NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “
we
,” “
us
,” “
our
” and “
Buckeye
” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries.
We own and operate a diversified network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered and miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Additionally, we are one of the largest independent terminalling and storage operators in the United States in terms of capacity available for service. We also own and operate one of the largest networks of active products terminals across our portfolio of pipelines, inland terminals and marine terminals located primarily in the East Coast, Midwest and Gulf Coast regions of the United States and in the Caribbean. Our network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk storage and blending hubs. Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our Gulf Coast regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), offers world-class marine terminalling, storage and processing capabilities. Our recent acquisition of an indirect 50% equity interest in VTTI B.V. (“VTTI”) expands our international presence with premier storage and marine terminalling services for petroleum products predominantly located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore. We are also a wholesale distributor of refined petroleum products in areas served by our pipelines and terminals.
Basis of Presentation and Principles of Consolidation
The unaudited condensed consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission. Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our results of operations for the interim periods. The unaudited condensed consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. We have eliminated all intercompany transactions in consolidation.
We believe that the disclosures in these unaudited condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended
December 31, 2016
.
Recent Accounting Developments
Retirement Benefits
. In March 2017, the Financial Accounting Standards Board (“FASB”) issued guidance to amend the presentation of net periodic pension cost and net periodic postretirement benefit cost. The guidance requires that the service cost component of net periodic pension and postretirement benefit cost be presented in the same income statement line item as other employee compensation costs, while the other components are required to be presented separately within non-operating income. The guidance also allows only the service cost component to be eligible for capitalization when applicable. The amendments are effective for interim and annual periods beginning after December 15, 2017. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements.
Revenue from Contracts with Customers
. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which amended existing accounting standards for revenue recognition, including industry-specific requirements, and provides entities with a single revenue recognition model for recognizing revenue from contracts with customers. The core principle of ASU 2014-09 is that an entity should recognize revenue from contracts with customers when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Furthermore, additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The two permitted transition methods under ASU 2014-09 are the full retrospective method, which would be applied to each prior reporting period presented and the cumulative effect of applying the standard would be recognized at the earliest period shown, or the modified retrospective method, in which the cumulative effect of applying the standard would be recognized at the date of initial application. In July 2015, the FASB deferred the effective date of ASU 2014-09 and is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted for annual and interim periods beginning after December 15, 2016. In 2016, the FASB issued accounting standards updates that amended several aspects of ASU 2014-09. We are currently evaluating the provisions of the standard and have formed an implementation work team consisting of representatives from across all of our business segments to evaluate and implement changes to business processes, systems and controls. In addition, we have implemented training on the new standard’s revenue recognition model and are continuing our contract review and documentation. We expect to adopt this guidance on January 1, 2018, and we are currently evaluating the impact that it will have on our consolidated financial statements under the elected modified retrospective transition method.
Equity-Based Compensation
. In March 2016, the FASB issued guidance to simplify several aspects of the accounting for employee equity-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows and classification of awards as liabilities or equity. The guidance was effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. Amendments related to the timing of when excess tax benefits are recognized, statutory withholding requirements and forfeitures were to be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows were to be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement were to be applied prospectively. Amendments related to the presentation of excess tax benefits on the statement of cash flows were to be applied using either a prospective transition method or a retrospective transition method. We adopted this guidance as of January 1, 2017 and did not recognize a retrospective transition adjustment. In addition, the adoption of this guidance did not have a material impact on our consolidated financial statements or on our disclosures.
2. ACQUISITIONS
Business Combination
Indianola terminalling facility acquisition
In August 2016, we acquired a liquid petroleum products terminalling facility in Indianola, Pennsylvania from Kinder Morgan Transmix Company, LLC for
$26.0 million
. The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The acquisition cost has been allocated on a preliminary basis to assets acquired based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques. The estimates of fair value reflected as of
March 31, 2017
are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands):
|
|
|
|
|
Inventories
|
$
|
1,554
|
|
Property, plant and equipment
|
16,713
|
|
Goodwill
|
7,758
|
|
Allocated purchase price
|
$
|
26,025
|
|
Unaudited Pro forma Financial Results for the Indianola terminalling facility acquisition
Our consolidated statements of operations do not include earnings from the terminalling facility prior to August 4, 2016, the effective acquisition date of these assets. The preparation of unaudited pro forma financial information for the terminalling facility is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the
three
months ended
March 31, 2017
.
Equity Transaction
VTTI Acquisition
In January 2017, we acquired an indirect
50%
equity interest in VTTI for cash consideration of
$1.15 billion
(the “VTTI Acquisition”). We own VTTI jointly with Vitol S.A. (“Vitol”). VTTI is one of the largest independent global marine terminal businesses which, through its subsidiaries and partnership interests, owns and operates approximately
57 million
barrels of petroleum products storage across
14
terminals located on
five
continents. These marine terminals are predominately located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore, and offer world-class storage and marine terminalling services for refined petroleum products, liquid petroleum gas and crude oil. We and VIP Terminals Finance B.V., a subsidiary of Vitol, have equal board representation and voting rights in the VTTI joint venture. We account for this investment using the equity method of accounting. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. The earnings from our equity investment in VTTI are reported in our Global Marine Terminals segment. In addition, we include our proportionate share of our equity method investments’ unrealized gains and losses in other comprehensive income in our unaudited condensed consolidated financial statements. We recognized a foreign currency translation gain of
$2.9 million
in other comprehensive income for the three months ended March 31, 2017 related to our investment in VTTI.
