NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1
—Organization and Basis of Consolidation and Presentation
Organization
Plains GP Holdings, L.P. (“PAGP”) is a Delaware limited partnership formed in July 2013 that has elected to be taxed as a corporation for United States federal income tax purposes. PAGP does not directly own any operating assets; as of
March 31, 2018
, its principal sources of cash flow are derived from an indirect investment in Plains All American Pipeline, L.P. (“PAA”), a publicly traded Delaware limited partnership. As used in this Form 10-Q and unless the context indicates otherwise (taking into account the fact that PAGP has no operating activities apart from those conducted by PAA and its subsidiaries), the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAGP and its subsidiaries.
As of
March 31, 2018
, PAGP owned (i) a
100%
managing member interest in Plains All American GP LLC (“GP LLC”), an entity that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate
55%
limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately
156.0 million
Class A units of AAP (“AAP units”) and indirect ownership of approximately
1.0 million
AAP units through GP LLC. GP LLC is a Delaware limited liability company that also holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of
March 31, 2018
, directly owned a limited partner interest in PAA through its ownership of approximately
283.9 million
PAA common units (approximately
36%
of PAA’s total outstanding common units and Series A preferred units combined). AAP is the sole member of PAA GP LLC (“PAA GP”), a Delaware limited liability company that directly holds the non-economic general partner interest in PAA.
PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services primarily for crude oil, natural gas liquids (“NGL”) and natural gas. PAA owns an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs in the United States and Canada. Our business activities are conducted through
three
operating segments: Supply and Logistics, Transportation and Facilities. See
Note 13
for further discussion of our operating segments.
PAA GP Holdings LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities and is responsible for exercising on our behalf any rights we have as the sole and managing member of GP LLC, including responsibility for conducting the business and managing the operations of AAP and PAA. GP LLC employs our domestic officers and personnel involved in the operation and management of AAP and PAA. PAA’s Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC (“PMC”).
Definitions
Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:
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AOCI
|
=
|
Accumulated other comprehensive income/(loss)
|
ASC
|
=
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Accounting Standards Codification
|
ASU
|
=
|
Accounting Standards Update
|
Bcf
|
=
|
Billion cubic feet
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Btu
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=
|
British thermal unit
|
CAD
|
=
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Canadian dollar
|
CODM
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=
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Chief Operating Decision Maker
|
EBITDA
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=
|
Earnings before interest, taxes, depreciation and amortization
|
EPA
|
=
|
United States Environmental Protection Agency
|
FASB
|
=
|
Financial Accounting Standards Board
|
GAAP
|
=
|
Generally accepted accounting principles in the United States
|
ICE
|
=
|
Intercontinental Exchange
|
ISDA
|
=
|
International Swaps and Derivatives Association
|
LIBOR
|
=
|
London Interbank Offered Rate
|
LTIP
|
=
|
Long-term incentive plan
|
Mcf
|
=
|
Thousand cubic feet
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NGL
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=
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Natural gas liquids, including ethane, propane and butane
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NYMEX
|
=
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New York Mercantile Exchange
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Oxy
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=
|
Occidental Petroleum Corporation or its subsidiaries
|
PLA
|
=
|
Pipeline loss allowance
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SEC
|
=
|
United States Securities and Exchange Commission
|
USD
|
=
|
United States dollar
|
WTI
|
=
|
West Texas Intermediate
|
Basis of Consolidation and Presentation
The accompanying unaudited condensed consolidated interim financial statements and related notes thereto should be read in conjunction with our
2017
Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAGP and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. The condensed consolidated balance sheet data as of
December 31, 2017
was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the
three
months ended
March 31, 2018
should not be taken as indicative of results to be expected for the entire year.
Management judgment is required to evaluate whether PAGP controls an entity. Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether PAGP is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that PAGP and its related parties have over those activities through variable interests; and (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether PAGP is a VIE’s primary beneficiary.
We have determined that our subsidiaries, PAA and AAP, are VIEs and should be consolidated by PAGP because:
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•
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The limited partners of PAA and AAP lack (i) substantive “kick-out rights” (i.e., the right to remove the general partner) based on a simple majority or lower vote and (ii) substantive participation rights and thus lack the ability to block actions of the general partner that most significantly impact the economic performance of PAA and AAP, respectively.
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•
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AAP is the primary beneficiary of PAA because it has the power to direct the activities that most significantly impact PAA’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to PAA.
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|
|
•
|
PAGP is the primary beneficiary of AAP because it has the power to direct the activities that most significantly impact AAP’s performance and the right to receive benefits, and obligation to absorb losses, that could be significant to AAP.
|
With the exception of a deferred tax asset of
$1,373 million
and
$1,386 million
as of
March 31, 2018
and
December 31, 2017
, respectively, substantially all assets and liabilities presented on PAGP’s consolidated balance sheet are those of PAA. Only the assets of each respective VIE can be used to settle the obligations of that individual VIE, and the creditors of each/either of those VIEs do not have recourse against the general credit of PAGP. PAGP did not provide any financial support to PAA or AAP during the
three
months ended
March 31, 2018
or the year ended
December 31, 2017
, respectively. See Note 15 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for information regarding the Omnibus Agreement entered into in connection with the Simplification Transactions.
Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.
Note 2
—Recent Accounting Pronouncements
Except as discussed below and in our
2017
Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the
three months ended March 31, 2018
that are of significance or potential significance to us.
Accounting Standards Updates Adopted During the Period
In February 2017, the FASB issued ASU 2017-05,
Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets
. The ASU clarifies what type of transactions involving nonfinancial assets are covered by the scope of the standard and provides guidance on how to account for those transactions, including partial sales of real estate. Within this guidance, all sales and partial sales of businesses, which may have previously been accounted for using the in-substance real estate guidance, should follow the consolidation guidance. This guidance is effective for interim and annual periods beginning after December 15, 2017, and must be adopted at the same time as Topic 606. We adopted this ASU on January 1, 2018, using the modified retrospective approach. The cumulative effect of our adoption resulted in increases in both the carrying value of investments in unconsolidated entities and retained earnings of
$113 million
related to the retained noncontrolling interest in those entities from partial sales of businesses accounted for under in-substance real estate guidance during 2016 and 2017.
In November 2016, the FASB issued ASU 2016-18,
Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)
, requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 31, 2017. We adopted this ASU on January 1, 2018. Our adoption did not have an impact on our statement of cash flows.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers,
followed by a series of related accounting standard updates (collectively referred to as “Topic 606”) with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of control of those goods or services. We adopted Topic 606 on January 1, 2018, and applied the modified retrospective approach. See Note 3 for additional information.
Other Accounting Standards Updates
In February 2016, the FASB issued ASU 2016-02,
Leases (Topic 842),
that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019 and are assessing the use of optional practical expedients. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations and cash flows. Although our evaluation is ongoing, we do expect that the adoption will impact our financial statements as the standard requires the recognition on the balance sheet of a right of use asset and corresponding lease liability. We are currently analyzing our contracts to determine whether they contain a lease under the revised guidance and have not quantified the amount of the asset and liability that will be recognized on our consolidated balance sheet.
Note 3
—Revenues
Revenue Recognition
On January 1, 2018, we adopted Topic 606 using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605, Revenue Recognition.
