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
September 30, 2017
, 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
September 30, 2017
, PAGP owned (i) a
100%
managing member interest in Plains All American GP LLC (“GP LLC”) that has also elected to be taxed as a corporation for United States federal income tax purposes and (ii) an approximate
54%
limited partner interest in Plains AAP, L.P. (“AAP”) through our direct ownership of approximately
153.5 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 holds the non-economic general partner interest in AAP. AAP is a Delaware limited partnership that, as of
September 30, 2017
, directly owned an approximate
36%
limited partner interest in PAA represented by approximately
286.8 million
PAA common units. 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 for crude oil, natural gas liquids (“NGL”), natural gas and refined products. 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: Transportation, Facilities and Supply and Logistics. 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”).
References to the “Plains Entities” include us, our general partner, GP LLC, AAP, PAA GP and PAA and its subsidiaries.
Simplification Transactions
On November 15, 2016, the Plains Entities closed a series of transactions and executed several organizational and ancillary documents (the “Simplification Transactions”) intended to simplify our capital structure, better align the interests of our stakeholders and improve our overall credit profile. The Simplification Transactions included, among other things:
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•
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the permanent elimination of PAA’s incentive distribution rights (“IDRs”) and the economic rights associated with its
2%
general partner interest in exchange for the issuance by PAA to AAP of
245.5 million
PAA common units (including approximately
0.8 million
units to be issued in the future) and the assumption by PAA of all of AAP’s outstanding debt (
$642 million
);
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•
|
the implementation of a unified governance structure pursuant to which the board of directors of GP LLC was eliminated and an expanded board of directors of our general partner assumed oversight responsibility over both us and PAA;
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•
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the provision for annual shareholder meetings beginning in 2018 for the purpose of electing certain directors with expiring terms in 2018, and the participation of PAA’s common unitholders and Series A preferred unitholders in such elections through PAA’s ownership of our newly issued Class C shares, which provide PAA, as the sole holder of such
|
Class C shares, the right to vote in elections of eligible directors together with the holders of our Class A and Class B shares;
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•
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the execution by AAP of a reverse split to adjust the number of AAP units such that the number of outstanding AAP units (assuming the conversion of AAP Class B units (the “AAP Management Units”) into AAP units) equaled the number of PAA common units received by AAP at the closing of the Simplification Transactions. Simultaneously, we executed a reverse split to adjust the number of Class A and Class B shares outstanding to equal the number of AAP units we own following AAP’s reverse unit split. These reverse splits, along with the Omnibus Agreement, resulted in economic alignment between our Class A shareholders and PAA’s common unitholders, such that the number of outstanding Class A shares equals the number of AAP units owned by us, which in turn equals the number of PAA common units held by AAP that are attributable to our interest in AAP. The Plains Entities also entered into an Omnibus Agreement, pursuant to which such one-to-one relationship will be maintained subsequent to the closing of the Simplification Transactions; and
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•
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the creation of a right for certain holders of the AAP units to cause AAP to redeem such AAP units in exchange for an equal number of PAA common units held by AAP. Holders of AAP units other than us and GP LLC continue to have the right to exchange their AAP units (together with the corresponding Class B shares and, if applicable, units of our general partner) for our Class A shares on a one-for-one basis.
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The Simplification Transactions were between and among consolidated subsidiaries of PAGP that are considered entities under common control. These equity transactions did not result in a change in the carrying value of the underlying assets and liabilities. In addition, the Simplification Transactions did not result in a change in ownership interest of PAGP in PAA as described in Accounting Standards Codification (“ASC”) 810-10-45-22, but instead were designed to be an exchange of equal economic ownership interests.
As part of the Simplification Transactions, as discussed above, we effected a reverse split of our Class A and Class B shares, in each case, at a ratio of approximately 1-for-2.663. The effect of the reverse split has been retroactively applied to all share and per-share amounts presented in this Form 10-Q.
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
|
=
|
Accounting Standards Codification
|
ASU
|
=
|
Accounting Standards Update
|
Bcf
|
=
|
Billion cubic feet
|
Btu
|
=
|
British thermal unit
|
CAD
|
=
|
Canadian dollar
|
CODM
|
=
|
Chief Operating Decision Maker
|
EBITDA
|
=
|
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
|
LIBOR
|
=
|
London Interbank Offered Rate
|
LTIP
|
=
|
Long-term incentive plan
|
Mcf
|
=
|
Thousand cubic feet
|
NGL
|
=
|
Natural gas liquids, including ethane, propane and butane
|
NYMEX
|
=
|
New York Mercantile Exchange
|
Oxy
|
=
|
Occidental Petroleum Corporation or its subsidiaries
|
PLA
|
=
|
Pipeline loss allowance
|
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 2016 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, 2016
was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the
three and nine
months ended
September 30, 2017
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.
Upon the completion of the Simplification Transactions, our governance and corporate structure was modified, and based on the guidance contained in ASC 810-10-35-4, we reconsidered our prior determination that our subsidiaries, AAP and PAA, were VIEs. Based on the analysis performed at that time, we concluded that both entities were no longer VIEs. Therefore we concluded that AAP and PAA should be assessed using the voting interest entity model ("VOE"). Under the VOE model, we
considered the new governance and corporate structure introduced by the Simplification Transactions and concluded that PAGP should continue to consolidate AAP and P AA. However, for the second quarter of 2017, we reassessed our consideration of whether PAA and AAP are VIEs and concluded that, contrary to our conclusion at the time of the Simplification Transactions, both PAA and AAP are more appropriately considered VIEs. This conclusion does not change our consolidation conclusion, has no impact on our financial statements and has limited impact on our related disclosures. We have determined that 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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•
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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.
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With the exception of a deferred tax asset of
$2,210 million
and
$1,876 million
as of
September 30, 2017
and
December 31, 2016
, 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
nine
months ended
September 30, 2017
or the year ended
December 31, 2016
, respectively. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2016 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 2016 Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the
nine months ended September 30, 2017
that are of significance or potential significance to us.
Accounting Standards Updates Adopted During the Period
In March 2016, the FASB issued ASU 2016-09,
Compensation — Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
, which simplified several aspects of the accounting for share-based payment
transactions, including the income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification of certain related payments on the statement of cash flows. This guidance was effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted the applicable provisions of the ASU on January 1, 2017 and (i) elected to account for forfeitures as they occur, utilizing the modified retrospective approach of adoption, and (ii) will classify cash paid for taxes when directly withholding units or shares from an employee’s award for tax-withholding purposes as a financing activity on our Condensed Consolidated Statement of Cash Flows. Our adoption did not have a material impact on our financial position or results of operations for the periods presented. We reclassified approximately
$6 million
of cash outflows from operating activities to financing activities for the nine months ended September 30, 2016 related to cash paid for minimum statutory withholding requirements for which PAA units were withheld from employees’ awards.
In January 2017, the FASB issued ASU 2017-04,
Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
. The amendments within this ASU eliminate Step 2 from the goodwill impairment test, which currently requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Under the amended standard, goodwill impairment will instead be measured using Step 1 of the goodwill impairment test with goodwill impairment being equal to the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in the first quarter of 2017 and applied the amendments therein to our 2017 annual goodwill impairment test.