The excess net investment in VTTI was
$580.8 million
at the acquisition date and was comprised of the following components: (i)
$225.3 million
related to the excess of the fair values of identifiable property, plant and equipment and intangible assets over their carrying values, which is amortized on a straight-line basis over the remaining useful lives of these underlying assets; and (ii)
$355.5 million
of implied goodwill which is not subject to amortization.
3. COMMITMENTS AND CONTINGENCIES
Claims and Legal Proceedings
In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material.
Environmental Contingencies
We recorded operating expenses, net of recoveries, of
$1.5 million
and
$1.6 million
during the
three months ended March 31, 2017
and
2016
, respectively, related to environmental remediation liabilities unrelated to claims and legal proceedings. As of
March 31, 2017
and
December 31, 2016
, we recorded environmental remediation liabilities of
$44.4 million
and
$44.3 million
, respectively. Costs ultimately incurred may be in excess of our estimates, which may have a material impact on our financial condition, results of operations or cash flows. At
March 31, 2017
and
December 31, 2016
, we had
$6.6 million
and
$7.2 million
, respectively, of receivables related to these environmental remediation liabilities covered by insurance or third-party claims.
4. INVENTORIES
Our inventory amounts were as follows at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
March 31,
2017
|
|
December 31,
2016
|
Liquid petroleum products (1)
|
$
|
282,960
|
|
|
$
|
337,424
|
|
Materials and supplies
|
22,167
|
|
|
19,379
|
|
Total inventories
|
$
|
305,127
|
|
|
$
|
356,803
|
|
|
|
(1)
|
Ending inventory was
182.8 million
and
198.2 million
gallons of liquid petroleum products as of
March 31, 2017
and
December 31, 2016
, respectively.
|
At
March 31, 2017
and
December 31, 2016
, approximately
91%
and
88%
of our liquid petroleum products inventory volumes were designated in a fair value hedge relationship, respectively. Because we generally designate inventory as a hedged item upon purchase, hedged inventory is valued at current market prices with the change in value of the inventory reflected in our unaudited condensed consolidated statements of operations. Our inventory volumes that are not designated as the hedged item in a fair value hedge relationship are economically hedged to reduce our commodity price exposure. Inventory not accounted for as a fair value hedge is accounted for at the lower of weighted average cost method or net realizable value.
5. PREPAID AND OTHER CURRENT ASSETS
Prepaid and other current assets consist of the following at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
March 31,
2017
|
|
December 31,
2016
|
Prepaid insurance
|
$
|
2,021
|
|
|
$
|
7,609
|
|
Margin deposits
|
20,299
|
|
|
43,912
|
|
Unbilled revenue
|
2,293
|
|
|
1,615
|
|
Prepaid taxes
|
9,284
|
|
|
7,357
|
|
Vendor prepayments
|
—
|
|
|
1,863
|
|
Other
|
6,386
|
|
|
4,180
|
|
Total prepaid and other current assets
|
$
|
40,283
|
|
|
$
|
66,536
|
|
6. EQUITY INVESTMENTS
The following table presents earnings from equity investments for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
Segment
|
|
2017
|
|
2016
|
VTTI B.V. (1)
|
Global Marine Terminals
|
|
$
|
8,389
|
|
|
$
|
—
|
|
West Shore Pipe Line Company
|
Domestic Pipelines & Terminals
|
|
1,342
|
|
|
2,331
|
|
Muskegon Pipeline LLC
|
Domestic Pipelines & Terminals
|
|
334
|
|
|
377
|
|
Transport4, LLC
|
Domestic Pipelines & Terminals
|
|
173
|
|
|
147
|
|
South Portland Terminal LLC
|
Domestic Pipelines & Terminals
|
|
120
|
|
|
233
|
|
Total earnings from equity investments
|
|
|
$
|
10,358
|
|
|
$
|
3,088
|
|
(1) We acquired an indirect
50%
equity interest in VTTI in January 2017. For additional information, see
Note 2
.
Summarized combined income statement data for our equity method investments are as follows for the periods indicated (amounts represent
100%
of investee income statement data in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Revenue
|
$
|
126,684
|
|
|
$
|
22,211
|
|
Operating income
|
45,645
|
|
|
12,533
|
|
Net income
|
30,112
|
|
|
8,339
|
|
Net income attributable to investees
|
23,987
|
|
|
8,339
|
|
7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
We are exposed to financial market risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage such risks.
Interest Rate Derivatives
From time to time, we utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the change in fair value of the swap instrument is positive and the counterparty may fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance, generally associated with the maturity of an existing debt obligation. We designate the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings.
