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3: EX-31.2 Certification -- §302 - SOA'02 HTML 28K
4: EX-32.1 Certification -- §906 - SOA'02 HTML 23K
5: EX-32.2 Certification -- §906 - SOA'02 HTML 23K
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18: R2 Condensed Consolidated Balance Sheets HTML 125K
28: R3 Condensed Consolidated Balance Sheets HTML 28K
(Parenthetical)
63: R4 Unaudited Condensed Consolidated Income Statements HTML 82K
40: R5 Unaudited Condensed Consolidated Statements of HTML 73K
Comprehensive (Loss) Income
19: R6 Unaudited Condensed Consolidated Statements of HTML 51K
Unitholders' Equity (Deficit)
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Cash Flows
62: R8 Description of Business and Summary of Significant HTML 42K
Accounting Policies
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51: R20 Partnership Distributions HTML 41K
56: R21 Subsequent Events HTML 25K
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(Details)
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Information for Partnership's Reportable Segments
(Details)
37: R47 Financial Instruments and Off-Balance Sheet Risk - HTML 43K
Narrative (Details)
59: R48 Financial Instruments and Off-Balance Sheet Risk - HTML 81K
Summary of Financial Assets and Financial
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on Recurring Basis (Details)
55: R49 Financial Instruments and Off-Balance Sheet Risk - HTML 63K
Summary of Offsetting Arrangements (Details)
42: R50 Financial Instruments and Off-Balance Sheet Risk - HTML 29K
Summary of Realized and Unrealized Gains (Losses)
on Derivative Instruments for Commodity Risk
Management (Details)
64: R51 Financial Instruments and Off-Balance Sheet Risk - HTML 48K
Schedule of Gross Volume of Commodity Derivative
Instruments Outstanding (Details)
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Level 3 Liabilities Reconciliation (Details)
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(Exact name of registrant as specified in its charter)
Delaware
45-2637964
(State
of incorporation)
(I.R.S. Employer Identification No.)
185 International Drive
Portsmouth, New Hampshire 03801
(Address of principal executive offices)
Registrant’s telephone number, including area code: (800) 225-1560
Securities registered pursuant to Section 12(b) of the Act:
Title
of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
SRLP
New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☐
Accelerated filer
☒
Non-accelerated
filer
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Notes to Unaudited Condensed Consolidated Financial Statements
(in thousands unless otherwise stated)
1. 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 the "General Partner" refer to Sprague Resources GP LLC; references to “Axel Johnson” or the "Sponsor" refer to Axel Johnson Inc. and its controlled
affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner; references to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of the General Partner.
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.
•
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 natural gas from natural gas producers and trading companies and sells and distributes natural gas to commercial and industrial customers.
•
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.
See Note 2 - Revenue for a description of the Partnership's revenue activities within these business segments.
As of September 30, 2019, the Sponsor, through its ownership of Sprague Holdings, owned 12,106,348
common units representing 53% of the limited partner interest in the Partnership. Sprague Holdings also owns 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 12 - Earnings Per Unit and Note 13 - Partnership Distributions.
Basis of Presentation
The Condensed
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. The accompanying unaudited Condensed Consolidated Financial Statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim financial information. As permitted under those rules, certain notes or other financial information that are normally required by U.S. generally accepted accounting principles (“GAAP”) to be included in annual financial statements have been condensed or omitted from these interim financial statements. These interim financial statements should be read in conjunction with the consolidated financial
statements and related notes of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 as filed with the SEC on March 14, 2019 (the “2018" Annual Report”).
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 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.
The Condensed Consolidated Financial Statements included herein reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Partnership’s consolidated financial position at September 30, 2019 and December 31, 2018, the consolidated results of operations for the three and nine months ended
September 30, 2019 and 2018, and the consolidated cash flows for the nine months ended September 30, 2019 and 2018. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year. Demand for some of the Partnership’s refined petroleum products, specifically heating oil and residual oil for space heating purposes, and to a lesser extent natural gas, are generally higher during the first and fourth quarters of the calendar year which may result in significant fluctuations
in the Partnership’s quarterly operating results.
Significant Accounting Policies
The Partnership's significant accounting policies are described in Note 1 - Description of Business and Summary of Significant Accounting Policies in the Partnership’s audited consolidated financial statements included in the 2018 Annual Report and are the same as are used in preparing these unaudited interim Condensed Consolidated Financial Statements except for the adoption of ASU 2016-02, Leases (Topic 842) which the Partnership adopted as of January 1, 2019. The adoption of Topic 842 is discussed further in Recent Accounting Pronouncements below, as well as in Note 3 - Leases.
Recent
Accounting Pronouncements
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 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 income statements in a manner similar to prior accounting guidance. The Partnership made an accounting policy election to not recognize an asset and liability for leases with a term of twelve months or less. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those
fiscal years. The Partnership adopted this new accounting standard using a modified retrospective approach, which applies the provisions of the new guidance as of January 1, 2019 without adjusting the comparative periods presented. See Note 3 - Leases for further information.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends the impairment model by requiring entities to use a forward-looking approach based on expected losses rather than incurred losses to estimate credit losses on certain types of financial instruments, including trade receivables. This may result in the earlier recognition of allowances for losses. The guidance is effective for interim and annual periods for fiscal years beginning
after December 15, 2019, with early adoption permitted. The Partnership is currently evaluating the impact of the new standard on its Condensed 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 July 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): 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 adoption of this new guidance did not have a material impact to the Partnership's consolidated financial statements.
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 natural gas from natural gas producers and trade companies and sells and distributes natural gas to commercial and industrial customers. 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 operations 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:
The
Partnership adopted the new lease standard using the required modified retrospective approach, effective January 1, 2019. The standard establishes a right-of-use ("ROU") model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months.
The Partnership chose to apply the transition provisions as of the period of adoption. Therefore, prior period financial information has not been adjusted and continues to be reflected in accordance with the Partnership’s historical accounting policy. The Partnership elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other things, allowed the Partnership to carry forward the historical lease classification. In addition, the Partnership elected
the practical expedient not to apply the recognition requirements in the lease standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that it is reasonably certain to exercise) and the practical expedient that permits lessees to make an accounting policy election (by class of underlying asset) to account for each separate lease component of a contract and its associated non-lease components as a single lease component. The adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases of approximately $19.7 million and $20.0 million, respectively. In addition, capital lease assets and liabilities are now classified as finance lease ROU assets and liabilities.
There was no impact on the Partnership’s Condensed Consolidated Statements of Unitholders’ Equity, Condensed Consolidated Income Statements or Condensed Consolidated Statement of Cash Flows.
The Partnership determines if an arrangement is a lease at inception. The Partnership's ROU assets are included in property, plant and equipment, net and noncurrent other assets for finance leases and operating leases, respectively. Lease liabilities are included in accrued liabilities, current and noncurrent other obligations and operating lease liabilities, less current portion in the Condensed Consolidated Balance Sheets. Operating lease expense is included in operating expenses and cost of products sold while amortization expense associated with ROU assets for finance leases is included in depreciation and amortization expense.
ROU
assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the Partnership’s obligations to make lease payments arising from the lease. ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. The Partnership uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Partnership’s lease terms may include options to extend lease terms ranging from 1 to 10 years while others include options to terminate at the Partnership’s discretion.
The Partnership’s operating and finance leases are primarily for time charters, facilities, railcars and equipment. The terms and conditions
for these leases vary by the type of underlying asset. For the three and nine months ended September 30, 2019, total operating lease expense was $2.2 million and $12.0 million, respectively, of which $1.1 million and $8.3 million was related to short-term leases, respectively. For the three and nine months ended September 30, 2019, total finance lease expense was $0.5 million and $1.5 million, respectively.