Accounting Standards Updates Issued During the Period
In January 2017, the FASB issued ASU 2017-01,
Business Combinations (Topic 805): Clarifying the Definition of a Business
, which improves the guidance for determining whether a transaction involves the purchase or disposal of a business or an asset. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We plan to adopt this guidance on January 1, 2018 and will apply the new guidance to applicable transactions occurring after that date.
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 update includes the following clarifications: (i) nonfinancial assets within the scope of Subtopic 610-20 may include nonfinancial assets transferred within a legal entity to a counterparty, (ii) an entity should allocate consideration to each distinct asset by applying the guidance in Topic 606 on allocating the transaction price to performance obligations and (iii) requires entities to derecognize a distinct nonfinancial asset or distinct in substance nonfinancial asset in a partial sale transaction when it (1) does not have (or ceases to have) a controlling financial interest in the legal entity that holds the asset in accordance with Subtopic 810-10 and (2) transfers control of the asset in accordance with Topic 606. 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 will adopt this guidance on January 1, 2018 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows.
In May 2017, the FASB issued ASU 2017-09,
Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting
to provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. Under the new guidance, modification accounting is required only if the fair value (or calculated value or intrinsic value, if such alternative method is used), the vesting conditions, or the classification of the award (equity or liability) changes as a result of the change in terms or conditions. This guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted, and prospective application required. We expect to adopt this guidance on January 1, 2018, and we do not currently anticipate that our adoption will have a material impact on our financial position, results of operations and cash flows.
In August 2017, the FASB issued ASU 2017-12,
Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities
to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Under the new guidance, (i) more financial and nonfinancial hedging strategies will be eligible for hedge accounting, (ii) presentation and disclosure requirements are amended and (iii) companies will change the way they assess effectiveness. This guidance is effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. We expect to adopt this guidance on January 1, 2019 and are currently evaluating the impact of the adoption on our financial position, results of operations and cash flows.
Other Accounting Standards Updates
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers (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 those goods or services. This ASU also requires additional disclosures. This ASU can be adopted either with a full retrospective approach or a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption and is effective for interim and annual periods beginning after December 15, 2017. We implemented a process to evaluate the impact of adopting this ASU on each type of revenue contract entered into with customers and our implementation team is in the process of determining appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We have not identified any significant revenue recognition timing differences for types of revenue streams assessed to date; however, our evaluation is not complete. In addition, we are assessing the impact of changes to disclosures and expect an increase in disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. We will adopt this guidance on January 1, 2018, and currently anticipate that we will apply the modified retrospective approach.
Note 3—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. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B 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 9
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.
For the three and nine months ended
September 30, 2017
, and the
three months ended September 30, 2016
, 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 nine months ended September 30, 2016, the possible exchange of any AAP units would have had a dilutive effect on basic net income per Class A share and the possible exchange of certain AAP Management Units would not have had a dilutive effect on basic net income per Class A share. For the
three and nine
months ended
September 30,
2017
and
2016
, 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):
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Three Months Ended
September 30,
|
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Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Basic Net Income per Class A Share
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to PAGP
|
$
|
4
|
|
|
$
|
24
|
|
|
$
|
69
|
|
|
$
|
102
|
|
Basic weighted average Class A shares outstanding
|
154
|
|
|
101
|
|
|
142
|
|
|
99
|
|
|
|
|
|
|
|
|
|
Basic net income per Class A share
|
$
|
0.03
|
|
|
$
|
0.24
|
|
|
$
|
0.49
|
|
|
$
|
1.03
|
|
|
|
|
|
|
|
|
|
Diluted Net Income per Class A Share
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to PAGP
|
$
|
4
|
|
|
$
|
24
|
|
|
$
|
69
|
|
|
$
|
102
|
|
Incremental net income attributable to PAGP resulting from assumed exchange of AAP units and AAP Management Units
|
—
|
|
|
—
|
|
|
—
|
|
|
138
|
|
Net income attributable to PAGP including incremental net income from assumed exchange of AAP units and AAP Management Units
|
$
|
4
|
|
|
$
|
24
|
|
|
$
|
69
|
|
|
$
|
240
|
|
|
|
|
|
|
|
|
|
Basic weighted average Class A shares outstanding
|
154
|
|
|
101
|
|
|
142
|
|
|
99
|
|
Dilutive shares resulting from assumed exchange of AAP units and AAP Management Units
|
—
|
|
|
—
|
|
|
—
|
|
|
137
|
|
Diluted weighted average Class A shares outstanding
|
154
|
|
|
101
|
|
|
142
|
|
|
236
|
|
|
|
|
|
|
|
|
|
Diluted net income per Class A share
|
$
|
0.03
|
|
|
$
|
0.24
|
|
|
$
|
0.49
|
|
|
$
|
1.02
|
|
Note 4—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 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 or parental guarantees. As of
September 30, 2017
and
December 31, 2016
, we had received
$120 million
and
$89 million
, respectively, of advance cash payments from third parties to mitigate credit risk. We also received
$60 million
and
$66 million
as of
September 30, 2017
and
December 31, 2016
, 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 a majority of net-cash settled 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
September 30, 2017
and
December 31, 2016
, 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
September 30, 2017
and
December 31, 2016
. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.
Note 5—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):
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|
|
|
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|
September 30, 2017
|
|
|
December 31, 2016
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Crude oil
|
10,632
|
|
|
barrels
|
|
$
|
480
|
|
|
$
|
45.15
|
|
|
|
23,589
|
|
|
barrels
|
|
$
|
1,049
|
|
|
$
|
44.47
|
|
NGL
|
16,604
|
|
|
barrels
|
|
390
|
|
|
$
|
23.49
|
|
|
|
13,497
|
|
|
barrels
|
|
242
|
|
|
$
|
17.93
|
|
Natural gas
|
—
|
|
|
Mcf
|
|
—
|
|
|
N/A
|
|
|
|
14,540
|
|
|
Mcf
|
|
32
|
|
|
$
|
2.20
|
|
Other
|
N/A
|
|
|
|
|
14
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
20
|
|
|
N/A
|
|
Inventory subtotal
|
|
|
|
|
|
884
|
|
|
|
|
|
|
|
|
|
|
|
1,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Linefill and base gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
12,477
|
|
|
barrels
|
|
729
|
|
|
$
|
58.43
|
|
|
|
12,273
|
|
|
barrels
|
|
710
|
|
|
$
|
57.85
|
|
NGL
|
1,630
|
|
|
barrels
|
|
47
|
|
|
$
|
28.83
|
|
|
|
1,660
|
|
|
barrels
|
|
45
|
|
|
$
|
27.11
|
|
Natural gas
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
|
|
30,812
|
|
|
Mcf
|
|
141
|
|
|
$
|
4.58
|
|
Linefill and base gas subtotal
|
|
|
|
|
|
884
|
|
|
|
|
|
|
|
|
|
|
|
896
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
1,800
|
|
|
barrels
|
|
86
|
|
|
$
|
47.78
|
|
|
|
3,279
|
|
|
barrels
|
|
163
|
|
|
$
|
49.71
|
|
NGL
|
2,120
|
|
|
barrels
|
|
49
|
|
|
$
|
23.11
|
|
|
|
1,418
|
|
|
barrels
|
|
30
|
|
|
$
|
21.16
|
|
Long-term inventory subtotal
|
|
|
|
|
|
135
|
|
|
|
|
|
|
|
|
|
|
|
193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
1,903
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,432
|
|
|
|
|
|
|
(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.
|
At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. Any resulting adjustments are a component of “Purchases and related costs” on our accompanying Condensed Consolidated Statements of Operations. We recorded a charge of
$35 million
during the
nine
months ended
September 30, 2017
primarily related to the writedown of our crude oil inventory due to a decline in prices. Substantially all of this inventory valuation adjustment was offset by the recognition of gains on derivative instruments being utilized to hedge future sales of our crude oil inventory. Such gains were recorded to “Supply and Logistics segment revenues” in our accompanying Condensed Consolidated Statements of Operations. See Note 10 for discussion of our derivative and risk management activities. We recorded an inventory valuation adjustment of
$3 million
during the
nine
months ended
September 30, 2016
.
