x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 45-2637964 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Title of each class | Name of each exchange on which registered | |
Common Units Representing Limited Partner Interests | New York Stock Exchange |
Large accelerated filer | o | Accelerated filer | x | |
Non-accelerated filer | o | (Do not check if a smaller reporting company) | Smaller reporting company | o |
Emerging growth company | o |
Page | ||
PART I | ||
Item 1. | ||
Item 1A. | ||
Item 1B. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
PART II | ||
Item 5. | ||
Item 6. | ||
Item 7. | ||
Item 7A. | ||
Item 8. | ||
Item 9. | ||
Item 9A. | ||
Item 9B. | ||
PART III | ||
Item 10. | ||
Item 11. | ||
Item 12. | ||
Item 13. | ||
Item 14. | ||
PART IV | ||
Item 15. | ||
Item 16. | ||
• | Increase our business with our existing assets and customers. We will make investments in our existing asset base to handle additional products and provide new services to customers. We also intend to win additional business by better serving customers' need for certainty of supply, reduced commodity price risk and high quality customer service. |
• | Acquire additional terminals and marketing and distribution businesses that are accretive. We intend to grow our asset and customer base by acquiring additional marine and inland terminals (both refined products and materials handling) within and adjacent to the geographic markets we currently serve. We also intend to acquire additional refined products and natural gas marketing businesses that can leverage our existing investment in our logistics capabilities and customer service systems to further increase our cash flow. |
• | Limit our exposure to commodity price risk and volatility. We take title to the products we sell in our refined products and natural gas segments, while our materials handling business does not take title to products and is operated predominantly under fixed-fee, multi-year contracts. We will continue to manage our exposure to commodity prices and seek to protect our sales margins by maintaining a balanced position in our purchases and sales through the use of derivatives and forward contracts. Our hedging activities are bounded by specific limits established by the board of directors of our General Partner, which are monitored and reported to senior management on a daily basis by our risk group. |
• | Maintain our operational excellence. We intend to maintain our long history of safe, cost-effective operations and environmental stewardship by investing in the maintenance of our assets and providing training programs for our personnel. We will work diligently to meet environmental regulations and we will continue to enhance our safety programs as our business grows and operating conditions change. |
• | Requiring capital expenditures to comply with environmental control requirements; |
• | Requiring remedial action to mitigate releases of hydrocarbons, hazardous substances or wastes caused by our operations or attributable to former operators; and, |
• | Curtailing the operations of facilities deemed in non-compliance with environmental laws and regulations. |
• | Competition from other companies that sell refined products, natural gas and/or renewable fuels in the Northeast United States and eastern Canada; |
• | Competition from other companies in the materials handling business; |
• | Demand for refined products, natural gas and our materials handling services in the markets we serve; |
• | Absolute price levels, and volatility of prices, of refined products and natural gas in both the spot and futures markets; |
• | Seasonal variation in temperature, which affects demand for natural gas and refined products such as heating oil and residual fuel oil (to the extent that it is used for space heating); and |
• | Prevailing economic and regulatory conditions. |
• | The level of maintenance capital expenditures we make; |
• | The level of operating and general and administrative expenses, including reimbursements to our General Partner and certain of its affiliates for services provided to us; |
• | Fluctuations or changes in federal, state, local and foreign tax rates, including Canadian income and withholding tax rates; |
• | The restrictions contained in our credit agreement, including borrowing base limitations and limitations on distributions; |
• | Our debt service requirements; |
• | The cost of acquisitions we make, if any; |
• | Fluctuations in our working capital needs; |
• | Our ability to access capital markets and to borrow under our credit agreement to make distributions to our unitholders; and |
• | The amount of cash reserves established by our General Partner, if any. |
• | Recession or other adverse economic conditions; |
• | Unseasonably warm temperatures which would negatively impact demand for natural gas and refined products; |
• | High prices caused by an increase in the market price of refined products or natural gas, higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products or natural gas; |
• | Increased conservation, technological advances and the availability of alternative energy, whether as a result of industry changes, governmental or regulatory actions or otherwise. For example, energy efficiency measures, including the installation of improved insulation and the development of more efficient furnaces and other heating devices and increased use of fuel efficient motor vehicles, have adversely affected demand for some of our products, particularly home heating oil and residual fuel oil; and, |
• | Conversion from consumption of heating oil or residual fuel oil to natural gas as such switching and conversions could reduce our sales of heating oil and residual fuel oil. |
• | Make cash distributions; |
• | Incur indebtedness; |
• | Create liens; |
• | Make investments; |
• | Engage in transactions with affiliates; |
• | Make any material change to the nature of our business; |
• | Dispose of assets; and |
• | Merge with another company or sell all or substantially all of our assets. |
• | Our ability to obtain additional financing, if necessary, for working capital, capital expenditures or other purposes may be impaired, or such financing may not be available on favorable terms; |
• | Our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make required debt service payments; |
• | We may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
• | Our flexibility in responding to changing business and economic conditions may be limited. |
• | Mistaken assumptions about volumes, cash flows, net sales and costs, including synergies; |
• | An inability to successfully integrate the businesses we acquire; |
• | An inability to hire, train or retain qualified personnel to manage and operate our newly acquired assets; |
• | The assumption of unknown liabilities; |
• | Limitations on rights to indemnity from the seller; |
• | Mistaken assumptions about the overall costs of equity or debt used to finance an acquisition; |
• | The diversion of management’s and employees’ attention from other business concerns; |
• | Unforeseen difficulties operating in new product areas or new geographic areas; and |
• | Customer or key employee losses at the acquired businesses. |
• | Damage to storage facilities and other assets caused by tornadoes, hurricanes, floods, earthquakes, fires, explosions, extreme weather conditions and other natural disasters; |
• | Acts or threats of terrorism; |
• | Unanticipated equipment and mechanical failures at our facilities; |
• | Disruptions in supply infrastructure or logistics and other events beyond our control; |
• | Operator error; and |
• | Environmental pollution or other environmental issues. |
• | Our General Partner is allowed to take into account the interests of parties other than us, such as its affiliates, including Axel Johnson, in resolving conflicts of interest, which has the effect of limiting its duty to our unitholders. |
• | Affiliates of our General Partner, including Axel Johnson and Sprague Holdings, may engage in competition with us. |
• | Neither our partnership agreement nor any other agreement requires Axel Johnson or Sprague Holdings to pursue a business strategy that favors us. Axel Johnson’s directors and officers have a fiduciary duty to make decisions in the best interests of the stockholders of Axel Johnson. |
• | Some officers of our General Partner who provide services to us devote time to affiliates of our General Partner. |
• | Our partnership agreement limits the liability of and reduces the duties owed by our General Partner to us and our common unitholders, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty. |
• | 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. |
• | 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. |
• | 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. |
• | 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. |
• | We were conducting business in a state but had not complied with that particular state’s partnership statute; or |
• | Your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business. |
Liquids Storage Terminals | Number of Storage Tanks | Storage Tank Capacity (Bbls) | Principal Products and Materials | |||||
** | Sorel-Tracy Quebec, Canada | 27 | 3,282,600 | refined products; asphalt, crude oil | ||||
** | Newington, NH: River Road | 29 | 1,157,300 | refined products; asphalt; tallow | ||||
** | Searsport, ME | 17 | 1,140,700 | refined products; caustic soda; asphalt | ||||
* | Bridgeport, CT | 11 | 1,120,600 | refined products | ||||
* | Albany, NY | 9 | 1,103,600 | refined products | ||||
** | South Portland, ME | 25 | 1,021,000 | refined products; asphalt; clay slurry | ||||
* | East Providence, RI | 9 | 970,400 | refined products | ||||
** | Bronx, NY | 18 | 907,500 | refined products; asphalt | ||||
** | Newington, NH: Avery Lane | 12 | 722,000 | refined products, asphalt | ||||
* | New Haven, CT (1) | 15 | 683,300 | refined products | ||||
* | Quincy, MA | 9 | 657,000 | refined products | ||||
** | Providence, RI | 4 | 484,000 | refined products; asphalt | ||||
*** | Everett, MA | 4 | 317,600 | asphalt | ||||
* | Quincy, MA: TRT (2) | 4 | 304,200 | refined products | ||||
* | Springfield, MA | 10 | 268,200 | refined products | ||||
*** | Oswego, NY | 3 | 209,800 | asphalt | ||||
* | Lawrence, NY and Inwood NY | 10 | 174,000 | refined products | ||||
* | New Bedford, MA (3) | 2 | 85,900 | refined products | ||||
* | Mount Vernon, NY | 7 | 72,100 | refined products | ||||
* | Stamford, CT | 3 | 46,600 | refined products | ||||
* | Washington, PA area - four locations | 20 | 9,100 | refined products | ||||
Total | 248 | 14,737,500 |
Dry Storage Terminals | Number of Storage Pads and Warehouses | Storage Capacity (Square Feet) | Principal Products and Materials | ||||
** | Searsport, ME | 2 warehouses; | 90,000 | break bulk; salt; petroleum coke; | |||
15 pads | 872,000 | heavy lift | |||||
** | Newington, NH: River Road | 3 pads | 390,000 | salt; gypsum | |||
*** | Portland, ME (4) | 7 warehouses; | 215,000 | break bulk; dry bulk; coal; | |||
3 pads | 95,000 | salt | |||||
** | South Portland, ME | 3 pads | 230,000 | salt; coal | |||
** | Providence, RI | 1 pad | 75,000 | salt | |||
9 warehouses; | |||||||
Total | 25 pads | 1,967,000 |
(1) | These tanks are controlled via a storage and thruput agreement with an initial term through July 2, 2019. |
(2) | Operating assets and real estate are leased from an unaffiliated third party through April 30, 2025. |
(3) | Operating assets and real estate are leased from a subsidiary of Sprague Holdings through October 30, 2023. |
(4) | One storage warehouse is leased from an unaffiliated third party and the balance of the property is owned by us. |
• | Our cash distribution policy may be affected by restrictions on distributions under our credit agreement as well as by restrictions in future debt agreements that we enter into. Specifically, our credit agreement contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit agreement, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy. |
• | Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. |
• | Under Section 17-607 of the Delaware Act we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. |
• | We may lack sufficient cash to make distributions to our unitholders due to a number of operational, commercial and other factors or increases in our operating costs, general and administrative expenses, principal and interest payments on our outstanding debt and working capital requirements. |
• | If we make distributions out of capital surplus, as opposed to distributable cash flow, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. We do not anticipate that we will make any distributions from capital surplus. |
• | Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership, limited liability company and corporate laws and other laws and regulations. |
Years Ended December 31, | |||||||||||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||
(in thousands, except unit data and operating data) | |||||||||||||||||||
Statements of Operations Data: | |||||||||||||||||||
Net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 2,389,998 | $ | 3,481,914 | $ | 5,069,762 | |||||||||
Cost of products sold (exclusive of depreciation and amortization) | 3,445,385 | 2,602,788 | 2,179,089 | 3,188,924 | 4,755,031 | ||||||||||||||
Operating expenses | 88,659 | 72,284 | 65,882 | 71,468 | 62,993 | ||||||||||||||
Selling, general and administrative | 80,799 | 87,582 | 84,257 | 94,403 | 76,420 | ||||||||||||||
Depreciation and amortization | 33,378 | 28,125 | 21,237 | 20,342 | 17,625 | ||||||||||||||
Total operating costs and expenses | 3,648,221 | 2,790,779 | 2,350,465 | 3,375,137 | 4,912,069 | ||||||||||||||
Operating income | 122,912 | 64,217 | 39,533 | 106,777 | 157,693 | ||||||||||||||
Other income (expense) | 293 | 108 | (114 | ) | 298 | (288 | ) | ||||||||||||
Interest income | 577 | 339 | 388 | 456 | 569 | ||||||||||||||
Interest expense | (38,931 | ) | (31,345 | ) | (27,533 | ) | (27,367 | ) | (29,651 | ) | |||||||||
Income before income taxes | 84,851 | 33,319 | 12,274 | 80,164 | 128,323 | ||||||||||||||
Income tax provision (1) | (5,032 | ) | (3,822 | ) | (2,108 | ) | (1,816 | ) | (5,509 | ) | |||||||||
Net income | $ | 79,819 | $ | 29,497 | $ | 10,166 | $ | 78,348 | $ | 122,814 | |||||||||
Income attributable to Kildair through December 8, 2014 | — | — | — | — | (4,080 | ) | |||||||||||||
Incentive distributions declared | (7,879 | ) | (3,993 | ) | (1,742 | ) | (321 | ) | — | ||||||||||
Limited partners’ interest in net income | $ | 71,940 | $ | 25,504 | $ | 8,424 | $ | 78,027 | $ | 118,734 | |||||||||
Net income per limited partner unit: | |||||||||||||||||||
Common—basic | $ | 3.17 | $ | 1.15 | $ | 0.40 | $ | 3.71 | $ | 5.88 | |||||||||
Common—diluted | $ | 3.16 | $ | 1.13 | $ | 0.38 | $ | 3.65 | $ | 5.84 | |||||||||
Weighted-average units used to compute net income per limited partner unit: | |||||||||||||||||||
Common—basic | 22,728,218 | 22,208,964 | 11,202,427 | 10,975,941 | 10,131,928 | ||||||||||||||
Common—diluted | 22,737,404 | 22,474,872 | 11,560,617 | 11,141,333 | 10,195,566 | ||||||||||||||
Subordinated—basic and diluted | N/A | N/A | 10,071,970 | 10,071,970 | 10,071,970 | ||||||||||||||
Distributions declared per unit | $ | 2.66 | $ | 2.46 | $ | 2.22 | $ | 1.98 | $ | 1.74 | |||||||||
Adjusted EBITDA (2) | $ | 102,005 | $ | 109,230 | $ | 110,197 | $ | 113,348 | $ | 108,283 |
Years Ended December 31, | |||||||||||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||
(in thousands, except operating data) | |||||||||||||||||||
Cash Flow Data: | |||||||||||||||||||
Net cash provided by (used in): | |||||||||||||||||||
Operating activities | $ | 158,979 | $ | 57,042 | $ | 131,744 | $ | 287,613 | $ | 15,564 | |||||||||
Investing activities | (16,855 | ) | (153,269 | ) | (44,897 | ) | (14,565 | ) | (132,492 | ) | |||||||||
Financing activities | (141,315 | ) | 100,286 | (115,129 | ) | (245,965 | ) | 118,390 | |||||||||||
Other Financial and Operating Data (unaudited): | |||||||||||||||||||
Capital expenditures | $ | 17,249 | $ | 46,955 | $ | 15,986 | $ | 14,899 | $ | 18,580 | |||||||||
Ten Year Average Heating Degree Days (3) | 4,907 | 4,944 | 4,923 | 4,946 | 4,945 | ||||||||||||||
Heating Degree Days (3) | 5,020 | 4,807 | 4,717 | 5,059 | 5,291 | ||||||||||||||
Variance from average heating degree days | 2 | % | (3 | )% | (4 | )% | 2 | % | 7 | % | |||||||||
Variance from prior period heating degree days | 4 | % | 2 | % | (7 | )% | (4 | )% | 4 | % | |||||||||
Total refined products volumes sold (barrels) | 37,639 | 33,720 | 33,240 | 40,099 | 39,720 | ||||||||||||||
Variance from refined products volume from prior period | 12 | % | 1 | % | (17 | )% | 1 | % | 13 | % | |||||||||
Total natural gas volumes sold (MMBtus) | 60,385 | 61,883 | 61,732 | 56,894 | 54,430 | ||||||||||||||
Variance from natural gas volume from prior period | (2 | )% | — | % | 9 | % | 5 | % | 5 | % | |||||||||
Balance Sheet Data (at period end): | |||||||||||||||||||
Cash and cash equivalents | $ | 7,530 | $ | 6,815 | $ | 2,682 | $ | 30,974 | $ | 4,080 | |||||||||
Property, plant and equipment, net | 349,846 | 350,059 | 251,101 | 250,909 | 250,126 | ||||||||||||||
Total assets | 1,245,240 | 1,362,985 | 1,012,474 | 1,000,332 | 1,339,840 | ||||||||||||||
Total debt (including capital lease obligations) | 667,415 | 728,666 | 561,259 | 621,100 | 822,307 | ||||||||||||||
Total liabilities | 1,108,264 | 1,231,151 | 887,037 | 842,847 | 1,223,946 | ||||||||||||||
Total unitholders’ equity | 136,976 | 131,834 | 125,437 | 157,485 | 115,894 |
(1) | The Partnership is treated as a pass through entity for U.S. federal income tax purposes. For pass through entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in our financial statements. The Partnership’s Canadian entities are subject to Canadian income tax. |
(2) | We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA adjusted for changes in unrealized gains (losses) with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts, adjusted for changes in the fair value of contingent consideration, adjusted for the impact of acquisition related expenses, and adjusted for the impact of biofuel excise tax credits resulting from retroactive tax legislation changes that occurred in 2018. For a discussion of the non-GAAP financial measure EBITDA and adjusted EBITDA, please read “Non-GAAP Financial Measures” in Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations”. |
(3) | We use heating degree day amounts as reported by the NOAA Regional Climate Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2010. Commencing April 1, 2018, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same locations over the previous ten-year period. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day amounts in this document have been revised to conform to this presentation. |
Years Ended December 31, | |||||||||||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||
(in thousands) | |||||||||||||||||||
Net income | $ | 79,819 | $ | 29,497 | $ | 10,166 | $ | 78,348 | $ | 122,814 | |||||||||
Add/(deduct): | |||||||||||||||||||
Interest expense, net | 38,354 | 31,006 | 27,145 | 26,911 | 29,082 | ||||||||||||||
Tax expense (benefit) | 5,032 | 3,822 | 2,108 | 1,816 | 5,509 | ||||||||||||||
Depreciation and amortization | 33,378 | 28,125 | 21,237 | 20,342 | 17,625 | ||||||||||||||
EBITDA | $ | 156,583 | $ | 92,450 | $ | 60,656 | $ | 127,417 | $ | 175,030 | |||||||||
Add/(deduct): | |||||||||||||||||||
Change in unrealized gain on inventory (1) | (32,960 | ) | 124 | 31,304 | 2,079 | (11,070 | ) | ||||||||||||
Change in unrealized value on prepaid forward contracts (2) | — | (1,076 | ) | (1,552 | ) | 2,628 | — | ||||||||||||
Change in unrealized value on natural gas transportation contracts (3) | (19,114 | ) | 10,441 | 18,612 | (21,695 | ) | (58,694 | ) | |||||||||||
Other adjustments (4) | 771 | 231 | — | — | — | ||||||||||||||
Biofuel excise tax credits (5) | (4,022 | ) | 4,022 | — | — | — | |||||||||||||
Acquisition related expenses (6) | 747 | 3,038 | 1,177 | 2,919 | 3,017 | ||||||||||||||
Adjusted EBITDA | $ | 102,005 | $ | 109,230 | $ | 110,197 | $ | 113,348 | $ | 108,283 |
(1) | Inventory is valued at the lower of cost or net realizable value. The adjustment related to unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values. The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income (loss). |
(2) | Represents our estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income (loss) until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income (loss). The fair value of the derivatives we use to economically hedge our prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines in value. |
(3) | Represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized gains (losses). |
(4) | Represents the change in the fair value of the contingent consideration related to the 2017 Coen Energy acquisition and accretion expense. |
(5) | On February 9, 2018, the U.S. federal government enacted legislation that reinstated an excise tax credit program available for certain of our biofuel blending activities and in both cases the program was reinstated retroactively to January 1st of the previously expired year. During the year ended December 31, 2018, we recorded excise tax credits of approximately $4.0 million that relate to blending activities that occurred during the year ended December 31, 2017. We record these credits in the period the legislation was enacted as a reduction of cost of products sold (exclusive of depreciation and amortization) resulting in an increase in adjusted gross margin. This adjustment reflects the effect on our adjusted EBITDA had these credits been recorded in the period in which the blending activity took place. |
(6) | We incur expenses in connection with acquisitions and given the nature, variability of amounts, and the fact that these expenses would not have otherwise been incurred as part of our continuing operations, adjusted EBITDA excludes the impact of acquisition related expenses. |
As of December 31, | |||||||
2018 | 2017 | ||||||
United States | $ | 277,405 | $ | 273,374 | |||
Canada | 72,441 | 76,685 | |||||
Total | $ | 349,846 | $ | 350,059 |
• | 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 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. |
• | 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. |
• | New, stricter environmental laws and regulations are increasing the compliance cost of terminal operations, which could adversely affect our results of operations and financial condition. Our operations are subject to federal, state, local and foreign laws and regulations regulating product quality specifications, emissions in the air, discharges to land and water, and the generation, handling, treatment, and disposal of hazardous waste and other materials. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Compliance with laws and regulations may increase our overall cost of business including our capital cost to maintain and upgrade equipment and facilities. |
• | Seasonality and weather conditions. Our financial results are impacted by seasonality in our businesses and are generally better during the winter months, primarily because a material part of our business consists of supplying heating oil, residual fuel oil and natural gas for space heating purposes during the winter. For example, over the 36-month period ended December 31, 2018, we generated an average of 71% of our total heating oil and residual fuel oil net sales during the months of November through March in the Northeast United States. In addition, weather conditions, particularly during these five months, have a significant impact on the demand for our products. Warmer-than-normal temperatures during these months in our areas of operations can decrease the total volume of heating oil, residual fuel oil and natural gas we sell and the adjusted gross margins realized on those sales, whereas colder-than-normal temperatures increase demand for those products and the associated adjusted gross margins. |
• | Growth in exploration and production of shale gas has led to expanded use of natural gas in our marketing area and provided further downstream refined products sales opportunities to support the resource development activity. Supplies of natural gas from shale formations have grown both in the Northeastern region (e.g., Marcellus and Utica Shale) and the other parts of the United States. Further expansion of domestic natural gas supplies is expected. In conjunction with the production gains, natural gas usage in the Northeast United States has increased substantially with the growth trajectory expected to continue over the next few years. A possible outgrowth of this trend could be to reduce consumption of other fuels. However, significant refined products supply and supporting service requirements are expected to continue in support of the equipment used to develop this expanded production. |
• | Absolute price increase or decreases can impact demand and credit risk. Commodity prices in both our refined products and natural gas segments can vary sharply due to market conditions. As commodity product prices rise, we can experience reduced demand as customers engage in conservation efforts, are exposed to a higher level of credit risk to meet customer requirements, and incur increased working capital costs for holding inventory and accounts receivable. In a lower commodity price environment our customers are generally less prone to engage in conservation efforts, we experience lower credit risk, and working capital costs to hold inventory and finance accounts receivable. |
• | The impact of the market structure on our hedging strategy. We typically hedge our exposure to commodity price moves with NYMEX futures contracts and "over the counter" or "OTC" swaps. In markets where futures prices are higher than spot prices (typically referred to as contango), we generate positive margins when rolling our inventory hedges to successive months. In markets where futures prices are lower than spot prices (typically referred to as backwardation), we realize losses when rolling our inventory hedges to successive months. In backwardated markets, we operate with lower inventory levels and, as a result, have reduced hedging and financing requirements, thereby limiting losses. |
• | Energy efficiency, new technology and alternative fuels could reduce demand for our products. Increased conservation and technological advances have adversely affected the demand for heating oil and residual fuel oil. Consumption of residual fuel oil, in particular, has steadily declined in recent years, primarily due to customers converting from other fuels to natural gas, weak industrial demand and tightening of environmental regulations. Use of natural gas is expected to continue to displace other fuels, which we believe will favorably impact our natural gas volumes and margins. |
• | Interest rates could continue to rise. Since mid-2018, the credit markets have been experiencing increasing interest rates as compared to the near-record lows in interest rates that existed since mid-2009. Further increases in interest rates could affect our ability to access the debt capital markets on favorable terms. In addition, interest rates could be higher than current levels, causing our financing costs to increase accordingly. During the 24 months ended December 31, 2018, we hedged approximately 43% of our floating-rate debt with fixed-for-floating interest rate swaps. Although higher interest rates could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes. |
Years Ended December 31, | Increase/(Decrease) | |||||||||||||
2018 | 2017 | $ | % | |||||||||||
($ in thousands) | ||||||||||||||
Net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 916,137 | 32 | % | ||||||
Cost of products sold (exclusive of depreciation and amortization) | 3,445,385 | 2,602,788 | 842,597 | 32 | % | |||||||||
Operating expenses | 88,659 | 72,284 | 16,375 | 23 | % | |||||||||
Selling, general and administrative | 80,799 | 87,582 | (6,783 | ) | (8 | )% | ||||||||
Depreciation and amortization | 33,378 | 28,125 | 5,253 | 19 | % | |||||||||
Total operating costs and expenses | 3,648,221 | 2,790,779 | 857,442 | 31 | % | |||||||||
Operating income | 122,912 | 64,217 | 58,695 | 91 | % | |||||||||
Other (expense) income | 293 | 108 | 185 | 171 | % | |||||||||
Interest income | 577 | 339 | 238 | 70 | % | |||||||||
Interest expense | (38,931 | ) | (31,345 | ) | (7,586 | ) | 24 | % | ||||||
Income before income taxes | $ | 84,851 | $ | 33,319 | $ | 51,532 | 155 | % | ||||||
Income tax provision | (5,032 | ) | (3,822 | ) | (1,210 | ) | 32 | % | ||||||
Net income | $ | 79,819 | $ | 29,497 | $ | 50,322 | 171 | % | ||||||
Years Ended December 31, | Increase/(Decrease) | |||||||||||||
2017 | 2016 | $ | % | |||||||||||
($ in thousands) | ||||||||||||||
Net sales | $ | 2,854,996 | $ | 2,389,998 | $ | 464,998 | 19 | % | ||||||
Cost of products sold (exclusive of depreciation and amortization) | 2,602,788 | 2,179,089 | 423,699 | 19 | % | |||||||||
Operating expenses | 72,284 | 65,882 | 6,402 | 10 | % | |||||||||
Selling, general and administrative | 87,582 | 84,257 | 3,325 | 4 | % | |||||||||
Depreciation and amortization | 28,125 | 21,237 | 6,888 | 32 | % | |||||||||
Total operating costs and expenses | 2,790,779 | 2,350,465 | 440,314 | 19 | % | |||||||||
Operating income | 64,217 | 39,533 | 24,684 | 62 | % | |||||||||
Other income (expense) | 108 | (114 | ) | 222 | (195 | )% | ||||||||
Interest income | 339 | 388 | (49 | ) | (13 | )% | ||||||||
Interest expense | (31,345 | ) | (27,533 | ) | (3,812 | ) | 14 | % | ||||||
Income before income taxes | $ | 33,319 | $ | 12,274 | $ | 21,045 | 171 | % | ||||||
Income tax provision | (3,822 | ) | (2,108 | ) | (1,714 | ) | 81 | % | ||||||
Net income | $ | 29,497 | $ | 10,166 | $ | 19,331 | 190 | % |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
($ in thousands) | |||||||||||
Reconciliation of Operating Income to Adjusted Gross Margin: | |||||||||||
Operating income | $ | 122,912 | $ | 64,217 | $ | 39,533 | |||||
Operating costs and expenses not allocated to operating segments: | |||||||||||
Operating expenses | 88,659 | 72,284 | 65,882 | ||||||||
Selling, general and administrative | 80,799 | 87,582 | 84,257 | ||||||||
Depreciation and amortization | 33,378 | 28,125 | 21,237 | ||||||||
Add/(deduct): | |||||||||||
Change in unrealized gain on inventory (1) | (32,960 | ) | 124 | 31,304 | |||||||
Change in unrealized value on prepaid forward contracts (2) | — | (1,076 | ) | (1,552 | ) | ||||||
Change in unrealized value on natural gas transportation contracts(3) | (19,114 | ) | 10,441 | 18,612 | |||||||
Total adjusted gross margin (4): | $ | 273,674 | $ | 261,697 | $ | 259,273 | |||||
Adjusted Gross Margin by Segment: | |||||||||||
Refined products | $ | 150,965 | $ | 142,467 | $ | 142,581 | |||||
Natural gas | 57,875 | 65,060 | 62,435 | ||||||||
Materials handling | 57,515 | 46,512 | 45,712 | ||||||||
Other operations | 7,319 | 7,658 | 8,545 | ||||||||
Total adjusted gross margin | $ | 273,674 | $ | 261,697 | $ | 259,273 | |||||
Reconciliation of Net Income to Adjusted EBITDA | |||||||||||
Net income | $ | 79,819 | $ | 29,497 | $ | 10,166 | |||||
Add: | |||||||||||
Interest expense, net | 38,354 | 31,006 | 27,145 | ||||||||
Tax provision | 5,032 | 3,822 | 2,108 | ||||||||
Depreciation and amortization | 33,378 | 28,125 | 21,237 | ||||||||
EBITDA (4): | $ | 156,583 | $ | 92,450 | $ | 60,656 | |||||
Add/(deduct): | |||||||||||
Change in unrealized gain on inventory (1) | (32,960 | ) | 124 | 31,304 | |||||||
Change in unrealized value on prepaid forward contracts (2) | — | (1,076 | ) | (1,552 | ) | ||||||
Change in unrealized value on natural gas transportation contracts(3) | (19,114 | ) | 10,441 | 18,612 | |||||||
Biofuel tax credit (5) | (4,022 | ) | 4,022 | — | |||||||