ROU
assets obtained in exchange for new lease liabilities
$
4,057
Maturities of operating and finance lease liabilities as of September 30, 2019 are as follows:
Operating
Finance
Remaining
2019
$
2,574
$
530
2020
6,912
2,096
2021
6,985
1,841
2022
3,854
1,657
2023
1,125
965
Thereafter
1,359
110
Total
Lease Payments
22,809
7,199
Less: Interest
(1,917
)
(629
)
Total
$
20,892
$
6,570
From
a lessor perspective, the Partnership has entered into various throughput and materials handling arrangements with customers. These arrangements are accounted for as operating leases as determined by the use terms and rights outlined in the underlying agreements. The throughput contracts are agreements with refined products wholesalers that use the Partnership’s terminal facilities for a fee. The materials handling contracts are arrangements involving rentals of dedicated tanks, pads, land and small office locations for the purposes of storage, parking and other related uses. For the three and nine months ended September 30, 2019, income related to
the operating leases with the Partnership as the lessor, as described above, totaled $9.7 million and $31.2 million, respectively.
Less: current portion of working capital facilities
(70,060
)
(154,318
)
Long-term
portion
$
525,230
$
506,780
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 (the "Credit Agreement") that matures on April 27, 2021. Obligations under the Credit
Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries.
As of September 30, 2019, the revolving credit facilities under the Credit Agreement contained, among other items, the following:
•
A U.S. dollar revolving working capital facility of up to $950.0 million, subject to 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 borrowing base limits, to be used for working capital loans and letters of credit;
•
A revolving acquisition facility of up to $550.0 million, subject to the 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, and
Subject to certain conditions including the receipt of additional commitments from lenders, the ability to increase the U.S. dollar revolving working capital facility by $250.0 million and the multicurrency revolving working capital facility by $220.0 million, subject to a maximum combined 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.
Indebtedness
under the Credit Agreement bears interest, at the borrowers’ option, at a rate per annum equal to either (i) the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) 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 highest of (a) the U.S. Prime Rate as in effect from time to time, (b) the greater of the Federal Funds Effective Rate and the Overnight Bank Funding Rate as in effect from time to time plus 0.50% and (c) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.
For
loans denominated in Canadian dollars, the alternate rate is the Prime Rate which is the higher of (a) the Canadian Prime Rate as in effect from time to time and (b) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.
The working capital facilities are subject to borrowing base reporting and as of September 30, 2019 and December 31, 2018, had a borrowing base of $351.2 million and $512.4 million, respectively. As of September 30, 2019 and December 31,
2018, outstanding letters of credit were $35.6 million and $65.5 million, respectively. As of September 30, 2019, excess availability under the working capital facilities was $72.9 million and excess availability under the acquisition facilities was $197.4 million.
The weighted average interest rate was 5.1% and 5.3% at September 30, 2019 and December 31, 2018,
respectively. No amounts are due under the Credit Agreement until the maturity date. However, the current portion of the Credit Agreement at September 30, 2019 and December 31, 2018 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 include 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 September 30,
2019, the Partnership was in compliance with these covenants.
7. 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 $23.8 million and $24.5 million for the three months ended September 30, 2019 and 2018, respectively, and $75.6 million and
$87.4 million for the nine months ended September 30, 2019 and 2018, respectively. Through the General Partner, the Partnership also participates in the Sponsor’s pension and other post-retirement benefits. At September 30, 2019 and December 31, 2018, total amounts due to the General Partner with respect to these benefits and overhead costs were $7.1 million and $9.8 million, respectively.
8.
Segment Reporting
The Partnership has four reportable segments that comprise the structure used by the chief operating decision makers (CEO and CFO) 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 operations.
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 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 operations segment primarily consists of the purchase, sale and distribution of coal, and commercial trucking activities unrelated to its refined products segment. Other operations are not reported separately as they represent less than 10% of consolidated net sales and adjusted gross margin. The other operations reporting 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, 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 three and nine months ended September 30, 2019 and 2018, respectively. The Partnership’s foreign sales, primarily sales of refined products and natural gas to its customers in Canada, were $63.3 million and $69.0 million for the three months ended September 30,
2019 and 2018, respectively, and $180.2 million and $205.3 million for the nine months ended September 30, 2019 and 2018, respectively.
Change in unrealized value on natural gas transportation contracts
(4)
(7,005
)
(5,939
)
6,429
4,413
Operating costs and expenses not allocated to operating segments:
Operating
expenses
(20,461
)
(21,047
)
(65,325
)
(66,537
)
Selling, general and administrative
(17,570
)
(16,923
)
(56,309
)
(63,349
)
Depreciation
and amortization
(8,466
)
(8,343
)
(25,263
)
(25,146
)
Operating income (loss)
1,673
(9,482
)
53,827
73,948
Other
income
—
293
128
293
Interest income
121
123
447
404
Interest
expense
(9,918
)
(9,073
)
(31,915
)
(28,369
)
Income tax provision
(1,610
)
(295
)
(3,078
)
(2,984
)
Net
(loss) income
$
(9,734
)
$
(18,434
)
$
19,409
$
43,292
(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 adjusted gross margin, which is a non-GAAP financial measure. Adjusted gross margin is also used by external users of the Partnership’s consolidated financial statements to assess the Partnership’s economic results of operations and its commodity market value reporting to lenders. In determining adjusted gross margin, the Partnership adjusts its segment results for the impact of unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income.
(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 change in unrealized gain on inventory which is not included in net income, 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 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 losses (gains) with respect to the derivatives that are included in net income.
(4)
Represents
the Partnership’s estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income 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).
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 operations. There are no significant fixed assets attributable to the natural gas reportable segment.
As of September 30, 2019, goodwill recorded for the refined products, natural gas, materials handling and other operations
segments amounted to $71.4 million, $35.5 million, $6.9 million and $1.2 million, respectively.
9. Financial Instruments and Off-Balance Sheet Risk
As of September 30, 2019 and December 31, 2018, 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 September 30,
2019 and December 31, 2018, 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 September 30, 2019 and December 31, 2018, 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 September 30, 2019, the carrying value of the deferred consideration approximated fair value because there has been no significant subsequent change in the estimated fair value discount rate or probability of outcome.
The following table presents financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis:
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 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 or 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. A majority of all of the Partnership’s commodity derivative contracts outstanding as of September 30, 2019 will settle prior to March 31, 2021.
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 determines fair value using 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 liability.
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 September 30,
2019 and December 31, 2018.
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 Partnership presents derivatives at gross fair values in the Condensed Consolidated Balance Sheets. 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, exclusive of cash collateral, was $44.2
million at September 30, 2019. Information related to these offsetting arrangements is set forth below:
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 for the three and nine months ended September 30, 2019 and 2018. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:
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 the interest rate risk associated with LIBOR based 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 expects to continue to utilize interest rate swaps to hedge cash flow risk and to manage our exposure to LIBOR interest rates or its replaced equivalent for the foreseeable future.
The Partnership's interest rate swap agreements outstanding as of September 30, 2019 were as follows:
Beginning
Ending
Notional
Amount
January 2019
January 2020
$
300,000
January 2020
January 2021
$
300,000
January
2021
January 2022
$
300,000
January 2022
January 2023
$
250,000
There
was no material ineffectiveness determined for the cash flow hedges for the three and nine months ended September 30, 2019 and 2018.
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 September 30, 2019, the amount of unrealized losses, net of tax, expected to be reclassified to earnings during the following twelve-month period was $2.5 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 Condensed Consolidated Income Statements.
The Partnership records changes in the estimated fair value of the contingent consideration within selling, general and administrative expenses in the Condensed Consolidated Income Statements. Changes in the contingent consideration
liability are measured at fair value on a recurring basis using unobservable inputs (Level 3) and during fiscal 2019 are as follows:
The Partnership is subject to a tax on sales made in Quebec from 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. Since filing this legal action in June 2018, the Partnership has been assessed $4.5 million of tax, including interest and penalties, for the period of 2007 to 2018. Similarly, since the filing, the Partnership has been assessed $8.8 million, including a 15% penalty and interest, from the Ministry of the Environment, and the Fight Against Climate Change (known as MELCC) under separate regulation that was in effect for the period from 2007 through 2014. The Partnership is disputing this 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.
