of the federal Solid Waste Disposal Act. Historically, our compliance costs with the existing requirements of RCRA, the Solid Waste Disposal Act and similar state and local laws, and the cost involved in complying with these requirements has not been material though there can be no assurance that such costs will not be material in the future. While we are currently incurring ongoing costs for monitoring groundwater at several facilities that we operate such costs are not anticipated to have a material impact on our financial condition or results of operations.
Above-Ground Storage Tanks
Above-ground tanks that contain petroleum and other hazardous substances are subject to comprehensive regulation under environmental laws. Generally, these laws impose liabilities for releases and require secondary containment systems for tanks or require the operators take alternative precautions to ensure that no contamination results from tank leaks or spills. Historically, our compliance costs with the existing environmental requirements applicable to above-ground storage tank have not been material but there can be no assurance that such costs will not be material in the future.
The Oil Pollution Act of 1990, or OPA, addresses three principal areas of oil pollution-prevention, containment and cleanup. In order to handle, store or transport oil, we are required to file oil spill response plans with the U.S. Coast Guard (for marine facilities) and the EPA. States in which we operate have enacted laws similar to OPA. We maintain such plans, and when required have submitted plans and received federal and state approvals necessary to comply with the OPA, the CWA and related regulations.
Under OPA and comparable state laws, responsible parties for a regulated facility from which oil is discharged may be subject to strict, joint and several liability for removal costs and certain other consequences of an oil spill such as natural resource damages, where the spill is into navigable waters or along shorelines. Under the authority of the federal CWA, the EPA imposes specific requirements for Spill Prevention, Control, and Countermeasure, or SPCC, plans that are designed to prevent, and minimize the impacts of, releases from above ground storage tanks. Historically, our compliance costs with the existing requirements of OPA, the CWA and similar state laws have not been material but there can be no assurance that such costs will not be material in the future.
From time to time, we experience spills and releases during various phases of our operations, and some of these releases can reach waters that applicable federal and state laws would define as navigable. As a result we may be responsible for fines and penalties as well as required capital expenditures and for implementation of compliance and maintenance programs.
Water Discharges
The CWA, and analogous state laws impose strict controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. This law and comparable state laws prohibit the discharge of pollutants into regulated waters, except in accordance with the terms of a permit issued by the EPA or analogous state agency and impose substantial liabilities for noncompliance. The CWA also regulates the discharge of storm water runoff from certain industrial facilities. Accordingly, several of our facilities are required to obtain and maintain storm water discharge permits, which require monitoring and sampling of storm water runoff from such facilities. While we have experienced permit discharge exceedances at some of our terminals, from time to time, we do not anticipate any material liabilities as a result of such exceedances and, furthermore, do not anticipate that foreseeable new permit requirements will have a material adverse effect on our financial position or results of operations.
The CWA further prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit, and there continues to be uncertainty on the federal government’s applicable jurisdictional reach over waters of the United States, including wetlands. The EPA and U.S. Army Corps of Engineers (the “Corps”) under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. While the EPA and Corps under the Trump Administration issued a final rule in January 2021 narrowing federal jurisdictional reach over waters of the United States, President Biden issued an executive order to further review and assess these regulations consistent with the new administration’s policy objectives, following which the EPA and Corps announced plans in June 2021 to initiate a new rulemaking process that would repeal the 2020 rule and restore protections that were in place prior to the 2015. Although the EPA and Corps did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico have vacated the 2020 rule in decisions announced during the third quarter of 2021. While these district court decisions may be appealed, it is clear that the EPA and Corps intend to adopt a more expansive definition for waters of the United States. As an initial step, the agencies published on December 7, 2021 a proposed rulemaking that would put back into place the pre-2015 definition of “waters of the United States” in effect prior to 2015 rule issued under the Obama Administration and updated to reflect consideration of Supreme Court decisions. The proposed rule, if adopted would serve as an interim approach to “waters of the United States” and provide the agency with time to develop a subsequent rule that builds upon the currently proposed rule based, in part, on additional stakeholder involvement. Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the CWA and the definition of WOTUS. As a result of these developments, the scope of jurisdiction under the CWA is uncertain at this time. To the extent any rule expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Air Emissions
Our operations are subject to the CAA and comparable state and local laws. Under such laws, permits are typically required to emit pollutants into the atmosphere above certain thresholds. The trend in air emissions regulation is to place more restrictions and limitations on activities that may affect the environment. If more restrictive air laws and regulations are enacted in the future, they may have a material adverse effect on our financial condition or results of operations.
Various federal, state and local agencies have the authority to prescribe product quality specifications for the refined products that we sell, largely in an effort to reduce air pollution. Failure to comply with these regulations can result in substantial penalties. Historically, our compliance costs with the existing requirements of the CAA and similar state laws have not been material but there can be no assurance that such costs will not be material in the future.
Changes in product quality specifications could require us to incur additional handling costs or reduce our throughput volume. For instance, different product specifications for different markets could require the construction of additional storage. Also, states in which we operate have either started or plan to limit the sulfur content of home heating oil, which could also increase our costs to purchase such oil or limit our ability to sell heating oil.
Changing sulfur regulations also impact the residual fuel oil business. Restrictions on certain grades of product and in certain cases, banning residual fuel oil in certain municipalities or regions, will force us to reconfigure existing tanks that are in residual fuel oil service.
Climate Change
The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions.
No comprehensive climate change legislation has been implemented at the United States federal level, but President Biden has made the combat of climate change arising from GHG emissions a priority under his Administration and has issued, and may continue to issue, executive orders or other regulatory initiatives in pursuit of his regulatory agenda. The EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources and require the monitoring and annual reporting of GHG emissions from certain specified large GHG emissions sources. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, GHG reporting and tracking programs, and restriction of GHG emissions. While our operations fall below the thresholds that would characterize large sources, we are required to implement systems to track certain purchases of product and, historically, the costs of complying with such tracking requirements has not been material.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, GHG reporting and tracking programs, and restriction of GHG emissions. For example, a number of states, including Connecticut, Maine, New Hampshire, New York and Pennsylvania, have introduced legislation to establish taxes or assessments on the carbon content of fuels. These states and others also participate in, or may soon join, interstate efforts such as the Regional Greenhouse Gas Initiative (“RGGI”), a cap-and-trade program to limit emissions from the power sector. Future efforts at the state level to limit emissions associated with transportation fuels and heating fuels could increase costs, reduce the market for, or impact the pricing of, our products, and thus adversely impact our business.
Overall, there has been a trend towards increased regulation of GHGs and initiatives, both domestically and internationally, to limit GHG emissions. Future efforts to limit emissions associated with transportation fuels and heating fuels could reduce the market for, or pricing of, our products, and thus adversely impact our business. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50% - 52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”), during which the multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 counties joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.
In addition to the regulatory efforts described above, activists concerned about the potential effects of climate change have, in certain instances, directed their attention at sources of funding for fossil-fuel energy companies. This could make it more difficult to secure funding for projects. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. Additionally, financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. For example, the Federal Reserve has joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector and, in November 2021, issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. The SEC has also announced that it will promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, and we cannot predict what any such rules may require to the extent the rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient.
Kildair is subject to both Canadian federal and provincial environmental regulations relating to climate change, GHG emissions, fuel content requirements, and energy policies, including, without limitation, regulations that require the purchase of emission allowances, credits and/or compliance units needed to cover emissions attributable to the combustion of some fossil fuels it sells for consumption or otherwise related to the renewable fuel content of such fuels. These laws and regulations are currently under review by the federal and provincial authorities and, as a result, modifications to the regulatory framework is expected in the near future, notably involving the imposition of a carbon levy on products sold by Kildair as well as carbon intensity reduction requirements on such products. In December 2021, the federal government published an update to the federal carbon pricing benchmark beyond 2022. Under the updated scheme, the minimum national carbon pollution price has been established for 2023 to 2030, with the carbon price set at CAD$65/tonne in 2023 with a further annual increase of CAD$15 per year up to to $170/tonne in 2030. To comply with these laws and regulations, Kildair must, and will, incur costs such as, for example, the cost to purchase allowances, credits and compliance units, that allow Kildair to continue operations at its current or increased levels. Increased costs may result in increased prices for Kildair’s products or decreased profitability. Increased product price as well as the laws and regulations applicable to Kildair's customers, who are themselves subject to laws and regulations relating to climate change, GHG emissions, and energy policies, could result in a reduction of demand for Kildair’s product and therefore reduce our revenues. Additional risks include the inability of Kildair to acquire the required amount of emission allowances, credits or compliance units to offset emissions and/or meet the renewable fuel content which would subject Kildair to various fines.
Additionally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets and thus could have an adverse effect on our exploration and production operations. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production. While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions in areas where we operate could result in increased compliance costs or costs of consuming fossil fuels. Additionally, political, financial and litigation risks may result in us restricting, delaying or canceling certain operational activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner. The occurrence of one or more of these developments could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Members of the investment community have recently increased their focus on sustainability practices, including practices related to GHGs and climate change, in the oil and natural gas industry. As a result, we and others in our industry have come under increasing pressure to improve our sustainability practices. Additionally, members of the investment community have begun to screen companies such as ours for sustainability performance before investing in our common units. If we are unable to establish adequate sustainability practices, our common unit price may be negatively impacted, our reputation may be negatively affected, and it may be more difficult for us to compete effectively. Our efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to perform services for certain customers.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Common units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business.
If any of the following risks were actually to occur, our business, financial condition, results of operations and ability to pay distributions to our unitholders could be materially adversely affected. Additional risks and uncertainties not currently known to us or that we currently consider to be immaterial may also materially adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.
Risks Related to Our Business
We may not have sufficient distributable cash flow following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our General Partner and its affiliates, to enable us to pay the current quarterly distribution of $0.4338 to our unitholders.
For the quarter ended December 31, 2021, we paid a distribution of $0.4338 per unit, which is significantly less than the minimum quarterly distribution of $0.6675 per unit. In order to pay a quarterly distribution amount of $0.4338 per unit per quarter, or $1.73 per unit on an annualized basis, we will require distributable cash flow of $11.4 million per quarter, or $45.6 million per year, based on the number of common units currently outstanding. We may not have sufficient distributable cash flow each quarter to enable us to pay the quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations and our borrowing capacity, which will fluctuate from quarter to quarter based on, among other things:
•Competition from other companies that sell refined products, natural gas, renewable fuels and material handling businesses in the Northeast United States and eastern Canada as well as demand for such products and services;
•Absolute price levels, and volatility of prices, of refined products and natural gas in both the spot and futures markets;
•Seasonal variation in temperature, which affects demand for natural gas and refined products such as heating oil and residual fuel oil (to the extent that it is used for space heating); and
•Prevailing economic and regulatory conditions.
In addition, the actual amount of distributable cash flow that we distribute will depend on other factors such as:
•The level of maintenance capital expenditures we make;
•The level of operating and general and administrative expenses, including reimbursements to our General Partner and certain of its affiliates for services provided to us;
•Fluctuations or changes in federal, state, local and foreign tax rates, including Canadian income and withholding tax rates;
•The restrictions contained in our Credit Agreement (as defined herein), including borrowing base limitations and limitations on distributions as well as debt service requirements;
•Fluctuations in our working capital needs;
•Our ability to access capital markets and to borrow under our Credit Agreement to make distributions to our unitholders; and
The COVID-19 pandemic could adversely impact our business, financial condition and results of operations.
The global outbreak of the novel coronavirus ("COVID-19") was declared a pandemic by the World Health Organization and a national emergency by the U.S. Government in March 2020 and has negatively affected the U.S. and global economy - including commodity and stock volatility, disrupted global supply chains, travel and transport restrictions, mandated closures and orders to “shelter-in-place,” and disruption of the financial markets. As a result of the pandemic, we experienced a period of lower revenues in certain customer sectors, particularly during the period from March 2020 through December 2020.
In 2021, a wide array of sectors continued to be affected by COVID-19, and its variants, including but not limited to energy, transportation, manufacturing and commercial and retail businesses and global economic conditions continued to be volatile. Some of the Partnership’s commercial and industrial customers continue to experience impacts to their operations due to reduced demand and increased government restrictions, particularly as it relates to the shutdown or limitations imposed on various businesses. While we expect that many of these effects will not be permanent, it is impossible to predict their duration.
With the easing of restrictions, health advancements and other ongoing measures to alleviate the pandemic in 2021, demand for refined products appears to have normalized and fuel prices are now at levels higher than pre-pandemic. While stabilization is a positive trend, there is risk of permanent demand destruction if economic conditions deteriorate, or if some businesses are unable to recover. In order to continue to mitigate the effects of the pandemic, even as market conditions have improved, we continue to focus on the safety of employees and other stakeholders as well as a number of initiatives relating to cost reduction, liquidity and operating efficiencies.
The Partnership makes estimates and assumptions that affect the reported amounts on these condensed consolidated financial statements and accompanying notes as of the date of the financial statements. The Partnership assessed accounting
estimates that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses, the carrying value of goodwill, intangible assets, and other long-lived assets. This assessment was conducted in the context of information reasonably available to the Partnership, as well as consideration of the future potential impacts of COVID-19, and its variants, on the Partnership’s business as of December 31, 2021. While market conditions for our products and services appear to have stabilized as compared to a year ago, the pandemic remains fluid, indicating that the full impact may not have been realized across our business and operations. The economic and operational landscape has been altered, and it is difficult to determine whether such changes are temporary or permanent, with challenges related to staffing, supply chain, and transportation globally. Accordingly if the impact is more severe or longer in duration than the Partnership has assumed, such impact could potentially result in impairments and increases in credit allowances. As we strategize with regard to fiscal year 2022 and beyond, the Partnership continues to monitor the evolving impacts of COVID-19 and its variants closely and adapting our operations to changing demand patterns and the potential impact of the COVID-19 pandemic on future cash flows and access to adequate liquidity.
Our business is seasonal and generally our financial results are lower in the second and third quarters of the calendar year which may result in an increased need to borrow money in order to make quarterly distributions to our unitholders during these quarters.
Demand for natural gas and some refined products, specifically home heating oil and residual fuel oil for space heating purposes, is generally higher during the period of November through March than during the period of April through October. Therefore, our results of operations for the first and fourth calendar quarters are generally better than for the second and third calendar quarters. For example, over the 36-month period ended December 31, 2021, we generated an average of 76% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States and Canada. With reduced cash flow during the second and third calendar quarters, we may be required to borrow money in order to pay the minimum quarterly distribution to unitholders. Any restrictions on our ability to borrow could restrict our ability to make quarterly distributions to unitholders.
A significant decrease in demand for refined products, natural gas or our materials handling services in the areas we serve would adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
A significant decrease in demand for refined products, natural gas or our materials handling services in the areas that we serve would significantly reduce net sales and, therefore, adversely affect our business, financial condition, results of operations, our ability to borrow and make quarterly distributions to our unitholders. Factors that could lead to a decrease in market demand for refined products or natural gas include:
•Recession or other adverse economic conditions, including but not limited to, public health crises that reduce economic activity, affect the demand for travel (public and private), as well as impact costs of operation and availability of supply (including the coronavirus COVID-19 pandemic);
•Unseasonably warm temperatures or higher prices;
•Increased conservation, technological advances and the availability of alternative energy, whether as a result of industry changes, governmental or regulatory actions or otherwise; and,
•Conversion from consumption of heating oil or residual fuel oil to natural gas as such switching and conversions could reduce our sales of heating oil and residual fuel oil.
Factors that could lead to a decrease in demand for our materials handling services include weakness in the housing and construction industries and the economy generally.
Certain of our operating costs and expenses are fixed and do not vary with the volumes we store, distribute and sell. These costs and expenses may not decrease ratably, or at all, should we experience a reduction in volumes stored, distributed and sold. As a result, we may experience declines in operating margin if our volumes decrease.
Our business, financial condition, results of operations and ability to make quarterly distributions to unitholders are influenced by changes in demand for, and therefore indirectly by changes in the prices of, refined products and natural gas, which could adversely affect our profit margins, our customers’ and suppliers’ financial condition, contract performance, trade credit and the amount and cost of borrowing under our Credit Agreement.
Financial and operating results from our purchasing, storing, terminalling and selling operations are influenced by price volatility in the markets for refined products and natural gas. When prices for refined products and natural gas rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs to our customers, resulting in lower margins for a period of time before margins expand to cover the incremental costs. Significant increases in the costs of refined products can materially increase our costs to carry inventory. We use the working capital facility in our Credit Agreement, which limits the amounts that we can borrow, as the primary source of financing for our working capital requirements. Lastly, higher prices for refined products or natural gas may (1) diminish our access to trade credit support or
cause it to become more expensive and (2) decrease the amount of borrowings available for working capital as a result of total available commitments, borrowing base limitations and advance rates thereunder.
Restrictions in our Credit Agreement could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders as well as the value of our common units.
We are dependent upon the earnings and cash flow generated by operations in order to meet our debt service obligations and to allow us to make cash distributions to unitholders. The operating and financial restrictions and covenants in our Credit Agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue business, which may, in turn, adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. Our Credit Agreement contains covenants requiring us to maintain certain financial ratios. The provisions of the Credit Agreement may affect our ability to obtain future financing for and pursue attractive business opportunities and maintain flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the Credit Agreement could result in an event of default which could enable our lenders, subject to the terms and conditions of our Credit Agreement, to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. See Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources."
Warmer weather conditions during winter could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Weather conditions during winter have an impact on the demand for heating oil, residual fuel oil and natural gas. Because we supply distributors whose customers depend on heating oil, residual fuel oil and natural gas during the winter, warmer-than-normal temperatures during the first and fourth calendar quarters in one or more regions in which we operate can decrease the total volume we sell and the adjusted gross margin realized on those sales and, consequently, our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Our risk management policies, processes and procedures cannot eliminate all commodity price risk or basis risk, which could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. In addition, any noncompliance with our risk management policies, processes and procedures could result in significant financial losses.
While our risk management policies, processes and procedures are designed to limit commodity price risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, we change our hedged position daily in response to movements in our inventory. If we overestimate or underestimate sales from inventory, we may be unhedged for the amount of the overestimate or underestimate. Although 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 that these steps will detect and/or prevent all violations of such risk management policies, processes and procedures.
Some of our refined products and natural gas competitors have capital resources many times greater than ours and control greater supplies. Competitors able to supply customers with products and services at a lower price could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Our competitors include terminal companies, major integrated oil companies and their marketing affiliates and independent marketers of varying size, financial resources and experience. Some of our competitors are substantially larger than us, have capital resources many times greater than ours, control greater supplies of refined products and natural gas than us and/or control substantially greater storage capacity than us.
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our customers and employees, in data centers and on our networks. The secure maintenance of this information is critical to our operations. Despite our security measures, information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disrupt operations and the services we provide to customers, damage our reputation, and cause a loss of confidence in our products and services, which could adversely affect business/operating margins, revenues and competitive position.
A principal focus of our business strategy is to grow and expand our business through acquisitions. If we do not make acquisitions on economically acceptable terms, our future growth may be limited and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.
A principal focus of our business strategy is to grow and expand our business through acquisitions. Our ability to grow depends, in part, on our ability to make accretive acquisitions that result in an increase in cash from operations generated per unit. If we are unable to make accretive acquisitions, either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, such acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.
Any acquisition involves potential risks, including, among other things:
•Mistaken assumptions about volumes, cash flows, net sales and costs, including synergies;
•An inability to successfully integrate the businesses we acquire;
•An inability to hire, train or retain qualified personnel to manage and operate our newly acquired assets;
•The assumption of unknown liabilities;
•Unforeseen difficulties operating in new product areas or new geographic areas; and
•Customer or key employee losses at the acquired businesses.
A portion of our net sales is generated under contracts that must be renegotiated or replaced periodically. If we are unable to successfully renegotiate or replace these contracts, our business, financial condition, results of operations and ability to make quarterly distributions to unitholders could be adversely affected.
Most of our contracts with refined products customers are for a single season or on a spot basis, while most of our contracts with natural gas customers are for a term of one year or less. As these contracts and our materials handling contracts expire from time to time, they must be renegotiated or replaced. While our materials handling contracts are generally long-term, they are also subject to periodic renegotiation or replacement. If we cannot successfully renegotiate or replace any of our contracts, or if we renegotiate or replace them on less favorable terms, net sales and margins from these contracts could decline and our business, financial condition, results of operations and ability to make quarterly distributions to unitholders could be adversely affected.
Due to our lack of geographic diversification, adverse developments in the terminals we use or in our operating areas would adversely affect results of operations and distributable cash flow.
Our operations are largely located in the Northeast United States and eastern Canada. Due to our lack of geographic diversification, an adverse development in the businesses or areas in which we operate, including adverse developments due to catastrophic events, weather or decreases in demand for refined products or materials handling services, could have a significantly greater impact on our results of operations and distributable cash flow than if we operated in more diverse locations.
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. If any event of a substantial nature were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of related operations.
We may be unable to maintain or obtain insurance of the type and amount we believe to be appropriate for our business at reasonable rates or at all. As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase or escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Certain types of risks, such as fines and penalties, or remediation or damages claims from environmental pollution, are either not covered by insurance or applicable insurance may be unavailable for particular claims based on exclusions or limitations in the policies.
Our terminalling and materials handling operations are subject to federal, state and local laws and regulations relating to environmental protection and operational safety and health that expose us to substantial costs and that may become more stringent over time.
A fundamental risk inherent in terminalling and materials handling operations is that we may incur substantial environmental costs and liabilities. In particular, our terminalling operations involve the receipt, storage and redelivery of refined products and are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects, including the discharge of materials into the environment, or otherwise relating to the protection of the environment, operational safety and related matters. We are also subject to laws and regulations that impose product quality
specifications that could have a material adverse effect on our business. The trend of more expansive and stringent environmental and occupational safety and health legislation and regulations could continue, resulting in material increases in our costs of doing business and consequently affecting profitability. See “Item 1. Business-Environment” for more discussion on these environmental and occupational health and safety matters. Compliance with existing environmental and occupational safety and health laws, regulations, executive orders and other regulatory initiatives, or any other such new legal requirements, could, among other things, require us to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital or operating expenditures, which costs may be significant. One or more of these developments that impact us could have a material adverse effect on our business, results of operations and financial condition, reduce demand for our services, and ability to make quarterly distributions to our unitholders.
The risks of spills and releases and the associated liabilities for investigation, remediation and third-party claims, if any, are inherent in terminalling operations, and the liabilities that we incur may be substantial.
Our operation of refined products terminals and storage facilities as well as our transportation and logistics activities are inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or other hazardous substances. If any of these events have previously occurred or occur in the future, whether in connection with any of our storage facilities or terminals, any other facility to which we send or have sent wastes or by-products for treatment or disposal or on any property which we own or have owned, we could be liable for all costs, jointly and severally, and administrative, civil and criminal penalties associated with the investigation and remediation of such facilities under federal, state and local environmental laws or the common law. We may also be held liable for damages to natural resources, personal injury or property damage claims from third parties, including the owners of properties located near our terminals and those with whom we do business, alleging contamination from spills or releases from our facilities or operations. See “Item 1. Business-Environment” for more discussion on liabilities that may arise as a result of spills and releases of regulated substances.
Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs and reduced demand for refined products as a fuel source, which could in turn reduce demand for our products and adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to eliminate such future emissions. As a result, our operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. See “Item 1. Business-Environment” for more discussion on the threat of climate change and restriction of GHG emissions. The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions could result in increased compliance costs or costs of consuming fossil fuels. Such legislation, executive actions or regulations could result in our increased costs to operate and reduced demand for our services. Additionally, political, financial and litigation risks may result in us restricting, delaying or canceling operational activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner. The occurrence of one or more of these developments could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make quarterly distributions to unitholders.
Increasing attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy, may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our customers. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Additionally, while we may elect to seek out various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we elected
to pursue such target and were able to achieve the desired target levels, such achievement may have been accomplished as a result of entering into various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Notwithstanding our election to pursue aspirational targets in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies or the corresponding infrastructure projects based on climate change related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact our customers, which may adversely impact our business, financial condition or results of operations.
We are subject to federal, state and local laws and regulations that govern the product quality specifications of the refined products we purchase, store, transport and sell.
Various federal, state and local government agencies have the authority to prescribe specific product quality specifications to the sale of commodities. Changes in product quality specifications, such as reduced sulfur content in refined products, or other more stringent requirements for fuels, could reduce our ability to procure or create products of various specifications and limit purchase and storage opportunities associated with market dislocations and discrepancies. Changes in product specifications may require us to incur additional handling costs and capital expenditures. If we are unable to procure product or recover these costs through increased sales, our business would be negatively impacted and we may not be able to meet our financial obligations.
We depend on unionized labor for our operations in Bronx, Lawrence, and Albany, New York; Providence, Rhode Island; and Sorel-Tracy Quebec, Canada. Work stoppages or labor disturbances at these facilities could disrupt our business.
Work stoppages or labor disturbances by our unionized labor force could have an adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to unitholders. In addition, employees who are not currently represented by labor unions may seek representation in the future, and renegotiation of collective bargaining agreements may result in agreements with terms that are less favorable to us than our current agreements.
We rely on our information technology systems to manage numerous aspects of our business, and a disruption of these systems could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
We depend on our information technology, or IT, systems to manage numerous aspects of our business and to provide analytical information to management. Our IT systems are an essential component of our business and growth strategies, and a serious disruption to our IT systems could limit our ability to manage and operate our business efficiently. These systems are vulnerable to, among other things, damage and interruption from power loss or natural disasters, computer system and network failures, loss of telecommunication services, physical and electronic loss of data, security breaches and computer viruses. We employ back-up IT facilities and have disaster recovery plans; however, these safeguards may not entirely prevent delays or other complications that could arise from an IT systems failure, a natural disaster or a security breach. Significant failure or interruption in our IT systems could cause our business and competitive position to suffer and damage our reputation, which would adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to unitholders.
Risks Inherent in an Investment in Us
We distribute significant portions of our distributable cash flow, which could limit our ability to grow and make acquisitions.
We rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute a significant portion of our distributable cash flow, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in the partnership agreement or Credit Agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional
commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may adversely impact the cash that we have available to distribute to unitholders.
Hartree Partners LP indirectly controls our General Partner, which has sole responsibility for conducting our business and managing our operations. Our General Partner and its affiliates, including Hartree, 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.
On April 20, 2021, the Partnership and Hartree Partners, LP ("Hartree") announced that Sprague Holdings entered into an agreement to sell to Sprague HP Holdings, LLC (a wholly owned subsidiary of Hartree) the interest of Sprague Holdings in the General Partner, the incentive distribution rights and all of the common units representing limited partner interests that Sprague Holdings owned in the Partnership (the “Transaction”). The Transaction was completed and effective on May 28, 2021.
•Our General Partner is allowed to take into account the interests of parties other than us, such as its affiliates, including Hartree and its affiliates, in resolving conflicts of interest, which has the effect of limiting its duty to our unitholders.
•Affiliates of our General Partner, including Hartree and Sprague Holdings, may engage in competition with us.
•Neither our partnership agreement nor any other agreement requires Hartree or Sprague Holdings to pursue a business strategy that favors us.
•Our partnership agreement limits the liability of and reduces the duties owed by our General Partner to us and our common unitholders, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
•Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval.
•Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reductions or increases of cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders and to the holders of the incentive distribution rights.
•Our General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces distributable cash flow. Such determination can affect the amount of distributable cash flow available to the holders of our common units and to the holders of the incentive distribution rights. Our partnership agreement does not limit the amount of maintenance capital expenditures that our General Partner can cause us to make.
•Our partnership agreement and the services agreement allow our General Partner to determine, in good faith, the expenses that are allocable to us. Our partnership agreement and the services agreement do not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. These expenses include salary, incentive compensation and other amounts paid to persons, including affiliates of our General Partner, who perform services for us or on our behalf.
•Our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, including incentive distributions.
•Our partnership agreement permits us to distribute up to $25.0 million as distributable cash flow, even if it is generated from sources that would otherwise constitute capital surplus, and this cash may be used to fund the incentive distributions.
•Our partnership agreement does not restrict our General Partner from entering into additional contractual arrangements with any of its affiliates on our behalf.
•Our General Partner intends to limit its liability regarding our contractual and other obligations.
•Our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of all outstanding common units.
•Our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates.
•Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
•Sprague Holdings, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights without the approval of the conflicts committee of the board of directors of our General Partner or unitholders. This election may result in lower distributions to common unitholders in certain situations.
Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including their executive officers, directors and owners. Other than as provided in our omnibus agreement, any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential
conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders.
Our General Partner intends to limit its liability regarding our obligations.
Our General Partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our partnership agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner’s duty to act in good faith, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of distributable cash flow otherwise available for distribution to unitholders.
Our partnership agreement limits our General Partner’s duties to our unitholders.
Our partnership agreement contains provisions that modify and reduce the standards to which our General Partner would otherwise be held under state fiduciary duty law. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:
•How to allocate business opportunities among us and its other affiliates;
•Whether to exercise its limited call right;
•How to exercise its voting rights with respect to any units it owns;
•Whether to exercise its registration rights with respect to any units it owns; and
•Whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to our unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
•Provides that whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation, or at equity;
•Provides that a determination, other action or failure to act by our General Partner, the board of directors of our General Partner or any committee thereof (including the conflicts committee) will be deemed to be in good faith unless our General Partner, the board of directors of our General Partner or any committee thereof believed such determination, other action or failure to act was adverse to the interests of the Partnership;
•Provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith;
•Provides that our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
•Provides that our General Partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:
1.Approved by the conflicts committee of the board of directors of our General Partner, although our General Partner is not obligated to seek such approval; or
2.Approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Cost reimbursements and fees due to our General Partner and its affiliates for services provided to us or on our behalf, which may be determined in our General Partner’s sole discretion, may be substantial and will reduce our distributable cash flow.
Under our partnership agreement, prior to making any distribution on the common units, our General Partner and its affiliates shall be reimbursed for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Pursuant to the terms of the services agreement, our General Partner has agreed to provide certain general and administrative services and operational services to us, and we have agreed to reimburse our General Partner and its affiliates for all costs and expenses incurred in connection with providing such services to us, including salary, incentive compensation, insurance premiums and other amounts allocable to the employees and directors of our General Partner or its affiliates that perform services on our behalf. Our General Partner and its affiliates also may provide us other services for which we may be charged fees as determined by our General Partner. Our partnership agreement and the services agreement do not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. Payments to our General Partner and its affiliates may be substantial and will reduce the amount of distributable cash flow.
Unitholders have limited voting rights and, even if they are dissatisfied, cannot remove our General Partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner or the board of directors of our General Partner and will have no right to elect our General Partner or the board of directors of our General Partner on an annual or other continuing basis. The board of directors of our General Partner is chosen by Sprague Holdings, a wholly owned subsidiary of Hartree and the sole member of our General Partner. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
The unitholders will be unable to remove our General Partner without its consent because our General Partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2⁄3% of all outstanding common units is required to remove our General Partner. As of March 3, 2022, Sprague Holdings owned 74.5% of our common units.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units resulting in ownership of at or in excess of such levels with the prior approval of the board of directors of our General Partner, cannot vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Sprague Holdings to transfer its membership interest in our General Partner to a third party. The new members of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with their own choices and to control the decisions taken by the board of directors and officers.
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 Hartree accepting offers made by us relating to assets owned by it, as Hartree would have less of an economic incentive to grow our business, which in turn may impact our ability to grow our asset base.
We may issue additional units without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, neither the partnership agreement nor the Credit Agreement prohibits the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
•Our unitholders’ proportionate ownership interest in us will decrease;
•The amount of distributable cash flow on each unit may decrease;
•The ratio of taxable income to distributions may increase;
•The relative voting strength of each previously outstanding unit may be diminished; and
•The market price of our common units may decline.
Sprague Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of March 3, 2022, Sprague Holdings held 19,548,849 common units. We have agreed to provide Sprague Holdings with certain registration rights (which may facilitate the sale by Sprague Holdings of its common units into the public markets). The sale of these units in the public or private markets, or the perception that such sales might occur, could have an adverse impact on the price of the common units or on any trading market that may develop.
We rely on the master limited partnership ("MLP") structure and its appeal to investors for accessing debt and equity markets to finance our growth and repay or refinance our debt. The volatility in energy prices over the past few years has, among other factors, caused increased volatility and contributed to a dislocation in pricing for MLPs.
The volatility in pricing for MLPs and other energy companies may be adversely affected by a lower energy prices environment. A number of MLPs have reduced or eliminated their distributions to unitholders. A protracted deterioration in the valuation of our common units would increase our cost of capital, make any equity issuance significantly dilutive and may affect our ability to access capital markets and, as a result, our capacity to pay distributions to our unitholders and service or refinance our debt.
An increase in interest rates may cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return on government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
Our General Partner’s discretion in establishing cash reserves may reduce the amount of distributable cash flow that we distribute.
The partnership agreement permits our General Partner to reduce the amount of distributable cash flow distributed to our unitholders by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners.
Our General Partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our General Partner or its affiliates.
In some instances, our General Partner may cause us to borrow funds from its affiliates, including Hartree, or from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make incentive distributions.
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 3, 2022, Sprague Holdings and its affiliates owned 74.5% of our common units.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine that:
•We were conducting business in a state but had not complied with that particular state’s partnership statute; or
•Your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.
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 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 target distribution levels at higher levels based on 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 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 target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels.
The New York Stock Exchange (NYSE) does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
As a limited partnership, we are not required to have a majority of independent directors on our General Partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee, as is required for other NYSE-listed entities. Accordingly, unitholders do not have the same protections afforded to certain entities, including most corporations that are subject to all of the NYSE corporate governance requirements.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes, or we become subject to entity level taxation for state tax purposes, our cash available for distribution would be substantially reduced. The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for
U.S. federal income tax purposes unless it satisfies a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely pay additional state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distributions to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
Any modification to the U.S. federal income tax laws or other applicable tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative
developments and proposals and their potential effect on your investment in our common units.
In addition to U.S. federal income tax, we are currently subject to entity level taxes and fees in a number of states and such taxes and fees reduce our distributable cash flow. Changes in current state and local laws may subject us to additional entity-level taxation by individual states and local governments. Additionally, unitholders may be subject to other state and local taxes that are imposed by various jurisdictions in which the unitholder resides or in which we conduct business or own property.
Our partnership agreement provides that if a law is enacted, or existing law is modified or interpreted in a manner, that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or non-U.S. income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
Notwithstanding our treatment for U.S. federal income tax purposes, we are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, our distributable cash flow would be further reduced.
A material amount of our business operations and subsidiaries are subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of our distributable cash flow. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions, the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional tax being imposed on us. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income. Any such increases in tax imposed on us would further reduce our distributable cash flow. Although these taxes may be properly characterized as foreign income taxes, unitholders may not be able to credit them against their liability for U.S. federal income taxes on their share of our earnings.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholders may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for
distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than our unitholders expect.
If a unitholder sells common units, such unitholder will recognize gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease its tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the units being sold will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price received is less than the unitholder’s original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells units, such unitholder may incur a tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, our deduction for "business interest" is limited to the sum of our business interest income and 30% of our "adjusted taxable income." For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.
Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts ("IRAs"), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trades or businesses) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. If you are a tax exempt entity, you should consult your tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ("effectively connected income"). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder's sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Department of the Treasury and the IRS suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022. If you are a non-U.S. person, you should consult your tax adviser before investing in our common units.
If a tax authority contests the tax positions we take, the market for our common units may be adversely affected and the cost of any such contest would reduce our distributable cash flow.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. Tax authorities may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with a tax authority may materially and adversely affect the market for our common units and the price at which they trade. Our costs of any contest with a tax authority will be borne indirectly by our unitholders and our General Partner because the costs will reduce our distributable cash flow.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing our publicly traded units to have different capital accounts, unless the IRS issues further guidance.
In the event the IRS makes an audit adjustment to our income tax return and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Due to a number of factors including our inability to match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of our General Partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g. a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan to the short seller may be considered to have disposed of the loaned units. In that case, such unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business and own property in numerous states, in the United States most of which impose a personal income tax as well as an income tax on corporations and other entities. We may own property or conduct business in other U.S. states or non-U.S. countries that impose a personal income tax in the future. It is the unitholder’s responsibility to file all U.S. federal, state, local and non-U.S. tax returns.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
The following tables set forth information with respect to our owned, operated and/or controlled terminals as of December 31, 2021.
Liquids Storage Terminals Number of
Storage Tanks Storage Tank
Capacity (Bbls) Principal Products and Materials
** Sorel-Tracy Quebec, Canada 27 3,282,600 refined products; asphalt
** Newington, NH: River Road 29 1,157,325 refined products; asphalt; tallow
** Searsport, ME 17 1,141,186 refined products; caustic soda; asphalt
* Bridgeport, CT 13 1,335,000 refined products
* Albany, NY 9 1,103,600 refined products
** South Portland, ME 24 910,484 refined products; asphalt; clay slurry
* East Providence, RI 9 970,436 refined products
** Bronx, NY 18 907,500 refined products; asphalt
** Newington, NH: Avery Lane 12 722,000 refined products, asphalt
* Quincy, MA 9 657,000 refined products
* New Haven, CT (1)
9 517,505 refined products
** Providence, RI 4 484,000 refined products; asphalt
*** Everett, MA 4 317,600 asphalt
* Quincy, MA: TRT (2)
4 304,200 refined products
* Springfield, MA 10 268,200 refined products
* Lawrence, NY 8 148,000 refined products
* Stamford, CT 3 46,600 refined products
* Inwood, NY 2 26,000 refined products
* Washington, PA area - four locations 20 9,071 refined products
Total 231 14,308,307
Dry Storage Terminals Number of Storage
Pads and Warehouses Storage Capacity
(Square Feet) Principal Products and Materials
** Searsport, ME 2 warehouses; 90,000 break bulk; salt; petroleum coke;
15 pads 872,000 heavy lift
** Newington, NH: River Road 3 pads 390,000 salt; gypsum
*** Portland, ME (3)
7 warehouses; 215,000 break bulk; dry bulk; coal;
3 pads 95,000 salt
** South Portland, ME 3 pads 230,000 salt; coal
** Providence, RI 1 pad 75,000 salt
9 warehouses;
Total 25 pads 1,967,000
*Refined Product activities; **Refined Products and Materials Handling activities; *** Materials Handling activities
(1)These tanks are controlled via a storage and throughput agreement with no expiration.
(2)Operating assets and real estate are leased from an unaffiliated third party through April 30, 2025.
(3)One storage warehouse is leased from an unaffiliated third party and the balance of the property is owned by us.
On April 29, 2021, we sold the Oswego terminal to an unaffiliated buyer. In connection with the sale, the Partnership recorded a net gain of $9.0 million which is included within other operating income in the consolidated statements of operations for the year ended December 31, 2021. The remaining $0.7 million of other operating income for the year ended December 31, 2021 relates to a gain associated with a parcel of land sold at the Bronx terminal on April 29, 2021.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
From time to time, we are a party to various legal proceedings or claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the caption Legal, Environmental and Other Proceedings in Note 19 - Commitments and Contingencies to our consolidated financial statements included in Part II, Item 8 of this Annual Report, which information is incorporated by reference into this Item 3.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
Part II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our public common units began trading on the NYSE under the symbol “SRLP” on October 25, 2013. As of March 3, 2022, Sprague Holdings owned 19,548,849 common units, which represents 74.5% of the limited partner interest in us. We have gathered tax information for our known unitholders and from brokers/nominees and, based on the information collected, we have estimated that the number of our beneficial common unitholders was 16,300 at December 31, 2021 and was 12,492 at December 31, 2020.
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
On October 25, 2021, the Partnership announced a distribution cut from $0.6675 per unit to $0.4338 per unit, which is less than the minimum quarterly distribution of $0.6675 per unit. The board of directors of our General Partner will determine the amount of our quarterly distributions and may change our distribution policy at any time. The board of directors of our General Partner may determine to reserve or reinvest excess cash in order to permit gradual or consistent increases in quarterly distributions and may borrow to fund distributions in quarters when we generate less distributable cash flow than necessary to sustain or grow our cash distributions per unit.
There is no guarantee that unitholders will receive quarterly cash distributions from us. We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate. Uncertainties regarding future cash distributions to our unitholders include, among other things, the following factors:
•Our cash distribution policy may be affected by restrictions on distributions under our Credit Agreement as well as by restrictions in future debt agreements that we enter into. Specifically, our Credit Agreement contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions or if we are otherwise in default under our Credit Agreement, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.
•Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy.
•Under Section 17-607 of the Delaware Act we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
•We may lack sufficient cash to make distributions to our unitholders due to a number of operational, commercial and other factors or increases in our operating costs, general and administrative expenses, principal and interest payments on our outstanding debt and working capital requirements.
•If we make distributions out of capital surplus, as opposed to distributable cash flow, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. We do not anticipate that we will make any distributions from capital surplus.
•Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership, limited liability company and corporate laws and other laws and regulations.
See Part I, Item 1A - Risk Factors -Risk Related to our Business.
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.
Incentive Distribution Rights
On February 11, 2021, Sprague Holdings provided notice to the Partnership that Sprague Holdings had made an IDR Reset Election (the “IDR Reset Election”), as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the “Partnership Agreement”). Pursuant to the IDR Reset Election, Sprague Holdings relinquished the right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of the Partnership’s initial public offering and the Partnership issued 3,107,248 common units to Sprague Holdings. Pursuant to the IDR Reset Election, the levels at which the incentive distribution rights participate in distributions were reset at higher amounts based on then-current common unit distribution rates and a formula in the Partnership Agreement. The IDR Reset Election was effective on March 5, 2021, and as part of the IDR Reset Election, the target distribution levels were adjusted as follows: (i) the Minimum Quarterly Distribution was reset to equal $0.6675 per Common Unit per Quarter, (ii) the First Target Distribution was reset to equal $0.7676 per Common Unit per Quarter, (iii) the Second Target Distribution was reset to equal $0.8344 per Common Unit per Quarter and (iv) the Third Target Distribution was reset to equal $1.0013 per Common Unit per Quarter.
Issuer Purchases of Equity Securities
None.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved
This item is reserved as a result of the Partnership’s adoption of Item 301 of Regulation S-K, pursuant to rules adopted by the Securities and Exchange Commission on November 19, 2020, which included removing the requirement to include selected financial data.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and notes to the Consolidated Financial Statements included elsewhere in this report, as well as the other financial information appearing elsewhere in this Annual Report. This section of this Form 10-K generally includes comparisons of certain 2021 financial information to the same information for 2020. Year-to-year comparisons of the 2020 financial information to the same information for 2019 that are not included in this Form 10-K are contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 filed with the SEC on March 4, 2021, which comparative information is incorporated by reference herein.
A reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Part IV, Item 15 - “Exhibits and Financial Statement Schedules” of this Annual Report.
Overview
We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and provide storage and handling services for a broad range of materials. In October 2013, we became a publicly traded master limited partnership ("MLP") and our common units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP."
Our Predecessor was founded in 1870 as the Charles H. Sprague Company in Boston, Massachusetts; and, in 1905, the company opened the Penobscot Coal and Wharf Company, a tidewater terminal located in Searsport, Maine. By World War II, the company was operating eleven terminals and a fleet of two dozen vessels transporting coal and other products throughout the world. As fuel needs diversified in the United States, the company expanded its product offerings and invested in terminals, tankers, and product handling activities. In 1959, the company expanded its oil marketing activities via entry into the distillate oil market. In 1970, the company was sold to Royal Dutch Shell’s Asiatic Petroleum subsidiary; and, in 1972, Royal Dutch Shell sold the company to Axel Johnson Inc., a member of the Axel Johnson Group of Stockholm, Sweden.
On April 20, 2021, the Partnership and Hartree Partners, LP ("Hartree") announced that Sprague Holdings entered into an agreement to sell to Sprague HP Holdings, LLC (a wholly-owned subsidiary of Hartree) the interest of Sprague Holdings in the General Partner, the incentive distribution rights and all of the common units representing limited partner interests that Sprague Holdings owned in the Partnership (the “Transaction”). The Transaction was completed and effective on May 28, 2021 and the aggregate purchase price was $290.0 million, consisting of approximately $265.0 million attributable to the purchase of 16,058,484 common units and approximately $25.0 million attributable to the general partner interest and incentive distribution rights. The Partnership elected to not to apply push-down accounting in its consolidated financial statements upon the change in control on May 28, 2021.
On January 11, 2022, the Partnership received an unsolicited non-binding proposal from Hartree, pursuant to which Hartree would acquire all of the outstanding common units of the Partnership that Hartree and its affiliates do not already own in exchange for $16.50 in cash for each such common unit. The board of directors of the General Partner has delegated authority to evaluate and negotiate the proposal to its conflicts committee. The conflicts committee's evaluation process is currently ongoing.
The Partnership is one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of refined products and materials handling terminals and storage facilities predominantly located in the Northeast United States from New York to Maine and in Quebec, Canada that have a combined storage tank capacity of approximately 14.3 million barrels for refined products and other liquid materials, as well as approximately 2.0 million square feet of materials handling capacity. We also have access to approximately 48 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
We operate under four business segments: refined products, natural gas, materials handling and other operations. See Note 17 - Segment Reporting to our Consolidated Financial Statements for a presentation of financial results by reportable segment and see Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations" for a discussion of financial results by segment.
In our refined products segment we purchase a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sell them to
our customers. We have wholesale customers who resell the refined products we sell to them and commercial customers who consume the refined products directly. Our wholesale customers consist of approximately 1,100 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, drill sites, large industrial companies, real estate management companies, hospitals, educational institutions, and asphalt paving companies. In addition, our customers include businesses engaged in the development of natural gas resources in Pennsylvania and surrounding states.
