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Sprague Resources LP - Quarter Report: 2017 September (Form 10-Q)

Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-Q
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period                      to                     
Commission file number: 001-36137
 
Sprague Resources LP
(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
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o
Indicated by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  o
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. (Check one):
 
Large accelerated filer
o
Accelerated filer
x
 
 
 
 
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
o
 
 
 
 
Emerging growth company
o
 
 
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.   o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o  No  x
The registrant had 22,552,887 common units outstanding as of October 31, 2017.


Table of Contents


Table of Contents
 
 
 
Page
 
 
 
 
Item 1.
 
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
 
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.



Table of Contents


Part I – FINANCIAL INFORMATION
Item 1 — Condensed Consolidated Financial Statements
Sprague Resources LP
Condensed Consolidated Balance Sheets
(in thousands except units)
 
September 30,
2017
 
December 31,
2016
 
(Unaudited)
 
 
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
3,194

 
$
2,682

Accounts receivable, net
144,395

 
221,954

Inventories
249,101

 
318,899

Fair value of derivative assets
64,365

 
66,858

Other current assets
29,964

 
43,316

Total current assets
491,019

 
653,709

Property, plant and equipment, net
311,379

 
251,101

Intangibles, net
28,426

 
23,446

Other assets, net
80,174

 
13,668

Goodwill
85,655

 
70,550

Total assets
$
996,653

 
$
1,012,474

Liabilities and unitholders’ equity
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
62,276

 
$
138,358

Accrued liabilities
39,887

 
45,491

Fair value of derivative liabilities
71,041

 
95,339

Due to General Partner
6,886

 
14,218

Current portion of working capital facilities
22,332

 
153,603

Current portion of other obligations
6,343

 
4,190

Total current liabilities
208,765

 
451,199

Working capital facilities - less current portion
252,400

 
156,733

Acquisition facility
316,400

 
245,400

Other obligations - less current portion
41,725

 
16,955

Due to General Partner
1,623

 
1,269

Deferred income taxes
17,523

 
15,481

Total liabilities
838,436

 
887,037

Commitments and contingencies (Note 9)


 


Unitholders’ equity:
 
 
 
Common unitholders - public (10,437,179 units and 9,207,473 units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively)
206,868

 
175,314

Common unitholders - affiliated (12,106,348 and 2,034,378 units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively)
(38,793
)
 
(4,518
)
Subordinated unitholders - affiliated (10,071,970 units issued and outstanding as of December 31, 2016)
—

 
(34,576
)
Accumulated other comprehensive loss, net of tax
(9,858
)
 
(10,783
)
Total unitholders’ equity
158,217

 
125,437

Total liabilities and unitholders’ equity
$
996,653

 
$
1,012,474


The accompanying notes are an integral part of these financial statements.

1
Table of Contents


Sprague Resources LP
Unaudited Condensed Consolidated Statements of Operations
(in thousands except unit and per unit amounts)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Net sales
$
491,393

 
$
422,779

 
$
1,922,826

 
$
1,623,173

Cost of products sold (exclusive of depreciation and amortization)
456,656

 
383,211

 
1,720,860

 
1,463,938

Operating expenses
16,891

 
15,725

 
50,624

 
49,078

Selling, general and administrative
17,559

 
19,735

 
63,472

 
62,099

Depreciation and amortization
6,655

 
5,329

 
19,537

 
16,001

Total operating costs and expenses
497,761

 
424,000

 
1,854,493

 
1,591,116

Operating (loss) income
(6,368
)
 
(1,221
)
 
68,333

 
32,057

Other (expense) income
—

 
(19
)
 
183

 
(114
)
Interest income
75

 
40

 
247

 
379

Interest expense
(7,170
)
 
(6,685
)
 
(22,604
)
 
(20,179
)
(Loss) income before income taxes
(13,463
)
 
(7,885
)
 
46,159

 
12,143

Income tax (provision) benefit
(853
)
 
(909
)
 
(3,768
)
 
(861
)
Net (loss) income
(14,316
)
 
(8,794
)
 
42,391

 
11,282

Incentive distributions declared
(1,024
)
 
(488
)
 
(2,620
)
 
(1,144
)
Limited partners’ interest in net (loss) income
$
(15,340
)
 
$
(9,282
)
 
$
39,771

 
$
10,138

 
 
 
 
 
 
 
 
Net (loss) income per limited partner unit:
 
 
 
 
 
 
 
Common - basic
$
(0.68
)
 
$
(0.44
)
 
$
1.80

 
$
0.48

Common - diluted
$
(0.68
)
 
$
(0.44
)
 
$
1.78

 
$
0.46

Subordinated - basic and diluted
N/A

 
$
(0.44
)
 
N/A

 
$
0.48

Units used to compute net income per limited partner unit:
 
 
 
 
 
 
Common - basic
22,543,527

 
11,229,805

 
22,093,578

 
11,189,987

Common - diluted
22,543,527

 
11,229,805

 
22,368,432

 
11,506,830

Subordinated - basic and diluted
N/A

 
10,071,970

 
N/A

 
10,071,970

 
 
 
 
 
 
 
 
Distribution declared per unit
$
0.6225

 
$
0.5625

 
$
1.8225

 
$
1.6425









The accompanying notes are an integral part of these financial statements.

2
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Sprague Resources LP
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss)
(in thousands)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Net (loss) income
$
(14,316
)
 
$
(8,794
)
 
$
42,391

 
$
11,282

Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Unrealized gain (loss) on interest rate swaps
 
 
 
 
 
 
 
Net gain (loss) arising in the period
410

 
460

 
699

 
(1,176
)
Reclassification adjustment related to (loss) gain realized in income
(129
)
 
384

 
(13
)
 
1,182

Net change in unrealized gain on interest rate swaps
281

 
844

 
686

 
6

Tax effect
(3
)
 
(15
)
 
(10
)
 
—

 
278

 
829

 
676

 
6

Foreign currency translation adjustment
139

 
(925
)
 
249

 
(773
)
Other comprehensive income (loss)
417

 
(96
)
 
925

 
(767
)
Comprehensive (loss) income
$
(13,899
)
 
$
(8,890
)
 
$
43,316

 
$
10,515


















The accompanying notes are an integral part of these financial statements.

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Sprague Resources LP
Unaudited Condensed Consolidated Statements of Unitholders’ Equity (Deficit)
(in thousands)
 
 
Common-
Public
 
Common-
Sprague
Holdings
 
Subordinated-
Sprague
Holdings
 
Incentive Distribution Rights
 
Accumulated
Other
Comprehensive
Loss
 
Total
Balance at December 31, 2015
$
189,483

 
$
(1,370
)
 
$
(18,989
)
 
$
—

 
$
(11,639
)
 
$
157,485

Net income
3,815

 
847

 
4,192

 
1,312

 
—

 
10,166

Other comprehensive income
—

 
—

 
—

 
—

 
856

 
856

Unit-based compensation
1,820

 
404

 
2,000

 
—

 
—

 
4,224

Distributions paid
(19,894
)
 
(4,419
)
 
(21,878
)
 
(1,312
)
 
—

 
(47,503
)
Units issued with annual bonus
1,748

 
392

 
1,939

 
—

 
—

 
4,079

Units withheld for employee tax obligations
(1,658
)
 
(372
)
 
(1,840
)
 
—

 
—

 
(3,870
)
Balance at December 31, 2016
$
175,314

 
$
(4,518
)
 
$
(34,576
)
 
$
—

 
$
(10,783
)
 
$
125,437

Conversion of subordinated units to common units
—

 
(40,393
)
 
40,393

 
—

 
—

 
—

Net income
18,171

 
22,026

 
—

 
2,194

 
—

 
42,391

Other comprehensive income
—

 
—

 
—

 
—

 
925

 
925

Unit-based compensation
763

 
925

 
—

 
—

 
—

 
1,688

Distributions paid
(18,252
)
 
(16,146
)
 
(5,817
)
 
(2,194
)
 
—

 
(42,409
)
Units issued related to Carbo acquisition
31,401

 
—

 
—

 
—

 
—

 
31,401

Units issued with annual bonus
161

 
210

 
—

 
—

 
—

 
371

Units withheld for employee tax obligations
(690
)
 
(897
)
 
—

 
—

 
—

 
(1,587
)
Balance at September 30, 2017
$
206,868

 
$
(38,793
)
 
$
—

 
$
—

 
$
(9,858
)
 
$
158,217












The accompanying notes are an integral part of these financial statements.

4
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Sprague Resources LP
Unaudited Condensed Consolidated Statements of Cash Flows
(in thousands)
 
 
Nine Months Ended September 30,
 
2017
 
2016
Cash flows from operating activities
Net income
$
42,391

 
$
11,282

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization (includes amortization of deferred debt issuance costs)
23,881

 
18,961

Provision for doubtful accounts
(251
)
 
237

(Gain) loss on sale of assets
(101
)
 
106

Deferred income taxes
953

 
(69
)
Non-cash unit-based compensation
1,688

 
1,664

Changes in assets and liabilities:
 
 
 
Accounts receivable
77,660

 
27,086

Inventories
73,944

 
(25,064
)
Other assets
14,040

 
13,949

Fair value of commodity derivative instruments
(19,813
)
 
95,121

Due to General Partner and affiliates
(6,977
)
 
(5,960
)
Accounts payable, accrued liabilities and other
(80,524
)
 
(30,218
)
Net cash provided by operating activities
126,891

 
107,095

Cash flows from investing activities
 
 
 
Purchases of property, plant and equipment
(39,774
)
 
(11,436
)
Acquisitions, net of cash acquired
(72,184
)
 
(29,065
)
Proceeds from property insurance settlement and sale of assets
911

 
147

Net cash used in investing activities
(111,047
)
 
(40,354
)
Cash flows from financing activities
 
 
 
Net borrowings (payments) under credit agreements
35,003

 
(51,897
)
Net payments on other obligations
(1,977
)
 
(1,388
)
Debt issue costs
(4,483
)
 
(2,089
)
Distributions to unitholders
(42,409
)
 
(35,026
)
Foreign exchange on capital lease obligations
—

 
7

Units withheld for employee tax obligations
(1,587
)
 
(3,870
)
Net cash used in financing activities
(15,453
)
 
(94,263
)
Effect of exchange rate changes on cash balances held in foreign currencies
121

 
(3
)
Net change in cash and cash equivalents
512

 
(27,525
)
Cash and cash equivalents, beginning of period
2,682

 
30,974

Cash and cash equivalents, end of period
$
3,194

 
$
3,449

Supplemental disclosure of cash flow information
 
 
 
Cash paid for interest
$
18,293

 
$
17,730

Cash paid for taxes
$
1,601

 
$
755

Non-cash consideration related to Carbo acquisition:
 
 
 
     Common units issued
$
31,401

 
—

     Deferred consideration obligation
$
27,284

 
—

The accompanying notes are an integral part of these financial statements.