11. Equity and Equity-Based Compensation
Equity Awards - Performance-based Phantom Units
The board of directors of the General Partner grants performance-based phantom unit awards to key employees that vest at the end of a performance period (generally
three years). Phantom unit awards granted since 2016 include a performance criteria that considers Sprague Holdings operating cash flow, as defined ("OCF"), over a three year 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 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 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.
The Partnership's long-term incentive phantom unit awards include tandem distribution equivalent rights ("DERs") which entitle the participant to a cash payment 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.
The following table presents a summary of the Partnership’s phantom unit awards subject to vesting
during the nine months ended September 30, 2019:
During
the year ended December 31, 2018 and the nine months ended September 30, 2019, the Partnership reduced its estimate of the number of phantom unit awards granted in 2018 and 2017 that are expected to vest and, as a result, unit-based compensation expense (income) for the nine months ended September 30, 2019 was $0.1 million as compared to $(0.1) million for the nine months
ended September 30, 2018.
Unit-based compensation is included in selling, general and administrative expenses. Unrecognized compensation cost related to performance-based phantom units totaled $1.2 million as of September 30, 2019 which is expected to be recognized over a weighted average period of 27 months.
Equity - Changes in Partnership Units
There were no changes in the number of Partnership units outstanding during the three and nine months ended September 30,
2019.
12. Earnings Per Unit
The Partnership has identified the IDRs as participating securities and uses the two-class method when calculating the net income per unit applicable to limited partners. Earnings per unit applicable to limited partners is computed by dividing limited partners’ interest in net income, after deducting any incentive distributions, by the weighted-average number of outstanding common 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. Diluted earnings per unit includes the effects of potentially dilutive units on the Partnership’s common units, consisting of unvested phantom units.
Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of earnings per unit. Quarterly net income per limited partner and per unit amounts are stand-alone calculations and may not be additive to year to date amounts due to rounding and changes in outstanding units.
Weighted
average limited partner common units - basic
22,733,977
22,727,284
22,733,977
22,726,645
Dilutive effect of unvested phantom units
—
—
23,802
40,080
Weighted
average limited partner common units - dilutive
22,733,977
22,727,284
22,757,779
22,766,725
13. 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 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 October 25, 2019, the Partnership declared a cash distribution for the three months ended September 30, 2019, of $0.6675 per unit, totaling $15.2 million. Such distributions are to be paid on November 12, 2019, to unitholders of record on November 5, 2019. No IDR distribution was made with respect to the three months ended September 30, 2019. Please see Note 14 - Subsequent Events.
14.
Subsequent Events
On October 25, 2019, the General Partner entered into Amendment No. 2 (“Amendment No. 2”) to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013, as amended by Amendment No. 1, dated as of December 20, 2017. Amendment No. 2 provides, generally, that if the holder(s) of a majority of the IDRs in the Partnership request that all or a portion of the amount payable with respect to a given quarter to the holders of the IDRs not be distributed to the holders of the IDRs (the “Waived IDR Amount”), then the General Partner shall not distribute the Waived IDR Amount for such quarter. On October 25,
2019, Sprague Holdings agreed to waive its right to receive payment in respect of the IDRs with respect to the quarter ended September 30, 2019. Any Waived IDR Amount (including such waiver by Sprague Holdings) may be payable in the future, without interest, if certain conditions are met.
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
As used in this Quarterly Report on Form 10-Q ("Quarterly Report"), unless the context otherwise requires, references to "Sprague Resources," the "Partnership,""we,""our,""us," or like terms, refer to Sprague Resources LP and its subsidiaries; references to our "General Partner" refer to Sprague Resources GP LLC; references to "Axel Johnson" or the "Sponsor" refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General
Partner; and references to "Sprague Holdings" refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of our General Partner. Our General Partner is a wholly owned subsidiary of Axel Johnson.
This Quarterly Report and any information incorporated by reference, contains statements that we believe are “forward-looking statements”. Forward looking statements are statements that express our belief, expectations, estimates, or intentions, as well as those statements we make that are not statements of historical fact. Forward-looking statements provide our current expectations and contain projections of results of operations, or financial condition, and/ or forecasts of future events. Words such as “may”, “assume”,
“forecast”, “position”, “seek”, “predict”, “strategy”, “expect”, “intend”, “plan”, “estimate”, “anticipate”, “believe”, “project”, “budget”, “outlook”, “potential”, “will”, “could”, “should”, or “continue”, and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties which could cause our actual results to differ materially from those contained in any forward-looking statement. Consequently, no forward-looking statements can be guaranteed. You are cautioned not to place undue reliance on any forward-looking statements.
Factors that could cause actual results to differ from those in the forward-looking statements include, but are not limited to: (i) changes in federal, state, local, and foreign
laws or regulations including those that permit us to be treated as a partnership for federal income tax purposes, those that govern environmental protection and those that regulate the sale of our products to our customers; (ii) changes in the marketplace for our products or services resulting from events such as dramatic changes in commodity prices, increased competition, increased energy conservation, increased use of alternative fuels and new technologies, changes in local, domestic or international inventory levels, seasonality, changes in supply, weather and logistics disruptions, or general reductions in demand; (iii) security risks including terrorism and cyber-risk, (iv) adverse weather conditions, particularly warmer winter seasons and cooler summer seasons, climate change, environmental releases and natural disasters; (v) adverse local, regional, national, or international economic conditions, unfavorable capital market conditions and detrimental political
developments such as the inability to move products between foreign locales and the United States; (vi) nonpayment or nonperformance by our customers or suppliers; (vii) shutdowns or interruptions at our terminals and storage assets or at the source points for the products we store or sell, disruptions in our labor force, as well as disruptions in our information technology systems; (viii) unanticipated capital expenditures in connection with the construction, repair, or replacement of our assets; (ix) our ability to integrate acquired assets with our existing assets and to realize anticipated cost savings and other efficiencies and benefits; and, (x) our ability to successfully complete our organic growth and acquisition projects and/or to realize the anticipated financial and operational benefits. These are not all of the important factors that could cause actual results to differ materially from those expressed in our forward-looking statements. Other known or unpredictable
factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this Quarterly Report are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if realized, will have the expected consequences to or effect on us or our business or operations. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Quarterly Report may not occur.
When considering these forward-looking statements, please note that we provide additional cautionary discussion of risks and uncertainties in our Annual Report on Form 10-K for the year ended December 31, 2018, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March
14, 2019 (the “2018 Annual Report”), in Part I, Item 1A “Risk Factors”, in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and in Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk”. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Quarterly Report may not occur.
Forward-looking statements contained in this Quarterly Report speak only as of the date of this Quarterly Report (or other date as specified in this Quarterly Report) or as of the date given if provided in another filing with the SEC. We undertake no obligation, and disclaim any obligation, to publicly update, review or revise any forward-looking statements to reflect events or circumstances after the date of such statements. All forward looking statements
attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in our existing and future periodic reports filed with the SEC.
We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner. We engage in the purchase, storage, distribution and sale of refined products and natural gas, and provide storage and handling services for a broad range of materials.
In October 2013, we became a publicly traded master limited partnership ("MLP") and our common units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP".