During 2016, we entered into
seven
forward-starting interest rate swaps with a total aggregate notional amount of
$350.0 million
, which we entered into in anticipation of the issuance of debt on or before January 15, 2018, and
eleven
forward-starting interest rate swaps with a total aggregate notional amount of
$500.0 million
, which we entered into in anticipation of the issuance of debt on or before November 15, 2018. We expect to issue new fixed-rate debt on or before January 15, 2018 to repay the
$300.0 million
of
6.050%
notes that are due on January 15, 2018, and on or before November 15, 2018 to repay the
$400.0 million
of
2.650%
notes that are due on November 15, 2018, as well as to fund capital expenditures and other general partnership purposes, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms.
During the
three
months ended
March 31, 2017
, unrealized
gains
of
$1.7 million
were recorded in accumulated other comprehensive income (“AOCI”) to reflect the change in the fair values of the forward-starting interest rate swaps.
Commodity Derivatives
Our Merchant Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts, which we designated as fair value hedges, with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Our Merchant Services segment also uses exchange-traded refined petroleum contracts to hedge expected future transactions related to certain gasoline inventory that we manage on behalf of a third party, which are designated as cash flow hedges, with the effective portion of the hedge reported in other comprehensive income (“OCI”) and reclassified into earnings when the expected future transaction affects earnings. Any gains or losses incurred on the derivative instruments that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings.
Additionally, our Merchant Services segment enters into exchange-traded refined petroleum product futures contracts on behalf of our Domestic Pipelines & Terminals segment to manage the risk of market price volatility on the narrowing gasoline-to-butane pricing spreads associated with our butane blending activities managed by a third party. These futures contracts are not designated in a hedge relationship for accounting purposes. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market.
The following table summarizes our commodity derivative instruments outstanding at
March 31, 2017
(amounts in thousands of gallons):
|
|
|
|
|
|
|
|
|
|
|
|
Volume (1)
|
|
Accounting
|
Derivative Purpose
|
|
Current
|
|
Long-Term
|
|
Treatment
|
Derivatives NOT designated as hedging instruments:
|
|
|
|
|
|
|
|
|
Physical fixed price derivative contracts
|
|
7,712
|
|
|
1,574
|
|
|
Mark-to-market
|
Physical index derivative contracts
|
|
34,667
|
|
|
—
|
|
|
Mark-to-market
|
Futures contracts for refined petroleum products
|
|
1,431
|
|
|
18,690
|
|
|
Mark-to-market
|
|
|
|
|
|
|
|
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
Physical fixed price derivative contracts
|
|
8,818
|
|
|
—
|
|
|
Cash Flow Hedge
|
Cash flow hedge contracts
|
|
9,618
|
|
|
—
|
|
|
Cash Flow Hedge
|
Futures contracts for refined petroleum products
|
|
150,822
|
|
|
15,288
|
|
|
Fair Value Hedge
|
|
|
(1)
|
Volume represents absolute value of net notional volume position.
|
Our futures contracts designated as fair value hedges related to our inventory portfolio and our futures contracts designated as cash flow hedges related to refined petroleum products extend to the
fourth quarter of 2018
.
Effective January, 2017, the Chicago Mercantile Exchange (“CME”) amended its rulebook, resulting in the characterization of variation margin transfers as settlement payments, as opposed to adjustments to collateral. These amendments impacted the accounting treatment of our exchange-traded derivatives contracts, primarily comprised of our futures contracts, for which the CME serves as the central clearing party, or exchange-settled derivative traded on the over-the-counter (“OTC”)market. As a result, commencing with the first quarter of 2017, we began reducing the corresponding derivative asset and liability balances for our exchange-settled derivative contracts to reflect the settlement of those positions via the variation margin. The variation margin is now considered partial settlement of the derivative contract and will result in realized gains or losses which prior to January 1, 2017 were classified as unrealized gains or losses on derivatives. In addition, we maintain an initial margin deposit with the broker in an amount sufficient to cover the fair value of our open futures positions. This margin deposit is considered collateral and is included within prepaid and other current assets in our condensed consolidated balance sheets and is not offset against the fair values of our derivative instruments.