Acquisition related expenses (6) | 747 | 3,038 | 1,177 | ||||||||
Other adjustments (7) | 771 | 231 | — | ||||||||
Adjusted EBITDA (5) | $ | 102,005 | $ | 109,230 | $ | 110,197 | |||||
Other Data: | |||||||||||
Ten Year Average Heating Degree Days (8) | 4,907 | 4,944 | 4,923 | ||||||||
Heating Degree Days (8) | 5,020 | 4,807 | 4,717 | ||||||||
Variance from average heating degree days | 2 | % | (3 | )% | (4 | )% | |||||
Variance from prior period heating degree days | 4 | % | 2 | % | (7 | )% |
(1) | Inventory is valued at the lower of cost or net realizable value. The adjustment related to unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values.The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income (loss). |
(2) | Represents our estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income (loss) until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income (loss). The fair value of the derivatives we use to economically hedge our prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines in value. |
(3) | Represents our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized gains (losses). |
(4) | For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “How Management Evaluates Our Results of Operations.” |
(5) | On February 9, 2018, the U.S. federal government enacted legislation that reinstated an excise tax credit program available for certain of our biofuel blending activities. The program had expired on December 31, 2016 and was reinstated retroactively to January 1, 2017. During the year ended December 31, 2018, we recorded excise tax credits of approximately $4.0 million that relate to blending activities that occurred during the year ended December 31, 2017. We record the credit in the period the legislation was enacted as a reduction of cost of products sold (exclusive of depreciation and amortization) resulting in an increase in adjusted gross margin. This adjustment reflects the effect on our adjusted EBITDA had these credits been recorded in the period in which the blending activity took place. |
(6) | We incur expenses in connection with acquisitions and given the nature, variability of amounts, and the fact that these expenses would not have otherwise been incurred as part of our continuing operations, adjusted EBITDA excludes the impact of acquisition related expenses. |
(7) | Represents the change in the fair value of contingent consideration related to the 2017 Coen Energy acquisition and other expense. |
(8) | We use heating degree day amounts as reported by the NOAA Regional Climate Center. Prior to April 1, 2018, we reported degree day information utilizing the New England oil home heating region and for comparison purposes we used historical degree day information for the New England oil home heating region over the period of 1981-2010. Commencing April 1, 2018, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same locations over the previous ten-year period. We made these changes to incorporate more recent average information and to better reflect the geographic locations of our customer base. All degree day amounts in this document have been revised to conform to this presentation. |
Years Ended December 31, | Increase/(Decrease) | |||||||||||||
2018 | 2017 | $ | % | |||||||||||
($ and volumes in thousands, except adjusted unit gross margin) | ||||||||||||||
Volumes: | ||||||||||||||
Refined products (gallons) | 1,580,838 | 1,416,240 | 164,598 | 12 | % | |||||||||
Natural gas (MMBtus) | 60,385 | 61,883 | (1,498 | ) | (2 | )% | ||||||||
Materials handling (short tons) | 2,627 | 2,366 | 261 | 11 | % | |||||||||
Materials handling (gallons) | 488,972 | 385,896 | 103,076 | 27 | % | |||||||||
Net Sales: | ||||||||||||||
Refined products | $ | 3,357,769 | $ | 2,455,577 | $ | 902,192 | 37 | % | ||||||
Natural gas | 332,038 | 331,669 | 369 | — | % | |||||||||
Materials handling | 57,509 | 46,513 | 10,996 | 24 | % | |||||||||
Other operations | 23,817 | 21,237 | 2,580 | 12 | % | |||||||||
Total net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 916,137 | 32 | % | ||||||
Adjusted Gross Margin: | ||||||||||||||
Refined products | $ | 150,965 | $ | 142,467 | $ | 8,498 | 6 | % | ||||||
Natural gas | 57,875 | 65,060 | (7,185 | ) | (11 | )% | ||||||||
Materials handling | 57,515 | 46,512 | 11,003 | 24 | % | |||||||||
Other operations | 7,319 | 7,658 | (339 | ) | (4 | )% | ||||||||
Total adjusted gross margin | $ | 273,674 | $ | 261,697 | $ | 11,977 | 5 | % | ||||||
Adjusted Unit Gross Margin: | ||||||||||||||
Refined products | $ | 0.095 | $ | 0.101 | $ | (0.006 | ) | (6 | )% | |||||
Natural gas | $ | 0.958 | $ | 1.051 | $ | (0.093 | ) | (9 | )% |
Years Ended December 31, | Increase/(Decrease) | |||||||||||||
2017 | 2016 | $ | % | |||||||||||
($ and volumes in thousands, except adjusted unit gross margin) | ||||||||||||||
Volumes: | ||||||||||||||
Refined products (gallons) | 1,416,240 | 1,396,080 | 20,160 | 1 | % | |||||||||
Natural gas (MMBtus) | 61,883 | 61,732 | 151 | — | % | |||||||||
Materials handling (short tons) | 2,366 | 2,523 | (157 | ) | (6 | )% | ||||||||
Materials handling (gallons) | 385,896 | 276,402 | 109,494 | 40 | % | |||||||||
Net Sales: | ||||||||||||||
Refined products | $ | 2,455,577 | $ | 1,988,597 | $ | 466,980 | 23 | % | ||||||
Natural gas | 331,669 | 334,003 | (2,334 | ) | (1 | )% | ||||||||
Materials handling | 46,513 | 45,734 | 779 | 2 | % | |||||||||
Other operations | 21,237 | 21,664 | (427 | ) | (2 | )% | ||||||||
Total net sales | $ | 2,854,996 | $ | 2,389,998 | $ | 464,998 | 19 | % | ||||||
Adjusted Gross Margin: | ||||||||||||||
Refined products | $ | 142,467 | $ | 142,581 | $ | (114 | ) | — | % | |||||
Natural gas | 65,060 | 62,435 | 2,625 | 4 | % | |||||||||
Materials handling | 46,512 | 45,712 | 800 | 2 | % | |||||||||
Other operations | 7,658 | 8,545 | (887 | ) | (10 | )% | ||||||||
Total adjusted gross margin | $ | 261,697 | $ | 259,273 | $ | 2,424 | 1 | % | ||||||
Adjusted Unit Gross Margin: | ||||||||||||||
Refined products | $ | 0.101 | $ | 0.102 | $ | (0.001 | ) | (1 | )% | |||||
Natural gas | $ | 1.051 | $ | 1.011 | $ | 0.040 | 4 | % |
Years Ended December 31, | Increase/(Decrease) | |||||||||||||
2018 | 2017 | $ | % | |||||||||||
($ in thousands) | ||||||||||||||
Operating expenses | $ | 88,659 | $ | 72,284 | $ | 16,375 | 23 | % | ||||||
Selling, general and administrative expenses | $ | 80,799 | $ | 87,582 | $ | (6,783 | ) | (8 | )% | |||||
Depreciation and amortization | $ | 33,378 | $ | 28,125 | $ | 5,253 | 19 | % | ||||||
Interest expense, net | $ | 38,354 | $ | 31,006 | $ | 7,348 | 24 | % |
Years Ended December 31, | Increase/(Decrease) | |||||||||||||
2017 | 2016 | $ | % | |||||||||||
($ in thousands) | ||||||||||||||
Operating expenses | $ | 72,284 | $ | 65,882 | $ | 6,402 | 10 | % | ||||||
Selling, general and administrative expenses | $ | 87,582 | $ | 84,257 | $ | 3,325 | 4 | % | ||||||
Depreciation and amortization | $ | 28,125 | $ | 21,237 | $ | 6,888 | 32 | % | ||||||
Interest expense, net | $ | 31,006 | $ | 27,145 | $ | 3,861 | 14 | % |
Capital Expenditures | |||||||||||
Expansion | Maintenance | Total | |||||||||
($ in thousands) | |||||||||||
Years Ended December 31, | |||||||||||
2018 (1) | $ | 6,825 | $ | 9,577 | $ | 16,402 | |||||
2017 (2) | $ | 26,870 | $ | 11,521 | $ | 38,391 | |||||
2016 | $ | 7,518 | $ | 8,468 | $ | 15,986 |
(1) | Excludes approximately $0.8 million of land acquired in 2018 in connection with the 2017 Coen Energy acquisition. |
(2) | Excludes approximately $8.6 million of assets acquired in 2017 that were previously leased by the Partnership. |
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) | $ | 25,897 | $ | 9,485 | $ | 11,700 | $ | 3,531 | $ | 1,181 | |||||||||
Capital lease obligations (including interest) | 6,768 | 1,765 | 3,156 | 1,847 | — | ||||||||||||||
Credit facilities (including interest) (2) | 733,863 | 190,145 | 543,718 | — | — | ||||||||||||||
Product purchases (3) | 503,763 | 480,181 | 23,582 | — | — | ||||||||||||||
Transportation and storage (4) | 36,376 | 19,751 | 14,332 | 2,293 | — | ||||||||||||||
Contingent consideration (including discount) (5) | 10,000 | 2,000 | 8,000 | — | — | ||||||||||||||
Deferred consideration (6) | 31,820 | $ | 3,818 | $ | 7,636 | 7,636 | 12,730 | ||||||||||||
Total | $ | 1,348,487 | $ | 707,145 | $ | 612,124 | $ | 15,307 | $ | 13,911 |
(1) | We have leases for a refined products terminal, refined products storage, maritime charters, 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, 2018. The credit agreement has a contractual maturity of April 27, 2021, 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. Therefore, the current portion of the working capital revolving credit facility included in our Consolidated Balance Sheets is the amount we expect to pay down during the course of the year, and the long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. Interest is calculated using the rates in effect as of December 31, 2018, 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) | Contingent consideration payments are related to the Coen Energy acquisition. The amount is remeasured at fair value every reporting period with the change in fair value recorded in general and administrative expenses (see Notes 3 - Business Combinations and 14 - Other Obligations, of Part II, Item 8 of this Annual Report on Form 10-K). The actual amount ultimately paid out may be different depending on the level of achievement of certain operating milestones. |
(6) | Deferred consideration payments are related to the Carbo acquisition (see Notes 3 - Business Combinations and 14 - Other Obligations, of Part II, Item 8 of this Annual Report on Form 10-K). |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
(in thousands) | |||||||||||
Net cash provided by operating activities | $ | 158,979 | $ | 57,042 | $ | 131,744 | |||||
Net cash used in investing activities | $ | (16,855 | ) | $ | (153,269 | ) | $ | (44,897 | ) | ||
Net cash provided by (used in) financing activities | $ | (141,315 | ) | $ | 100,286 | $ | (115,129 | ) |
• | A U.S. dollar revolving working capital facility of up to $950.0 million, subject to the Partnership's borrowing base limits, to be used for working capital loans and letters of credit; |
• | A multicurrency revolving working capital facility of up to $100.0 million, subject to the Partnership's borrowing base limits, to be used for working capital loans and letters of credit; and |
• | A revolving acquisition facility of up to $550.0 million, subject to the acquisition facility Partnership's borrowing base limits, to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate purposes related to the Partnership’s current businesses, and |
• | Subject to certain conditions including the receipt of additional commitments from lenders, the ability to increase the U.S. dollar revolving working capital facilities by $250.0 million and the multicurrency revolving working capital facility by $220.0 million, subject to a maximum increase for both facilities of $270.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million. |
Product Group | Primary Financial Hedging Instrument | |
Gasolines | NYMEX RBOB futures contract | |
Distillates | NYMEX Ultra Low Sulfur Diesel futures contract | |
Residual Fuel Oils | New York Harbor 1% Sulfur Residual Fuel Oil Swaps |
2018 | 2017 | 2016 | |||||||||
(in thousands) | |||||||||||
Refined products contracts | $ | 54,616 | $ | 12,856 | $ | (25,316 | ) | ||||
Natural gas contracts | (1,353 | ) | (1,555 | ) | 7,153 | ||||||
Total | $ | 53,263 | $ | 11,301 | $ | (18,163 | ) |
Interest Rate Swap Agreements | ||||||
Beginning | Ending | Notional Amount | ||||
(in thousands) | ||||||
January 2018 | January 2019 | $ | 275,000 | |||
January 2019 | January 2020 | $ | 300,000 | |||
January 2020 | January 2021 | $ | 300,000 | |||
January 2021 | January 2022 | $ | 300,000 | |||
January 2022 | January 2023 | $ | 250,000 |
Fair Value Measurement | Active Markets Level 1 | Observable Inputs Level 2 | Unobservable Inputs Level 3 | ||||||||||||
(in thousands) | |||||||||||||||
Derivative assets: | |||||||||||||||
Commodity fixed forwards | $ | 42,893 | $ | — | $ | 42,893 | $ | — | |||||||
Commodity swaps and options | 120,258 | 120,231 | 27 | — | |||||||||||
Commodity derivatives | 163,151 | 120,231 | 42,920 | — | |||||||||||
Interest rate swaps | 2,629 | — | 2,629 | — | |||||||||||
Currency swaps | 2 | — | 2 | — | |||||||||||
Total derivative assets | $ | 165,782 | $ | 120,231 | $ | 45,551 | $ | — | |||||||
Derivative liabilities: | |||||||||||||||
Commodity fixed forwards | $ | 21,036 | $ | — | $ | 21,036 | $ | — | |||||||
Commodity swaps and options | 78,678 | 78,674 | 4 | — | |||||||||||
Commodity derivatives | 99,714 | 78,674 | 21,040 | — | |||||||||||
Interest rate swaps | 2,452 | — | 2,452 | — | |||||||||||
Total derivative liabilities | $ | 102,166 | $ | 78,674 | $ | 23,492 | $ | — |
Refined Products | Natural Gas | ||||||||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | 2016 | ||||||||||||||||||
(in thousands) | (in thousands) | ||||||||||||||||||||||
At December 31 | $ | 193 | $ | 67 | $ | 49 | $ | 309 | $ | 341 | $ | 325 | |||||||||||
Average | 54 | 85 | 107 | 358 | 223 | 346 | |||||||||||||||||
High | 193 | 545 | 282 | 740 | 421 | 1,248 | |||||||||||||||||
Low | 12 | 21 | 26 | 172 | 120 | 129 |
Name | Age | Position with our General Partner | |||
Michael D. Milligan | 55 | Chairman of the Board of Directors | |||
Beth A. Bowman | 62 | Director | |||
C. Gregory Harper | 54 | Director | |||
Ben J. Hennelly | 48 | Director | |||
Gary A. Rinaldi | 61 | Director | |||
Sally A. Sarsfield | 59 | Director | |||
David C. Glendon* | 53 | President, Chief Executive Officer and Director | |||
David C. Long* | 45 | Chief Financial Officer | |||
R.J. Kory Arthur* | 54 | Vice President, Chief Accounting Officer | |||
Thomas F. Flaherty* | 63 | Vice President, Refined Products | |||
Steven D. Scammon* | 57 | Vice President, Chief Risk Officer | |||
Paul A. Scoff* | 59 | Vice President, General Counsel, Chief Compliance Officer and Secretary | |||
Joseph S. Smith* | 62 | Vice President, Corporate Development & IT | |||
James A. Therriault* | 58 | Vice President, Materials Handling | |||
Burton S. Russell | 63 | Vice President, Operations | |||
Gillian H. Tierney | 50 | Vice President, Human Resources | |||
Brian W. Weego* | 52 | Vice President, Natural Gas |
* | Indicates an “executive officer” for purposes of Item 401(b) of Regulation S-K. |
THE NON-MANAGEMENT MEMBERS OF THE BOARD OF DIRECTORS |
Michael D. Milligan, Chairman |
Beth A. Bowman |
C. Gregory Harper |
Ben J. Hennelly |
Sally A. Sarsfield |
David C. Glendon | President and Chief Executive Officer |
Gary A. Rinaldi | Senior Vice President, Chief Operating Officer and Chief Financial Officer |
Thomas F. Flaherty | Vice President, Refined Products |
Steven D. Scammon | Vice President, Chief Risk Officer |
Brian W. Weego | Vice President, Natural Gas |
• | The compensation paid to our executives should be competitive with that paid to the executives of those companies with which we compete for executive talent so that we attract and retain a skilled and experienced management team. |
• | Incentive compensation should be a material portion of total compensation so that our executives are properly motivated to achieve or exceed our financial and business goals. |
• | Incentive compensation should align the interests of the executive team with those of the unitholders. |
• | Base salary; |
• | Annual cash incentive bonus; |
• | Long-term equity incentive awards; and, |
• | Other benefits, including retirement, health and welfare, and related benefits and, in certain instances, the use of a car or a car allowance. |
Name | 2017 Base Salaries | 2018 Base Salaries | Percentage Increase | |||
David C. Glendon | $365,925 | $371,413 | 1.5% | |||
Gary A. Rinaldi | $365,925 | $371,413 | 1.5% | |||
Thomas F. Flaherty | $268,666 | $272,695 | 1.5% | |||
Steven D. Scammon | $280,233 | $284,436 | 1.5% | |||
Brian W. Weego | $257,981 | $265,720 | 3.0% |
Increase of Sprague Holdings Operating Cash Flow Above Threshold | Percentage of Target Phantom Units that Vest | |
0.0% | 0% | |
5.2% | 50% | |
10.3% | 100% | |
46.7% | 200% |
2018 Long-Term Incentive Program | |||||
Name | Target Number of Phantom Units Granted | Grant Date Fair Value per Common Unit (1) | |||
David C. Glendon | 20,000 | $23.30 | |||
Gary A. Rinaldi | 20,000 | $23.30 | |||
Thomas F. Flaherty | 5,250 | $23.30 | |||
Steven D. Scammon | 5,000 | $23.30 | |||
Brian W. Weego | 5,250 | $23.30 |
(1) | The value of the phantom performance awards is based on the grant date fair value of those common units, as calculated pursuant to FASB ASC Topic 718. |
• | Our overall compensation levels are competitive with the market. |
• | Our compensation mix is balanced among fixed components like salary and benefits, as well as annual incentives that reward overall company and individual performance. |
• | Our long-term equity incentive program ties vesting to performance over a period of multiple years with common units paid out at the end of the applicable performance period if the pre-established goals are met. These programs were designed to encourage executives to focus on unitholder interests over the longer term. In contrast, the annual incentive bonus focuses on performance over the shorter term. The combination of both programs appropriately focuses our employees on both our short- and long-term performance. |
• | The board of directors of our General Partner has retained an appropriate level of discretion to reduce annual incentive bonus payments if it determines that such adjustments would be appropriate based on our interests and the interests of our unitholders. |
Name and Title | Year | Salary ($)(1) | Bonus ($) (2) | Stock Awards ($)(3) | Change in Pension Value Non-Qualified Deferred Compensation Earnings ($)(4) | All Other Compensation ($)(5) | Total ($) | |||||||||||||
David C. Glendon | 2018 | 369,936 | — | 466,000 | N/A | 23,650 | 859,586 | |||||||||||||
President and Chief Executive Officer | 2017 | 363,993 | 310,000 | 502,740 | N/A | 23,220 | 1,199,953 | |||||||||||||
2016 | 356,394 | 495,650 | 511,890 | N/A | 22,790 | 1,386,724 | ||||||||||||||
Gary A. Rinaldi | 2018 | 369,936 | — | 466,000 | N/A | 23,650 | 859,586 | |||||||||||||
Senior Vice President, Chief Operating Officer and Chief Financial Officer | 2017 | 363,993 | 310,000 | 502,740 | N/A | 23,220 | 1,199,953 | |||||||||||||
2016 | 356,394 | 495,650 | 511,890 | N/A | 22,790 | 1,386,724 | ||||||||||||||
Thomas F. Flaherty | 2018 | 271,611 | — | 122,325 | — | 49,400 | 443,336 | |||||||||||||
Vice President, Refined Products | 2017 | 267,248 | 115,000 | 133,000 | 89,002 | 48,720 | 652,970 | |||||||||||||
2016 | 262,008 | 175,325 | 163,965 | 50,462 | 48,540 | 700,300 | ||||||||||||||
Steven D. Scammon | 2018 | 283,306 | — | 116,500 | — | 23,650 | 423,456 | |||||||||||||
Vice President, Chief Risk Officer | 2017 | 279,118 | 110,000 | 126,350 | 13,621 | 23,220 | 552,309 | |||||||||||||
2016 | 275,356 | 192,701 | 117,931 | 7,037 | 22,790 | 615,815 | ||||||||||||||
Brian W. Weego | 2018 | 263,637 | — | 122,325 | — | 23,057 | 409,019 | |||||||||||||
Vice President, Natural Gas | 2017 | 255,958 | 115,000 | 133,000 | 13,172 | 22,179 | 539,309 | |||||||||||||
2016 | 247,874 | 175,325 | 155,205 | 6,228 | 21,834 | 606,466 |
(1) | Amounts in this column reflect all compensation earned by the Named Executive Officers during the fiscal year as base salary. Prior to April 2, 2018, the annual base salaries for our Named Executive Officers were $365,925 for Messrs. Glendon and Rinaldi, $268,666 for Mr. Flaherty, $280,233 for Mr. Scammon, and $257,981 for Mr. Weego. Effective April 2, 2018, the annual base salaries for our Named Executive Officers were as follows: $371,413 for Messrs. Glendon and Rinaldi, $272,695 for Mr. Flaherty, $284,436 for Mr. Scammon, and $265,720 for Mr. Weego. |
(2) | Amounts in this column for 2018 reflect the fact that no cash amounts were paid under our annual incentive bonus program. |
(3) | Amounts in this column for 2018 reflect the grant date fair value for the performance based phantom awards computed in accordance with FASB ASC Topic 718, disregarding estimated forfeitures, which was $23.30 per common unit. The values of the performance-based phantom units at the grant date assuming that the highest level of performance conditions will be achieved for our Named Executive Officers are as follows: $932,000 for Messrs. Glendon and Rinaldi, $244,650 for Messrs. Flaherty and Weego, and $233,000 for Mr. Scammon. |
(4) | Amounts in this column represent the actuarial increase, if any, in the present value of benefits under the DB Plan and the RRP determined by using interest rate and mortality rate assumptions consistent with those used in the Pension Benefits table below. Messrs. Glendon and Rinaldi do not participate in these plans. Negative values are not reported in this column and are instead indicated by use of a dash. |
(5) | The amounts set forth in this column for 2018 represent: (i) 401(k) plan matching contributions; (ii) our contribution to the DC Plan; (iii) Named Executive Officer car allowance for Mr. Flaherty; and, (iv) other incidental payments. Although we typically make a contribution to the DC Plan equal to 5% of each Named Executive Officer’s base pay, we make a supplemental contribution of an additional 5% for Mr. Flaherty as a result of his age and years of service at the time of the adoption of the DC Plan, and, as such, the amount of his DC Plan contribution is double that of the other Named Executive Officers. For a quantification of these benefits, please see the table below. For more information regarding these benefits, please see the Other Benefits section of our Compensation Discussion and Analysis above. |
Recipient | 401(k) Plan Matching Contribution ($) | Defined Contribution Plan ($) | Car Allowance ($) | Other Incidental ($) | All Other Compensation Total ($) | |||||
David C. Glendon | 9,900 | 13,750 | — | — | 23,650 | |||||
Gary A. Rinaldi | 9,900 | 13,750 | — | — | 23,650 | |||||
Thomas F. Flaherty | 9,900 | 27,500 | 12,000 | — | 49,400 | |||||
Steven D. Scammon | 9,900 | 13,750 | — | — | 23,650 | |||||
Brian W. Weego | 9,307 | 13,750 | — | — | 23,057 |
Name | Grant Date | Estimated Future Payouts Under Equity Incentive Plan Awards (1) | All Other Stock Awards: Number of Shares of Stock or Units (#) | Grant Date Fair Value of Stock and Option Awards ($)(2) | |||||||||||||
Threshold (#) | Target (#) | Maximum (#) | |||||||||||||||
David C. Glendon | 3/8/2018 | — | 20,000 | 40,000 | — | 466,000 | |||||||||||
Gary A. Rinaldi (3) | 3/8/2018 | — | 20,000 | 40,000 | — | 466,000 | |||||||||||
Thomas F. Flaherty | 3/8/2018 | — | 5,250 | 10,500 | — | 122,325 | |||||||||||
Steven D. Scammon | 3/8/2018 | — | 5,000 | 10,000 | — | 116,500 | |||||||||||
Brian W. Weego | 3/8/2018 | — | 5,250 | 10,500 | — | 122,325 |
(1) | Amounts shown in the “Estimated Future Payouts Under Equity Incentive Plan Awards” columns represent the target and maximum settlement levels with respect to the performance-based phantom unit awards granted to our Named Executive Officers pursuant to our LTIP during 2018. The performance-based phantom unit awards do not have a threshold value. Vesting of the phantom units will be determined based on Sprague Holdings Operating Cash Flow performance during the performance period from January 1, 2018 through December 31, 2020. The performance-based phantom unit awards include a distribution equivalent right, which will be paid upon the settlement of the underlying phantom unit. For more information regarding the performance-based phantom unit awards, please see the Components of Compensation - Long-Term Equity Incentive Awards section of our Compensation Discussion and Analysis above. |
(2) | The amounts in this column reflect the aggregate grant date fair value of awards granted to our Named Executive Officers in 2018 computed in accordance with FASB ASC Topic 718, disregarding estimated forfeitures. The grant date fair value of the phantom units issued pursuant to our long term equity incentive program was $23.30 per phantom unit. For a discussion of the valuation assumptions used in determining the grant date fair value of these awards see Note 20 - Equity-Based Compensation of the Notes to Consolidated Financial Statements included in this Annual Report. |
(3) | As a result of Mr. Rinaldi's retirement effective December 31, 2018, his actual payout is limited pursuant to the terms of the phantom unit agreements to a prorated portion of the ultimate payout determined at the end of the performance period ending December 31, 2020. See "Potential Payments Upon Termination or a Change in Control" below. |
Stock Awards | ||||||||||||
Name | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or other Rights That Have Not Vested (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or other Rights That Have Not Vested ($)(1) | ||||||||
David C. Glendon | — | — | ||||||||||
18,900 | (2) | 273,861 | ||||||||||
20,000 | (3) | 289,800 | ||||||||||
Gary A. Rinaldi (4) | — | — | ||||||||||
18,900 | (2) | 273,861 | ||||||||||
20,000 | (3) | 289,800 | ||||||||||
Thomas F. Flaherty | — | — | ||||||||||
5,000 | (2) | 72,450 | ||||||||||
5,250 | (3) | 76,073 | ||||||||||
Steven D. Scammon | — | — | ||||||||||
4,750 | (2) | 68,828 | ||||||||||
5,000 | (3) | 72,450 | ||||||||||
Brian W. Weego | — | — | ||||||||||
5,000 | (2) | 72,450 | ||||||||||
5,250 | (3) | 76,073 |
(1) | Amounts represented assume a market value of $14.49 per common unit, the closing price of our common units on December 31, 2018. |
(2) | Because these awards do not have a threshold value, these figures represent the target settlement level with respect to the performance-based phantom unit awards granted to our Named Executive Officers pursuant to our LTIP on March 6, 2017 based on our performance through December 31, 2018 as required by the Exchange Act. The number of phantom units that will ultimately vest will depend on our performance through the end of the three-year performance period ending December 31, 2019. These awards contain cash distribution equivalent rights that are paid out to the phantom unit holders at the time of settlement of the underlying phantom unit in the same form (cash or common units) as was delivered to our common unitholders at the time of the distribution. From the date of grant until December 31, 2018, all distributions delivered to common unitholders have been paid in cash. |
Name | Plan Name | Number of Years Credited Service (#)(1)(2) | Present Value of Accumulated Benefit ($)(3) | Payments During 2018 Fiscal Year ($) | |||||
David C. Glendon | Axel Johnson Inc. Retirement Plan | — | — | — | |||||
Axel Johnson Inc. Retirement Restoration Plan | — | — | — | ||||||
Gary A. Rinaldi | Axel Johnson Inc. Retirement Plan | — | — | — | |||||
Axel Johnson Inc. Retirement Restoration Plan | — | — | — | ||||||
Thomas F. Flaherty | Axel Johnson Inc. Retirement Plan | 20.4 | 755,701 | — | |||||
Axel Johnson Inc. Retirement Restoration Plan | 20.4 | 196,460 | — | ||||||
Steven D. Scammon | Axel Johnson Inc. Retirement Plan | 3.0 | 89,711 | — | |||||
Axel Johnson Inc. Retirement Restoration Plan | 3.0 | 25,544 | — | ||||||
Brian W. Weego | Axel Johnson Inc. Retirement Plan | 5.0 | 86,345 | — | |||||
Axel Johnson Inc. Retirement Restoration Plan | — | — | — |
(1) | Amounts in this column represent the number of years of credited service rounded to the nearest month and were frozen as of December 31, 2003. |
(2) | Messrs. Glendon and Rinaldi were not eligible to participate in the DB Plan or the RRP as they were hired after January 1, 2003. |
(3) | Amounts in this column represent the actuarial present value of each Named Executive Officer’s accumulated benefit under the DB Plan and the RRP as of December 31, 2018. In quantifying the present value of the accumulated benefit indicated above, we used the same assumptions used for financial reporting purposes under GAAP, except that retirement age was assumed to be the earliest time at which a participant may retire under the plan without any benefit reduction due to age. The material assumptions were as follows: (i) an estimated discount rate of 4.40% for the Axel Johnson Inc. Retirement Plan and an estimated discount rate of 4.30% for the Axel Johnson Inc. Retirement Restoration Plan; (ii) the RP-2014 annuitant table and the MP-2018 mortality improvement scale applied from the RP-2014 mortality table base year; and, (iii) expected long-term rate of return on plan assets of 6.25%. |
1.1% of final average compensation | x | Credited service (up to 40 years, rounded to the nearest month) | + | 0.4% of final average compensation in excess of social security covered compensation | x | Credited service (up to 35 years, rounded to the nearest month) |
Name | Cash Severance ($)(1) | Outplacement Support ($)(2) | Health and Dental ($)(3) | Accelerated Equity ($)(4) | Total Potential Termination Benefits ($) | ||||||||||
David C. Glendon | |||||||||||||||
Termination Without Cause | 371,413 | 6,000 | 22,673 | — | 400,086 | ||||||||||
Retirement, Death, Disability | — | — | — | 33,776 | 33,776 | ||||||||||
Thomas F. Flaherty | |||||||||||||||
Termination Without Cause | 272,695 | 6,000 | 17,018 | — | 295,713 | ||||||||||
Retirement, Death, Disability | — | — | — | 8,866 | 8,866 | ||||||||||
Steven D. Scammon | |||||||||||||||
Termination Without Cause | 284,436 | 6,000 | 22,673 | — | 313,109 | ||||||||||
Retirement, Death, Disability | — | — | — | 8,444 | 8,444 | ||||||||||
Brian W. Weego | |||||||||||||||
Termination Without Cause | 265,720 | 6,000 | 18,661 | — | 290,381 | ||||||||||
Retirement, Death, Disability | — | — | — | 8,866 | 8,866 |
(1) | Amounts in this column reflect 12 months' worth of continued base salary severance based on each Named Executive Officer's base salary in effect as of December 31, 2018. |
(2) | Amounts in this column reflect the estimated cost to us of providing outplacement services to the Named Executive Officers over a six-month period. The actual cost of such services could vary based on the individual needs of each Named Executive Officer and the outside provider of such services. |
(3) | Amounts in this column reflect the value of continued health and dental benefits for a 12-month period based on the value of the benefits received by each individual as of December 31, 2018. |
(4) | A prorated portion of the performance-based phantom units granted in each 2017 and 2018 will remain outstanding and eligible to vest based on actual performance, as determined following the end of the applicable performance period, in the event of a Named Executive Officer's separation from service due to a qualified retirement, death or Disability (as described below) prior to the completion of the applicable performance period. The performance periods applicable to the 2017 and 2018 awards will end on December 31, 2019 and December 31, 2020, respectively, and the number of phantom units that vest for each award will be based on performance through the last day of the applicable performance period. Based upon the performance metrics applicable to the 2017 phantom unit awards and using our performance through December 31, 2018, it is estimated that none of the phantom units granted in 2017 will vest following the end of the performance period, and accordingly no 2017 awards are included in the calculation of our Named Executive Officers' retirement or termination due to death or Disability on December 31, 2018. Actual payment under the 2017 phantom unit awards, assuming maximum performance, could total up to $547,722 for Mr. Glendon, $144,900 for Mr. Flaherty, $137,655 for Mr. Scammon, and $144,900 for Mr. Weego, calculated using the closing price of our common units on December 31, 2018, which was $14.49. Based upon the performance metrics applicable to the 2018 phantom unit awards and using our performance through December 31, 2018, it is estimated that the phantom units granted in 2018 will vest at the 35% performance level following the end of the performance period. As such, the prorated amount our Named Executive Officers would be eligible to receive following the end of the performance period in connection with their retirement or termination due to death or Disability on December 31, 2018 is shown in this column. Actual payment under the 2018 phantom unit awards assuming maximum performance could total up to $579,600 for Mr. Glendon, $152,145 each for Messrs. Flaherty and Weego, and $144,900 for Mr. Scammon, calculated using the closing price of our common units on December 31, 2018, which was $14.49. |