5
Table of Contents


Sprague Resources LP
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 to engage in the purchase, storage, distribution and sale of refined products and natural gas, and to provide storage and handling services for a broad range of materials.
Unless the context otherwise requires, references to “Sprague Resources” and the “Partnership” refer to Sprague Resources LP and its subsidiaries. Unless the context otherwise requires, references to “Axel Johnson” or the “Parent” or the "Sponsor" refer to Axel Johnson Inc. and its controlled affiliates, collectively, other than Sprague Resources, its subsidiaries and its General Partner. References to “Sprague Holdings” refer to Sprague Resources Holdings LLC, a wholly owned subsidiary of Axel Johnson and the owner of the General Partner. References to the “General Partner” refer to Sprague Resources GP LLC.
The Partnership owns, operates and/or controls a network of refined products and materials handling terminals located in the Northeast United States and in Quebec, Canada. The Partnership also utilizes third-party terminals in the Northeast United States through which it sells or distributes refined products pursuant to rack, exchange and throughput agreements. The Partnership has four business segments: refined products, natural gas, materials handling and other operations. The refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, kerosene, jet fuel, gasoline and asphalt (primarily from refining companies, trading organizations and producers), and sells them to wholesale and commercial customers. The natural gas segment purchases, sells and distributes natural gas to commercial and industrial customers in the Northeast and Mid-Atlantic United States. The Partnership purchases the natural gas it sells from natural gas producers and trading companies. The materials handling segment offloads, stores and prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. The Partnership’s other operations include the purchase and distribution of coal, certain commercial trucking activities and the heating equipment service business.
As of September 30, 2017, the Parent, through its ownership of Sprague Holdings, owns 12,106,348 common units representing 54% 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%, 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 partnership units that it owns. See Notes 11 and 12.
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, 2016 as filed with the SEC on March 10, 2017 (the “2016 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 revenues and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are asset valuations, the fair value of derivative assets and liabilities, environmental, and legal obligations.
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 2016 Annual Report, and are the same as are used in preparing these unaudited interim condensed consolidated financial statements.

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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, 2017 and December 31, 2016 and the consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, respectively, and the consolidated cash flows for the nine months ended September 30, 2017 and 2016, respectively. 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.
Recent Accounting Pronouncements
In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities. The objective of the guidance is to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership is currently evaluating the impact of this new standard on the 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 ASU will be applied prospectively, and is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for any impairment tests performed after January 1, 2017.
In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805), which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of this new guidance is not expected to have a material impact on the Partnership's consolidated financial statements.
In August 2016, the FASB issued ASU 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments which addresses eight specific cash flow issues with the objective of reducing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. The Partnership has not yet adopted the provisions of this ASU, which is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and is to be applied retrospectively to all periods presented. Early application is permitted, including adoption in an interim period. The adoption of this new guidance is not expected to have a material impact on the Partnership's consolidated statement of cash flows.
In March 2016, the FASB issued ASU 2016-09 Compensation- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which addresses areas for simplification involving several aspects of the accounting for share-based payment transactions including, among other things, income tax consequences of excess benefits and deficiencies, classification of awards as either equity or liabilities, classification on the statement of cash flows, and the use of forfeiture estimates. The Partnership adopted the provisions of this ASU in 2017, which did not have a material impact to the Partnership's consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02 Leases (Topic 842), which, among other things, requires lessees to recognize at the commencement date of a lease a liability, which is a lessee's 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. Under the new guidance, lessor accounting is largely unchanged. This ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. The Partnership is currently evaluating the impact of this new standard on the consolidated financial statements.

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In July 2015, the FASB issued ASU 2015-11 Simplifying the Measurement of Inventory, which requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The Partnership adopted the provisions of this ASU in 2017, which did not have a material impact to the Partnership's consolidated financial statements.
In May 2014, the FASB issued ASU 2014-9, Revenue from Contracts with Customers (Topic 606), which revises the principles of revenue recognition from one based on the transfer of risks and rewards to when a customer obtains control of a good or service. The FASB has issued several ASUs subsequent to ASU 2014-9 in order to clarify implementation guidance but did not change the core principle of the guidance in Topic 606. These ASUs are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership has reviewed and gained an understanding of the new revenue recognition accounting guidance, has completed a revenue stream scoping process and is working with business segment representatives to evaluate any necessary changes to business processes, systems and controls. In addition, the Partnership is continuing to review its contracts and documentation. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date our evaluation is not complete. We will conclude on the overall impacts of adopting Topic 606 prior to December 31, 2017. The Partnership currently expects to adopt this guidance on January 1, 2018, using the modified retrospective approach, under which the cumulative effect of initially applying the new guidance is recognized as an adjustment to the opening balance of unitholders' equity.
2. Business Combinations
During the nine months ended September 30, 2017, the Partnership completed four business acquisitions as described below. Allocations of the preliminary purchase price to the assets acquired and liabilities assumed have been made to record, where applicable, inventory, derivative assets and liabilities, natural gas transportation assets and liabilities, property, plant and equipment, identifiable intangible assets such as customer relationships and non-compete agreements as well as goodwill. Any net assets remaining to be allocated are included in Other Assets, net until the allocation is finalized. Proforma information related to these acquisition has not been presented because the impact on the Partnership’s Consolidated Statements of Operations is not material.
The Partnership is gathering information to complete the allocations which are expected to be finalized during 2017. The final allocations and resulting effect on income from operations may differ from these preliminary amounts. In connection with these transactions, the Partnership recognized $1.3 million of acquisition related costs during the nine months ended September 30, 2017 that were expensed and are included in selling, general and administrative expense.
Carbo Terminals    
On April 18, 2017, the Partnership acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under the Credit Agreement (see note 5), an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and $31.4 million in unregistered common units. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck. The operations of Carbo Industries, Inc. are included in the Partnership's refined products segment since the acquisition date.
The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at the acquisition date: 
Inventories
$
3,220

Other current assets, net
69

     Net assets remaining to be allocated
68,667

     Net assets acquired
$
71,956

Capital Terminal
On February 10, 2017, the Partnership purchased the East Providence, Rhode Island refined product terminal business of Capital Properties Inc. (the “Capital Terminal”). Consideration paid was $22.0 million and was financed with borrowings under the Credit Agreement. The terminal’s distillate storage capacity of 1.0 million barrels had been leased by the Partnership since April 2014 and was previously included in the Partnership’s total storage capacity. The operations of the Capital Terminal are included in the Partnership's refined products segment since the acquisition date.

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The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at the acquisition date: 
Property, plant and equipment
$
22,010

Accrued liabilities and other, net
(22
)
Net assets acquired
$
21,988

Global Natural Gas & Power
On February 1, 2017, the Partnership purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under the Credit Agreement. This business markets natural gas and electricity to commercial, industrial, municipal and institutional customer locations in the Northeast United States. The operations of Global Natural Gas & Power are included in the Partnership's natural gas segment since the acquisition date.
The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at the acquisition date: 
     Inventory
$
286

Derivative assets
12,326

Intangibles
5,046

Total identifiable assets acquired
17,658

Derivative liabilities
(10,997
)
     Net identifiable assets acquired
6,661

     Goodwill
9,592

     Net assets acquired
$
16,253



L.E. Belcher Terminal
On February 1, 2017, the Partnership purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for approximately $20.0 million, not including the purchase of inventory, assumption of derivative assets (liabilities) and other adjustments. Consideration paid was $20.7 million and was financed with borrowings under the Credit Agreement. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses. The operations of L.E. Belcher are included in the Partnership's refined products segment since the acquisition date.
The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at the acquisition date: 
Inventories
$
632

Derivative and other current assets
658

Property, plant and equipment
9,247

Intangibles
5,300

Total identifiable assets acquired
15,837

     Derivative and other current liabilities
(680
)
     Net identifiable assets acquired
15,157

     Goodwill
5,513

     Net assets acquired
$
20,670






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3. Accumulated Other Comprehensive Loss, Net of Tax
Amounts included in accumulated other comprehensive loss, net of tax, consisted of the following:
 
 
September 30,
2017
 
December 31, 2016
Fair value of interest rate swaps, net of tax
$
1,567

 
$
891

Cumulative foreign currency translation adjustment
(11,425
)
 
(11,674
)
Accumulated other comprehensive loss, net of tax
$
(9,858
)
 
$
(10,783
)
4. Inventories
 
September 30,
2017
 
December 31,
2016
Petroleum and related products
$
236,878

 
$
305,827

Asphalt
8,035

 
7,089

Coal
2,722

 
3,149

Natural gas
1,466

 
2,834

Inventories
$
249,101

 
$
318,899

5. Credit Agreement
 
September 30,
2017
 
December 31, 2016
Working capital facilities
$
274,732

 
$
310,336

Acquisition facility
316,400

 
245,400

Total credit agreement
591,132

 
555,736

Less: current portion of working capital facilities
(22,332
)
 
(153,603
)
Long-term portion
$
568,800

 
$
402,133


On April 27, 2017, Sprague Operating Resources LLC and Kildair Service ULC ("Kildair"), wholly owned subsidiaries of the Partnership, entered into an agreement that amended and restated the revolving credit agreement to extend the maturity through April 27, 2021, reduce the U.S. dollar working capital facility from $1.0 billion to $950.0 million, reduce the multicurrency working capital facility from $120.0 million to $100.0 million, reduce interest rates under certain leverage ratio scenarios, as well as make other modifications (the "Credit Agreement"). Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries.
As of September 30, 2017, the revolving credit facilities under the Credit Agreement contained, among other items, the following:
 
•
U.S. dollar revolving working capital facility of up to $950.0 million, subject to the Partnership's borrowing base limits, to be used by the Partnership for working capital loans and letters of credit;
•
Multicurrency revolving working capital facility of up to $100.0 million, subject to Kildair's borrowing base limits, to be used by Kildair for working capital loans and letters of credit;
•
Revolving acquisition facility of up to $550.0 million 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, the U.S. dollar revolving working capital facility may be increased by $250.0 million and the multicurrency revolving working capital facility may be increased by $220.0 million, subject to a maximum increase for both facilities of $270.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million.
Indebtedness under the Credit Agreement bears interest, at the borrowers’ option, at a rate per annum equal to either the Eurocurrency Base Rate (which is the LIBOR Rate for loans denominated in U.S. dollars and CDOR for loans denominated in Canadian dollars, in each case adjusted for certain regulatory costs) for interest periods of one, two, three or six months plus a specified margin or an alternate rate plus a specified margin.
For the U.S. dollar working capital facility and the acquisition facility, the alternate rate is the Base Rate which is the higher of (a) the U.S. Prime Rate as in effect from time to time, (b) the Federal Funds 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%.