The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our unaudited condensed consolidated balance sheets at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
Derivatives NOT Designated as Hedging Instruments
|
|
Derivatives Designated as Hedging Instruments
|
|
Derivative Carrying Value
|
|
Netting Balance Sheet Adjustment (1)
|
|
Net Total
|
Physical fixed price derivative contracts
|
$
|
1,353
|
|
|
$
|
—
|
|
|
$
|
1,353
|
|
|
$
|
(236
|
)
|
|
$
|
1,117
|
|
Physical index derivative contracts
|
244
|
|
|
—
|
|
|
244
|
|
|
(1
|
)
|
|
243
|
|
Interest rates derivatives
|
—
|
|
|
26,239
|
|
|
26,239
|
|
|
—
|
|
|
26,239
|
|
Total current derivative assets
|
1,597
|
|
|
26,239
|
|
|
27,836
|
|
|
(237
|
)
|
|
27,599
|
|
Physical fixed price derivative contracts
|
193
|
|
|
—
|
|
|
193
|
|
|
—
|
|
|
193
|
|
Interest rates derivatives
|
—
|
|
|
38,080
|
|
|
38,080
|
|
|
—
|
|
|
38,080
|
|
Total non-current derivative assets
|
193
|
|
|
38,080
|
|
|
38,273
|
|
|
—
|
|
|
38,273
|
|
Physical fixed price derivative contracts
|
(1,096
|
)
|
|
(1,825
|
)
|
|
(2,921
|
)
|
|
236
|
|
|
(2,685
|
)
|
Physical index derivative contracts
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
Total current derivative liabilities
|
(1,097
|
)
|
|
(1,825
|
)
|
|
(2,922
|
)
|
|
237
|
|
|
(2,685
|
)
|
Net derivative assets
|
$
|
693
|
|
|
$
|
62,494
|
|
|
$
|
63,187
|
|
|
$
|
—
|
|
|
$
|
63,187
|
|
|
|
(1)
|
Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
Derivatives NOT Designated as Hedging Instruments
|
|
Derivatives Designated as Hedging Instruments
|
|
Derivative Carrying Value
|
|
Netting Balance Sheet Adjustment (1)
|
|
Net Total
|
Physical fixed price derivative contracts
|
$
|
1,499
|
|
|
$
|
—
|
|
|
$
|
1,499
|
|
|
$
|
(306
|
)
|
|
$
|
1,193
|
|
Physical index derivative contracts
|
334
|
|
|
—
|
|
|
334
|
|
|
(1
|
)
|
|
333
|
|
Futures contracts for refined products
|
51,431
|
|
|
21
|
|
|
51,452
|
|
|
(51,452
|
)
|
|
—
|
|
Total current derivative assets
|
53,264
|
|
|
21
|
|
|
53,285
|
|
|
(51,759
|
)
|
|
1,526
|
|
Physical fixed price derivative contracts
|
164
|
|
|
—
|
|
|
164
|
|
|
(5
|
)
|
|
159
|
|
Futures contracts for refined products
|
226
|
|
|
—
|
|
|
226
|
|
|
(226
|
)
|
|
—
|
|
Interest rates derivatives
|
—
|
|
|
62,609
|
|
|
62,609
|
|
|
—
|
|
|
62,609
|
|
Total non-current derivative assets
|
390
|
|
|
62,609
|
|
|
62,999
|
|
|
(231
|
)
|
|
62,768
|
|
Physical fixed price derivative contracts
|
(4,517
|
)
|
|
—
|
|
|
(4,517
|
)
|
|
306
|
|
|
(4,211
|
)
|
Physical index derivative contracts
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
Futures contracts for refined products
|
(57,828
|
)
|
|
(15,685
|
)
|
|
(73,513
|
)
|
|
51,452
|
|
|
(22,061
|
)
|
Total current derivative liabilities
|
(62,346
|
)
|
|
(15,685
|
)
|
|
(78,031
|
)
|
|
51,759
|
|
|
(26,272
|
)
|
Physical fixed price derivative contracts
|
(61
|
)
|
|
—
|
|
|
(61
|
)
|
|
5
|
|
|
(56
|
)
|
Futures contracts for refined products
|
(4,384
|
)
|
|
—
|
|
|
(4,384
|
)
|
|
226
|
|
|
(4,158
|
)
|
Total non-current derivative liabilities
|
(4,445
|
)
|
|
—
|
|
|
(4,445
|
)
|
|
231
|
|
|
(4,214
|
)
|
Net derivative (liabilities) assets
|
$
|
(13,137
|
)
|
|
$
|
46,945
|
|
|
$
|
33,808
|
|
|
$
|
—
|
|
|
$
|
33,808
|
|
|
|
(1)
|
Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.
|
At
March 31, 2017
, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for refined products contracts noted above) varied in duration in the overall portfolio, but did not extend beyond
December 2018
. In addition, at
March 31, 2017
, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.