i. | Estimated wages and salaries based on all payroll payments, excluding group term life; and |
ii. | Estimated target annual incentive bonus amounts for each employee. |
Name (1) | Fees Earned or Paid in Cash ($)(4) | Unit Awards ($)(5)(6) | Total ($) | ||||
Robert B. Evans (2) | 56,250 | — | 56,250 | ||||
C. Gregory Harper | 75,000 | 60,000 | 135,000 | ||||
Beth A. Bowman | 71,250 | 60,000 | 131,250 | ||||
Ben J. Hennelly (3) | 60,000 | 60,000 | 120,000 |
(1) | Mr. Milligan and Ms. Sarsfield, as officers of Axel Johnson, and Messrs. Glendon and Rinaldi are not included in this table because they receive no separate compensation for their services as directors. The compensation received by Messrs. Glendon and Rinaldi as our Named Executive Officers is shown in the Summary Compensation Table. |
(2) | On September 24, 2018, Robert B. Evans notified Sprague Resources GP LLC, the general partner of the Partnership, of his decision to resign from the board of directors effective as of October 1, 2018. Mr. Evan’s resignation is not the result of any disagreement with management or the board of directors related to the Partnership’s operations, policies or practices. |
(3) | Mr. Hennelly, an independent strategy and finance consultant, is a former officer of Axel Johnson and former President and Chief Executive Officer of Decisyon Inc., a company in which Axel Johnson owns a 20% minority interest. Effective September 2016, Mr. Hennelly receives separate compensation for his services as a director. |
(4) | The amounts in this column reflect the aggregate dollar amount of fees earned or paid in cash for fiscal year 2018, including annual retainer fees and chairmanship or membership fees. Mr. Evans served on the Conflicts Committee (Chairman) and the Audit Committee, and Mr. Harper served on the Audit Committee (Chairman) and Conflicts Committee. Ms. Bowman is a member of the Audit Committee and the Conflicts Committee. |
(5) | Represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. Messrs. Harper and Hennelly and Ms. Bowman all received a fully vested grant of 2,231 units valued at approximately $60,000 in October 2018. Please see Note 20 - Equity-Based Compensation in the Notes to our Consolidated Financial Statements for assumptions used in valuing our common units. |
(6) | On December 31, 2018, none of our directors held outstanding, unvested equity awards. |
• | each person known by us to be a beneficial owner of more than 5% of our outstanding units, including Sprague Holdings; |
• | each of the directors of and nominees to our General Partner’s board of directors; |
• | each of the named executive officers of our General Partner; and |
• | all of the directors, director nominees and executive officers of our General Partner as a group. |
Name of Beneficial Owner | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | ||
Sprague Holdings LLC (1)(2) | 12,106,348 | 53.3% | ||
Axel Johnson (2)(3) | 12,106,348 | 53.3% | ||
Lexa International Corporation (2)(4) | 12,106,348 | 53.3% | ||
Antonia Ax:son Johnson (2)(5) | 12,106,348 | 53.3% | ||
OppenheimerFunds, Inc. (6) | 1,662,185 | 7.3% | ||
Goldman Sachs Asset Management (7) | 1,195,335 | 5.3% | ||
Gary A. Rinaldi | 110,360 | * | ||
David C. Glendon | 110,173 | * | ||
Thomas E. Flaherty | 36,662 | * | ||
Brian W. Weego | 33,312 | * | ||
Steven D. Scammon | 30,046 | * | ||
Michael D. Milligan | 20,000 | * | ||
C. Gregory Harper | 16,502 | * | ||
Beth A. Bowman | 12,176 | * | ||
Sally A. Sarsfield | 4,100 | * | ||
Ben J. Hennelly | — | * | ||
All executive officers and directors of our General Partner as a group (15 persons) | 468,248 | (8) | 2.1% |
* | Represents less than 1%. |
(1) | The address for this entity is 185 International Drive, Portsmouth, NH 03801. |
(2) | Common units shown as beneficially owned by Axel Johnson, Lexa International Corporation and Antonia Ax:son Johnson reflect common units owned of record by Sprague Holdings. Sprague Holdings is a wholly-owned subsidiary of Axel Johnson and, as such, Axel Johnson may be deemed to share beneficial ownership of the units beneficially owned by Sprague Holdings and its subsidiaries, but disclaims such beneficial ownership. Axel Johnson is a wholly-owned subsidiary of Lexa International Corporation and, as such, Lexa International Corporation may be deemed to share beneficial ownership of the units beneficially owned by Sprague Holdings, but disclaims such beneficial ownership. Lexa International Corporation, through certain non-U.S. entities, is controlled by Antonia Ax:son Johnson and, as such, Antonia Ax:son Johnson may be deemed to share beneficial ownership of the units beneficially owned by Sprague Holdings, but disclaims such beneficial ownership. |
(3) | The address for this entity is 155 Spring Street, 6th Floor, New York, NY 10012. |
(4) | The address for this entity is 2410 Old Ivy Road, Suite 300, Charlottesville, VA 22903. |
(5) | The address for this person is c/o Axel Johnson AB, Villagatan 6, SE-100 41 Stockholm, Sweden. |
(6) | The address for this entity is 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting power and shared dispositive power for 1,662,185 common units that are held in the accounts of investment advisory clients advised by OppenheimerFunds, Inc., directly and through its subsidiaries. Beneficial ownership reported is based solely on a Schedule 13G/A filed on January 15, 2019. |
(7) | Goldman Sachs Asset Management, L.P., together with GS Investment Strategies, LLC, reported as "Goldman Sachs Asset Management". The address for Goldman Sachs Asset Management is 200 West Street, New York, NY 10282. Goldman Sachs Asset Management reported shared voting power and shared dispositive power with respect to all of the 1,195,335 common units. Beneficial ownership reported based solely on a Schedule 13G/A filed on February 5, 2019. |
(8) | The address of each of the executive officers and directors is 185 International Drive, Portsmouth, NH 03801. |
Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of Securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||
Plan Category | (a)(1) | (b)(2) | (c) | |||
Equity compensation plans approved by security holders | 403,855 | — | 243,922 | |||
Equity compensation plans not approved by security holders | — | — | — |
(1) | Awards in this column represent the total number of all performance-based phantom units granted under our LTIP and outstanding as of December 31, 2018. We have not granted any stock option awards. |
(2) | The outstanding phantom units do not have an exercise price. As such, there is no weighted average exercise price to report for outstanding awards. |
• | Any acquisition of any additional interests in any assets or businesses owned by Axel Johnson or its controlled affiliates at the time of the IPO but not contributed to us in connection with the IPO, including any replacements and natural extensions thereof; |
• | Any investment in or acquisition of any assets or businesses primarily engaged in the businesses in which we are engaged as of the closing of the IPO and that do not operate primarily in the United States or Quebec, Ontario or the Maritimes, Canada; |
• | Any investment in or acquisition of a minority non-controlling interest in any assets or businesses primarily engaged in the businesses described above; or |
• | Any investment in or acquisition of any assets or businesses that Axel Johnson or its controlled affiliates, at the time of the closing of the IPO, are actively seeking to invest in or acquire, or have the right to invest in or acquire. |
Fiscal 2018 | Fiscal 2017 | ||||||
Audit Fees (1) | $ | 3,160,300 | $ | 2,710,500 | |||
Audit-Related Fees (2) | 17,500 | 12,800 | |||||
Tax Fees (3) | 248,200 | 272,200 | |||||
All Other Fees | 2,700 | 5,000 | |||||
Total | $ | 3,428,700 | $ | 3,000,500 |
(1) | Audit fees consisted of the audit of our annual financial statements, reviews of our interim financial statements and services associated with SEC registration statements and other SEC matters. |
(2) | Audit-related fees consisted of a renewable fuel energy regulatory audit. |
(3) | Tax fees consisted of services related to tax compliance, the review of our partnership Form K-1, and research and consultation on other tax related matters. |
(a) | Financial Statements, Financial Statement Schedules and Exhibits—The following documents are filed as part of this Annual Report on Form 10-K for the year ended December 31, 2018. |
1. | Sprague Resources LP Audited Consolidated Financial Statements: |
Page | |
2. | Financial Statement Schedules—No schedules are included because the required information is inapplicable or is presented in the Consolidated Financial Statements or related notes thereto. |
3. | Exhibits: |
Exhibit No. | Description | |
2.1*** | ||
2.2*** | ||
2.3*** | ||
2.4*** | ||
2.5*** |
Exhibit No. | Description | |
2.6*** | ||
3.1 | ||
3.2 | ||
3.3 | ||
3.4 | ||
3.5 | ||
10.1 | ||
10.2 | ||
10.3 | ||
10.4 | ||
10.5 | ||
10.6 | ||
10.7 | ||
10.9† | ||
10.10† | ||
10.11† | ||
10.12† | ||
10.13† | ||
10.14† | ||
21.1* | ||
23.1* | ||
31.1* | ||
31.2* | ||
32.1** | ||
32.2** |
101.INS* | XBRL Instance Document | |
101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.CAL* | XBRL Taxonomy Extension Calculation | |
101.DEF* | XBRL Taxonomy Extension Definition | |
101.LAB* | XBRL Taxonomy Extension Label Linkbase | |
101.PRE* | XBRL Taxonomy Extension Presentation |
† | Compensatory plan or arrangement. |
* | Filed herewith. |
** | Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K. |
*** | Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules to the Asset Purchase Agreements have been omitted. The registrant hereby agrees to furnish supplementally to the SEC, upon its request, any or all omitted schedules. |
Sprague Resources LP | |
By: | Sprague Resources GP LLC, its General Partner |
By: | /s/ David C. Glendon |
David C. Glendon | |
President, Chief Executive Officer | |
(On behalf of the registrant, and in his capacity as principal executive officer) | |
Date: | March 14, 2019 |
Signature | Title | Date | ||
/s/ Michael D. Milligan | March 14, 2019 | |||
Michael D. Milligan | Chairman of the Board of Directors | |||
/s/ David C. Glendon | March 14, 2019 | |||
David C. Glendon | President, Chief Executive Officer and Director (Principal Executive Officer) | |||
/s/ David C. Long | March 14, 2019 | |||
David C. Long | Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |||
/s/ Beth A. Bowman | March 14, 2019 | |||
Beth A. Bowman | Director | |||
/s/ C. Gregory Harper | March 14, 2019 | |||
C. Gregory Harper | Director | |||
/s/ Ben J. Hennelly | March 14, 2019 | |||
Ben J. Hennelly | Director | |||
/s/ Gary A. Rinaldi | March 14, 2019 | |||
Gary A. Rinaldi | Director | |||
/s/ Sally A. Sarsfield | March 14, 2019 | |||
Sally A. Sarsfield | Director |
Page | |
December 31, 2018 | December 31, 2017 | ||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 7,530 | $ | 6,815 | |||
Accounts receivable, net | 269,908 | 316,613 | |||||
Inventories | 259,568 | 335,859 | |||||
Fair value of derivative assets | 153,438 | 107,254 | |||||
Other current assets | 8,888 | 39,946 | |||||
Total current assets | 699,332 | 806,487 | |||||
Fair value of derivative assets long-term | 12,344 | 7,493 | |||||
Property, plant, and equipment, net | 349,846 | 350,059 | |||||
Intangibles, net | 59,987 | 71,891 | |||||
Other assets, net | 8,694 | 12,018 | |||||
Goodwill | 115,037 | 115,037 | |||||
Total assets | $ | 1,245,240 | $ | 1,362,985 | |||
Liabilities and unitholders’ equity | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 197,995 | $ | 205,105 | |||
Accrued liabilities | 65,959 | 49,038 | |||||
Fair value of derivative liabilities | 90,151 | 156,763 | |||||
Due to General Partner | 7,688 | 11,228 | |||||
Current portion of working capital facilities | 154,318 | 275,613 | |||||
Current portion of other obligations | 7,044 | 6,476 | |||||
Total current liabilities | 523,155 | 704,223 | |||||
Commitments and contingencies | |||||||
Working capital facilities - less current portion | 130,680 | 66,237 | |||||
Acquisition facility | 376,100 | 383,500 | |||||
Fair value of derivative liabilities long-term | 12,015 | 8,265 | |||||
Other obligations, less current portion | 46,455 | 49,625 | |||||
Due to General Partner | 2,093 | 1,678 | |||||
Deferred income taxes | 17,766 | 17,623 | |||||
Total liabilities | 1,108,264 | 1,231,151 | |||||
Unitholders’ equity: | |||||||
Common unitholders - public (10,627,629 and 10,446,539 units issued and outstanding as of December 31, 2018 and 2017, respectively) | 196,680 | 193,977 | |||||
Common unitholders - affiliated (12,106,348 units issued and outstanding) | (48,182 | ) | (53,273 | ) | |||
Accumulated other comprehensive loss, net of tax | (11,522 | ) | (8,870 | ) | |||
Total unitholders’ equity | 136,976 | 131,834 | |||||
Total liabilities and unitholders’ equity | $ | 1,245,240 | $ | 1,362,985 |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 2,389,998 | |||||
Cost of products sold (exclusive of depreciation and amortization) | 3,445,385 | 2,602,788 | 2,179,089 | ||||||||
Operating expenses | 88,659 | 72,284 | 65,882 | ||||||||
Selling, general and administrative | 80,799 | 87,582 | 84,257 | ||||||||
Depreciation and amortization | 33,378 | 28,125 | 21,237 | ||||||||
Total operating costs and expenses | 3,648,221 | 2,790,779 | 2,350,465 | ||||||||
Operating income | 122,912 | 64,217 | 39,533 | ||||||||
Other income (expense) | 293 | 108 | (114 | ) | |||||||
Interest income | 577 | 339 | 388 | ||||||||
Interest expense | (38,931 | ) | (31,345 | ) | (27,533 | ) | |||||
Income before income taxes | 84,851 | 33,319 | 12,274 | ||||||||
Income tax provision | (5,032 | ) | (3,822 | ) | (2,108 | ) | |||||
Net income | 79,819 | 29,497 | 10,166 | ||||||||
Incentive distributions declared | (7,879 | ) | (3,993 | ) | (1,742 | ) | |||||
Limited partners’ interest in net income | $ | 71,940 | $ | 25,504 | $ | 8,424 | |||||
Net income per limited partner unit: | |||||||||||
Common—basic | $ | 3.17 | $ | 1.15 | $ | 0.40 | |||||
Common—diluted | $ | 3.16 | $ | 1.13 | $ | 0.38 | |||||
Subordinated—basic and diluted | N/A | N/A | $ | 0.40 | |||||||
Weighted average units used to compute net income per limited partner unit: | |||||||||||
Common—basic | 22,728,218 | 22,208,964 | 11,202,427 | ||||||||
Common—diluted | 22,737,404 | 22,474,872 | 11,560,617 | ||||||||
Subordinated—basic and diluted | N/A | N/A | 10,071,970 | ||||||||
Distribution declared per unit | $ | 2.66 | $ | 2.46 | $ | 2.22 |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Net income | $ | 79,819 | $ | 29,497 | $ | 10,166 | |||||
Other comprehensive (loss) income, net of tax: | |||||||||||
Unrealized gain (loss) on interest rate swaps | |||||||||||
Net income (loss) arising in the period | (253 | ) | 1,884 | 223 | |||||||
Reclassification adjustment related to (gains) losses realized in income | (2,179 | ) | (173 | ) | 1,519 | ||||||
Net change in unrealized loss (gain) on interest rate swaps | (2,432 | ) | 1,711 | 1,742 | |||||||
Tax effect | 20 | (14 | ) | (25 | ) | ||||||
(2,412 | ) | 1,697 | 1,717 | ||||||||
Foreign currency translation adjustment | (240 | ) | 216 | (861 | ) | ||||||
Other comprehensive (loss) income | (2,652 | ) | 1,913 | 856 | |||||||
Comprehensive income | $ | 77,167 | $ | 31,410 | $ | 11,022 |
Common- Public | Common- Sprague Holdings | Subordinated Sprague Holdings | Incentive Distribution Rights | Accumulated Other Comprehensive Loss | Total | ||||||||||||||||||
Balance as of December 31, 2015 | $ | 189,483 | $ | (1,370 | ) | $ | (18,989 | ) | $ | — | $ | (11,639 | ) | $ | 157,485 | ||||||||
Net income | 3,815 | 847 | 4,192 | 1,312 | — | 10,166 | |||||||||||||||||
Other comprehensive income | — | — | — | — | 856 | 856 | |||||||||||||||||
Unit-based compensation | 1,820 | 404 | 2,000 | — | — | 4,224 | |||||||||||||||||
Distributions paid | (19,894 | ) | (4,419 | ) | (21,878 | ) | (1,312 | ) | — | (47,503 | ) | ||||||||||||
Common units issued with annual bonus | 1,748 | 392 | 1,939 | — | — | 4,079 | |||||||||||||||||
Units withheld for employee tax obligations | (1,658 | ) | (372 | ) | (1,840 | ) | — | — | (3,870 | ) | |||||||||||||
Balance as of December 31, 2016 | 175,314 | (4,518 | ) | (34,576 | ) | — | (10,783 | ) | 125,437 | ||||||||||||||
Conversion of subordinated units to common units | — | (40,393 | ) | 40,393 | — | — | — | ||||||||||||||||
Net income | 11,955 | 14,324 | — | 3,218 | — | 29,497 | |||||||||||||||||
Other comprehensive income | — | — | — | — | 1,913 | 1,913 | |||||||||||||||||
Unit-based compensation | 1,034 | 1,240 | — | — | — | 2,274 | |||||||||||||||||
Distributions paid | (25,198 | ) | (23,239 | ) | (5,817 | ) | (3,218 | ) | — | (57,472 | ) | ||||||||||||
Common units issued for Carbo acquisition | 31,401 | — | — | — | — | 31,401 | |||||||||||||||||
Common units issued with annual bonus | 161 | 210 | — | — | — | 371 | |||||||||||||||||
Units withheld for employee tax obligations | (690 | ) | (897 | ) | — | — | — | (1,587 | ) | ||||||||||||||
Balance as of December 31, 2017 | 193,977 | (53,273 | ) | — | — | (8,870 | ) | 131,834 | |||||||||||||||
Net income | 33,940 | 38,683 | — | 7,196 | — | 79,819 | |||||||||||||||||
Other comprehensive loss | — | — | — | — | (2,652 | ) | (2,652 | ) | |||||||||||||||
Unit-based compensation | (419 | ) | (477 | ) | — | — | — | (896 | ) | ||||||||||||||
Distributions paid | (29,646 | ) | (31,779 | ) | — | (7,196 | ) | — | (68,621 | ) | |||||||||||||
Units withheld for employee tax obligations | (1,172 | ) | (1,336 | ) | — | — | — | (2,508 | ) | ||||||||||||||
Balance as of December 31, 2018 | $ | 196,680 | $ | (48,182 | ) | $ | — | $ | — | $ | (11,522 | ) | $ | 136,976 |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Cash flows from operating activities | |||||||||||
Net income | $ | 79,819 | $ | 29,497 | $ | 10,166 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation and amortization (includes amortization of deferred debt issue costs) | 36,930 | 33,361 | 25,211 | ||||||||
(Gain) loss on sale of assets and insurance recoveries | (268 | ) | (231 | ) | 189 | ||||||
Changes in fair value of contingent consideration | 677 | 168 | — | ||||||||
Provision for doubtful accounts | 1,598 | (206 | ) | 231 | |||||||
Non-cash unit-based compensation | (896 | ) | 2,274 | 3,681 | |||||||
Other | 94 | 63 | — | ||||||||
Deferred income taxes | 77 | 857 | 387 | ||||||||
Changes in assets and liabilities: | |||||||||||
Accounts receivable | 44,975 | (94,454 | ) | (61,541 | ) | ||||||
Inventories | 76,291 | (12,247 | ) | (77,235 | ) | ||||||
Prepaid expenses and other assets | 31,058 | 4,253 | 17,051 | ||||||||
Fair value of commodity derivative instruments | (116,329 | ) | 24,812 | 165,108 | |||||||
Due to/from General Partner and affiliates | (3,124 | ) | (2,580 | ) | 759 | ||||||
Accounts payable, accrued liabilities and other | 8,077 | 71,475 | 47,737 | ||||||||
Net cash provided by operating activities | 158,979 | 57,042 | 131,744 | ||||||||
Cash flows from investing activities | |||||||||||
Purchases of property, plant and equipment | (17,249 | ) | (46,955 | ) | (15,986 | ) | |||||
Proceeds from property insurance settlements and sale of assets | 394 | 1,003 | 154 | ||||||||
Business acquisitions | — | (107,317 | ) | (29,065 | ) | ||||||
Net cash used in investing activities | (16,855 | ) | (153,269 | ) | (44,897 | ) | |||||
Cash flows from financing activities | |||||||||||
Net (payments) borrowings under credit agreements | (63,787 | ) | 169,248 | (59,910 | ) | ||||||
Payments on capital leases, term debt and other obligations | (6,136 | ) | (5,030 | ) | (1,763 | ) | |||||
Debt issue costs | (263 | ) | (4,873 | ) | (2,089 | ) | |||||
Distributions to unitholders | (68,621 | ) | (57,472 | ) | (47,503 | ) | |||||
Foreign exchange on capital lease obligations | — | — | 6 | ||||||||
Repurchased units withheld for employee tax obligations | (2,508 | ) | (1,587 | ) | (3,870 | ) | |||||
Net cash (used in) provided by financing activities | (141,315 | ) | 100,286 | (115,129 | ) | ||||||
Effect of exchange rate changes on cash balances held in foreign currencies | (94 | ) | 74 | (10 | ) | ||||||
Net change in cash and cash equivalents | 715 | 4,133 | (28,292 | ) | |||||||
Cash and cash equivalents, beginning of period | 6,815 | 2,682 | 30,974 | ||||||||
Cash and cash equivalents, end of period | $ | 7,530 | $ | 6,815 | $ | 2,682 | |||||
Supplemental disclosure of cash flow information | |||||||||||
Cash paid for interest | $ | 35,174 | $ | 25,781 | $ | 24,231 | |||||
Cash paid for taxes | $ | 4,139 | $ | 1,689 | $ | 789 | |||||
Non-cash consideration related to acquisitions: | |||||||||||
Common units issued - Carbo | $ | — | $ | 31,401 | — | ||||||
Deferred consideration - Carbo | $ | — | $ | 27,284 | — | ||||||
Contingent consideration - Coen | $ | — | $ | 9,557 | — | ||||||
Assets acquired under capital lease obligations | $ | 4,449 | $ | 1,110 | $ | 1,384 |
1. | Description of Business and Summary of Significant Accounting Policies |
• | The refined products segment purchases 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 sells them to wholesale and commercial customers. |
• | The natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers. The Partnership purchases the natural gas it sells from natural gas producers and trading companies. |
• | The materials handling segment offloads, stores and prepares 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. |
• | The other operations segment primarily includes the purchase and distribution of coal and certain commercial trucking activities |
Furniture and fixtures | 5 to 10 years |
Plant and machinery | 5 to 30 years |
Building and leasehold improvements | 10 to 25 years |
2. | Revenue |
Years Ended December 31 | |||||||||||
2018 | 2017 | 2016 | |||||||||
Net sales: | |||||||||||
Refined products | |||||||||||
Distillates | $ | 2,686,833 | $ | 1,873,782 | $ | 1,471,912 | |||||
Gasoline | 320,168 | 280,891 | 270,243 | ||||||||
Heavy fuel oil and asphalt | 350,768 | 300,904 | 246,442 | ||||||||
Total refined products | $ | 3,357,769 | $ | 2,455,577 | $ | 1,988,597 | |||||
Natural gas | 332,038 | 331,669 | 334,003 | ||||||||
Materials handling | 57,509 | 46,513 | 45,734 | ||||||||
Other operations | 23,817 | 21,237 | 21,664 | ||||||||
Net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 2,389,998 | |||||
Net sales by Country: | |||||||||||
United States | $ | 3,480,744 | $ | 2,589,293 | $ | 2,193,566 | |||||
Canada | 290,389 | 265,703 | 196,432 | ||||||||
Net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 2,389,998 |
3. | Business Combinations |
Inventories | $ | 567 | |
Other current assets | 115 | ||
Property, plant and equipment | 12,972 | ||
Intangibles | 18,375 | ||
Total identifiable assets acquired | 32,029 | ||
Other liabilities | (256 | ) | |
Net identifiable assets acquired | 31,773 | ||
Goodwill | 13,095 | ||
Net assets acquired | $ | 44,868 |
Inventories | $ | 3,220 | |
Derivative assets and other assets | 111 | ||
Property, plant and equipment | 22,995 | ||
Intangibles | 29,000 | ||
Total identifiable assets acquired | 55,326 | ||
Other liabilities | (188 | ) | |
Net identifiable assets acquired | 55,138 | ||
Goodwill | 16,718 | ||
Net assets acquired | $ | 71,856 |
Property, plant and equipment | $ | 21,960 | |
Accrued liabilities and other, net | (22 | ) | |
Net assets acquired | $ | 21,938 |
Inventory | $ | 286 | |
Derivative assets | 5,873 | ||
Natural gas transportation assets | 695 | ||
Derivative assets, long-term | 1,089 | ||
Natural gas transportation assets, long-term | 378 | ||
Intangibles | 5,046 | ||
Total identifiable assets acquired | 13,367 | ||
Derivative liabilities | (4,865 | ) | |
Natural gas transportation liabilities | (465 | ) | |
Derivative liabilities, long-term | (1,214 | ) | |
Natural gas transportation liabilities, long-term | (162 | ) | |
Net identifiable assets acquired | 6,661 | ||
Goodwill | 9,592 | ||
Net assets acquired | $ | 16,253 |
Inventories | $ | 632 | |
Derivative and other current assets | 658 | ||
Property, plant and equipment | 9,152 | ||
Intangibles | 5,800 | ||
Total identifiable assets acquired | 16,242 | ||
Derivative and other current liabilities | (680 | ) | |
Net identifiable assets acquired | 15,562 | ||
Goodwill | 5,081 | ||
Net assets acquired | $ | 20,643 |
Years Ended December 31, | |||||||
2017 | 2016 | ||||||
Net sales | $ | 2,957,205 | $ | 2,590,663 | |||
Net income | 29,431 | 4,216 | |||||
Limited partners’ interest in net income | 25,438 | 2,474 | |||||
Net income per limited partner common unit-basic | 1.15 | 0.12 | |||||
Net income per limited partner common unit-diluted | 1.13 | 0.11 |
Derivative assets | $ | 22,678 | |||||
Other current assets and prepaids | 2,168 | ||||||
Intangibles and other | 6,539 | ||||||
Natural gas transportation assets | 8,040 | ||||||
Total identifiable assets acquired | 39,425 | ||||||
Accrued liabilities | (219 | ) | |||||
Derivative liabilities | (15,007 | ) | |||||
Natural gas transportation liabilities | (2,396 | ) | |||||
Net identifiable assets acquired | 21,803 | ||||||
Goodwill | 7,262 | ||||||
Net assets acquired | $ | 29,065 |
4. | Accumulated Other Comprehensive Loss, Net of Tax |
As of December 31, | |||||||
2018 | 2017 | ||||||
Fair value of interest rate swaps, net of tax | $ | 176 | $ | 2,588 | |||
Cumulative foreign currency translation adjustment | (11,698 | ) | (11,458 | ) | |||
Accumulated other comprehensive loss, net of tax | $ | (11,522 | ) | $ | (8,870 | ) |
5. | Accounts Receivable, Net |
As of December 31, | |||||||
2018 | 2017 | ||||||
Accounts receivable, trade | $ | 262,912 | $ | 310,800 | |||
Less allowance for doubtful accounts | (2,066 | ) | (2,014 | ) | |||
Net accounts receivable, trade | 260,846 | 308,786 | |||||
Accounts receivable, other | 9,062 | 7,827 | |||||
Accounts receivable, net | $ | 269,908 | $ | 316,613 |
Balance at Beginning of Period | Charged to Expense | Charged (to) from Another Account | (Deductions) | Balance at End of Period | |||||||||||||||
Balance, December 31, 2018: | |||||||||||||||||||
Allowance for doubtful accounts | $ | 2,014 | $ | 1,598 | $ | 8 | $ | (1,554 | ) | $ | 2,066 | ||||||||
Allowance for notes receivable | 531 | — | (8 | ) | (215 | ) | 308 | ||||||||||||
Total | $ | 2,545 | $ | 1,598 | $ | — | $ | (1,769 | ) | $ | 2,374 | ||||||||
Balance, December 31, 2017: | |||||||||||||||||||
Allowance for doubtful accounts | $ | 4,282 | $ | (207 | ) | $ | 11 | $ | (2,072 | ) | $ | 2,014 | |||||||
Allowance for notes receivable | 641 | — | (11 | ) | (99 | ) | 531 | ||||||||||||
Total | $ | 4,923 | $ | (207 | ) | $ | — | $ | (2,171 | ) | $ | 2,545 | |||||||
Balance, December 31, 2016: | |||||||||||||||||||
Allowance for doubtful accounts | $ | 4,139 | $ | 230 | $ | 20 | $ | (107 | ) | $ | 4,282 | ||||||||
Allowance for notes receivable | 1,401 | — | (20 | ) | (740 | ) | 641 | ||||||||||||
Total | $ | 5,540 | $ | 230 | $ | — | $ | (847 | ) | $ | 4,923 |
6. | Inventories |
As of December 31, | |||||||
2018 | 2017 | ||||||
Petroleum and related products | $ | 253,385 | $ | 329,712 | |||
Coal | 2,566 | 3,712 | |||||
Natural gas | 3,617 | 2,435 | |||||
Inventories | $ | 259,568 | $ | 335,859 |
7. | Other Current Assets |
As of December 31, | |||||||
2018 | 2017 | ||||||
Margin deposits with brokers | $ | 827 | $ | 29,321 | |||
Prepaid software & fees | 5,627 | 7,200 | |||||
Natural gas transportation | — | 1,056 | |||||
Other | 2,434 | 2,369 | |||||
Other current assets | $ | 8,888 | $ | 39,946 |
8. | Property, Plant and Equipment, Net |
As of December 31, | |||||||
2018 | 2017 | ||||||
Plant, machinery, furniture and fixtures | $ | 416,398 | $ | 401,092 | |||
Building and leasehold improvements | 19,159 | 18,631 | |||||
Land and land improvements | 87,854 | 86,758 | |||||
Construction in progress | 9,308 | 6,580 | |||||
Property, plant and equipment, gross | 532,719 | 513,061 | |||||
Less: accumulated depreciation | (182,873 | ) | (163,002 | ) | |||
Property, plant and equipment, net | $ | 349,846 | $ | 350,059 |
As of December 31, | |||||||
2018 | 2017 | ||||||
Plant, machinery, furniture and fixtures | $ | 21,231 | $ | 17,131 | |||
Building and leasehold improvements | 962 | 962 | |||||
Land and land improvements | 251 | 251 | |||||
Property, plant and equipment, gross | 22,444 | 18,344 | |||||
Less: accumulated amortization | (9,849 | ) | (9,117 | ) | |||
Property, plant and equipment, net | $ | 12,595 | $ | 9,227 |
9. | Intangibles, Net |
As of December 31, 2018 | |||||||||||||
Remaining Useful Life (Years) | Gross | Accumulated Amortization | Net | ||||||||||
Customer relationships | 3 - 24 | $ | 80,919 | $ | 26,582 | $ | 54,337 | ||||||
Non-compete agreements | 1 - 4 | 11,189 | 6,102 | 5,087 | |||||||||
Other | 1 - 4 | 2,544 | 1,981 | 563 | |||||||||
Intangible assets, net | $ | 94,652 | $ | 34,665 | $ | 59,987 |
As of December 31, 2017 | |||||||||||||
Remaining Useful Life (Years) | Gross | Accumulated Amortization | Net | ||||||||||
Customer relationships | 1 - 25 | $ | 84,219 | $ | 21,595 | $ | 62,624 | ||||||
Non-compete agreements | 2 - 5 | 13,587 | 5,317 | 8,270 | |||||||||
Other | 1 - 5 | 2,500 | 1,503 | 997 | |||||||||
Intangible assets, net | $ | 100,306 | $ | 28,415 | $ | 71,891 |
10. | Other Assets, Net |
As of December 31, | |||||||
2018 | 2017 | ||||||
Deferred debt issuance costs, net | $ | 8,335 | $ | 11,625 | |||
Natural gas transportation, long-term portion | — | 37 | |||||
Other | 359 | 356 | |||||
Other assets, net | $ | 8,694 | $ | 12,018 |
11. | Accrued Liabilities |
As of December 31, | |||||||
2018 | 2017 | ||||||
Margin deposits from brokers | $ | 28,529 | $ | — | |||
Customer prepayments and deposits | 9,846 | 8,178 | |||||
Accrued product taxes | 9,830 | 9,783 | |||||
Accrued product costs | 6,310 | 11,517 | |||||
Other | 11,444 | 19,560 | |||||
Other current liabilities | $ | 65,959 | $ | 49,038 |
12. | Credit Agreement |
As of December 31, | |||||||
2018 | 2017 | ||||||
Working capital facilities | $ | 284,998 | $ | 341,850 | |||
Acquisition facility | 376,100 | 383,500 | |||||
Total credit agreement | 661,098 | 725,350 | |||||
Less: current portion of working capital facilities | (154,318 | ) | (275,613 | ) | |||
Total long-term portion | $ | 506,780 | $ | 449,737 |
• | A U.S. dollar revolving working capital facility of up to $950.0 million, subject to the Partnership's borrowing base limits, to be used by the Partnership for working capital loans and letters of credit; |
• | A multicurrency revolving working capital facility of up to $100.0 million, subject to Kildair's borrowing base limits, to be used for working capital loans and letters of credit, and |
• | Revolving acquisition facility of up to $550.0 million, subject to the Partnership's acquisition facility borrowing base limits, to be used for loans and letters of credit to fund capital expenditures and acquisitions and other general corporate purposes related to the Partnership’s current businesses. |
• | Subject to certain conditions including the receipt of additional commitments from lenders, the U.S. dollar or revolving working capital facility may be increased by $250.0 million and the multicurrency revolving working capital facility by $220.0 million subject to a maximum increase for both facilities of $270.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million. |