In our natural gas segment we purchase natural gas from natural gas producers and trading companies and sell and distribute natural gas to approximately 15,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States.
Our materials handling segment is generally conducted under multi-year agreements as either fee-based activities or as leasing arrangements when the right to use an identified asset (such as storage tanks or storage locations) has been conveyed in the agreement. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. Historically, a majority of our materials handling activity has generated qualified income.
Our other operations segment primarily includes the marketing and distribution of coal conducted in our Portland, Maine terminal, and commercial trucking activity conducted by our Canadian subsidiary.
We take title to the products we sell in our refined products and natural gas segments. In order to manage our exposure to commodity price fluctuations, we use derivatives and forward contracts to maintain a position that is substantially balanced between product purchases and product sales. We do not take title to any of the products in our materials handling segment.
Our foreign sales, primarily sales of refined products and natural gas to customers in Canada, were $301.4 million, $185.1 million and $255.5 million for the years ended December 31, 2021, 2020 and 2019, respectively. Long-lived assets (exclusive of intangible and other assets, net, and goodwill) classified by geographic location were as follows:
As of December 31,
2021 2020
United States $ 257,976 $ 266,469
Canada 65,654 68,827
Total $ 323,630 $ 335,296
COVID-19
The global outbreak of the novel coronavirus (COVID-19) was declared a pandemic by the World Health Organization and a national emergency by the U.S. Government in March 2020 and has negatively affected the U.S. and global economy - including commodity and stock volatility, disrupted global supply chains, resulted in significant travel and transport restrictions, including mandated closures and orders to “shelter-in-place,” and created significant disruption of the financial markets. As a result, we experienced a period of lower revenues in certain customer sectors, particularly during the period from March 2020 through December 2020.
In 2021, a wide array of sectors continued to be impacted by COVID-19 and its variants, including, but not limited to, the energy, transportation, manufacturing and commercial and retail businesses. Global economic conditions also continued to be negatively impacted by the pandemic. Some of the Partnership’s commercial and industrial customers in these industries continue to experience substantial reductions in their operations due to reduced demand and increased government restrictions, particularly as it relates to the shutdown of various businesses in affected regions. While we expect that many of these effects will not be permanent, it is impossible to predict their duration.
With the easing of restrictions, health advancements and other ongoing measures to alleviate the pandemic in 2021, customer demand has started to normalize and fuel prices now at higher levels than pre-pandemic. While the stabilization is a positive trend, there continues to be a risk of permanent demand destruction if economic conditions deteriorate, or if some businesses are unable to recover. In order to continue to mitigate the effects of the pandemic, even as market conditions have improved, we continue to focus on the safety of employees and other stakeholders as well as a number of initiatives relating to cost reduction, liquidity and operating efficiencies.
The Partnership makes estimates and assumptions that affect the reported amounts on these consolidated financial statements and accompanying notes as of the date of the financial statements. The Partnership assessed accounting estimates that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses, the carrying value of goodwill, intangible assets, and other long-lived assets. This assessment was conducted in the context of
information reasonably available to the Partnership, as well as consideration of the future potential impacts of COVID-19, and its variants, on the Partnership’s business as of December 31, 2021. While market conditions for our products and services appear to have stabilized as compared to a year ago, the pandemic remains fluid, indicating that the full impact may not have been realized across our business and operations. The economic and operational landscape has been altered, and it is difficult to determine whether such changes are temporary or permanent, with challenges related to staffing, supply chain, and transportation globally. Accordingly if the impact is more severe or longer in duration than the partnership has assumed, such impact could potentially result in impairments and increases in credit allowances. As we strategize with regard to fiscal year 2022 and beyond, the Partnership continues to monitor the evolving impacts of COVID-19 and its variants closely and adapting our operations to changing demand patterns and the potential impact of the COVID-19 pandemic on future cash flows and access to adequate liquidity.
IDR Reset Election
On February 11, 2021, Sprague Holdings provided notice to the Partnership that Sprague Holdings had made the IDR Reset Election. Pursuant to the IDR Reset Election, Sprague Holdings relinquished the right to receive incentive distribution payments based on the minimum quarterly and target cash distribution levels set at the time of the Partnership’s initial public offering and the Partnership issued 3,107,248 common units to Sprague Holdings. Pursuant to the IDR Reset Election, the levels at which the incentive distribution rights participate in distributions were reset at higher amounts based on then-current common unit distribution rates and a formula in the Partnership Agreement. The IDR Reset Election was effective on March 5, 2021, and as part of the IDR Reset Election, the target distribution levels were adjusted as follows: (i) the Minimum Quarterly Distribution was reset to equal $0.6675 per Common Unit per Quarter, (ii) the First Target Distribution was reset to equal $0.7676 per Common Unit per Quarter, (iii) the Second Target Distribution was reset to equal $0.8344 per Common Unit per Quarter and (iv) the Third Target Distribution was reset to equal $1.0013 per Common Unit per Quarter.
How Management Evaluates Our Results of Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) adjusted EBITDA and adjusted gross margin, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.
EBITDA, adjusted EBITDA and adjusted gross margin used in this Annual Report are non-GAAP financial measures. We also present maintenance capital expenditures and expansion capital expenditures, additional non-GAAP financial measures, as described in "Liquidity and Capital Resources - Capital Expenditures" of this Annual Report.
EBITDA and Adjusted EBITDA
Management believes that adjusted EBITDA is an aid in assessing repeatable operating performance that is not distorted by non-recurring items or market volatility and the ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our unitholders.
We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA adjusted for the change in unrealized hedging gains (losses) with respect to refined products and natural gas inventory as well as natural gas transportation contracts, changes in the fair value of contingent consideration, impact of acquisition related expenses and other operating income.
EBITDA and adjusted EBITDA are used as supplemental financial measures by external users of our financial statements, such as investors, trade suppliers, research analysts and commercial banks to assess:
•The financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;
•The ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our equity holders;
•Repeatable operating performance that is not distorted by non-recurring items or market volatility; and
•The viability of acquisitions and capital expenditure projects.
EBITDA and adjusted EBITDA are not prepared in accordance with GAAP and should not be considered alternatives to net income (loss) or operating income (loss), or any other measure of financial performance presented in accordance with
GAAP. EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income (loss) and operating income (loss).
The GAAP measure most directly comparable to EBITDA and adjusted EBITDA is net income (loss). EBITDA and adjusted EBITDA should not be considered as alternatives to net income (loss) or cash provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and adjusted EBITDA are not presentations made in accordance with GAAP and have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Because EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income (loss) and are defined differently by different companies, our definitions of EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies.
We recognize that the usefulness of EBITDA and adjusted EBITDA as evaluative tools may have certain limitations, including:
•EBITDA and adjusted EBITDA do not include interest expense. Because we have borrowed money in order to finance our operations, interest expense is a necessary element of our costs and impacts our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations;
•EBITDA and adjusted EBITDA do not include depreciation and amortization expense. Because capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits, any measure that excludes depreciation and amortization expense may have material limitations;
•EBITDA and adjusted EBITDA do not include provision for income taxes. Because the payment of income taxes is a necessary element of our costs, any measure that excludes income tax expense may have material limitations;
•EBITDA and adjusted EBITDA do not reflect capital expenditures or future requirements for capital expenditures or contractual commitments;
•EBITDA and adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and
•EBITDA and adjusted EBITDA do not allow us to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss.
Adjusted Gross Margin
Management purchases, stores and sells energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes adjusted gross margin. In determining adjusted gross margin, management adjusts its segment results for the impact of unrealized gains and losses with regard to refined products and natural gas inventory as well as natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income (loss). Adjusted gross margin is also used by external users of our consolidated financial statements to assess our economic results of operations and our commodity market value reporting to lenders.
We define adjusted gross margin as net sales less cost of products sold (exclusive of depreciation and amortization) adjusted for the impact of unrealized gains and losses with respect to refined products and natural gas inventory as well as natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. Adjusted gross margin has no impact on reported volumes or net sales.
Adjusted gross margin is used as a supplemental financial measure by management to describe our operations and economic performance to investors, trade suppliers, research analysts and commercial banks to assess:
•The economic results of our operations;
•The market value of our inventory and natural gas transportation contracts for financial reporting to our lenders, as well as for borrowing base purposes; and
•Repeatable operating performance that is not distorted by non-recurring items or market volatility.
Adjusted gross margin is not prepared in accordance with GAAP and should not be considered as an alternative to net income (loss) or operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
We define adjusted unit gross margin as adjusted gross margin divided by units sold, as expressed in gallons for refined products, and in MMBtus for natural gas.
For a reconciliation of adjusted gross margin and adjusted EBITDA to the GAAP measures most directly comparable, see the reconciliation tables included in Results of Operations. See Segment Reporting included under Note 17 to our Consolidated Financial Statements for a presentation of our financial results by reportable segment.
Management evaluates our segment performance based on adjusted gross margin. Based on the way we manage our business, it is not reasonably possible for us to allocate the components of operating expenses, selling, general and administrative expenses and depreciation and amortization among the operating segments.
Operating Expenses
Operating expenses are costs associated with the operation of the terminals and truck fleet used in our business. Employee wages, pension and 401(k) plan expenses, boiler fuel, repairs and maintenance, utilities, insurance, property taxes, services and lease payments comprise the most significant portions of our operating expenses. Employee wages and related employee expenses included in our operating expenses are incurred on our behalf by our General Partner and reimbursed by us. These expenses remain relatively stable independent of the volumes through our system but can fluctuate depending on the activities performed during a specific period.
Selling, General and Administrative Expenses
Selling, general and administrative expenses ("SG&A") include employee salaries and benefits, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Employee wages, related employee expenses and certain rental costs included in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us.
Heating Degree Days
A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated over the course of a year and can be compared to a monthly or a long-term average ("normal") to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and archived by the National Climate Data Center. In order to incorporate more recent average information and to better reflect the geographic locations of our customer base, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same geographic locations over the previous ten-year period.
Hedging Activities
We hedge our inventory within the guidelines set in our risk management policies. In a rising commodity price environment, the market value of our inventory will generally be higher than the cost of our inventory. For GAAP purposes, we are required to value our inventory at the lower of cost or net realizable value. The hedges on this inventory will lose value as the value of the underlying commodity rises, creating hedging losses. Because we do not utilize hedge accounting, GAAP requires us to record those hedging losses in our income statements. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP requires us to record those hedging gains in our income statements.
The refined products inventory market valuation is calculated using daily independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are primarily based in large, liquid trading hubs including but not limited to, New York Harbor (NYH) or US Gulf Coast (USGC), with our inventory values determined after adjusting these prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to one of these supply sources. Our natural gas inventory is limited, with the valuation updated monthly based on the volume and prices at the corresponding inventory locations. The prices are based on the most applicable monthly Inside FERC, or IFERC, assessments published by Platts near the beginning of the following month.
Similarly, we can hedge our natural gas transportation assets (i.e., pipeline capacity) within the guidelines set in our risk management policy. Although we do not own any natural gas pipelines, we secure the use of pipeline capacity to support our natural gas requirements by either leasing capacity over a pipeline for a defined time period or by being assigned capacity from a local distribution company for supplying our customers. As the spread between the price of gas between the origin and delivery point widens (assuming the value exceeds the fixed charge of the transportation), the market value of the natural gas transportation contracts assets will typically increase. If the market value of the transportation asset exceeds costs, we may seek
to hedge or “lock in” the value of the transportation asset for future periods using available financial instruments. For GAAP purposes, the increase in value of the natural gas transportation assets is not recorded as income in the income statements until the transportation is utilized in the future (i.e., when natural gas is delivered to our customer). If the value of the natural gas transportation assets increase, the hedges on the natural gas transportation assets lose value, creating hedging losses in our income statements. 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 reflect the unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts. By making such adjustments, as reflected in adjusted gross margin and adjusted EBITDA, we believe that we are able to align more closely hedging gains and losses to the period in which the revenue from the sale of inventory and income from transportation contracts relating to those hedges is realized.
Trends and Factors that Impact our Business
This section identifies certain factors and industry-wide trends that may affect our financial performance and results of operations.
•New, stricter environmental laws and regulations are increasing the compliance cost of terminal operations, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state, local and foreign laws and regulations regulating product quality specifications, emissions in the air, discharges to land and water, and the generation, handling, treatment, and disposal of hazardous waste and other materials. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Compliance with laws and regulations may increase our overall cost of business, including our capital cost to maintain and upgrade equipment and facilities.
Within the last year, decarbonization of energy and energy use has become a major focal point for many policymakers leading to decisions aimed at changing the future mix of energy sources. Certain jurisdictions in our operational territories are pursuing efforts to require future new build construction and major renovations to include all-electric buildings with a specific ban on fossil fuel use in new construction. Currently, Massachusetts, Rhode Island and New York are actively pursuing efforts to enact legislation that bans the use of fossil fuels in existing or new buildings, depending on the state. Should policymaker efforts come to fruition, new regulations requiring electric heat could potentially displace traditional heating-related sales growth of refined products and natural gas. However, there is a diversity of opinion on the speed at which the energy mix can change leading to some opposition and to delays in legislative efforts to implement changes aimed at shifting energy consumption, as illustrated by New Hampshire’s recently enacted legislation that would prohibit municipalities from banning certain heat sources.
•Seasonality and weather conditions. Our financial results are impacted by seasonality in our businesses and are generally better during the winter months, primarily because a material part of our business consists of supplying heating oil, residual fuel oil and natural gas for space heating purposes during the winter. For example, over the 36-month period ended December 31, 2021, we generated an average of 76% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States. In addition, weather conditions, particularly during these five months, have a significant impact on the demand for our products. Warmer-than-normal temperatures during these months in our areas of operations can decrease the total volume of heating oil, residual fuel oil and natural gas we sell and the adjusted gross margins realized on those sales, whereas colder-than-normal temperatures increase demand for those products and the associated adjusted gross margins.
•Evolution of the shale gas industry in the Marcellus and Utica formations, among other U.S. regions, can have volatile effects on our financial results. Increased natural gas production can alter the supply and demand balance, price curves, and margin expectations of the Northeastern markets that we serve both in the near and over the long term. The amount of drilling and fracking operations can ebb and flow within these areas. In addition, technology-driven changes such as automated fueling or the use of electric fleets can impact the fuel and manual
support required at these operations. Consequently, we may experience variability in the revenue we receive from this business segment. We can also see variability in the commercial segment such as in the construction industry, at times related to the increase or decrease in fracking and natural gas production, leading to further volatility.
•Absolute price increase or decreases can impact demand and credit risk. Commodity prices in both our refined products and natural gas segments can vary sharply due to market conditions. As commodity product prices rise, we can experience reduced demand as customers engage in conservation efforts, are exposed to a higher level of credit risk to meet customer requirements, and incur increased working capital costs for holding inventory and accounts receivable. In a lower commodity price environment our customers are generally less prone to engage in conservation efforts, we experience lower credit risk, and working capital costs to hold inventory and finance accounts receivable.
•The impact of the market structure on our hedging strategy. We typically hedge our exposure to commodity price moves with NYMEX futures contracts and "over the counter" or "OTC" swaps. In markets where futures prices are higher than spot prices (typically referred to as contango), we generate positive margins when rolling our inventory hedges to successive months. In markets where futures prices are lower than spot prices (typically referred to as backwardation), we realize losses when rolling our inventory hedges to successive months. In backwardated markets, we operate with lower inventory levels and, as a result, have reduced hedging and financing requirements, thereby limiting losses.
•Energy efficiency, new technology and alternative fuels could reduce demand for our products. Increased conservation and technological advances have adversely affected the demand for heating oil and residual fuel oil. Consumption of residual fuel oil, in particular, has steadily declined in recent years, primarily due to customers converting from other fuels to natural gas, weak industrial demand and tightening of environmental regulations. Use of natural gas is expected to continue to displace other fuels, which we believe will favorably impact our natural gas volumes and margins.
•Interest rates could rise. Interest rates could be higher than current levels, causing our financing costs to increase accordingly. During the 24 months ended December 31, 2021, we hedged approximately 48% of our floating-rate debt with fixed-for-floating interest rate swaps. Although higher interest rates could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes.
Results of Operations
Overview
Our current and future results of operations may not be comparable to our historical results of operations. Our results of operations may be impacted by, among other things, swings in commodity prices, primarily in refined products and natural gas, and acquisitions or dispositions. We use economic hedges to minimize the impact of changing prices on refined products and natural gas inventory. As a result, commodity price increases at the end of a year can create lower gross margins as the economic hedges, or derivatives, for such inventory may lose value, whereas an increase in the value of such inventory is disregarded for GAAP financial reporting purposes and recorded at the lower of cost or net realizable value. Please read “How Management Evaluates Our Results of Operations.”
The following tables set forth information regarding our results of operations for the periods presented:
Years Ended December 31, Increase/(Decrease)
2021 2020 $ %
($ in thousands)
Net sales $ 3,498,160 $ 2,335,983 $ 1,162,177 50 %
Cost of products sold (exclusive of depreciation and amortization) 3,343,302 2,071,805 1,271,497 61 %
Operating expenses 80,673 77,070 3,603 5 %
Selling, general and administrative 82,700 81,514 1,186 1 %
Depreciation and amortization 33,335 34,066 (731) (2) %
Total operating costs and expenses 3,540,010 2,264,455 1,275,555 56 %
Other operating income 9,700 8,094 1,606 20 %
Operating (loss) income (32,150) 79,622 (111,772) (140) %
Other income - 1,948 (1,948) (100) %
Interest income 171 299 (128) (43) %
Interest expense (34,109) (40,669) (6,560) (16) %
(Loss) income before income taxes $ (66,088) $ 41,200 $ (107,288) (260) %
Income tax provision (2,828) (7,389) (4,561) (62) %
Net (loss) income $ (68,916) $ 33,811 $ (102,727) (304) %
Reconciliation to Adjusted Gross Margin, EBITDA and Adjusted EBITDA
The following table sets forth a reconciliation of our consolidated operating income to our total adjusted gross margin, a non-GAAP measure, for the periods presented and a reconciliation of our consolidated net income to EBITDA and Adjusted EBITDA, non-GAAP measures, for the periods presented. See above "Management’s Discussion and Analysis of Financial Condition and Results of Operations - EBITDA and Adjusted EBITDA" of this report. The table below also presents information on weather conditions for the periods presented.
Years Ended December 31,
2021 2020
($ in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:
Operating (loss) income $ (32,150) $ 79,622
Operating costs and expenses not allocated to operating segments:
Operating expenses 80,673 77,070
Selling, general and administrative 82,700 81,514
Depreciation and amortization 33,335 34,066
Other operating income (4) (9,700) (8,094)
Add/(deduct):
Change in unrealized (loss) gain on inventory (1) (13,437) 20,148
Change in unrealized value on natural gas transportation contracts (2) 132,554 (9,565)
Total adjusted gross margin (3): $ 273,975 $ 274,761
Adjusted Gross Margin by Segment:
Refined products $ 150,419 $ 171,626
Natural gas 65,801 40,741
Materials handling 50,327 56,185
Other operations 7,428 6,209
Total adjusted gross margin $ 273,975 $ 274,761
Reconciliation of Net Income to Adjusted EBITDA
Net (loss) income $ (68,916) $ 33,811
Add:
Interest expense, net 33,938 40,370
Tax provision 2,828 7,389
Depreciation and amortization 33,335 34,066
EBITDA (4): $ 1,185 $ 115,636
Add/(deduct):
Change in unrealized (loss) gain on inventory (1) (13,437) 20,148
Change in unrealized value on natural gas transportation contracts (2) 132,554 (9,565)
Gain on sale of fixed assets not in the ordinary course of business and other operating income (4) (9,700) (8,094)
Other non-operating income (5) - (1,947)
Acquisition related expenses (6) - 1
Other adjustments (7) 139 564
Adjusted EBITDA $ 110,741 $ 116,743
Other Data:
Ten Year Average Heating Degree Days 4,850 4,870
Heating Degree Days 4,518 4,546
Variance from average heating degree days (7) % (7) %
Variance from prior period heating degree days (1) % (6) %
(1)Inventory is valued at the lower of cost or net realizable value. The adjustment related to change in unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values. The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income (loss).
(2)Represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized hedging losses (gains) in net income (loss).
(3)For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “How Management Evaluates Our Results of Operations.”
(4)On April 29, 2021, we sold the Oswego terminal to an unaffiliated buyer. In connection with the sale, we recorded a net gain of $9.0 million which is included within other operating income in the consolidated statements of operations for the year ended December 31, 2021. The remaining $0.7 million of other operating income for the twelve months ended December 31, 2021 relates to a gain associated with a parcel of land sold at the Bronx terminal.
On December 23, 2020, we sold the Mt. Vernon terminal to an unaffiliated buyer. In connection with the sale, we recorded a net gain of $8.1 million for the year ended December 31, 2020, which is included within other operating income in the consolidated statements of operations.
(5)On November 1, 2019, a fire occurred at the Kildair Tracy Terminal which impacted certain buildings and equipment at the facility. The resulting damage was covered by insurance coverage in place at the time of the incident, net of applicable deductibles. In connection with the insurance reimbursement for the asset losses from the fire, the Partnership recorded a $1.9 million gain for the year ended December 31, 2020, representing insurance proceeds that were in excess of the carrying value of impacted property, plant and equipment. This gain was included within other income in the consolidated statements of operations.
(6)We incur expenses in connection with acquisitions and given the nature, variability of amounts, and the fact that these expenses would not have otherwise been incurred as part of our continuing operations, adjusted EBITDA excludes the impact of acquisition related expenses.
(7)Represents the change in the fair value of contingent consideration related to the 2017 Coen Energy acquisition (ended in 2020) and other expense.
Analysis of Consolidated Operating Results
For the year ended December 31, 2021, our operating income decreased $111.8 million, or 140%, to an operating loss of $(32.2) million, as compared to operating income of $79.6 million for the year ended December 31, 2020. For the years ended December 31, 2021 and 2020, our operating (loss) income includes unrealized commodity derivative losses with respect to refined products and natural gas of $(119.1) million and $(10.6) million, respectively, which decreased operating income for the year ended December 31, 2021 by $108.5 million.
See "Analysis of Operating Segments" and "Liquidity and Capital Resources" below for additional details on changes in our operating results.