There was no material impact to opening retained earnings as of January 1, 2018 due to the adoption of Topic 606. There also was no material impact to revenues, or any other financial statement line items, for the three months ended March 31, 2018 as a result of applying Topic 606.
Under Topic 606, we disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors. Our business activities are conducted through
three
operating segments: Supply and Logistics, Transportation and Facilities. See
Note 13
for further discussion of our operating segments.
Supply and Logistics Segment Revenues from Contracts with Customers.
The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by segment and type of activity (in millions):
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|
Three Months Ended
March 31, 2018
|
Supply and Logistics revenues from contracts with customers
|
|
Crude oil transactions
|
$
|
7,023
|
|
NGL and other transactions
|
1,151
|
|
Total Supply and Logistics revenues from contracts with customers
|
$
|
8,174
|
|
Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. The consideration received under these contracts is variable based on commodity prices. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges which are excluded from Supply and Logistics segment revenues in our Condensed Consolidated Statements of Operations. Revenues recognized by our Supply and Logistics segment primarily represent margin based activities.
Additionally, we may utilize derivatives in connection with the transactions described above. Derivative revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue. The change in the fair value of derivatives that are not designated or do not qualify for hedge accounting is recognized in revenues each period along with the ineffective portion of the change in fair value of derivatives that are designated as cash flow hedges. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred in AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings.
Transportation Segment Revenues from Contracts with Customers.
The following table presents our Transportation segment revenues from contracts with customers disaggregated by segment and type of activity (in millions):
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Three Months Ended
March 31, 2018
|
Transportation revenues from contracts with customers
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|
Tariff activities:
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|
Crude oil pipelines
|
$
|
389
|
|
NGL pipelines
|
27
|
|
Total tariff activities
|
416
|
|
Trucking
|
34
|
|
Total Transportation revenues from contracts with customers
|
$
|
450
|
|
Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date.
Facilities Segment Revenues from Contracts with Customers.
The following table presents our Facilities segment revenues from contracts with customers disaggregated by segment and type of activity (in millions):
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|
|
|
|
|
Three Months Ended
March 31, 2018
|
Facilities revenues from contracts with customers
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|
Crude oil, NGL and other terminalling and storage
|
$
|
166
|
|
NGL and natural gas processing and fractionation
|
100
|
|
Rail load / unload
|
16
|
|
Total Facilities revenues from contracts with customers
|
$
|
282
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|
Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (iii) fees from NGL fractionation and isomerization services, (iv) fees from natural gas and condensate processing services, (v) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services (“natural gas storage related activities”) and (vi) loading and unloading fees at our rail terminals.
We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Natural gas storage related activities fees are recognized in the period the natural gas moves across our header system. We recognize rail loading and unloading fees when the volumes are delivered or received.
Reconciliation to Total Revenues of Reportable Segments.
Topic 606 requires us to provide information about the relationship between the disaggregated revenues presented above and segment revenues. These disclosures only include information regarding revenues associated with consolidated entities, and revenues from entities accounted for by the equity method are not included in the disclosures. The following table presents the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statement of Operations (in millions):
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|
Three Months Ended March 31, 2018
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|
Transportation
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|
Facilities
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Supply and
Logistics
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Total
|
Revenues from contracts with customers
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|
$
|
450
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|
|
$
|
282
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|
|
$
|
8,174
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|
|
$
|
8,906
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|
Other items in revenues
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|
4
|
|
|
10
|
|
|
(62
|
)
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|
(48
|
)
|
Total revenues of reportable segments
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|
$
|
454
|
|
|
$
|
292
|
|
|
$
|
8,112
|
|
|
$
|
8,858
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
(460
|
)
|
Total revenues
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|
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|
|
|
|
$
|
8,398
|
|
Minimum Volume Commitments.
We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. These contracts are within the scope of Topic 606. In addition, we have certain buy/sell agreements that require customers to deliver a minimum volume over an agreed upon period that are within the scope of ASC Topic 845,
Nonmonetary Transactions
, (“Topic 845”). Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.
At March 31, 2018 and December 31, 2017, counterparty deficiencies associated with agreements (under Topic 606 and Topic 845) that include minimum volume commitments totaled
$59 million
and
$57 million
, respectively, of which
$44 million
and
$37 million
, respectively, was recorded as a contract liability, which we refer to as deferred revenue. The remaining balance of
$15 million
and
$20 million
at March 31, 2018 and December 31, 2017, respectively, was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.
Contract Balances
. Our contract balances primarily consist of trade accounts receivable and liabilities. Our liabilities primarily consist of deferred revenues and advance cash payments. We invoice customers in the month following that in which products or services were provided and generally require payment within
30 days
of the invoice date. See
Note 5
for further discussion of trade accounts receivable and advance cash payments. Included in these deferred revenues are amounts recognized under minimum volume commitments, as discussed above.
The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheet (in millions):
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|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Trade accounts receivable arising from revenues from contracts with customers
|
$
|
2,783
|
|
|
$
|
2,584
|
|
Other trade accounts receivables and other receivables
(1)
|
3,674
|
|
|
3,709
|
|
Impact due to contractual rights of offset with counterparties
|
(3,434
|
)
|
|
(3,264
|
)
|
Trade accounts receivable and other receivables, net
|
$
|
3,023
|
|
|
$
|
3,029
|
|
|
|
(1)
|
The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.
|
Our contract liabilities primarily consist of amounts received under minimum volume commitments for which revenues are yet to be recognized and customer pre-payments and deposits. The following table presents the change in the contract liability balance during the three months ended March 31, 2018 (in millions):
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|
|
|
|
|
|
|
|
Minimum Volume Commitments
|
|
Customer Prepayments and Other
|
|
Total Deferred Revenues
|
Balance at December 31, 2017
|
$
|
8
|
|
|
$
|
86
|
|
|
$
|
94
|
|
Amounts recognized as revenue
|
(5
|
)
|
|
(70
|
)
|
|
(75
|
)
|
Additions
|
5
|
|
|
95
|
|
|
100
|
|
Other
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
Balance at March 31, 2018
|
$
|
8
|
|
|
$
|
108
|
|
|
$
|
116
|
|
Remaining Performance Obligations
. Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of March 31, 2018 (in millions):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remainder of 2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 and Thereafter
|
Pipeline revenues supported by minimum volume commitments
(1)
|
$
|
77
|
|
|
$
|
158
|
|
|
$
|
225
|
|
|
$
|
214
|
|
|
$
|
212
|
|
|
$
|
682
|
|
Long-term storage, terminalling and throughput agreements revenues
|
327
|
|
|
347
|
|
|
276
|
|
|
212
|
|
|
168
|
|
|
679
|
|
Total
|
$
|
404
|
|
|
$
|
505
|
|
|
$
|
501
|
|
|
$
|
426
|
|
|
$
|
380
|
|
|
$
|
1,361
|
|
|
|
(1)
|
Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects.
|
The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 requirements for presentation:
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|
•
|
Minimum volume commitments related to the assets of equity method investees — contracts include those related to the Eagle Ford, BridgeTex, STACK, Caddo, Saddlehorn, White Cliffs, Cheyenne and Diamond pipeline systems;
|
|
|
•
|
Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions;
|
|
|
•
|
Supply and Logistics contracts within the scope of Topic 845 — including buy/sell arrangements with future committed volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems;
|
|
|
•
|
All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below;
|
|
|
•
|
Transportation and Facilities contracts that are short-term, as discussed below;
|
|
|
•
|
Contracts within the scope of ASC Topic 840, Leases; and
|
|
|
•
|
Contracts within the scope of ASC Topic 815, Derivatives and Hedging.
|
We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations under Topic 606 due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above.
Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, which excludes the presentation of remaining performance obligations for short-term transportation, storage and processing services, supply and logistics arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.
Note 4—Net Income Per Class A Share
Basic net income per Class A share is determined by dividing net income attributable to PAGP by the weighted average number of Class A shares outstanding during the period. Our Class B and Class C shares do not share in the earnings of the Partnership; accordingly, basic and diluted net income per Class B and Class C share has not been presented.
Diluted net income per Class A share is determined by dividing net income attributable to PAGP by the diluted weighted average number of Class A shares outstanding during the period. For purposes of calculating diluted net income per Class A share, both the net income attributable to PAGP and the diluted weighted average number of Class A shares outstanding consider the impact of possible future exchanges of (i) AAP units and the associated Class B shares into our Class A shares and (ii) certain Class B units of AAP (referred to herein as “AAP Management Units”) into our Class A shares. In addition, the calculation of the diluted weighted average number of Class A shares outstanding considers the effect of potentially dilutive awards under the Plains GP Holdings, L.P. Long-Term Incentive Plan (the “PAGP LTIP”).
All AAP Management Units that have satisfied the applicable performance conditions are considered potentially dilutive. Exchanges of potentially dilutive AAP units and AAP Management Units are assumed to have occurred at the beginning of the period and the incremental income attributable to PAGP resulting from the assumed exchanges is representative of the incremental income that would have been attributable to PAGP if the assumed exchanges occurred on that date. See Note 11 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for information regarding exchanges of AAP units and AAP Management Units. PAGP LTIP awards that are deemed to be dilutive are reduced by a hypothetical share repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 16 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for information regarding PAGP LTIP awards.
For the three months ended
March 31, 2018
and 2017, the possible exchange of any AAP units and certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share. For the
three
months ended
March 31,
2018
and
2017
, our PAGP LTIP awards were dilutive; however, there were less than
0.1 million
dilutive LTIP awards for each period, which did not change the presentation of weighted average Class A shares outstanding or net income per Class A share.
The following table sets forth the computation of basic and diluted net income per Class A share (in millions, except per share data):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2018
|
|
2017
|
Basic and Diluted Net Income per Class A Share
|
|
|
|
|
|
Net income attributable to PAGP
|
$
|
37
|
|
|
$
|
41
|
|
Basic and diluted weighted average Class A shares outstanding
|
157
|
|
|
120
|
|
|
|
|
|
Basic and diluted net income per Class A share
|
$
|
0.23
|
|
|
$
|
0.34
|
|
Note 5—Accounts Receivable, Net
Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. As of
March 31, 2018
and
December 31, 2017
, we had received
$132 million
and
$117 million
, respectively, of advance cash payments from third parties to mitigate credit risk. We also received
$44 million
and
$54 million
as of
March 31, 2018
and
December 31, 2017
, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for the majority of our net-cash arrangements.
We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At
March 31, 2018
and
December 31, 2017
, substantially all of our trade accounts receivable (net of allowance for doubtful accounts) were less than
30
days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled
$3 million
at both
March 31, 2018
and
December 31, 2017
. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.
Note 6—Inventory, Linefill and Base Gas and Long-term Inventory
Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
|
December 31, 2017
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
9,171
|
|
|
barrels
|
|
$
|
494
|
|
|
$
|
53.87
|
|
|
|
7,800
|
|
|
barrels
|
|
$
|
402
|
|
|
$
|
51.54
|
|
NGL
|
4,144
|
|
|
barrels
|
|
115
|
|
|
$
|
27.75
|
|
|
|
10,774
|
|
|
barrels
|
|
294
|
|
|
$
|
27.29
|
|
Other
|
N/A
|
|
|
|
|
11
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
17
|
|
|
N/A
|
|
Inventory subtotal
|
|
|
|
|
|
620
|
|
|
|
|
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Linefill and base gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
12,428
|
|
|
barrels
|
|
719
|
|
|
$
|
57.85
|
|
|
|
12,340
|
|
|
barrels
|
|
719
|
|
|
$
|
58.27
|
|
NGL
|
1,596
|
|
|
barrels
|
|
43
|
|
|
$
|
26.94
|
|
|
|
1,597
|
|
|
barrels
|
|
45
|
|
|
$
|
28.18
|
|
Natural gas
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
|
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
Linefill and base gas subtotal
|
|
|
|
|
|
870
|
|
|
|
|
|
|
|
|
|
|
|
872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
1,823
|
|
|
barrels
|
|
108
|
|
|
$
|
59.24
|
|
|
|
1,870
|
|
|
barrels
|
|
105
|
|
|
$
|
56.15
|
|
NGL
|
1,989
|
|
|
barrels
|
|
51
|
|
|
$
|
25.64
|
|
|
|
2,167
|
|
|
barrels
|
|
59
|
|
|
$
|
27.23
|
|
Long-term inventory subtotal
|
|
|
|
|
|
159
|
|
|
|
|
|
|
|
|
|
|
|
164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
1,649
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,749
|
|
|
|
|
|
|
(1)
|
Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.
|
Note 7
—Divestitures
During the first quarter of 2018, we received proceeds from asset sales of
$83 million
, and we received an additional approximately
$255 million
from sales completed subsequent to quarter end through May 1, 2018. The assets sold primarily included non-core property and equipment previously reported in our Facilities and Transportation segments. As of March 31, 2018, we had classified approximately
$150 million
of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”) related to these transactions.
Note 8
—Debt
Debt consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
SHORT-TERM DEBT
|
|
|
|
|
|
PAA commercial paper notes, bearing a weighted-average interest rate of 2.8% and 2.4%, respectively
(1)
|
$
|
116
|
|
|
$
|
—
|
|
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.9% and 2.6%, respectively
(1)
|
285
|
|
|
664
|
|
PAA senior unsecured revolving credit facility, bearing a weighted-average interest rate of 3.0%
(1)
|
238
|
|
|
—
|
|
Other
|
135
|
|
|
73
|
|
Total short-term debt
(2)
|
774
|
|
|
737
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
|
PAA senior notes, net of unamortized discounts and debt issuance costs of $65 and $67, respectively
(3)
|
8,935
|
|
|
8,933
|
|
PAA commercial paper notes and senior secured hedged inventory facility borrowings
(3)
|
—
|
|
|
247
|
|
PAA senior unsecured revolving credit facility
(3)
|
112
|
|
|
—
|
|
Other
|
3
|
|
|
3
|
|
Total long-term debt
|
9,050
|
|
|
9,183
|
|
Total debt
(4)
|
$
|
9,824
|
|
|
$
|
9,920
|
|
|
|
(1)
|
We classified these PAA commercial paper notes and credit facility borrowings as short-term as of
March 31, 2018
and
December 31, 2017
, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.
|
|
|
(2)
|
As of
March 31, 2018
and
December 31, 2017
, balance includes borrowings of
$217 million
and
$212 million
, respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.