13. | Related Party Transactions |
14. | Other Obligations |
As of December 31, | |||||||
2018 | 2017 | ||||||
Deferred consideration | $ | 21,779 | $ | 23,966 | |||
Contingent consideration | 6,532 | 7,855 | |||||
Port Authority terminal obligations | 6,365 | 7,056 | |||||
Asset retirement obligation | 3,481 | 3,789 | |||||
Postretirement benefits | 2,160 | 2,412 | |||||
Other | 6,138 | 4,547 | |||||
Other obligations, long-term portion | $ | 46,455 | $ | 49,625 |
2019 | $ | 3,818 | |
2020 | 3,818 | ||
2021 | 3,818 | ||
2022 | 3,818 | ||
2023 | 3,818 | ||
Thereafter | 12,730 | ||
Total | 31,820 | ||
Less amount representing interest | (7,854 | ) | |
Present value of payments | 23,966 | ||
Less current portion | (2,187 | ) | |
Deferred consideration, long-term portion | $ | 21,779 |
Years Ended December 31, | |||||||
2018 | 2017 | ||||||
ARO - beginning of period | $ | 4,490 | $ | — | |||
Accrue fair value of ARO | — | 3,662 | |||||
Change in estimates | (139 | ) | 785 | ||||
Accretion expense | 92 | 63 | |||||
Retirement of ARO | (462 | ) | (20 | ) | |||
ARO - end of period | 3,981 | 4,490 | |||||
Less current portion | (500 | ) | (701 | ) | |||
ARO - long-term | $ | 3,481 | $ | 3,789 |
15. | Income Taxes |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Current | |||||||||||
U.S. Federal income tax | $ | 118 | $ | 120 | $ | 229 | |||||
State and local income tax | 95 | 231 | 1,199 | ||||||||
Foreign income taxes | 4,742 | 2,614 | 293 | ||||||||
Total current income tax provision | 4,955 | 2,965 | 1,721 | ||||||||
Deferred | |||||||||||
U.S. Federal income tax | 5 | 3 | (9 | ) | |||||||
State and local income tax | 567 | (188 | ) | (388 | ) | ||||||
Foreign income taxes | (495 | ) | 1,042 | 784 | |||||||
Total deferred income tax provision | 77 | 857 | 387 | ||||||||
Total income tax provision | $ | 5,032 | $ | 3,822 | $ | 2,108 |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
United States | $ | 69,283 | $ | 18,517 | $ | 8,385 | |||||
Foreign | 15,568 | 14,802 | 3,889 | ||||||||
Total income before income taxes | $ | 84,851 | $ | 33,319 | $ | 12,274 |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Statutory U.S. Federal income tax | $ | 17,819 | $ | 11,661 | $ | 4,296 | |||||
Partnership income not subject to tax | (14,427 | ) | (6,360 | ) | (2,691 | ) | |||||
State and local income taxes, net of federal tax | 662 | 46 | 787 | ||||||||
Foreign earnings taxed at higher (lower) rates | 978 | (1,525 | ) | (284 | ) | ||||||
Total income tax provision | $ | 5,032 | $ | 3,822 | $ | 2,108 |
As of December 31, | |||||||
2018 | 2017 | ||||||
Deferred tax assets (liabilities) | |||||||
Depreciation and amortization | (17,845 | ) | (18,065 | ) | |||
Other differences, net | 545 | 908 | |||||
Valuation allowance | (466 | ) | (466 | ) | |||
Net deferred tax liabilities | $ | (17,766 | ) | $ | (17,623 | ) |
16. | Retirement Plans |
17. | Segment Reporting |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Net sales: | |||||||||||
Refined products | $ | 3,357,769 | $ | 2,455,577 | $ | 1,988,597 | |||||
Natural gas | 332,038 | 331,669 | 334,003 | ||||||||
Materials handling | 57,509 | 46,513 | 45,734 | ||||||||
Other operations | 23,817 | 21,237 | 21,664 | ||||||||
Net sales | $ | 3,771,133 | $ | 2,854,996 | $ | 2,389,998 | |||||
Adjusted gross margin (1): | |||||||||||
Refined products | $ | 150,965 | $ | 142,467 | $ | 142,581 | |||||
Natural gas | 57,875 | 65,060 | 62,435 | ||||||||
Materials handling | 57,515 | 46,512 | 45,712 | ||||||||
Other operations | 7,319 | 7,658 | 8,545 | ||||||||
Adjusted gross margin | 273,674 | 261,697 | 259,273 | ||||||||
Reconciliation to operating income (2): | |||||||||||
Add(deduct): | |||||||||||
Change in unrealized gain on inventory (3) | 32,960 | (124 | ) | (31,304 | ) | ||||||
Change in unrealized value on prepaid forward contract (4) | — | 1,076 | 1,552 | ||||||||
Change in unrealized value on natural gas transportation contracts (5) | 19,114 | (10,441 | ) | (18,612 | ) | ||||||
Operating costs and expenses not allocated to operating segments: | |||||||||||
Operating expenses | (88,659 | ) | (72,284 | ) | (65,882 | ) | |||||
Selling, general and administrative | (80,799 | ) | (87,582 | ) | (84,257 | ) | |||||
Depreciation and amortization | (33,378 | ) | (28,125 | ) | (21,237 | ) | |||||
Operating income | 122,912 | 64,217 | 39,533 | ||||||||
Other income (expense) | 293 | 108 | (114 | ) | |||||||
Interest income | 577 | 339 | 388 | ||||||||
Interest expense | (38,931 | ) | (31,345 | ) | (27,533 | ) | |||||
Income tax provision | (5,032 | ) | (3,822 | ) | (2,108 | ) | |||||
Net income | $ | 79,819 | $ | 29,497 | $ | 10,166 |
(1) | The Partnership trades, purchases, stores and sells energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes |
(2) | Reconciliation of adjusted gross margin to operating income, the most directly comparable GAAP measure. |
(3) | Inventory is valued at the lower of cost or net realizable value. The adjustment related to unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between the inventory valued at lower of cost or net realizable value as compared to market values. The fair value of the derivatives the Partnership uses to economically hedge its inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging (gains) with respect to the derivatives that are included in net income (loss). |
(4) | Represents the Partnership’s estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income (loss) until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income (loss). The fair value of the derivatives the Partnership uses to economically hedge its prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines in value. |
(5) | Represents the Partnership’s estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized gains (losses). |
As of December 31, 2016 | Activity (1) | As of December 31, 2017 | Activity | As of December 31, 2018 | |||||||||||||||
Refined products | $ | 36,550 | $ | 34,895 | $ | 71,445 | $ | — | $ | 71,445 | |||||||||
Natural gas | 25,888 | 9,592 | 35,480 | — | 35,480 | ||||||||||||||
Materials handling | 6,896 | — | 6,896 | — | 6,896 | ||||||||||||||
Other | 1,216 | — | 1,216 | — | 1,216 | ||||||||||||||
Total | $ | 70,550 | $ | 44,487 | $ | 115,037 | $ | — | $ | 115,037 |
(1) | Reflects goodwill attributable to business acquisitions. See Note 3 - Business Combinations. |
As of December 31, | |||||||
2018 | 2017 | ||||||
United States | $ | 277,405 | $ | 273,374 | |||
Canada | 72,441 | 76,685 | |||||
Total | $ | 349,846 | $ | 350,059 |
18. | Financial Instruments and Off-Balance Sheet Risk |
As of December 31, 2018 | |||||||||||||||
Fair Value Measurement | Quoted Prices in Active Markets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | ||||||||||||
Derivative assets: | |||||||||||||||
Commodity fixed forwards | $ | 42,893 | $ | — | $ | 42,893 | $ | — | |||||||
Futures, swaps and options | 120,258 | 120,231 | 27 | — | |||||||||||
Commodity derivatives | 163,151 | 120,231 | 42,920 | — | |||||||||||
Interest rate swaps | 2,629 | — | 2,629 | — | |||||||||||
Currency swaps | 2 | — | 2 | — | |||||||||||
Total derivative assets | $ | 165,782 | $ | 120,231 | $ | 45,551 | $ | — | |||||||
Derivative liabilities: | |||||||||||||||
Commodity fixed forwards | $ | 21,036 | $ | — | $ | 21,036 | $ | — | |||||||
Futures, swaps and options | 78,678 | 78,674 | 4 | — | |||||||||||
Commodity derivatives | 99,714 | 78,674 | 21,040 | — | |||||||||||
Interest rate swaps | 2,452 | — | 2,452 | — | |||||||||||
Total derivative liabilities | $ | 102,166 | $ | 78,674 | $ | 23,492 | $ | — | |||||||
Contingent consideration | $ | 8,402 | $ | — | $ | — | $ | 8,402 |
As of December 31, 2017 | |||||||||||||||
Fair Value Measurement | Quoted Prices in Active Markets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | ||||||||||||
Derivative assets: | |||||||||||||||
Commodity fixed forwards | $ | 11,502 | $ | — | $ | 11,502 | $ | — | |||||||
Futures, swaps and options | 100,630 | 100,613 | 17 | — | |||||||||||
Commodity derivatives | 112,132 | 100,613 | 11,519 | — | |||||||||||
Interest rate swaps | 2,615 | — | 2,615 | — | |||||||||||
Total derivative assets | $ | 114,747 | $ | 100,613 | $ | 14,134 | $ | — | |||||||
Derivative liabilities: | |||||||||||||||
Commodity fixed forwards | $ | 61,195 | $ | — | $ | 61,195 | $ | — | |||||||
Futures, swaps and options | 103,827 | 103,654 | 173 | — | |||||||||||
Commodity derivatives | 165,022 | 103,654 | 61,368 | — | |||||||||||
Interest rate swaps | 6 | — | 6 | — | |||||||||||
Total derivative liabilities | $ | 165,028 | $ | 103,654 | $ | 61,374 | $ | — | |||||||
Contingent consideration | $ | 9,725 | $ | — | $ | — | $ | 9,725 |
As of December 31, 2018 | |||||||||||||||
Gross Amount Not Offset in the Balance Sheet | Net Amount | ||||||||||||||
Gross Amounts of Assets/ Liabilities in Balance Sheet | Financial Instruments | Cash Collateral Posted | |||||||||||||
Commodity derivative assets | $ | 163,151 | $ | (82,837 | ) | $ | (28,529 | ) | $ | 51,785 | |||||
Currency swap derivative assets | 2,629 | — | — | 2,629 | |||||||||||
Currency swaps | 2 | — | — | 2 | |||||||||||
Fair value of derivative assets | $ | 165,782 | $ | (82,837 | ) | $ | (28,529 | ) | $ | 54,416 | |||||
Commodity derivative liabilities | $ | (99,714 | ) | $ | 82,837 | $ | 20 | $ | (16,857 | ) | |||||
Interest rate swap derivative liabilities | (2,452 | ) | — | — | (2,452 | ) | |||||||||
Fair value of derivative liabilities | $ | (102,166 | ) | $ | 82,837 | $ | 20 | $ | (19,309 | ) |
As of December 31, 2017 | |||||||||||||||
Gross Amount Not Offset in the Balance Sheet | Net Amount | ||||||||||||||
Gross Amounts of Assets/ Liabilities in Balance Sheet | Financial Instruments | Cash Collateral Posted | |||||||||||||
Commodity derivative assets | $ | 112,132 | $ | (86,493 | ) | $ | (4,303 | ) | $ | 21,336 | |||||
Interest rate swap derivative assets | 2,615 | — | — | 2,615 | |||||||||||
Fair value of derivative assets | $ | 114,747 | $ | (86,493 | ) | $ | (4,303 | ) | $ | 23,951 | |||||
Commodity derivative liabilities | $ | (165,022 | ) | $ | 86,493 | $ | 20,975 | $ | (57,554 | ) | |||||
Interest rate swap derivative liabilities | (6 | ) | — | — | (6 | ) | |||||||||
Fair value of derivative liabilities | $ | (165,028 | ) | $ | 86,493 | $ | 20,975 | $ | (57,560 | ) |
Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Refined products contracts | $ | 54,616 | $ | 12,856 | $ | (25,316 | ) | ||||
Natural gas contracts | (1,353 | ) | (1,555 | ) | 7,153 | ||||||
Total | $ | 53,263 | $ | 11,301 | $ | (18,163 | ) |
As of December 31, 2018 | As of December 31, 2017 | ||||||
Refined Products (Barrels) | Natural Gas (MMBTUs) | Refined Products (Barrels) | Natural Gas (MMBTUs) | ||||
Long contracts | 8,796 | 132,030 | 9,255 | 133,532 | |||
Short contracts | (12,379) | (72,223) | (13,487) | (72,074) |
Interest Rate Swap Agreements | ||||||
Beginning | Ending | Notional Amount | ||||
January 2018 | January 2019 | $ | 275,000 | |||
January 2019 | January 2020 | $ | 300,000 | |||
January 2020 | January 2021 | $ | 300,000 | |||
January 2021 | January 2022 | $ | 300,000 | |||
January 2022 | January 2023 | $ | 250,000 |
Years Ended December 31, | |||||||
2018 | 2017 | ||||||
Contingent consideration - beginning of period | $ | 9,725 | $ | — | |||
Accrued contingent consideration | — | 9,557 | |||||
Payments | (2,000 | ) | — | ||||
Change in estimated fair value | 677 | 168 | |||||
Contingent consideration - end of period | $ | 8,402 | $ | 9,725 | |||
Less current portion | (1,870 | ) | (1,870 | ) | |||
Contingent consideration - long-term portion | $ | 6,532 | $ | 7,855 |
19. | Commitments and Contingencies |
2019 | $ | 9,485 | |
2020 | 5,816 | ||
2021 | 5,884 | ||
2022 | 2,943 | ||
2023 | 588 |
20. | Equity and Equity-Based Compensation |
• | Year ended December 31, 2018 - granted 143,981 OCF-based phantom units with a grant date fair value of $23.30 per unit and a performance period ending December 31, 2020. |
• | Year ended December 31, 2017 - granted 132,977 OCF-based phantom units with a grant date fair value of $26.96 per unit and a performance period ending December 31, 2019. |
• | Year ended December 31, 2016 - granted 166,900 OCF-based phantom units with a grant date fair value of $17.52 per unit and a performance period ending December 31, 2018. |
• | Performance period ending December 31, 2018 - did not achieve minimum performance levels. |
• | Performance period ending December 31, 2017 - vested at a 195.5% level and as a result 271,748 units (vested market value of $7.0 million) were issued in January 2018 with 97,351 units withheld for employee tax obligations. |
• | Performance period ending December 31, 2016 - vested at a 200% level and as a result 142,100 units (vested market value of $3.9 million) were issued in January 2017 with 52,785 units withheld for employee tax obligations. |
• | Performance period ending December 31, 2015 - vested at a 200% level and as a result 74,050 units (vested market value of $1.4 million) were issued in January 2016 with 24,683 units withheld for employee tax obligations. |
2018 Awards | 2017 Awards | 2016 Awards | ||||||||||||||||||
Units | Weighted Average Grant Date Fair Value (per unit) | Units | Weighted Average Grant Date Fair Value (per unit) | Units | Weighted Average Grant Date Fair Value (per unit) | |||||||||||||||
Nonvested at December 31, 2017 | — | $ | — | 131,000 | $ | 26.96 | 163,900 | $ | 17.52 | |||||||||||
Granted | 143,981 | 23.30 | — | — | — | — | ||||||||||||||
Forfeited | (20,811 | ) | (23.30 | ) | (11,013 | ) | (26.95 | ) | (3,202 | ) | (17.52 | ) | ||||||||
Vested (end of performance period) | — | — | — | — | (160,698 | ) | (17.52 | ) | ||||||||||||
Nonvested at December 31, 2018 | 123,170 | $ | 23.30 | 119,987 | $ | 26.96 | — | $ | — |
Common Units | ||||||||
Public | Sprague Holdings | Subordinated Units | ||||||
Balance as of December 31, 2015 | 8,977,378 | 2,034,378 | 10,071,970 | |||||
Units issued in connection with employee bonus | 161,018 | — | — | |||||
Units issued in connection with performance-based awards | 49,367 | — | — | |||||
Director vested awards | 9,824 | — | — | |||||
Other awards | 9,886 | — | — | |||||
Balance as of December 31, 2016 | 9,207,473 | 2,034,378 | 10,071,970 | |||||
Conversion of subordinated units | — | 10,071,970 | (10,071,970 | ) | ||||
Units issued in connection with employee bonus | 8,840 | — | — | |||||
Units issued in connection with performance-based awards | 89,315 | — | — | |||||
Units issued in connection with Carbo acquisition | 1,131,551 | — | — | |||||
Director vested awards | 9,360 | — | — | |||||
Balance as of December 31, 2017 | 10,446,539 | 12,106,348 | — | |||||
Units issued in connection with performance-based awards | 174,397 | — | — | |||||
Director vested awards | 6,693 | — | — | |||||
Balance as of December 31, 2018 | 10,627,629 | 12,106,348 | — |
21. | Earnings Per Unit |
Years Ended December 31, | ||||||||
2018 | 2017 | 2016 | ||||||
Weighted average limited partner common units - basic | 22,728,218 | 22,208,964 | 11,202,427 | |||||
Dilutive effect of unvested phantom units | 9,186 | 265,908 | 358,190 | |||||
Weighted average limited partner common units - dilutive | 22,737,404 | 22,474,872 | 11,560,617 |
Year Ended December 31, 2016 | |||||||||||||||
Common | Subordinated | IDR | Total | ||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||
Net income | $ | 10,166 | |||||||||||||
Distributions declared | $ | 24,998 | $ | 22,358 | $ | 1,742 | $ | 49,098 | |||||||
Assumed net income from operations after distributions | (20,562 | ) | (18,370 | ) | — | (38,932 | ) | ||||||||
Assumed net income to be allocated | $ | 4,436 | $ | 3,988 | $ | 1,742 | $ | 10,166 | |||||||
Income per unit - basic | $ | 0.40 | $ | 0.40 | |||||||||||
Income per unit - diluted | $ | 0.38 | $ | 0.40 |
22. | Quarterly Financial Data (Unaudited) |
Year Ended December 31, 2018 | |||||||||||||||||||
First | Second | Third | Fourth | Total | |||||||||||||||
(in thousands, except for per unit amounts) | |||||||||||||||||||
Net sales | $ | 1,331,148 | $ | 741,656 | $ | 618,455 | $ | 1,079,874 | $ | 3,771,133 | |||||||||
Net income (loss) | 74,921 | (13,195 | ) | (18,434 | ) | 36,527 | 79,819 | ||||||||||||
Limited partners' interest in net income (loss) | 73,207 | (15,250 | ) | (20,489 | ) | 34,472 | 71,940 | ||||||||||||
Net income (loss) per limited partner unit: (1) | |||||||||||||||||||
Common-basic | $ | 3.22 | $ | (0.67 | ) | $ | (0.90 | ) | $ | 1.52 | $ | 3.17 | |||||||
Common-diluted | $ | 3.21 | $ | (0.67 | ) | $ | (0.90 | ) | $ | 1.51 | $ | 3.16 |
Year Ended December 31, 2017 | |||||||||||||||||||
First | Second | Third | Fourth | Total | |||||||||||||||
(in thousands, except for per unit amounts) | |||||||||||||||||||
Net sales | $ | 917,807 | $ | 513,626 | $ | 491,393 | $ | 932,170 | $ | 2,854,996 | |||||||||
Net income (loss) | 64,499 | (7,792 | ) | (14,316 | ) | (12,894 | ) | 29,497 | |||||||||||
Limited partners' interest in net income (loss) | 63,757 | (8,646 | ) | (15,340 | ) | (14,267 | ) | 25,504 | |||||||||||
Net income (loss) per limited partner unit: (1) | |||||||||||||||||||
Common-basic | $ | 2.98 | $ | (0.39 | ) | $ | (0.68 | ) | $ | (0.63 | ) | $ | 1.15 | ||||||
Common-diluted | $ | 2.94 | $ | (0.39 | ) | $ | (0.68 | ) | $ | (0.63 | ) | $ | 1.13 |
(1) | Quarterly net income (loss) per limited partner unit amounts are stand-alone calculations and may not be additive to full year amounts due to rounding and changes in outstanding units. |
23. | Partnership Distributions |
Cash Distributed | ||||||||||||||||||||||||
For the Quarter Ended | Distribution Date | Per Unit | Common | Subordinated | IDR | DER | Total | |||||||||||||||||
December 31, 2016 | February 14, 2017 | $0.5775 | $ | 6,544 | $ | 5,817 | $ | 597 | $ | 802 | $ | 13,760 | ||||||||||||
March 31, 2017 | May 15, 2017 | $0.5925 | $ | 13,357 | $ | — | $ | 742 | $ | — | $ | 14,099 | ||||||||||||
June 30, 2017 | August 11, 2017 | $0.6075 | $ | 13,696 | $ | — | $ | 854 | $ | — | $ | 14,550 | ||||||||||||
September 30, 2017 | November 13, 2017 | $0.6225 | $ | 14,039 | $ | — | $ | 1,024 | $ | — | $ | 15,063 | ||||||||||||
December 31, 2017 | February 12, 2018 | $0.6375 | $ | 14,489 | $ | — | $ | 1,373 | $ | 1,760 | $ | 17,622 | ||||||||||||
March 31, 2018 | May 18, 2018 | $0.6525 | $ | 14,830 | $ | — | $ | 1,714 | $ | — | $ | 16,544 | ||||||||||||
June 30, 2018 | August 10, 2018 | $0.6675 | $ | 15,170 | $ | — | $ | 2,055 | $ | — | $ | 17,225 | ||||||||||||
September 30, 2018 | November 13, 2018 | $0.6675 | $ | 15,175 | $ | — | $ | 2,055 | $ | — | $ | 17,230 |
Name | State or Other Jurisdiction of Incorporation | Percent of Ownership |
Sprague Operating Resources LLC | Delaware | 100% |
Sprague Energy Solutions Inc. | Delaware | 100% |
Sprague Connecticut Properties LLC | Delaware | 100% |
Sprague Terminal Services LLC | Delaware | 100% |
Sprague Co-op Member LLC | Delaware | 100% |
Coen Transport LLC | Pennsylvania | 100% |
Coen Energy LLC | Pennsylvania | 100% |
Sprague Natural Gas LLC | Delaware | 100% |
Kildair Service ULC | Canada | 99.2% |
[0.8% owned by Sprague Co-op Member LLC] | ||
Sprague Resources Canada ULC | Canada | 100% |
Wintergreen Transport Corporation ULC | Canada | 100% |
Sprague Resources Finance Corp | Delaware | 100% |
• | Form S-8 No. 333-191923 pertaining to the Sprague Resources LP 2013 Long Term Incentive Plan; and |
• | Form S-3 No. 333-200148 pertaining to Sprague Resources LP and Sprague Resources Finance Corp |
1. | I have reviewed this annual report on Form 10-K of Sprague Resources LP; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: March 14, 2019 |
/s/ DAVID C. GLENDON |
David C. Glendon |
President and Chief Executive Officer |
1. | I have reviewed this annual report on Form 10-K of Sprague Resources LP; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: March 14, 2019 |
/s/ DAVID C. LONG |
David C. Long |
Chief Financial Officer |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
Date: March 14, 2019 |
/s/ DAVID C. GLENDON |
David C. Glendon |
President and Chief Executive Officer |
(Principal Executive Officer) |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
Date: March 14, 2019 |
/s/ DAVID C. LONG |
David C. Long |
Chief Financial Officer |
(Principal Financial Officer) |
Document and Entity Information - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Mar. 08, 2019 |
Jun. 29, 2018 |
|
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | SRLP | ||
Entity Registrant Name | Sprague Resources LP | ||
Entity Central Index Key | 0001525287 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 257 | ||
Entity Common Stock, Shares Outstanding | 22,733,977 | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false |
Consolidated Balance Sheets (Parenthetical) - shares |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Common Unitholders - Public | ||
Units, issued (in shares) | 10,627,629 | 10,446,539 |
Units, outstanding (in shares) | 10,627,629 | 10,446,539 |
Common Unitholders - Affiliated | ||
Units, issued (in shares) | 12,106,348 | 12,106,348 |
Units, outstanding (in shares) | 12,106,348 | 12,106,348 |
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Statement of Comprehensive Income [Abstract] | |||
Net income | $ 79,819 | $ 29,497 | $ 10,166 |
Unrealized gain (loss) on interest rate swaps | |||
Net income (loss) arising in the period | (253) | 1,884 | 223 |
Reclassification adjustment related to (gains) losses realized in income | (2,179) | (173) | 1,519 |
Net change in unrealized loss (gain) on interest rate swaps | (2,432) | 1,711 | 1,742 |
Tax effect | 20 | (14) | (25) |
Unrealized gain (loss) on interest rate swaps, Total | (2,412) | 1,697 | 1,717 |
Foreign currency translation adjustment | (240) | 216 | (861) |
Other comprehensive (loss) income | (2,652) | 1,913 | 856 |
Comprehensive income | $ 77,167 | $ 31,410 | $ 11,022 |
Consolidated Statements of Unitholders' Equity - USD ($) $ in Thousands |
Total |
Common- Public |
Common- Sprague Holdings |
Subordinated Sprague Holdings |
Incentive Distribution Rights |
Accumulated Other Comprehensive Loss |
---|---|---|---|---|---|---|
Beginning balance at Dec. 31, 2015 | $ 157,485 | $ 189,483 | $ (1,370) | $ (18,989) | $ 0 | $ (11,639) |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||
Net income | 10,166 | 3,815 | 847 | 4,192 | 1,312 | |
Other comprehensive income (loss) | 856 | 856 | ||||
Unit-based compensation | 4,224 | 1,820 | 404 | 2,000 | ||
Distributions paid | (47,503) | (19,894) | 4,419 | (21,878) | (1,312) | |
Common units issued with annual bonus | 4,079 | 1,748 | 392 | 1,939 | ||
Units withheld for employee tax obligations | (3,870) | (1,658) | (372) | (1,840) | ||
Ending balance at Dec. 31, 2016 | 125,437 | 175,314 | (4,518) | (34,576) | 0 | (10,783) |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||
Net income | 29,497 | 11,955 | 14,324 | 0 | 3,218 | |
Conversion of subordinated units to common units | 0 | (40,393) | 40,393 | |||
Other comprehensive income (loss) | 1,913 | 1,913 | ||||
Unit-based compensation | 2,274 | 1,034 | 1,240 | 0 | ||
Distributions paid | (57,472) | (25,198) | (23,239) | (5,817) | (3,218) | |
Common units issued for acquisitions | 31,401 | 31,401 | ||||
Common units issued with annual bonus | 371 | 161 | 210 | |||
Units withheld for employee tax obligations | (1,587) | (690) | (897) | |||
Ending balance at Dec. 31, 2017 | 131,834 | 193,977 | (53,273) | 0 | 0 | (8,870) |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||
Net income | 79,819 | 33,940 | 38,683 | 7,196 | ||
Other comprehensive income (loss) | (2,652) | (2,652) | ||||
Unit-based compensation | (896) | (419) | (477) | |||
Distributions paid | (68,621) | (29,646) | (31,779) | (7,196) | ||
Units withheld for employee tax obligations | (2,508) | (1,172) | (1,336) | |||
Ending balance at Dec. 31, 2018 | $ 136,976 | $ 196,680 | $ (48,182) | $ 0 | $ 0 | $ (11,522) |
Description of Business and Summary of Significant Accounting Policies |
12 Months Ended | ||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | |||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||
Description of Business and Summary of Significant Accounting Policies |
Partnership Businesses Sprague Resources LP (the “Partnership”) is a Delaware limited partnership formed on June 23, 2011 by Sprague Holdings and its General Partner and engages in the purchase, storage, distribution and sale of refined products and natural gas, and provides storage and handling services for a broad range of materials. Unless the context otherwise requires, references to “Sprague Resources,” and the “Partnership,” refer to Sprague Resources LP and its subsidiaries; references to “Axel Johnson” or the “Parent” or the "Sponsor" refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner; references to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of the General Partner, and references to the “General Partner” refer to Sprague Resources GP LLC. The Partnership owns, operates and/or controls a network of refined products and materials handling terminals located in the Northeast United States and in Quebec, Canada. The Partnership also utilizes third-party terminals in the Northeast United States through which it sells or distributes refined products pursuant to rack, exchange and throughput agreements. The Partnership has four business segments: refined products, natural gas, materials handling and other operations.
See Note 2 - Revenue for a description of the Partnership's revenue activities within these business segments. As of December 31, 2018, the Parent, through its ownership of Sprague Holdings, owned 12,106,348 common units representing 53% of the limited partner interest in the Partnership. Sprague Holdings also owns the General Partner, which in turn owns a non-economic interest in the Partnership. Sprague Holdings currently holds incentive distribution rights ("IDRs") that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from distributable cash flow in excess of $0.474375 per unit per quarter. The maximum distribution of 50% does not include any distributions that Sprague Holdings may receive on any limited partner units that it owns. See Note 21 - Earnings per Unit and Note 23 - Partnership Distributions. Prior to February 16, 2017, Sprague Holdings owned, directly or indirectly, all of the Partnership’s subordinated units. The principal difference between the Partnership’s common units and subordinated units is that during the subordination period, the common units had the right to receive a minimum quarterly distribution of $0.4125 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of cash from distributable cash flow could be made on the subordinated units. On February 16, 2017, based upon meeting certain distribution and performance tests provided in the Partnership's partnership agreement, all 10,071,970 subordinated units outstanding converted to common units on a one-for-one basis. Services Agreement The Partnership, the General Partner and Sprague Holdings operate under a services agreement (the “Services Agreement”) pursuant to which the General Partner provides certain general and administrative and operational services to the Partnership and Sprague Holdings, and the Partnership and Sprague Holdings reimburse the General Partner for all costs and expenses incurred in connection with providing such services to the Partnership and Sprague Holdings. The Services Agreement does not limit the amount that may be reimbursed or paid by the Partnership to the General Partner. The initial term of the Services Agreement expired on October 30, 2018 and automatically renewed at the end of the initial term for successive one-year terms until terminated in accordance with the terms thereof. The Services Agreement does not limit the ability of the officers and employees of the General Partner to provide services to other affiliates of Sprague Holdings or unaffiliated third parties. See Note 13 - Related Party Transactions. As of December 31, 2018, the General Partner employed approximately 800 full-time employees who support the Partnership’s operations, 60 of whom were covered by five collective bargaining agreements. One of these agreements, covering six employees is up for renewal in 2019. As of December 31, 2018, the Partnership's Canadian subsidiary had 101 employees, 37 of whom were covered by one collective bargaining agreement which expires on March 18, 2021. Basis of Presentation The Consolidated Financial Statements include the accounts of the Partnership and its wholly-owned subsidiaries. Intercompany transactions between the Partnership and its subsidiaries have been eliminated. Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset and liability valuations as part of an acquisition, the fair value of derivative assets and liabilities, valuation of contingent consideration, valuation of reporting units within the goodwill impairment assessment, and if necessary long-lived asset impairments and environmental and legal obligations. Revenue Recognition and Cost of Products Sold Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The majority of the Partnership’s 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, the Partnership recognizes revenue for refined products and natural gas when title and risk of loss have been transferred to the customer which is generally at the time of shipment or delivery of products. Revenue for the Partnership’s 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 the Partnership expects 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 Partnership's 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). Estimated discounts are included in the transaction price of the contracts with customers as a reduction to net sales. Cash discounts were $7.7 million, $5.9 million and $3.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. The Partnership sells its products or provides its services directly to commercial customers and wholesale distributors generally under agreements with payment terms typically less than 30 days. The Partnership has elected to 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). The Partnership has elected to exclude from net sales any value add, sales and other taxes which it collects concurrently with revenue-producing activities. These accounting policy elections are consistent with the way the Partnership historically recorded shipping and handling fees and taxes. The majority of the Partnership's revenue is derived from contracts (i) with an original expected length of one year or less and (ii) contracts for which it recognizes revenue at the amount in which it has the right to invoice the customer as product is delivered. The Partnership has elected the practical expedient not to disclose the value of remaining performance obligations associated with these types of contracts. Commodity Derivatives The Partnership utilizes derivative instruments consisting of futures contracts, forward contracts, swaps, options and other derivatives individually or in combination, to mitigate its exposure to fluctuations in prices of refined petroleum products and natural gas. The use of these derivative instruments within the Partnership's risk management policy may, on a limited basis, generate gains or losses from changes in market prices. The Partnership enters into futures and over-the-counter (“OTC”) transactions either on regulated exchanges or in the OTC market. Futures contracts are exchange-traded contractual commitments to either receive or deliver a standard amount or value of a commodity at a specified future date and price, with some futures contracts based on cash settlement rather than a delivery requirement. Futures exchanges typically require margin deposits as security. OTC contracts, which may or may not require margin deposits as security, involve parties that have agreed either to exchange cash payments or deliver or receive the underlying commodity at a specified future date and price. The Partnership posts initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets and other current liabilities. In addition, the Partnership may either pay or receive margin based upon exposure with counterparties. Payments made by the Partnership are included in other current assets, whereas payments received by the Partnership are included in accrued liabilities. Substantially all of the Partnership’s commodity derivative contracts outstanding as of December 31, 2018 will settle prior to June 30, 2020. The Partnership enters into some master netting arrangements to mitigate credit risk with significant counterparties. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Partnership to terminate all contracts upon occurrence of certain events, such as a counterparty’s default. The Partnership has elected not to offset the fair value of its derivatives, even where these arrangements provide the right to do so. The Partnership’s derivative instruments are recorded at fair value, with changes in fair value recognized in net income (loss) each period. The Partnership’s fair value measurements are determined using the market approach and includes non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Partnership’s credit is considered for payable balances. The Partnership does 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 the fair value of derivative instruments executed with the same counterparty under the same master netting arrangement. The Partnership had no right to reclaim or obligation to return cash collateral as of December 31, 2018 or 2017. Interest Rate Derivatives The Partnership manages its exposure to variable LIBOR borrowings by using interest rate swaps to convert a portion of its variable rate debt to fixed rates. These interest rate swaps are designated as cash flow hedges and the effective portion of changes in fair value of the swaps are included as a component of comprehensive income (loss) and accumulated other comprehensive income (loss), net of tax. Any ineffective portion of the changes in fair value of the swaps is recorded in interest expense. To designate a derivative as a cash flow hedge, the Partnership documents at inception the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. The assessment, updated at least quarterly, is based on the most recent relevant historical correlation between the derivative and the item hedged. If during the term of the derivative, the hedge is found to be less than highly effective, hedge accounting is prospectively discontinued and the remaining gains and losses are reclassified to income in the current period. Market and Credit Risk The Partnership manages the risk fluctuations in the price and transportation costs of its commodities through the use of derivative instruments. The volatility of prices for energy commodities can be significantly influenced by market supply and demand, changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. The Partnership monitors and manages its exposure to market risk on a daily basis in accordance with approved policies. The Partnership has a number of financial instruments that are potentially at risk including cash and cash equivalents, receivables and derivative contracts. The Partnership’s primary exposure is credit risk related to its receivables and counterparty performance risk related to its derivative assets, which is the loss that may result from a customer’s or counterparty’s non-performance. The Partnership uses credit policies to control credit risk, including utilizing an established credit approval process, monitoring customer and counterparty limits, employing credit mitigation measures such as analyzing customer financial statements, and accepting personal guarantees and various forms of collateral. The Partnership believes that the counterparties to its derivative contracts will be able to satisfy their contractual obligations. Credit risk is limited by the large number of customers and counterparties comprising the Partnership’s business and their dispersion across different industries. The Partnership’s cash is in demand deposits placed with federally insured financial institutions. Such deposit accounts at times may exceed federally insured limits. The Partnership has not experienced any losses on such accounts. Fair Value Measurements The Partnership determines 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 OTC derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Partnership utilizes fair value measurements based on Level 2 inputs for its 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. The Partnership utilizes fair value measurements based on Level 3 inputs for its contingent consideration obligation. Long-Term Incentive Plan The General Partner adopted the Sprague Resources LP 2013 Long-Term Incentive Plan (the “LTIP”), for the benefit of employees, consultants and directors of the General Partner and its affiliates, who provide services to the General Partner or an affiliate. The LTIP provides the Partnership with the flexibility to grant unit options, restricted units, phantom units, unit appreciation rights, cash awards, distribution equivalent rights, substitute awards and other unit-based awards or any combination of the foregoing. The LTIP will expire upon the earlier of (i) its termination by the board of directors of the General Partner, (ii) the date common units are no longer available under the LTIP for grants or (iii) the tenth anniversary of the date the LTIP was approved by the General Partner. The board of directors of the General Partner grants performance-based phantom unit awards to key employees that vest over a period of time (usually three years). Upon vesting, a holder of performance-based phantom units is entitled to receive a number of common units of the Partnership equal to a percentage (between 0 and 200%) of the phantom units granted, based on the Partnership’s achieving pre-determined performance criteria. The Partnership uses authorized but unissued units to satisfy its unit-based obligations. TUR-based Phantom Units Phantom unit awards granted through 2015 include a market condition criteria that considers the Partnership's total unitholder return ("TUR") over the three year vesting period, compared with the total unitholder return of a peer group of other master limited partnership energy companies over the same period. These awards are equity awards with both service and market-based conditions, which results in compensation cost being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market based conditions are satisfied. The fair value of the TUR based phantom units was estimated at the date of grant based on a Monte Carlo model that estimates the most likely performance outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership’s common units as of the valuation date, the historical volatility of the market price of the Partnership’s common units, the historical volatility of the market price of the common units or common stock of the peer companies and the correlation between changes in the market price of the Partnership’s common units and those of the peer companies. OCF-based Phantom Units Phantom unit awards granted since 2015 include a performance criteria that considers Sprague Holdings operating cash flow, as defined therein ("OCF"), over a three year performance period. The number of common units that may be received in settlement of each phantom unit award can range between 0 and 200% of the number of phantom units granted based on the level of OCF achieved during the vesting period. These awards are equity awards with performance and service conditions which result in compensation cost being recognized over the requisite service period once payment is determined to be probable. Compensation expense related to the OCF based awards is estimated each reporting period by multiplying the number of common units underlying such awards that, based on the Partnership's estimate of OCF, are probable to vest, by the grant-date fair value of the award and is recognized over the requisite service period using the straight-line method. The fair value of the OCF based phantom units was the grant date closing price listed on the New York Stock Exchange. The number of units that the Partnership estimates are probable to vest could change over the vesting period. Any such change in estimate is recognized as a cumulative adjustment calculated as if the new estimate had been in effect from the grant date. Distribution Equivalent Rights The Partnership's performance-based phantom unit awards include tandem distribution equivalent rights ("DERs") which entitle the participant to a cash payment only upon vesting that is equal to any cash distribution paid on a common unit between the grant date and the date the phantom units were settled. Payments made in connection with DERs are recorded as a distribution in unitholders' equity. Earnings (Loss) Per Unit The Partnership computes income (loss) per unit using the two-class method. Net income (loss) attributable to common unitholders and subordinated unitholders for purposes of the basic income (loss) per unit computation was allocated between the common unitholders and subordinated unitholders by applying the provisions of the partnership agreement. Under the two-class method, any excess of distributions declared over net income (loss) was allocated to the partners based on their respective sharing of income specified in the partnership agreement. Net income (loss) per unit was determined by dividing the net income (loss) allocated to the common unitholders and the subordinated unitholders under the two-class method by the number of common units and subordinated units outstanding in the period. As previously noted, on February 16, 2017, based upon meeting certain distribution and performance tests provided in the Partnership's partnership agreement, all 10,071,970 subordinated units outstanding converted to common units on a one-for-one basis. As discussed in Note 21 - Earnings Per Unit, there was no allocation between the common unitholders and subordinated unitholders for the year ended December 31, 2017 since all subordinated units outstanding were converted to common units on February 16, 2017, and the subordinated units did not share in any distribution of cash generated during 2017. Cash and Cash Equivalents Cash and cash equivalents include cash and highly liquid investments which are readily convertible into cash and have maturities of three months or less when purchased. Inventories The Partnership’s inventories are valued at the lower of cost or net realizable value. Cost is primarily determined using the first-in, first-out method, except for the Partnership's Canadian subsidiary, which used the weighted average method. Inventory consists of petroleum products, natural gas and coal. The Partnership uses derivative instruments, primarily futures, forwards and swaps, to economically hedge substantially all of its inventory. Property, Plant and Equipment, Net Property, plant and equipment, net are recorded at historical cost. Depreciation is computed on a straight-line basis over the following estimated useful lives:
Leasehold improvements are amortized over the term of the lease or the estimated useful life of the improvement, whichever is shorter. Maintenance and repairs are charged to expense as incurred. Costs and related accumulated depreciation of properties sold or otherwise disposed of are removed from the respective accounts, and any resulting gains or losses are recorded at that time. Long-lived Asset Impairment The Partnership evaluates the carrying value of its property, plant and equipment and finite lived intangible assets for impairment when events or changes in circumstances indicate the carrying amount of an individual asset or asset group may not be recoverable based on estimated future undiscounted cash flows. Future cash flow projections include assumptions of future sales levels, the impact of controllable cost reduction programs, and the level of working capital needed to support each business. To the extent the carrying amount of the asset group is not recoverable based on undiscounted cash flows, the amount of impairment is measured by the difference between the carrying value and the fair value of the individual assets or asset group. Purchase Price Allocation The cost of an acquired entity is allocated to the assets acquired and liabilities assumed based on their respective fair values at the date of acquisition. Property, plant and equipment and goodwill generally represent large components of these acquisitions. In addition to goodwill, intangible assets acquired generally include customer relationships and non-compete agreements. Goodwill is calculated as the excess of the cost of the acquired entity over the net of the fair value of the assets acquired and the liabilities assumed. For all material acquisitions the Partnership determines the fair value of the assets acquired and liabilities assumed, including goodwill, based on recognized business valuation methodologies. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, based on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. For contingent consideration arrangements, a liability is recognized at fair value as of the acquisition date with subsequent fair value adjustments recorded in operations. Additional information regarding the Partnership's contingent consideration arrangements may be found in Note 3 - Business Combinations, Note 14 - Other Obligations and Note 18 - Financial Instruments and Off-Balance Sheet Risk. Other assets acquired and liabilities assumed typically include, but are not limited to, inventory, accounts receivable, accounts payable and other working capital items. Because of their short-term nature, the fair values of these other assets and liabilities generally approximate the book values on the acquired entity’s balance sheet. Goodwill Goodwill is not amortized but tested for impairment at the reporting unit level, at least annually (as of October 31 each year), by determining the fair value of the reporting unit and comparing it to its carrying value, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, the Partnership will determine if there is a potential impairment by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than the carrying amount, an impairment loss would be reported. The Partnership assesses the fair value of its reporting units based on a discounted cash flow valuation model (Level 3 measurement). The key assumptions used are discount rates and growth rates, applied to cash flow projections. These assumptions contemplate business, market and overall economic conditions. After applying the discounted cash flow methods to measure the fair value of its reporting units, including the consideration of reasonably likely adverse changes in the rates and assumptions described above, the Partnership determined that there have been no goodwill impairments to date. In performing the discounted cash flow analysis, the Partnership also used a range of discount rate assumptions to evaluate the sensitivity on the fair values resulting from the discounted cash flow valuation. Intangibles, Net Intangibles, net consist of intangible assets with finite lives, primarily customer relationships and non-compete agreements. Intangibles and other assets are amortized over their respective estimated useful lives. The Partnership believes the sum-of-the-years’-digits method of amortization properly reflects the timing of the recognition of the economic benefits realized from its intangible assets. Income Taxes The Partnership is organized as a pass-through entity for U.S. federal income tax purposes. As a result, the partners are responsible for U.S. federal income taxes based on their respective share of taxable income. Net income (loss) for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. The Partnership, however, is subject to a statutory requirement that non-qualifying income cannot exceed 10% of total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of non-qualifying income exceeds this statutory limit, the Partnership would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through Sprague Energy Solutions, Inc., a taxable corporate subsidiary. Sprague Energy Solutions, Inc. is subject to U.S. federal and state income tax and pays any income taxes related to the results of its operations. For the year ended December 31, 2018, the Partnership’s non-qualifying income did not exceed the statutory limit. The Partnership is subject to income tax and franchise tax in certain domestic state and local as well as foreign jurisdictions. Income taxes (e.g., deferred tax assets, deferred tax liabilities, taxes currently payable and tax expense) are recorded based on amounts refundable or payable in the current year and include the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred taxes are measured by applying currently enacted tax rates. The Partnership establishes a valuation allowance for deferred tax assets when it is more likely than not that these assets will not be realized. The Partnership's Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes and are subject to Canadian federal and provincial taxes. Additionally, payments of dividends from the Partnership's Canadian entities to other Sprague entities are subject to Canadian withholding tax that is treated as income tax expense. The partnership's foreign subsidiaries record investment tax credits under the deferral method. The Partnership recognizes the financial statement effect of an uncertain tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. The Partnership classifies interest and penalties associated with uncertain tax positions as income tax expense. During the years ended December 31, 2018, 2017 and 2016, the interest and penalties recognized by the Partnership were immaterial. The Partnership and its subsidiaries tax returns are subject to examination by the Internal Revenue Service and by the Canada Revenue Agency for the years ended December 31, 2017, 2016 and 2015. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since the operations of the Partnership are generally not subject to federal income tax, the Tax Act has not had a material impact to the Partnership. Foreign Currency The Partnership’s reporting currency is the U.S. dollar. The Partnership's most significant foreign operations are conducted by Kildair, a Canadian subsidiary. The functional currency of Kildair is the U.S. dollar. Kildair has an operating subsidiary whose functional currency is the Canadian 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. For the years ended December 31, 2018, 2017 and 2016, 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, amounted to gains of $0.2 million, $0.3 million and $0.1 million, respectively, which is recorded in cost of products sold (exclusive of depreciation and amortization). Recent Accounting Pronouncements In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities. The objective of the guidance is to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership anticipates that the adoption of this ASU in 2019 will not have a material impact to the Partnership's consolidated financial statements. In January 2017, the FASB issued ASU 2017-04 Intangibles - Goodwill and Other (Topic 350): Simplifying the Accounting for Goodwill Impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The standard will be applied prospectively, and is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for any impairment tests performed after January 1, 2017. In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805), which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of this new guidance in 2018 did not have an impact on the Partnership's consolidated financial statements. In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. The adoption of this new guidance in 2018 did not have an impact on the Partnership's consolidated statement of cash flows. In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842), which, among other things, requires lessees to recognize an obligation to make lease payments arising from a lease, measured on a discounted basis, and a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Expenses are recognized in the consolidated statement of operations in a manner similar to current accounting guidance. The Partnership expects to make an accounting policy election to not recognize an asset and liability for leases with a term of twelve months or less. Under the new guidance, lessor accounting is largely unchanged. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Partnership will adopt the accounting standard using a modified retrospective approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Partnership is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $20 million of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which revises the principles of revenue recognition from one based on the transfer of risks and rewards to when a customer obtains control of a good or service. The FASB has issued several ASUs subsequent to ASU 2014-09 in order to clarify implementation guidance but did not change the core principle of the guidance in Topic 606. These ASUs are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this standard in 2018 did not have a material impact on the Partnership's consolidated financial statements nor result in significant changes to business processes, systems, or internal controls. |
Revenue |
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Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue |
Disaggregated Revenue In general, the Partnership's business segmentation is aligned according to the nature and economic characteristics of its products and customer relationships which provides meaningful disaggregation of each business segment's results of operations. The Partnership operates its businesses in the Northeast and Mid-Atlantic United States and Eastern Canada. The refined products segment purchases 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 sells them to wholesale and commercial customers. Refined products revenue-producing activities are direct sales to customers, including throughput and exchange transactions. Revenue is recognized when the product is delivered. Revenue is not recognized on exchange agreements, which are entered into primarily to acquire refined products by taking delivery of products closer to the Partnership’s end markets. Rather, net differentials or fees for exchange agreements are recorded within cost of products sold (exclusive of depreciation and amortization). The natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers. The Partnership purchases the natural gas it sells from natural gas producers and trading companies. Natural gas revenue-producing activities are sales to customers at various points on natural gas pipelines or at local distribution companies (i.e. utilities). Natural gas sales not billed by month-end are accrued based upon gas volumes delivered. The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products. A majority of the materials handling segment revenue is generated under leasing arrangements with revenue recorded over the lease term generally on a straight-line basis. Contingent rentals are recorded as revenue only when billable under the arrangement. For materials handling contracts that are not leases, the Partnership recognizes revenue either at a point in time as services are performed or over a period of time if the services are performed in a continuous fashion over the period of the contract. The other operations segment primarily includes the purchase and distribution of coal and certain commercial trucking activities. Revenue from other activities is recognized when the product is delivered or the services are rendered. Further disaggregation of net sales by business segment and geographic destination is as follows:
Contract Balances Contract liabilities primarily relate to advances or deposits received from the Partnership's customers before revenue is recognized. These amounts are included in accrued liabilities and amounted to $9.8 million and $8.2 million as of December 31, 2018 and December 31, 2017, respectively. A substantial portion of the contract liabilities as of December 31, 2017 remains outstanding as of December 31, 2018 as they are primarily deposits. The Partnership does not have any material contract assets as of December 31, 2018 or December 31, 2017. |
Business Combinations |
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Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combinations |
The Partnership completed five business acquisitions during the year ended December 31, 2017 and one business acquisition during the year ended December 31, 2016, as described below. Allocations of the purchase price to the assets acquired and liabilities assumed have been made to record, where applicable, inventory, derivative assets and liabilities, natural gas transportation assets and liabilities, property, plant and equipment, identifiable intangible assets such as customer relationships and non-compete agreements as well as goodwill. The Partnership recognized $3.0 million and $0.1 million of acquisition costs during the year ended December 31, 2017 and 2016, respectively, which were expensed and are included in selling, general and administrative expense. Year Ended December 31, 2017 Coen Energy On October 1, 2017, the Partnership purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC, as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Coen Energy, located in Washington, PA, provides energy products to commercial, and residential customers located in Pennsylvania, Ohio and West Virginia. The Coen Energy business also provides energy fuel services to customers that are engaged in Marcellus and Utica shale drilling operations. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees as of December 31, 2017. Initial cash consideration was $35.3 million, not including the purchase of inventory and other adjustments, which was financed with borrowings under the Credit Agreement (see Note 12 - Credit Agreement). Contingent consideration of up to $12 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020. The Partnership estimated the fair value of the contingent consideration to be $9.6 million as of the date of the acquisition resulting in total consideration of $44.9 million. See Note 18 - Financial Instruments and Off-Balance Sheet Risk, for additional information regarding the Partnership’s contingent consideration obligation. The operations of Coen Energy are included in the Partnership's refined products segment since the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The goodwill recognized is primarily attributable to Coen’s reputation in it's geographic market area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate. Carbo Terminals On April 18, 2017, the Partnership acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under the Credit Agreement, an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and $31.4 million in unregistered common units. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck. The operations of Carbo are included in the Partnership's refined products segment since the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The goodwill recognized is primarily attributable to Carbo’s reputation in the New York City area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate. Capital Terminal On February 10, 2017, the Partnership purchased the East Providence, Rhode Island refined product terminal business of Capital Properties Inc. (the “Capital Terminal”). Consideration paid was $22.0 million and was financed with borrowings under the Credit Agreement. The terminal’s distillate storage capacity of 1.0 million barrels had been leased by the Partnership since April 2014 and was previously included in the Partnership’s total storage capacity. The operations of the Capital Terminal are included in the Partnership's refined products segment since the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
Global Natural Gas & Power On February 1, 2017, the Partnership purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under the Credit Agreement. This business markets natural gas and electricity to commercial, industrial, municipal and institutional customer locations in the Northeast United States. The operations of Global Natural Gas & Power are included in the Partnership's natural gas segment since the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The goodwill recognized is primarily attributable to Global Natural Gas & Power’s reputation in its market regions, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate. L.E. Belcher Terminal On February 1, 2017, the Partnership purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for $20.0 million, not including the purchase of inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $20.7 million and was financed with borrowings under the Credit Agreement. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses. The operations of L.E. Belcher are included in the Partnership's refined products segment since the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The goodwill recognized is primarily attributable to LEB’s reputation in the Springfield, Massachusetts area, the in-place workforce and the residual cash flow the Partnership believes that it will be able to generate. Following is the unaudited pro forma consolidated net sales and net income as if the businesses acquired during the year ended December 31, 2017 had been included in the consolidated results of the Partnership for the twelve months ended December 31, 2017 and 2016:
These amounts have been calculated after applying the Partnership’s accounting policies and adjusting the results of the acquired businesses to reflect the depreciation and amortization that would have been charged assuming the fair value adjustments to property, plant and equipment and intangible assets had been applied on January 1, 2016, together with an adjustment to reflect taxes as a pass-through entity for U.S. federal income tax purposes. The net sales and net income (loss) of the acquired businesses included in the Partnership’s consolidated operating results from their respective acquisition dates, through the year ended December 31, 2017 were $142.8 million and $(10.3) million, respectively. Year Ended December 31, 2016 Natural Gas Business of Santa Buckley Energy, Inc. On February 1, 2016, the Partnership purchased the natural gas business of Santa Buckley Energy, Inc. (“SBE”) for $17.5 million, not including the purchase of natural gas inventory, utility security deposits, and other adjustments. Total consideration at closing was $29.1 million. SBE markets natural gas to commercial, industrial and municipal consumers in the Northeast United States. The acquisition was accounted for as a business combination and was financed with borrowings under the Partnership’s credit facility. The operations of SBE are included in the Partnership's natural gas segment since the acquisition date. The following table summarizes the fair values of the assets acquired and liabilities assumed:
The goodwill recognized is primarily attributable to SBE’s reputation in the Northeast United States and the residual cash flow the Partnership believes that it will be able to generate. |
Accumulated Other Comprehensive Loss, Net of Tax |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Loss, Net of Tax |
Amounts included in accumulated other comprehensive loss, net of tax, consisted of the following:
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Accounts Receivable, Net |
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Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable, Net |