The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
Location
|
|
2017
|
|
2016
|
Derivatives NOT designated as hedging instruments:
|
|
|
|
|
|
|
|
Physical fixed price derivative contracts
|
Product sales
|
|
$
|
2,487
|
|
|
$
|
(2,255
|
)
|
Physical index derivative contracts
|
Product sales
|
|
(16
|
)
|
|
(27
|
)
|
Physical fixed price derivative contracts
|
Cost of product sales
|
|
467
|
|
|
5,115
|
|
Physical index derivative contracts
|
Cost of product sales
|
|
163
|
|
|
214
|
|
Futures contracts for refined products
|
Cost of product sales
|
|
(90
|
)
|
|
(1,482
|
)
|
|
|
|
|
|
|
Derivatives designated as fair value hedging instruments:
|
|
|
|
|
|
|
|
Futures contracts for refined products
|
Cost of product sales
|
|
$
|
33,577
|
|
|
$
|
1,613
|
|
Physical inventory - hedged items
|
Cost of product sales
|
|
(20,351
|
)
|
|
8,326
|
|
|
|
|
|
|
|
Ineffectiveness excluding the time value component on fair value hedging instruments:
|
|
|
|
|
|
|
|
Fair value hedge ineffectiveness (excluding time value)
|
Cost of product sales
|
|
$
|
(959
|
)
|
|
$
|
647
|
|
Time value excluded from hedge assessment
|
Cost of product sales
|
|
14,185
|
|
|
9,292
|
|
Net gain in income
|
|
|
$
|
13,226
|
|
|
$
|
9,939
|
|
The change in value recognized in OCI and the gains and losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
Gain Recognized in OCI on Derivatives for the
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Derivatives designated as cash flow hedging instruments:
|
|
|
|
|
|
Interest rate contracts
|
$
|
1,710
|
|
|
$
|
—
|
|
Commodity derivatives
|
1,275
|
|
|
—
|
|
Total
|
$
|
2,985
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) Gain Reclassified from AOCI to Income (Effective Portion) for the
|
|
|
|
Three Months Ended
March 31,
|
|
Location
|
|
2017
|
|
2016
|
Derivatives designated as cash flow hedging instruments:
|
|
|
|
|
|
|
|
Interest rate contracts
|
Interest and debt expense
|
|
$
|
(3,038
|
)
|
|
$
|
(3,038
|
)
|
Commodity derivatives
|
Product Sales
|
|
—
|
|
|
1,266
|
|
Total
|
|
|
$
|
(3,038
|
)
|
|
$
|
(1,772
|
)
|
Over the next twelve months, we expect to reclassify
$11.0 million
of net losses attributable to interest rate derivatives from AOCI to earnings as an increase to interest and debt expense. The net losses consist of
$11.9 million
of amortization of hedge losses related to our settled forward-starting interest rate swaps and
$0.9 million
of estimated amortization of forecasted hedge gains on our forward-starting interest swaps that we expect to settle in late 2017. The ineffective portion of the change in fair value of cash flow hedges was not material for the
three
months ended
March 31, 2017
.
8. FAIR VALUE MEASUREMENTS
We categorize our financial assets and liabilities using the three-tier hierarchy as follows:
Recurring
The following table sets forth financial assets and liabilities measured at fair value on a recurring basis, as of the measurement dates indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 1
|
|
Level 2
|
Financial assets:
|
|
|
|
|
|
|
|
|
|
|
|
Physical fixed price derivative contracts
|
$
|
—
|
|
|
$
|
1,546
|
|
|
$
|
—
|
|
|
$
|
1,352
|
|
Physical index derivative contracts
|
—
|
|
|
244
|
|
|
—
|
|
|
333
|
|
Futures contracts for refined products
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest rate derivatives
|
—
|
|
|
64,319
|
|
|
—
|
|
|
62,609
|
|
|
|
|
|
|
|
|
|
Financial liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Physical fixed price derivative contracts
|
—
|
|
|
(2,921
|
)
|
|
—
|
|
|
(4,267
|
)
|
Physical index derivative contracts
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
Futures contracts for refined products
|
—
|
|
|
—
|
|
|
(26,219
|
)
|
|
—
|
|
Fair value
|
$
|
—
|
|
|
$
|
63,187
|
|
|
$
|
(26,219
|
)
|
|
$
|
60,027
|
|
The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York Mercantile Exchange.
The values of the Level 2 interest rate derivatives were determined using fair value estimates obtained from our counterparties, which are verified using other available market data, including cash flow models which incorporate market inputs, including the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements. Credit value adjustments (“CVAs”), which are used to reflect the potential nonperformance risk of our counterparties, are considered in the fair value assessment of interest rate derivatives. We determined that the impact of CVAs is not significant to the overall valuation of interest rate derivatives.
The values of the Level 2 commodity derivative contracts were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 physical fixed price derivative assets are net of CVAs determined using an expected cash flow model, which incorporates assumptions about the credit risk of the derivative contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Merchant Services segment determined CVAs are appropriate because few of the Merchant Services segment’s customers entering into these derivative contracts are large organizations with nationally recognized credit ratings. The CVAs were nominal as of
March 31, 2017
and
December 31, 2016
. As of
March 31, 2017
and
December 31, 2016
, the Merchant Services segment did not hold any net liability derivative position containing credit contingent features.
Financial instruments included in current assets and current liabilities are reported in the unaudited condensed consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly issued debt with the market prices of the publicly issued debt of other MLPs with similar credit ratings and terms. The fair values of our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates. The carrying value and fair value of our debt, using Level 2 input values, were as follows at the dates indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
Carrying
Amount
|
|
Fair Value
|
|
Carrying
Amount
|
|
Fair Value
|
Fixed-rate debt
|
$
|
3,968,819
|
|
|
$
|
4,114,152
|
|
|
$
|
3,967,695
|
|
|
$
|
4,083,488
|
|
Variable-rate debt
|
850,523
|
|
|
850,523
|
|
|
250,000
|
|
|
250,000
|
|
Total debt
|
$
|
4,819,342
|
|
|
$
|
4,964,675
|
|
|
$
|
4,217,695
|
|
|
$
|
4,333,488
|
|
We recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did not have any transfers between Level 1 and Level 2 during the
three months ended March 31, 2017
and
2016
, respectively.
