SRLP Sprague Resources LP - 10-K

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

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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

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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.

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A principal focus of our business strategy is to grow and expand our business through acquisitions. If we do not make acquisitions on economically acceptable terms, our future growth may be limited and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

A principal focus of our business strategy is to grow and expand our business through acquisitions. Our ability to grow depends, in part, on our ability to make accretive acquisitions that result in an increase in cash from operations generated per unit. If we are unable to make accretive acquisitions, either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, such acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

Any acquisition involves potential risks, including, among other things:

• Mistaken assumptions about volumes, cash flows, net sales and costs, including synergies;

• An inability to successfully integrate the businesses we acquire;

• An inability to hire, train or retain qualified personnel to manage and operate our newly acquired assets;

• The assumption of unknown liabilities;

• 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

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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

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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

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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

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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.

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Cost reimbursements and fees due to our General Partner and its affiliates for services provided to us or on our behalf, which may be determined in our General Partner’s sole discretion, may be substantial and will reduce our distributable cash flow.

Under our partnership agreement, prior to making any distribution on the common units, our General Partner and its affiliates shall be reimbursed for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Pursuant to the terms of the services agreement, our General Partner has agreed to provide certain general and administrative services and operational services to us, and we have agreed to reimburse our General Partner and its affiliates for all costs and expenses incurred in connection with providing such services to us, including salary, incentive compensation, insurance premiums and other amounts allocable to the employees and directors of our General Partner or its affiliates that perform services on our behalf. Our General Partner and its affiliates also may provide us other services for which we may be charged fees as determined by our General Partner. Our partnership agreement and the services agreement do not limit the amount of expenses for which our General Partner and its affiliates may be reimbursed. Payments to our General Partner and its affiliates may be substantial and will reduce the amount of distributable cash flow.

Unitholders have limited voting rights and, even if they are dissatisfied, cannot remove our General Partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner or the board of directors of our General Partner and will have no right to elect our General Partner or the board of directors of our General Partner on an annual or other continuing basis. The board of directors of our General Partner is chosen by Sprague Holdings, a wholly owned subsidiary of 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:

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• 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

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• 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

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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

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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.

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If a tax authority contests the tax positions we take, the market for our common units may be adversely affected and the cost of any such contest 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.

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Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan to the short seller may be considered to have disposed of the loaned units. In that case, such unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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

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

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

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

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We conduct business and own property in numerous states, in the United States most of which impose a personal income tax as well as an income tax on corporations and other entities. We may own property or conduct business in other U.S. states or non-U.S. countries that impose a personal income tax in the future. It is the unitholder’s responsibility to file all U.S. federal, state, local and non-U.S. tax returns.

Item 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

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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,

United States

Canada

Total

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

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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

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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.

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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

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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

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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.

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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)

($ in thousands)

Net sales

Cost of products sold (exclusive of depreciation and amortization)

Operating expenses

Selling, general and administrative

Depreciation and amortization

Total operating costs and expenses

Other operating income

Operating (loss) income

Other income

Interest income

Interest expense

(Loss) income before income taxes

Income tax provision

Net (loss) income

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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,

($ in thousands)

Reconciliation of Operating Income to Adjusted Gross Margin:

Operating (loss) income

Operating costs and expenses not allocated to operating segments:

Operating expenses

Selling, general and administrative

Depreciation and amortization

Other operating income (4)

Add/(deduct):

Change in unrealized (loss) gain on inventory (1)

Change in unrealized value on natural gas transportation contracts (2)

Total adjusted gross margin (3):

Adjusted Gross Margin by Segment:

Refined products

Natural gas

Materials handling

Other operations

Total adjusted gross margin

Reconciliation of Net Income to Adjusted EBITDA

Net (loss) income

Add:

Interest expense, net

Tax provision

Depreciation and amortization

EBITDA (4):

Add/(deduct):

Change in unrealized (loss) gain on inventory (1)

Change in unrealized value on natural gas transportation contracts (2)

Gain on sale of fixed assets not in the ordinary course of business and other operating income (4)

Other non-operating income (5)

Acquisition related expenses (6)

Other adjustments (7)

Adjusted EBITDA

Other Data:

Ten Year Average Heating Degree Days

Heating Degree Days

Variance from average heating degree days

Variance from prior period heating degree days

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(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.

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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)

($ and volumes in thousands, except adjusted unit gross margin)

Volumes:

Refined products (gallons)

Natural gas (MMBtus)

Materials handling (short tons)

Materials handling (gallons)

Net Sales:

Refined products

Natural gas

Materials handling

Other operations

Total net sales

Adjusted Gross Margin:

Refined products

Natural gas

Materials handling

Other operations

Total adjusted gross margin

Adjusted Unit Gross Margin:

Refined products

Natural gas

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.

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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)

($ in thousands)

Operating expenses

Selling, general and administrative expenses

Depreciation and amortization

Interest expense, net

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.

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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,

(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.

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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)

Finance lease obligations (including interest)

Credit facilities (including interest) (2)

Product purchases (3)

Transportation and storage (4)

Deferred consideration (5)

Total

(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,

(in thousands)

Net cash (used in) provided by operating activities

Net cash (used in) provided by investing activities

Net cash provided by (used in) financing activities

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

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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.

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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.

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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

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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.

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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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