10
Table of Contents


For the Canadian dollar working capital facility, 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, 2017 and December 31, 2016, had a borrowing base of $398.4 million and $525.4 million, respectively. As of September 30, 2017 and December 31, 2016, outstanding letters of credit were $31.2 million and $31.6 million, respectively. As of September 30, 2017, excess availability under the working capital facilities was $92.5 million and excess availability under the acquisition facilities was $233.6 million.
The weighted average interest rate was 3.7% and 3.4% at September 30, 2017 and December 31, 2016, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the Credit Agreement at September 30, 2017 and December 31, 2016 represents the amounts of the working capital facility intended to be repaid during the following twelve month period.
The Credit Agreement contains certain restrictions and covenants among which are a minimum level of net working capital, fixed charge coverage and debt leverage ratios and limitations on the incurrence of indebtedness. The Credit Agreement limits the Partnership’s ability to make distributions in the event of a default as defined in the Credit Agreement. As of September 30, 2017, the Partnership was in compliance with these covenants.
6. 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 $19.7 million and $21.0 million for the three months ended September 30, 2017 and 2016, and $67.9 million and $66.8 million for the nine months ended September 30, 2017 and 2016, respectively. Through the General Partner, the Partnership also participates in the Parent’s pension and other post-retirement benefits. At September 30, 2017 and December 31, 2016, total amounts due to the General Partner with respect to these benefits and overhead costs were $8.5 million and $15.5 million, respectively.
7. Segment Reporting
The Partnership has four reporting operating segments that comprise the structure used by the chief operating decision makers (CEO and CFO/COO) to make key operating decisions and assess performance. These segments are refined products, natural gas, materials handling and other activities.
The Partnership’s refined products segment purchases a variety of refined products, such as heating oil, diesel fuel, residual fuel oil, asphalt, 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, large industrial companies, real estate management companies, hospitals and educational institutions.
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 Partnership’s materials handling segment offloads, stores, and/or prepares for delivery a variety of customer-owned products, including asphalt, clay slurry, salt, gypsum, crude oil, residual fuel oil, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. These services are fee-based activities which are generally conducted under multi-year agreements.
The Partnership’s other activities include the purchase, sale and distribution of coal, commercial trucking activities unrelated to its refined products segment and a heating equipment service business. Other activities are not reported separately as they represent less than 10% of consolidated net sales and adjusted gross margin.
The Partnership evaluates segment performance based on adjusted gross margin, a non-GAAP measure, which is net sales less cost of products sold (exclusive of depreciation and amortization) increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts.

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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, 2017 and 2016, respectively. The Partnership’s foreign sales, primarily sales of refined products, asphalt and natural gas to its customers in Canada, were $82.5 million and $55.2 million for the three months ended September 30, 2017 and 2016, and $187.1 million and $124.1 million for the nine months ended September 30, 2017 and 2016, respectively.
Summarized financial information for the Partnership’s reportable segments is presented in the table below:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Net sales:
 
 
 
 
 
 
 
Refined products
$
425,492

 
$
350,528

 
$
1,638,066

 
$
1,331,197

Natural gas
49,694

 
55,868

 
235,068

 
240,256

Materials handling
11,395

 
11,304

 
34,118

 
35,848

Other operations
4,812

 
5,079

 
15,574

 
15,872

Net sales
$
491,393

 
$
422,779

 
$
1,922,826

 
$
1,623,173

Adjusted gross margin (1):
 
 
 
 
 
 
 
Refined products
$
32,014

 
$
38,693

 
$
95,307

 
$
104,070

Natural gas
3,197

 
2,773

 
44,355

 
43,734

Materials handling
11,395

 
11,305

 
34,118

 
35,826

Other operations
1,897

 
1,985

 
5,800

 
6,257

Adjusted gross margin
48,503

 
54,756

 
179,580

 
189,887

Reconciliation to operating income (loss) (2):
 
 
 
 
 
 
 
Add: unrealized gain (loss) on inventory derivatives (3)
(13,673
)
 
(14,636
)
 
15,374

 
(26,592
)
Add: unrealized gain on prepaid forward contract derivatives (4)
667

 
120

 
907

 
1,161

Add: unrealized (loss) gain on natural gas transportation contracts (5)
(760
)
 
(672
)
 
6,105

 
(5,221
)
Operating costs and expenses not allocated to operating segments:
 
 
 
 
 
 
 
Operating expenses
(16,891
)
 
(15,725
)
 
(50,624
)
 
(49,078
)
Selling, general and administrative
(17,559
)
 
(19,735
)
 
(63,472
)
 
(62,099
)
Depreciation and amortization
(6,655
)
 
(5,329
)
 
(19,537
)
 
(16,001
)
Operating (loss) income
(6,368
)
 
(1,221
)
 
68,333

 
32,057

Other (expense) income
—

 
(19
)
 
183

 
(114
)
Interest income
75

 
40

 
247

 
379

Interest expense
(7,170
)
 
(6,685
)
 
(22,604
)
 
(20,179
)
Income tax (provision) benefit
(853
)
 
(909
)
 
(3,768
)
 
(861
)
Net (loss) income
$
(14,316
)
 
$
(8,794
)
 
$
42,391

 
$
11,282


(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 hedging gains and losses with regard to refined products and natural gas inventory derivatives, prepaid forward contract derivatives and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income. These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory, prepaid fixed forwards and the utilization of transportation contracts relating to those hedges is realized in net income. Adjusted gross margin has no impact on reported volumes or net sales.
(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 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.

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Table of Contents


(4)
The unrealized hedging gain (loss) on prepaid forward contract derivatives represents the Partnership’s estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income. The fair value of the derivatives the Partnership uses to economically hedge its prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines, which creates unrealized hedging gains (losses) that are included in net income.
(5)
The unrealized hedging gain (loss) on natural gas transportation contracts 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 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 as of each period end.
Segment Assets
Due to the commingled nature and uses of the Partnership’s fixed assets, the Partnership does not track its fixed assets between its refined products and materials handling operating segments or its other activities. There are no significant fixed assets attributable to the natural gas reportable segment.
At September 30, 2017, goodwill recorded for the refined products, natural gas, materials handling and other operations segments amounted to $42.1 million, $35.5 million, $6.9 million and $1.2 million, respectively. The Partnership expects additional goodwill to be recorded once the allocation of the Carbo business combination entered into in April 2017 is finalized. See Note 2 - Business Combinations.
8. Financial Instruments and Off-Balance Sheet Risk
As of September 30, 2017 and December 31, 2016, the carrying amounts of cash, cash equivalents and accounts receivable approximated fair value because of the short maturity of these instruments. As of September 30, 2017 and December 31, 2016, 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. As of September 30, 2017 and December 31, 2016, the carrying value of the Partnership’s debt approximated fair value due to the variable interest nature of these instruments.
Derivative Instruments
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. In addition, the Partnership may either pay or receive margin based upon exposure with counterparties. Payments made by the Partnership are included in other current assets, whereas payments received by the Partnership are included in accrued liabilities. Substantially all of the Partnership’s commodity derivative contracts outstanding as of September 30, 2017 will settle prior to March 31, 2019.
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.

13
Table of Contents


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 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, 2017 and December 31, 2016.
The following table presents financial assets and financial liabilities of the Partnership measured at fair value on a recurring basis:
 
 
As of September 30, 2017
 
Fair Value
Measurement
 
Quoted
Prices in
Active
Markets
Level 1
 
Significant
Other
Observable
Inputs
Level 2
 
Significant
Unobservable
Inputs
Level 3
Financial assets:
 
 
 
 
 
 
 
Commodity fixed forwards
$
62,367

 
$
—

 
$
62,367

 
$
—

Commodity swaps and options
173

 
—

 
173

 
—

Commodity derivatives
62,540

 
—

 
62,540

 
—

Interest rate swaps
1,825

 
—

 
1,825

 
—

Total
$
64,365

 
$
—

 
$
64,365

 
$
—

Financial liabilities:
 
 
 
 
 
 
 
Commodity fixed forwards
$
70,692

 
$
—

 
$
70,692

 
$
—

Commodity swaps and options
112

 
—

 
112

 
—

Commodity derivatives
70,804

 
—

 
70,804

 
—

Interest rate swaps
235

 
—

 
235

 
—

Currency swap derivative liabilities
2

 
—

 
2

 
—

Total
$
71,041

 
$
—

 
$
71,041

 
$
—


14
Table of Contents


 
As of December 31, 2016
 
Fair Value
Measurement
 
Quoted
Prices in
Active
Markets
Level 1
 
Significant
Other
Observable
Inputs
Level 2
 
Significant
Unobservable
Inputs
Level 3
Financial assets:
 
 
 
 
 
 
 
Commodity fixed forwards
$
65,618

 
$
—

 
$
65,618

 
$
—

Commodity derivatives
65,618

 
—

 
65,618

 
—

Interest rate swaps
1,240

 
—

 
1,240

 
—

Total
$
66,858

 
$
—

 
$
66,858

 
$
—

Financial liabilities:
 
 
 
 
 
 
 
Commodity fixed forwards
$
94,875

 
$
—

 
$
94,875

 
$
—

Commodity swaps and options
103

 
—

 
103

 
—

Commodity derivatives
94,978

 
—

 
94,978

 
—

Interest rate swaps
336

 
—

 
336

 
—

Other
25

 
—

 
25

 
—

Total
$
95,339

 
$
—

 
$
95,339

 
$
—


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 $60.2 million at September 30, 2017. Information related to these offsetting arrangements is set forth below:
 
As of September 30, 2017
 
 
 
 
 
Gross Amount Not Offset in
the Balance Sheet
 
 
 
Gross Amount of
Recognized
Assets/
Liabilities
 
Gross
Amount
Offset in the
Balance Sheet
 
Amount of
Assets/
Liabilities
in the
Balance Sheet
 
Financial
Instruments
 
Cash
Collateral
Posted
 
Net Amount
Commodity derivative assets
$
62,540

 
$
—

 
$
62,540

 
$
(4,141
)
 
$
(13
)
 
$
58,386

Interest rate swap derivative assets
1,825

 
—

 
1,825

 
—

 
—

 
1,825

Fair value of derivative assets
$
64,365

 
$
—

 
$
64,365

 
$
(4,141
)
 
$
(13
)
 
$
60,211

 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative liabilities
$
(70,804
)
 
$
—

 
$
(70,804
)
 
$
4,141

 
$
—

 
$
(66,663
)
Interest rate swap derivative liabilities
(235
)
 
—

 
(235
)
 
—

 
—

 
(235
)
Other liabilities
(2
)
 
—

 
(2
)
 
—

 
—

 
(2
)
Fair value of derivative liabilities
$
(71,041
)
 
$
—

 
$
(71,041
)
 
$
4,141

 
$
—

 
$
(66,900
)

 
As of December 31, 2016
 
 
 
 
 
 
 
Gross Amount Not Offset in
the Balance Sheet
 
 
 
Gross Amount of
Recognized
Assets/
Liabilities
 
Gross
Amount
Offset in the
Balance Sheet
 
Amount of
Assets/
Liabilities
in the
Balance Sheet
 
Financial
Instruments
 
Cash
Collateral
Posted
 
Net Amount
Commodity derivative assets
$
65,618

 
$
—

 
$
65,618

 
$
(2,154
)
 
$
(209
)
 
$
63,255

Interest rate swap derivative assets
1,240

 
—

 
1,240

 
—

 
—

 
1,240

Fair value of derivative assets
$
66,858

 
$
—

 
$
66,858

 
$
(2,154
)
 
$
(209
)
 
$
64,495

 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative liabilities
$
(94,978
)
 
$
—

 
$
(94,978
)
 
$
2,154

 
$
—

 
$
(92,824
)
Interest rate swap derivative liabilities
(336
)
 
—

 
(336
)
 
—

 
—

 
(336
)
Other liabilities
(25
)
 
—

 
(25
)
 
—

 
—

 
(25
)
Fair value of derivative liabilities
$
(95,339
)
 
$
—

 
$
(95,339
)
 
$
2,154

 
$
—

 
$
(93,185
)


15
Table of Contents


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):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Refined products contracts
$
(17,281
)
 
$
2,957

 
$
27,637

 
$
(2,176
)
Natural gas contracts
(908
)
 