Unbilled accounts receivable, included in accounts receivable, trade at December 31, 2018 and 2017 were $50.5 million and $81.6 million, respectively. Unbilled receivables relate primarily to the delivery and sale of natural gas to customers in the current month for which the right to bill exists. Such amounts generally are invoiced to the customer the following month when actual usage data becomes available. Accounts receivable, other consists primarily of product tax receivables. A reconciliation of the beginning and ending amount of allowance for doubtful accounts follows:
Notes receivable, net of allowance, are generally long-term arrangements and were fully reserved as of December 31, 2018 and 2017. |
Inventories |
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Inventory Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventories |
Due to changing market conditions, the Partnership recorded a provision of $24.3 million, $0.4 million and $1.7 million as of December 31, 2018, 2017 and 2016, respectively, to write-down petroleum and related products, and natural gas inventory to its net realizable value. These charges are included in cost of products sold (exclusive of depreciation and amortization). |
Other Current Assets |
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Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Current Assets |
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Property, Plant and Equipment, Net |
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Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment, Net |
Depreciation expense for the years ended December 31, 2018, 2017 and 2016 was $21.5 million, $18.3 million and $16.0 million, respectively. Property, plant and equipment include the following amounts under capital leases:
Amortization expense on capital leased assets is included in depreciation expense and for the years ended December 31, 2018, 2017 and 2016 was $1.5 million, $1.6 million and $1.5 million, respectively. |
Intangibles, Net |
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Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangibles, Net |
The Partnership recorded amortization expense related to intangible assets of $11.9 million, $9.8 million and $5.2 million during the years ended December 31, 2018, 2017 and 2016, respectively. The amortization of intangible assets is recorded in depreciation and amortization expense. Fully amortized intangible assets have been eliminated from both the gross and accumulated amortization amounts. During the year ended December 31, 2017, the Partnership acquired intangible assets of $58.2 million (consisting of $47.9 million of customer relationships, $9.5 million of non-compete agreements and $0.8 million of other intangibles). See Note 3 - Business Combinations. The estimated future annual amortization expense of intangible assets for the years ending December 31, 2019, 2020, 2021, 2022 and 2023 is $10.3 million, $8.7 million, $7.2 million, $5.8 million and $4.8 million, respectively. As acquisitions and dispositions occur in the future, these amounts may vary. |
Other Assets, Net |
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Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Assets, Net |
Deferred Debt Issuance Costs The Partnership recorded amortization expense related to deferred debt issuance costs of $3.5 million, $5.2 million and $4.0 million during the years ended December 31, 2018, 2017 and 2016, respectively. The amortization expense for the year ended December 31, 2017 included a write-off of $1.6 million attributable to the refinancing and extension of the Credit Agreement. Deferred debt issuance costs are amortized over the life of the related debt on a straight-line basis and recorded in interest expense. Natural Gas Transportation Assets The Partnership records the fair value of natural gas transportation contracts acquired in business combinations. In 2017, the Partnership recorded an asset of $1.1 million and a liability of $0.6 million in connection with the Global Natural Gas & Power acquisition. In 2016, the Partnership recorded an asset of $8.0 million and a liability of $2.4 million in connection with the SBE acquisition. These assets and liabilities are amortized into cost of products sold (exclusive of depreciation and amortization) in the natural gas segment over the life of the underlying agreements. During the years ended December 31, 2018, 2017 and 2016, the Partnership recorded a charge to cost of products sold (exclusive of depreciation and amortization) of $0.5 million, $1.8 million and $6.5 million, respectively, which included $0.3 million and $1.6 million during the year ended December 31, 2017 and 2016, respectively, due to a decline in value as a result of decreasing natural gas spreads. Natural gas transportation assets and liabilities were fully amortized as of December 31, 2018. |
Accrued Liabilities |
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Payables and Accruals [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued Liabilities |
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Credit Agreement |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Credit Agreement |
Sprague Operating Resources LLC and Kildair Service ULC ("Kildair"), wholly owned subsidiaries of the Partnership, are borrowers under an amended and restated revolving credit agreement that matures on April 27, 2021 (the "Credit Agreement"). Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries. As of December 31, 2018, the revolving credit facilities under the Credit Agreement contained, among other items, the following:
Indebtedness under the Credit Agreement bears interest, at the borrowers' option, at a rate per annum equal to either (i) the Eurocurrency Base 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) for interest periods of one, two, three or six 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 higher of (a) the U.S. Prime Rate as in effect from time to time, (b) the greater of 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 working capital facilities are subject to borrowing base reporting and as of December 31, 2018 and 2017, had a borrowing base of $512.4 million and $623.2 million, respectively. As of December 31, 2018 and 2017, outstanding letters of credit were $65.5 million and $72.3 million, respectively. As of December 31, 2018, excess availability under the working capital facility was $161.9 million and excess availability under the acquisition facilities was $173.9 million. The weighted average interest rate was 5.3% and 4.2% at December 31, 2018 and 2017, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the Credit Agreement at December 31, 2018 and 2017 represents the amounts of the working capital facility intended to be repaid during the following twelve month period. The Credit Agreement contains certain restrictions and covenants among which are a minimum level of net working capital, fixed charge coverage and debt leverage ratios and limitations on the incurrence of indebtedness. The Credit Agreement limits the Partnership’s ability to make distributions in the event of a default as defined in the Credit Agreement. As of December 31, 2018, the Partnership was in compliance with these covenants. |
Related Party Transactions |
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Dec. 31, 2018 | |||||||
Related Party Transactions [Abstract] | |||||||
Related Party Transactions |
The General Partner charges the Partnership for the reimbursements of employee costs and related employee benefits and other overhead costs supporting the Partnership’s operations which amounted to $111.8 million, $97.3 million and $90.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts due to the General Partner were $9.8 million and $12.9 million as of December 31, 2018 and 2017, respectively. Through the General Partner, the Partnership participates in the Parent’s pension and other post-retirement benefits (see Note 16 - Retirement Plans). |
Other Obligations |
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Other Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Obligations |
Deferred Consideration - Carbo Terminals In connection with the Carbo acquisition entered into during 2017, the Partnership is obligated to pay to Carbo a total of $38.2 million in equal monthly installments of $0.3 million payable over a ten year period. The obligation was recorded at an estimated fair value of $27.3 million using a discount rate of 7.1%. The short-term portion of this obligation as of December 31, 2018 is $2.2 million and is included in the current portion of other obligations. Deferred consideration obligation maturities for each of the next five years and thereafter as of December 31, 2018 are as follow:
Contingent Consideration - Coen Energy In connection with the Coen Energy acquisition entered into during 2017, the Partnership may be obligated to pay contingent consideration of up to $12.0 million during the three year period following the acquisition. The contingent consideration represents a liability recognized at fair value as of the acquisition date with subsequent fair value adjustments at each reporting period to be recorded in operations. The estimated fair value of this obligation as of December 31, 2018 and 2017, is $8.4 million and $9.7 million, respectively. The short-term portion of this obligation of $1.9 million and $1.9 million as of December 31, 2018, and 2017 respectively, is included in the current portion of other obligations and represents an estimate of the expected future payment during the following twelve month period. See Note 3 - Business Combinations and Note 18 - Financial Instruments and Off-Balance Sheet Risk for additional information regarding the Partnership's contingent consideration obligation. Port Authority Terminal Obligations The Port Authority terminal obligations represent long-term obligations of the Partnership to a third party that constructed dock facilities at the Partnership’s Searsport, Maine terminal. These amounts will be repaid by future wharfage fees incurred by the Partnership for the use of these facilities. The short-term portion of these obligations of $0.6 million at December 31, 2018 and $0.6 million at December 31, 2017 is included in accrued liabilities and represents an estimate of the expected future wharfage fees for the ensuing year. The Partnership has exclusive rights to the use of the dock facilities through a license and operating agreement (“License Agreement”), which expires in 2033. The License Agreement provides the Partnership the option to purchase the dock facilities at any time at an amount equal to the remaining license fees due. The related dock facilities assets are treated as a capital lease and are included in property, plant and equipment. Asset Retirement Obligation The Partnership has accrued an asset retirement obligation (“ARO”) that relates to an environmental obligation associated with the purchase of a terminal in Bridgeport, Connecticut. The obligation was recorded in 2017 when the obligation was determinable. The current portion of the ARO represents the estimated obligation retirements for the ensuing year and is recorded in accrued liabilities. The changes in the ARO are as follows:
Post Retirement Benefits Postretirement benefit obligations are comprised of actuarially determined postretirement healthcare, life insurance and other postretirement benefits. See Note 16 - Retirement Plans. |
Income Taxes |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes |
The Partnership is generally not subject to U.S. federal and state income tax with the exception of the Partnership's subsidiary Sprague Energy Solutions, Inc. The Partnership's Canadian operations are subject to Canadian federal and provincial income taxes. The income tax provision (benefit) attributable to operations is summarized as follows:
U.S. and international components of income before income taxes were as follows:
Reconciliations of the statutory U.S. federal income tax to the effective income tax for operations are as follows:
The components of the deferred tax assets (liabilities) were as follows:
The Partnership's Canadian subsidiary had a net operating loss carryforward of $7.0 million as of December 31, 2016, which was fully utilized in the year ended December 31, 2017. As of December 31, 2018, the Partnership has not provided deferred Canadian withholding taxes on accumulated Canadian earnings of $41.2 million which are considered to be indefinitely reinvested outside the U.S. The unrecognized deferred withholding tax liability associated with these earnings is $10.3 million as of December 31, 2018. |
Retirement Plans |
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Postemployment Benefits [Abstract] | |||||||
Retirement Plans |
Pension Plans Through the General Partner, the Partnership participates in a noncontributory defined benefit pension plan, the Axel Johnson Inc. Retirement Plan (the “Plan”), sponsored by the Parent. Benefits under the Plan were frozen as of December 31, 2003, and are based on a participant’s years of service and compensation through December 31, 2003. The Plan’s assets are invested principally in equity and fixed income securities. The Parent’s policy is to satisfy the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”). Through the General Partner, the Partnership also participates in an unfunded pension plan, the Axel Johnson Inc. Retirement Restoration Plan, for employees whose benefits under the defined benefit pension plan were reduced due to limitations under U.S. federal tax laws. Benefits under this plan were frozen as of December 31, 2003. Both the Plan and the Retirement Restoration Plan are administered by the Parent. The costs of these benefits are based on the Partnership’s portion of the projected benefit obligations under these plans. Charges related to these employee benefit plans were $1.1 million, $1.1 million and $1.0 million during the years ended December 31, 2018, 2017 and 2016, respectively. Eligible employees also receive a defined contribution retirement benefit generally equal to a defined percentage of their eligible compensation. This contribution by the Partnership to employee accounts in Axel Johnson Inc.’s Thrift and Defined Contribution Plan is in addition to any Partnership match on 401(k) contributions that employees currently choose to make. The Partnership made total contributions to these plans of $5.4 million, $5.0 million and $4.5 million during the years ended December 31, 2018, 2017 and 2016, respectively. Other Postretirement Benefits The Parent and some of its subsidiaries, which include the Partnership, have a number of health care and life insurance benefit plans covering eligible employees who reach retirement age while working for the Parent. The plans are not funded. In general, employees hired after December 31, 1990, are not eligible for postretirement health care benefits. The Partnership has recorded postretirement expense of $0.3 million during the years ended December 31, 2018, 2017 and 2016, for all periods, related to these plans. |
Segment Reporting |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting |
The Partnership has four reportable segments that comprise the structure used by the chief operating decision makers (CEO and CFO/COO) to make key operating decisions and assess performance. When establishing a reporting segment, the Partnership aggregates individual operating units that are in the same line of business and have similar economic characteristics. These reportable segments are refined products, natural gas, materials handling and other activities. The Partnership's refined products segment purchases 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 sells them to its customers. The Partnership has wholesale customers who resell the refined products they purchase from the Partnership and commercial customers who consume the refined products they purchase. The Partnership’s wholesale customers consist of home heating oil retailers and diesel fuel and gasoline resellers. The Partnership’s commercial customers include federal and state agencies, municipalities, regional transit authorities, drill sites, large industrial companies, real estate management companies, hospitals and educational institutions. The refined products reportable segment consists of three operating segments. The Partnership's natural gas segment purchases natural gas from natural gas producers and trading companies and sells and distributes natural gas to commercial and industrial customers primarily in the Northeast and Mid-Atlantic United States. The natural gas reportable segment consists of one operating segment. The Partnership's materials handling segment offloads, stores, and/or prepares 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. These services are generally provided 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. The materials handling reportable segment consists of two operating segments. The Partnership's other segment primarily consists of the purchase, sale and distribution of coal, and commercial trucking activities unrelated to its refined products segment. Other activities are not reported separately as they represent less than 10% of consolidated net sales and adjusted gross margin. The other activities segment consists of two operating segments. The Partnership evaluates segment performance based on adjusted gross margin, a non-GAAP measure, which is net sales less cost of products sold (exclusive of depreciation and amortization) increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts. Based on the way the business is managed, it is not reasonably possible for the Partnership to allocate the components of operating costs and expenses among the operating segments. There were no significant intersegment sales for any of the years presented below. The Partnership had no single customer that accounted for more than 10% of total net sales for the years ended December 31, 2018, 2017 and 2016, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas to its customers in Canada, were $290.4 million, $265.7 million and $196.4 million for the years ended December 31, 2018, 2017 and 2016, respectively. Summarized financial information for the Partnership’s reportable segments is presented in the table below:
Segment Assets Due to the commingled nature and uses of the Partnership’s fixed assets, the Partnership does not track its fixed assets between its refined products and materials handling operating segments or its other activities. There are no significant fixed assets attributable to the natural gas reportable segment. Changes in the carrying amount of goodwill by segment were as follows:
Long-lived Assets Long-lived assets (exclusive of intangible and other assets, net, and goodwill) classified by geographic location were as follows:
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Financial Instruments and Off-Balance Sheet Risk |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Instruments and Off-Balance Sheet Risk |
As of December 31, 2018 and 2017, the carrying amounts of cash, cash equivalents, accounts receivable, accounts payable and accrued liabilities approximated fair value because of the short maturity of these instruments. As of December 31, 2018 and 2017, the carrying value of the Partnership’s margin deposits with brokers approximates fair value and consists of initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets or other current liabilities. As of December 31, 2018 and 2017, the carrying value of the Partnership’s debt approximated fair value due to the variable interest nature of these instruments. The Partnership’s deferred consideration was recorded in connection with an acquisition on April 18, 2017 using an estimated fair value discount at the time of the transaction. As of December 31, 2018 and 2017, the carrying value of the deferred consideration approximated fair value due to the fact that there has been no significant subsequent change in the estimated fair value discount rate. The following table presents all financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis:
Derivative Instruments The Partnership enters into derivative contracts with counterparties, some of which are subject to master netting arrangements, which allow net settlements under certain conditions. The maximum amount of loss due to credit risk that the Partnership would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the net fair value of these financial instruments, was $82.9 million at December 31, 2018. Information related to these offsetting arrangements as of December 31, 2018 and 2017 is as follows:
As of December 31, 2018, the Partnership held total cash collateral of $28.5 million and posted cash collateral of $0.8 million. As of December 31, 2017, the Partnership held total cash collateral of $4.3 million and posted cash of $29.3 million. The following table presents total realized and unrealized gains (losses) on derivative instruments utilized for commodity risk management purposes included in cost of products sold (exclusive of depreciation and amortization):
There were no discretionary trading activities included in realized and unrealized gains (losses) on derivatives instruments for the years ended December 31, 2018, 2017 and 2016. The following table presents the gross volume of commodity derivative instruments outstanding for the periods indicated:
Interest Rate Derivatives The Partnership has entered into interest rate swaps to manage its exposure to changes in interest rates on its Credit Agreement. The Partnership’s interest rate swaps hedge actual and forecasted LIBOR borrowings and have been designated as cash flow hedges. Counterparties to the Partnership’s interest rate swaps are large multinational banks and the Partnership does not believe there is a material risk of counterparty non-performance. The Partnership's interest rate swap agreements outstanding as of December 31, 2018 were as follows:
There was no material ineffectiveness determined for the cash flow hedges for the years ended December 31, 2018, 2017 and 2016. The Partnership records unrealized gains and losses on its interest rate swaps as a component of accumulated other comprehensive loss, net of tax, which is reclassified to earnings as interest expense when the payments are made. As of December 31, 2018, the amount of unrealized gains, net of tax, expected to be reclassified to earnings during the following twelve-month period was $1.0 million. Contingent Consideration As part of the Coen Energy acquisition in 2017, the Partnership is obligated to pay contingent consideration of up to $12.0 million if certain earnings objectives during the first three years following the acquisition are met. The estimated fair value of the contingent consideration arrangement is classified within Level 3 and was determined using an income approach based on probability-weighted discounted cash flows. Under this method, a set of discrete potential future earnings was determined using internal estimates based on various revenue growth rate assumptions for each scenario. A probability was assigned to each discrete potential future earnings estimate. The resulting probability-weighted contingent consideration amounts were discounted using a weighted average discount rate of 7.0%. Changes in either the revenue growth rates, related earnings or the discount rate could result in a material change to the amount of contingent consideration accrued and such changes will be recorded in the Partnership's consolidated statements of operations. Changes in the contingent consideration liability measured at fair value on a recurring basis using unobservable inputs (Level 3) are as follows:
The Partnership records the change in estimated fair value within selling, general and administrative expenses in the Partnership's Consolidated Statements of Operations. |
Commitments and Contingencies |
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies |
Operating Leases The Partnership has leases for a refined products terminal, refined products storage, maritime charters, office facilities, and equipment for periods extending to 2034 which are recorded as operating leases. Renewal options exist for a substantial portion of these leases. For operating leases, rental expense was $21.1 million, $20.1 million and $21.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. The following table summarizes the future minimum payments for the following five fiscal years for operating lease obligations as of December 31, 2018 with non-cancellable lease terms of one year or more:
Legal, Environmental and Other Proceedings The Partnership is subject to a tax on sales made in Quebec on product it imports into the province. During a recent audit by the Quebec Energy Board (QEB) of the annual filings, the Partnership initiated legal action seeking a declaration to limit the applicability of the tax to direct imports, as well as the periods subject to review. After filing legal action, the Partnership has been assessed $3.5 million of tax, including interest and penalties, for the period of 2013 to 2017, and has provided requested information for previous years. During September 2018, the Partnership received an assessment of $8.2 million, including a penalty and interest, from the Ministry of Sustainable Development, Environment, and the Fight Against Climate Change (known as MDDELCC) under separate regulation that was in effect for the period from 2007 through 2014. The Partnership is disputing the MDDELCC assessment on the same basis as set out in the QEB legal action described above. The Partnership has accrued an amount which it believes to be a reasonable estimate of the low end of a range of loss related to these matters and such amount is not material to the consolidated financial statements. The Partnership is involved in other various lawsuits, other proceedings and environmental matters, all of which arose in the normal course of business. The Partnership believes, based upon its examination of currently available information, its experience to date, and advice from legal counsel, that the individual and aggregate liabilities resulting from the resolution of these contingent matters will not have a material adverse impact on the Partnership’s consolidated results of operations, financial position or cash flows. |
Equity and Equity-Based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity and Equity-Based Compensation |
Equity Awards - Annual Bonus Program The board of directors of the General Partner has approved an annual bonus program which is provided to substantially all employees. Under this program bonuses for the majority of participants will be settled in cash with others receiving a combination of cash and common units. The Partnership records the expected bonus payment as a liability until a grant date has been established and awards finalized, which occurs in the first quarter of the year following the year for which the bonus is earned. Of the bonus accrued as of December 31, 2016, approximately $0.4 million was settled in 2017 by issuing 13,465 common units (market value at settlement of $0.4 million) with 4,625 units withheld from to satisfy employee tax obligations. Of the bonus accrued as of December 31, 2015, approximately $5.0 million was settled in 2016 by issuing 239,641 common units (market value at settlement of $4.1 million) with 78,623 units withheld to satisfy employee tax obligations. Equity Awards - Director Compensation During the years ended December 31, 2018, 2017, and 2016 the board of directors of the General Partner issued 6,693, 9,360, and 9,824, vested units as compensation to certain of its directors, respectively, with estimated total grant date fair values of approximately $0.2 million for each period. Equity Awards - Performance-based Phantom Units The General Partner adopted the Sprague Resources LP 2013 Long-Term Incentive Plan (the “LTIP”), for the benefit of employees, consultants and directors of the General Partner and its affiliates, who provide services to the General Partner or an affiliate. The LTIP initially limited the number of common units that may be delivered, pursuant to vested awards, to 800,000 common units. On January 1 of each calendar year occurring after the second anniversary of the effective date and prior to the expiration of the LTIP, the total number of common units reserved and available for issuance under the LTIP will increase by 200,000 common units. As of December 31, 2018, there were 403,855 common units reserved for issuance and 243,922 available for issuance. Phantom units have been granted as follows:
Phantom units have vested as follows:
The following table presents a summary of the status of the Partnership’s phantom unit awards subject to vesting:
The Partnership estimates the number of performance-based units that are probable to vest over the vesting period and records any change in such estimate as a cumulative adjustment to unit-based compensation expense calculated as if the new estimate had been in effect from the grant date. During the year ended December 31, 2018, the Partnership reduced its estimates of the number of performance-based phantom units expected to vest and as a result unit-based compensation for the year ended December 31, 2018 was $(0.9) million as compared to $2.2 million and $3.7 million, for the years ended December 31, 2017 and 2016, respectively. Unit-based compensation is included in selling, general and administrative expenses. Units issued under the Partnership’s 2013 LTIP are newly issued. Total unrecognized compensation cost related to the performance-based phantom units totaled $0.6 million as of December 31, 2018, which is expected to be recognized over a weighted average period of 24 months. Equity - Changes in Partnership's Units Pursuant to the terms of the partnership agreement, upon payment of the cash distribution on February 14, 2017, and meeting certain distribution and performance tests, the subordination period for the subordinated units expired on February 16, 2017. At the expiration of the subordination period, all subordinated units converted into common units on a one-for-one basis. The following table provides information with respect to changes in the Partnership’s unit:
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Earnings Per Unit |
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Earnings Per Share [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Unit |
Earnings per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income (loss), after deducting any incentive distributions, by the weighted average number of outstanding common and subordinated units. The Partnership’s net income is allocated to the limited partners in accordance with their respective ownership percentages, after giving effect to priority income allocations for incentive distributions, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the limited partners based on their respective ownership interests. Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income (loss) allocations used in the calculation of earnings per unit. In addition to the common and subordinated units, the Partnership has also identified the IDRs as participating securities and uses the two-class method when calculating the net income (loss) per unit applicable to limited partners, which is based on the weighted average number of common units outstanding during the period. Diluted earnings per unit includes the effects of potentially dilutive units on the Partnership’s common units, consisting of unvested phantom units. Basic and diluted earnings (losses) per unit applicable to subordinated limited partners are the same because there were no potentially dilutive subordinated units outstanding. The table below shows the weighted average common units outstanding used to compute net income per common unit for the periods indicated.