Analysis of Operating Segments
The following tables set forth information regarding our results of operating segments for the periods presented:
Years Ended December 31, Increase/(Decrease)
2021 2020 $ %
($ and volumes in thousands, except adjusted unit gross margin)
Volumes:
Refined products (gallons) 1,502,385 1,364,474 137,911 10 %
Natural gas (MMBtus) 55,122 55,746 (624) (1) %
Materials handling (short tons) 2,026 2,316 (290) (13) %
Materials handling (gallons) 452,620 410,754 41,866 10 %
Net Sales:
Refined products $ 3,142,509 $ 1,998,197 $ 1,144,312 57 %
Natural gas 284,529 261,358 23,171 9 %
Materials handling 50,484 56,347 (5,863) (10) %
Other operations 20,638 20,081 557 3 %
Total net sales $ 3,498,160 $ 2,335,983 $ 1,162,177 50 %
Adjusted Gross Margin:
Refined products $ 150,419 $ 171,626 $ (21,207) (12) %
Natural gas 65,801 40,741 25,060 62 %
Materials handling 50,327 56,185 (5,858) (10) %
Other operations 7,428 6,209 1,219 20 %
Total adjusted gross margin $ 273,975 $ 274,761 $ (786) - %
Adjusted Unit Gross Margin:
Refined products $ 0.100 $ 0.126 $ (0.026) (21) %
Natural gas $ 1.194 $ 0.731 $ 0.463 63 %
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Refined Products
Refined products net sales increased $1.1 billion, or 57% as compared to 2020 due primarily to the substantially higher oil price environment, with average sales prices increasing by 43%. The 10% increase in volumes was also a contributor to the higher net sales. The increased volumes were primarily a combination of distillates and gasoline, with heavy oil modestly higher. The increase in distillates was a combination of higher diesel volumes with gains from regional transit authorities, on-site fueling operations, and marine fueling requirements. Despite slightly warmer weather conditions, heating oil volumes were also higher. The gain in gasoline volumes was due to a recovery in transportation demand, with the higher heavy oil volumes a result of additional on-land demand at our Canadian operations.
Refined products adjusted gross margin in 2021 decreased $21.2 million or 12% as compared to 2020, as the 21% reduction in adjusted unit gross margins more than offset the higher volumes. The lower gross adjusted margins were primarily a result of substantially less attractive market conditions to purchase, store and hedge oil inventory compared to the market conditions last year, which was characterized by a surplus supply and weaker demand environment. Both the U.S. and Canadian operations contributed to the decline in adjusted gross margins.
Natural Gas
Natural gas net sales in 2021 increased by $23.2 million, or 9%, compared to 2020, due to 10% higher average price, partially offset by a 1% decrease in volume. The higher average sales price reflects the major increase in the market prices, particularly in the second half of the year.
Natural gas adjusted gross margin in 2021 increased $25.1 million, or 62%, primarily as a result of a 63% increase in average adjusted unit gross margins. The increase in adjusted unit gross margins was due to enhanced supply and inventory optimization opportunities as well as basis changes contributing to net gains from mark-to-market valuations of derivative contracts and natural gas transportation contracts. The enhanced supply and optimization opportunities occurred at various times throughout the year, including a combination of periods during the winter and colder temperatures concomitant higher price volatility, as well as in the summer as both market prices and volatility increased.
Materials Handling
Materials handling net sales and adjusted gross margin both decreased by $5.9 million or 10% each, compared to the same period last year. The decline was a result of $3.2 million reduction in the Canadian operations along with a $2.7 million decrease in the U.S. The decline in the Canadian operations was a result of reduced tank rental demand from third parties. The variance in the U.S. was primarily due to lower road salt and windmill component handling activity, with a decline in asphalt also a contributor. The decrease in salt was due to fewer bulk vessel deliveries, as mild winter conditions led to lower salt usage and less resupply requirements. Reduced windmill handling revenue resulted since there were lower component deliveries compared to the substantial activity early last year. The asphalt decline was primarily due to a combination of the sale of our Oswego terminal in April as well as some repair requirements that reduced tankage availability and revenue generation. These reductions were partially offset by increases in the U.S. heating requirements due to higher commodity prices and additional gypsum handling related to enhanced economic activity.
Other Operations
Net sales from other operations increased by $0.6 million, or 3%, with an increase in adjusted gross margin of $1.2 million, or 20% as compared to 2020 . The increase in adjusted gross margin was a result of higher coal margins, with a physical inventory reconciliation completed last year leading to part of this variance. An increase in boiler service activity was also a contributor.
Operating Costs and Expenses
The following tables set forth information regarding our results of operating costs and expenses for the periods presented:
Years Ended December 31, Increase/(Decrease)
2021 2020 $ %
($ in thousands)
Operating expenses $ 80,673 $ 77,070 $ 3,603 5 %
Selling, general and administrative expenses $ 82,700 $ 81,514 $ 1,186 1 %
Depreciation and amortization $ 33,335 $ 34,066 $ (731) (2) %
Interest expense, net $ 33,938 $ 40,370 $ (6,432) (16) %
Operating Expenses. Operating expenses increased $3.6 million, or 5%, compared to the same period last year, primarily reflecting an increase of $1.7 million of employee-related expenses, $1.4 million in insurance related costs and $0.4 million in utilities and boiler fuel.
Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $1.2 million, or 1%, led by $0.7 million increase in insurance related costs and $0.4 million increase in incentive compensation.
Depreciation and Amortization. Depreciation and amortization decreased $0.7 million, or 2%, primarily driven by the sales of the Oswego terminal in April 2021 and Mt. Vernon terminal in 2020.
Interest Expense, net. Interest expense, net decreased $6.4 million, or 16%, compared to the same period last year primarily due to decreased net borrowing rates.
Liquidity and Capital Resources
Liquidity
Our primary liquidity needs are to fund our working capital requirements, operating expenses, capital expenditures and quarterly distributions. Cash generated from operations, our borrowing capacity under our Credit Agreement (as defined below) and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. At December 31, 2021, our working capital deficit was $(99.3) million.
As of December 31, 2021, the undrawn borrowing capacity under the working capital facilities of our Credit Agreement was $171.8 million and the undrawn borrowing capacity under the acquisition facility was $53.8 million. We enter our seasonal peak period during the fourth quarter of each year, during which inventory, accounts receivable and debt levels increase. As we move out of the winter season at the end of the first quarter of the following year, typically inventory is reduced, accounts receivable are collected and converted into cash and debt is paid down. During the twelve months ended December 31, 2021, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a high of $402.0 million to a low of $148.7 million.
We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our Credit Agreement to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flow would likely have an adverse effect on our ability to meet our financial commitments and debt service obligations.
Capital Expenditures
Our terminals require investments to maintain, expand, upgrade or enhance existing assets and to comply with environmental and operational regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. We define maintenance capital expenditures as capital expenditures made to replace assets, or to maintain the long-term operating capacity of our assets or operating income. Examples of maintenance capital expenditures are expenditures required to maintain equipment reliability, terminal integrity and safety and to address environmental laws and regulations. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as maintenance expenses as we incur them. We define expansion capital expenditures as capital expenditures made to increase the long-term operating capacity of our assets or our operating income whether through construction or acquisition of additional assets. Examples of expansion capital expenditures include the acquisition of equipment and the development or acquisition of additional storage capacity, to the extent such capital expenditures are expected to expand our operating capacity or our operating income.
The following table summarizes expansion and maintenance capital expenditures for the periods indicated:
Capital Expenditures
Expansion Maintenance Total
($ in thousands)
Years Ended December 31,
2021 $ 2,283 $ 11,605 $ 13,888
2020 (1)
$ 3,810 $ 6,193 $ 10,003
(1)Excludes approximately $2.1 million for building and equipment expenditures related to replacement of assets at Kildair Tracy Terminal due to property, plant and equipment losses from the November 1, 2019 fire.
We currently expect maintenance capital expenditures of approximately $10 million to $18 million and expansion capital expenditures, excluding acquisitions, of approximately $2 million to $5 million in 2022. These current estimates depend, in part, on the timing of completion of projects, availability of equipment and workforce, weather, and unanticipated events or opportunities requiring additional maintenance or investments. We anticipate that future maintenance capital expenditures will be funded with cash generated by operations and that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity offerings. We believe that we will have sufficient cash flow from operations, borrowing capacity under our credit agreement and the ability to issue additional equity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks and geopolitical events, each of which could adversely affect our cash flow and access to debt and equity markets.
Contractual Obligations
We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at December 31, 2021 were as follows:
Payments due by period
Total Less than
1 year 1-3 years 4-5 years More than
5 years
(in thousands)
Operating lease obligations (1) $ 19,534 $ 7,823 $ 10,981 $ 620 $ 110
Finance lease obligations (including interest) 15,749 4,028 5,648 2,898 3,175
Credit facilities (including interest) (2) 902,669 525,269 377,400 - -
Product purchases (3) 666,640 662,282 4,358 - -
Transportation and storage (4) 62,525 31,561 29,388 1,576 -
Deferred consideration (5) 20,366 3,818 7,637 7,637 1,274
Total $ 1,687,483 $ 1,234,781 $ 435,412 $ 12,731 $ 4,559
(1)We have leases for a refined products terminal, refined products storage, maritime charters, equipment, office and plant facilities that are accounted for as operating leases.
(2)Amounts include principal and interest on our working capital revolving credit facility and our acquisition line revolving credit facility at December 31, 2021. The Credit Agreement has a contractual maturity of May 19, 2023, and no scheduled principal payments are required prior to that date. However, we repay amounts outstanding and borrow funds based on our working capital requirements. The curren+t portion of Credit Agreement represents the amounts of the working capital facility. Interest is calculated using the rates in effect as of December 31, 2021, and we assume a ratable payment of the current portion of the working capital revolving credit facility through the expiration date.
(3)Product purchases include estimated purchase commitments for refined products and natural gas. The value of these future supply commitments, if not fixed in price, will fluctuate based on prevailing market prices. The prices at which we purchase refined products and natural gas are determined by reference to published market prices prevailing at the time of purchase. The value of our product purchase commitments were computed based on contractual prices.
(4)Transportation and storage commitments include refined products throughput agreements at third-party terminals and natural gas pipeline transportation and storage agreements that have minimum usage requirements.
(5)Deferred consideration payments are related to the Carbo acquisition (see Note 14 - Other Obligations, of Part II, Item 8 of this Annual Report on Form 10-K).
Cash Flows
Years Ended December 31,
2021 2020 2019
(in thousands)
Net cash (used in) provided by operating activities $ (56,778) $ 154,466 $ (65,365)
Net cash (used in) provided by investing activities $ (2,775) $ 514 $ (13,886)
Net cash provided by (used in) financing activities $ 56,480 $ (156,552) $ 77,068
Operating Activities
Net cash used in operating activities for the year ended December 31, 2021 was $56.8 million and was negatively impacted by net loss of $68.9 million, an increase of $87.4 million in accounts receivable driven by a combination of higher sales prices and volumes, and an increase of $184.3 million in inventories largely due to increases in the cost of inventory purchases. Cash flows from operations were positively impacted as a result of an increase of $118.0 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases, a change of $87.0 million in derivative instruments as a result of the increase in commodity prices in refined products during the year, a decrease in prepaid expenses and other assets of $52.7 million primarily driven by changes in collateral requirements.
Net cash provided by operating activities for the year ended December 31, 2020 was $154.5 million and was favorably impacted by net income of $33.8 million, a change of $9.1 million in derivative instruments as a result of the increase in commodity prices in refined products during the year, a decrease of $88.1 million in accounts receivable driven by a combination of lower sales prices and volumes and a decrease of $37.7 million in inventories largely due to reductions in the
cost of inventory purchases. Cash flows from operations were negatively impacted as a result of a reduction of $52.8 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases.
Investing Activities
Net cash used in investing activities for the year ended December 31, 2021 was $2.8 million and consisted primarily of $11.6 million related to maintenance capital expenditures, $2.3 million related to expansion capital expenditures across our terminal system offset by $11.1 million related to proceeds largely driven by the proceeds of approximately $10.1 million from the sale of the Oswego terminal in April 2021.
Net cash provided by investing activities for the year ended December 31, 2020 was $0.5 million and consisted primarily of $6.2 million related to maintenance capital expenditures, $3.8 million related to expansion capital expenditures across our terminal system offset by $12.7 million related to proceeds largely driven by the proceeds of approximately $10.3 million from the sale of the Mount Vernon terminal.
Financing Activities
Net cash provided by financing activities for the year ended December 31, 2021 was $56.5 million, and primarily resulted from $133.6 million of net borrowings under our Credit Agreement due to increased financing requirements from higher commodity prices, year-end timing of accounts receivable and average higher inventory levels, which were offset by distributions of $63.8 million.
Net cash used in financing activities for the year ended December 31, 2020 was $156.6 million, and primarily resulted from $70.6 million of net payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels and the reduction of inventory levels as well as distributions of $67.3 million.
Credit Agreement
On May 11, 2021, Sprague Operating Resources LLC (the "U.S. Borrower") and Kildair, (the "Canadian Borrower" and, together with the U.S. Borrower, the “Borrowers”), wholly owned subsidiaries of the Partnership, entered into a first amendment (the "First Amendment") to the second amended and restated credit agreement dated May 19, 2020 (the “Original Credit Agreement;” the Original Credit Agreement as amended by the First Amendment, the "Credit Agreement"). Upon the effective date, the First Amendment increased the acquisition facility from $430 million to $450 million and was accounted for as a modification of a syndicated loan arrangement with partial extinguishment to the extent there was a decrease in the borrowing capacity on a creditor by creditor basis. Overall, the Credit Agreement matures on May 19, 2023. The Partnership and certain of its subsidiaries (the “Subsidiary Guarantors”) are guarantors of the obligations under the Credit Agreement. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership, the Borrowers and the Subsidiary Guarantors (collectively, the “Loan Parties”).
As of December 31, 2021, the revolving credit facilities under the Credit Agreement contained, among other items, the following:
•A committed U.S. dollar revolving working capital facility of up to $465.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;
•An uncommitted U.S. dollar revolving working capital facility of up to $200.0 million, subject to borrowing base limits and the sole discretion of the lenders, to be used for working capital loans and letters of credit;
•A multicurrency revolving working capital facility of up to $85.0 million, subject to borrowing base limits, to be used for working capital loans and letters of credit;
•A revolving acquisition facility of up to $450.0 million, subject to covenants, to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate purposes; and
•Subject to certain conditions, including the receipt of additional commitments from lenders, the ability to increase the U.S. dollar revolving working capital facility to up to $1.2 billion and the multicurrency revolving working capital facility to up to $320.0 million. Additionally, subject to certain conditions, the revolving acquisition facility may be increased to up to $750.0 million.
Indebtedness under the Credit Agreement bears interest, at the Borrowers' option, at a rate per annum equal to either (i) the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs, and in each case with a floor of 0.25%) for interest periods of one, two (solely with respect to Eurocurrency Rate loans denominated in Canadian dollars), three or six (solely with respect to Eurocurrency Rate loans denominated in U.S. dollars) months plus a specified margin or (ii) an alternate rate plus a specified margin.
For loans denominated in U.S. dollars, the alternate rate is the Base Rate which is the highest of (a) the U.S. Prime Rate as in effect from time to time, (b) the greater of the Federal Funds Effective Rate and the Overnight Bank Funding Rate as in effect from time to time plus 0.50% and (c) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.
For loans denominated in Canadian dollars, the alternate rate is the Prime Rate which is the higher of (a) the Canadian Prime Rate as in effect from time to time and (b) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.
The specified margins for the working capital revolving facilities vary based on the utilization of the working capital facilities as a whole, measured on a quarterly basis. The specified margin for (x) the committed U.S. dollar revolving working capital facility ranged from 1.00% to 1.50% for loans bearing interest at the Base Rate and from 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate, (y) the uncommitted U.S. dollar revolving working capital facility ranged from 0.75% to 1.25% for loans bearing interest at the Base Rate and 1.75% to 2.25% for loans bearing interest at the Eurocurrency Rate and (z) the multicurrency revolving working capital facility ranged from 1.00% to 1.50% for loans bearing interest at the Base Rate and 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate.
The specified margin for the revolving acquisition facility varies based on the consolidated total leverage of the Loan Parties. The specified margin for the revolving acquisition facility range from 1.25% to 2.25% for loans bearing interest at the Base Rate and from 2.25% to 3.25% for loans bearing interest at the Eurocurrency Rate.
In addition, the Borrowers will incur a commitment fee on the unused portion of (x) the committed U.S. dollar revolving working capital facility and multicurrency revolving working capital facility ranging from 0.375% to 0.500% per annum and (y) the revolving acquisition facility at a rate ranging from 0.35% to 0.50% per annum. Overdue amounts bear interest at the applicable rates described above plus an additional margin of 2%.
The Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit the Partnership from making distributions to unitholders if any event of default occurs or would result from the distribution or if the Loan Parties would not be in pro forma compliance with the financial covenants after giving effect to the distribution. In addition, the Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, but not limited to, covenants that require the Loan Parties to maintain: a minimum consolidated EBITDA-to fixed-charge ratio, a minimum consolidated net working capital amount and a maximum consolidated total leverage-to-EBITDA ratio. The Credit Agreement also limits the Loan Parties ability to incur debt, grant liens, make certain investments or acquisitions, enter into affiliate transactions and dispose of assets. The Partnership was in compliance with the covenants under the Credit Agreement at December 31, 2021.
The Credit Agreement also contains events of default that are usual and customary for a financing of this type, size and purpose including, among others, non-payment of principal, interest or fees, violation of certain covenants, material inaccuracy of representations and warranties, bankruptcy and insolvency events, cross-payment default and cross-acceleration, material judgments and events constituting a change of control. If an event of default exists under the Credit Agreement, the lenders will be able to terminate the lending commitments, accelerate the maturity of the Credit Agreement and exercise other rights and remedies with respect to the collateral.
Impact of Inflation
Inflation in the United States and Canada has been relatively low in recent years and, though inflation has accelerated in 2021, did not have a material impact on our results of operations for the years ended December 31, 2021, 2020 and 2019.
Foreign Currency
Our most significant foreign operations are conducted by Kildair, our Canadian subsidiary. The functional currency of Kildair is the U.S. Dollar.
Kildair converts receivables and payables denominated in other than their functional currency at the exchange rate as of the balance sheet date. Kildair utilizes forward currency contracts to manage its exposure to currency fluctuations of certain of its transactions that are denominated in Canadian dollars. These forward currency exchange contracts are recorded at fair value at the balance sheet date and changes in fair value are recognized in net income (loss) as these forward currency contracts have not been designated as hedges. Transaction exchange gains or losses net of the impact of the forward currency exchange contracts, except for certain transaction gains or losses related to intercompany receivable and payables, are recorded in cost of products sold (exclusive of depreciation and amortization).
Transaction gains and losses related to intercompany receivables and payables not anticipated to be settled in the foreseeable future are excluded from the determination of net income (loss) and are recorded as a translation adjustment to accumulated other comprehensive income (loss) as a component of unitholders’ equity. As of December 31, 2021, all intercompany receivables or payables are anticipated to be settled in the foreseeable future and therefore, no amounts are included in accumulated other comprehensive income (loss).
Critical Accounting Policies and Estimates
Use of Estimates
The Partnership’s Consolidated Financial Statements have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires the Partnership to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by the Partnership are assets and liabilities valuations as part of an acquisition, the fair value of derivative assets and liabilities, valuation of the reporting units within the goodwill quantitative impairment assessment, and if necessary long-lived asset impairments and environmental and legal obligations.
These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis:
Derivatives
As a matter of policy, refined products and natural gas businesses utilize futures contracts, forward contracts, swaps, options and other derivatives in an effort to minimize the impact of commodity price fluctuations. On a selective basis and within our risk management policy’s guidelines, we utilize futures contracts, forward contracts, swaps, options and other derivatives to generate profits from changes in market prices.
We record all derivative instruments as either assets or liabilities in the statement of financial position and measure those instruments at fair value. We recognize changes in the fair value of our commodity derivative instruments currently in earnings as cost of products sold (exclusive of depreciation and amortization).
We do not offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts, including amounts that approximate fair value, recognized for derivative instruments executed with the same counterparty under the same master netting arrangement.
We also use interest rate swaps to convert a portion of our floating rate debt to fixed rates. These interest rate swaps are designated as cash flow hedges and the changes in fair value of the swaps are included as a component of comprehensive income (loss) and accumulated other comprehensive loss, net of tax, respectively.
Our derivative instruments are recorded at fair value, with changes in fair value recognized in net income (loss) or other comprehensive income (loss) each period, as appropriate. Fair value measurements are determined using the market approach
and include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and our credit is considered for payable balances.
We determine fair value based on a hierarchy for the inputs used to measure the fair value of financial assets and liabilities based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using significant unobservable inputs (Level 3). Multiple inputs may be used to measure fair value; however, the level of fair value is based on the lowest significant input level within this fair value hierarchy.
Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable and are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity.
Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter ("OTC") derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. We utilize fair value measurements based on Level 2 inputs for our fixed forward contracts, over-the-counter commodity price swaps, interest rate swaps and forward currency contracts.
Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from significant unobservable inputs determined from sources with little or no market activity for comparable contracts or for positions with longer durations.
Goodwill
Goodwill is defined as the excess of cost over the fair value of assets acquired and liabilities assumed in a business combination. We test goodwill at the reporting unit level annually as of October 31 or on an as needed basis, for indicators of impairment at each reporting unit that has recorded goodwill. In performing the test, we either use a qualitative assessment or a single step quantitative approach. Under the qualitative approach we consider a number of factors, including the amount by which the previous quantitative test's fair value exceeded the carrying value of the reporting units, actual performance as compared to internal forecasts used in the previous quantitative test, an evaluation of discount rates, and an evaluation of current economic factors for both the worldwide economy and specifically the oil and gas industry, and any significant changes in customer and supplier relationships. We weigh these factors to determine if it is more likely than not that the fair value of the reporting unit exceeds its carrying value. If after performing a qualitative assessment, indicators are present, or we identify factors that cause us to believe it is appropriate to perform a more precise calculation of fair value, we would move beyond the qualitative assessment and perform a quantitative impairment test.
Under the quantitative impairment test, we perform a comparison of the reporting unit’s carrying value to its fair value. We estimate the fair value of a reporting unit based upon future net discounted cash flows (Level 3 measurement). In calculating these estimates, we develop a discounted cash flow model based on forecasted operating results, discount rates, and growth rates, which contemplate business, market and overall economic conditions. Further, the discount rates used require estimates of the cost of equity and debt financing. The estimates of fair value of these reporting units could change if actual operating results or discount rates vary from these estimates. We performed sensitivity analyses on the fair values resulting from the discounted cash flows valuation utilizing more conservative assumptions that reflect reasonably likely future changes in the discount rates and perpetual growth rate in each of the reporting units. Based upon our 2021 annual impairment testing analyses, including the consideration of reasonably likely adverse changes in assumptions described above, the Partnership determined that all of its reportable units had fair values exceeding their carrying value. As of December 31, 2021, there was $35.5 million of goodwill allocated to the natural gas reporting unit which had a negative carrying value with respect to the annual goodwill test performed.
Revenue Recognition
Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The majority of our revenue is generated from refined products and natural gas contracts that have a single performance obligation which is the delivery of the related energy product. Accordingly, we recognize revenue for refined products and natural gas when title and control have been transferred to the customer which is generally at the time of shipment or delivery of products.