(3,370
)
 
13,850

 
16,472

Total
$
(18,189
)
 
$
(413
)
 
$
41,487

 
$
14,296

There were no discretionary trading activities for the three and nine months ended September 30, 2017 and 2016. The following table presents gross volume of commodity derivative instruments outstanding for the periods indicated:
 
 
As of September 30, 2017
 
As of December 31, 2016
 
Refined Products
(Barrels)
 
Natural Gas
(MMBTUs)
 
Refined Products
(Barrels)
 
Natural Gas
(MMBTUs)
Long contracts
6,785

 
132,367

 
9,882

 
131,240

Short contracts
(10,051
)
 
(71,639
)
 
(13,940
)
 
(76,556
)
Interest Rate Derivatives
The Partnership has entered into interest rate swaps to manage its exposure to changes in interest rates on its Credit Agreement. The Partnership’s interest rate swaps hedge actual and forecasted LIBOR borrowings have been designated as cash flow hedges. Counterparties to the Partnership’s interest rate swaps are large multinational banks and the Partnership does not believe there is a material risk of counterparty non-performance.
The Partnership's interest rate swap agreements outstanding as of September 30, 2017 were as follows:
Interest Rate Swap Agreements
Beginning
 
Ending
 
Notional Amount
January 2017
 
January 2018
 
$
225,000

January 2018
 
January 2019
 
$
275,000

January 2019
 
January 2020
 
$
125,000

January 2020
 
January 2021
 
$
50,000

January 2021
 
January 2022
 
$
50,000

There was no material ineffectiveness determined for the cash flow hedges for the three and nine months ended September 30, 2017 and 2016.
The Partnership records unrealized gains and losses on its interest rate swaps as a component of accumulated other comprehensive loss, net of tax, which is reclassified to earnings as interest expense when the payments are made. As of September 30, 2017, the amount of unrealized gains, net of tax, expected to be reclassified to earnings during the following twelve-month period was $0.8 million.
9. Commitments and Contingencies
Legal, Environmental and Other Proceedings
The Partnership is involved in 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.

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10. Equity and Equity-Based Compensation
Equity Awards - Annual Bonus Program
The board of directors of the General Partner has approved an annual bonus program which is provided to substantially all employees. Under this program bonuses for the majority of participants will be settled in cash with others receiving a combination of cash and common units. The Partnership records the expected bonus payment as a liability until a grant date has been established and awards finalized, which occurs in the first quarter of the year following the year for which the bonus is earned. Of the annual bonus accrued as of December 31, 2016, approximately $0.4 million was subsequently settled by issuing 13,465 common units in 2017 (market value at settlement of $0.4 million) with 4,625 units being withheld to satisfy tax withholding obligations.
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). Upon vesting, a holder of performance-based phantom units is entitled to receive a number of common units of the Partnership equal to a percentage (between 0 and 200%) of the phantom units granted, based on the Partnership’s achieving pre-determined performance criteria. The Partnership uses authorized but unissued units to satisfy its unit-based obligations.

TUR-based Phantom Units
Phantom unit awards granted in 2015 and 2014, include a market condition criteria that considers the Partnership's total unitholder return ("TUR") over the vesting period, compared with the total unitholder return of a peer group of other master limited partnership energy companies over the same period. These awards are equity awards with both service and market-based conditions, which results in compensation cost being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market based conditions are satisfied. The fair value of the TUR based phantom units was estimated at the date of grant based on a Monte Carlo model that estimates the most likely performance outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership’s common units as of the valuation date, the historical volatility of the market price of the Partnership’s common units, the historical volatility of the market price of the common units or common stock of the peer companies and the correlation between changes in the market price of the Partnership’s common units and those of the peer companies. TUR-based phantom units issued in 2014 with a performance period ending as of December 31, 2016 vested at the 200% level and as a result 142,100 common units (vested market value of $3.9 million) were issued during January 2017 with 52,785 units being withheld to satisfy tax withholding obligations.

OCF-based Phantom Units
Phantom unit awards granted in 2017 and 2016 include a performance criteria that considers Sprague Holdings operating cash flow, as defined ("OCF"), over a three year performance period. The number of common units that may be received in settlement of each phantom unit award can range between 0 and 200% of the number of phantom units granted based on the level of OCF achieved during the vesting period. These awards are equity awards with performance and service conditions which result in compensation cost being recognized over the requisite service period once payment is determined to be probable. Compensation expense related to the OCF based awards is estimated each reporting period by multiplying the number of common units underlying such awards that, based on the Partnership's estimate of OCF, are probable to vest, by the grant-date fair value of the award and is recognized over the requisite service period using the straight-line method. The fair value of the OCF based phantom units was the grant date closing price listed on the New York Stock Exchange. The number of units that the Partnership estimates are probable to vest could change over the vesting period. Any such change in estimate is recognized as a cumulative adjustment calculated as if the new estimate had been in effect from the grant date.

Distribution Equivalent Rights
The Partnership's 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.

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A summary of the Partnership’s unit awards subject to vesting during the nine months ended September 30, 2017 is set forth below:
 
2017 Phantom Units
(OCF-based)
 
2016 Phantom Units
(OCF-based)
 
2015 Phantom Units
(TUR-based)
 
Units
 
Weighted
Average
Grant Date
Fair Value
(per unit)
 
Units
 
Weighted
Average
Grant Date
Fair Value
(per unit)
 
Units
 
Weighted
Average
Grant Date
Fair Value
(per unit)
Nonvested at December 31, 2016
—

 
$
—

 
166,900

 
$
17.52

 
141,000

 
$
31.58

  Granted
132,977

 
26.62

 
—

 
—

 
—

 
—

  Forfeited
(1,977
)
 
(26.60
)
 
(3,000
)
 
(17.52
)
 
(2,000
)
 
(31.58
)
  Vested
—

 
—

 
—

 
—

 
—

 
—

Nonvested at September 30, 2017
131,000

 
$
26.62

 
163,900

 
$
17.52

 
139,000

 
$
31.58

Unit-based compensation recorded in unitholders’ equity for the three months ended September 30, 2017 and 2016 was $(0.2) million and $0.8 million, and for the nine months ended September 30, 2017 and 2016 was $1.7 million and $2.6 million, respectively, and is included in selling, general and administrative expenses. Unrecognized compensation cost related to performance-based phantom unit awards totaled $4.4 million as of September 30, 2017 which is expected to be recognized over a weighted average period of 14 months.
Equity - Changes in Partnership Units
Pursuant to the terms of the partnership agreement, upon payment of the cash distribution on February 14, 2017, and meeting certain distribution and performance tests, the subordination period for the Partnership's subordinated units expired and all subordinated units converted into common units on a one-for-one basis.
The following table provides information with respect to changes in the Partnership’s units:
 
 
Common Units
 
Subordinated
Units
 
Public
 
Sprague
Holdings
 
Sprague
Holdings
Balance as of December 31, 2016
9,207,473

 
2,034,378

 
10,071,970

Conversion of subordinated units
—

 
10,071,970

 
(10,071,970
)
Units issued in connection with phantom and performance awards
89,315

 
—

 
—

Units issued in connection with employee bonus
8,840

 
—

 
—

Units issued in connection with Carbo acquisition
1,131,551

 
—

 
—

Balance as of September 30, 2017
10,437,179

 
12,106,348

 
—

11. Earnings Per Unit
Earnings per unit applicable to limited partners (including subordinated unitholders) is computed by dividing limited partners’ interest in net income (loss), after deducting any incentive distributions, by the weighted-average number of outstanding common and subordinated units. The Partnership’s net income is allocated to the limited partners in accordance with their respective ownership percentages, after giving effect to priority income allocations for incentive distributions, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the limited partners based on their respective ownership interests. Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income (loss) allocations used in the calculation of earnings (loss) per unit. Quarterly net income (loss) 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.
In addition to the common and subordinated units, the Partnership has also identified the IDRs and unvested unit awards as participating securities and uses the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of units outstanding during the period. Diluted earnings per unit includes the effects of potentially dilutive units on the Partnership’s common units, consisting of unvested unit awards. Basic and diluted earnings per unit applicable to subordinated limited partners are the same because there are no potentially dilutive subordinated units outstanding.

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The following table shows the weighted average common units outstanding used to compute net income per common unit for the periods indicated.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Weighted average limited partner common units - basic
22,543,527

 
11,229,805

 
22,093,578

 
11,189,987

Dilutive effect of unvested phantom units
—

 
—

 
274,854

 
316,843

Weighted average limited partner common units - dilutive
22,543,527

 
11,229,805

 
22,368,432

 
11,506,830


All outstanding subordinated units converted to common units on February 16, 2017. Since the subordinated units did not share in the distribution of cash generated during the three and nine months ended September 30, 2017, the Partnership did not allocate any earnings or loss to the subordinated unitholders. The following tables provide a reconciliation of net income and the assumed allocation of net income to the limited partners’ interest for purposes of computing net income per unit during periods prior to the conversion of the subordinated units:

 
Three Months Ended September 30, 2016
 
Common
 
Subordinated
 
IDR
 
Total
 
(in thousands, except for per unit amounts)
Net loss
 
 
 
 
 
 
$
(8,794
)
Distributions declared
$
6,324

 
$
5,665

 
$
488

 
$
12,477

Assumed net loss from operations after distributions
(11,217
)
 
(10,054
)
 
—

 
(21,271
)
Assumed net loss to be allocated
$
(4,893
)
 
$
(4,389
)
 
$
488

 
$
(8,794
)
Loss per unit - basic
$
(0.44
)
 
$
(0.44
)
 
 
 
 
Loss per unit - diluted
$
(0.44
)
 
$
(0.44
)
 
 
 
 

 
Nine Months Ended September 30, 2016
 
Common
 
Subordinated
 
IDR
 
Total
 
(in thousands, except for per unit amounts)
Net income
 
 
 
 
 
 
$
11,282

Distributions declared
$
18,455

 
$
16,542

 
$
1,144

 
$
36,141

Assumed net income from operations after distributions
(13,119
)
 
(11,740
)
 
—

 
(24,859
)
Assumed net income to be allocated
$
5,336

 
$
4,802

 
$
1,144

 
$
11,282

Income per unit - basic
$
0.48

 
$
0.48

 
 
 
 
Income per unit - diluted
$
0.46

 
$
0.48

 
 
 
 
12. Partnership Distributions
The Partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders will receive as well as incentive distributions. Payments made in connection with DERs are recorded as a distribution.
Cash distributions for the periods indicated were as follows:
For the Quarter Ended
 
Payment Date
 
Per Unit
 
Common
 
Subordinated
 
IDR
 
DER
 
Total
December 31, 2016
 
February 14, 2017
 
$0.5775
 
$
6,544

 
$
5,817

 
$
597

 
$
802

 
$
13,760

March 31, 2017
 
May 15, 2017
 
$0.5925
 
$
13,357

 
$
—

 
$
742

 
$
—

 
$
14,099

June 30, 2017
 
August 11, 2017
 
$0.6075
 
$
13,696

 
$
—

 
$
854

 
$
—

 
$
14,550

September 30, 2017 (1)
 
November 13, 2017
 
$0.6225
 
$
14,039

 
$
—

 
$
1,024

 
$
—

 
$
15,063

(1)
On October 26, 2017, the Partnership declared a cash distribution of $0.6225 per unit to be paid to unitholders of record on November 6, 2017.