Non-Recurring
Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. For the
three
months ended
March 31, 2017
and
2016
, there were
no
fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements.
9. PENSIONS AND OTHER POSTRETIREMENT BENEFITS
Buckeye Pipe Line Services Company, which employs the majority of our workforce, sponsors a defined benefit plan, the Retirement Income Guarantee Plan (the “RIGP”), and an unfunded post-retirement benefit plan (the “Retiree Medical Plan”). The RIGP and Retiree Medical Plan are closed and have limited participation. The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the
three months ended March 31, 2017
and
2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RIGP
|
|
Retiree Medical Plan
|
|
Three Months Ended
March 31,
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Service cost
|
$
|
(9
|
)
|
|
$
|
(9
|
)
|
|
$
|
81
|
|
|
$
|
91
|
|
Interest cost
|
105
|
|
|
127
|
|
|
327
|
|
|
333
|
|
Expected return on plan assets
|
(64
|
)
|
|
(71
|
)
|
|
—
|
|
|
—
|
|
Amortization of unrecognized losses
|
130
|
|
|
145
|
|
|
47
|
|
|
50
|
|
Net periodic benefit cost
|
$
|
162
|
|
|
$
|
192
|
|
|
$
|
455
|
|
|
$
|
474
|
|
During the
three months ended March 31, 2017
and
2016
, we contributed
$1.3 million
and
$0.8 million
, respectively, in aggregate to the RIGP and Retiree Medical Plans.
10. UNIT-BASED COMPENSATION PLANS
We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (the “LTIP”). We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). These compensation plans are further discussed below.
We recognized compensation expense related to the LTIP and the Option Plan of
$8.7 million
and
$6.3 million
for the
three months ended March 31, 2017
and
2016
, respectively.
LTIP
As of
March 31, 2017
, there were
1,656,179
LP Units available for issuance under the LTIP.
Deferral Plan under the LTIP
We also maintain the Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective February 4, 2015 (the “Deferral Plan”), pursuant to which we issue phantom and matching units under the LTIP to certain employees in lieu of a portion of the cash payments such employees would be entitled to receive under the Buckeye Partners, L.P. Annual Incentive Compensation Plan, as amended and restated, effective January 1, 2012. At
December 31, 2016
and
2015
, actual compensation awards deferred under the Deferral Plan were
$4.4 million
and
$3.1 million
, for which
145,138
and
139,526
phantom units (including matching units) were granted during the
three months ended March 31, 2017
and the year ended
December 31, 2016
, respectively. These grants are included as granted in the LTIP activity table below.
Awards under the
LTIP
During the
three months ended March 31, 2017
, the Compensation Committee of the Board granted
295,009
phantom units to employees (including the
145,138
phantom units granted pursuant to the Deferral Plan, as discussed above),
18,000
phantom units to independent directors of Buckeye GP and
206,539
performance units to employees.
The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
Number of
LP Units
|
|
Weighted
Average
Grant Date
Fair Value
per LP Unit (1)
|
Unvested at January 1, 2017
|
1,296
|
|
|
$
|
63.54
|
|
Granted (2)
|
520
|
|
|
70.49
|
|
Performance adjustment (3)
|
32
|
|
|
71.50
|
|
Vested
|
(319
|
)
|
|
69.95
|
|
Forfeited
|
(20
|
)
|
|
63.51
|
|
Unvested at March 31, 2017
|
1,509
|
|
|
$
|
64.47
|
|
|
|
(1)
|
Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures.
|
|
|
(2)
|
Includes both phantom and performance awards. Performance awards are granted at a target amount but, depending on our performance during the vesting period with respect to certain pre-established goals, the number of LP Units issued upon vesting of such performance awards can be greater or less than the target amount.
|
|
|
(3)
|
Represents the LP Units to be issued in excess of target amounts for performance awards that vested during the three months ended
March 31, 2017
as a result of our above target performance with respect to applicable performance goals.
|
At
March 31, 2017
,
$54.8 million
of compensation expense related to the LTIP is expected to be recognized over a weighted average period of
2.1 years
.
Unit Option Plan
The following is a summary of the changes in the options outstanding (all of which are vested) under the Option Plan for the periods indicated (in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
LP Units
|
|
Weighted
Average
Strike Price
per LP Unit
|
|
Weighted
Average
Remaining
Contractual
Term (in years)
|
|
Aggregate
Intrinsic
Value (1)
|
Outstanding at January 1, 2017
|
10
|
|
|
$
|
50.36
|
|
|
0.1
|
|
|
$
|
151
|
|
Exercised
|
(10
|
)
|
|
—
|
|
|
|
|
|
|
|
Outstanding at March 31, 2017
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Exercisable at March 31, 2017
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
|
(1)
|
Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in
March 2017
and the exercise price, multiplied by the number of exercisable, in-the-money options.
|
The total intrinsic value of options exercised during each of the
three months ended March 31, 2017
and
2016
was
$0.2 million
and
$0.1 million
, respectively.
11. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. The partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units.
At-the-Market Offering Program
In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities America, Inc. (collectively, the “ATM Underwriters”). Under the terms of the Equity Distribution Agreement, we may offer and sell up to
$500.0 million
in aggregate gross sales proceeds of LP Units from time to time through the ATM Underwriters, acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution Agreement. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the New York Stock Exchange or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices or as otherwise agreed with any of such firms.
During the
three months ended March 31, 2017
, we sold approximately
50 thousand
LP Units under the Equity Distribution Agreement and received
$3.2 million
in net proceeds after deducting commissions and other related expenses, including nominal compensation fees paid in aggregate to the agents under the Equity Distribution Agreement.
Summary of Changes in Outstanding LP Units
The following is a summary of changes in Buckeye
’
s outstanding LP Units for the periods indicated (in thousands):
|
|
|
|
|
Limited
Partners
|
LP Units outstanding at January 1, 2017
|
140,264
|
|
LP Units issued pursuant to the Option Plan (1)
|
10
|
|
LP Units issued pursuant to the LTIP (1)
|
203
|
|
Issuance of LP Units through the Equity Distribution Agreement
|
50
|
|
LP Units outstanding at March 31, 2017
|
140,527
|
|
(1) The number of LP Units issued represents issuance net of tax withholding.
Cash Distributions
We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Actual cash distributions on our LP Units totaled
$174.9 million
(
$1.2375
per LP Unit) and
$154.9 million
(
$1.1875
per LP Unit) during the
three months ended March 31, 2017
and
2016
, respectively.
On
May 5, 2017
, we announced a quarterly distribution of
$1.25
per LP Unit that will be paid on
May 22, 2017
to unitholders of record on
May 15, 2017
. Based on the LP Units outstanding as of
March 31, 2017
, estimated cash distributed to unitholders on
May 22, 2017
will total
$176.7 million
.
12. EARNINGS PER UNIT
The following table is a reconciliation of the weighted average units outstanding used in computing the basic and diluted earnings per unit for the periods indicated (in thousands, except per unit amounts):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Net income attributable to Buckeye Partners, L.P.
|
$
|
123,576
|
|
|
$
|
131,113
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
Weighted average units outstanding - basic
|
140,377
|
|
|
129,703
|
|
|
|
|
|
Earnings per unit - basic
|
$
|
0.88
|
|
|
$
|
1.01
|
|
|
|
|
|
Diluted:
|
|
|
|
|
|
Weighted average units outstanding - basic
|
140,377
|
|
|
129,703
|
|
Dilutive effect of LP Unit options and LTIP awards granted
|
621
|
|
|
426
|
|
Weighted average units outstanding - diluted
|
140,998
|
|
|
130,129
|
|
|
|
|
|
Earnings per unit - diluted
|
$
|
0.88
|
|
|
$
|
1.01
|
|
13. BUSINESS SEGMENTS
We operate and report in
three
business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. Each segment uses the same accounting policies as those used in the preparation of our unaudited condensed consolidated financial statements. All inter-segment revenues, operating income and assets have been eliminated.
Domestic Pipelines & Terminals
The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines, vessels, and bulk and marine terminals, transports those products to other locations for a fee, and provides bulk storage and terminal throughput services. The segment also has butane blending capabilities and provides crude oil services, including train loading/unloading, storage and throughput. This segment owns and operates pipeline systems and liquid petroleum products terminals in the continental United States, including
three
terminals owned by the Merchant Services segment but operated by the Domestic Pipelines & Terminals segment, and
two
underground propane storage caverns. Additionally, this segment provides turn-key operations and maintenance of third-party pipelines and performs pipeline construction management services typically for cost plus a fixed fee.
Global Marine Terminals
The Global Marine Terminals segment provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading along with petroleum processing services in the East Coast and Gulf Coast regions of the United States and in the Caribbean. The segment has
seven
liquid petroleum product terminals located in The Bahamas, Puerto Rico and St. Lucia in the Caribbean, as well as the New York Harbor and Corpus Christi, Texas in the United States.
The earnings from our equity investment in VTTI, acquired in January 2017, are reported in our Global Marine Terminals segment. VTTI is one of the largest independent global marine terminal businesses that, through its subsidiaries and partnership interests, owns and operates approximately
57 million
barrels of petroleum products storage across
14
terminals located on
five
continents. These marine terminals are predominately located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore, and offer world-class storage and marine terminalling services for refined petroleum products, liquid petroleum gas and crude oil.
Merchant Services
The Merchant Services segment is a wholesale distributor of refined petroleum products in the United States and in the Caribbean. This segment recognizes revenues when products are delivered. The segment’s products include gasoline, natural gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel, kerosene and fuel oil. The segment owns
three
terminals, which are operated by the Domestic Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products.