Our Predecessor was founded in 1870 as the Charles H. Sprague Company in Boston, Massachusetts; and, in 1905, the company opened the Penobscot Coal and Wharf Company, a tidewater terminal located in Searsport, Maine. By World War II, the company was operating eleven terminals and a fleet of two dozen vessels transporting coal and other products throughout the world. As fuel needs diversified in the United States, the company expanded
its product offerings and invested in terminals, tankers, and product handling activities. In 1959, the company expanded its oil marketing activities via entry into the distillate oil market. In 1970, the company was sold to Royal Dutch Shell’s Asiatic Petroleum subsidiary; and, in 1972, Royal Dutch Shell sold the company to Axel Johnson Inc., a member of the Axel Johnson Group of Stockholm, Sweden.
We are one of the largest independent wholesale distributors of refined products in the Northeast United States based on aggregate terminal capacity. We own, operate and/or control a network of refined products and materials handling terminals strategically located throughout
the Northeast United States and in Quebec, Canada that have a combined storage tank capacity of 14.3 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. We also have access to more than 40 third-party terminals in the Northeast United States through which we sell or distribute refined products pursuant to rack, exchange and throughput agreements.
We operate under four business segments: refined products, natural gas, materials handling and other operations. See Note 8 - Segment Reporting to our Condensed Consolidated Financial Statements for a presentation of financial results by reportable segment and see Part I, Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results
of Operations for a discussion of financial results by segment.
In our refined products segment we purchase a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel and gasoline (primarily from refining companies, trading organizations and producers), and sell them to our customers. We have wholesale customers who resell the refined products we sell to them and commercial customers who consume the refined products directly. Our wholesale customers consist of approximately 1,000 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, drill sites, large industrial companies, real estate management companies, hospitals, educational institutions, and asphalt paving companies. In addition, as a result of our acquisition of
Coen Energy in 2017, our customers include businesses engaged in the development of natural gas resources in Pennsylvania and surrounding states.
In our natural gas segment we purchase natural gas from natural gas producers and trading companies and sell and distribute natural gas to approximately 14,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States.
Our materials handling segment is generally conducted under multi-year agreements as either fee-based activities or as leasing arrangements when the right to use an identified asset (such as storage tanks or storage locations) has been conveyed in the agreement. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal,
petroleum coke, caustic soda, tallow, pulp and heavy equipment. Historically, a majority of our materials handling activity has generated qualified income.
Our other operations segment primarily includes the marketing and distribution of coal conducted in our Portland, Maine terminal, and commercial trucking activity conducted by our Canadian subsidiary.
We take title to the products we sell in our refined products and natural gas segments. In order to manage our exposure to commodity price fluctuations, we use derivatives and forward contracts to maintain a position that is substantially balanced between product purchases and product sales. We do not take title to any of the products in our materials handling segment.
As of September 30, 2019, our Sponsor, through its ownership of Sprague Holdings, owns 12,106,348 common units representing an aggregate of 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”) which entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from distributable cash flow in excess of $0.474375 per unit per quarter. The maximum IDR distribution of 50.0% does not include any distributions that Sprague
Holdings may receive on any limited partner units that it owns.
IDR Waiver
On October 25, 2019, the General Partner entered into Amendment No. 2 (“Amendment No. 2”) to the First Amended and Restated Agreement of Limited Partnership of Sprague Resources LP dated as of October 30, 2013, as amended by Amendment No. 1, dated as of December 20, 2017. Amendment No. 2 provides, generally, that if the holder(s) of a majority of the IDRs in the Partnership request that all or a portion of the amount payable with respect to a given quarter to the holders of the IDRs not be distributed to the holders of the IDRs (the “Waived IDR Amount”), then the General Partner shall not distribute the Waived IDR Amount for such quarter. On October
25, 2019, Sprague Holdings agreed to waive its right to receive payment in respect of the IDRs with respect to the quarter ended September 30, 2019. Any Waived IDR Amount (including such waiver by Sprague Holdings) may be payable in the future, without interest, if certain conditions are met.
How Management Evaluates Our Results of Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) adjusted EBITDA and adjusted gross margin, (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.
EBITDA, adjusted EBITDA and adjusted gross margin used in this Quarterly Report are non-GAAP financial measures.
EBITDA and Adjusted EBITDA
Management believes that adjusted EBITDA is an aid in assessing repeatable operating performance that is not distorted by non-recurring items or market volatility and the ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our unitholders.
We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA adjusted for the change in unrealized hedging gains (losses) with respect to refined products and natural gas inventory, and natural gas transportation contracts,
adjusted for changes in the fair value of contingent consideration, adjusted for the impact of acquisition related expenses, and adjusted for the impact of biofuel excise tax credits resulting from retroactive tax legislation changes that occurred in 2018.
EBITDA and adjusted EBITDA are used as supplemental financial measures by external users of our financial statements, such as investors, trade suppliers, research analysts and commercial banks to assess:
•
The financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;
•
The
ability of our assets to generate sufficient revenue, that when rendered to cash, will be available to pay interest on our indebtedness and make distributions to our equity holders;
•
Repeatable operating performance that is not distorted by non-recurring items or market volatility; and
•
The viability of acquisitions and capital expenditure projects.
EBITDA and
adjusted EBITDA are not prepared in accordance with GAAP and should not be considered alternatives to net income (loss) or operating income (loss), or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income (loss) and operating income (loss).
The GAAP measure most directly comparable to EBITDA and adjusted EBITDA is net income (loss). EBITDA and adjusted EBITDA should not be considered as alternatives to net income (loss) or cash provided by (used in) operating activities, or any other measure of financial performance or liquidity presented in accordance
with GAAP. EBITDA and adjusted EBITDA are not presentations made in accordance with GAAP and have important limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Because EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income (loss) and are defined differently by different companies, our definitions of EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies.
We recognize that the usefulness of EBITDA and adjusted
EBITDA as evaluative tools may have certain limitations, including:
•
EBITDA and adjusted EBITDA do not include interest expense. Because we have borrowed money in order to finance our operations, interest expense is a necessary element of our costs and impacts our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations;
•
EBITDA and adjusted EBITDA do not include depreciation and amortization expense. Because capital
assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits, any measure that excludes depreciation and amortization expense may have material limitations;
•
EBITDA and adjusted EBITDA do not include provision for income taxes. Because the payment of income taxes is a necessary element of our costs, any measure that excludes income tax expense may have material limitations;
•
EBITDA and adjusted EBITDA do not reflect capital expenditures or future requirements for
capital expenditures or contractual commitments;
•
EBITDA and adjusted EBITDA do not reflect changes in, or cash requirements for, working capital needs; and
•
EBITDA and adjusted EBITDA do not allow us to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss.
Adjusted Gross Margin
Management trades, purchases, stores and sells
energy commodities that experience market value fluctuations. To manage the Partnership’s underlying performance, including its physical and derivative positions, management utilizes adjusted gross margin. In determining adjusted gross margin, management adjusts its segment results for the impact of unrealized gains and losses with regard to refined products and natural gas inventory, and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income (loss). Adjusted gross margin is also used by external users of our consolidated financial statements to assess our economic results of operations and our commodity market value reporting to lenders.
We define adjusted gross margin as net sales less cost of products
sold (exclusive of depreciation and amortization) and decreased by total commodity derivative gains and losses included in net income (loss) and increased by realized commodity derivative gains and losses included in net income (loss), in each case with respect to refined products and natural gas inventory, and natural gas transportation contracts. Adjusted gross margin has no impact on reported volumes or net sales.
Adjusted gross margin is used as a supplemental financial measure by management to describe our operations and economic performance to investors, trade suppliers, research analysts and commercial banks to assess:
•
The
economic results of our operations;
•
The market value of our inventory and natural gas transportation contracts for financial reporting to our lenders, as well as for borrowing base purposes; and
•
Repeatable operating performance that is not distorted by non-recurring items or market volatility.
Adjusted
gross margin is not prepared in accordance with GAAP and should not be considered as an alternative to net income (loss) or operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
We define adjusted unit gross margin as adjusted gross margin divided by units sold, as expressed in gallons for refined products and in MMBtus for natural gas.