|
|
|
(3)
|
As of
March 31, 2018
and
December 31, 2017
, we classified a portion of PAA's commercial paper notes and PAA's credit facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis.
|
|
|
(4)
|
PAA’s fixed-rate senior notes had a face value of approximately
$9.0 billion
at both
March 31, 2018
and
December 31, 2017
. We estimated the aggregate fair value of these notes as of
March 31, 2018
and
December 31, 2017
to be approximately
$8.8 billion
and
$9.1 billion
, respectively. PAA’s fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near the end of the reporting period. We estimate that the carrying value of outstanding borrowings under the credit facilities and the PAA commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for the PAA senior notes, the credit facilities and the PAA commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.
|
Borrowings and Repayments
Total borrowings under the credit facilities and the PAA commercial paper program for the
three
months ended
March 31, 2018
and
2017
were approximately
$10.5 billion
and
$18.8 billion
, respectively. Total repayments under the credit facilities and the PAA commercial paper program were approximately
$10.7 billion
and
$19.2 billion
for the
three
months ended
March 31, 2018
and
2017
, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.
Letters of Credit
In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions and construction activities. At
March 31, 2018
and
December 31, 2017
, we had outstanding letters of credit of
$102 million
and
$166 million
, respectively.
Note 9
—Partners’ Capital and Distributions
Shares Outstanding
The following tables present the activity for our Class A shares, Class B shares and Class C shares:
|
|
|
|
|
|
|
|
|
|
|
Class A Shares
|
|
Class B Shares
|
|
Class C Shares
|
Outstanding at December 31, 2017
|
156,111,139
|
|
|
126,984,572
|
|
|
510,925,432
|
|
Exchange Right exercises
(1)
|
907,899
|
|
|
(907,899
|
)
|
|
—
|
|
Redemption Right exercises
(1)
|
—
|
|
|
(39,224
|
)
|
|
39,224
|
|
Issuance of Series A preferred units by a subsidiary
|
—
|
|
|
—
|
|
|
1,393,926
|
|
Other
|
—
|
|
|
—
|
|
|
17,766
|
|
Outstanding at March 31, 2018
|
157,019,038
|
|
|
126,037,449
|
|
|
512,376,348
|
|
|
|
|
|
|
|
|
|
|
|
|
Class A Shares
|
|
Class B Shares
|
|
Class C Shares
|
Outstanding at December 31, 2016
|
101,206,526
|
|
|
138,043,486
|
|
|
491,910,863
|
|
Conversion of AAP Management Units
(1)
|
—
|
|
|
276,405
|
|
|
—
|
|
Exchange Right exercises
(1)
|
479,298
|
|
|
(479,298
|
)
|
|
—
|
|
Redemption Right exercises
(1)
|
—
|
|
|
(3,454,374
|
)
|
|
3,454,374
|
|
Sales of Class A shares
|
50,086,326
|
|
|
—
|
|
|
—
|
|
Sales of common units by a subsidiary
|
—
|
|
|
—
|
|
|
4,033,567
|
|
Issuance of Series A preferred units by a subsidiary
|
—
|
|
|
—
|
|
|
1,287,773
|
|
Other
|
7,810
|
|
|
—
|
|
|
82,872
|
|
Outstanding at March 31, 2017
|
151,779,960
|
|
|
134,386,219
|
|
|
500,769,449
|
|
___________________________________________
|
|
(1)
|
See Note 11 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.
|
Distributions
The following table details the distributions paid to Class A shareholders during or pertaining to the first
three
months of
2018
(in millions, except per share data):
|
|
|
|
|
|
|
|
|
|
Distribution Payment Date
|
|
Distributions to
Class A Shareholders
|
|
Distributions per
Class A Share
|
May 15, 2018
(1)
|
|
$
|
47
|
|
|
$
|
0.30
|
|
February 14, 2018
|
|
$
|
47
|
|
|
$
|
0.30
|
|
___________________________________________
|
|
(1)
|
Payable to shareholders of record at the close of business on
May 1, 2018
for the period from
January 1, 2018
through
March 31, 2018
.
|
Consolidated Subsidiaries
Noncontrolling Interests in Subsidiaries
As of
March 31, 2018
, noncontrolling interests in our subsidiaries consisted of (i) limited partner interests in PAA including a
64%
interest in PAA common units and PAA Series A preferred units combined and
100%
of PAA's Series B preferred units and (ii) an approximate
45%
limited partner interest in AAP.
Subsidiary Distributions
PAA Common Unit Distributions.
The following table details the distributions to PAA’s common unitholders during or pertaining to the first
three
months of
2018
(in millions, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
Cash Distribution per Common Unit
|
|
|
Common Unitholders
|
|
Total Cash Distribution
|
|
|
Distribution Payment Date
|
|
Public
|
|
AAP
|
|
|
|
May 15, 2018
(1)
|
|
$
|
133
|
|
|
$
|
85
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
February 14, 2018
|
|
$
|
133
|
|
|
$
|
85
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
May 1, 2018
for the period from
January 1, 2018
through
March 31, 2018
.
|
PAA Series A Preferred Unit Distributions
. With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), PAA was able to elect to pay distributions on the PAA Series A preferred units in additional preferred units, in cash or a combination of both. On February 14, 2018, PAA issued
1,393,926
Series A preferred units in lieu of a cash distribution of
$37 million
on PAA's Series A preferred units outstanding as of January 31, 2018, the record date for such distribution.
The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to any quarter ending after the Initial Distribution Period, PAA must pay distributions on the Series A preferred units in cash. On May 15, 2018, PAA will pay a cash distribution of
$37 million
on its Series A preferred units outstanding as of May 1, 2018, the record date for such distribution, for the period from
January 1, 2018
through
March 31, 2018
. At
March 31, 2018
, such amount was accrued to distributions payable (in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet).
The purchasers may convert their Series A preferred units into PAA common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, at any time, in whole or in part, subject to certain minimum conversion amounts (and not more often than once per quarter).
PAA Series B Preferred Unit Distributions.
On May 15, 2018, PAA will pay the semi-annual cash distribution of
$24.5 million
on its Series B preferred units to holders of record at the close of business on May 1, 2018, for the period from November 15, 2017 through May 14, 2018. As of March 31, 2018, we had accrued approximately
$18 million
of distributions payable to its Series B preferred unitholders (in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet).
AAP Distributions.
The following table details the distributions paid to AAP’s partners during or pertaining to the first
three
months of
2018
from distributions received from PAA (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution to AAP's Partners
|
Distribution Payment Date
|
|
Noncontrolling Interests
|
|
PAGP
|
|
Total Cash Distributions
|
May 15, 2018
(1)
|
|
$
|
38
|
|
|
$
|
47
|
|
|
$
|
85
|
|
February 14, 2018
|
|
$
|
38
|
|
|
$
|
47
|
|
|
$
|
85
|
|
___________________________________________
|
|
(1)
|
Payable to unitholders of record at the close of business on
May 1, 2018
for the period from
January 1, 2018
through
March 31, 2018
.
|
Note 10
—Derivatives and Risk Management Activities
We identify the risks that underlie our core business activities and use risk management strategies to mitigate those risks when we determine that there is value in doing so. Our policy is to use derivative instruments for risk management purposes and not for the purpose of speculating on hydrocarbon commodity (referred to herein as “commodity”) price changes. We use various derivative instruments to manage our exposure to (i) commodity price risk, as well as to optimize our profits, (ii) interest rate risk and (iii) currency exchange rate risk. Our commodity price risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity. Our interest rate and currency exchange rate risk management policies and procedures are designed to monitor our derivative positions and ensure that those positions are consistent with our objectives and approved strategies. When we apply hedge accounting, our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and throughout the hedging relationship, we assess whether the derivatives employed are highly effective in offsetting changes in cash flows of anticipated hedged transactions.