Note 6
—Acquisitions and Dispositions
Acquisitions
The following acquisitions were accounted for using the acquisition method of accounting and the determination of the fair value of the assets and liabilities acquired has been estimated in accordance with the applicable accounting guidance.
Alpha Crude Connector Acquisition
On February 14, 2017, we acquired all of the issued and outstanding membership interests in Alpha Holding Company, LLC for cash consideration of approximately
$1.217 billion
, subject to working capital and other adjustments (the “ACC Acquisition”). The ACC Acquisition was initially funded through borrowings under PAA's senior unsecured revolving credit facility. Such borrowings were subsequently repaid with proceeds from PAA's March 2017 issuance of its common units to AAP pursuant to the Omnibus Agreement and in connection with our underwritten equity offering. See
Note 9
for additional information.
Upon completion of the ACC Acquisition, we became the owner of a crude oil gathering system known as the “Alpha Crude Connector” (the “ACC System”) located in the Northern Delaware Basin in Southeastern New Mexico and West Texas. The ACC System comprises approximately
515
miles of gathering and transmission lines and
five
market interconnects, including to our Basin Pipeline at Wink. We intend to make additional interconnects to our existing Northern Delaware Basin systems as well as additional enhancements intended to increase the ACC System capacity to approximately
350,000
barrels per day, depending on the level of volume at each delivery point. The ACC System is supported by acreage dedications covering approximately
315,000
gross acres, including a significant acreage dedication from one of the largest producers in the region. The ACC System complements our other Permian Basin assets and enhances the services available to the producers in the Northern Delaware Basin.
The determination of the acquisition-date fair value of the assets acquired and liabilities assumed is preliminary. We expect to finalize our fair value determination in 2017. The following table reflects the preliminary fair value determination (in millions):
|
|
|
|
|
|
|
|
Identifiable assets acquired and liabilities assumed:
|
|
Estimated Useful Lives (Years)
|
|
Recognized amount
|
Property and equipment
|
|
3 - 70
|
|
$
|
299
|
|
Intangible assets
|
|
20
|
|
646
|
|
Goodwill
|
|
N/A
|
|
271
|
|
Other assets and liabilities, net (including $4 million of cash acquired)
|
|
N/A
|
|
1
|
|
|
|
|
|
$
|
1,217
|
|
Intangible assets are included in “Other long-term assets, net” on our Condensed Consolidated Balance Sheets. The preliminary determination of fair value to intangible assets above is comprised of
five
acreage dedication contracts and associated customer relationships that will be amortized over a remaining weighted average useful life of approximately
20
years. The value assigned to such intangible assets will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits will be consumed. Amortization expense was approximately
$7 million
for the period from February 14, 2017 through
September 30, 2017
, and the future amortization expense is estimated as follows for the next five years (in millions):
|
|
|
|
|
|
Remainder of 2017
|
|
$
|
3
|
|
2018
|
|
$
|
25
|
|
2019
|
|
$
|
34
|
|
2020
|
|
$
|
42
|
|
2021
|
|
$
|
48
|
|
Goodwill is an intangible asset representing the future economic benefits expected to be derived from other assets acquired that are not individually identified and separately recognized. The goodwill arising from the ACC Acquisition, which is tax deductible, represents the anticipated opportunities to generate future cash flows from undedicated acreage and the synergies created between the ACC System and our existing assets. The assets acquired in the ACC Acquisition, as well as the associated goodwill, are primarily included in our Transportation segment.
During the nine months ended
September 30, 2017
, we incurred approximately
$6 million
of acquisition-related costs associated with the ACC Acquisition. Such costs are reflected as a component of general and administrative expenses in our Condensed Consolidated Statements of Operations.
Pro forma financial information assuming the ACC Acquisition had occurred as of the beginning of the calendar year prior to the year of acquisition, as well as the revenues and earnings generated during the period since the acquisition date, were not material for disclosure purposes.
Other Acquisitions
In February 2017, we acquired a propane marine terminal for cash consideration of approximately
$41 million
. The assets acquired are included in our Facilities segment. We did not recognize any goodwill related to this acquisition.
Investment Acquisition
On April 3, 2017, we and an affiliate of Noble Midstream Partners LP (“Noble”) completed the acquisition of Advantage Pipeline, L.L.C. (“Advantage”) for a purchase price of
$133 million
through a newly formed 50/50 joint venture (the “Advantage Joint Venture”). For our
50%
share (
$66.5 million
), we contributed approximately
1.3
million PAA common units with a value of approximately
$40 million
and approximately
$26 million
in cash. We account for our interest in the Advantage Joint Venture under the equity method of accounting.
Advantage owns a
70
-mile,
16
-inch crude oil pipeline located in the southern Delaware Basin (the “Advantage Pipeline”), which is contractually supported by a third-party acreage dedication and a volume commitment from our wholly-owned marketing subsidiary. Noble serves as operator of Advantage Pipeline. During the third quarter of 2017, Noble completed construction of a pipeline to deliver crude oil to the Advantage Pipeline from its central gathering facility in the southern Delaware Basin, and we completed construction of a pipeline to connect our Wolfbone Ranch facility to the Advantage Pipeline near Highway 285 in Reeves County, Texas.
Dispositions, Divestitures and Assets Held for Sale
During the
nine
months ended
September 30, 2017
, we received proceeds of approximately
$407 million
from the sale of certain non-core assets, including:
|
|
•
|
our Bluewater natural gas storage facility located in Michigan;
|
|
|
•
|
non-core pipeline segments primarily located in the Midwestern United States; and
|
|
|
•
|
a
40%
undivided interest in a segment of our Red River Pipeline extending from Cushing, Oklahoma to the Hewitt Station near Ardmore, Oklahoma (the “Hewitt Segment”) for our net book value. We retained a
60%
undivided interest in the Hewitt Segment and a
100%
interest in the remaining portion of the Red River Pipeline that extends from Ardmore to Longview, Texas.
|
Our Bluewater natural gas storage facility was reported in our Facilities segment, and the pipeline segments were reported in our Transportation segment.