On February 16, 2017, all 10,071,970 subordinated units outstanding converted to common units on a one-for-one basis. The Partnership did not allocate any earnings or loss to the subordinated unitholders for the year ended December 31, 2017, since the subordinated units did not share in the distribution of cash generated during 2017. The following tables provide a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per unit during periods prior to the conversion of the subordinated units:
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Quarterly Financial Data (Unaudited) |
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Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Data (Unaudited) |
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Partnership Distributions |
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Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partnership Distributions |
The Partnership's partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders will receive. Payments made in connection with DERs are recorded as a distribution. Cash distributions for the periods indicated were as follows:
In addition, on January 23, 2019, the Partnership declared a cash distribution for the three months ended December 31, 2018, of $0.6675 per unit, totaling $17.2 million (including an IDR distribution of $2.1 million). Such distributions were paid on February 13, 2019, to unitholders of record on February 8, 2019. |
Description of Business and Summary of Significant Accounting Policies (Policies) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||
Basis of Presentation | Basis of Presentation The Consolidated Financial Statements include the accounts of the Partnership and its wholly-owned subsidiaries. Intercompany transactions between the Partnership and its subsidiaries have been eliminated. |
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Use of Estimates | Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and the reported net sales and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset and liability valuations as part of an acquisition, the fair value of derivative assets and liabilities, valuation of contingent consideration, valuation of reporting units within the goodwill impairment assessment, and if necessary long-lived asset impairments and environmental and legal obligations. |
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Revenue Recognition and Cost of Products Sold | Revenue Recognition and Cost of Products Sold Revenue is recognized when performance obligations under the terms of a contract with a customer are satisfied. The majority of the Partnership’s 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, the Partnership recognizes revenue for refined products and natural gas when title and risk of loss have been transferred to the customer which is generally at the time of shipment or delivery of products. Revenue for the Partnership’s 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 the Partnership expects 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 Partnership's 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). Estimated discounts are included in the transaction price of the contracts with customers as a reduction to net sales. Cash discounts were $7.7 million, $5.9 million and $3.7 million for the years ended December 31, 2018, 2017 and 2016, respectively. The Partnership sells its products or provides its services directly to commercial customers and wholesale distributors generally under agreements with payment terms typically less than 30 days. The Partnership has elected to 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). The Partnership has elected to exclude from net sales any value add, sales and other taxes which it collects concurrently with revenue-producing activities. These accounting policy elections are consistent with the way the Partnership historically recorded shipping and handling fees and taxes. The majority of the Partnership's revenue is derived from contracts (i) with an original expected length of one year or less and (ii) contracts for which it recognizes revenue at the amount in which it has the right to invoice the customer as product is delivered. The Partnership has elected the practical expedient not to disclose the value of remaining performance obligations associated with these types of contracts. |
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Commodity Derivatives | Commodity Derivatives The Partnership utilizes derivative instruments consisting of futures contracts, forward contracts, swaps, options and other derivatives individually or in combination, to mitigate its exposure to fluctuations in prices of refined petroleum products and natural gas. The use of these derivative instruments within the Partnership's risk management policy may, on a limited basis, generate gains or losses from changes in market prices. The Partnership enters into futures and over-the-counter (“OTC”) transactions either on regulated exchanges or in the OTC market. Futures contracts are exchange-traded contractual commitments to either receive or deliver a standard amount or value of a commodity at a specified future date and price, with some futures contracts based on cash settlement rather than a delivery requirement. Futures exchanges typically require margin deposits as security. OTC contracts, which may or may not require margin deposits as security, involve parties that have agreed either to exchange cash payments or deliver or receive the underlying commodity at a specified future date and price. The Partnership posts initial margin with futures transaction brokers, along with variation margin, which is paid or received on a daily basis, and is included in other current assets and other current liabilities. In addition, the Partnership may either pay or receive margin based upon exposure with counterparties. Payments made by the Partnership are included in other current assets, whereas payments received by the Partnership are included in accrued liabilities. Substantially all of the Partnership’s commodity derivative contracts outstanding as of December 31, 2018 will settle prior to June 30, 2020. The Partnership enters into some master netting arrangements to mitigate credit risk with significant counterparties. Master netting arrangements are standardized contracts that govern all specified transactions with the same counterparty and allow the Partnership to terminate all contracts upon occurrence of certain events, such as a counterparty’s default. The Partnership has elected not to offset the fair value of its derivatives, even where these arrangements provide the right to do so. The Partnership’s derivative instruments are recorded at fair value, with changes in fair value recognized in net income (loss) each period. The Partnership’s fair value measurements are determined using the market approach and includes non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Partnership’s credit is considered for payable balances. The Partnership does 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 the fair value of derivative instruments executed with the same counterparty under the same master netting arrangement. The Partnership had no right to reclaim or obligation to return cash collateral as of December 31, 2018 or 2017. |
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Interest Rate Derivatives | Interest Rate Derivatives The Partnership manages its exposure to variable LIBOR borrowings by using interest rate swaps to convert a portion of its variable rate debt to fixed rates. These interest rate swaps are designated as cash flow hedges and the effective portion of changes in fair value of the swaps are included as a component of comprehensive income (loss) and accumulated other comprehensive income (loss), net of tax. Any ineffective portion of the changes in fair value of the swaps is recorded in interest expense. To designate a derivative as a cash flow hedge, the Partnership documents at inception the assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. The assessment, updated at least quarterly, is based on the most recent relevant historical correlation between the derivative and the item hedged. If during the term of the derivative, the hedge is found to be less than highly effective, hedge accounting is prospectively discontinued and the remaining gains and losses are reclassified to income in the current period. |
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Market and Credit Risk | Market and Credit Risk The Partnership manages the risk fluctuations in the price and transportation costs of its commodities through the use of derivative instruments. The volatility of prices for energy commodities can be significantly influenced by market supply and demand, changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. The Partnership monitors and manages its exposure to market risk on a daily basis in accordance with approved policies. The Partnership has a number of financial instruments that are potentially at risk including cash and cash equivalents, receivables and derivative contracts. The Partnership’s primary exposure is credit risk related to its receivables and counterparty performance risk related to its derivative assets, which is the loss that may result from a customer’s or counterparty’s non-performance. The Partnership uses credit policies to control credit risk, including utilizing an established credit approval process, monitoring customer and counterparty limits, employing credit mitigation measures such as analyzing customer financial statements, and accepting personal guarantees and various forms of collateral. The Partnership believes that the counterparties to its derivative contracts will be able to satisfy their contractual obligations. Credit risk is limited by the large number of customers and counterparties comprising the Partnership’s business and their dispersion across different industries. The Partnership’s cash is in demand deposits placed with federally insured financial institutions. Such deposit accounts at times may exceed federally insured limits. The Partnership has not experienced any losses on such accounts. |
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Fair Value Measurements | Fair Value Measurements The Partnership determines 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 OTC derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Partnership utilizes fair value measurements based on Level 2 inputs for its 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. The Partnership utilizes fair value measurements based on Level 3 inputs for its contingent consideration obligation. |
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Long-Term Incentive Plan | Long-Term Incentive Plan The General Partner adopted the Sprague Resources LP 2013 Long-Term Incentive Plan (the “LTIP”), for the benefit of employees, consultants and directors of the General Partner and its affiliates, who provide services to the General Partner or an affiliate. The LTIP provides the Partnership with the flexibility to grant unit options, restricted units, phantom units, unit appreciation rights, cash awards, distribution equivalent rights, substitute awards and other unit-based awards or any combination of the foregoing. The LTIP will expire upon the earlier of (i) its termination by the board of directors of the General Partner, (ii) the date common units are no longer available under the LTIP for grants or (iii) the tenth anniversary of the date the LTIP was approved by the General Partner. The board of directors of the General Partner grants performance-based phantom unit awards to key employees that vest over a period of time (usually three years). Upon vesting, a holder of performance-based phantom units is entitled to receive a number of common units of the Partnership equal to a percentage (between 0 and 200%) of the phantom units granted, based on the Partnership’s achieving pre-determined performance criteria. The Partnership uses authorized but unissued units to satisfy its unit-based obligations. TUR-based Phantom Units Phantom unit awards granted through 2015 include a market condition criteria that considers the Partnership's total unitholder return ("TUR") over the three year vesting period, compared with the total unitholder return of a peer group of other master limited partnership energy companies over the same period. These awards are equity awards with both service and market-based conditions, which results in compensation cost being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market based conditions are satisfied. The fair value of the TUR based phantom units was estimated at the date of grant based on a Monte Carlo model that estimates the most likely performance outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership’s common units as of the valuation date, the historical volatility of the market price of the Partnership’s common units, the historical volatility of the market price of the common units or common stock of the peer companies and the correlation between changes in the market price of the Partnership’s common units and those of the peer companies. OCF-based Phantom Units Phantom unit awards granted since 2015 include a performance criteria that considers Sprague Holdings operating cash flow, as defined therein ("OCF"), over a three year performance period. The number of common units that may be received in settlement of each phantom unit award can range between 0 and 200% of the number of phantom units granted based on the level of OCF achieved during the vesting period. These awards are equity awards with performance and service conditions which result in compensation cost being recognized over the requisite service period once payment is determined to be probable. Compensation expense related to the OCF based awards is estimated each reporting period by multiplying the number of common units underlying such awards that, based on the Partnership's estimate of OCF, are probable to vest, by the grant-date fair value of the award and is recognized over the requisite service period using the straight-line method. The fair value of the OCF based phantom units was the grant date closing price listed on the New York Stock Exchange. The number of units that the Partnership estimates are probable to vest could change over the vesting period. Any such change in estimate is recognized as a cumulative adjustment calculated as if the new estimate had been in effect from the grant date. Distribution Equivalent Rights The Partnership's performance-based phantom unit awards include tandem distribution equivalent rights ("DERs") which entitle the participant to a cash payment only upon vesting that is equal to any cash distribution paid on a common unit between the grant date and the date the phantom units were settled. Payments made in connection with DERs are recorded as a distribution in unitholders' equity. |
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Earnings (Loss) Per Unit | Earnings (Loss) Per Unit The Partnership computes income (loss) per unit using the two-class method. Net income (loss) attributable to common unitholders and subordinated unitholders for purposes of the basic income (loss) per unit computation was allocated between the common unitholders and subordinated unitholders by applying the provisions of the partnership agreement. Under the two-class method, any excess of distributions declared over net income (loss) was allocated to the partners based on their respective sharing of income specified in the partnership agreement. Net income (loss) per unit was determined by dividing the net income (loss) allocated to the common unitholders and the subordinated unitholders under the two-class method by the number of common units and subordinated units outstanding in the period. As previously noted, on February 16, 2017, based upon meeting certain distribution and performance tests provided in the Partnership's partnership agreement, all 10,071,970 subordinated units outstanding converted to common units on a one-for-one basis. As discussed in Note 21 - Earnings Per Unit, there was no allocation between the common unitholders and subordinated unitholders for the year ended December 31, 2017 since all subordinated units outstanding were converted to common units on February 16, 2017, and the subordinated units did not share in any distribution of cash generated during 2017. |
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Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash and highly liquid investments which are readily convertible into cash and have maturities of three months or less when purchased. |
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Inventories | Inventories The Partnership’s inventories are valued at the lower of cost or net realizable value. Cost is primarily determined using the first-in, first-out method, except for the Partnership's Canadian subsidiary, which used the weighted average method. Inventory consists of petroleum products, natural gas and coal. The Partnership uses derivative instruments, primarily futures, forwards and swaps, to economically hedge substantially all of its inventory. |
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Property, Plant and Equipment, Net | Property, Plant and Equipment, Net Property, plant and equipment, net are recorded at historical cost. Depreciation is computed on a straight-line basis over the following estimated useful lives:
Leasehold improvements are amortized over the term of the lease or the estimated useful life of the improvement, whichever is shorter. Maintenance and repairs are charged to expense as incurred. Costs and related accumulated depreciation of properties sold or otherwise disposed of are removed from the respective accounts, and any resulting gains or losses are recorded at that time |
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Long-lived Asset Impairment | Long-lived Asset Impairment The Partnership evaluates the carrying value of its property, plant and equipment and finite lived intangible assets for impairment when events or changes in circumstances indicate the carrying amount of an individual asset or asset group may not be recoverable based on estimated future undiscounted cash flows. Future cash flow projections include assumptions of future sales levels, the impact of controllable cost reduction programs, and the level of working capital needed to support each business. To the extent the carrying amount of the asset group is not recoverable based on undiscounted cash flows, the amount of impairment is measured by the difference between the carrying value and the fair value of the individual assets or asset group. |
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Purchase Price Allocation | Purchase Price Allocation The cost of an acquired entity is allocated to the assets acquired and liabilities assumed based on their respective fair values at the date of acquisition. Property, plant and equipment and goodwill generally represent large components of these acquisitions. In addition to goodwill, intangible assets acquired generally include customer relationships and non-compete agreements. Goodwill is calculated as the excess of the cost of the acquired entity over the net of the fair value of the assets acquired and the liabilities assumed. For all material acquisitions the Partnership determines the fair value of the assets acquired and liabilities assumed, including goodwill, based on recognized business valuation methodologies. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired or liabilities assumed. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, based on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. For contingent consideration arrangements, a liability is recognized at fair value as of the acquisition date with subsequent fair value adjustments recorded in operations. Additional information regarding the Partnership's contingent consideration arrangements may be found in Note 3 - Business Combinations, Note 14 - Other Obligations and Note 18 - Financial Instruments and Off-Balance Sheet Risk. Other assets acquired and liabilities assumed typically include, but are not limited to, inventory, accounts receivable, accounts payable and other working capital items. Because of their short-term nature, the fair values of these other assets and liabilities generally approximate the book values on the acquired entity’s balance sheet. |
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Goodwill | Goodwill Goodwill is not amortized but tested for impairment at the reporting unit level, at least annually (as of October 31 each year), by determining the fair value of the reporting unit and comparing it to its carrying value, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, the Partnership will determine if there is a potential impairment by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than the carrying amount, an impairment loss would be reported. The Partnership assesses the fair value of its reporting units based on a discounted cash flow valuation model (Level 3 measurement). The key assumptions used are discount rates and growth rates, applied to cash flow projections. These assumptions contemplate business, market and overall economic conditions. After applying the discounted cash flow methods to measure the fair value of its reporting units, including the consideration of reasonably likely adverse changes in the rates and assumptions described above, the Partnership determined that there have been no goodwill impairments to date. In performing the discounted cash flow analysis, the Partnership also used a range of discount rate assumptions to evaluate the sensitivity on the fair values resulting from the discounted cash flow valuation. |
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Intangibles, Net | Intangibles, Net Intangibles, net consist of intangible assets with finite lives, primarily customer relationships and non-compete agreements. Intangibles and other assets are amortized over their respective estimated useful lives. The Partnership believes the sum-of-the-years’-digits method of amortization properly reflects the timing of the recognition of the economic benefits realized from its intangible assets. |
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Income Taxes | Income Taxes The Partnership is organized as a pass-through entity for U.S. federal income tax purposes. As a result, the partners are responsible for U.S. federal income taxes based on their respective share of taxable income. Net income (loss) for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. The Partnership, however, is subject to a statutory requirement that non-qualifying income cannot exceed 10% of total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of non-qualifying income exceeds this statutory limit, the Partnership would be taxed as a corporation. Accordingly, certain activities that generate non-qualifying income are conducted through Sprague Energy Solutions, Inc., a taxable corporate subsidiary. Sprague Energy Solutions, Inc. is subject to U.S. federal and state income tax and pays any income taxes related to the results of its operations. For the year ended December 31, 2018, the Partnership’s non-qualifying income did not exceed the statutory limit. The Partnership is subject to income tax and franchise tax in certain domestic state and local as well as foreign jurisdictions. Income taxes (e.g., deferred tax assets, deferred tax liabilities, taxes currently payable and tax expense) are recorded based on amounts refundable or payable in the current year and include the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred taxes are measured by applying currently enacted tax rates. The Partnership establishes a valuation allowance for deferred tax assets when it is more likely than not that these assets will not be realized. The Partnership's Canadian operations are conducted within entities that are treated as corporations for Canadian tax purposes and are subject to Canadian federal and provincial taxes. Additionally, payments of dividends from the Partnership's Canadian entities to other Sprague entities are subject to Canadian withholding tax that is treated as income tax expense. The partnership's foreign subsidiaries record investment tax credits under the deferral method. The Partnership recognizes the financial statement effect of an uncertain tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. The Partnership classifies interest and penalties associated with uncertain tax positions as income tax expense. During the years ended December 31, 2018, 2017 and 2016, the interest and penalties recognized by the Partnership were immaterial. The Partnership and its subsidiaries tax returns are subject to examination by the Internal Revenue Service and by the Canada Revenue Agency for the years ended December 31, 2017, 2016 and 2015. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since the operations of the Partnership are generally not subject to federal income tax, the Tax Act has not had a material impact to the Partnership. |
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Foreign Currency | Foreign Currency The Partnership’s reporting currency is the U.S. dollar. The Partnership's most significant foreign operations are conducted by Kildair, a Canadian subsidiary. The functional currency of Kildair is the U.S. dollar. Kildair has an operating subsidiary whose functional currency is the Canadian 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. |
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Recent Accounting Pronouncements | Recent Accounting Pronouncements In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities. The objective of the guidance is to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership anticipates that the adoption of this ASU in 2019 will not have a material impact to the Partnership's consolidated financial statements. In January 2017, the FASB issued ASU 2017-04 Intangibles - Goodwill and Other (Topic 350): Simplifying the Accounting for Goodwill Impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The standard will be applied prospectively, and is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for any impairment tests performed after January 1, 2017. In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805), which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of this new guidance in 2018 did not have an impact on the Partnership's consolidated financial statements. In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. The adoption of this new guidance in 2018 did not have an impact on the Partnership's consolidated statement of cash flows. In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842), which, among other things, requires lessees to recognize an obligation to make lease payments arising from a lease, measured on a discounted basis, and a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Expenses are recognized in the consolidated statement of operations in a manner similar to current accounting guidance. The Partnership expects to make an accounting policy election to not recognize an asset and liability for leases with a term of twelve months or less. Under the new guidance, lessor accounting is largely unchanged. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Partnership will adopt the accounting standard using a modified retrospective approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Partnership is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $20 million of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which revises the principles of revenue recognition from one based on the transfer of risks and rewards to when a customer obtains control of a good or service. The FASB has issued several ASUs subsequent to ASU 2014-09 in order to clarify implementation guidance but did not change the core principle of the guidance in Topic 606. These ASUs are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The adoption of this standard in 2018 did not have a material impact on the Partnership's consolidated financial statements nor result in significant changes to business processes, systems, or internal controls. |
Description of Business and Summary of Significant Accounting Policies (Tables) |
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Dec. 31, 2018 | |||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||
Schedule of Estimated Useful Lives of Property Plant and Equipment | Property, plant and equipment, net are recorded at historical cost. Depreciation is computed on a straight-line basis over the following estimated useful lives:
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Revenue (Tables) |
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disaggregation of Revenue | Further disaggregation of net sales by business segment and geographic destination is as follows:
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Business Combinations (Tables) |
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value of Assets and Acquired and Liabilities Assumed | The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The following table summarizes the fair values of the assets acquired and liabilities assumed:
The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
The following table summarizes the fair values of the assets acquired and liabilities assumed at the acquisition date:
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Summary of Business Combination Pro Forma Information | Following is the unaudited pro forma consolidated net sales and net income as if the businesses acquired during the year ended December 31, 2017 had been included in the consolidated results of the Partnership for the twelve months ended December 31, 2017 and 2016:
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Accumulated Other Comprehensive Loss, Net of Tax (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Other Comprehensive Loss, Net of Tax | Amounts included in accumulated other comprehensive loss, net of tax, consisted of the following:
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Accounts Receivable, Net (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accounts Receivable, Net |
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Reconciliation of Beginning and Ending Amount of Allowance for Doubtful Accounts | A reconciliation of the beginning and ending amount of allowance for doubtful accounts follows:
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Inventories (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventory Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Inventories |
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Other Current Assets (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Other Current Assets |
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Property, Plant and Equipment, Net (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Property, Plant and Equipment, Net |
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Schedule of Property, Plant and Equipment Include Amounts for Capital Leases | Property, plant and equipment include the following amounts under capital leases:
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Intangibles, Net (Tables) |
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Intangible Assets Useful Life and Amortization |
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Other Assets, Net (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Other Assets, Net |
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Accrued Liabilities (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Payables and Accruals [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accrued Liabilities |
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Credit Agreement (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Credit Agreements |
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Other Obligations (Tables) |
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Other Liabilities |
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Summary of Deferred Consideration | Deferred consideration obligation maturities for each of the next five years and thereafter as of December 31, 2018 are as follow:
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Schedule of Change in Asset Retirement Obligation | The changes in the ARO are as follows:
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Income Taxes (Tables) |
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Income Tax Provision (Benefit) Attributable to Operations | The income tax provision (benefit) attributable to operations is summarized as follows:
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Components of Income (Loss) Before Income Taxes and Equity in Net Loss of Foreign Affiliate | U.S. and international components of income before income taxes were as follows:
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Schedule of Reconciliations of Statutory U.S. Federal Income Tax to Effective Income Tax for Operations | Reconciliations of the statutory U.S. federal income tax to the effective income tax for operations are as follows:
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Schedule of Components of Deferred Tax Assets (Liabilities) | The components of the deferred tax assets (liabilities) were as follows:
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Segment Reporting (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Financial Information for Partnership's Reportable Segments | Summarized financial information for the Partnership’s reportable segments is presented in the table below:
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Summary of Changes in Carrying Amount of Goodwill by Segment | Changes in the carrying amount of goodwill by segment were as follows:
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Summary of Long-Lived Assets (Exclusive of Intangible and Other Assets, Net and Goodwill) Classified by Geographic Location | Long-lived assets (exclusive of intangible and other assets, net, and goodwill) classified by geographic location were as follows:
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Financial Instruments and Off-Balance Sheet Risk (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Financial Assets and Liabilities | The following table presents all financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis:
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Offsetting Liabilities | Information related to these offsetting arrangements as of December 31, 2018 and 2017 is as follows:
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Offsetting Assets | Information related to these offsetting arrangements as of December 31, 2018 and 2017 is as follows:
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Summary of Realized and Unrealized (Losses) and Gains on Derivative Instruments for Commodity Risk Management | The following table presents total realized and unrealized gains (losses) on derivative instruments utilized for commodity risk management purposes included in cost of products sold (exclusive of depreciation and amortization):
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Gross Volume of Commodity Derivative Instruments | The following table presents the gross volume of commodity derivative instruments outstanding for the periods indicated:
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Schedule of Interest Rate Swaps Notional Amount | The Partnership's interest rate swap agreements outstanding as of December 31, 2018 were as follows:
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Summary of Liabilities Measured on a Recurring Basis, Unobservable Input Reconciliation, | Changes in the contingent consideration liability measured at fair value on a recurring basis using unobservable inputs (Level 3) are as follows:
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Commitments and Contingencies (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||
Schedule of Future Annual Payments for Operating Leases | The following table summarizes the future minimum payments for the following five fiscal years for operating lease obligations as of December 31, 2018 with non-cancellable lease terms of one year or more:
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Equity and Equity-Based Compensation (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Partnership's Unit Awards Subject to Vesting | The following table presents a summary of the status of the Partnership’s phantom unit awards subject to vesting:
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Schedule of Changes in Partnership's Units | The following table provides information with respect to changes in the Partnership’s unit:
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Earnings Per Unit (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Weighted Average Common Units Outstanding | The table below shows the weighted average common units outstanding used to compute net income per common unit for the periods indicated.