Commodity Price Risk Hedging
Our core business activities involve certain commodity price-related risks that we manage in various ways, including through the use of derivative instruments. Our policy is to (i) only purchase inventory for which we have a market, (ii) structure our sales contracts so that price fluctuations do not materially affect our operating income and (iii) not acquire and hold physical inventory or derivatives for the purpose of speculating on commodity price changes. The material commodity-related risks inherent in our business activities can be divided into the following general categories:
Commodity Purchases and Sales
— In the normal course of our operations, we purchase and sell commodities. We use derivatives to manage the associated risks and to optimize profits. As of
March 31, 2018
, net derivative positions related to these activities included:
|
|
•
|
A net long position of
3.3 million
barrels associated with our crude oil purchases, which was unwound ratably during April 2018 to match monthly average pricing.
|
|
|
•
|
A net short time spread position of
6.7 million
barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through June 2019.
|
|
|
•
|
A crude oil grade basis position of
36.4 million
barrels through December 2019. These derivatives allow us to lock in grade basis differentials.
|
|
|
•
|
A net short position of
14.9 million
barrels through February 2020 related to anticipated net sales of our crude oil and NGL inventory.
|
Pipeline Loss Allowance Oil
— As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of
March 31, 2018
, our PLA hedges included a short position consisting of crude oil futures of
1.1 million
barrels and a long call option position of
0.7 million
barrels through December 2019.
Natural Gas Processing/NGL Fractionation
— We purchase natural gas for processing and operational needs. Additionally, we purchase NGL mix for fractionation and sell the resulting individual specification products (including ethane, propane, butane and condensate). In conjunction with these activities, we hedge the price risk associated with the purchase of the natural gas and the subsequent sale of the individual specification products. As of
March 31, 2018
, we had a long natural gas position of
51.3
Bcf which hedges our natural gas processing and operational needs through December 2020. We also had a short propane position of
7.9 million
barrels through December 2019, a short butane position of
2.4 million
barrels through December 2019 and a short WTI position of
0.8 million
barrels through December 2019. In addition, we had a long power position of
0.3 million
megawatt hours, which hedges a portion of our power supply requirements at our Canadian natural gas processing and fractionation plants through December 2019.
Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.
Interest Rate Risk Hedging
We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.
The following table summarizes the terms of our outstanding interest rate derivatives as of
March 31, 2018
(notional amounts in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Transaction
|
|
Number and Types of
Derivatives Employed
|
|
Notional
Amount
|
|
Expected
Termination Date
|
|
Average Rate
Locked
|
|
Accounting
Treatment
|
Anticipated interest payments
|
|
16 forward starting swaps (30-year)
|
|
$
|
400
|
|
|
6/15/2018
|
|
2.86
|
%
|
|
Cash flow hedge
|
Anticipated interest payments
|
|
8 forward starting swaps (30-year)
|
|
$
|
200
|
|
|
6/14/2019
|
|
2.83
|
%
|
|
Cash flow hedge
|
Currency Exchange Rate Risk Hedging
Because a significant portion of our Canadian business is conducted in CAD we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options.
As of
March 31, 2018
, our outstanding foreign currency derivatives include derivatives we use to hedge currency exchange risk (i) associated with USD-denominated commodity purchases and sales in Canada and (ii) created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales.
The following table summarizes our open forward exchange contracts as of
March 31, 2018
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USD
|
|
CAD
|
|
Average Exchange Rate
USD to CAD
|
Forward exchange contracts that exchange CAD for USD:
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
161
|
|
|
$
|
208
|
|
|
$1.00 - $1.29
|
|
|
|
|
|
|
|
|
|
Forward exchange contracts that exchange USD for CAD:
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
382
|
|
|
$
|
491
|
|
|
$1.00 - $1.29
|
|
|
2019
|
|
$
|
21
|
|
|
$
|
27
|
|
|
$1.00 - $1.28
|
Preferred Distribution Rate Reset Option
A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. The Preferred Distribution Rate Reset Option of the PAA Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, the PAA partnership agreement, and recorded at fair value on our Condensed Consolidated Balance Sheets. Corresponding changes in fair value are recognized in “Other expense, net” in our Condensed Consolidated Statement of Operations. At
March 31, 2018
and
December 31, 2017
, the fair value of this embedded derivative was a liability of approximately
$26 million
and
$22 million
, respectively. We recognized losses of approximately
$4 million
during both the three months ended
March 31, 2018
and 2017. See Note 11 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for additional information regarding the Series A preferred units and Preferred Distribution Rate Reset Option.
Summary of Financial Impact
We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.
A summary of the impact of our derivatives recognized in earnings is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
|
|
Three Months Ended March 31, 2017
|
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
|
|
Derivatives in
Hedging
Relationships
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
$
|
—
|
|
|
$
|
(45
|
)
|
|
$
|
(45
|
)
|
|
|
$
|
—
|
|
|
$
|
96
|
|
|
$
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating costs
|
|
—
|
|
|
1
|
|
|
1
|
|
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
1
|
|
|
—
|
|
|
1
|
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other expense, net
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
1
|
|
|
$
|
(54
|
)
|
|
$
|
(53
|
)
|
|
|
$
|
(2
|
)
|
|
$
|
91
|
|
|
$
|
89
|
|
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of
March 31, 2018
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
Balance Sheet
Location
|
|
Fair
Value
|
|
|
Balance Sheet
Location
|
|
Fair
Value
|
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
Other current assets
|
|
$
|
2
|
|
|
|
Other current liabilities
|
|
$
|
(15
|
)
|
|
Other long-term assets, net
|
|
1
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(1
|
)
|
|
Other current liabilities
|
|
11
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments
|
|
|
$
|
14
|
|
|
|
|
|
$
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
Other current assets
|
|
$
|
260
|
|
|
|
Other current assets
|
|
$
|
(418
|
)
|
|
Other long-term assets, net
|
|
9
|
|
|
|
Other long-term assets, net
|
|
(2
|
)
|
|
Other current liabilities
|
|
9
|
|
|
|
Other current liabilities
|
|
(72
|
)
|
|
Other long-term liabilities and deferred credits
|
|
1
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(14
|
)
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
|
|
|
|
|
Other current liabilities
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
—
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(26
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
279
|
|
|
|
|
|
$
|
(533
|
)
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
$
|
293
|
|
|
|
|
|
$
|
(549
|
)
|
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of
December 31, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
Balance Sheet
Location
|
|
Fair
Value
|
|
|
Balance Sheet
Location
|
|
Fair
Value
|
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
Other current liabilities
|
|
$
|
2
|
|
|
|
Other current liabilities
|
|
$
|
(27
|
)
|
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(11
|
)
|
Total derivatives designated as hedging instruments
|
|
|
$
|
2
|
|
|
|
|
|
$
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
Other current assets
|
|
$
|
73
|
|
|
|
Other current assets
|
|
$
|
(227
|
)
|
|
Other long-term assets, net
|
|
1
|
|
|
|
Other current liabilities
|
|
(131
|
)
|
|
Other current liabilities
|
|
5
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(5
|
)
|
|
Other long-term liabilities and deferred credits
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
Other current assets
|
|
6
|
|
|
|
Other current assets
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
—
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(22
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
88
|
|
|
|
|
|
$
|
(387
|
)
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
$
|
90
|
|
|
|
|
|
$
|
(425
|
)
|
Our derivative transactions (other than the Preferred Distribution Rate Reset Option) are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.
Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable:
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Initial margin
|
$
|
41
|
|
|
$
|
48
|
|
Variation margin posted
|
176
|
|
|
164
|
|
Net broker receivable
|
$
|
217
|
|
|
$
|
212
|
|
The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
|
December 31, 2017
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross position - asset/(liability)
|
$
|
293
|
|
|
$
|
(549
|
)
|
|
|
$
|
90
|
|
|
$
|
(425
|
)
|
Netting adjustment
|
(441
|
)
|
|
441
|
|
|
|
(239
|
)
|
|
239
|
|
Cash collateral paid
|
217
|
|
|
—
|
|
|
|
212
|
|
|
—
|
|
Net position - asset/(liability)
|
$
|
69
|
|
|
$
|
(108
|
)
|
|
|
$
|
63
|
|
|
$
|
(186
|
)
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location After Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
$
|
61
|
|
|
$
|
—
|
|
|
|
$
|
62
|
|
|
$
|
—
|
|
Other long-term assets, net
|
8
|
|
|
—
|
|
|
|
1
|
|
|
—
|
|
Other current liabilities
|
—
|
|
|
(68
|
)
|
|
|
—
|
|
|
(151
|
)
|
Other long-term liabilities and deferred credits
|
—
|
|
|
(40
|
)
|
|
|
—
|
|
|
(35
|
)
|
|
$
|
69
|
|
|
$
|
(108
|
)
|
|
|
$
|
63
|
|
|
$
|
(186
|
)
|
As of
March 31, 2018
, there was a net loss of
$190 million
deferred in AOCI. The deferred net loss recorded in AOCI is expected to be reclassified to future earnings contemporaneously with (i) the earnings recognition of the underlying hedged commodity transaction or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at
March 31, 2018
, we expect to reclassify a net loss of
$8 million
to earnings in the next twelve months. The remaining deferred loss of
$182 million
is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of
March 31, 2018
; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.
The following table summarizes the net deferred gain recognized in AOCI for derivatives (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2018
|
|
2017
|
Interest rate derivatives, net
|
$
|
31
|
|
|
$
|
7
|
|
At
March 31, 2018
and
December 31, 2017
, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in PAA's credit ratings. Although we may be required to post margin on our cleared derivatives as described above, we do not require our non-cleared derivative counterparties to post collateral with us.
Recurring Fair Value Measurements
Derivative Financial Assets and Liabilities
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value as of March 31, 2018
|
|
|
Fair Value as of December 31, 2017
|
Recurring Fair Value Measures
(1)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Commodity derivatives
|
|
$
|
(92
|
)
|
|
$
|
(135
|
)
|
|
$
|
—
|
|
|
$
|
(227
|
)
|
|
|
$
|
5
|
|
|
$
|
(278
|
)
|
|
$
|
(8
|
)
|
|
$
|
(281
|
)
|
Interest rate derivatives
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(36
|
)
|
Foreign currency derivatives
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Preferred Distribution Rate Reset Option
|
|
—
|
|
|
—
|
|
|
(26
|
)
|
|
(26
|
)
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
Total net derivative asset/(liability)
|
|
$
|
(92
|
)
|
|
$
|
(138
|
)
|
|
$
|
(26
|
)
|
|
$
|
(256
|
)
|
|
|
$
|
5
|
|
|
$
|
(310
|
)
|
|
$
|
(30
|
)
|
|
$
|
(335
|
)
|
|
|
(1)
|
Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
|
Level 1
Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives such as futures and options. The fair value of exchange-traded commodity derivatives is based on unadjusted quoted prices in active markets.
Level 2
Level 2 of the fair value hierarchy includes exchange-cleared commodity derivatives and over-the-counter commodity, interest rate and foreign currency derivatives that are traded in active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs.
Level 3
Level 3 of the fair value hierarchy includes certain physical commodity contracts, over-the-counter financial commodity contracts, and the Preferred Distribution Rate Reset Option contained in PAA’s partnership agreement which is classified as an embedded derivative.
The fair value of our Level 3 physical commodity contracts and over-the-counter financial commodity contracts are based on valuation models utilizing significant unobservable pricing inputs and timing estimates, which involve management judgment. Significant deviations from these inputs and estimates could result in a material change in fair value to our physical commodity contracts and over-the-counter financial commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. Unrealized gains and losses associated with the over-the counter financial commodity contracts are reported in our Condensed Consolidated Statements of Operations as Field operating costs.
The fair value of the embedded derivative feature contained in PAA’s partnership agreement is based on a valuation model that estimates the fair value of the PAA Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including PAA’s common unit price, ten-year U.S. treasury rates, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations in “Other expense, net.”
To the extent any transfers between levels of the fair value hierarchy occur, our policy is to reflect these transfers as of the beginning of the reporting period in which they occur.
Rollforward of Level 3 Net Asset/(Liability)
The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives classified as Level 3 (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2018
|
|
2017
|
Beginning Balance
|
$
|
(30
|
)
|
|
$
|
(36
|
)
|
Net losses for the period included in earnings
|
(1
|
)
|
|
(3
|
)
|
Settlements
|
5
|
|
|
3
|
|
Ending Balance
|
$
|
(26
|
)
|
|
$
|
(36
|
)
|
|
|
|
|
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
Note 11—Related Party Transactions
See Note 15 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for a complete discussion of our related party transactions.
Ownership of PAGP Class C Shares
As of
March 31, 2018
and December 31, 2017, PAA owned
512,376,348
and
510,925,432
, respectively, Class C shares. The Class C shares represent a non-economic limited partner interest in us that provides PAA, as the sole holder, a “pass-through” voting right through which PAA's common unitholders and Series A preferred unitholders have the effective right to vote, pro rata with the holders of our Class A and Class B shares, for the election of eligible directors, commencing in May 2018.
Transactions with
Oxy
As of
March 31, 2018
, Oxy had a representative on the board of directors of our general partner and owned approximately
11%
of the limited partner interests in AAP. During the
three
months ended
March 31, 2018
and
2017
, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2018
|
|
2017
|
Revenues
|
$
|
278
|
|
|
$
|
234
|
|
|
|
|
|
Purchases and related costs
(1)
|
$
|
(71
|
)
|
|
$
|
(40
|
)
|
|
|
(1)
|
Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations.
|
We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Trade accounts receivable and other receivables
|
$
|
1,074
|
|
|
$
|
1,075
|
|
|
|
|
|
Accounts payable
|
$
|
984
|
|
|
$
|
990
|
|
Transactions with Equity Method Investees
We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting. We recorded revenues of
$3 million
and
$1 million
during the
three
months ended
March 31, 2018
and
2017
, respectively. In addition, we utilized transportation services and purchased petroleum products provided by these companies. Costs related to these services totaled
$130 million
and
$86 million
for the
three
months ended
March 31, 2018
and
2017
, respectively. These transactions were conducted at posted tariff rates or contracted rates or prices that we believe approximate market.