As of
September 30, 2017
, we classified approximately
$630 million
of assets as held for sale on our Condensed Consolidated Balance Sheet (in “Other current assets”). The assets held for sale are primarily property and equipment, are included in our Facilities and Transportation segments and are related to transactions to sell our interests in:
|
|
•
|
certain non-core pipelines in the Rocky Mountain and Bakken regions, which closed during the fourth quarter of 2017; and
|
|
|
•
|
certain of our West Coast terminal assets located in California. During the third quarter of 2017, in order to avoid continued uncertainty and costs associated with efforts by the Attorney General for the State of California to block the proposed transaction, our previously disclosed definitive agreement for the potential sale of California terminal assets was jointly terminated by us and the potential third party purchaser. During the fourth quarter of 2017, we entered into definitive agreements to sell these assets to another third-party purchaser.
|
In the aggregate, including non-cash impairment losses recognized upon reclassification to assets held for sale, we recognized net losses related to pending or completed asset sales of approximately
$15 million
and
$15 million
for the three and nine months ended September 30, 2017, respectively, which are included in “Depreciation and amortization” on our Condensed Consolidated Statements of Operations. For the three-month period, such amount is comprised of gains of
$5 million
and losses of
$20 million
. For the nine-month 2017 period, such amount is comprised of gains of
$42 million
, primarily related to the sale of the non-core pipeline segments, including the write-off of a portion of the remaining book value, and losses of
$57 million
.
During the fourth quarter of 2017, we and an affiliate of CVR Refining, LP (“CVR Refining”) formed a 50/50 joint venture, Midway Pipeline LLC, which acquired from us the Cushing to Broome crude oil pipeline system. The Cushing to Broome pipeline system connects CVR Refining’s Coffeyville, Kansas refinery to the Cushing, Oklahoma oil hub. We will continue to serve as operator of the pipeline.
Note 7—Goodwill
Goodwill by segment and changes in goodwill are reflected in the following table (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
|
|
Facilities
|
|
Supply and Logistics
|
|
Total
|
Balance at December 31, 2016
|
$
|
806
|
|
|
$
|
1,034
|
|
|
$
|
504
|
|
|
$
|
2,344
|
|
Acquisitions
(1)
|
271
|
|
|
—
|
|
|
—
|
|
|
271
|
|
Foreign currency translation adjustments
|
17
|
|
|
8
|
|
|
4
|
|
|
29
|
|
Dispositions and reclassifications to assets held for sale
|
(13
|
)
|
|
(33
|
)
|
|
—
|
|
|
(46
|
)
|
Balance at September 30, 2017
|
$
|
1,081
|
|
|
$
|
1,009
|
|
|
$
|
508
|
|
|
$
|
2,598
|
|
|
|
(1)
|
Goodwill is recorded at the acquisition date based on a preliminary fair value determination. This preliminary goodwill balance may be adjusted when the fair value determination is finalized.
|
We completed our goodwill impairment test as of June 30, 2017 using a qualitative assessment. We determined that it was more likely than not that the fair value of each reporting unit was greater than its respective book value; therefore, additional impairment testing was not necessary and goodwill was not considered impaired.
Note 8
—Debt
Debt consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
September 30,
2017
|
|
December 31, 2016
|
SHORT-TERM DEBT
|
|
|
|
|
|
PAA commercial paper notes, bearing a weighted-average interest rate of 2.4% and 1.6%, respectively
(1)
|
$
|
93
|
|
|
$
|
563
|
|
PAA senior secured hedged inventory facility, bearing a weighted-average interest rate of 2.3% and 1.8%, respectively
(1)
|
753
|
|
|
750
|
|
PAA senior notes:
|
|
|
|
|
|
6.13% senior notes due January 2017
|
—
|
|
|
400
|
|
Other
|
72
|
|
|
2
|
|
Total short-term debt
(2)
|
918
|
|
|
1,715
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
|
PAA senior notes, net of unamortized discounts and debt issuance costs of $69 and $76, respectively
(3)
|
9,881
|
|
|
9,874
|
|
PAA commercial paper notes, bearing a weighted-average interest rate of 2.4% and 1.6%, respectively
(3)
|
605
|
|
|
247
|
|
Other
|
3
|
|
|
3
|
|
Total long-term debt
|
10,489
|
|
|
10,124
|
|
Total debt
(4)
|
$
|
11,407
|
|
|
$
|
11,839
|
|
|
|
(1)
|
We classified these PAA commercial paper notes and credit facility borrowings as short-term as of
September 30, 2017
and
December 31, 2016
, 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
September 30, 2017
and
December 31, 2016
, balance includes borrowings of
$194 million
and
$410 million
, respectively, for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.
|
|
|
(3)
|
As of
September 30, 2017
, we have classified PAA's
$600 million
,
6.50%
senior notes due May 2018 as long-term and as of both
September 30, 2017
and
December 31, 2016
, we have classified a portion of PAA's commercial paper notes 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 (including current maturities) had a face value of approximately
$9.9 billion
and
$10.3 billion
as of
September 30, 2017
and
December 31, 2016
, respectively. We estimated the aggregate fair value of these notes as of
September 30, 2017
and
December 31, 2016
to be approximately
$10.0 billion
and
$10.4 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.
|
Credit Facilities
In August 2017, PAA extended the maturity dates of its senior unsecured revolving credit facility, senior secured hedged inventory facility and senior unsecured 364-day revolving credit facility to August 2022, August 2020 and August 2018, respectively, for each extending lender. Additionally, a provision was added to the 364-day revolving credit facility agreement whereby PAA may elect to have the entire principal balance of any loans outstanding on the maturity date of the 364-day revolving credit facility converted into a non-revolving term loan with a maturity date of August 2019.
Borrowings and Repayments
Total borrowings under the credit facilities and the PAA commercial paper program for the
nine
months ended
September 30, 2017
and
2016
were approximately
$52.6 billion
and
$41.4 billion
, respectively. Total repayments under the credit facilities and the PAA commercial paper program were approximately
$52.7 billion
and
$41.6 billion
for the
nine
months ended
September 30, 2017
and
2016
, 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
September 30, 2017
and
December 31, 2016
, we had outstanding letters of credit of
$95 million
and
$73 million
, respectively.
Senior Notes Repayments
PAA's
$400 million
,
6.13%
senior notes were repaid in January 2017. We utilized cash on hand and available capacity under PAA's commercial paper program and credit facilities to repay these notes.