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13. Subsequent Events
Coen Energy Acquisition
On October 1, 2017, the Partnership purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC, as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Initial consideration, not including the purchase of inventory and other adjustments, was $35.3 million in cash which was financed with borrowings under the Credit Agreement. Contingent consideration of up to $12 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020.
Coen Energy, located in Washington, PA, currently provides energy products and complimentary energy field services to over 7,000 energy field services, commercial, and residential customers located in Pennsylvania, Ohio and West Virginia. Coen Energy's Field Services segment provides fuel sales, delivery and related services supporting Marcellus and Utica shale drilling activity. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees.



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Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q (“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 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, 2016, as filed with the U.S. Securities and Exchange Commission (“SEC”) on March 10, 2017 (the “2016 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.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the Partnership’s financial statements and related notes thereto as of and for the three and nine months ended September 30, 2017 contained elsewhere in this Quarterly Report and the audited financial statements and related notes included in our 2016 Annual Report.

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Overview
We are a Delaware limited partnership formed in June 2011 by Sprague Holdings and our General Partner to engage in the purchase, storage, distribution and sale of refined products and natural gas, and to provide storage and handling services for a broad range of materials. Our limited partnership units representing limited partner interests are listed on the New York Stock Exchange ("NYSE") under the ticker symbol “SRLP". As used in this Quarterly Report, unless otherwise indicated, “we,” “us,” “our” mean Sprague Resources LP and, where the context requires, includes our subsidiaries.
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 capacity of 14.8 million barrels for refined products and other liquid materials, as well as 2.0 million square feet of materials handling capacity. We also have an aggregate of 1.9 million barrels of additional storage capacity attributable to 49 storage tanks not currently in service. These tanks are not necessary for the operation of our business at current levels. In the event that such additional capacity were desired, additional time and capital would be required to bring any of such storage tanks into service. Furthermore, we have access to more than 50 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 “Segment Reporting” included under Note 7 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 Operation—Results of Operation” 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, gasoline and asphalt (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 more than 900 home heating oil retailers and diesel fuel and gasoline resellers. Our commercial customers include federal and state agencies, municipalities, regional transit authorities, large industrial companies, real estate management companies, hospitals, educational institutions and asphalt paving companies. For the three months ended September 30, 2017 and 2016, we sold 251.5 million and 237.5 million gallons of refined products and for the nine months ended September 30, 2017 and 2016, we sold 1.0 billion and 1.0 billion gallons, respectively.
In our natural gas segment we purchase, sell and distribute natural gas to approximately 16,000 commercial and industrial customer locations across 13 states in the Northeast and Mid-Atlantic United States. We purchase the natural gas from natural gas producers and trading companies. For the three months ended September 30, 2017 and 2016 we sold 11.0 million Bcf and 11.8 million Bcf of natural gas and for the nine months ended September 30, 2017 and 2016, we sold 44.7 million and 44.8 million Bcf, respectively.
Our materials handling segment is a fee-based business and is generally conducted under multi-year agreements. We offload, store and/or prepare for delivery a variety of customer-owned products, including asphalt, crude oil, residual fuel, clay slurry, salt, gypsum, coal, petroleum coke, caustic soda, tallow, pulp and heavy equipment. For the three months ended September 30, 2017 we offloaded, stored and/or prepared for delivery 0.6 million short tons of products and 74.2 million gallons of liquid materials. For the three months ended September 30, 2016, we offloaded, stored and/or prepared for delivery 0.8 million short tons of products and 78.3 million gallons of liquid materials. For the nine months ended September 30, 2017 we offloaded, stored and/or prepared for delivery 1.9 million short tons of products and 301.9 million gallons of liquid materials. For the nine months ended September 30, 2016, we offloaded, stored and/or prepared for delivery 2.0 million short tons of products and 234.7 million gallons of liquid materials.
Our other operations segment includes the marketing and distribution of coal conducted in our Portland, Maine terminal, commercial trucking activity conducted by our Canadian subsidiary and our heating equipment service business.
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.

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As of September 30, 2017, our Sponsor, through its ownership of Sprague Holdings, owns 12,106,348 common units representing an aggregate of 54% 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.
Recent Developments
Coen Energy Acquisition
On October 1, 2017 we purchased the membership interests of Coen Energy, LLC and Coen Transport, LLC as well as assets consisting of four bulk plants and underlying real estate (collectively, “Coen Energy”). Coen Energy, located in Washington, PA, provides energy products and complimentary energy field services to over 7,000 Energy Field Services, Commercial, and Residential customers located in Pennsylvania, Ohio and West Virginia. The Energy Field Services segment provides fuel sales, delivery, management and related services supporting the Marcellus and the Utica shale drilling activity. The Coen Energy business is supported by four in-land bulk plants, two throughput locations, approximately 100 delivery vehicles and approximately 250 employees.
Initial consideration paid was $35.3 million in cash, not including the purchase of inventory and other adjustments, which was financed with borrowings under our credit facility. Contingent consideration of up to $12 million is payable based on achieving certain economic performance measures during the three year period ending September 30, 2020.
Carbo Terminals Acquisition
On April 18, 2017, we acquired substantially all of the assets of Carbo Industries, Inc. and certain of its affiliates (together “Carbo”) by purchasing Carbo's Inwood and Lawrence, New York refined product terminal assets and its associated wholesale distribution business. The fair value of the consideration totaled $72.0 million and consisted of $13.3 million in cash that was financed through borrowings under our credit facility, an obligation to pay $38.2 million over a ten year period (estimated net present value of $27.3 million) and $31.4 million in unregistered common units. The Carbo terminals have a combined gasoline, ethanol and distillate storage capacity of 174,000 barrels and are supplied primarily by pipeline with the ability to also accept product deliveries by barge and truck.
Capital Terminal Acquisition
On February 10, 2017, we acquired the East Providence, Rhode Island refined product terminal of Capital Terminal Company (the “Capital Terminal”). Consideration paid was $22.0 million and was financed with borrowings under our credit facility. The terminal’s combined distillate storage capacity of just over 1.0 million barrels had been leased by us since April 2014 and was previously included in our total storage capacity.
In conjunction with this acquisition, we undertook an expansion capital project to convert half of the terminal’s storage capacity to gasoline and ethanol service to support a new ten year fee-for-service gasoline storage and handling agreement with a major East Coast gasoline marketer and another project to optimize distillate storage between this newly acquired terminal and our existing terminal facility in Providence to allow for expanded materials handling capability. Both projects are expected to be completed prior to December 31, 2017 at a total cost of approximately $16 million.
Global Natural Gas & Power Acquisition
On February 1, 2017, we purchased the natural gas marketing and electricity brokering business of Global Partners LP ("Global Natural Gas & Power") for $17.3 million, not including the purchase of natural gas inventory, assumption of derivative liabilities and other adjustments. Consideration paid was $16.3 million and was financed with borrowings under our credit facility. The business serves approximately 4,000 commercial, industrial, municipal and institutional customer locations in the Northeast United States with approximately 8 billion cubic feet of natural gas and 1 billion kWh of electricity annually.
L.E. Belcher Terminal Acquisition
On February 1, 2017, we purchased the Springfield, Massachusetts refined product terminal assets of Leonard E. Belcher, Incorporated (“L.E. Belcher”) for approximately $20.0 million in cash, not including the purchase of inventory and other adjustments. Consideration paid was $20.7 million and was financed with borrowings under our credit facility. The purchase consists of two pipeline-supplied distillate terminals and one distillate storage facility with a combined capacity of 283,000 barrels, as well as L.E. Belcher’s associated wholesale and commercial fuels businesses.


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Amendment to Credit Agreement
On April 27, 2017, we entered into an agreement to amend the Credit Agreement to extend the maturity through April 27, 2021, reduce the U.S. dollar working capital facility from $1.0 billion to $950.0 million, reduce the multicurrency working capital facility from $120 million to $100 million, reduce interest rates under certain leverage ratio scenarios and make other modifications. See Part I, Item 2 "Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Credit Agreement.”
Conversion of Subordinated Units
Pursuant to the terms of our partnership agreement, upon payment of the cash distribution on February 14, 2017, and meeting certain distribution and performance tests, the subordination period for our subordinated units expired on February 16, 2017. At the expiration of the subordination period, all 10,071,970 subordinated units converted into common units on a one-for-one basis.
Non-GAAP Financial Measures
We present the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin in this Quarterly Report as described below.

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 (described below), (2) operating expenses, (3) selling, general and administrative (or SG&A) expenses and (4) heating degree days.
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, the viability of acquisitions and capital expenditure projects and 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 unit holders.
We define EBITDA as net income (loss) before interest, income taxes, depreciation and amortization. We define adjusted EBITDA as EBITDA increased by unrealized hedging losses and decreased by unrealized hedging gains, in each case with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts.
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, 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 an alternative 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 is defined differently by different

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companies, our definitions of EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies.
We recognize that the usefulness of EBITDA and adjusted EBITDA as an evaluative tool may have certain limitations, including:
 
•
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 hedging gains and losses with regard to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts, which are not marked to market for the purpose of recording unrealized gains or losses in net income (loss). These adjustments align the unrealized hedging gains and losses to the period in which the revenue from the sale of inventory, prepaid fixed forwards and the utilization of transportation contracts relating to those hedges is realized 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 its 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, prepaid forward contracts and natural gas transportation contracts. Adjusted gross margin has no impact on reported volumes or net sales.
Adjusted gross margin is used as supplemental financial measures by management to describe our operations and economic performance to investors, trade suppliers, research analysts and commercial banks to assess:
 
•
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 alternatives to net income (loss) or operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define adjusted unit gross margin as adjusted gross margin divided by units sold, as expressed in gallons for refined products, and in MMBtus for natural gas.
For a reconciliation of adjusted gross margin and adjusted EBITDA to the GAAP measures most directly comparable, see the reconciliation tables included in "Results of Operations." See "Segment Reporting" included under Note 7 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

25
Table of Contents


reasonably possible for us to allocate the components of operating expenses, selling, general and administrative expenses and depreciation and amortization among the operating segments.
Operating Expenses
Operating expenses are costs associated with the operation of the terminals and truck fleet used in our business. Employee wages, pension and 401(k) plan expenses, boiler fuel, repairs and maintenance, utilities, insurance, property taxes, services and lease payments comprise the most significant portions of our operating expenses. Employee wages and related employee expenses included in our operating expenses are incurred on our behalf by our General Partner and reimbursed by us. These expenses remain relatively stable independent of the volumes through our system but can fluctuate depending on the activities performed during a specific period.
Selling, General and Administrative Expenses
Selling, general and administrative expenses ("SG&A") include employee salaries and benefits, discretionary bonus, marketing costs, corporate overhead, professional fees, information technology and office space expenses. Employee wages, related employee expenses and certain rental costs included in our SG&A expenses are incurred on our behalf by our General Partner and reimbursed by us.
Heating Degree Days
A “degree day” is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how much the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated over the course of a year and can be compared to a monthly or a long-term average (“normal”) to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2010.
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 statement of operations. In contrast, in a declining commodity price market we generally incur hedging gains. GAAP requires us to record those hedging gains in our statement of operations. The refined products inventory market valuation is calculated daily using independent bulk market price assessments from major pricing services (either Platts or Argus). These third-party price assessments are primarily based in 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 statement of operations 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 statement of operations. The natural gas transportation assets market value is calculated daily based on the volume and prices at the corresponding pipeline locations. The daily prices are based on trader assessed quotes which represent observable

26
Table of Contents


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 2016 Annual Report for a discussion of the trends and factors that impact our business.