For a reconciliation of adjusted gross margin and adjusted EBITDA to the GAAP measures most directly comparable, see the reconciliation tables included in "Results of Operations." See Note 8 - Segment Reporting to our Condensed Consolidated Financial Statements for a presentation of our financial results by reportable segment.
Management evaluates our segment performance based on adjusted gross margin. Based on the way we manage our business, it is not reasonably possible for us to allocate the components of operating expenses, selling, general and administrative expenses and depreciation and amortization among the operating segments.
Operating expenses are costs associated with the operation of the terminals and truck fleet used in our business. Employee wages, pension and 401(k) plan expenses,
boiler fuel, repairs and maintenance, utilities, insurance, property taxes, services and lease payments comprise the most significant portions of our operating expenses. Employee wages and related employee expenses included in our operating expenses are incurred on our behalf by our General Partner and reimbursed by us. These expenses remain relatively stable independent of the volumes through our system but can fluctuate depending on the activities performed during a specific period.
Selling, General and Administrative Expenses
Selling, general and administrative expenses ("SG&A") include employee salaries and benefits, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Employee wages, related employee expenses and certain rental costs included
in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us.
Heating Degree Days
A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated over the course of a year and can be compared to a monthly or a long-term average ("normal") to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and archived by the National Climate Data Center. In order to incorporate more recent average information and to better
reflect the geographic locations of our customer base, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same geographic locations over the previous ten-year period.
Hedging Activities
We hedge our inventory within the guidelines set in our risk management policies. In a rising commodity price environment, the market value of our inventory will generally be higher than the cost of our inventory. For GAAP purposes, we are required to value our inventory at the lower of cost or net realizable value. The hedges on this inventory will lose value as the value of the underlying commodity rises, creating hedging losses. Because we do not utilize hedge accounting, GAAP requires us to record those hedging losses in our income statements. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP
requires us to record those hedging gains in our income statements.
The refined products inventory market valuation is calculated using daily independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are primarily based in large, liquid trading hubs including but not limited to, New York Harbor (NYH) or US Gulf Coast (USGC), with our inventory values determined after adjusting these prices to the various inventory locations by adding expected cost differentials (primarily freight) compared to one of these supply sources. Our natural gas inventory is limited, with the valuation updated monthly based on the volume and prices at the corresponding inventory locations. The prices are based on the most applicable monthly Inside FERC, or IFERC, assessments published by Platts near the beginning of the following month.
Similarly,
we can hedge our natural gas transportation assets (i.e., pipeline capacity) within the guidelines set in our risk management policy. Although we do not own any natural gas pipelines, we secure the use of pipeline capacity to support our natural gas requirements by either leasing capacity over a pipeline for a defined time period or by being assigned capacity from a local distribution company for supplying our customers. As the spread between the price of gas between the origin and delivery point widens (assuming the value exceeds the fixed charge of the transportation), the market value of the natural gas transportation contracts assets will typically increase. If the market value of the transportation asset exceeds costs, we may seek to hedge or “lock in” the value of the transportation asset for future periods using available financial instruments. For GAAP purposes,
the increase in value of the natural gas transportation assets is not recorded as income in the income statements until the transportation is utilized in the future (i.e., when natural gas is delivered to our customer). If the value of the natural gas transportation assets increase, the hedges on the natural gas transportation assets lose value, creating hedging losses in our income statements. The natural gas transportation assets market value is calculated daily based on the volume and prices at the corresponding pipeline locations. The daily prices are based on trader assessed quotes which represent observable transactions in the market place, with the end-month valuations primarily based on Platts prices where available or adding a location differential to the price assessment of a more liquid location.
As described above, pursuant to GAAP, we value our commodity derivative hedges at the end of each reporting period based on current commodity prices and record hedging gains or losses, as appropriate. Also as described above, and pursuant to GAAP, our refined products and natural gas inventory and natural gas transportation contract rights, to which the commodity derivative hedges relate, are not marked to market for the purpose of recording gains or losses. In measuring our operating performance, we rely on our GAAP financial results, but we also find it useful to adjust those numbers to show only the impact of hedging gains and losses actually realized in the period being reviewed. By making such adjustments, as reflected in adjusted gross margin and
adjusted EBITDA, we believe that we are able to align more closely hedging gains and losses to the period in which the revenue from the sale of inventory and income from transportation contracts relating to those hedges is realized.
Trends and Factors that Impact our Business
In addition to the other information set forth in this report, please refer to our 2018 Annual Report for a discussion of the trends and factors that impact our business.
Results of Operations
Our current and future results of operations may not be comparable to our historical results of operations. Our results of
operations may be impacted by, among other things, swings in commodity prices, primarily in refined products and natural gas, and acquisitions or dispositions. We use economic hedges to minimize the impact of changing prices on refined products and natural gas inventory. As a result, commodity price increases at the end of a period can create lower gross margins as the economic hedges, or derivatives, for such inventory may lose value, whereas an increase in the value of such inventory is disregarded for GAAP financial reporting purposes and recorded at the lower of cost or net realizable value. Please read “How Management Evaluates Our Results of Operations.”
The following tables set forth information regarding our results of operations for the periods presented:
Three
Months Ended September 30,
Increase/(Decrease)
2019
2018
$
%
(in thousands)
Net
sales
$
582,590
$
618,455
$
(35,865
)
(6
)%
Cost
of products sold (exclusive of depreciation and amortization)
Cost
of products sold (exclusive of depreciation and amortization)
2,302,192
2,462,279
(160,087
)
(7
)%
Operating expenses
65,325
66,537
(1,212
)
(2
)%
Selling,
general and administrative
56,309
63,349
(7,040
)
(11
)%
Depreciation and amortization
25,263
25,146
117
—
%
Total
operating costs and expenses
2,449,089
2,617,311
(168,222
)
(6
)%
Operating income
53,827
73,948
(20,121
)
(27
)%
Other
income
128
293
(165
)
—
%
Interest income
447
404
43
11
%
Interest
expense
(31,915
)
(28,369
)
(3,503
)
12
%
Income before income taxes
22,487
46,276
(23,789
)
(51
)%
Income
tax provision
(3,078
)
(2,984
)
(94
)
3
%
Net income
$
19,409
$
43,292
$
(23,883
)
(55
)%
Analysis
of Consolidated Operating Results
Net loss was $9.7 million and $18.4 million for the three months ended September 30, 2019 and 2018, respectively and operating income (loss) was $1.7 million and $(9.5) million for the three months ended September 30, 2019 and 2018,
respectively. Operating results for the three months ended September 30, 2019 and 2018 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory and natural gas transportation contracts of $(3.6) million and $(9.2) million, respectively. Excluding these unrealized items, operating income for the three months ended September 30, 2019 increased
$5.5 million, or 2104%, as compared to the three months ended September 30, 2018.
Net income was $19.4 million and $43.3 million for the nine months ended September 30, 2019 and 2018, respectively and operating income was $53.8 million and $73.9
million for the nine months ended September 30, 2019 and 2018, respectively. Operating results for the nine months ended September 30, 2019 and 2018 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory, and natural gas transportation contracts of $5.3 million and $23.7
million, respectively. Excluding these unrealized items, operating income for the nine months ended September 30, 2019 decreased $1.7 million, or 3%, as compared to the nine months ended September 30, 2018.
See "Analysis of Operating Segments", "Operating Costs and Expenses" and "Liquidity and Capital Resources" below for additional details on our operating results.
Reconciliation to Adjusted Gross Margin, EBITDA and Adjusted EBITDA
The following table sets forth a reconciliation of our consolidated operating income (loss) to our total adjusted gross margin, a non-GAAP measure, for the periods presented and a reconciliation of our consolidated net income (loss) to EBITDA and Adjusted EBITDA, non-GAAP measures, for the periods presented. See above “Management’s Discussion and Analysis of Financial Condition and Results of Operations - How Management Evaluates Our Results of Operations - EBITDA and Adjusted EBITDA” of this report. The table below also presents information on weather conditions for the periods presented.