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, 2016
|
101,206,526
|
|
|
138,043,486
|
|
|
491,910,863
|
|
Conversion of AAP Management Units
(1)
|
—
|
|
|
1,557,860
|
|
|
—
|
|
Exchange Right exercises
(1)
|
3,231,281
|
|
|
(3,231,281
|
)
|
|
—
|
|
Redemption Right exercises
(1)
|
—
|
|
|
(4,959,861
|
)
|
|
4,959,861
|
|
Sales of Class A shares
|
50,086,326
|
|
|
—
|
|
|
—
|
|
Sales of common units by a subsidiary
|
—
|
|
|
—
|
|
|
4,033,567
|
|
Issuance of common units by a subsidiary in connection with acquisition of interest in Advantage Joint Venture (Note 6)
|
—
|
|
|
—
|
|
|
1,252,269
|
|
Issuances of Series A preferred units by a subsidiary
|
—
|
|
|
—
|
|
|
3,941,096
|
|
Other
|
19,060
|
|
|
—
|
|
|
603,497
|
|
Outstanding at September 30, 2017
|
154,543,193
|
|
|
131,410,204
|
|
|
506,701,153
|
|
|
|
|
|
|
|
|
|
Class A Shares
|
|
Class B Shares
|
Outstanding at December 31, 2015
|
86,099,037
|
|
|
141,485,588
|
|
Conversion of AAP Management Units
(1)
|
—
|
|
|
13,567,916
|
|
Exchange Right exercises
(1)
|
14,665,076
|
|
|
(14,665,076
|
)
|
Issuance of Class A shares under LTIP
|
7,811
|
|
|
—
|
|
Outstanding at September 30, 2016
|
100,771,924
|
|
|
140,388,428
|
|
___________________________________________
|
|
(1)
|
See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for information regarding conversions of AAP Management Units, Exchange Rights and Redemption Rights.
|
Distributions
On August 25, 2017, PAA announced its intention to reset its annualized distribution to
$1.20
per common unit, beginning with the third-quarter distribution payable November 14, 2017. The amount of cash available to distribute to our Class A shareholders is completely dependent upon the amount of cash distributed by PAA to AAP in respect of its common units; therefore, any change in the distribution level on PAA's common units has a corresponding impact on the distribution level on our Class A shares. See “—Subsidiary Distributions” below for additional information.
The following table details the distributions paid to our Class A shareholders during or pertaining to the first
nine
months of
2017
(in millions, except per share data):
|
|
|
|
|
|
|
|
|
|
Distribution Payment Date
|
|
Distributions to
Class A Shareholders
|
|
Distributions per
Class A Share
|
November 14, 2017
(1)
|
|
$
|
46
|
|
|
$
|
0.30
|
|
August 14, 2017
|
|
$
|
84
|
|
|
$
|
0.55
|
|
May 15, 2017
|
|
$
|
84
|
|
|
$
|
0.55
|
|
February 14, 2017
|
|
$
|
57
|
|
|
$
|
0.55
|
|
___________________________________________
|
|
(1)
|
Payable to shareholders of record at the close of business on
October 31, 2017
for the period
July 1, 2017
through
September 30, 2017
.
|
Sales of Class A Shares
The following table summarizes our sales of Class A shares during the
nine
months ended
September 30, 2017
, all of which occurred in the first four months of the year (net proceeds in millions):
|
|
|
|
|
|
|
|
|
|
Type of Offering
|
|
Class A Shares Issued
|
|
Net Proceeds
(1)
|
|
Continuous Offering Program
|
|
1,786,326
|
|
|
$
|
61
|
|
(2)
|
Underwritten Offering
|
|
48,300,000
|
|
|
1,474
|
|
|
|
|
50,086,326
|
|
|
$
|
1,535
|
|
|
|
|
(1)
|
Amounts are net of costs associated with the offerings.
|
|
|
(2)
|
We pay commissions to our sales agents in connection with issuances of Class A shares under our Continuous Offering Program. We paid
$1 million
of such commissions during the
nine
months ended
September 30, 2017
.
|
Pursuant to the Omnibus Agreement entered into by the Plains Entities in connection with the Simplification Transactions, we used the net proceeds from the sale of our Class A shares, after deducting the sales agents’ commissions and offering expenses, to purchase from AAP a number of AAP units equal to the number of Class A shares sold in such offering at a price equal to the net proceeds from such offering. Also pursuant to the Omnibus Agreement, immediately following such purchase and sale, AAP used the net proceeds it received from such sale of AAP units to us to purchase from PAA an equivalent number of common units of PAA. See “—Subsidiary Sales of Units” below.
The cash purchase by PAGP of additional units issued by AAP and corresponding cash purchase by AAP of additional common units issued by PAA results in the allocation of the fair value of the proceeds between controlling and noncontrolling interests in AAP and PAA based on their respective ownership percentages. Additionally, in accordance with ASC 810, an adjustment in partners' capital based on historical carrying value is recognized by PAGP’s Class A shareholders on their increase in ownership of subsidiary entities and a corresponding adjustment is recognized in partners' capital by PAGP’s noncontrolling interests due to the dilution of their ownership interest. The allocation to noncontrolling interests results from the difference between the fair value per unit of the additional units issued and the historical carrying value per unit. Such amounts are reflected in “Sales of Class A shares” on our Condensed Consolidated Statements of Changes in Partners' Capital.
Consolidated Subsidiaries
Noncontrolling Interests in Subsidiaries
As of
September 30, 2017
, noncontrolling interests in our subsidiaries consisted of (i) a
64%
limited partner interest in PAA, (ii) an approximate
46%
limited partner interest in AAP and (iii) a
25%
interest in SLC Pipeline LLC.
Subsidiary Sales of Units
Issuance of Series B Preferred Units
On October 10, 2017, PAA issued
800,000
Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in PAA (the “Series B preferred units”) at a price to the public of
$1,000
per unit. PAA used the net proceeds of
$788 million
, after deducting the underwriters’ discounts and offering expenses, from the issuance of the Series B preferred units to repay amounts outstanding under its credit facilities and commercial paper program and for general partnership purposes.
The Series B preferred units represent perpetual equity interests in PAA, and they have no stated maturity or mandatory redemption date and are not redeemable at the option of the holders under any circumstances. Holders of the Series B preferred units generally have no voting rights, except for limited voting rights with respect to (i) potential amendments to PAA's partnership agreement that would have a material adverse effect on the existing preferences, rights, powers or duties of the Series B preferred units, (ii) the creation or issuance of any parity securities if the cumulative distributions payable on then outstanding Series B preferred units are in arrears, (iii) the creation or issuance of any senior securities and (iv) the payment of distributions to PAA's common unitholders out of capital surplus. The Series B preferred units rank, as to the payment of distributions and amounts payable on a liquidation event, on par with PAA's outstanding Series A preferred units.
The Series B preferred units have a liquidation preference of
$1,000
per unit. Holders of PAA's Series B preferred units are entitled to receive, when, as and if declared by its general partner out of legally available funds for such purpose, cumulative semiannual or quarterly cash distributions, as applicable. Distributions on the Series B preferred units accrue and are cumulative from October 10, 2017, the date of original issue, and are payable semiannually in arrears on the 15th day of May and November through and including November 15, 2022, and after November 15, 2022, quarterly in arrears on the 15th day of February, May, August and November of each year. The initial distribution rate for the Series B preferred units from and including October 10, 2017 to, but not including, November 15, 2022 is
6.125%
per year of the liquidation preference per unit (equal to
$61.25
per unit per year). On and after November 15, 2022, distributions on the Series B preferred units will accumulate for each distribution period at a percentage of the liquidation preference equal to the then-current three-month LIBOR plus a spread of
4.11%
. PAA will pay a pro-rated initial distribution on the Series B preferred units on November 15, 2017 to holders of record at the close of business on November 1, 2017 in an amount equal to approximately
$5.9549
per unit (a total distribution of approximately
$5 million
).
Upon the occurrence of certain rating agency events, PAA may redeem the Series B preferred units, in whole but not in part, at a price of
$1,020
(
102%
of the liquidation preference) per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared. In addition, at any time on or after November 15, 2022, PAA may redeem the Series B preferred units, at its option, in whole or in part, at a redemption price of
$1,000
per Series B preferred unit plus an amount equal to all accumulated and unpaid distributions thereon to, but not including, the date of redemption, whether or not declared.