Financial Information by Segment
The following table summarizes revenue by each segment for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Revenue:
|
|
|
|
|
|
Domestic Pipelines & Terminals
|
$
|
253,512
|
|
|
$
|
237,953
|
|
Global Marine Terminals
|
164,476
|
|
|
170,064
|
|
Merchant Services
|
571,126
|
|
|
389,737
|
|
Intersegment
|
(19,841
|
)
|
|
(17,160
|
)
|
Total revenue
|
$
|
969,273
|
|
|
$
|
780,594
|
|
For the
three
months ended
March 31, 2017
and
2016
, no customers contributed
10%
or more of consolidated revenue.
The following table summarizes revenue by major geographic area for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Revenue:
|
|
|
|
|
|
United States
|
$
|
887,862
|
|
|
$
|
696,889
|
|
International
|
81,411
|
|
|
83,705
|
|
Total revenue
|
$
|
969,273
|
|
|
$
|
780,594
|
|
Adjusted EBITDA
Adjusted EBITDA is a measure not defined by GAAP. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense; transaction, transition, and integration costs associated with acquisitions; gains and losses on foreign currency transactions and foreign currency derivative financial instruments; and certain other operating expense or income items, reflected in net income, that we do not believe are indicative of our core operating performance results and business outlook, such as hurricane-related costs, gains and losses on property damage recoveries, and gains and losses on asset sales. The definition of Adjusted EBITDA is also applied to our proportionate share in the Adjusted EBITDA of significant equity method investments, such as that in VTTI, and is not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our
50%
equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Adjusted EBITDA is a non-GAAP financial measure that is used by our senior management, including our Chief Executive Officer, to assess the operating performance of our business and optimize resource allocation. We use Adjusted EBITDA as a primary measure to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities.
We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.
The following tables present Adjusted EBITDA by segment and on a consolidated basis and a reconciliation of net income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Adjusted EBITDA:
|
|
|
|
|
|
Domestic Pipelines & Terminals
|
$
|
139,443
|
|
|
$
|
128,481
|
|
Global Marine Terminals
|
130,631
|
|
|
106,623
|
|
Merchant Services
|
7,435
|
|
|
9,522
|
|
Total Adjusted EBITDA
|
$
|
277,509
|
|
|
$
|
244,626
|
|
|
|
|
|
Reconciliation of Net Income to Adjusted EBITDA:
|
|
|
|
|
|
Net income
|
$
|
126,309
|
|
|
$
|
134,977
|
|
Less: Net income attributable to noncontrolling interests
|
(2,733
|
)
|
|
(3,864
|
)
|
Net income attributable to Buckeye Partners, L.P.
|
123,576
|
|
|
131,113
|
|
Add: Interest and debt expense
|
55,885
|
|
|
47,783
|
|
Income tax expense
|
222
|
|
|
615
|
|
Depreciation and amortization (1)
|
65,488
|
|
|
61,426
|
|
Non-cash unit-based compensation expense
|
8,678
|
|
|
6,335
|
|
Acquisition and transition expense (2)
|
1,029
|
|
|
122
|
|
Hurricane-related costs (3)
|
2,403
|
|
|
—
|
|
Proportionate share of Adjusted EBITDA for the equity method investment in VTTI (4)
|
28,617
|
|
|
—
|
|
Less: Amortization of unfavorable storage contracts (5)
|
—
|
|
|
(2,768
|
)
|
Earnings from the equity method investment in VTTI (4)
|
(8,389
|
)
|
|
—
|
|
Adjusted EBITDA
|
$
|
277,509
|
|
|
$
|
244,626
|
|
|
|
(1)
|
Includes
100%
of the depreciation and amortization expense of
$17.5 million
and
$16.8 million
for Buckeye Texas for the
three months ended March 31, 2017
and
2016
, respectively.
|
|
|
(2)
|
Represents transaction, internal and third-party costs related to asset acquisition and integration.
|
|
|
(3)
|
Represents operating expenses incurred at our BBH facility as a result of Hurricane Matthew, which occurred in October 2016.
|
|
|
(4)
|
Due to the significance of our equity method investment in VTTI, effective January 1, 2017, we applied the definition of Adjusted EBITDA, covered in our description of Adjusted EBITDA, with respect to our proportionate share of VTTI’s Adjusted EBITDA. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our
50%
equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial.
|
|
|
(5)
|
Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection with the BBH acquisition.
|
14. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2017
|
|
2016
|
Cash paid for interest (net of capitalized interest)
|
$
|
54,539
|
|
|
$
|
53,234
|
|
Cash paid for income taxes
|
180
|
|
|
1
|
|
Capitalized interest
|
1,029
|
|
|
1,011
|
|
Liabilities related to capital projects outstanding at
March 31, 2017
and
2016
of
$49.6 million
and
$76.8 million
, respectively, are not included under “Capital expenditures” within the unaudited condensed consolidated statements of cash flows.