Inventory is valued at the lower of cost or net realizable value. The adjustment related to change in unrealized gain on inventory which is not included in net income (loss), represents the estimated difference between inventory valued at the lower of cost or net realizable value as compared to market values. The fair value of the derivatives we use to economically hedge our inventory declines or appreciates in value as the value of the underlying inventory appreciates or declines, which creates unrealized hedging losses (gains) with respect to the derivatives that are included in net income (loss).
(2)
Represents
our estimate of the change in fair value of the natural gas transportation contracts which are not recorded in net income (loss) until the transportation is utilized in the future (i.e., when natural gas is delivered to the customer), as these contracts are executory contracts that do not qualify as derivatives. As the fair value of the natural gas transportation contracts decline or appreciate, the offsetting physical or financial derivative will also appreciate or decline creating unmatched unrealized hedging losses (gains) in net income
(loss).
(3)
For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “How Management Evaluates Our Results of Operations.”
(4)
On 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 six months ended June 30, 2018, we recorded excise tax credits of $4.0 million that relate to blending activities that occurred during the year ended December 31, 2017, resulting in an increase in adjusted gross margin during the period. 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.
(5)
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.
(6)
Represents the change in the fair value of contingent consideration related to the 2017 Coen Energy acquisition and other expense.
(7)
For purposes of evaluating our results of operations, we use heating degree day amounts as reported by the NOAA
Regional Climate Center. In order to incorporate more recent average information and to better reflect the geographic locations of our customer base, we report degree day information for Boston and New York City (weighted equally) with a historical average for the same geographic locations over the previous ten-year period.
Refined products net sales decreased $36.5 million, or 7%, compared to the same period last year, due to a lower price environment, with the average sales price declining by nearly 12%. Volumes increased by 6%, primarily due to distillates, resulting from a combination of higher discretionary and contractual volumes. The bulk of this distillate volume increase was diesel fuel, with sizable gains in a number of our key markets. Gasoline and residual fuel oil sales volumes were also higher, at 2% to 3% more than the same period last year.
Refined products adjusted gross margin increased $6.8 million, or
25%, compared to the same period last year. The increase in adjusted gross margin was primarily a result of higher adjusted unit gross margin, with the gains in volume a lesser factor. A key contributor to the higher adjusted unit gross margin was a significant improvement at Kildair due to a combination of a more attractive market environment for supplying and hedging fuel oil, as well as better marine fuel margins. Improvement in distillate adjusted unit gross margins due to better diesel and heating oil results was also a factor.
Natural Gas
Natural gas net sales increased $2.1 million, or 4%, compared to the same period last year driven by a 14%
gain in volumes. Sales were strong, including a number of new customers with higher than typical requirements. The higher volume was partially offset by an 8% decrease in average sales price, consistent with the lower underlying natural gas price environment.
Natural gas adjusted gross margin increased $0.7 million, or 22%, compared to the same period last year, due to the higher sales volume as well as the 7% higher adjusted unit margin. The improved unit gross margin was driven primarily by a stronger valuation of forward positions due to more favorable natural gas market conditions.
Materials handling net sales and adjusted gross margin were both $13.1 million, $1.6 million lower than the same period last year. More than half of this decrease occurred at our U.S. operations, resulting from lower bulk deliveries partly due to timing differences as well as tariff-driven reductions in pulp and paper handling. A gain in asphalt handling partially offset these reductions. Kildair adjusted gross margin also declined compared to the same period last year, primarily due to the expiration of the crude handling contract at the end of May. This reduction at Kildair was partially moderated
by gains due to incremental Vacuum Gas Oil and Heavy Fuel Oil tank rental income from two customers.
Other Operations
Net sales from other operations increased $0.1 million, or 2%, due to a combination of higher trucking revenues at Kildair and higher coal sales prices compared to the same period last year. Adjusted gross margin declined by $0.2 million.
Refined products net sales decreased $176.9 million, or 7%, compared to the same period last year, due to a combination of lower volumes and prices. The 3% decline in volume was primarily due to a reduction in residual fuel oil, with gasoline also a notable contributor. Key factors leading to the residual fuel oil volume decrease were less supportive weather, limited natural gas interruptions and reduced marine bunker requirements. Kildair also had a one-time bulk export last year which is a significant part of the volume differences. Higher competitive intensity was the key factor leading to the lower gasoline volumes. The 4% lower average sales price reflects the reduced market price environment
during the nine months ended September 30, 2019 compared to the same period last year.
Refined products adjusted gross margin decreased $5.9 million, or 5%, compared to the same period last year. This reduction was due to a combination of the 3%
decline in volume discussed above along with a 2% reduction in average adjusted unit gross margin. Higher competitive intensity on discretionary volumes and less supportive weather were key drivers of the decline in the adjusted unit gross margin.
Natural Gas
Natural gas net sales decreased $14.0 million, or 6%, compared to the same period last year as a result of the lower natural gas price environment. Sales volumes increased by 4% compared to last year with the gains in the spring and summer periods more than balancing the reduced winter volumes.
Natural gas adjusted gross margin decreased by $5.4
million, or 12%, compared to the same period last year, due to the 15% lower adjusted unit gross margin. The decrease in adjusted unit gross margins primarily reflects a reduction compared to the results achieved with the higher cash prices and margin opportunities in the winter period last year.
Materials Handling
Materials handling net sales and adjusted gross margin both increased $1.8 million, or 4%, compared to the same period last year. Incremental revenue at Kildair led to the gain due to a significant increase in Vacuum Gas Oil and Heavy Fuel Oil tank rental agreement income from two customers as well as nine months of the
asphalt materials handling agreement compared to seven months last year. These gains at Kildair were partially offset by the expiration of the crude handling agreement at the end of May 2019. At Sprague’s U.S. operations, adjusted gross margin decreased modestly as small gains in various bulk and break bulk activities were more than offset by the reduction in heavy lift adjusted gross margin following the completion of ethane cracker modules handling requirements.
Other Operations
Net sales from other operations increased by $0.7 million, or 4%, due to a combination of higher trucking revenues at Kildair and higher coal sales prices compared to the same period last year. Adjusted gross margin was $0.4 million
lower than last year.
Operating
Expenses. Operating expenses decreased $0.6 million, or 3%, compared to the same period last year, reflecting a decrease of $0.4 million of stockpile expenses and $0.2 million of decreased transportation related expenses.
Selling, General and Administrative Expenses. SG&A expenses increased $0.6 million, or 4%, compared to the same period last year driven by a $2.3 million reduction to incentive compensation expense recorded in the third quarter of 2018 to reflect a lower estimated number of phantom units that were expected to vest over the vesting period. This increase was partially offset by $1.1 million
in decreased employee related expenses attributed to our cost reduction initiatives as well as a $0.5 million decrease in professional fees.
Depreciation and Amortization. Depreciation and amortization was approximately flat as increased depreciation expense offset decreased amortization expense.
Interest Expense, net. Interest expense, net increased $0.8 million, or 9%, compared to the same period last year primarily due to increased interest rates.
Operating
Expenses. Operating expenses decreased $1.2 million, or 2%, compared to the same period last year, reflecting $0.5 million of decreased transportation related expenses and $0.4 million of decreased legal expenses.
Selling, General and Administrative Expenses. SG&A expenses decreased $7.0 million or 11%, compared to the same period last year. This decrease was driven by a $3.4 million in lower employee related costs attributed to our cost reduction initiatives and decreases of $1.1 million in sales commissions, $0.8 million in incentive compensation, $0.8 million of professional fees and $0.5 million in
merger related costs.