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Table of Contents


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 year can create lower gross margins as the economic hedges, or derivatives, for such inventory may lose value, whereas an increase in the value of such inventory is disregarded for GAAP financial reporting purposes and recorded at the lower of cost or net realizable value. Please read “How Management Evaluates Our Results of Operations.” For a description of acquisition activity during the periods presented, please read "Business Combinations" included under Note 2 to our Condensed Consolidated Financial Statements.
The following tables set forth information regarding our results of operations for the periods presented:
 
Three Months Ended September 30,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 
(in thousands)
Net sales
$
491,393

 
$
422,779

 
$
68,614

 
16
 %
Cost of products sold (exclusive of depreciation and amortization)
456,656

 
383,211

 
73,445

 
19
 %
Operating expenses
16,891

 
15,725

 
1,166

 
7
 %
Selling, general and administrative
17,559

 
19,735

 
(2,176
)
 
(11
)%
Depreciation and amortization
6,655

 
5,329

 
1,326

 
25
 %
Total operating costs and expenses
497,761

 
424,000

 
73,761

 
17
 %
Operating income (loss)
(6,368
)
 
(1,221
)
 
(5,147
)
 
422
 %
Other income
—

 
(19
)
 
19

 
(100
)%
Interest income
75

 
40

 
35

 
88
 %
Interest expense
(7,170
)
 
(6,685
)
 
(485
)
 
7
 %
Loss before income taxes
(13,463
)
 
(7,885
)
 
(5,578
)
 
71
 %
Income tax (provision) benefit
(853
)
 
(909
)
 
56

 
(6
)%
Net loss
$
(14,316
)
 
$
(8,794
)
 
$
(5,522
)
 
63
 %

 
Nine Months Ended September 30,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 
(in thousands)
Net sales
$
1,922,826

 
$
1,623,173

 
$
299,653

 
18
 %
Cost of products sold (exclusive of depreciation and amortization)
1,720,860

 
1,463,938

 
256,922

 
18
 %
Operating expenses
50,624

 
49,078

 
1,546

 
3
 %
Selling, general and administrative
63,472

 
62,099

 
1,373

 
2
 %
Depreciation and amortization
19,537

 
16,001

 
3,536

 
22
 %
Total operating costs and expenses
1,854,493

 
1,591,116

 
263,377

 
17
 %
Operating income
68,333

 
32,057

 
36,276

 
113
 %
Other income (expense)
183

 
(114
)
 
297

 
(261
)%
Interest income
247

 
379

 
(132
)
 
(35
)%
Interest expense
(22,604
)
 
(20,179
)
 
(2,425
)
 
12
 %
Income before income taxes
46,159

 
12,143

 
34,016

 
280
 %
Income tax (provision) benefit
(3,768
)
 
(861
)
 
(2,907
)
 
338
 %
Net income
$
42,391

 
$
11,282

 
$
31,109

 
276
 %

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Analysis of Consolidated Operating Results
Net loss was $14.3 million and $8.8 million for the three months ended September 30, 2017 and 2016, respectively and operating loss was $6.4 million and $1.2 million for the three months ended September 30, 2017 and 2016, respectively. Operating results for the three months ended September 30, 2017 and 2016 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts of $(13.8) million and $(15.2) million, respectively. Excluding these unrealized items, operating income for the three months ended September 30, 2017 decreased $6.6 million, or 47%, as compared to the three months ended September 30, 2016.
Net income was $42.4 million and $11.3 million for the nine months ended September 30, 2017 and 2016, respectively and operating income was $68.3 million and $32.1 million for the nine months ended September 30, 2017 and 2016, respectively. Operating results for the nine months ended September 30, 2017 and 2016 include unrealized commodity derivative gains and losses with respect to refined products and natural gas inventory, prepaid forward contracts and natural gas transportation contracts of $22.4 million and $(30.7) million, respectively. Excluding these unrealized items, operating income for the nine months ended September 30, 2017 decreased $16.9 million, or 27%, as compared to the nine months ended September 30, 2016.
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 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-Non-GAAP Financial Measures” and “How Management Evaluates Our Results of Operations” of this report. The table below also presents information on weather conditions for the periods presented.

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Table of Contents


 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Reconciliation of Operating Income to Adjusted Gross Margin:
 
 
 
 
 
 
Operating income (loss)
$
(6,368
)
 
$
(1,221
)
 
$
68,333

 
$
32,057

Operating costs and expenses not allocated to operating segments:
 
 
 
 
 
 
 
Operating expenses
16,891

 
15,725

 
50,624

 
49,078

Selling, general and administrative
17,559

 
19,735

 
63,472

 
62,099

Depreciation and amortization
6,655

 
5,329

 
19,537

 
16,001

Add: unrealized (gain) loss on inventory derivatives (1)
13,673

 
14,636

 
(15,374
)
 
26,592

Add: unrealized (gain) on prepaid forward contract derivatives (2)
(667
)
 
(120
)
 
(907
)
 
(1,161
)
Add: unrealized loss (gain) on natural gas transportation contracts (3)
760

 
672

 
(6,105
)
 
5,221

Total adjusted gross margin (4):
$
48,503

 
$
54,756

 
$
179,580

 
$
189,887

Adjusted Gross Margin by Segment:
 
 
 
 
 
 
 
Refined products
$
32,014

 
$
38,693

 
$
95,307

 
$
104,070

Natural gas
3,197

 
2,773

 
44,355

 
43,734

Materials handling
11,395

 
11,305

 
34,118

 
35,826

Other operations
1,897

 
1,985

 
5,800

 
6,257

Total adjusted gross margin
$
48,503

 
$
54,756

 
$
179,580

 
$
189,887

Reconciliation of Net (Loss) Income to Adjusted EBITDA
 
 
 
 
 
 
 
Net (loss) income
$
(14,316
)
 
$
(8,794
)
 
$
42,391

 
$
11,282

Add/(deduct):
 
 
 
 
 
 
 
Interest expense, net
7,095

 
6,645

 
22,357

 
19,800

Tax provision (benefit)
853

 
909

 
3,768

 
861

Depreciation and amortization
6,655

 
5,329

 
19,537

 
16,001

EBITDA (4):
$
287

 
$
4,089

 
$
88,053

 
$
47,944

Add: unrealized (gain) loss on inventory derivatives (1)
13,673

 
14,636

 
(15,374
)
 
26,592

Add: unrealized gain on prepaid forward contract derivatives (2)
(667
)
 
(120
)
 
(907
)
 
(1,161
)
Add: unrealized loss (gain) on natural gas transportation contracts (3)
760

 
672

 
(6,105
)
 
5,221

Adjusted EBITDA (4):
$
14,053

 
$
19,277

 
$
65,667

 
$
78,596

Other Data:
 
 
 
 
 
 
 
Normal heating degree days (5)
204

 
204

 
4,432

 
4,468

Actual heating degree days
146

 
72

 
4,019

 
3,938

Variance from normal heating degree days
(28
)%
 
(65
)%
 
(9
)%
 
(12
)%
Variance from prior period actual heating degree days
103
 %
 
(28
)%
 
2
 %
 
(19
)%

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(1)
Inventory is valued at the lower of cost or net realizable value. 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.
(2)
The unrealized hedging gain (loss) on prepaid forward contract derivatives represents our estimate of the change in fair value of the prepaid forward contracts which are not recorded in net income until the forward contract is settled in the future (i.e., when the commodity is delivered to the customer). As these contracts are prepaid, they do not qualify as derivatives and changes in the fair value are therefore not included in net income. The fair value of the derivatives we use to economically hedge our prepaid forward contracts declines or appreciates in value as the value of the underlying prepaid forward contract appreciates or declines, which creates unrealized hedging gains (losses) that are included in net income.
(3)
The unrealized (gain) loss on natural gas transportation contracts represents our 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 hedging losses (gains) in net income.
(4)
For a discussion of the non-GAAP financial measures EBITDA, adjusted EBITDA and adjusted gross margin, see “How Management Evaluates Our Results of Operations.”
(5)
As reported by the NOAA/National Weather Service for the New England oil home heating region over the period of 1981-2011.
Analysis of Operating Segments
Three Months Ended September 30, 2017 compared to Three Months Ended September 30, 2016
 
Three Months Ended September 30,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 
(in thousands, except adjusted unit gross margin)
Volumes:
 
 
 
 
 
 
 
Refined products (gallons)
251,496

 
237,510

 
13,986

 
6
 %
Natural gas (MMBtus)
10,963

 
11,810

 
(847
)
 
(7
)%
Materials handling (short tons)
603

 
764

 
(161
)
 
(21
)%
Materials handling (gallons)
74,214

 
78,330

 
(4,116
)
 
(5
)%
Net Sales:
 
 
 
 
 
 
 
Refined products
$
425,492

 
$
350,528

 
$
74,964

 
21
 %
Natural gas
49,694

 
55,868

 
(6,174
)
 
(11
)%
Materials handling
11,395

 
11,304

 
91

 
1
 %
Other operations
4,812

 
5,079

 
(267
)
 
(5
)%
Total net sales
$
491,393

 
$
422,779

 
$
68,614

 
16
 %
Adjusted Gross Margin:
 
 
 
 
 
 
 
Refined products
$
32,014

 
$
38,693

 
$
(6,679
)
 
(17
)%
Natural gas
3,197

 
2,773

 
424

 
15
 %
Materials handling
11,395

 
11,305

 
90

 
1
 %
Other operations
1,897

 
1,985

 
(88
)
 
(4
)%
Total adjusted gross margin
$
48,503

 
$
54,756

 
$
(6,253
)
 
(11
)%
Adjusted Unit Gross Margin:
 
 
 
 
 
 
 
Refined products
$
0.127

 
$
0.163

 
$
(0.036
)
 
(22
)%
Natural gas
$
0.292

 
$
0.235

 
$
0.057

 
24
 %

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Refined Products
Refined products net sales increased $75.0 million, or 21%, compared to the same period last year, primarily due to 15% increase in the average sales price given a higher energy price environment. A 6% gain in volumes also contributed to the overall sales increase.
Refined products adjusted gross margin decreased $6.7 million, or 17%, compared to the third quarter of 2016. This reduction was due to the 22% decline in average adjusted unit gross margin, more than offsetting the 6% gain in volumes. The key factors contributing to the lower adjusted unit gross margins were less favorable market conditions to supply and carry inventory and a well-supplied market leading to strong competitive intensity.
The higher volume was primarily due to the contributions from Kildair along with the L.E. Belcher and Carbo acquisitions completed earlier this year. Increased volumes were obtained in both distillates and heavy oil, with a decrease in gasoline. The distillate volume gains were a combination of heating oil and diesel with significant contributions from L.E. Belcher and Carbo, as well as Kildair. The higher heavy oils volumes were due to increased activity at Kildair, including both local sales as well as marine bunker volumes. The reduction in gasoline volume was primarily a result of the high competitive intensity for discretionary sales in a well-supplied market.
Natural Gas
Natural gas net sales decreased $6.2 million, or 11%, as compared to the same period last year due to a 7% reduction in volumes and a 4% reduction in average sales price. The volume decrease was primarily a result of the loss of a few higher volume, lower adjusted unit gross margin customers.
Natural gas adjusted gross margin increased by $0.4 million, or 15%, compared to the same period last year, due primarily to higher adjusted unit gross margins, which more than offset the lower volumes. The improved adjusted unit gross margins were primarily a result of increases in the valuation of forward contracts, partially offset by decreased optimization opportunities for transportation assets.
Materials Handling
Materials handling net sales and adjusted gross margin both increased by $0.1 million, each representing 1% gains as compared to the same period last year. These gains were primarily due to enhanced refined products storage and handling revenues at Kildair, with the other materials handling activity down slightly, in particular as a result of lower salt handling requirements due to re-supply timing differences.
Other Operations
Net sales from other operations declined by $0.3 million compared to the same period last year, with adjusted gross margin decreasing by $0.1 million. The net sales and adjusted gross margin reductions were primarily a result of decreased coal volumes.