Receivables from our equity method investees totaled
$38 million
and
$26 million
at
March 31, 2018
and December 31, 2017, respectively, and primarily included amounts related to transportation services. Accounts payable to our equity method investees were
$50 million
and
$41 million
at
March 31, 2018
and December 31, 2017, respectively, and primarily included amounts related to transportation services.
In addition, we have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a
50%
interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.
Note 12
—Commitments and Contingencies
Loss Contingencies — General
To the extent we are able to assess the likelihood of a negative outcome for a contingency, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.
We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.
Legal Proceedings — General
In the ordinary course of business, we are involved in various legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully protect us from losses arising from current or future legal proceedings.
Taking into account what we believe to be all relevant known facts and circumstances, and based on what we believe to be reasonable assumptions regarding the application of those facts and circumstances to existing laws and regulations, we do not believe that the outcome of the legal proceedings in which we are currently involved (including those described below) will, individually or in the aggregate, have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Environmental — General
Although over the course of the last several years we have made significant investments in our maintenance and integrity programs, and have hired additional personnel in those areas, we have experienced (and likely will experience future) releases of hydrocarbon products into the environment from our pipeline, rail, storage and other facility operations. These releases can result from accidents or from unpredictable man-made or natural forces and may reach surface water bodies, groundwater aquifers or other sensitive environments. Damages and liabilities associated with any such releases from our existing or future assets could be significant and could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
We record environmental liabilities when environmental assessments and/or remedial efforts are probable and the amounts can be reasonably estimated. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. We record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.
Environmental expenditures that pertain to current operations or to future revenues are expensed or capitalized consistent with our capitalization policy for property and equipment. Expenditures that result from the remediation of an existing condition caused by past operations and that do not contribute to current or future profitability are expensed.
At
March 31, 2018
, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled
$153 million
, of which
$64 million
was classified as short-term and
$89 million
was classified as long-term. At
December 31, 2017
, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled
$162 million
, of which
$72 million
was classified as short-term and
$90 million
was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At
March 31, 2018
, we had recorded receivables totaling
$54 million
for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which
$28 million
was
reflected in “Trade accounts receivable and other receivables, net” and
$26 million
was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. At
December 31, 2017
, we had recorded
$55 million
of such receivables, of which
$29 million
was reflected in “Trade accounts receivable and other receivables, net” and
$26 million
was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet.
In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Specific Legal, Environmental or Regulatory Matters
Line 901 Incident
. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, is approximately
2,934
barrels; of this amount, we estimate that
598
barrels reached the Pacific Ocean.
As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending:
On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remains in service under a pressure restriction. No timeline has been established for the restart of Line 901 or Line 903.
On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we may have fines or penalties imposed upon us, or civil or criminal charges brought against us, in the future.
In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and
one
of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The May 2016 Indictment included a total of
46
counts. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Since May of 2016,
31
of the criminal charges against PAA (including
one
felony charge) and all of the criminal charges against our employee, have been dismissed.
Nine
of the remaining
15
charges are misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining
six
counts relate to the release of crude oil or reporting of the release. PAA believes that the criminal charges (including the
three
felony charges) are unwarranted and that neither PAA nor any of its employees engaged in any criminal behavior at any time in connection with this accident. PAA continues to vigorously defend itself against the charges.
Also in late May of 2015, the United States Attorney for the Department of Justice, Central District of California, Environmental Crimes Section (“DOJ”) began an investigation into whether there were any violations of federal criminal statutes in connection with the Line 901 incident, including potential violations of the federal Clean Water Act. We are cooperating with the DOJ’s investigation by responding to their requests for documents and access to our employees. The DOJ has already spoken to several of our employees and has expressed an interest in talking to other employees; consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil actions or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment, have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and
no
fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil actions or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies.
Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we are processing those claims for payment as we receive them. In addition, we have also had
nine
class action lawsuits filed against us,
six
of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release. To date, the court has certified three sub-classes of claimants and denied certification of the other proposed sub-class. The sub-classes that have been certified include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas; (ii) individuals or businesses who were employed by or had contracts with certain designated oil platforms and related onshore processing facilities in the vicinity of the release as of the date of the release and (iii) beachfront property and easement owners whose properties were oiled. We are petitioning for leave to appeal the oil industry and property class certifications. We are also defending a separate class action lawsuit proceeding in the United States District Court for the Central District of California brought on behalf of the Line 901 and Line 903 easement holders seeking injunctive relief as well as compensatory damages.
There have also been
two
securities law class action lawsuits filed on behalf of certain purported investors in PAA and/or PAGP against PAA, PAGP and/or certain of their respective officers, directors and underwriters. Both of these lawsuits have been consolidated into a single proceeding in the United States District Court for the Southern District of Texas. In general, these lawsuits allege that the various defendants violated securities laws by misleading investors regarding the integrity of PAA’s pipelines and related facilities through false and misleading statements, omission of material facts and concealing of the true extent of the spill. The plaintiffs claim unspecified damages as a result of the reduction in value of their investments in PAA and PAGP, which they attribute to the alleged wrongful acts of the defendants. PAA and PAGP, and the other defendants, denied the allegations in, and moved to dismiss these lawsuits. On March 29, 2017, the Court ruled in our favor dismissing all claims against all defendants. Plaintiffs refiled their complaint. On April 2, 2018, the Court dismissed all of the refiled claims against all defendants with prejudice. Plaintiffs have filed notice of intent to file an appeal of the dismissal. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we have indemnified and funded the defense costs of our officers and directors in connection with this lawsuit; we have also indemnified and funded the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters.
In addition,
four
unitholder derivative lawsuits have been filed by certain purported investors in PAA against PAA, certain of its affiliates and certain officers and directors.
Two
of these lawsuits were filed in the United States District Court for the Southern District of Texas and were administratively consolidated into one action and later dismissed on the basis that Plains Partnership agreements require that derivative suits be filed in Delaware Chancery Court.
Following the order dismissing the Texas Federal Court suits, a new derivative suit brought by different plaintiffs was filed in Delaware Chancery Court. The other remaining lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court. In general, these lawsuits allege that the various defendants breached their fiduciary duties, engaged in gross mismanagement and made false and misleading statements, among other similar allegations, in connection with their management and oversight of PAA during the period of time leading up to and following the Line 901 release. The plaintiffs in the remaining lawsuit claim that PAA suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in this lawsuit and have responded accordingly. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with this lawsuit.
We have also received several other individual lawsuits and complaints from companies and individuals alleging damages arising out of the Line 901 incident. These lawsuits and claims generally seek compensatory and punitive damages, and in some cases permanent injunctive relief.