Depreciation and Amortization. Depreciation and amortization was approximately flat as increased depreciation expense offset decreased amortization expense.
Interest Expense, net. Interest expense, net increased $3.5 million, or 12%, compared to the same period last year primarily due to increased interest rates.
Liquidity and Capital Resources
Liquidity
Our primary liquidity needs
are to fund our working capital requirements, operating expenses, capital expenditures and quarterly distributions. Cash generated from operations, our borrowing capacity under our Credit Agreement (as defined below) and potential future issuances of additional partnership interests or debt securities are our primary sources of liquidity. At September 30, 2019, we had working capital of $157.7 million.
As of September 30, 2019, the undrawn borrowing capacity under the working capital facilities of our Credit Agreement was $72.9 million and the undrawn borrowing capacity under the acquisition facility was $197.4 million.
We enter our seasonal peak period during the fourth quarter of each year, during which inventory, accounts receivable and debt levels increase. As we move out of the winter season at the end of the first quarter of the following year, typically inventory is reduced, accounts receivable are collected and converted into cash and debt is paid down. During the nine months ended September 30, 2019, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of $197.8 million to a high of $394.7 million.
We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our Credit Agreement to meet our financial commitments,
debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flow would likely have an adverse effect on our ability to meet our financial commitments and debt service obligations.
Credit Agreement
Sprague Operating Resources LLC and Kildair, wholly owned subsidiaries of the Partnership, are borrowers under an amended and restated revolving credit agreement (our "Credit Agreement") that matures on April 27, 2021. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries.
As of September 30, 2019, the revolving credit facilities under the Credit Agreement contained, among other items, the following:
A U.S. dollar revolving working capital facility of up to $950.0 million, subject
to 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 borrowing base limits, to be used for working capital loans and letters of credit;
•
A revolving acquisition facility of up to $550.0 million, subject to the 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, and
•
Subject to certain conditions including the receipt of additional commitments from lenders, the ability to increase the U.S. dollar revolving working capital facility by $250.0 million and the multicurrency revolving working capital facility by $220.0 million, subject to a maximum combined 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.
Indebtedness
under the Credit Agreement bears interest, at the borrowers' option, at a rate per annum equal to either (i) the Eurocurrency Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) 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 highest of (a) the U.S. Prime Rate as in effect from time to time, (b) the greater of the Federal Funds Effective Rate and the Overnight Bank Funding Rate as in effect from time to time plus 0.50% and (c) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.
For
loans denominated in Canadian dollars, the alternate rate is the Prime Rate which is the higher of (a) the Canadian Prime Rate as in effect from time to time and (b) the one-month Eurocurrency Rate for U.S. dollars as in effect from time to time plus 1.00%.
The specified margin for the working capital facilities will range, based upon the percentage utilization of this facility, from 1.00% to 1.50% for loans bearing interest at the alternative Base Rate and from 2.00% to 2.50% for loans bearing interest at the Eurocurrency Rate and for letters of credit issued under the U.S. dollar working capital facility or the multicurrency working capital facility. The specified margin for the acquisition facility will range, based on the Partnership’s consolidated total leverage ratio, from 1.25% to 2.25% for loans bearing interest at the alternate Base Rate and from 2.25% to 3.25% for loans
bearing interest at the Eurocurrency Rate and for letters of credit issued under the acquisition facility. In addition, the Partnership will incur a commitment fee on the unused portion of the facilities at a rate ranging from 0.375% to 0.50% per annum. Overdue amounts bear interest at the applicable rates described above plus an additional margin of 2%.
The Credit Agreement contains various covenants and restrictive provisions that, among other things, prohibit the Partnership from making distributions to unitholders if any event of default occurs or would result from the distribution or if the Partnership would not be in pro forma compliance with its financial covenants after giving effect to the distribution. In addition, the Credit Agreement contains various covenants that are usual and customary for a financing of this type, size and purpose, including, but not limited to, covenants that require the Partnership to maintain:
a minimum consolidated EBITDA-to-fixed charge ratio, a minimum consolidated net working capital amount, a maximum consolidated total leverage-to-EBITDA ratio and a maximum consolidated senior secured leverage-to-EBITDA ratio. The credit agreement also limits the Partnership's ability to incur debt, grant liens, make certain investments or acquisitions, dispose of assets, and incur additional indebtedness. The Partnership was in compliance with the covenants under the Credit Agreement at September 30, 2019.
The Credit Agreement also contains events of default that are usual and customary for a financing of this type, size and purpose including, among others, non-payment of principal, interest or fees, violation of certain covenants, material inaccuracy of representations and warranties, bankruptcy and insolvency events, cross-payment
default and cross-acceleration, material judgments and events constituting a change of control. If an event of default exists under the Credit Agreement, the lenders will be able to terminate the lending commitments, accelerate the maturity of the Credit Agreement and exercise other rights and remedies with respect to the collateral.
Our
terminals require investments to maintain, expand, upgrade or enhance existing assets and to comply with environmental and operational regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. We define maintenance capital expenditures as capital expenditures made to replace assets, or to maintain the long-term operating capacity of our assets or operating income. Examples of maintenance capital expenditures are expenditures required to maintain equipment reliability, terminal integrity and safety and to address environmental laws and regulations. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as maintenance expenses as we incur them. We define expansion capital expenditures as capital expenditures made to increase the long-term operating capacity of our assets or our operating income whether
through construction or acquisition of additional assets. Examples of expansion capital expenditures include the acquisition of equipment and the development or acquisition of additional storage capacity, to the extent such capital expenditures are expected to expand our operating capacity or our operating income.
The following table summarizes expansion and maintenance capital expenditures for the periods indicated. This information excludes property, plant and equipment acquired in business combinations:
We anticipate that future maintenance capital expenditures will be funded with cash generated by operations and that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity offerings.
Net cash provided by operating activities for the nine months ended September 30, 2019 was $130.7 million. Cash inflows for
the period were the result of a decrease of $103.5 million in inventories due to a reduction in inventory requirements, a decrease of $110.7 million in accounts receivable due to a seasonal reduction in sales volume, $19.4 million in net income and $36.3 million representing the net impact in our derivative instruments as a result of contract activity and changes in commodity prices during the period. These inflows were offset by cash outflows as a result of a reduction of $147.6 million in accounts payable and accrued liabilities primarily relating to the timing
of invoice payments for product purchases.
Net cash provided by operating activities for the nine months ended September 30, 2018 was $191.3 million and was primarily driven by cash inflows as a result of a decrease of $123.9 million in inventories due to a seasonal reduction in inventory requirements, a decrease of $124.9 million in accounts receivable due to a seasonal reduction in sales volume, and $43.3 million in net income. These inflows were offset by cash outflows as a result of a reduction
of $114.8 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and $29.6 million representing the net impact in our derivative instruments as a result contract activity and changes in commodity prices during the period.
Net cash used in investing activities for the nine months ended September 30, 2019 was $10.2 million, and primarily resulted from $4.4 million related to expansion capital expenditures and $6.0 million related to maintenance capital expenditure projects across our terminal system.
Net cash used in investing activities for the nine months ended September 30, 2018
was $13.0 million of which $5.8 million related to expansion capital expenditures and $7.6 million related to maintenance capital expenditure projects across our terminal system.
Financing Activities
Net cash used in financing activities for the nine months ended September 30, 2019 was $121.1 million, and primarily resulted from $66.0 million of payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels, the reduction of inventory levels and distributions
of $51.7 million.
Net cash used in financing activities for the nine months ended September 30, 2018 was $166.6 million, and primarily resulted from $109.5 million of payments under our Credit Agreement due to reduced financing requirements from accounts receivable levels, the reduction of seasonal inventory levels and distributions of $51.4 million.
Impact of Inflation
Inflation in the United States and Canada has been relatively low in recent years and did not have a material impact on our results
of operations for the nine months ended September 30, 2019 and 2018.