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Nine Months Ended September 30, 2017 compared to Nine Months Ended September 30, 2016
 
Nine Months Ended September 30,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 
(in thousands, except adjusted unit gross margin)
Volumes:
 
 
 
 
 
 
 
Refined products (gallons)
994,518

 
978,264

 
16,254

 
2
 %
Natural gas (MMBtus)
44,677

 
44,799

 
(122
)
 
0
 %
Materials handling (short tons)
1,879

 
2,016

 
(137
)
 
(7
)%
Materials handling (gallons)
301,896

 
234,738

 
67,158

 
29
 %
Net Sales:
 
 
 
 
 
 
 
Refined products
$
1,638,066

 
$
1,331,197

 
$
306,869

 
23
 %
Natural gas
235,068

 
240,256

 
(5,188
)
 
(2
)%
Materials handling
34,118

 
35,848

 
(1,730
)
 
(5
)%
Other operations
15,574

 
15,872

 
(298
)
 
(2
)%
Total net sales
$
1,922,826

 
$
1,623,173

 
$
299,653

 
18
 %
Adjusted Gross Margin:
 
 
 
 
 
 
 
Refined products
$
95,307

 
$
104,070

 
$
(8,763
)
 
(8
)%
Natural gas
44,355

 
43,734

 
621

 
1
 %
Materials handling
34,118

 
35,826

 
(1,708
)
 
(5
)%
Other operations
5,800

 
6,257

 
(457
)
 
(7
)%
Total adjusted gross margin
$
179,580

 
$
189,887

 
$
(10,307
)
 
(5
)%
Adjusted Unit Gross Margin:
 
 
 
 
 
 
 
Refined products
$
0.096

 
$
0.106

 
$
(0.010
)
 
(9
)%
Natural gas
$
0.993

 
$
0.976

 
$
0.017

 
2
 %


Refined Products
Refined products net sales increased $306.9 million, or 23%, compared to the same period last year, primarily due to 21% increase in the average sales price with the higher refined products price environment. A 2% increase in volumes was a lesser contributor to the higher sales.
Refined products adjusted gross margin decreased $8.8 million, or 8%, compared to the same period last year, driven by lower adjusted unit gross margins. The 9% decline in average adjusted unit gross margins was primarily a result of less attractive market conditions to supply and carry inventory as well as high competitive intensity for discretionary sales. Volumes were modestly higher than the same period last year, with significant contributions from Kildair and recent acquisitions, in particular L.E. Belcher. These volume gains in both distillates and heavy oils more than offset a decline in the remainder of Sprague's refined products business. The reduction in gasoline volume was primarily a result of the high competitive intensity for discretionary sales in a well-supplied market.
Natural Gas
Natural gas net sales decreased $5.2 million, or 2%, compared to the same period last year as a result of a 2% reduction in the average sales price. Volumes were flat as the reduction from the loss of certain higher volume, lower adjusted unit gross margin accounts essentially offset the contribution from the Global natural gas acquisition beginning in February 2017.
Natural gas adjusted gross margin increased by $0.6 million, compared to the same period last year, driven by 2% gain in adjusted unit gross margin. The increased adjusted unit gross margins were due to a continuing shift in customer mix, partially offset by fewer pipeline capacity optimization opportunities and a lower fair value derivative valuation.
 

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Materials Handling
Materials handling net sales and adjusted gross margin both decreased by $1.7 million, or 5%, compared to the same period last year. The decrease was primarily due to reduced windmill component handling. Other contributors to the reduction included lower gypsum and slag activity due to timing differences, as well as a modest decrease in refined products storage requirements at Kildair. Partially offsetting these declines were higher asphalt requirements including the expansion of a key contract, increased salt activity due to the higher incidence of storm events, and advanced timing of petroleum coke handling requirements.
Other Operations
Net sales from other operations declined by $0.3 million with adjusted gross margin decreasing by $0.5 million. The decline in adjusted gross margin was a combination of reductions in fuel burner service, trucking at Kildair and lower coal volumes.

Operating Costs and Expenses
Three Months Ended September 30, 2017 compared to Three Months Ended September 30, 2016
 
Three Months Ended September 30,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 
(in thousands)
 
 
 
 
Operating expenses
$
16,891

 
$
15,725

 
$
1,166

 
7%
Selling, general and administrative
$
17,559

 
$
19,735

 
$
(2,176
)
 
(11)%
Depreciation and amortization
$
6,655

 
$
5,329

 
$
1,326

 
25%
Interest expense, net
$
7,095

 
$
6,645

 
$
450

 
7%
Operating Expenses. Operating expenses increased by $1.2 million, or 7%, compared to the same period last year, reflecting $1.2 million of operating expenses at our terminals acquired during the first half of 2017 and increased maintenance and utility expenses at our existing terminals, partially offset by lower stockpile expenses.
Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $2.2 million, or 11%, compared to the same period last year. The predominant driver of this decrease was lower incentive compensation, partially offset by expenses connected to our Global Natural Gas & Power acquisition.
Depreciation and Amortization. Depreciation and amortization increased $1.3 million, or 25%, compared to the same period last year, primarily as a result of the acquisitions completed during the first half of 2017.
Interest Expense, net. Interest expense, net increased $0.5 million, or 7%, compared to the same period last year primarily relating to the financing of the four acquisitions which were completed in the first half of 2017.

Nine Months Ended September 30, 2017 compared to Nine Months Ended September 30, 2016
 
Nine Months Ended September 30,
 
Increase/(Decrease)
 
2017
 
2016
 
$
 
%
 
(in thousands)
 
 
 
 
Operating expenses
$
50,624

 
$
49,078

 
$
1,546

 
3%
Selling, general and administrative
$
63,472

 
$
62,099

 
$
1,373

 
2%
Depreciation and amortization
$
19,537

 
$
16,001

 
$
3,536

 
22%
Interest expense, net
$
22,357

 
$
19,800

 
$
2,557

 
13%
Operating Expenses. Operating expenses increased by $1.5 million, or 3% as compared to the same period last year, reflecting $2.4 million of operating expenses at our terminals acquired during the first half of 2017, offset by a $0.9 million decrease in stockpile expenses at our other terminals.

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Selling, General and Administrative Expenses. Selling, general and administrative expenses increased $1.4 million, or 2%, compared to the same period last year, primarily as a result of a $1.8 million increase of selling and administrative expenses related to the recent Global Natural Gas & Power acquisition. Decreased employee related expenses of $1.6 million driven by lower incentive compensation were more than offset by increased merger and acquisition expenses and systems costs in support of continued growth.
Depreciation and Amortization. Depreciation and amortization increased $3.5 million, or 22%, compared to the same period last year, primarily as a result of the acquisitions completed during the first half of 2017.
Interest Expense, net. Interest expense, net increased $2.6 million, or 13%, compared to the same period last year primarily related to a one-time charge attributable to the refinancing and extension of our Credit Agreement and increased borrowings for the four acquisitions completed during the first half of 2017.
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, 2017, we had working capital of $282.3 million.
As of September 30, 2017, the undrawn borrowing capacity under the working capital facilities was $92.5 million and the undrawn borrowing capacity under the acquisition facility was $233.6 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, 2017, the amount drawn under the working capital facilities of our Credit Agreement fluctuated from a low of $115.0 million to a high of $310.3 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
On April 27, 2017, Sprague Operating Resources LLC and Kildair Service ULC ("Kildair") entered into an agreement that amended and restated the revolving credit agreement to extend the maturity through April 27, 2021, reduce the U.S. dollar working capital facility from $1.0 billion to $950.0 million, reduce the multicurrency working capital facility from $120.0 million to $100.0 million, reduce interest rates under certain leverage ratio scenarios, as well as make other modifications, the “Credit Agreement”. Obligations under the Credit Agreement are secured by substantially all of the assets of the Partnership and its subsidiaries.
As of September 30, 2017, the revolving credit facilities under the Credit Agreement contained, among other items, the following:

•
U.S. dollar revolving working capital facility of up to $950.0 million, subject to the Partnership's borrowing base limits, to be used for working capital loans and letters of credit;
•
Multicurrency revolving working capital facility of up to $100.0 million, subject to the Partnership's borrowing base limits, to be used by Kildair for working capital loans and letters of credit;
•
Revolving acquisition facility of up to $550.0 million 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, the U.S. dollar revolving working capital facilities may be increased by $250.0 million and the multicurrency revolving working capital facility may be increased by $220.0 million, subject to a maximum increase for both facilities of $270.0 million in the aggregate. Additionally, subject to certain conditions, the revolving acquisition facility may be increased by $200.0 million.

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Indebtedness under the Credit Agreement will bear interest, at the borrowers' option, at a rate per annum equal to either 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 an alternate rate plus a specified margin.
For the U.S. dollar working capital facility and the acquisition facility, the alternate rate is the Base Rate which is the higher of (a) the U.S. Prime Rate as in effect from time to time, (b) the Federal Funds 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 the Canadian dollar working capital facility, 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.
The working capital facilities are subject to borrowing base reporting and as of September 30, 2017 and December 31, 2016, had a borrowing base of $398.4 million and $525.4 million, respectively. As of September 30, 2017 and December 31, 2016, outstanding letters of credit were $31.2 million and $31.6 million, respectively. As of September 30, 2017, excess availability under the working capital facilities was $92.5 million and excess availability under the acquisition facilities was $233.6 million.
The weighted average interest rate was 3.7% and 3.4% at September 30, 2017 and December 31, 2016, respectively. No amounts are due under the Credit Agreement until the maturity date, however, the current portion of the Credit Agreement at September 30, 2017 and December 31, 2016 represents the amounts of the working capital facility intended to be repaid during the following twelve month period.
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, among others: 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, a maximum consolidated senior secured leverage-to-EBITDA ratio. The Credit Agreement also limits our 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, 2017.
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-accelerations, 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.

Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.

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Capital Expenditures
Our terminals require investments to maintain, expand, upgrade or enhance existing assets and to comply with environmental and operational regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent 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. Expansion capital expenditures are 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 acquisitions.
 