Revenue for our materials handling segment is recorded on a straight-line basis under leasing arrangements or as services are performed.
Revenue is measured as the amount of consideration we expect to receive in exchange for transferring products or providing services and is generally based upon a negotiated index, formula, list or fixed price. An allowance for doubtful accounts is recorded to reflect an estimate of the ultimate realization of the accounts receivable and includes an assessment of the customers’ creditworthiness and the probability of collection. The provision for the allowance for doubtful accounts is included in cost of products sold (exclusive of depreciation and amortization) and has not been significant in the past. Estimated discounts are included in the transaction price of the contracts with customers as a reduction to net sales. We sell our products or provide services directly to commercial customers and wholesale distributors generally under agreements with payment terms typically less than 30 days.
We account for shipping and handling as activities to fulfill the promise to transfer the good. As such, shipping and handling fees billed to customers in a sales transaction are recorded in net sales and shipping and handling costs incurred are recorded in cost of products sold (exclusive of depreciation and amortization). We exclude from net sales any value add, sales and other taxes which it collects concurrently with revenue-producing activities.
The majority of our revenue is derived from (i) contracts with an original expected length of one year or less and (ii) contracts for which we recognize revenue at the amount in which we have the right to invoice the customer as product is delivered.
Recent Accounting Pronouncements
For information on recent accounting pronouncements impacting our business, see Recent Accounting Pronouncements included under Note 1 - Description of Business and Summary of Significant Accounting Policies to our Consolidated Financial Statements (Part II, Item 8 of this Annual Report).

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk, interest rate risk and market/credit risk. We utilize various derivative instruments to manage exposure to commodity risk and swaps to manage exposure to interest rate risk.
Commodity Price Risk
We use various financial instruments as we seek to hedge our commodity price risk. We sell our refined products and natural gas primarily in the Northeast. We hedge our refined products positions primarily with a combination of futures contracts that trade on the NYMEX, and fixed-for-floating price swaps in the form of bilateral contracts that are traded “over-the-counter” or "OTC." Although there are some notable differences between futures and the fixed-for-floating price swaps, both can provide a fixed price while the counterparty receives a price that fluctuates as market prices change.
As indicated in the table below, we primarily use futures contracts to hedge light oil transactions and swaps contracts for hedging residual fuel oils. There are no residual fuel oil futures contracts that actively trade in the United States. Each of the financial instruments trade by month for many months forward, allowing us the ability to hedge future contractual commitments.
Product Group Primary Financial Hedging Instrument
Gasolines NYMEX RBOB futures contract
Distillates NYMEX Ultra Low Sulfur Diesel futures contract
Residual Fuel Oils New York Harbor 1% Sulfur Residual Fuel Oil Swaps
In addition to the financial instruments listed above, we may periodically use the ethanol futures contract that trades on the Chicago Board of Trade, or CBOT, to hedge ethanol that is used for blending into our gasoline. This ethanol contract is based on Chicago delivery. There are also swaps alternatives available in the market to hedge ethanol. In addition, we also use Rotterdam Barge 0.1% Sulfur Gasoil swaps as the primary means to hedge Kildair's marine gas oil positions.
For natural gas, there are no quality differences that need to be considered when hedging. Our primary hedging requirements relate to fixed price and basis (location) exposure. We largely hedge our natural gas fixed price exposure using fixed-for-floating price swaps that trade on the ICE with the prices based on the Henry Hub location near Erath, Louisiana. The Henry Hub is the most active natural gas trading location in the United States. Although we typically use swaps, there is also an actively traded NYMEX Henry Hub natural gas futures contract that we can use. We primarily use ICE basis swaps as the key financial instrument type to hedge our natural gas basis risk. Similar to the natural gas futures and ICE Henry Hub swaps, basis swaps for major locations trade actively for many months. These swaps are financially settled, typically using prices quoted by Platts. We also directly hedge our price exposure in oil and natural gas by using forward purchases or sales that require physical delivery of the product.
The following table presents total realized and unrealized gains (losses) on derivative instruments utilized for commodity risk management purposes. Such amounts are included in cost of products sold (exclusive of depreciation and amortization) for the years ended December 31, 2021, 2020 and 2019:
2021 2020 2019
(in thousands)
Refined products contracts $ (33,611) $ 15,434 $ (26,194)
Natural gas contracts (101,754) 46,024 38,513
Total $ (135,365) $ 61,458 $ 12,319
Substantially all of our commodity derivative contracts outstanding as of December 31, 2021 will settle prior to June 30, 2023.
Interest Rate Risk
We enter into interest rate swaps to manage exposures in changing interest rates. We swap the variable LIBOR interest rate payable under our Credit Agreement for fixed LIBOR interest rates. These interest rate swaps meet the criteria to receive cash flow hedge accounting treatment. Counterparties to our interest rate swaps are large multi-national banks and we do not believe there is a material risk of counterparty nonperformance. Additionally, we may enter into seasonal swaps which are intended to manage our increase in borrowings during the winter, as a result of higher inventory and accounts receivable levels.
Our interest rate swap agreements outstanding as of December 31, 2021 were as follows (in thousands):
Interest Rate Swap Agreements
Beginning Ending Notional Amount
January 2021 January 2022 $ 300,000
April 2021 April 2022 $ 25,000
January 2022 January 2023 $ 250,000
April 2022 April 2023 $ 25,000
January 2023 January 2024 $ 250,000
January 2024 January 2025 $ 50,000
During the two year period ended December 31, 2021, we hedged approximately 48% of our floating rate debt with fixed-for-floating interest rate swaps. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. Based on a sensitivity analysis for the year ended December 31, 2021, we estimate that if short-term interest rates increase 100 basis points or decrease to zero, our interest expense would increase by $3.2 million and decrease by $0.1 million, respectively. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges.
Derivative Instruments
The following tables present our derivative assets and derivative liabilities measured at fair value on a recurring basis as of December 31, 2021:
Fair Value
Measurement Active
Markets
Level 1 Observable
Inputs
Level 2 Unobservable
Inputs
Level 3
(in thousands)
Derivative assets:
Commodity fixed forwards $ 25,793 $ - $ 25,793 $ -
Commodity swaps and options 148,034 148,029 5 -
Commodity derivatives 173,827 148,029 25,798 -
Interest rate swaps 302 - 302
Total derivative assets $ 174,129 $ 148,029 $ 26,100 $ -
Derivative liabilities:
Commodity fixed forwards 176,602 - 176,602 -
Commodity swaps and options 78,026 77,948 78 -
Commodity derivatives 254,628 77,948 176,680 -
Interest rate swaps 5,295 - 5,295 -
Total derivative liabilities $ 259,923 $ 77,948 $ 181,975 $ -
Market and Credit Risk
The risk management activities for our refined products and natural gas segments involve managing exposures to the impact of market fluctuations in the price and transportation costs for commodities through the use of derivative instruments. The prices for energy commodities can be significantly influenced by market liquidity and changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. We monitor and manage our exposure to market risk on a daily basis in accordance with approved policies.
We maintain a control environment under the direction of our Chief Risk Officer through our risk management policy, processes and procedures, which our senior management has approved. Control measures include volumetric, value at risk, and stop loss limits, as well as contract term limits. Our Chief Risk Officer and Risk Management Committee must approve the use of new instruments or new commodities. Risk limits are monitored and reported daily to senior management. Our risk management department also performs independent verifications of sources of fair values. These controls apply to all of our commodity risk management activities.
We use a value at risk model to monitor commodity price risk within our risk management activities. The value at risk model uses both linear and simulation methodologies based on historical information, with the results representing the potential loss in fair value over one day at a 95% confidence level. Results may vary from time to time as hedging coverage, market pricing levels and volatility change.
We have a number of financial instruments that are potentially at risk including cash and cash equivalents, receivables and derivative contracts. Our primary exposure is credit risk related to our receivables and counterparty performance risk related to the fair value of derivative assets, which is the loss that may result from a customer’s or counterparty’s non-performance. We use credit policies to control credit risk, including utilizing an established credit approval process, monitoring customer and counterparty limits, employing credit mitigation measures such as analyzing customer financial statements, credit insurance with a third party provider and accepting personal guarantees and forms of collateral. We believe that our counterparties will be able to satisfy their contractual obligations. Credit risk is limited by the large number of customers and counterparties comprising our business and their dispersion across different industries.
Cash is held in demand deposit and other short-term investment accounts placed with federally insured financial institutions. Such deposit accounts at times may exceed federally insured limits. We have not experienced any losses on such accounts.
The following table presents the value at risk for our refined products and natural gas marketing and risk management commodity derivatives activities:
Refined Products Natural Gas
2021 2020 2019 2021 2020 2019
(in thousands) (in thousands)
At December 31 $ 96 $ 228 $ 119 $ 3,523 $ 711 $ 502
Average 87 675 127 955 424 381
High 261 2,448 461 4,111 738 657
Low 17 13 27 301 151 120

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
See Part IV, Item 15 - "Exhibits and Financial Statement Schedule-Index to Consolidated Financial Statements''.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership's reports under the Exchange Act is accumulated and communicated to the Partnership's management, including the President, Chief Executive Officer and the Chief Financial Officer of Sprague Resources GP LLC (the Partnership's general partner), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of December 31, 2021, the Partnership carried out an evaluation, under the supervision and with the participation of management (including the President, Chief Executive Officer and the Chief Financial Officer of the Partnership's general partner) of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on this evaluation, the general partner's President, Chief Executive Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of December 31, 2021.
Management’s Report Regarding Internal Control Over Financial Reporting
Management of the general partner, including the President, Chief Executive Officer and the Chief Financial Officer of the Partnership's general partner, is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal control over financial reporting may vary over time.
Management has assessed the effectiveness of Sprague Resources LP’s internal control over financial reporting as of December 31, 2021. In making its assessment, management has utilized the criteria set forth by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission in Internal Control-Integrated Framework (2013 Framework). Management concluded that based on its assessment, the Partnership's internal control over financial reporting was effective as of December 31, 2021. Ernst & Young LLP, Registered Public Accounting Firm, has issued an attestation report on our internal control over financial reporting which is included in this Annual Report on page.
Changes in Internal Control Over Financial Reporting
There have been no changes in our system of internal control over financial reporting during the three months ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
Executive Officers and Directors of our General Partner
Our General Partner oversees our operations and activities on our behalf through its board of directors. The board of directors of our General Partner appoints our officers, all of whom are employed by our General Partner and manage our day-to-day affairs. Neither our General Partner, nor the board of directors of our General Partner, is elected by our unitholders and neither will be subject to re-election in the future. Rather, the directors of our General Partner are appointed by Sprague Holdings, which owns 100% of our General Partner. The board of directors of our General Partner met five times during the 2021 fiscal year and each of its members attended 100% of the meetings. The audit committee of the board of directors of our General Partner met seven times during the 2021 fiscal year, of which each of its members attended 100% of the meetings. The conflicts committee of the board of directors of our General Partner did not meet during the 2021 fiscal year. Established in September 2021, the compensation committee of the board of directors of our General Partner met three times during the 2021 fiscal year with each of its members attending 100% of the meetings.
The following table provides information as of March 3, 2022 for the executive officers and directors of our General Partner. References to “our officers,” “our directors,” or “our board” refer to the officers, directors, and board of directors of our General Partner. Directors are appointed to hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board.
Name Age Position with our General Partner
Stephen M. Hendel 70 Chairman of the Board of Directors
Beth A. Bowman 65 Director, Conflicts Committee Chair
C. Gregory Harper 57 Director, Audit Committee Chair
John A. Shapiro 70 Director, Compensation Committee Chair
Stephen M. Semlitz 69 Director
Jonathan Guy Merison 62 Director
Scott Levy 49 Director
Jason T. Lemme 46 Director
David C. Glendon* 56 President, Chief Executive Officer and Director
David C. Long* 48 Chief Financial Officer
Thomas F. Flaherty* 66 Vice President, Refined Products
Steven D. Scammon* 60 Vice President, Chief Risk Officer
Brian W. Weego* 55 Vice President, Natural Gas
Paul A. Scoff* 62 Vice President, General Counsel, Chief Compliance Officer and Secretary
Joseph S. Smith* 65 Vice President, Corporate Development
James A. Therriault* 61 Vice President, Materials Handling
Thomas E. Carey 64 Vice President, Operations
Ben Hennelly 51 Chief Information Officer
* Indicates an “executive officer” for purposes of Item 401(b) of Regulation S-K.
Stephen M. Hendel - Mr. Hendel joined the board of directors as chairman in May 2021, upon the closing of the purchase by Hartree Partners, LP ("Hartree") of the general partner interest, the incentive distribution rights and all of the common units representing limited partner interests that were held by Sprague Holdings, a subsidiary of Axel Johnson Inc. . Mr. Hendel, is currently serving, and has served since March 1997, as a Founding Partner and Managing Director of Hartree, where he is actively involved in the management of the firm. Prior to co-founding Hartree, from 1985 to 1996, Mr. Hendel was a partner at Goldman Sachs, where he held various management roles in the J. Aron division including co-head of energy trading and oversight of J. Aron’s division of quantitative strategies. From 1994 to 1996, Mr. Hendel shared responsibility for the energy, commodity and currency business for J. Aron. Prior to joining J. Aron in 1980, he was an associate at Paul, Weiss, Rifkind, Wharton & Garrison. Mr. Hendel is active in a number of artistic not-for-profit foundations. Mr. Hendel holds a B.A. from Yale University and a J.D. from the University of Connecticut School of Law. We believe that Mr. Hendel’s more than 40 years of experience in the energy industry, as well as his extensive management skills he acquired through his involvement
in the strategy, operations and governance of Hartree, bring substantial perspective and leadership to the board of directors of our General Partner.
Beth A. Bowman - Ms. Bowman was appointed to the board of directors of our General Partner in October 2014. Ms. Bowman served at Shell Energy North America for 17 years where she was the Senior Vice President of Sales and Origination North America, until her retirement in September 2015. Prior to joining Shell, Ms. Bowman held management positions at Sempra Energy Trading and Sempra’s San Diego Gas & Electric utility. Ms. Bowman has served as a director at Targa Resources Corp., Targa Resources Partners LP and Targa Resources GP LLC since September 2018. In 2014, Ms. Bowman was named one of the Top 50 Most Powerful Women in Oil and Gas in the U.S. by the National Diversity Council. Ms. Bowman served on the boards of the California Power Exchange and the California Foundation of Energy and Environment. Ms. Bowman received her Bachelor of Science degree Civil Engineering from the University of Illinois, a Master’s degree in Civil Engineering from San Diego State University and a Master’s degree in Business Administration Finance from University of San Diego. We believe that Ms. Bowman’s extensive energy industry background, particularly her experience in senior leadership roles and board positions of other energy companies, provide the board of directors of our General Partner with valuable knowledge and skill.
C. Gregory Harper - Mr. Harper was appointed to the board of directors of our General Partner in October 2013 in connection with our IPO. In June 2021 Mr. Harper was appointed Chairman and CEO of Evergreen Midstream LLC and in March 2021 Mr. Harper began to serve on the board of directors of Woodway Energy Infrastructure LLC. From April 2018 until April 2020, Mr. Harper served as President and CEO of Blue Mountain Midstream and as a board member of its parent Riviera Resources Inc. In April 2017, Mr. Harper retired from Enbridge Inc. where he served as President, Gas Pipelines and Processing. In January 2014, Mr. Harper was appointed principal executive officer of Midcoast Holdings L.L.C., an indirect subsidiary of Enbridge Inc. Mr. Harper also served as Senior Vice President of Midstream with Southwestern Energy Company from August 2013 to January 2014. Prior to joining Southwestern Energy, Mr. Harper served as Senior Vice President and Group President of CenterPoint Energy Pipelines and Field Services from December 2008 to June 2013. Before joining CenterPoint Energy in 2008, Mr. Harper served as President, Chief Executive Officer and as a Director of Spectra Energy Partners, LP from March 2007 to December 2008. From January 2007 to March 2007, Mr. Harper was Group Vice President of Spectra Energy Corp., and he was Group Vice President of Duke Energy from January 2004 to December 2006. Mr. Harper served as Senior Vice President of Energy Marketing and Management for Duke Energy North America from January 2003 until January 2004 and Vice President of Business Development for Duke Energy Gas Transmission and Vice President of East Tennessee Natural Gas, LLC from March 2002 until January 2003. Mr. Harper currently serves on the University of Houston Bauer College Board and the board of directors of the Houston Area Women's Center. Mr. Harper received his Bachelor’s degree in Mechanical Engineering from the University of Kentucky and his Master’s degree in Business Administration from the University of Houston. We believe Mr. Harper’s extensive industry background, particularly his financial reporting and oversight expertise, brings important experience and skill to the board of directors of our General Partner.
John A. Shapiro - Mr. Shapiro was appointed to the board of directors of our General Partner in June 2021 at which time he was appointed as a member of the audit committee and the conflicts committee. Mr. Shapiro has more than 35 years of experience in the banking and energy industries and currently serves, and has served since November 2009, as a director on the board of Blueknight Energy Partners, L.P., a master limited partnership headquartered in Tulsa, Oklahoma. Since November 2015, Mr. Shapiro has served as a senior advisor to Mountain Capital Partners, LLC, a Houston-based private equity firm focused on upstream E&P investments. Additionally, he currently serves, and has served since December 2009, as a member of the board of Citymeals-on-Wheels. Mr. Shapiro was an officer at Morgan Stanley & Co., where he served from November 1984 to December 2008 in various capacities, ultimately as Global Head of Commodities and a member of the firm's Management Committee. While an officer at Morgan Stanley, Mr. Shapiro participated in the successful acquisitions of TransMontaigne Inc. and Heidmar Inc. and served as a member of the board of directors of both companies. Prior to joining Morgan Stanley & Co., Mr. Shapiro worked for Conoco, Inc. and New England Merchants National Bank. Mr. Shapiro has been a lecturer at Princeton University, Harvard University School of Government, HEC Business School (Paris, France) and the Oxford University Energy Program (Oxford, UK). Mr. Shapiro received his Master of Business Administration from Harvard University and a bachelor’s degree in economics from Princeton University. We believe that Mr. Shapiro’s leadership skills, financial expertise and industry expertise gained while serving on the board of other energy companies, among other factors, qualify him to serve as a member of the board of directors of our General Partner.
Stephen M. Semlitz- Mr. Semlitz was appointed to the board of directors of our General Partner in May 2021. Mr. Semlitz, is currently serving, and has served since March 1997, as a Founding Partner and Managing Director of Hartree, where he is actively involved in the management of the firm. Prior to co-founding Hartree, from 1985 to 1996, Mr. Semlitz was a partner at Goldman Sachs, where he developed the energy business from inception and was the Co-Head of Energy Trading. From 1980 to 1986, Mr. Semlitz was the Head Metals Trader at J. Aron and Goldman Sachs. Mr. Semlitz holds a B.S. and an MBA from
Cornell University. We believe that Mr. Semlitz’s 40 plus years' prior experience in the energy industry and prior experience in leadership positions allows him to bring substantial experience and skills to the board of directors of our General Partner.
Jonathan Guy Merison- Mr. Merison was appointed to the board of directors of our General Partner in May 2021. Mr. Merison is currently serving, and has served since March 1997, as a Founding Partner and Managing Director of Hartree, where he is actively involved in the management of the firm. Prior to joining Hartree, from 1995 to 1997, Mr. Merison served as a portfolio manager at Odyssey Partners, where he was the commodities portfolio manager. From 1986 to 1995, Mr. Merison managed the Products Trading, Grain Trading, and Derivatives Trading groups at J. Aron, a division of Goldman Sachs. Prior to joining Goldman Sachs Mr. Merison served as the Senior Manager at Czarnikow Schroeder USA from 1981 to 1986. We believe that Mr. Merison's significant investment, trading and leadership experience prepare him well to serve on the board of directors of our General Partner.
Scott Levy- Mr. Levy was appointed to the board of directors of our General Partner in May 2021. Mr. Levy is currently serving, and has served since July 2016, as a Partner of Hartree where he leads the firm’s Institutional Asset Management and Principal Investing activities. Prior to joining Hartree, Mr. Levy served on the Board of Directors of Hartree as one of Oaktree Capital Management’s (“Oaktree”) representatives. Mr. Levy joined Oaktree in 2011, where he worked as a Managing Director focused on the firms strategic and corporate development efforts. Prior to joining Oaktree, Mr. Levy was a Managing Director at Bank of America Merrill Lynch in the investment banking division focused on Mergers, Acquisitions and Restructuring. Mr. Levy began his career at Bankers Trust and subsequently Deutsche Bank. Over 11 years, Mr. Levy worked both as an analyst on the High Yield trading desk and an investment banker in the Financial Sponsor Advisory Group. Mr. Levy holds a B.A. in Mathematics from Colgate University. We believe that Mr. Levy’s experience in asset management and corporate development allows him to bring investment perspective, skills and experience to the board of directors of our General Partner.
Jason T. Lemme- Mr. Lemme was appointed to the board of directors in September 2021. Mr. Lemme is currently serving, and has served since May 2017, as the head of US Natural Gas Trading at Hartree. Mr. Lemme is a Partner of Hartree, an affiliate of the owner of our General Partner, and sits on Hartree’s Executive Committee. Prior to May 2017, Mr. Lemme led Hartree’s origination efforts in North America. Mr. Lemme has been with Hartree since 2002, and has held various positions in origination, investment and trading. Additionally, Mr. Lemme has served as a director of the New York Energy Forum since December 2019 and as a director of the Winston School of Short Hills since May 2020. Mr. Lemme graduated with a B.A. Economics from Rutgers University and earned a M.Sc. Global Market Economics from the London School of Economics. We believe that Mr. Lemme's almost 20 years prior experience in the energy industry and leadership roles qualify him to serve as a member of the board of directors of our General Partner.
David C. Glendon - Mr. Glendon was appointed to the board of directors of our General Partner and was named President and Chief Executive Officer ("CEO") of our General Partner in July 2011, a position he held with our Predecessor since January 15, 2008. Mr. Glendon was hired by our Predecessor on June 30, 2003 as the Senior Vice President of Oil and Materials Handling, focusing on driving the execution of a customer-centric approach across all elements of the business. Prior to joining our Predecessor, Mr. Glendon was a partner and global account manager at Monitor Group. He was also a founder and managing director of Monitor Equity Advisors, which worked with leading private capital providers in evaluating transactions and enhancing the strategic positions of their portfolio investments. Mr. Glendon received a Bachelor’s degree, cum laude, in Psychology from Williams College and a Master’s degree in Business Administration from the Stanford Graduate School of Business. As a result of his professional background, we believe Mr. Glendon brings executive-level strategic and financial skills along with significant operational experience that, when combined with his 15 years of consulting experience in a variety of industries and a deep knowledge of our business, make Mr. Glendon well-suited to serve on the board of directors of our General Partner.