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Schedule of Partnership's Basic Earnings (Loss) Per Common and Subordinated Unit | The following tables provide a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per unit during periods prior to the conversion of the subordinated units:
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Quarterly Financial Data (Unaudited) (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Quarterly Financial Data |
|
Partnership Distributions (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Cash Distributions Made to Limited Partners | The Partnership's partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders will receive. Payments made in connection with DERs are recorded as a distribution. Cash distributions for the periods indicated were as follows:
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Description of Business and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Property Plant and Equipment (Detail) |
12 Months Ended |
---|---|
Dec. 31, 2018 | |
Minimum | Furniture and Fixtures | |
Property, Plant and Equipment [Line Items] | |
Property, plant and equipment, useful life | 5 years |
Minimum | Plant and Machinery | |
Property, Plant and Equipment [Line Items] | |
Property, plant and equipment, useful life | 5 years |
Minimum | Building and Leasehold Improvements | |
Property, Plant and Equipment [Line Items] | |
Property, plant and equipment, useful life | 10 years |
Maximum | Furniture and Fixtures | |
Property, Plant and Equipment [Line Items] | |
Property, plant and equipment, useful life | 10 years |
Maximum | Plant and Machinery | |
Property, Plant and Equipment [Line Items] | |
Property, plant and equipment, useful life | 30 years |
Maximum | Building and Leasehold Improvements | |
Property, Plant and Equipment [Line Items] | |
Property, plant and equipment, useful life | 25 years |
Revenue - Narrative (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Revenue from Contract with Customer [Abstract] | ||
Customer prepayments and deposits | $ 9,846 | $ 8,178 |
Business Combinations - Summary of Proforma Information (Details) - USD ($) $ / shares in Units, $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Business Acquisition [Line Items] | ||
Net sales | $ 2,957,205 | $ 2,590,663 |
Net income | $ 29,431 | $ 4,216 |
Net income per limited partner common unit-basic (in dollars per share) | $ 1.15 | $ 0.12 |
Net income per limited partner common unit-diluted (in dollars per share) | $ 1.13 | $ 0.11 |
Limited Partner | ||
Business Acquisition [Line Items] | ||
Net income | $ 25,438 | $ 2,474 |
Accumulated Other Comprehensive Loss, Net of Tax - Schedule of Accumulated Other Comprehensive Loss, Net of Tax (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|---|---|
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Partners' capital | $ 136,976 | $ 131,834 | $ 125,437 | $ 157,485 |
AOCI Attributable to Parent | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Partners' capital | (11,522) | (8,870) | $ (10,783) | $ (11,639) |
Accumulated Foreign Currency Adjustment Attributable to Parent | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Partners' capital | (11,698) | (11,458) | ||
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Partners' capital | $ 176 | $ 2,588 |
Accounts Receivable, Net - Schedule of Accounts Receivable, Net (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Receivables [Abstract] | ||
Accounts receivable, trade | $ 262,912 | $ 310,800 |
Less allowance for doubtful accounts | (2,066) | (2,014) |
Net accounts receivable, trade | 260,846 | 308,786 |
Accounts receivable, other | 9,062 | 7,827 |
Accounts receivable, net | $ 269,908 | $ 316,613 |
Accounts Receivable, Net - Additional Information (Detail) - USD ($) $ in Millions |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Receivables [Abstract] | ||
Unbilled accounts receivable | $ 50.5 | $ 81.6 |
Inventories - Schedule of Inventories (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Inventory [Line Items] | ||
Inventories | $ 259,568 | $ 335,859 |
Petroleum and related products | ||
Inventory [Line Items] | ||
Inventories | 253,385 | 329,712 |
Coal | ||
Inventory [Line Items] | ||
Inventories | 2,566 | 3,712 |
Natural gas | ||
Inventory [Line Items] | ||
Inventories | $ 3,617 | $ 2,435 |
Inventories - Additional Information (Detail) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Petroleum, Natural Gas and Asphalt Inventory | |||
Public Utilities, Inventory [Line Items] | |||
Provision for inventory write-down | $ 24.3 | $ 0.4 | $ 1.7 |
Other Current Assets - Schedule of Other Current Assets (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Margin deposits with brokers | $ 827 | $ 29,321 |
Prepaid software & fees | 5,627 | 7,200 |
Natural gas transportation | 0 | 1,056 |
Other | 2,434 | 2,369 |
Other current assets | $ 8,888 | $ 39,946 |
Property, Plant and Equipment, Net - Schedule of Property, Plant and Equipment, Net (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 532,719 | $ 513,061 |
Less: accumulated depreciation | (182,873) | (163,002) |
Property, plant and equipment, net | 349,846 | 350,059 |
Plant, machinery, furniture and fixtures | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 416,398 | 401,092 |
Building and leasehold improvements | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 19,159 | 18,631 |
Land and land improvements | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 87,854 | 86,758 |
Construction in progress | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 9,308 | $ 6,580 |
Property, Plant and Equipment, Net - Additional Information (Detail) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Property, Plant and Equipment [Abstract] | |||
Depreciation expense | $ 21.5 | $ 18.3 | $ 16.0 |
Amortization expense on capital leased assets | $ 1.5 | $ 1.6 | $ 1.5 |
Property, Plant and Equipment, Net - Schedule of Property, Plant and Equipment Include Amounts for Capital Leases (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 22,444 | $ 18,344 |
Less: accumulated amortization | (9,849) | (9,117) |
Property, plant and equipment, net | 12,595 | 9,227 |
Plant, machinery, furniture and fixtures | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 21,231 | 17,131 |
Building and leasehold improvements | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 962 | 962 |
Land and land improvements | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 251 | $ 251 |
Intangibles, Net - Additional Information (Detail) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Finite-Lived Intangible Assets [Line Items] | |||
Intangible assets, amortization expense | $ 11.9 | $ 9.8 | $ 5.2 |
Intangible assets acquired | 58.2 | ||
Estimated future annual amortization expense of intangible assets, 2019 | 10.3 | ||
Estimated future annual amortization expense of intangible assets, 2020 | 8.7 | ||
Estimated future annual amortization expense of intangible assets, 2021 | 7.2 | ||
Estimated future annual amortization expense of intangible assets, 2022 | 5.8 | ||
Estimated future annual amortization expense of intangible assets, 2023 | $ 4.8 | ||
Customer relationships | |||
Finite-Lived Intangible Assets [Line Items] | |||
Intangible assets acquired | 47.9 | ||
Non-compete agreements | |||
Finite-Lived Intangible Assets [Line Items] | |||
Intangible assets acquired | 9.5 | ||
Other | |||
Finite-Lived Intangible Assets [Line Items] | |||
Intangible assets acquired | $ 0.8 |
Other Assets, Net - Schedule of Other Assets, Net (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Deferred debt issuance costs, net | $ 8,335 | $ 11,625 |
Natural gas transportation, long-term portion | 0 | 37 |
Other | 359 | 356 |
Other assets, net | $ 8,694 | $ 12,018 |
Other Assets, Net - Additional Information (Detail) - USD ($) $ in Thousands |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Feb. 01, 2016 |
|
Indefinite-lived Intangible Assets [Line Items] | ||||
Amortization expense related to deferred debt issuance costs | $ 3,500 | $ 5,200 | $ 4,000 | |
Write-off of debt issuance costs | 1,600 | |||
Cost of products sold of natural gas transportation assets | 3,445,385 | 2,602,788 | 2,179,089 | |
Natural gas | ||||
Indefinite-lived Intangible Assets [Line Items] | ||||
Provision for inventory write-down | 300 | 1,600 | ||
Global Natural Gas & Power | ||||
Indefinite-lived Intangible Assets [Line Items] | ||||
Natural gas transportation assets | 1,100 | |||
Natural gas transportation liabilities | 600 | |||
Santa Buckley Energy, Inc. (SBE) | ||||
Indefinite-lived Intangible Assets [Line Items] | ||||
Natural gas transportation assets | 8,000 | $ 8,040 | ||
Natural gas transportation liabilities | 2,400 | |||
Product | Natural gas | ||||
Indefinite-lived Intangible Assets [Line Items] | ||||
Cost of products sold of natural gas transportation assets | $ 500 | $ 1,800 | $ 6,500 |
Accrued Liabilities - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Payables and Accruals [Abstract] | ||
Margin deposits from brokers | $ 28,529 | $ 0 |
Customer prepayments and deposits | 9,846 | 8,178 |
Accrued product taxes | 9,830 | 9,783 |
Accrued product costs | 6,310 | 11,517 |
Other | 11,444 | 19,560 |
Other current liabilities | $ 65,959 | $ 49,038 |
Credit Agreement - Schedule of Debt (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Line of Credit Facility [Line Items] | ||
Credit Agreements | $ 661,098 | $ 725,350 |
Less: current portion of working capital facilities | (154,318) | (275,613) |
Total long-term portion | 506,780 | 449,737 |
Working capital facilities | ||
Line of Credit Facility [Line Items] | ||
Credit Agreements | 284,998 | 341,850 |
Total long-term portion | 130,680 | 66,237 |
Acquisition facility | ||
Line of Credit Facility [Line Items] | ||
Credit Agreements | 376,100 | 383,500 |
Total long-term portion | $ 376,100 | $ 383,500 |
Related Party Transactions - Additional Information (Detail) - General Partner - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Related Party Transaction [Line Items] | |||
Reimbursement of employees related benefits expenses and other costs | $ 111.8 | $ 97.3 | $ 90.3 |
Due to general partners | $ 9.8 | $ 12.9 |
Other Obligations - Schedule of Other Liabilities (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Other Liabilities Disclosure [Abstract] | ||
Deferred consideration | $ 21,779 | $ 23,966 |
Contingent consideration | 6,532 | 7,855 |
Port Authority terminal obligations | 6,365 | 7,056 |
Asset retirement obligation | 3,481 | 3,789 |
Postretirement benefits | 2,160 | 2,412 |
Other | 6,138 | 4,547 |
Other obligations, long-term portion | $ 46,455 | $ 49,625 |
Other Obligations - Summary of Deferred Consideration Maturity (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Other Liabilities Disclosure [Abstract] | ||
2019 | $ 3,818 | |
2020 | 3,818 | |
2021 | 3,818 | |
2022 | 3,818 | |
2023 | 3,818 | |
Thereafter | 12,730 | |
Total | 31,820 | |
Less amount representing interest | (7,854) | |
Present value of payments | 23,966 | |
Less current portion | (2,187) | |
Deferred consideration | $ 21,779 | $ 23,966 |
Other Obligations - Summary of Change in Asset Retirement Obligation (Details) - USD ($) $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
ARO - beginning of period | $ 4,490 | $ 0 |
Accrue fair value of ARO | 0 | 3,662 |
Change in estimates | (139) | 785 |
Accretion expense | 92 | 63 |
Retirement of ARO | (462) | (20) |
ARO - end of period | 3,981 | 4,490 |
Asset retirement obligation, current | (500) | (701) |
Asset retirement obligations, noncurrent | $ 3,481 | $ 3,789 |
Income Taxes - Schedule of Income Tax Provision (Benefit) Attributable to Operations (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Current | |||
U.S. Federal income tax | $ 118 | $ 120 | $ 229 |
State and local income tax | 95 | 231 | 1,199 |
Foreign income taxes | 4,742 | 2,614 | 293 |
Total current income tax provision | 4,955 | 2,965 | 1,721 |
Deferred | |||
U.S. Federal income tax | 5 | 3 | (9) |
State and local income tax | 567 | (188) | (388) |
Foreign income taxes | (495) | 1,042 | 784 |
Total deferred income tax provision | 77 | 857 | 387 |
Total income tax provision | $ 5,032 | $ 3,822 | $ 2,108 |
Income Taxes - Components of Income (Loss) Before Income Taxes and Equity in Net Loss of Foreign Affiliate (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Income Tax Disclosure [Abstract] | |||
United States | $ 69,283 | $ 18,517 | $ 8,385 |
Foreign | 15,568 | 14,802 | 3,889 |
Income before income taxes | $ 84,851 | $ 33,319 | $ 12,274 |
Income Taxes - Schedule of Reconciliations of Statutory U.S. Federal Income Tax to Effective Income Tax for Operations (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Income Tax Disclosure [Abstract] | |||
Statutory U.S. Federal income tax | $ 17,819 | $ 11,661 | $ 4,296 |
Partnership income not subject to tax | (14,427) | (6,360) | (2,691) |
State and local income taxes, net of federal tax | 662 | 46 | 787 |
Foreign earnings taxed at higher (lower) rates | 978 | (1,525) | (284) |
Total income tax provision | $ 5,032 | $ 3,822 | $ 2,108 |
Income Taxes - Schedule of Components of Deferred Tax Assets (Liabilities) (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Deferred tax assets (liabilities) | ||
Depreciation and amortization | $ (17,845) | $ (18,065) |
Other differences, net | 545 | 908 |
Valuation allowance | (466) | (466) |
Net deferred tax liabilities | $ (17,766) | $ (17,623) |
Income Taxes - Additional Information (Detail) - Canada - USD ($) $ in Millions |
Dec. 31, 2018 |
Dec. 31, 2016 |
---|---|---|
Income Taxes [Line Items] | ||
Foreign net operating loss carryforwards | $ 7.0 | |
Accumulated earnings subject to deferred withholding tax | $ 41.2 | |
Unrecognized deferred withholding tax liability | $ 10.3 |
Retirement Plans - Additional Information (Detail) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Postemployment Benefits [Abstract] | |||
Pension cost | $ 1.1 | $ 1.1 | $ 1.0 |
Defined contribution plan, Partnership contributions | 5.4 | 5.0 | 4.5 |
Expenses related to other postretirement benefits | $ 0.3 | $ 0.3 | $ 0.3 |
Segment Reporting - Additional Information (Detail) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018
USD ($)
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Sep. 30, 2018
USD ($)
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Jun. 30, 2018
USD ($)
|
Mar. 31, 2018
USD ($)
|
Dec. 31, 2017
USD ($)
|
Sep. 30, 2017
USD ($)
|
Jun. 30, 2017
USD ($)
|
Mar. 31, 2017
USD ($)
|
Dec. 31, 2018
USD ($)
segment
operating_unit
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Dec. 31, 2017
USD ($)
|
Dec. 31, 2016
USD ($)
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|
Segment Reporting Information [Line Items] | |||||||||||
Number of reporting segments | segment | 4 | ||||||||||
Foreign sales | $ 1,079,874 | $ 618,455 | $ 741,656 | $ 1,331,148 | $ 932,170 | $ 491,393 | $ 513,626 | $ 917,807 | $ 3,771,133 | $ 2,854,996 | $ 2,389,998 |
Assets | 1,245,240 | $ 1,362,985 | 1,245,240 | 1,362,985 | |||||||
Canada | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Foreign sales | $ 290,400 | 265,700 | 196,400 | ||||||||
Refined products | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of operating units | operating_unit | 3 | ||||||||||
Foreign sales | $ 3,357,769 | 2,455,577 | 1,988,597 | ||||||||
Natural gas | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of operating units | operating_unit | 1 | ||||||||||
Foreign sales | $ 332,038 | 331,669 | 334,003 | ||||||||
Assets | $ 0 | $ 0 | |||||||||
Materials handling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of operating units | operating_unit | 2 | ||||||||||
Foreign sales | $ 57,509 | 46,513 | 45,734 | ||||||||
Other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of operating units | operating_unit | 2 | ||||||||||
Foreign sales | $ 23,817 | $ 21,237 | $ 21,664 |
Segment Reporting - Summary of Financial Information for Partnership's Reportable Segments (Detail) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 |
Sep. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Net Sales | |||||||||||
Net sales | $ 1,079,874 | $ 618,455 | $ 741,656 | $ 1,331,148 | $ 932,170 | $ 491,393 | $ 513,626 | $ 917,807 | $ 3,771,133 | $ 2,854,996 | $ 2,389,998 |
Adjusted gross margin: | |||||||||||
Adjusted gross margin | 273,674 | 261,697 | 259,273 | ||||||||
Operating costs and expenses not allocated to operating segments: | |||||||||||
Operating expenses | 88,659 | 72,284 | 65,882 | ||||||||
Selling, general and administrative | 80,799 | 87,582 | 84,257 | ||||||||
Depreciation and amortization | 33,378 | 28,125 | 21,237 | ||||||||
Operating income | 122,912 | 64,217 | 39,533 | ||||||||
Other income (expense) | 293 | 108 | (114) | ||||||||
Interest income | 577 | 339 | 388 | ||||||||
Interest expense | (38,931) | (31,345) | (27,533) | ||||||||
Income tax provision | (5,032) | (3,822) | (2,108) | ||||||||
Net income | $ 36,527 | $ (18,434) | $ (13,195) | $ 74,921 | $ (12,894) | $ (14,316) | $ (7,792) | $ 64,499 | 79,819 | 29,497 | 10,166 |
Refined products | |||||||||||
Net Sales | |||||||||||
Net sales | 3,357,769 | 2,455,577 | 1,988,597 | ||||||||
Adjusted gross margin: | |||||||||||
Adjusted gross margin | 150,965 | 142,467 | 142,581 | ||||||||
Natural gas | |||||||||||
Net Sales | |||||||||||
Net sales | 332,038 | 331,669 | 334,003 | ||||||||
Adjusted gross margin: | |||||||||||
Adjusted gross margin | 57,875 | 65,060 | 62,435 | ||||||||
Materials handling | |||||||||||
Net Sales | |||||||||||
Net sales | 57,509 | 46,513 | 45,734 | ||||||||
Adjusted gross margin: | |||||||||||
Adjusted gross margin | 57,515 | 46,512 | 45,712 | ||||||||
Other | |||||||||||
Net Sales | |||||||||||
Net sales | 23,817 | 21,237 | 21,664 | ||||||||
Adjusted gross margin: | |||||||||||
Adjusted gross margin | 7,319 | 7,658 | 8,545 | ||||||||
Segment Reconciling Items | |||||||||||
Reconciliation to operating income: | |||||||||||
Add: unrealized gain (loss) on inventory derivatives | 32,960 | (124) | (31,304) | ||||||||
Add: unrealized gas (loss) on prepaid forward contract derivatives | 0 | 1,076 | 1,552 | ||||||||
Add: unrealized gain (loss) on natural gas transportation contracts | 19,114 | (10,441) | (18,612) | ||||||||
Operating costs and expenses not allocated to operating segments: | |||||||||||
Operating expenses | (88,659) | (72,284) | (65,882) | ||||||||
Selling, general and administrative | (80,799) | (87,582) | (84,257) | ||||||||
Depreciation and amortization | $ (33,378) | $ (28,125) | $ (21,237) |
Segment Reporting - Summary of Changes in Carrying Amount of Goodwill by Segment (Detail) - USD ($) $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | $ 115,037 | $ 70,550 |
Goodwill, activity | 0 | 44,487 |
Goodwill, Ending Balance | 115,037 | 115,037 |
Refined products | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 71,445 | 36,550 |
Goodwill, activity | 0 | 34,895 |
Goodwill, Ending Balance | 71,445 | 71,445 |
Natural gas | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 35,480 | 25,888 |
Goodwill, activity | 0 | 9,592 |
Goodwill, Ending Balance | 35,480 | 35,480 |
Materials handling | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 6,896 | 6,896 |
Goodwill, activity | 0 | 0 |
Goodwill, Ending Balance | 6,896 | 6,896 |
Other | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 1,216 | 1,216 |
Goodwill, activity | 0 | 0 |
Goodwill, Ending Balance | $ 1,216 | $ 1,216 |
Segment Reporting - Summary of Long-Lived Assets (Exclusive of Intangible and Other Assets, Net and Goodwill) Classified by Geographic Location (Detail) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Long-lived assets | $ 349,846 | $ 350,059 |
United States | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Long-lived assets | 277,405 | 273,374 |
Canada | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Long-lived assets | $ 72,441 | $ 76,685 |
Financial Instruments and Off-Balance Sheet Risk - Summary of Realized and Unrealized (Losses) and Gains on Derivative Instruments for Commodity Risk Management (Detail) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Realized and unrealized (losses) and gains on derivative instruments | $ 53,263 | $ 11,301 | $ (18,163) |
Refined products contracts | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Realized and unrealized (losses) and gains on derivative instruments | 54,616 | 12,856 | (25,316) |
Natural gas contracts | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Realized and unrealized (losses) and gains on derivative instruments | $ (1,353) | $ (1,555) | $ 7,153 |
Financial Instruments and Off-Balance Sheet Risk - Schedule of Gross Volume of Commodity Derivative Instruments Outstanding (Detail) bbl in Thousands, MMBTU in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2018
MMBTU
bbl
|
Dec. 31, 2017
MMBTU
bbl
|
|
Long contracts | Refined products contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Refined products, barrels | bbl | 8,796 | 9,255 |
Long contracts | Natural gas contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Natural Gas (MMBTU's) | MMBTU | 132,030 | 133,532 |
Short contracts | Refined products contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Refined products, barrels | bbl | 12,379 | 13,487 |
Short contracts | Natural gas contracts | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Natural Gas (MMBTU's) | MMBTU | 72,223 | 72,074 |
Financial Instruments and Off-Balance Sheet Risk - Interest Rate Derivatives - Notional Amounts (Details) - Designated as Hedging Instrument - Cash Flow Hedging |
Dec. 31, 2018
USD ($)
|
---|---|
Interest Rate Swaps Ending January 2018 | |
Derivative [Line Items] | |
Notional amount | $ 275,000,000 |
Interest Rate Swaps Ending January 2019 | |
Derivative [Line Items] | |
Notional amount | 300,000,000 |
Interest Rate Swaps Ending January 2020 | |
Derivative [Line Items] | |
Notional amount | 300,000,000 |
Interest Rate Swaps Ending January 2021 | |
Derivative [Line Items] | |
Notional amount | 300,000,000 |
Interest Rate Swaps Ending January 2022 | |
Derivative [Line Items] | |
Notional amount | $ 250,000,000 |
Financial Instruments and Off-Balance Sheet Risk Financial Instruments and Off-Balance Sheet Risk - Level 3 Liabilities Reconciliation (Details) - Significant Unobservable Inputs Level 3 - Business Combination, Contingent Consideration - USD ($) $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Contingent consideration - beginning of period | $ 9,725 | $ 0 |
Accrued contingent consideration | 0 | 9,557 |
Payments | (2,000) | 0 |
Change in estimated fair value | 677 | 168 |
Contingent consideration - end of period | 8,402 | 9,725 |
Less current portion | (1,870) | (1,870) |
Contingent consideration - long-term portion | $ 6,532 | $ 7,855 |
Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Sep. 30, 2018 |
|
Commitments and Contingencies Disclosure [Abstract] | ||||
Operating leases, rental expense | $ 21.1 | $ 20.1 | $ 21.9 | |
Import tax, penalty, and interest | $ 3.5 | |||
Import tax assessment, amount | $ 8.2 |
Commitments and Contingencies - Schedule of Future Annual Payments for Operating Leases (Detail) $ in Thousands |
Dec. 31, 2018
USD ($)
|
---|---|
Commitments and Contingencies Disclosure [Abstract] | |
2019 | $ 9,485 |
2020 | 5,816 |
2021 | 5,884 |
2022 | 2,943 |
2023 | $ 588 |
Earnings Per Unit - Additional Information (Detail) |
12 Months Ended | |
---|---|---|
Feb. 16, 2017
shares
|
Dec. 31, 2018
shares
|
|
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Subordinated units, conversion ratio | 1 | 1 |
Subordinated Units | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Potentially dilutive units outstanding (in shares) | 0 | |
Affiliated Entity | Subordinated Units | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||
Subordinated units converted into common units (in shares) | 10,071,970 |
Earnings Per Unit - Summary of Weighted Average Common Units Outstanding (Detail) - shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Earnings Per Share [Abstract] | |||
Weighted average limited partner common units - basic (in shares) | 22,728,218 | 22,208,964 | 11,202,427 |
Dilutive effect of unvested restricted and phantom units (in shares) | 9,186 | 265,908 | 358,190 |
Weighted average limited partner common units - dilutive (in shares) | 22,737,404 | 22,474,872 | 11,560,617 |
Quarterly Financial Data (Unaudited) - Summary of Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 |
Sep. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Net sales | $ 1,079,874 | $ 618,455 | $ 741,656 | $ 1,331,148 | $ 932,170 | $ 491,393 | $ 513,626 | $ 917,807 | $ 3,771,133 | $ 2,854,996 | $ 2,389,998 |
Net income | 36,527 | (18,434) | (13,195) | 74,921 | (12,894) | (14,316) | (7,792) | 64,499 | 79,819 | 29,497 | 10,166 |
Limited partners' interest in net income (loss) | $ 34,472 | $ (20,489) | $ (15,250) | $ 73,207 | $ (14,267) | $ (15,340) | $ (8,646) | $ 63,757 | $ 71,940 | $ 25,504 | $ 8,424 |
Net income per limited partner unit: | |||||||||||
Common—basic (in dollars per share) | $ 1.52 | $ (0.90) | $ (0.67) | $ 3.22 | $ (0.63) | $ (0.68) | $ (0.39) | $ 2.98 | $ 3.17 | $ 1.15 | $ 0.40 |
Common—diluted (in dollars per share) | $ 1.51 | $ (0.90) | $ (0.67) | $ 3.21 | $ (0.63) | $ (0.68) | $ (0.39) | $ 2.94 | $ 3.16 | $ 1.13 | $ 0.38 |
Partnership Distributions - Schedule of Cash Distributions Paid to Unitholder (Details) - USD ($) $ / shares in Units, $ in Thousands |
12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Nov. 13, 2018 |
Aug. 10, 2018 |
May 18, 2018 |
Feb. 12, 2018 |
Nov. 13, 2017 |
Aug. 11, 2017 |
May 15, 2017 |
Feb. 14, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Distribution Made to Limited Partner [Line Items] | |||||||||||
Distribution declared per common and subordinated units (in dollars per share) | $ 0.6675 | $ 0.6675 | $ 0.6525 | $ 0.6375 | $ 0.6225 | $ 0.6075 | $ 0.5925 | $ 0.5775 | $ 2.66 | $ 2.46 | $ 2.22 |
Cash distributions, paid | $ 17,230 | $ 17,225 | $ 16,544 | $ 17,622 | $ 15,063 | $ 14,550 | $ 14,099 | $ 13,760 | |||
Common Stock | |||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||
Cash distributions, paid | 15,175 | 15,170 | 14,830 | 14,489 | 14,039 | 13,696 | 13,357 | 6,544 | |||
Subordinated Units | |||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||
Cash distributions, paid | 0 | 0 | 0 | 5,817 | |||||||
Incentive Distribution Rights | |||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||
Cash distributions, paid | $ 2,055 | $ 2,055 | 1,714 | 1,373 | 1,024 | 854 | 742 | 597 | |||
Distribution Equivalents | |||||||||||
Distribution Made to Limited Partner [Line Items] | |||||||||||
Cash distributions, paid | $ 0 | $ 1,760 | $ 0 | $ 0 | $ 0 | $ 802 |
Partnership Distributions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions |
12 Months Ended | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Jan. 23, 2019 |
Nov. 13, 2018 |
Aug. 10, 2018 |
May 18, 2018 |
Feb. 12, 2018 |
Nov. 13, 2017 |
Aug. 11, 2017 |
May 15, 2017 |
Feb. 14, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Distribution Made to Limited Partner [Line Items] | ||||||||||||
Cash distribution, declared per share (in dollars per share) | $ 0.6675 | $ 0.6675 | $ 0.6525 | $ 0.6375 | $ 0.6225 | $ 0.6075 | $ 0.5925 | $ 0.5775 | $ 2.66 | $ 2.46 | $ 2.22 | |
Subsequent Event | ||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||
Cash distribution, declared per share (in dollars per share) | $ 0.6675 | |||||||||||
Cash distribution, declared value | $ 17.2 | |||||||||||
Subsequent Event | Incentive Distribution Rights | ||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||
Cash distribution, declared value | $ 2.1 |
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