Critical Accounting Policies and Estimates
Part I, Item, 2, "Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Condensed Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date
of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions.
These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis: the fair value of derivative assets and liabilities, goodwill impairment assessment, and revenue recognition and cost of products sold.
The
significant accounting policies and estimates that have been adopted and followed in the preparation of our Condensed Consolidated Financial Statements are detailed in Note 1 - Description of Business and Summary of Significant Accounting Policies included in our 2018 Annual Report and as updated in Note 3 - Leases to this Quarterly Report as it relates to the adoption of ASU 2016-02, Leases (Topic 842). Other than the impact of the adoption of the new lease guidance, there have been no changes in these policies and estimates that had a significant impact on the financial condition and results of operations for the periods covered in this Quarterly Report.
Recent Accounting Pronouncements
For information on recent accounting pronouncements impacting our business, see "Recent Accounting
Pronouncements" included under Note 1 - Description of Business and Summary of Significant Accounting Policies to our Condensed Consolidated Financial Statements.
Quantitative and Qualitative Disclosures about Market Risk
Market
risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk, interest rate risk and market/credit risk. We utilize various derivative instruments to manage exposure to commodity risk and swaps to manage exposure to interest rate risk.
Commodity Price Risk
We use various financial instruments as we seek to hedge our commodity price risk. We sell our refined products and natural gas primarily in the Northeast. We hedge our refined products positions primarily with a combination of futures contracts that trade on the New York Mercantile Exchange, or NYMEX, and fixed-for-floating price swaps in the form of bilateral contracts
that are traded “over-the-counter” or "OTC". Although there are some notable differences between futures and the fixed-for-floating price swaps, both can provide a fixed price while the counterparty receives a price that fluctuates as market prices change.
As indicated in the table below, we primarily use futures contracts to hedge light oil transactions and swaps contracts for residual fuel oil. There are no residual fuel oil futures contracts that actively trade in the United States. Each of the financial instruments trade by month for many months forward, allowing us the ability to hedge future contractual commitments.
New
York Harbor 1% Sulfur Residual Fuel Oil swaps contract
In addition to the financial instruments listed above, we periodically use the ethanol futures contracts (EH - CBOT Ethanol Futures and EZ - NY Ethanol Futures) to hedge ethanol that is used for blending into our gasoline. We also use Rotterdam Barge Gasoil 0.1% Sulfur swaps as the primary means to hedge Kildair's marine gas oil positions.
For natural gas, there are no quality differences that need to be considered when hedging. Our primary hedging requirements relate to fixed price and basis (location) exposure. We largely hedge our natural gas fixed price exposure using fixed-for-floating price swaps that trade on
the Intercontinental Exchange ("ICE") with the prices based on the Henry Hub location near Erath, Louisiana. The Henry Hub is the most active natural gas trading location in the United States. Although we typically use swaps, there is also an actively traded NYMEX Henry Hub natural gas futures contract that we can use. We primarily use ICE basis swaps as the key financial instrument type to hedge our natural gas basis risk. Similar to the natural gas futures and ICE Henry Hub swaps, basis swaps for major locations trade actively for many months. These swaps are financially settled, typically using prices quoted by Platts. We also directly hedge our price exposure in oil and natural gas by using forward purchases or sales that require physical delivery of the product.
The following table sets forth total realized and unrealized
gains and (losses) on derivative instruments utilized for commodity risk management purposes. Such amounts are included in cost of products sold (exclusive of depreciation and amortization) for the periods presented.
We enter into interest rate swaps to manage exposures in changing interest rates. We swap the variable LIBOR interest rate payable under our Credit Agreement
for fixed LIBOR interest rates. These interest rate swaps meet the criteria to receive cash flow hedge accounting treatment. Counterparties to our interest rate swaps are large multi-national banks and we do not believe there is a material risk of counterparty nonperformance. Additionally, we may enter into seasonal swaps which are intended to manage our increase in borrowings during the winter, as a result of higher inventory and accounts receivable levels.
Our interest rate swap agreements outstanding as of September 30, 2019 were as follows (in thousands):
Beginning
Ending
Notional
Amount
January 2019
January 2020
$
300,000
January 2020
January 2021
$
300,000
January
2021
January 2022
$
300,000
January 2022
January 2023
$
250,000
During
the two year period ended September 30, 2019 we hedged approximately 44% of our floating rate debt with fixed-for-floating interest rate swaps. We expect to continue to utilize interest rate swaps to manage our exposure to LIBOR interest rates. Based on a sensitivity analysis for the twelve months ended September 30, 2019, we estimate that if short-term interest rates increased or decreased 100 basis points, our interest expense would have increased approximately $3.6 million and decreased approximately $3.6 million, respectively. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate
debt outstanding, adjusted for interest rate hedges.
Derivative Instruments
The following tables present our derivative assets and derivative liabilities measured at fair value on a recurring basis as of September 30, 2019:
The risk management activities for our refined products and natural gas segments involve managing exposures to the impact of market fluctuations in the price and transportation costs for commodities through the use of derivative instruments. The prices for energy commodities can be significantly influenced by market liquidity and changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. We monitor and manage our exposure to market risk on a daily basis in accordance with approved policies.
We maintain a control environment under the direction of our Chief Risk Officer through our risk management policy, processes and procedures, which our senior management has approved. Control
measures include volumetric, value at risk, and stop loss limits, as well as contract term limits. Our Chief Risk Officer and Risk Management Committee must approve the use of new instruments or new commodities. Risk limits are monitored and reported daily to senior management. Our risk management department also performs independent verifications of sources of fair values. These controls apply to all of our commodity risk management activities.
We use a value at risk model to monitor commodity price risk within our risk management activities. The value at risk model uses both linear and simulation methodologies based on historical information, with the results representing the potential loss in fair value over one day at a 95% confidence level. Results may vary from time to time as hedging coverage, market pricing levels and volatility
change.
We have a number of financial instruments that are potentially at risk including cash and cash equivalents, receivables and derivative contracts. Our primary exposure is credit risk related to our receivables and counterparty performance risk related to the fair value of derivative assets, which is the loss that may result from a customer’s or counterparty’s non-performance. We use credit policies to control credit risk, including utilizing an established credit approval process, monitoring customer and counterparty limits, employing credit mitigation measures such as analyzing customer financial statements, credit insurance with a third party provider and accepting personal guarantees and forms of collateral. We believe that our counterparties will be able to satisfy their contractual obligations. Credit risk is limited by the
large number of customers and counterparties comprising our business and their dispersion across different industries.
Cash is held in demand deposit and other short-term investment accounts placed with federally insured financial institutions. Such deposit accounts at times may exceed federally insured limits. We have not experienced any losses on such accounts.
Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership's reports under the Exchange Act is accumulated and communicated to the Partnership's management, including the President and Chief Executive Officer and the Chief Financial Officer of our General Partner, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of September 30, 2019, the Partnership carried out an evaluation, under the supervision and with the participation of management (including the President and Chief Executive Officer and Chief Financial Officer of the General Partner) of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on this evaluation, the General Partner's President and Chief Executive Officer and Chief Financial Officer concluded that the Partnership's disclosure controls and procedures were effective as of September 30, 2019.
Changes in Internal Control Over Financial Reporting
There
have been no changes in our system of internal control over financial reporting during the three months ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
From time to time, we are a party to various legal proceedings or claims arising in the ordinary course of business. For information related to legal proceedings, see the discussion under the captions Legal, Environmental and Other Proceedings in Note 10 - Commitments and Contingencies to our consolidated financial statements included in Part I, Item 1 of this Quarterly Report, which information is incorporated by reference into this Part II, Item 1.
Item 1A.
Risk Factors
In
addition to other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A “Risk Factors” included in our 2018 Annual Report, which could materially affect our business, financial condition or future results.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