David C. Long - Mr. Long joined our General Partner in December 2018 and assumed the role of Chief Financial Officer in January 2019. From June 2013 until December 2018, Mr. Long served as Senior Vice President with Kinetico Incorporated, a subsidiary of Axel Johnson, Inc., during which he was responsible for marketing, sales and business development activity in North America. From February 2008 through June 2013, Mr. Long served as Senior Vice President and Chief Financial Officer of Kinetico Incorporated where he led the finance and accounting organization. From 1998 through 2008, Mr. Long held a variety of roles with Axel Johnson, Inc., most recently as Managing Director of Sales, Refined Products. Mr. Long holds a Bachelor’s degree from the University of Maine and a Master of Finance degree from Boston College.
Thomas F. Flaherty - Mr. Flaherty was appointed Vice President, Refined Products of our General Partner in February, 2014 with responsibility for all activities in the business unit including Marketing, Supply, and Pricing. Previously, Mr. Flaherty was appointed to the position of Vice President, Sales of our General Partner in July 2011, a position he held with our Predecessor since November 28, 2006. In that role, Mr. Flaherty was responsible for all refined products sales and marketing activities. Mr. Flaherty has served in various roles during his continuous tenure with our Predecessor since he was
hired as an Account Executive in Coal Sales in July 1983, including Vice President, Commercial Sales and subsequently Vice President, Industrial Marketing. Mr. Flaherty received his Bachelor’s degree in Management from the University of Massachusetts and a Master’s degree in Business Administration from the Whittemore School of Business, University of New Hampshire.
Steven D. Scammon - Mr. Scammon was appointed Vice President, Chief Risk Officer of our General Partner in February, 2014 with duties including overseeing risk management and related control processes, including all middle office activities and insurance groups. Previously, Mr. Scammon was appointed to the position of Vice President, Trading and Pricing of our General Partner in July 2011, a position he held with our Predecessor since January 28, 2008. In that role, Mr. Scammon was responsible for refined products trading and pricing. Mr. Scammon also managed customer service until February 2013 at which time he was moved into marketing. Mr. Scammon joined our Predecessor as Vice President, Clean Products on December 26, 2000 and has been continuously employed by our Predecessor since then. Prior to joining our Predecessor, Mr. Scammon served as Senior Vice President with the Consolidated Natural Gas Energy Services Co. Prior to that, Mr. Scammon served in several positions with Louis Dreyfus Corporation including as Global Position Manager and Manager - National Accounts. Mr. Scammon received his Bachelor’s degree in Economics from Denison University.
Paul A. Scoff - Mr. Scoff was appointed Vice President, General Counsel, Chief Compliance Officer and Secretary of our General Partner in July 2011, a position he held with our Predecessor since June 1, 2011. Mr. Scoff has been continuously employed by our Predecessor since December 1999, serving as Vice President, General Counsel and Secretary during such time. Prior to joining our Predecessor, Mr. Scoff was the Vice President and General Counsel of Genesis Energy L.P., a publicly traded master limited partnership. Prior to Genesis, Mr. Scoff served as Senior Counsel with Basis Petroleum (formerly known as Phibro Energy U.S.A. Inc., a division of Salomon Inc.). He also served as Senior Counsel with The Coastal Corporation prior to joining Basis Petroleum. He received his Juris Doctor from the University of Houston Law Center and his Bachelor’s degree, cum laude, in Political Science and English from Washington and Jefferson College.
Joseph S. Smith - Mr. Smith was appointed Vice President, Corporate Development & IT of our General Partner in February 2019; and, with Mr. Hennelly joining the General Partner as Chief Information Officer in July 2021, Mr. Smith now serves as Vice President, Corporate Development. In this role he has oversight responsibility for Kildair and Coen Energy as well as leading Sprague's acquisition sourcing and integration efforts. Prior to this appointment, Mr. Smith served as Vice President, Business Development from February 2014 to January 2019. Mr. Smith also served as Vice President, Chief Risk Officer and Strategic Planning of our General Partner from July 2011 to January 2014, a position he held with our Predecessor since July 2006. In such role, Mr. Smith was tasked with oversight responsibility for risk management and related control processes. Mr. Smith has been an employee of our Predecessor since April 2001 when he joined as Vice President, Corporate Planning and Development and was subsequently promoted to Vice President, Pricing and Performance Management. Prior to joining our Predecessor, Mr. Smith was a Principal with Arthur D. Little, Inc.’s international energy consulting practice. He also worked in various positions for Mobil Oil Corporation, including in the areas of sales and supply and research and development. Mr. Smith received his Bachelor’s degree in Chemical Engineering from the University of Maine. He received a Master’s degree in Chemical Engineering from Pennsylvania State University and a Master’s degree in Business Administration in Finance from Drexel University.
James A. Therriault - Mr. Therriault was appointed Vice President, Materials Handling of our General Partner in July 2011, a position he held with our Predecessor since October 2003. As Vice President, Materials Handling, Mr. Therriault is responsible for the sales and business development efforts of our materials handling business unit. Mr. Therriault has held a variety of business and financial positions since joining our Predecessor in 1984. Mr. Therriault graduated from The University of New Hampshire with a Bachelor of Arts degree in Economics and from the University of Southern New Hampshire with a Master’s degree in Business Administration.
Thomas E. Carey - Mr. Carey was appointed Vice President, Operations, on June 24, 2020. He is responsible for the safe, environmentally responsible and cost-efficient operation of our terminals and fleet. Mr. Carey joined Sprague in 2014. Prior to joining Sprague, Mr. Carey served as Senior Vice President of Operations for Castle Oil Corporation. Mr. Carey began his career in the oil industry in January 1979. In that time, he has continuously served in various positions including responsibility for terminals, fleet, safety, regulatory compliance, engineering and material handling.
Brian W. Weego - Mr. Weego was appointed Vice President, Natural Gas of our General Partner in July 2011, a position he held with our Predecessor since June 7, 2010. As Vice President, Natural Gas, Mr. Weego is responsible for all elements of the natural gas business unit. Mr. Weego has been continuously employed by our Predecessor since he was hired on December 7, 1998, having served as Manager, Natural Gas Supply Operations; Director, Natural Gas Marketing; and Managing Director, Natural Gas Marketing. Prior to joining our Predecessor, Mr. Weego spent 11 years in various segments in the natural gas industry and has worked for the Coastal Corporation (wholesale natural gas origination and sales), O&R Energy (natural
gas supply and trading) and Commonwealth Gas Company (natural gas utility supply planning and acquisition). Mr. Weego received a Bachelor of Science degree in Management from Lesley University and a Master’s degree in Business Administration from the University of New Hampshire Whittemore School of Business and Economics.
Ben J. Hennelly - Mr. Hennelly was appointed Chief Information Officer of our General Partner in July 2021. Mr. Hennelly, also serves as President of The Agrippa Works, Inc., a strategy and technology consultancy. Mr. Hennelly was a member of the board of directors of our General Partner from July 2011 until May 2021. He also served as President and Chief Executive Officer of Decisyon, Inc. from December 2014 through July 2017. Mr. Hennelly previously served as Chief Financial Officer for Axel Johnson Inc. during the period of March 2007 through June 2012 and as Executive Vice President for Axel Johnson Inc. from June 2012 through December 2014. Mr. Hennelly has held various positions within the Axel Johnson Group. Before joining the Axel Johnson Group in 2003, Mr. Hennelly was on the founding management team of EPIK Communications, a provider of broadband telecommunication services, and previously was a consultant with the Monitor Group, a global management strategy consulting firm, where he advised clients across a range of industries, including the energy industry. Mr. Hennelly holds a Bachelor of Arts degree from Cornell University and a Ph.D from Brown University.
Director Independence
NYSE rules do not require that the board of directors of our General Partner be composed of a majority of independent directors. Nonetheless, the board of directors of our General Partner has affirmatively determined that Ms. Bowman, Mr. Harper and Mr. Shapiro meet the independence standards established by the NYSE.
Committees of the Board of Directors
The board of directors of our General Partner has an audit committee, a conflicts committee and, beginning in September 2021, a compensation committee. Each of the standing committees of the board of directors has the composition and responsibilities described below. Ms. Bowman and Messrs. Harper and Shapiro are members of the audit, conflicts and compensation committees and are independent (as that term is defined in the applicable NYSE rules and Rule 10C-1 of the Exchange Act) and non-employee directors (as that term is defined in Rule 16b-3 of the Exchange Act).
Audit Committee
We are required to have an audit committee of at least three members and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act. Ms. Bowman and Messrs. Harper and Shapiro are the current members of our audit committee. The board of directors of our General Partner has determined that each director appointed to the audit committee is “financially literate,” and Mr. Harper, who serves as chairman of the audit committee, has “accounting or related financial management expertise” and constitutes an audit committee financial expert in accordance with SEC and NYSE rules and regulations. The audit committee of the board of directors of our General Partner serves as our audit committee and will assist the board in its oversight of the integrity of our consolidated financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee operates under a written charter and has the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management, as necessary. The audit committee met seven times during 2021.
Conflicts Committee
The board of directors of our General Partner established a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest. The conflicts committee will determine if the resolution of any such conflict of interest is fair and reasonable to us. The board of directors of our General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The committee consists of a minimum of two members, none of whom can be officers or employees of our General Partner or directors, officers or employees of its affiliates (other than as directors of our subsidiaries) and each of whom must meet the independence standards for service on an audit committee established by the NYSE and the SEC. Ms. Bowman and Messrs. Harper and Shapiro are the independent members of the conflicts committee. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our unitholders, and not a breach by our General Partner of any duties it may owe us or our unitholders. The conflicts committee did not meet during fiscal year 2021.
If the board of directors of our General Partner does not seek approval from the conflicts committee, and the board of directors of our General Partner approves a resolution or course of action taken with respect to a conflict of interest, then it will be presumed that, in making its decision, the board of directors of our General Partner acted in good faith, and in any proceeding brought by or on behalf of us or any unitholder, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Compensation Committee
As a limited partnership that is listed on the NYSE, we are not required to have a compensation committee. However, the board of directors of our General Partner determined that a compensation committee is appropriate in order to conform to best governance practices and in September 2021 established a charter for the compensation committee. The current members of the compensation committee include Ms. Bowman and Messrs. Shapiro and Harper. The compensation committee may delegate any of its responsibilities and duties to one or more members of the compensation committee to the extent permissible under the Exchange Act or the NYSE listing rules.
Oversight of our compensation plans is the compensation committee’s responsibility. The compensation committee oversees and evaluates the General Partner's human resources and compensation structure, policies, programs and succession planning and assesses whether appropriate incentives and leadership development opportunities are established for management and other employees. The compensation committee also determines and approves compensation for our CEO and our other executive officers, including our named executive officers.
The compensation committee has authority to select and oversee outside compensation advisors, including consultants, legal counsel and other advisors, to review or make recommendations on our compensation programs. The compensation committee has the authority to enter into retention agreements with any such advisors establishing the fees payable to such advisors by the Partnership and any other retention terms.
The compensation committee determines and approves the compensation of the CEO, with the exception of the CEOs base compensation, which shall be approved by the independent directors of the full board of directors of the General Partner following the recommendation of the compensation committee. The compensation committee may seek guidance or input from the CEO when making determinations about the compensation of the other executive officers. The CEO also may provide recommendations to the compensation committee concerning the high-level allocation of incentive award pools among senior management other than executive officers. The CEO also may determine the salaries and amounts of individual incentive awards to senior management members other than executive officers.
The compensation committee did not retain an independent compensation consultant to assist in evaluating and advising on the compensation of its officers and directors for the fiscal year 2021. The compensation committee met three times during fiscal year 2021.
Corporate Code of Business Conduct and Ethics
The board of directors of our General Partner has approved a Corporate Code of Business Conduct and Ethics which is applicable to all directors, officers and employees of our General Partner, including the principal executive officer and the principal financial officer. The Corporate Code of Business Conduct and Ethics is available on the “Investor Relations-Corporate Governance” section of our website at http://investors.spragueenergy.com/corporate-governance and in print without charge to any unitholder who sends a written request to our secretary at our principal executive offices. We intend to post any amendments of this code or waivers of its provisions applicable to directors or executive officers of our General Partner, including its principal executive officer and principal financial officer, at the above referenced Corporate Governance location on our website.
Procedures for Review, Approval and Ratification of Related Person Transactions
Under our Corporate Code of Business Conduct and Ethics, the board of directors of our General Partner or its authorized committee will periodically review all related-person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. Our Code of Business Conduct and Ethics and Partnership Agreement set forth policies and procedures with respect to transactions with related persons and potential conflicts of interest which, when taken together, provide a structure for the review and approval of transactions with related persons. In the event that the board of directors of our General Partner or its authorized committee considers ratification of a related-person transaction and determines not to so ratify, management will make all reasonable efforts to cancel or annul the transaction.
The conflicts committee is authorized to review, evaluate and approve any potential conflicts of interest between the General Partner or its affiliates (excluding the Partnership), on one hand, and the Partnership, its subsidiaries, or any limited partner of the Partnership, on the other hand; and, the conflicts committee may engage consultants, attorneys, independent accountants and/or other service providers to assist in the evaluation of quantitative and/or qualitative material conflicts matters. Any such approval by the conflicts committee will constitute approval of such matter and no other action of the board of directors is required.
In determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our General Partner or its authorized committee may consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the Corporate Code of Business Conduct and Ethics.
Current conflicts committee members include Ms. Bowman and Messrs. Harper and Shapiro and these three members qualify as independent directors, satisfying the SEC and NYSE standards for independence as of the date hereof.
In April 2021, the SEC approved an amendment to NYSE Rule 314.00 pertaining to related party transactions which requires the Audit Committee, or another independent body of the board of directors of the General Partner, to conduct a reasonable prior review of, and have oversight for, all related party transactions for conflicts of interest and prohibit a transaction if it determines it to be inconsistent with the interests of the Partnership. Pursuant to this amendment, the Audit Committee has established a process to review related party transactions and has provided prior approval for related party transactions that (i) occur in the ordinary course of business; (ii) comply with the Partnership's risk management policies; and, (iii) are conducted on an arm's length basis at market prices and terms.
Available Information
Our audit committee charter, conflicts committee charter, compensation committee charter, Corporate Code of Business Conduct and Ethics, Corporate Governance Guidelines, Financial Code of Ethics, Insider Trading Policy, Short-Swing Trading and Reporting Policy and Whistleblower Policy are available, free of charge within the “Investor Relations-Corporate Governance” section of our website at http://investors.spragueenergy.com/corporate-governance and in print to any unitholder who so requests. Requests for print copies may be directed to: Investor Relations, Sprague Resources LP, 185 International Drive, Portsmouth, New Hampshire 03801 or made by telephone by calling (800) 225-1560. The information contained on or connected to our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Pursuant to our Corporate Governance Guidelines, Mr. Hendel is the lead, non-management director and will preside over regularly scheduled executive sessions of the board of directors without management ("Lead Director"). To view the designated Lead Director and the method for communicating directly with the Lead Director, please see the “Investor Relations-Corporate Governance” section of our website at http://investors.spragueenergy.com/corporate-governance.
Section 16(a) Beneficial Ownership Reporting Compliance
Each director, executive officer (and, for a specified period, certain former directors and executive officers) of our General Partner and each holder of more than 10 percent of a class of our equity securities is required to report to the SEC his or her pertinent position or relationship, as well as transactions in those securities, by specified dates. Based solely upon a review of reports on Forms 3 and 4 (including any amendments) furnished to us during our most recent fiscal year, reports on Form 5 (including any amendments) furnished to us with respect to our most recent fiscal year, and written representations from officers and directors of our General Partner, we believe that all filings applicable to our General Partner’s officers and directors, and our beneficial owners, required by Section 16(a) of the Exchange Act were filed on a timely basis with respect to our most recent fiscal year with the exception of three instances where Form 4s were inadvertently filed late on behalf of a former director and two executives to report certain transactions as follows: (i) in March 2021, to report the award of common units to a former director, Gary A. Rinaldi; (ii) in March 2021, to report the award of common units to executive David C. Long and the payment of tax liability using a portion of securities received; and, (ii) in June 2021, a sale of common units by named executive officer Thomas F. Flaherty.
Employee, Officer and Director Hedging
Per the Short-Swing Trading and Reporting Policy of the General Partner adopted on October 14, 2013, no director, Section 16 officer, or employee who beneficially owns 10% or more of the Partnership's common units, (together, "insiders"), nor an immediate family member of an insider, nor any other relative of an insider living in the insider's home, may make any short sales of any Partnership securities. Also, such persons may not buy or sell puts, calls or options in respect of the Partnership's securities at any time.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
Compensation Committee Interlocks and Insider Participation
The board of directors of the General Partner has determined that all of the directors who served on the compensation committee during fiscal year 2021 are independent within the meaning of the NYSE listing standards. No member of the compensation committee is a current, or during fiscal year 2021 was, a former, officer, or employee of the General Partner. During fiscal year 2021, no member of the compensation committee had a relationship that must be described under the SEC rules relating to disclosure of “related person transactions” (for a description of our policy on “related person transactions,” see "Procedures for Review, Approval and Ratification of Related Person Transactions" in Item 10 and also see “Certain Relationships, Related Transactions and Director Independence” in Item 13. During fiscal year 2021, none of our executive officers served on the board of directors or compensation committee of any entity that had one or more of its executive officers serving on the board or the compensation committee.
Compensation Committee Report
As required by Item 407(e)(5) of Regulation S-K, our compensation committee has reviewed and discussed the Compensation Discussion and Analysis with our management and, based on such review and discussion, has recommended to the board of directors of our General Partner that the Compensation Discussion and Analysis be included in this Annual Report.
THE COMPENSATION COMMITTEE OF THE BOARD OF DIRECTORS OF SPRAGUE RESOURCES GP LLC
John A. Shapiro, Chair
Beth A. Bowman
C. Gregory Harper
Compensation Discussion and Analysis
Introduction
Our General Partner has sole responsibility for conducting our business and for managing our operations and its board of directors and officers make decisions on our behalf. We reimburse our General Partner for the expenses associated with the services its employees provide to us, including compensation expenses for executive officers and directors of our General Partner. The board of directors and the compensation committee of our General Partner has responsibility for establishing and evaluating the pay for the executive officers of our General Partner.
The purpose of this Compensation Discussion and Analysis is to explain our philosophy for determining the compensation program for the Chief Executive Officer, the Chief Financial Officer and the three other most highly compensated executive officers of our General Partner for 2021, referred to in this report as the “Named Executive Officers,” and to discuss why and how the 2021 compensation package for these executives was implemented. Disclosure regarding our Named Executive Officers’ compensation for the 2021 fiscal year is disclosed in the tables below and discussed in this Compensation Discussion and Analysis.
The Named Executive Officers for the fiscal year ending December 31, 2021 are as follows:
David C. Glendon President and Chief Executive Officer
David C. Long Chief Financial Officer
Thomas F. Flaherty Vice President, Refined Products
Brian W. Weego Vice President, Natural Gas
Steven D. Scammon Vice President, Chief Risk Officer
Objectives of Our Executive Compensation Program
Our executive compensation program is based on the following principles:
•The compensation paid to our executives should be competitive with that paid to the executives of those companies with which we compete for executive talent so that we attract and retain a skilled and experienced management team.
•Incentive compensation should be a material portion of total compensation so that our executives are properly motivated to achieve or exceed our financial and business goals.
•Unit holders should receive a minimum acceptable threshold return on investment before payout of incentive compensation.
•Management and owners should share value created above the agreed threshold return.
•Incentive compensation should align the interests of the executive team with those of the unitholders.
The board of directors believes these objectives are best met by providing a mix of competitive base salaries in combination with short- and long-term incentive compensation.
Setting Executive Compensation
Prior to September 14, 2021, we did not have a compensation committee and all compensation decisions were made by the board of directors. Upon the establishment of the compensation committee, the compensation committee makes recommendations to the board of directors with respect to incentive compensation plans and equity-based plans that are subject to approval by the board of directors. When making determinations about each element of compensation for the Named Executive Officers, the compensation committee reviews the goals and objectives relevant to their compensation; and, based on the compensation committee's evaluation, determines, approves and recommends the compensation of the Named Executive Officers.
The compensation committee may also ask Mr. Glendon and certain of our other executives to assess the design of, and make recommendations regarding, compensation and benefit programs and the performance measures and targeted levels of performance. The board of directors is under no obligation to implement the recommendations received from these executives but may take them into consideration when making compensation decisions.
Components of Compensation
For the fiscal year ending December 31, 2021, the compensation for our Named Executive Officers consisted of the following elements:
•Base salary;
•Annual and long-term incentive bonus; and,
•Other benefits, including retirement, health and welfare, and related benefits and, in certain instances, the use of a car or a car allowance.
Base Salary
Each Named Executive Officer’s base salary is a fixed component of compensation and does not vary depending on the level of performance achieved. Base salaries for the Named Executive Officers were historically set at levels deemed appropriate to retain their services. When establishing and evaluating base salary levels the compensation committee generally considers the responsibilities associated with each Named Executive Officer’s position, experience, skill, education, and potential to contribute to our overall success. For example, when the board of directors evaluates Mr. Glendon’s role as President and Chief Executive Officer, the compensation committee considers his current and prior performance. In establishing the base salaries for the rest of our Named Executive Officers, the compensation committee also considers the extent to which the particular individual has the skills to help us solve the challenges we face and the expertise to help us meet our future business goals. Finally, the compensation committee considers the other employment opportunities available to the executive and earning potential associated with those opportunities.
Base salaries for each Named Executive Officer are reviewed annually by the compensation committee as well as at the time of any promotion or significant change in job responsibilities. In connection with each review, individual and company performance over the course of the year are also considered. Mr. Glendon makes recommendations with regard to base salary levels for our Named Executive Officers other than himself, and the compensation committee takes these recommendations into account when reviewing base salary levels.
The following 2021 Base Salary increases for the Named Executive Officers were approved by the board of directors and became effective on April 5, 2021.
Name 2020 Base Salaries 2021 Base Salaries Percentage Increase
David C. Glendon $375,000 $382,000 1.9%
David C. Long $260,024 $267,825 3.0%
Thomas F. Flaherty $275,014 $280,514 2.0%
Brian W. Weego $270,000 $275,400 2.0%
Steven D. Scammon $286,001 $291,721 2.0%
We believe that the competitive base salaries we pay to our Named Executive Officers help us to satisfy the objectives of our executive compensation program by attracting and retaining experienced executive talent. Additionally, by providing our Named Executive Officers with competitive base salaries, we mitigate risk by providing those individuals with a portion of their income that is not subject to change based on our financial performance.
Annual and Long-Term Incentive Bonus
While base salaries offer an important retention tool by providing a fixed level of compensation to our Named Executive Officers, we also seek to incentivize and motivate employees to strive for both individual and overall company success by providing a substantial portion of their compensation in the form of a discretionary annual incentive bonus. Further, we feel that our industry has historically relied heavily on performance-based bonuses to compensate executive officers and we want our compensation program to be consistent with industry trends and practices.