Issuance of Common Units
Continuous Offering Program.
During the
nine
months ended
September 30, 2017
, PAA issued an aggregate of approximately
4.0 million
common units under its continuous offering program, generating proceeds of
$129 million
, net of
$1 million
of commissions paid to its sales agents.
The proceeds from the issuance of PAA common units were allocated among all of PAA’s common unitholders, including AAP, based on their percentage ownership of common units. Additionally, PAA’s capital attributable to AAP was adjusted based on historical carrying value, in accordance with ASC 810, to reflect the dilution of its interest in PAA as a result of the issuance of additional common units to the public unitholders. These adjustments were recognized by PAGP in proportion to PAGP’s ownership interest in AAP, which resulted in a net increase in partners’ capital attributable to PAGP resulting from the difference between the fair value per unit of the additional units issued and the historical carrying value per unit. Such amounts are reflected in “Sales of common units by a subsidiary” on our Condensed Consolidated Statements of Changes in Partners' Capital.
Omnibus Agreement.
During the
nine
months ended
September 30, 2017
, pursuant to the Omnibus Agreement discussed above, PAA sold (i) approximately
1.8 million
common units to AAP in connection with our issuance of Class A shares under our Continuous Offering Program and (ii)
48.3 million
common units to AAP in connection with our March 2017 underwritten offering.
Deferred Tax Asset Impact from the Sale of Subsidiary Units
In connection with the sales of AAP units and PAA common units referenced above, a deferred asset was created. The tax basis of PAGP’s purchase of the additional units was accounted for at fair market value for U.S. federal income tax purposes, but the GAAP basis was impacted by the adjustments that are based on historical carrying value. The resulting basis difference resulted in a deferred tax asset that was recorded as a component of partner’s capital as it results from transactions with shareholders.
Subsidiary Distributions
PAA Common Unit Distributions.
During the third quarter of 2017, PAA’s management engaged in discussions with our Board of Directors regarding a reassessment of PAA’s approach to distributions, with a focus on resetting PAA’s common unit distribution to a level supported by the distributable cash flow from its fee-based Transportation and Facilities segments. On August 25, 2017, PAA announced its intention to reset its annualized distribution to
$1.20
per common unit, beginning with the third-quarter distribution payable November 14, 2017. On October 10, 2017, the PAGP GP Board declared a distribution of
$1.20
(annualized) per common unit payable on November 14, 2017 to common unitholders of record as of October 31, 2017.
The following table details the distributions to PAA’s common unitholders paid in cash during or pertaining to the first
nine
months of
2017
(in millions, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
Cash Distribution per Common Unit
|
|
|
Common Unitholders
|
|
Total Cash Distribution
|
|
|
Distribution Payment Date
|
|
Public
|
|
AAP
|
|
|
|
November 14, 2017
(1)
|
|
$
|
132
|
|
|
$
|
86
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
August 14, 2017
|
|
$
|
240
|
|
|
$
|
159
|
|
|
$
|
399
|
|
|
|
$
|
0.55
|
|
May 15, 2017
|
|
$
|
240
|
|
|
$
|
159
|
|
|
$
|
399
|
|
|
|
$
|
0.55
|
|
February 14, 2017
|
|
$
|
237
|
|
|
$
|
134
|
|
|
$
|
371
|
|
|
|
$
|
0.55
|
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
October 31, 2017
for the period
July 1, 2017
through
September 30, 2017
.
|
PAA Series A Preferred Unit Distributions
. With respect to any quarter ending on or prior to December 31, 2017 (the “Initial Distribution Period”), PAA may elect to pay distributions on the PAA Series A preferred units in additional preferred units, in cash or a combination of both. With respect to any quarter ending after the Initial Distribution Period, PAA must pay distributions on the PAA Series A preferred units in cash. On February 14, 2017, PAA issued
1,287,773
Series A preferred units in lieu of a cash distribution of
$34 million
on PAA's Series A preferred units outstanding as of the record date for such distribution. On May 15, 2017, PAA issued
1,313,527
Series A preferred units in lieu of a cash distribution of
$34 million
on PAA's Series A preferred units outstanding as of the record date for such distribution. On August 14, 2017, PAA issued
1,339,796
Series A preferred units in lieu of a cash distribution of
$35 million
on PAA's Series A preferred units outstanding as of the record date for such distribution.
On November 14, 2017, PAA will issue
1,366,593
Series A preferred units in lieu of a cash distribution of $
36
million on PAA's Series A preferred units outstanding as of October 31, 2017, the record date for such distribution.
PAA Series B Preferred Unit Distributions.
For its Series B preferred units issued on October 10, 2017, PAA will pay a pro-rated initial distribution on November 15, 2017. See “—Subsidiary Sales of Units” above for additional information.
AAP Distributions.
The following table details the distributions paid to AAP’s partners during or pertaining to the first
nine
months of
2017
from distributions received from PAA (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distribution to AAP's Partners
|
Distribution Payment Date
|
|
Noncontrolling Interests
|
|
PAGP
|
|
Total Cash Distributions
|
November 14, 2017
(1)
|
|
$
|
40
|
|
|
$
|
46
|
|
|
$
|
86
|
|
August 14, 2017
|
|
$
|
75
|
|
|
$
|
84
|
|
|
$
|
159
|
|
May 15, 2017
|
|
$
|
75
|
|
|
$
|
84
|
|
|
$
|
159
|
|
February 14, 2017
|
|
$
|
77
|
|
|
$
|
57
|
|
|
$
|
134
|
|
___________________________________________
|
|
(1)
|
Payable to unitholders of record at the close of business on
October 31, 2017
for the period
July 1, 2017
through
September 30, 2017
.
|
Other Distributions.
During the
nine
months ended
September 30, 2017
, distributions of
$2 million
were paid to noncontrolling interests in SLC Pipeline LLC.
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
September 30, 2017
, net derivative positions related to these activities included:
|
|
•
|
A net long position of
6.9 million
barrels associated with our crude oil purchases, which was unwound ratably during October 2017 to match monthly average pricing.
|
|
|
•
|
A net short time spread position of
3.5 million
barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through December 2018.
|
|
|
•
|
A crude oil grade basis position of
25.2 million
barrels through December 2019. These derivatives allow us to lock in grade basis differentials.