Capital Expenditures
 
Expansion
 
Maintenance
 
Total
 
(in thousands)
Nine Months Ended September 30,
 
 
 
 


2017 (1)
$
23,422

 
$
7,884

 
$
31,306

2016
$
5,083

 
$
6,353

 
$
11,436


(1)
Excludes approximately $8.5 million of assets acquired in 2017 that were previously leased by the Partnership.

We anticipate that future maintenance capital expenditures and future expansion capital requirements will be funded with cash generated by operations or provided through long-term borrowings or other debt financings and/or equity offerings.
Cash Flows
 
Nine Months Ended September 30,
 
2017
 
2016
 
(in thousands)
Net cash provided by operating activities
$
126,891

 
$
107,095

Net cash used in investing activities
$
(111,047
)
 
$
(40,354
)
Net cash used in financing activities
$
(15,453
)
 
$
(94,263
)
Operating Activities
Net cash provided by operating activities for the nine months ended September 30, 2017 was $126.9 million and was primarily driven by cash inflows as a result of a decrease of $73.9 million in inventories due to a seasonal reduction in inventory requirements, a decrease of $77.7 million in accounts receivable due to seasonal reduction in sales volume, and $42.4 million in net income. These inflows were offset by cash outflows as a result of a reduction of $80.5 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and an increase of $19.8 million in our derivative fixed forward contracts as a result of changes in commodity prices during the period.
Net cash provided by operating activities for the nine months ended September 30, 2016 was $107.1 million and was primarily driven by a decrease of $95.1 million in derivative instruments relating to the ratable liquidation of our fixed forward contracts as we come out of the peak season, a decrease of $27.1 million in accounts receivable relating to lower commodity prices and volumes and $11.3 million in net income. These inflows were offset by cash outflows as a result of a reduction of $30.2 million in accounts payable and accrued liabilities primarily relating to the timing of invoice payments for product purchases and an increase of $25.1 million in inventories due to higher volume levels.


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Investing Activities
Net cash used in investing activities for the nine months ended September 30, 2017 was $111.0 million of which $72.2 million related to the purchase of four business acquisitions, $23.4 million related to expansion capital expenditures, $7.9 million related to maintenance capital expenditure projects across our terminal system and $8.5 million related to a purchase of real estate previously leased by us at our Portland Merrill terminal.
Net cash used in investing activities for the nine months ended September 30, 2016 was $40.4 million of which $29.1 million related to financing our acquisitions, $5.1 million related to expansion capital expenditures and $6.4 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, 2017 was $15.5 million, and primarily resulted from distributions of $42.4 million partially offset by $35.0 million of borrowings under our Credit Agreement acquisition line to fund the acquisitions.
Net cash used in financing activities for the nine months ended September 30, 2016 was $94.3 million and primarily resulted from $51.9 million of net payments under our Credit Agreement due to reduced financing requirements from lower commodity prices and accounts receivable levels and distributions of $34.8 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, 2017 and 2016.
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: asset valuations, the fair value of derivative assets and liabilities, environmental and legal obligations.
The significant accounting policies and estimates that have been adopted and followed in the preparation of our consolidated financial statements are detailed in Note 1—“Description of Business and Summary of Significant Accounting Policies” included in our 2016 Annual Report. There have been no subsequent 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 to our Condensed Consolidated Financial Statements.

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Item 3.
Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk, interest rate risk and market/credit risk. We utilize various derivative instruments to manage exposure to commodity risk and swaps to manage exposure to interest rate risk.
Commodity Price Risk
We use various financial instruments as we seek to hedge our commodity price risk. We sell our refined products and natural gas primarily in the Northeast. We hedge our refined products positions primarily with a combination of futures contracts that trade on the NYMEX, and fixed-for-floating price swaps in the form of bilateral contracts that are traded “over-the-counter” or "OTC". Although there are some notable differences between futures and the fixed-for-floating price swaps, both can provide a fixed price while the counterparty receives a price that fluctuates as market prices change.
As indicated in the table below, we primarily use futures contracts to hedge light oil transactions and swaps contracts for 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.
 
Product Group
  
Primary Financial Hedging Instrument
Gasolines
  
NYMEX RBOB futures contract
Distillates
  
NYMEX Ultra Low Sulfur Diesel futures contract
Residual Fuel Oils
  
New York Harbor 1% Sulfur Residual Fuel Oil swaps contract
In addition to the financial instruments listed above, we periodically use the ethanol futures contract that trades on the Chicago Board of Trade, or CBOT, to hedge ethanol that is used for blending into our gasoline. This ethanol contract is based on Chicago delivery. 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 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.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
(in thousands)
 
2017
 
2016
 
2017
 
2016
Refined products contracts
$
(17,281
)
 
$
2,957

 
$
27,637

 
$
(2,176
)
Natural gas contracts
(908
)
 
(3,370
)
 
13,850

 
16,472

Total
$
(18,189
)
 
$
(413
)
 
$
41,487

 
$
14,296

Substantially all of our commodity derivative contracts outstanding as of September 30, 2017 will settle prior to March 31, 2019.

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Interest Rate Risk
We enter into interest rate swaps to manage exposures in changing interest rates. We swap the variable LIBOR interest rate payable under our Credit Agreement for fixed LIBOR interest rates. These interest rate swaps meet the criteria to receive cash flow hedge accounting treatment. Counterparties to our interest rate swaps are large multi-national banks and we do not believe there is a material risk of counterparty nonperformance. Additionally, we may enter into seasonal swaps which are intended to manage our increase in borrowings during the winter, as a result of higher inventory and accounts receivable levels.
Our interest rate swap agreements outstanding as of September 30, 2017 were as follows (in thousands):
Interest Rate Swap Agreements
Beginning
 
Ending
 
Notional Amount
January 2017
 
January 2018
 
$
225,000

January 2018
 
January 2019
 
$
275,000

January 2019
 
January 2020
 
$
125,000

January 2020
 
January 2021
 
$
50,000

January 2021
 
January 2022
 
$
50,000

During the two year period ended September 30, 2017 we hedged approximately 46% 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, 2017, we estimate that if short-term interest rates increased or decreased by 100 basis points, our interest expense would have increased by approximately $2.9 million and decreased by approximately $2.5 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 all of our financial assets and financial liabilities measured at fair value on a recurring basis as of September 30, 2017 (in thousands):
 
As of September 30, 2017
 
Fair Value
Measurement
 
Quoted
Prices in
Active
Markets
Level 1
 
Significant
Other
Observable
Inputs
Level 2
 
Significant
Unobservable
Inputs
Level 3
Financial assets:
 
 
 
 
 
 
 
Commodity fixed forwards
$
62,367

 
$
—

 
$
62,367

 
$
—

Commodity swaps and options
173

 
—

 
173

 
—

Commodity derivatives
62,540

 
—

 
62,540

 
—

Interest rate swaps
1,825

 
—

 
1,825

 
—

Total
$
64,365

 
$
—

 
$
64,365

 
$
—

Financial liabilities:
 
 
 
 
 
 
 
Commodity fixed forwards
$
70,692

 
$
—

 
$
70,692

 
$
—

Commodity swaps and options
112

 
—

 
112

 
—

Commodity derivatives
70,804

 
—

 
70,804

 
—

Interest rate swaps
235

 
—

 
235

 
—

Other
2

 
—

 
2

 
—

Total
$
71,041

 
$
—

 
$
71,041

 
$
—


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Market and Credit Risk
The risk management activities for our refined products and natural gas segments involve managing exposures to the impact of market fluctuations in the price and transportation costs for commodities through the use of derivative instruments. The prices for energy commodities can be significantly influenced by market liquidity and changes in seasonal demand, weather conditions, transportation availability, and federal and state regulations. We monitor and manage our exposure to market risk on a daily basis in accordance with approved policies.
We maintain a control environment under the direction of our Chief Risk Officer through our risk management policy, processes and procedures, which our senior management has approved. Control measures include volumetric, value at risk, and stop loss limits, as well as contract term limits. Our Chief Risk Officer and Risk Management Committee must approve the use of new instruments or new commodities. Risk limits are monitored and reported daily to senior management. Our risk management department also performs independent verifications of sources of fair values. These controls apply to all of our commodity risk management activities.
We use a value at risk model to monitor commodity price risk within our risk management activities. The value at risk model uses both linear and simulation methodologies based on historical information, with the results representing the potential loss in fair value over one day at a 95% confidence level. Results may vary from time to time as hedging coverage, market pricing levels and volatility change.
We have a number of financial instruments that are potentially at risk including cash and cash equivalents, receivables and derivative contracts. Our primary exposure is credit risk related to our receivables and counterparty performance risk related to the fair value of derivative assets, which is the loss that may result from a customer’s or counterparty’s non-performance. We use credit policies to control credit risk, including utilizing an established credit approval process, monitoring customer and counterparty limits, employing credit mitigation measures such as analyzing customer financial statements, credit insurance with a third party provider and accepting personal guarantees and forms of collateral. We believe that our counterparties will be able to satisfy their contractual obligations. Credit risk is limited by the large number of customers and counterparties comprising our business and their dispersion across different industries.

Cash is held in demand deposit and other short-term investment accounts placed with federally insured financial institutions. Such deposit accounts at times may exceed federally insured limits. We have not experienced any losses on such accounts.

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Item 4.
Controls and Procedures

Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2017. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits 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 by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2017, our Chief Executive Officer and Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.
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, 2017 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.


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PART II—OTHER INFORMATION
 
Item 1.
Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our consolidated financial condition or results of operations.
Item 1A.
Risk Factors
In addition to other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” included in our 2016 Annual Report, which could materially affect our business, financial condition or future results.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3.
Defaults Upon Senior Securities
None.
Item 4.
Mine Safety Disclosures
Not applicable.
Item 5.
Other Information
None.



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Item 6.
Exhibits

The exhibits listed in the accompanying Exhibits Index are filed or incorporated by reference as part of this Form 10-Q.

EXHIBIT INDEX
Exhibit
No.
 
Description
2.1* ***
 
 
 
2.2***
 
 
 
 
2.3***
 
 
 
 
2.4***
 
 
 
 
2.5***
 
 
 
 
2.6***
 
 
 
 
3.1
 
 
 
 
3.2
 
 
 
31.1*
 
 
 
31.2*
 
 
 
32.1**
 
 
 
32.2**
 
 
 




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101.INS*
 
XBRL Instance Document
 
 
101.SCH*
 
XBRL Taxonomy Extension Schema Document
 
 
101.CAL*
 
XBRL Taxonomy Extension Calculation
 
 
101.DEF*
 
XBRL Taxonomy Extension Definition
 
 
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase
 
 
101.PRE*
 
XBRL Taxonomy Extension Presentation
*
Filed herewith.
**
Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.
***
Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules to the Asset Purchase Agreements have been omitted. The registrant hereby agrees to furnish supplementally to the SEC, upon its request, any or all omitted schedules.



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SIGNATURES
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.
 
 
SPRAGUE RESOURCES LP
 
 
 
 
By:
Sprague Resources GP LLC,
 
 
Its General Partner
 
 
 
Date: November 7, 2017
 
/s/ Gary A. Rinaldi
 
 
Gary A. Rinaldi
Senior Vice President, Chief Operating Officer and Chief Financial Officer (on behalf of the registrant, and in his capacity as Principal Financial Officer)


46