The board of directors restructured the short- and long-term incentive compensation for the Named Executive Officers in 2021. Changes for 2021 included:
•75% of annual incentive bonus paid in cash in the first quarter of 2022, based on return on equity (“ROE”);
•25% of annual incentive bonus to be paid in cash or common units as a long-term incentive bonus in the first quarter of each of 2023, 2024, and 2025 if the ROE threshold for each such year is met and approved by the board of directors in its sole discretion;
•increases in target bonus levels for Named Executive Officers; and
•no equity or equity-based awards granted to the Named Executive Officers (other than the portion of the 2020 annual incentive bonus that was settled in common units in the first quarter of 2021).
These changes to our compensation program were made by our board of directors to address retention concerns and to ensure that a minimum acceptable level of return was received by our unitholders prior to the payment of any amounts under our short- or long-term compensation program. The compensation committee determined that the annual and long-term incentive bonuses for 2021 will be paid entirely in cash due to the pending, unsolicited merger offer of January 11, 2022, from Hartree Partners, LP. The target levels for the Named Executive Officers as follows: Messrs. Long, Flaherty and Weego were each set at 100% of their base salary and Mr. Scammon’s target was 90% of base salary. The 2021 target for Mr. Glendon was set at 250% of his base salary in order to reflect the additional responsibilities associated with his position. Target levels were increased for 2021 to address retention concerns and to increase the value of the award since it would be utilized to calculate the total value of both annual and long-term incentive bonuses, thus replacing value that has historically been granted as long-term equity incentive awards.
Our board of directors selected ROE as the performance metric for the 2021 incentive bonus program, as such metric demonstrates the Partnership's ability to deliver on its growth plan. ROE is a non-GAAP measure and, for Named Executive Officer annual incentive compensation purposes, we define ROE as (i) Sprague operating cash flow ("Sprague OCF") divided by (ii) the Partnership's Market Capitalization, as defined below.
Sprague OCF is a non-GAAP measure; and, for Named Executive Officer 2021 incentive compensation purposes, Sprague OCF defined as net income (loss) before income taxes (i) plus compensation, depreciation and amortization expense (ii) less capital expenditures and (iii) adjusted for (a) the change in unrealized hedging gains (losses) with respect to refined products and natural gas inventory and natural gas transportation contracts, (b) changes in the fair value of contingent consideration, (c) the impact of acquisition related expenses, and (d) extraordinary gains.
Market Capitalization is also a non-GAAP measure; and, for Named Executive Officer 2021 annual incentive compensation purposes, it is calculated as the sum of: (i) the average value of outstanding limited partnership units over the 20 trading days prior to and including December 31, 2020; and, (ii) the value of the incentive distribution rights.
The board of directors proposed a minimum threshold ROE of 5%, or $25.7 million, of Sprague OCF for the 2021 annual incentive bonus pool that must be met before the pool would begin to fund. If the Sprague OCF threshold of $25.7 is met, 22.5% of the Sprague OCF in excess of the threshold amount (the "sharing amount") would be allocated to the bonus pool on a straight line sharing basis. For 2021, the Sprague OCF for annual incentive compensation purposes was $73.6 million. As a result, the Sprague OCF threshold level for the annual incentive bonus program was met.
The board of directors retains the authority to amend or terminate the incentive bonus program, including increasing, decreasing or cancelling bonuses at any time prior to payment of the short or long-term incentive bonus amounts.
The annual incentive bonus received by each Named Executive Officer for 2021 was initially calculated based on the percentage funding level for the total bonus pool. Mr. Glendon then recommended an annual incentive bonus that may be higher or lower based on each Named Executive Officer’s personal performance as well as the performance of their respective business
for that year. Mr. Glendon submitted his recommendations to the compensation committee who then reviewed and discussed the recommendations. After weighing all of this information, the compensation committee established the final annual incentive bonus amounts for each Named Executive Officer.
The following table presents the target bonus levels and the actual payout percentage received by each Named Executive Officer:
Name Target Bonus Percentage of Target Achieved Actual Percentage of Target Paid After Applying Committee Discretion (1) 2021 Bonus Paid in 2022 (3) 2021 Bonus To Be Paid Ratably in 2023, 2024 and 2025(4)
David C. Glendon $955,000 105% 105% $750,000 $250,000
David C. Long $267,825 105% 108% (2) $217,500 $72,500
Thomas F. Flaherty $280,514 105% 107% (2) $225,000 $75,000
Brian W. Weego $275,400 105% 111% (2) $228,750 $76,250
Steven D. Scammon $262,549 105% 105% $206,250 $68,750
(1)Rounded to the nearest whole percentage.
(2)The difference between the Percentage of Target Achieved and the Actual Percentage of Target Paid After Applying Committee Discretion was due to the Named Executive Officer's strong performance during the year.
(3)Represents 75% of the 2021 incentive bonus. To the extent that this figure is greater than 105% of target bonus as the result of discretion applied by the compensation committee and the board of directors, the excess paid over and above 105% of target is reported in the Bonus column of the Summary Compensation Table. Otherwise, these amounts are reported in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
(4)Represents 25% of the 2021 incentive bonus.
Accordingly, 75% of the Named Executive Officer's annual incentive bonus for 2021 was paid in cash in the first quarter of 2022 and the remaining 25% will vest ratably over a three year period and be paid out in common units or cash, or a combination of both, in the discretion of the compensation committee, if the conditions described above are met and approved by the board in its sole discretion. The portion of the 2021 annual incentive bonus that was paid in the first quarter of 2022 is included in the Summary Compensation Table in the column titled "Non-Equity Incentive Compensation"; and, to the extent the actual payout percentage was in excess of the 105% bonus target, the excess amount paid is listed in the "Bonus" column.
Equity Incentive Compensation
In October 2013, our General Partner adopted the LTIP, which provides us with the flexibility to grant a wide variety of cash and equity or equity-based awards. A portion of the annual incentive bonus paid to the Named Executive Officers for performance during 2020 was paid in fully vested common units in the first quarter of 2021. The issuance of such common units represented the only equity or equity-based awards that were granted to any Named Executive Officer during 2021 and was reported in our 10-K filed for the fiscal year ended December 31, 2020.
After a thorough review and analysis in early 2021, the board of directors determined that the outstanding phantom unit awards held by the Named Executive Officers was not meeting the needs and expectations of the board of directors. As a result, in March of 2021, the board of directors terminated all phantom unit awards granted to the Named Executive Officers in 2018, 2019 and 2020. Instead of granting long-term equity incentive compensation in 2021, the board of directors provided the potential for equity compensation as described above.
Severance and Change in Control Benefits
The Named Executive Officers did not have agreements with us that contained severance provisions or change of control payment provisions during the 2021 fiscal year. However, we have a general practice of paying severance to certain of our employees in the event they are terminated by us without cause and they enter into a release. The severance historically provided to executives, such as the Named Executive Officers, serving at the Vice President level and above consists of the following: (i) 12 months of continued base salary payments, (ii) six months of outplacement support, and (iii) health and dental insurance for 12 months at the same cost to the individual as they paid during their employment with us.
We believe that the severance practices described above create an important retention tool for us as post-termination payments allow employees to leave our employment with value in the event of certain terminations of employment that are beyond their control. As a general matter, post-termination payments allow management to focus their attention and energy on making objective business decisions that are in the best interest of the company without allowing personal considerations to affect
the decision-making process. Additionally, executive officers at other companies in our industry and the general market in which we compete for executive talent commonly provide post-termination payments, and we have consistently provided this benefit to certain executives in order to remain competitive in attracting and retaining skilled professionals in our industry.
Other Benefits
Health and Welfare Benefits
Eligible full-time employees, including our Named Executive Officers, may participate in the same health and welfare benefits. These benefits include group health, vision, and dental insurance coverage; participation in our retirement plan; short and long term disability insurance and life insurance coverage; participation in our flexible spending plan; and tuition assistance. The health and dental plans require employee contributions toward the cost of premiums. We provide short and long term disability as well as basic life insurance at no cost to our employees. Employees may also elect additional life insurance coverage at their own expense.
Retirement Benefits
Retiree Health and Life Insurance
During 2021, we provided eligible employees hired prior to January 1, 1991 who were scheduled to work at least 30 hours per week and met certain age and service requirements with the opportunity to participate in our retiree health plan. The obligation for premiums under the retiree health plan is shared by both us and the participants; and, our contributions to such premiums are capped. The retiree health plan does not provide dental benefits. Because Mr. Flaherty is the only Named Executive Officer that was employed by our Predecessor prior to January 1, 1991, he is the only Named Executive Officer eligible to participate in our retiree health plan. We also provide eligible employees with the opportunity to receive post-retirement life insurance on a non-discriminatory basis so long as certain age and service requirements are met. We have historically provided all eligible employees with a retirement program that consisted of multiple sources of contributions.
Sprague Retirement Plan
Eligible employees who are regularly scheduled to at least 1,000 hours per year, including the Named Executive Officers, are eligible to make salary deferrals (either pre-tax or Roth) and after-tax contributions to our retirement plan, and we have historically made certain matching contributions. Employees can contribute between 1% and 70% of their eligible compensation (i.e., base pay, annual bonus, overtime pay, and commissions) as salary deferrals; however, combined pre-tax and Roth contributions cannot exceed 70% of eligible compensation. The amounts that can be contributed are also subject to the annual limitations imposed by federal tax law. The company will match 60% of the first 6% of eligible compensation that an employee contributes as a salary deferral. The company also provides employer contributions to certain eligible employees. For 2021, the company provided an amount equal to 5% of all eligible compensation for eligible employees, including the Named Executive Officers. The company also provided an additional 3%-8% of eligible compensation for eligible employees with certain levels of service who participated in a defined benefit plan sponsored by our former affiliate at the time it was frozen and were close to retirement age. Mr. Flaherty is the only NEO who received this additional contribution in 2021, and he received a 5% contribution. This additional contribution is intended to help those employees with a shorter earnings horizon, as they had less time to adjust their financial retirement planning following our affiliate’s decision to freeze the defined benefit plan. Participating employees are immediately 100% vested in all contributions including employee and company contributions as well as any earnings of the plan.
Automobiles and Auto Allowances
We provide cars to employees based on their job requirements, such as the amount of travel that is necessary in order for such employee to properly perform his or her job duties. Employees who are eligible to receive a car benefit may elect whether to receive the use of a company car or a cash auto allowance. In 2021, Mr. Flaherty was the only Named Executive Officer eligible to receive this benefit.
Risk Assessment
The board of directors has reviewed our compensation policies as generally applicable to the employees of our General Partner and believes that such policies do not encourage excessive and unnecessary risk-taking, and that the level of risk associated with such policies is not reasonably likely to have a material adverse effect on us. Each time a new compensation policy or program is implemented we consider any risks that may be created by its implementation and work to design the program so as to minimize such risks. In addition, we continually evaluate the effectiveness of our compensation programs, by analyzing the incentives such programs create and considering how we can minimize or eliminate incentives that may create risk for us.
Our compensation policies and practices are centrally designed and administered, and are substantially identical between our business divisions, except in cases such as commission arrangements which have been tailored to encourage specific sales behavior. In addition, we believe the following specific factors, in particular, reduce the likelihood of excessive risk-taking:
•Our overall compensation levels are competitive with the market.
•Our compensation mix consists of fixed components like salary and benefits, as well as annual incentives that reward overall company and individual performance.
•Our annual incentive bonus program combines short-term and long-term performance goals which we believe appropriately focuses our Named Executive Officers on both our short- and long-term performance.
•The board of directors of our General Partner has retained an appropriate level of discretion to modify, eliminate, or withhold amounts under the annual and long-term incentive bonus compensation program.
Although a significant portion of the compensation provided to our Named Executive Officers is performance-based, we believe our compensation program does not encourage excessive and unnecessary risk taking by the executive officers (or other employees) as the program are designed to encourage employees to remain focused on both our short- and long-term operational and financial goals. We set performance goals that we believe are challenging but reasonable in light of our past performance and market conditions. At the end of each year, we review the performance of every employee as part of an annual performance review that involves several levels of management oversight. The results of those performance reviews, in addition to our short- and long-term performance, become a major factor in determining what incentives each employee will receive.
A portion of the performance-based, variable compensation we provide to our Named Executive Officers is comprised of amounts that are subject to non-payment or vesting if the organization does not achieve a threshold level of Sprague OCF and approval by the board of directors. As such, we believe that executives are less likely to take unreasonable risks. Once threshold levels of performance are achieved, our performance-based incentives provide payouts of compensation at levels below full performance target achievement, in lieu of an “all or nothing” approach.
Additionally, we have a Chief Risk Officer who serves as chair of the Risk Management Committee, comprised of several members of management. The Risk Management Committee is responsible for reviewing policies and procedures which could encourage risk taking. In addition to our internal reporting structure, the Chief Risk Officer has a direct reporting relationship to the board of directors and has the authority to review all aspects of our business and to develop and maintain policies and procedures that discourage employees from taking unnecessary or inappropriate risks.
Summary Compensation Table
The table below summarizes the total compensation earned by or paid to our Named Executive Officers during the last three fiscal years.
Name and Title Year Salary
($)(1) Bonus
($) (2) Stock
Awards
($)(3) Non-Equity Incentive Plan Compensation ($)(4) Change in
Pension Value
Non-Qualified
Deferred
Compensation
Earnings
($)(5) All
Other
Compensation
($)(6) Total ($)
David C. Glendon 2021 380,481 - - 1,070,010 - 24,940 1,475,431
President and Chief Executive Officer 2020 381,177 45,000 727,177 - N/A 24,510 1,177,864
2019 371,307 - 502,400 - N/A 24,080 897,787
David C. Long
2021 265,725 6,588 - 291,053 - 23,866 587,232
Chief Financial Officer 2020 263,575 40,000 337,377 - 13,836 22,668 677,456
2019 255,000 - 171,520 - 16,857 21,898 465,275
Thomas F. Flaherty 2021 279,034 4,095 - 316,425 - 51,440 650,994
Vice President, Refined Products 2020 279,635 40,000 228,759 - 51,066 50,031 649,491
2019 272,696 - 145,920 - 97,304 48,781 564,701
Brian W. Weego 2021 273,946 11,873 - 312,398 - 23,299 621,516
Vice President, Natural Gas 2020 270,000 30,000 228,759 - 20,175 23,560 572,494
2019 265,721 - 145,920 - 25,978 22,851 460,470
Steven D. Scammon 2021 290,181 - - 287,701 - 24,940 602,822
Vice President, Chief Risk Officer 2020 291,050 40,000 220,544 - 20,024 24,510 596,128
2019 284,437 - 134,560 - 26,476 23,791 469,264
(1)Amounts in this column reflect all compensation earned by the Named Executive Officers during the fiscal year as base salary.
(2)Amounts in this column reflect the discretionary cash bonus paid for the year specified. More specifically, for 2021, the amounts reported represent the portion of the 2021 annual cash incentive bonus that was paid over and above the 105% of target (the actual performance level).
(3)Amounts in this column reflect the grant date fair value for the common units granted to our Named Executive Officers in the year noted as well as the portion of the annual bonus earned for that year that was paid in common units in the first quarter of the subsequent year.
(4)These are the amounts paid under the annual incentive bonus program for performance in 2021. These amounts are comprised of the following:
Name Portion of 2021 Incentive Bonus Paid in Q1 2022 ($) Portion of the 2020 Incentive Bonus Paid in Q1 2022 Based on 2021 Performance ($) Non-Equity Incentive Plan Total ($)
David C. Glendon 750,000 320,010 1,070,010
David C. Long 210,912 80,141 291,053
Thomas F. Flaherty 220,905 95,520 316,425
Brian W. Weego 216,878 95,520 312,398
Steven D. Scammon 206,250 81,451 287,701
(5)Amounts in this column represent the actuarial increase, if any, in the present value of benefits under pension plans sponsored by our former affiliate in 2019 and 2020. Mr. Glendon did not participate in these plans. Negative values are not reported in this column and are instead indicated by use of a dash.
(6)The amounts set forth in this column for 2021 represent: (i) Retirement Plan matching contributions; (ii) Retirement Plan employer contributions; (iii) Named Executive Officer car allowance for Mr. Flaherty; and, (iv) other incidental payments. Although we typically make a contribution to the Retirement Plan equal to 5% of each Named Executive Officer’s base
pay, we make a supplemental contribution of an additional 5% for Mr. Flaherty as a result of his age and years of service at the time our former affiliate froze its defined benefit plan, and, as such, the amount of his employer contribution is double that of the other Named Executive Officers. For a quantification of these benefits, please see the table below. For more information regarding these benefits, please see the Other Benefits section of our Compensation Discussion and Analysis above.
Recipient 401(k) Plan Matching Contribution ($) Defined Contribution Plan ($) Car Allowance ($) All Other Compensation Total ($)
David C. Glendon 10,440 14,500 - 24,940
David C. Long 9,366 14,500 - 23,866
Thomas F. Flaherty 10,440 29,000 12,000 51,440
Brian W. Weego 8,799 14,500 - 23,299
Steven D. Scammon 10,440 14,500 - 24,940
Grants of Plan-Based Awards
The Grants of Plan-Based Awards Table sets forth information regarding the annual and long-term incentive bonus granted for performance in 2021.
Name
Estimated future payouts under non-equity incentive plan awards
Threshold ($)
Target ($)(1)
Maximum ($)
David C. Glendon 955,000
David C. Long 267,825
Thomas F. Flaherty 280,514
Brian W. Weego 275,400
Steven D. Scammon 262,549
(1) Reflects the target bonus amount for each Named Executive Officer under our annual and long-term incentive compensation program for 2021. Because the award provides for only a single estimated payout, that amount is reported as the target and no threshold or maximum amounts are reported. For additional information regarding our annual and long-term incentive compensation program for 2021 please see the section of our Compensation Discussion and Analysis entitled “Annual and Long-Term Incentive Bonus”, above.
Outstanding Equity Awards at Fiscal Year-End and Option Exercises and Stock Vested
No time-based or performance-based phantom units held by our Named Executive Officers vested during 2021. We have not granted any stock options or stock appreciation rights under our LTIP or otherwise. The fully vested common units granted in the first quarter of 2021 in payment of the 2020 annual cash incentive bonus were reported in our 10-K filed for the fiscal year ended December 31, 2020.
Potential Payments Upon Termination or a Change in Control
The Named Executive Officers did not have agreements with us that contained severance provisions or change in control payment provisions during the 2021 fiscal year. However, we have a general practice of paying severance to certain of our employees in the event they are terminated by us without cause and they execute a release. A termination without “cause” has historically been determined on a case-by-case basis rather than by applying any one definition or a specific set of events to each employee. The severance payments historically provided to executives, such as the Named Executive Officers, serving at the Vice President level and above, consist of the following: (i) 12 months of continued base salary severance, (ii) 6 months of outplacement support; and, (iii) health and dental insurance for 12 months provided at the same cost as such individual paid during his or her employment with us.
The table below quantifies the payments that would be due to each of our Named Executive Officers if the events described below had occurred on December 31, 2021. These amounts are estimates calculated based on the assumptions included in the
footnotes below. The actual value received by our Named Executive Officers upon the occurrence of one of these events may vary from the amounts reported below.
Name Cash Severance ($)(1) Outplacement
Support ($)(2) Health and
Dental ($)(3) Annual and Long-Term Incentive Bonus ($)(4) Total
Potential
Termination
Benefits ($)
David C. Glendon
Termination Without Cause 382,000 6,000 25,952 - 413,952
Retirement, Death, Disability - - - - -
David C. Long
Termination Without Cause 267,825 6,000 27,337 - 301,162
Retirement, Death, Disability - - - - -
Thomas F. Flaherty
Termination Without Cause 280,514 6,000 19,508 - 306,022
Retirement, Death, Disability - - - - -
Brian W. Weego
Termination Without Cause 275,400 6,000 19,508 - 300,908
Retirement, Death, Disability - - - - -
Steven D. Scammon
Termination Without Cause 291,721 6,000 25,952 - 323,673
Retirement, Death, Disability - - - - -
(1) Amounts in this column reflect 12 months' worth of continued base salary severance based on each Named Executive Officer's base salary in effect as of December 31, 2021.
(2) Amounts in this column reflect the estimated cost to us of providing outplacement services to the Named Executive Officers over a six-month period. The actual cost of such services could vary based on the individual needs of each Named Executive Officer and the outside provider of such services.
(3) Amounts in this column reflect the value of continued health and dental benefits for a 12-month period based on the value of the benefits received by each individual as of December 31, 2021.
(4) Amounts in this column assume threshold performance is achieved.
CEO Pay Ratio - 18.5:1
Pursuant to Section 953(b) of the Dodd-Frank Act and Item 402(u) of Regulation S-K, this section provides information regarding the relationship of the annual total compensation for fiscal year 2021 of Mr. Glendon, our Chief Executive Officer (“CEO”), to that of our Median Employee (as defined below).
For fiscal year 2020, our CEO’s annual total compensation, as reported in the Summary Compensation Table, was $1,475,431, and our Median Employee’s annual total compensation was $79,726. The ratio of our CEO’s total annual compensation to that of our Median Employee for fiscal year 2021 is 18.5 to 1.
Determining our Median Employee
In determining our Median Employee (as defined below), we selected October 31, 2021 as the date on which to identify our total employee population, which includes all employees in the U.S. and Canada. Employees on leave of absence were also included. In identifying our Median Employee, we used the compensation of all of our employees for the twelve-month period of January 1, 2021, through December 31, 2021, which included the following items:
i.Actual wages and salaries based on all payroll payments, excluding group term life; and
ii.Actual, or if not available target, annual incentive bonus amounts for each employee.
For permanent employees who were not employed for the full twelve-month period, their wages, salaries and target annual incentive bonuses were adjusted to reflect an estimate of such base rates of pay for the full twelve-month period. Wages and
salaries were not adjusted for seasonal, part-time or temporary employees. In addition, we applied a Canadian to U.S. dollar exchange rate of 1.2639 USD per 1.00 CAD at December 31, 2021 to the compensation elements paid in Canadian currency.
After calculating each employee’s compensation using this consistently applied methodology, we then ranked all of our 747 employees, excluding the CEO, based on compensation from lowest to highest. We calculated the annual total compensation of the employee ranked 374 in the same manner as the "Total Compensation" shown for our CEO in the Summary Compensation Table above to determine compensation for the median employee ("Median Employee").
2021 DIRECTOR COMPENSATION
We use a combination of cash and equity compensation to attract and retain qualified candidates to serve as directors of our General Partner. In setting director compensation, we consider the time commitment directors must make in performing their duties, the level of skills required by directors and the market competitiveness of director compensation levels.