|
|
|
•
|
A net short position of
14.4 million
barrels through December 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 that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. 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
September 30, 2017
, our PLA hedges included a long call option position of
1.0 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
September 30, 2017
, we had a long natural gas position of
63.9
Bcf which hedges our natural gas processing and operational needs through December 2020. We also had a short propane position of
10.0 million
barrels through December 2018, a short butane position of
3.0 million
barrels through December 2018 and a short WTI position of
1.0 million
barrels through December 2018. In addition, we had a long power position of
0.4 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 risk 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 derivatives as of
September 30, 2017
(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 and, at times, a portion of our debt is denominated 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
September 30, 2017
, 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
September 30, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USD
|
|
CAD
|
|
Average Exchange Rate
USD to CAD
|
Forward exchange contracts that exchange CAD for USD:
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
$
|
174
|
|
|
$
|
215
|
|
|
$1.00 - $1.24
|
|
|
2018
|
|
$
|
12
|
|
|
$
|
15
|
|
|
$1.00 - $1.22
|
|
|
|
|
|
|
|
|
|
Forward exchange contracts that exchange USD for CAD:
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
$
|
307
|
|
|
$
|
385
|
|
|
$1.00 - $1.26
|
|
|
2018
|
|
$
|
118
|
|
|
$
|
147
|
|
|
$1.00 - $1.25
|
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 income/(expense), net” in our Condensed Consolidated Statement of Operations. At
September 30, 2017
and
December 31, 2016
, the fair value of this embedded derivative was a liability of approximately
$33 million
and
$32 million
, respectively. We recognized a gain of approximately
$2 million
during the three months ended
September 30, 2017
and a net gain of less than
$1 million
during the nine months ended
September 30, 2017
. We recognized gains of approximately
$17 million
and
$42 million
during the
three and nine
months ended
September 30, 2016
. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K for additional information regarding the 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 derivative activities recognized in earnings is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
|
Three Months Ended September 30, 2016
|
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
(1)
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
|
|
Derivatives in
Hedging
Relationships
(1)
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
$
|
—
|
|
|
$
|
(226
|
)
|
|
$
|
(226
|
)
|
|
|
$
|
1
|
|
|
$
|
10
|
|
|
$
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation segment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating costs
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
—
|
|
|
3
|
|
|
3
|
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income/(expense), net
|
|
—
|
|
|
2
|
|
|
2
|
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(10
|
)
|
|
$
|
(225
|
)
|
|
$
|
(235
|
)
|
|
|
$
|
(1
|
)
|
|
$
|
25
|
|
|
$
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
|
Nine Months Ended September 30, 2016
|
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
(1)
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
|
|
Derivatives in
Hedging
Relationships
(1)
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
$
|
—
|
|
|
$
|
(31
|
)
|
|
$
|
(31
|
)
|
|
|
$
|
1
|
|
|
$
|
(118
|
)
|
|
$
|
(117
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation segment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating costs
|
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(16
|
)
|
|
—
|
|
|
(16
|
)
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
—
|
|
|
5
|
|
|
5
|
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income/(expense), net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
42
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(19
|
)
|
|
$
|
(34
|
)
|
|
$
|
(53
|
)
|
|
|
$
|
(7
|
)
|
|
$
|
(70
|
)
|
|
$
|
(77
|
)
|
|
|
(1)
|
During the three and nine months ended
September 30, 2017
, we reclassified losses of approximately
$8 million
and
$10 million
to Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring. During the
nine
months ended
September 30, 2016
we reclassified losses of approximately
$2 million
and
$2 million
to Supply and Logistics segment revenues and Interest expense, net, respectively, due to anticipated hedged transactions being probable of not occurring.
|
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of
September 30, 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
|
|
$
|
(26
|
)
|
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(10
|
)
|
Total derivatives designated as hedging instruments
|
|
|
$
|
2
|
|
|
|
|
|
$
|
(36
|
)
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
Other current assets
|
|
$
|
74
|
|
|
|
Other current assets
|
|
$
|
(184
|
)
|
|
Other long-term assets, net
|
|
1
|
|
|
|
Other current liabilities
|
|
(97
|
)
|
|
Other current liabilities
|
|
10
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(19
|
)
|
|
Other long-term liabilities and deferred credits
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
Other current assets
|
|
6
|
|
|
|
Other current assets
|
|
(2
|
)
|
|
|
|
|
|
|
|
Other current liabilities
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
—
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(33
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
96
|
|
|
|
|
|
$
|
(337
|
)
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
$
|
98
|
|
|
|
|
|
$
|
(373
|
)
|
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of
December 31, 2016
(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
|
|
$
|
(23
|
)
|
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(27
|
)
|
Total derivatives designated as hedging instruments
|
|
|
$
|
—
|
|
|
|
|
|
$
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
Other current assets
|
|
$
|
101
|
|
|
|
Other current assets
|
|
$
|
(344
|
)
|
|
Other long-term assets, net
|
|
2
|
|
|
|
Other long-term assets, net
|
|
(1
|
)
|
|
Other long-term liabilities and deferred credits
|
|
2
|
|
|
|
Other current liabilities
|
|
(14
|
)
|
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
Other current liabilities
|
|
3
|
|
|
|
Other current liabilities
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
—
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(32
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
108
|
|
|
|
|
|
$
|
(431
|
)
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
$
|
108
|
|
|
|
|
|
$
|
(481
|
)
|
Our derivative transactions are governed through ISDA (International Swaps and Derivatives Association) 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:
|
|
|
|
|
|
|
|
|
|
September 30,
2017
|
|
December 31, 2016
|
Initial margin
|
$
|
51
|
|
|
$
|
119
|
|
Variation margin posted
|
143
|
|
|
291
|
|
Net broker receivable
|
$
|
194
|
|
|
$
|
410
|
|
The following table presents information about derivative financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2017
|
|
|
December 31, 2016
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross position - asset/(liability)
|
$
|
98
|
|
|
$
|
(373
|
)
|
|
|
$
|
108
|
|
|
$
|
(481
|
)
|
Netting adjustment
|
(203
|
)
|
|
203
|
|
|
|
(350
|
)
|
|
350
|
|
Cash collateral paid
|
194
|
|
|
—
|
|
|
|
410
|
|
|
—
|
|
Net position - asset/(liability)
|
$
|
89
|
|
|
$
|
(170
|
)
|
|
|
$
|
168
|
|
|
$
|
(131
|
)
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location After Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
$
|
88
|
|
|
$
|
—
|
|
|
|
$
|
167
|
|
|
$
|
—
|
|
Other long-term assets, net
|
1
|
|
|
—
|
|
|
|
1
|
|
|
—
|
|
Other current liabilities
|
—
|
|
|
(113
|
)
|
|
|
—
|
|
|
(40
|
)
|
Other long-term liabilities and deferred credits
|
—
|
|
|
(57
|
)
|
|
|
—
|
|
|
(91
|
)
|
|
$
|
89
|
|
|
$
|
(170
|
)
|
|
|
$
|
168
|
|
|
$
|
(131
|
)
|
As of
September 30, 2017
, there was a net loss of
$224 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
September 30, 2017
, we expect to reclassify a net loss of
$8 million
to earnings in the next twelve months. The remaining deferred loss of
$216 million
is expected to be reclassified to earnings through 2049. A portion of these amounts is based on market prices as of
September 30, 2017
; 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 loss recognized in AOCI for derivatives (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Interest rate derivatives, net
|
$
|
(3
|
)
|
|
$
|
(20
|
)
|
|
$
|
(15
|
)
|
|
$
|
(178
|
)
|
At
September 30, 2017
and
December 31, 2016
, 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 September 30, 2017
|
|
|
Fair Value as of December 31, 2016
|
Recurring Fair Value Measures
(1)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Commodity derivatives
|
|
$
|
(4
|
)
|
|
$
|
(198
|
)
|
|
$
|
(8
|
)
|
|
$
|
(210
|
)
|
|
|
$
|
(113
|
)
|
|
$
|
(171
|
)
|
|
$
|
(4
|
)
|
|
$
|
(288
|
)
|
Interest rate derivatives
|
|
—
|
|
|
(34
|
)
|
|
—
|
|
|
(34
|
)
|
|
|
—
|
|
|
(50
|
)
|
|
—
|
|
|
(50
|
)
|
Foreign currency derivatives
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
Preferred Distribution Rate Reset Option
|
|
—
|
|
|
—
|
|
|
(33
|
)
|
|
(33
|
)
|
|
|
—
|
|
|
—
|
|
|
(32
|
)
|
|
(32
|
)
|
Total net derivative liability
|
|
$
|
(4
|
)
|
|
$
|
(230
|
)
|
|
$
|
(41
|
)
|
|
$
|
(275
|
)
|
|
|
$
|
(113
|
)
|
|
$
|
(224
|
)
|
|
$
|
(36
|
)
|
|
$
|
(373
|
)
|
|
|
(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 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 is based on a valuation model utilizing timing estimates, which involve management judgment. Significant changes in timing could result in a material change in fair value to our physical 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.