In addition to the foregoing, as the “responsible party” for the Line 901 incident we are liable for various costs and for certain natural resource damages under the Oil Pollution Act, and we also have exposure to the payment of additional fines, penalties and costs under other applicable federal, state and local laws, statutes and regulations. To the extent any such costs are reasonably estimable, we have included an estimate of such costs in the loss accrual described below.
Taking the foregoing into account, as of
March 31, 2018
, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately
$335 million
, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statement of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (iv) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, the amount of time it takes for us to resolve all of the current and future lawsuits, claims and investigations that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.
As of
March 31, 2018
, we had a remaining undiscounted gross liability of
$87 million
related to this event, of which approximately
$55 million
is presented as a current liability in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet, with the remainder presented in “Other long-term liabilities and deferred credits”. We maintain insurance coverage, which is subject to certain exclusions and deductibles, in the event of such environmental liabilities. Subject to such exclusions and deductibles, we believe that our coverage is adequate to cover the current estimated total emergency response and clean-up costs, claims settlement costs and remediation costs and we believe that this coverage is also adequate to cover any potential increase in the estimates for these costs that exceed the amounts currently identified. Through
March 31, 2018
, we had collected, subject to customary reservations,
$174 million
out of the approximate
$220 million
of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of
March 31, 2018
, we have recognized a receivable of approximately
$46 million
for the portion of the release costs that we believe is probable of recovery from insurance, net of deductibles and amounts already collected. Of this amount, approximately
$22 million
is recognized as a current asset in “Trade accounts receivable and other receivables, net” on our Condensed Consolidated Balance Sheet, with the remainder in “Other long-term assets, net”. We have completed the required clean-up and remediation work as determined by the Unified Command and the Unified Command has been dissolved; however, we expect to make payments for additional costs associated with restoration of the impacted areas, as well as natural resource damage assessment and compensation, legal, professional and regulatory costs, in addition to fines and penalties, during future periods.
Note 13
—Operating Segments
We manage our operations through
three
operating segments: Transportation, Facilities and Supply and Logistics. See
Note 3
for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including segment adjusted EBITDA (as defined below) and maintenance capital investment.
We define segment adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment adjusted EBITDA excludes depreciation and amortization.
Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.
The following tables reflect certain financial data for each segment (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
253
|
|
|
$
|
141
|
|
|
$
|
8,111
|
|
|
$
|
(107
|
)
|
|
$
|
8,398
|
|
Intersegment
(2)
|
|
201
|
|
|
151
|
|
|
1
|
|
|
107
|
|
|
460
|
|
Total revenues of reportable segments
|
|
$
|
454
|
|
|
$
|
292
|
|
|
$
|
8,112
|
|
|
$
|
—
|
|
|
$
|
8,858
|
|
Equity earnings in unconsolidated entities
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
75
|
|
Segment adjusted EBITDA
|
|
$
|
335
|
|
|
$
|
185
|
|
|
$
|
72
|
|
|
|
|
$
|
592
|
|
Maintenance capital
|
|
$
|
29
|
|
|
$
|
14
|
|
|
$
|
2
|
|
|
|
|
$
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
225
|
|
|
$
|
134
|
|
|
$
|
6,395
|
|
|
$
|
(87
|
)
|
|
$
|
6,667
|
|
Intersegment
(2)
|
|
164
|
|
|
159
|
|
|
5
|
|
|
87
|
|
|
415
|
|
Total revenues of reportable segments
|
|
$
|
389
|
|
|
$
|
293
|
|
|
$
|
6,400
|
|
|
$
|
—
|
|
|
$
|
7,082
|
|
Equity earnings in unconsolidated entities
|
|
$
|
53
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
53
|
|
Segment adjusted EBITDA
|
|
$
|
273
|
|
|
$
|
188
|
|
|
$
|
51
|
|
|
|
|
$
|
512
|
|
Maintenance capital
|
|
$
|
29
|
|
|
$
|
27
|
|
|
$
|
3
|
|
|
|
|
$
|
59
|
|
|
|
(1)
|
Transportation revenues from external customers include inventory exchanges that are substantially similar to tariff-like arrangements with our customers. Under these arrangements, our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See
Note 3
for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue from external customers presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.
|
|
|
(2)
|
Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market at the time the agreement is executed or renegotiated.
|
Segment Adjusted EBITDA Reconciliation
The following table reconciles segment adjusted EBITDA to net income attributable to PAGP (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31,
|
|
2018
|
|
2017
|
Segment adjusted EBITDA
|
$
|
592
|
|
|
$
|
512
|
|
Adjustments
(1)
:
|
|
|
|
Depreciation and amortization of unconsolidated entities
(2)
|
(14
|
)
|
|
(14
|
)
|
Gains from derivative activities net of inventory valuation adjustments
(3)
|
23
|
|
|
289
|
|
Long-term inventory costing adjustments
(4)
|
13
|
|
|
(7
|
)
|
Deficiencies under minimum volume commitments, net
(5)
|
(10
|
)
|
|
(11
|
)
|
Equity-indexed compensation expense
(6)
|
(11
|
)
|
|
(3
|
)
|
Net gain/(loss) on foreign currency revaluation
(7)
|
(10
|
)
|
|
4
|
|
Significant acquisition-related expenses
(8)
|
—
|
|
|
(5
|
)
|
Unallocated general and administrative expenses
|
(1
|
)
|
|
(1
|
)
|
Depreciation and amortization
|
(127
|
)
|
|
(122
|
)
|
Interest expense, net
|
(106
|
)
|
|
(129
|
)
|
Other expense, net
|
(1
|
)
|
|
(5
|
)
|
Income before tax
|
348
|
|
|
508
|
|
Income tax expense
|
(75
|
)
|
|
(106
|
)
|
Net income
|
273
|
|
|
402
|
|
Net income attributable to noncontrolling interests
|
(236
|
)
|
|
(361
|
)
|
Net income attributable to PAGP
|
$
|
37
|
|
|
$
|
41
|
|
|
|
(1)
|
Represents adjustments utilized by our CODM in the evaluation of segment results.
|
|
|
(2)
|
Includes our proportionate share of the depreciation and amortization and gains or losses on significant asset sales of equity method investments.
|
|
|
(3)
|
We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify the earnings that were recognized during the period related to derivative instruments for which the identified underlying transaction does not occur in the current period and exclude the related gains and losses in determining segment adjusted EBITDA. In addition, we exclude gains and losses on derivatives that are related to investing activities, such as the purchase of linefill. We also exclude the impact of corresponding inventory valuation adjustments, as applicable.
|
|
|
(4)
|
We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this
|
inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We exclude the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and writedowns of such inventory that result from price declines from segment adjusted EBITDA.
|
|
(5)
|
We have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on our capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue, as a selected item impacting comparability. Our CODM views the inclusion of the contractually committed revenues associated with that period as meaningful to segment adjusted EBITDA as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results.
|
|
|
(6)
|
Includes equity-indexed compensation expense associated with awards that will or may be settled in PAA common units.
|
|
|
(7)
|
Includes gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities.
|
|
|
(8)
|
Includes acquisition-related expenses associated with the acquisition of the Alpha Crude Connector Gathering System (the “ACC Acquisition”). See Note 6 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of segment adjusted EBITDA for the three months ended March 31, 2017 as our CODM does not view such expenses as integral to understanding our core segment operating performance.
|