Each non-employee director receives an annual retainer of $60,000, paid in quarterly installments. Each non-employee director also receives an annual equity award, granted within five business days of October 15 of each year, equal to the number of fully vested common units having a grant date fair value of approximately $60,000. Further, each non-employee director serving as a chairman or a member of a committee of the board receives an annual supplemental retainer of $10,000 or $5,000, respectively, paid in quarterly installments. If directors serve on more than one committee, they receive a supplemental retainer for each committee upon which they serve. All directors receive reimbursement for out-of-pocket expenses associated with attending meetings of the board or committees of the board of directors. Each director is covered by liability insurance and will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
The table below summarizes the compensation earned by members of the board for the fiscal year ended December 31, 2021.
Name (1) Fees Earned or
Paid in Cash
($)(2) Unit Awards
($)(3)(4) All Other Compensation ($) Total
($)
C. Gregory Harper 77,500 60,000 137,500
Beth A. Bowman 77,500 60,000 137,500
John A. Shapiro (5) 57,500 60,000 117,500
Gary A. Rinaldi (6) 15,000 - 15,000
Ben J. Hennelly (7) 17,500 - 456,077 473,577
(1)Mr. Milligan and Ms. Sarsfield, as officers of Axel Johnson, and Messrs. Hendel, Semlitz, Merison, Levy, Lemme, and Voelker as officers of Hartree, and Mr. Glendon are not included in this table because they receive no compensation for their services as directors. The compensation received by Mr. Glendon as a Named Executive Officer is shown in the Summary Compensation Table.
(2)The amounts in this column reflect the aggregate dollar amount of fees earned or paid in cash for fiscal year 2021, including annual retainer fees and chairmanship or membership fees. Ms. Bowman served on the Conflicts Committee (Chair) and the Audit Committee and , beginning in September 2021, the Compensation Committee. Mr. Harper served on the Audit Committee (Chair) and the Conflicts Committee and, beginning in September 2021, the Compensation Committee. Mr. Shapiro joined the board of directors on June 23, 2021 and served on the Audit Committee and Conflicts Committee; and, beginning in September 2021, served on the Compensation Committee (Chair).
(3)Represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. Messrs. Harper and Shapiro and Ms. Bowman all received a fully vested grant of 2,764 common units valued at approximately $60,000 in October 2021. Please see Note 20 - Equity and Equity-Based Compensation in the Notes to our Consolidated Financial Statements for assumptions used in valuing our common units.
(4)On December 31, 2021, none of our directors held outstanding, unvested equity awards.
(5)Mr. Shapiro was appointed to the board of directors as of June 23, 2021 and received three out of the four quarterly retainer payments and an October 2021 stock award of 2,764 units. Mr. Shapiro also earned the supplemental retainer for his role as Chair of the Compensation Committee.
(6)Mr. Rinaldi ceased serving as a member of our board of directors on May 28, 2021, in connection with closing of the Transaction between Sprague Holdings (a subsidiary of Axel Johnson) and Sprague HP Holdings, LLC (a wholly-owned subsidiary of Hartree Partners LP) and, as a result, only received compensation for services rendered as a member of the board through such date.
(7)April 19, 2021, Mr. Hennelly, then a member of our board of directors, entered into an offer letter (the “Offer Letter”) under which Mr. Hennelly would serve as Chief Information Officer (“CIO”) for the General Partner effective as of July 1, 2021. Mr. Hennelly ceased serving as a member of our board of directors on May 28, 2021 in
connection with closing of the Transaction between Sprague Holdings (a subsidiary of Axel Johnson) and Sprague HP Holdings, LLC (a wholly-owned subsidiary of Hartree Partners LP) and, as a result, only received compensation for services rendered as a member of the board through such date. Pursuant to the Offer Letter for the CIO position, the General Partner has agreed to pay Mr. Hennelly $265,000 annually with a discretionary, annual incentive compensation opportunity equal to 100% of base salary, of which 25% would be deferred and, subject to threshold attainment and board approval, and in the board's sole discretion, paid out ratably over three successive years. Mr. Hennelly's total compensation includes compensation from his board service, consulting fees, wages and benefits and incentive bonus compensation. Amounts paid to Mr. Hennelly in his capacity as a consultant to our General Partner and as CIO in 2021 are reflected in the All Other Compensation column.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of common units of Sprague Resources LP that are issued and outstanding as of March 3, 2022 and held by:
•each person known by us to be a beneficial owner of more than 5% of our outstanding units, including Sprague Holdings;
•each of the directors of and nominees to our General Partner’s board of directors;
•each of the named executive officers of our General Partner; and
•all of the directors, director nominees and executive officers of our General Partner as a group.
All of such information is based on publicly available filings, unless otherwise known to us from other sources. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
Name of Beneficial Owner Common Units
Beneficially
Owned Percentage of
Common Units
Beneficially
Owned
Sprague HP Holdings, LLC (1)(2) 19,548,849 74.5%
Hartree Partners, LP (1)(2) 19,548,849 74.5%
Hartree Partners GP, LLC (1)(2) 19,548,849 74.5%
Stephen M. Hendel - *
Stephen M. Semlitz - *
Jonathan Guy Merison - *
Scott A. Levy 45,135 *
Jason T. Lemme - *
C. Gregory Harper 26,615 *
Beth A. Bowman 17,718 *
John A. Shapiro 2,764 *
David C. Glendon 123,459 *
David C. Long 30,050 *
Thomas E. Flaherty 41,991 *
Brian W. Weego - *
Steven D. Scammon 38,908 *
All executive officers and directors of our
General Partner as a group (18 persons) 413,153 (3) 1.6%
* Represents less than 1%.
(1)The address for this entity is 1185 Avenue of the Americas, New York, NY 10036.
(2)Common units shown as beneficially owned by Hartree Partners and LP, Hartree Partners GP, LLC reflect common units owned of record by Sprague HP Holdings, LLC. Hartree Partners, LP is the sole member of Sprague HP Holdings, LLC and, as such, Hartree Partners, LP may be deemed to share beneficial ownership of the units beneficially owned by Sprague HP Holdings, LLC, but disclaims such beneficial ownership. Hartree Partners GP, LLC is the general partner of Hartree Partners, LP and, as such, Hartree Partners GP, LLC may be deemed to share beneficial ownership of the units
beneficially owned by Sprague HP Holdings, LLC, but disclaims such beneficial ownership. Beneficial ownership reported is based solely on Form 13D filed on January 11, 2022.
(3)The address of each of the executive officers and directors is 185 International Drive, Portsmouth, NH 03801.
Securities Authorized for Issuance Under Equity Compensation Plans
The following information is reported as of December 31, 2021.
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights Weighted-average
exercise price of
outstanding options,
warrants and rights Number of Securities remaining
available for future issuance
under equity compensation
plans (excluding securities
reflected in column (a))
Plan Category (a)(1) (b)(2) (c)
Equity compensation plans approved by security holders - - 975,605
Equity compensation plans not approved by security holders - - -
(1)Awards in this column represent the total number of all performance-based phantom units granted under our LTIP and outstanding as of December 31, 2021. We have not granted any stock option awards.
(2)The outstanding phantom units do not have an exercise price. As such, there is no weighted average exercise price to report for outstanding awards.
Our only equity compensation plan is the Sprague Resources LP 2013 Long-Term Incentive Plan, also referred to herein as the “LTIP”. The LTIP was approved by our shareholders prior to our initial public offering but has not been approved by our public shareholders. A description of the material terms of the LTIP is available in our registration statement on Form S-1, last filed on October 15, 2013 under the heading “Compensation Discussion and Analysis-2013 Long-Term Incentive Plan.”

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships, Related Transactions and Director Independence
Distributions and Payments to Sprague Holdings and Its Affiliates
The following summarizes the distributions and payments made or to be made by us to Sprague Holdings and its affiliates in connection with our formation and ongoing operation and distributions and payments that would be made by us if we were to liquidate in accordance with the terms of our partnership agreement. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Formation Stage
Consideration given to Sprague Holdings and its affiliates for the contributions of assets and liabilities to us included the following:
•1,571,970 common units;
•10,071,970 subordinated units (converted to common units on February 16, 2017);
•non-economic general partner interest; and
•incentive distribution rights; and
Operational Stage
Distributions of Cash to Sprague Holdings and its Affiliates
We will generally make cash distributions to common unitholders, including Sprague Holdings as the holder of an aggregate of 19,548,849 common units. Our General Partner will not receive distributions on its non-economic general partner interest. If distributions exceed the minimum quarterly distribution and other higher target levels, the holders of our incentive distribution rights (currently Sprague Holdings) will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target level. During the year ended December 31, 2021, Sprague Holdings received $2.1 million related to its incentive distribution rights and received distributions of approximately $30.0 million on its common units.
On February 11, 2021, Sprague Holdings provided notice to the Partnership that Sprague Holdings had made an IDR Reset Election (the “IDR Reset Election”), as defined in our partnership agreement. Pursuant to the IDR Reset Election, the Partnership issued 3,107,248 common units to Sprague Holdings, the minimum quarterly distribution amount was increased from $0.4125 per common unit per quarter to $0.6675 per common unit per quarter and the levels at which the incentive distribution rights participate in distributions will be reset at higher amounts based on current common unit distribution rates and a formula in our partnership agreement. The IDR Reset Election was consummated and the common units were issued on March 5, 2021.
On October 25, 2021, the Partnership announced a distribution cut from $0.6675 per unit to $0.4338 per unit, which is less than the minimum quarterly distribution of $0.6675 per unit. The board of directors of our General Partner determines the amount of our quarterly distributions and may change our distribution policy at any time.
Payments to our General Partner and its Affiliates
Our General Partner will not receive any management fee or other compensation for its management of us, except as set forth in the services agreement entered into in connection with the closing of the IPO. Under the terms of the partnership agreement, our General Partner and its affiliates will be reimbursed for all expenses incurred on our behalf.
Pursuant to the terms of the services agreement, our General Partner agreed to provide certain general and administrative services and operational services to us, and we agreed to reimburse our General Partner and its affiliates for all costs and expenses incurred in connection with providing such services to us, including salary, 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. Neither the partnership agreement nor the services agreement limits the amount that may be reimbursed or paid by us to our General Partner or its affiliates. The aggregate amount of reimbursements and fees paid by us to our General Partner was $97.2 million for the year ended December 31, 2021.
During the year ended December 31, 2021, the Partnership recorded tank use and storage fee revenue of $0.7 million from lease agreements entered into with Hartree which expired in 2021 and were not renewed. In addition the Partnership made oil and natural gas product purchases from Hartree totaling $147.9 million and generated sales of natural gas products to Hartree of $3.3 million.
During the year ended December 31, 2020, the Partnership recorded tank use and storage fee revenue of $1.4 million from lease agreements entered into with Hartree. In connection with these agreements, the Partnership made net inventory purchases from Hartree Partners LP totaling $71.2 million.
Withdrawal or Removal of our General Partner
If our General Partner withdraws or is removed, the general partner interest and its affiliates’ incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation
Upon our liquidation, our partners, including our General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
Agreements with Affiliates
In connection with the completion of our IPO on October 30, 2013, we entered into certain agreements with our sponsor and certain of its affiliates, as described below.
Omnibus Agreement
On May 28, 2021, pursuant to the terms of the purchase agreement, dated April 20, 2021, among Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson Inc., Sprague HP Holdings, LLC and Hartree Partners, LP, Sprague Resources Holdings LLC and Axel Johnson Inc. provided notice to the General Partner and the Partnership of the termination, pursuant to its terms, of the Omnibus Agreement, dated October 30, 2013 among Axel Johnson Inc., Sprague Resources Holdings LLC, the General Partner and the Partnership.
There were no transactions under the Omnibus Agreement during fiscal year 2021.
Services Agreement
The Partnership, Sprague Energy Solutions, Inc. (“Sprague Solutions”) and Sprague Holdings entered into a services agreement with our General Partner pursuant to which our General Partner agreed to provide certain general and administrative services and operational services to us and our subsidiaries, Sprague Solutions and Sprague Holdings. Pursuant to the terms of the services agreement, we agreed to reimburse our General Partner and its affiliates for all costs and expenses incurred in connection with providing such services to us, including salary, 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. Pursuant to the terms of the services agreement, our General Partner agreed to provide the same services to Sprague Solutions and Sprague Holdings, which also agreed to reimburse our General Partner and its affiliates for all costs and expenses incurred in connection with providing such services.
The services agreement does not limit the amount that may be reimbursed or paid by us to our General Partner or its affiliates. The amount of reimbursements and fees paid by us to our General Partner was $97.2 million for the year ended December 31, 2021.
The initial term of the services agreement was for five years, beginning on October 30, 2013. The agreement automatically renews at the end of the initial term for successive one-year terms until terminated by us or by Sprague Solutions or by giving 180 days prior written notice to our General Partner. The agreement will automatically terminate on the date Sprague Resources GP LLC ceases to be our General Partner. The provisions of the services agreement that are applicable to Sprague Holdings may be terminated by Sprague Holdings by giving 180 days prior written notice to our General Partner, and will automatically terminate on the date on which Sprague Holdings ceases to be our affiliate. The provisions of the services agreement applicable to Sprague Solutions shall automatically terminate on the date on which Sprague Solutions ceases to be a wholly owned direct or indirect subsidiary of us. The services agreement does not limit the ability of the officers and employees of our General Partner to provide services to other affiliates of Sprague Holdings or unaffiliated third parties.
The services agreement is not the result of arm’s-length negotiations and may not have been effected on terms at least as favorable to the parties to the agreement as could have been obtained from unaffiliated third parties.
Terminal Operating Agreement
In October 2013, we entered into an exclusive terminal operating agreement with Sprague Massachusetts Properties LLC, which is a wholly owned subsidiary of Axel Johnson, or one of its wholly owned subsidiaries, with respect to the terminal in New Bedford, Massachusetts. Pursuant to the terminal operating agreement, we were granted the exclusive use and operation
of, and will retain title to all of the refined products stored at, the New Bedford terminal in exchange for a monthly fee of $15,200, subject to adjustment for changes in the Consumer Price Index for the Northeast region. This agreement is not the result of arm’s-length negotiations and may not have been effected on terms at least as favorable to the parties to this agreement as could have been obtained from unaffiliated third parties. The initial term of the terminal operating agreement was for five years, beginning on October 30, 2013 and the agreement has been subsequently extended through October 30, 2023. Additionally, the terminal operating agreement will terminate upon 60 days’ written notice from Axel Johnson or Sprague Massachusetts Properties LLC in the event that Axel Johnson or Sprague Massachusetts Properties LLC determines that termination is necessary to facilitate the sale or development of the New Bedford terminal.
Director Independence
The information required by Item 407(a) of Regulation S-K is included in Part III, Item 10 - "Directors, Executive Officers and Corporate Governance” above.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
The Audit Committee has selected Ernst & Young LLP to serve as the Partnership’s independent auditor for the fiscal year ending December 31, 2021. The Audit Committee in its discretion may select a different registered public accounting firm at any time during the year if it determines that such a change will be in the best interests of the Partnership and our unitholders.
Audit Fees
The following is a summary of the fees billed to us by Ernst & Young LLP for professional services rendered for the fiscal years ended December 31, 2021 and 2020:
2021 2020
Audit Fees (1) $ 1,799,200 $ 1,765,000
Tax Fees (2) 254,962 248,958
Total $ 2,054,162 $ 2,013,958
(1)Audit fees consisted of the audit of our annual financial statements, reviews of our interim financial statements and services associated with SEC registration statements and other SEC matters.
(2)Tax fees consisted of services related to tax compliance, the review of our partnership Form K-1, and research and consultation on other tax related matters.
Policy for Approval of Audit and Non-Audit Services
Our audit committee charter requires that all services provided by our independent public accountants, both audit and non-audit, must be pre-approved by the audit committee. The pre-approval of audit and non-audit services may be given at any time up to a year before commencement of the specified service.
In determining whether to approve a particular audit or permitted non-audit service, the audit committee will consider, among other things, whether such service is consistent with maintaining the independence of the independent public accountants. The audit committee will also consider whether the independent public accountants are best positioned to provide the most effective and efficient service to us and whether the service might be expected to enhance our ability to manage or control risk or improve audit quality.
All fees paid or expected to be paid to Ernst & Young LLP for fiscal 2021 and 2020 were pre-approved by the audit committee in accordance with this policy.
Part IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
(a)Financial Statements, Financial Statement Schedules and Exhibits-The following documents are filed as part of this Annual Report on Form 10-K for the year ended December 31, 2021.
1 Sprague Resources LP Audited Consolidated Financial Statements:
Index to Consolidated Financial Statements
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Consolidated Balance Sheets as of December 31, 2021 and December 31, 2020
Consolidated Statements of Operations for the Years Ended December 31, 2021, December 31, 2020 and December 31, 2019
Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2021, December 31, 2020 and December 31, 2019
Consolidated Statements of Unitholders’ Equity for the Years Ended December 31, 2021, December 31, 2020 and December 31, 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, December 31, 2020 and December 31, 2019
Notes to Consolidated Financial Statements
2 Financial Statement Schedules-No schedules are included because the required information is inapplicable or is presented in the Consolidated Financial Statements or related notes thereto.
3 Exhibits:
Exhibit
No. Description
3.1 Certificate of Limited Partnership of Sprague Energy Partners LP (incorporated by reference to Exhibit 3.1 of Sprague Resources LP's Registration Statement on Form S-1 filed July 27, 2011 (File No. 333-175826)
3.2 Amendment to the Certificate of Limited Partnership of Sprague Energy Partners LP (Changing Name to Sprague Resources LP) (incorporated by reference to Exhibit 3.2 of Sprague Resources LP's Registration Statement on Form S-1 filed July 27, 2011 (File No. 333-175826).
3.3 Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013, effective March 1, 2021.
3.4 Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013 effective October 25, 2019 (incorporated by reference to Exhibit 3.1 of Sprague Resources LP's Current Report on Form 8-K filed October 25, 2019 (File No. 001-36137)).
Exhibit
No. Description
3.5 Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013 effective December 20, 2017 (incorporated by reference to Exhibit 3.1 of Sprague Resources LP's Current Report on Form 8-K filed December 20, 2017 (File No. 001-36137).
3.6 First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP, dated as of October 30, 2013, (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).
3.7 Amended and Restated Limited Liability Company Agreement of Sprague Resources GP LLC (incorporated by reference to Exhibit 3.2 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).
3.8 Composite copy of the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP, dated as of October 30, 2013, as amended by Amendment No. 1, effective December 20, 2017, Amendment No. 2, effective October 25, 2019, and Amendment No. 3, effective March 1, 2021.
3.9 Second Amended and Restated Limited Liability Company Agreement of Sprague Resources GP LLC (incorporated by reference to Exhibit 3.1 of Sprague Resources LP’s Current Report on Form 8-K filed May 28, 2021 (File No. 001-36137)).
4.1 Description of Securities Registered under Section 12 of the Exchange Act (incorporated by reference to Exhibit 4.1 of Sprague Resources LP’s Annual Report on Form 10-K for the year ended December 31, 2019, filed March 5, 2020 (File No. 001-36137)).
10.1 Second Amended and Restated Credit Agreement, dated May 19, 2020, among Sprague Operating Resources LLC, as U.S. borrower, Kildair Service ULC, as Canadian borrower, the several lenders parties thereto, MUFG Bank Ltd., as administrative agent, the co-syndication agents, the co-collateral agents and the co-documentation agents party thereto (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Current Report Form 8-K filed May 21, 2020 (File No. 001-36137)).
10.2 Unit Purchase Agreement, dated March 13, 2017 by and between Sprague Resources, LP and Carbo Industries, Inc. (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Current Report on Form 8-K filed March 16, 2017 (File No. 001-36137)).
10.3 Omnibus Agreement by and among Axel Johnson Inc., Sprague Resources Holdings LLC, Sprague Resources LP and Sprague Resources GP LLC (incorporated by reference to Exhibit 10.3 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).
10.4 Services Agreement by and among Sprague Resources GP LLC, Sprague Resources LP, Sprague Resources Holdings LLC and Sprague Energy Solutions Inc. (incorporated by reference to Exhibit 10.4 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).
10.5 Terminal Operating Agreement by and between Sprague Massachusetts Properties LLC and Sprague Operating Resources LLC (incorporated by reference to Exhibit 10.5 of Sprague Resources LP’s Current Report on Form 8-K filed November 5, 2013 (File No. 001-36137)).
10.6† Sprague Resources LP 2013 Long-Term Incentive Plan, effective as of October 28, 2013 (incorporated by reference to Exhibit 4.4 to Sprague Resources LP’s Registration Statement on Form S-8, filed on October 28, 2013 (File No. 333-191923)).
10.7† Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.8 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).
10.8† Form of Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.9 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).
10.9† Form of Unit Award Letter (incorporated by reference to Exhibit 10.10 to Sprague Resources LP’s Registration Statement on Form S-1, filed on September 24, 2013 (File No. 333-175826)).
Exhibit
No. Description
10.10† Form of Phantom Unit Agreement (Performance Based Vesting) (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Quarterly Report on Form 10-Q filed on August 13, 2014 (File No. 001-36137)).
10.11† Amended and Restated Director Compensation Summary (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Quarterly Report on Form 10-Q filed on November 7, 2016 (File No. 001-36137)).
10.12† Form of Phantom Unit Agreement (Performance Based Vesting) (incorporated by reference to Exhibit 10.13 of Sprague Resources LP's Annual Report on Form 10-K filed March 10, 2016 (File No. 001-36137)).
10.13† Offer Letter with Ben Hennelly, dated April 19, 2021 (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Current Report on Form 8-K filed April 21, 2021 (File No. 001-36137)).
10.14 First Amendment, dated May 11, 2021, to Second Amended and Restated Credit Agreement, dated May 19, 2020, among Sprague Operating Resources LLC, as U.S. borrower, Kildair Service ULC, as Canadian borrower, the several lenders parties thereto, MUFG Bank Ltd., as administrative agent, the co-syndication agents, the co-collateral agents and the co-documentation agents party thereto (incorporated by reference to Exhibit 10.1 of Sprague Resources LP’s Current Report on Form 8-K filed May 11, 2021 (File No. 001-36137)).
10.15 Indemnification Agreement, dated September 1, 2021.
21.1* Subsidiaries of the Registrant.
23.1* Consent of Ernst & Young LLP.
31.1* Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a) /15d-14(a), by Chief Executive Officer.
31.2* Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a) /15d-14(a), by Chief Financial Officer.
32.1** Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer.
32.2** Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer.
101.INS* Inline XBRL Instance Document - The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101.SCH* Inline XBRL Taxonomy Extension Schema Document
101.CAL* Inline XBRL Taxonomy Extension Calculation
101.DEF* Inline XBRL Taxonomy Extension Definition
101.LAB* Inline XBRL Taxonomy Extension Label Linkbase
101.PRE* Inline XBRL Taxonomy Extension Presentation
104* Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101)
† Compensatory plan or arrangement.
* Filed herewith.
** Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.
*** Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules to the Asset Purchase Agreements have been omitted. The registrant hereby agrees to furnish supplementally to the SEC, upon its request, any or all omitted schedules and its materiality and privacy or confidentiality analyses.