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 as “Other income/(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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Beginning Balance
|
$
|
(30
|
)
|
|
$
|
(35
|
)
|
|
$
|
(36
|
)
|
|
$
|
11
|
|
Net gains/(losses) for the period included in earnings
|
(8
|
)
|
|
17
|
|
|
(1
|
)
|
|
41
|
|
Settlements
|
(1
|
)
|
|
—
|
|
|
4
|
|
|
(10
|
)
|
Derivatives entered into during the period
|
(2
|
)
|
|
1
|
|
|
(8
|
)
|
|
(59
|
)
|
Ending Balance
|
$
|
(41
|
)
|
|
$
|
(17
|
)
|
|
$
|
(41
|
)
|
|
$
|
(17
|
)
|
|
|
|
|
|
|
|
|
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period
|
$
|
(10
|
)
|
|
$
|
18
|
|
|
$
|
(8
|
)
|
|
$
|
43
|
|
Note 11—Related Party Transactions
See Note 15 to our Consolidated Financial Statements included in Part IV of our
2016
Annual Report on Form 10-K for a complete discussion of our related party transactions.
Transactions with
Oxy
As of
September 30, 2017
, Oxy had a representative on the board of directors of our general partner and owned approximately
10%
of the limited partner interests in AAP. During the
three and nine
months ended
September 30, 2017
and
2016
, 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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Revenues
|
$
|
204
|
|
|
$
|
171
|
|
|
$
|
657
|
|
|
$
|
424
|
|
|
|
|
|
|
|
|
|
Purchases and related costs
(1)
|
$
|
(68
|
)
|
|
$
|
4
|
|
|
$
|
(169
|
)
|
|
$
|
(46
|
)
|
|
|
(1)
|
Purchases and related costs include crude oil buy/sell transactions that are accounted for as inventory exchanges and are presented net 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):
|
|
|
|
|
|
|
|
|
|
September 30,
2017
|
|
December 31, 2016
|
Trade accounts receivable and other receivables
|
$
|
877
|
|
|
$
|
789
|
|
|
|
|
|
Accounts payable
|
$
|
833
|
|
|
$
|
836
|
|
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
September 30, 2017
, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled
$134 million
, of which
$47 million
was classified as short-term and
$87 million
was classified as long-term. At
December 31, 2016
, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled
$147 million
, of which
$61 million
was classified as short-term and
$86 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
September 30, 2017
, we had recorded receivables totaling
$47 million
for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which
$26 million
was reflected in “Trade accounts receivable and other receivables, net” and
$21 million
was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. At
December 31, 2016
, we had recorded
$56 million
of such receivables, of which
$39 million
was reflected in “Trade accounts receivable and other receivables, net” and
$17 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.
On September 11, 2015, we received a Notice of Probable Violation and Proposed Compliance Order from PHMSA arising out of its inspection of Lines 901 and 903 in August, September and October of 2013 (the “2013 Audit NOPV”). The 2013 Audit NOPV alleges that the Partnership committed probable violations of various federal pipeline safety regulations by failing to document, or inadequately documenting, certain activities. On October 12, 2015, the Partnership filed a response to the 2013 Audit NOPV. By letter dated September 21, 2017, PHMSA issued a Final Order in this matter withdrawing one alleged violation and affirming a second. With regard to the second violation, PHMSA further determined that compliance had been achieved and included no compliance terms related to it in the Final Order. We therefore consider this matter closed.
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,
36
of which were misdemeanor charges relating to wildlife allegedly taken as a result of the accidental release. The remaining
10
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 intends to continue to vigorously defend itself against the charges. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts.
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 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 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, including potential classes such as commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or from persons or businesses who resold commercial seafood landed in such areas, certain owners of oceanfront and/or beachfront property on the Pacific Coast of California, and other classes of individuals and businesses that were allegedly impacted by the release. To date, only the commercial fisherman and seafood reseller class has been certified by the court. 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 have refiled their complaint and we are opposing their claims. 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 these lawsuits; we are also indemnifying and funding 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. 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
two
remaining lawsuits 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 these lawsuits 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 these lawsuits.
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
September 30, 2017
, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately
$300 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 accrued such estimate of aggregate total costs to “Field operating costs” primarily during 2015. 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
September 30, 2017
, we had a remaining undiscounted gross liability of
$64 million
related to this event, of which approximately
$36 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
September 30, 2017
, we had collected, subject to customary reservations,
$166 million
out of the approximate
$205 million
of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of
September 30, 2017
, we have recognized a receivable of approximately
$39 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
$18 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. 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 or 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 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 September 30, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
(1)
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
274
|
|
|
$
|
140
|
|
|
$
|
5,573
|
|
|
$
|
(114
|
)
|
|
$
|
5,873
|
|
Intersegment
(2)
|
|
172
|
|
|
151
|
|
|
1
|
|
|
114
|
|
|
438
|
|
Total revenues of reportable segments
|
|
$
|
446
|
|
|
$
|
291
|
|
|
$
|
5,574
|
|
|
$
|
—
|
|
|
$
|
6,311
|
|
Equity earnings in unconsolidated entities
|
|
$
|
80
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
80
|
|
Segment adjusted EBITDA
|
|
$
|
363
|
|
|
$
|
182
|
|
|
$
|
(56
|
)
|
|
|
|
$
|
489
|
|
Maintenance capital
|
|
$
|
32
|
|
|
$
|
28
|
|
|
$
|
3
|
|
|
|
|
$
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2016
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
(1)
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
227
|
|
|
$
|
135
|
|
|
$
|
4,876
|
|
|
$
|
(68
|
)
|
|
$
|
5,170
|
|
Intersegment
(2)
|
|
174
|
|
|
147
|
|
|
3
|
|
|
68
|
|
|
392
|
|
Total revenues of reportable segments
|
|
$
|
401
|
|
|
$
|
282
|
|
|
$
|
4,879
|
|
|
$
|
—
|
|
|
$
|
5,562
|
|
Equity earnings in unconsolidated entities
|
|
$
|
46
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
46
|
|
Segment adjusted EBITDA
|
|
$
|
308
|
|
|
$
|
171
|
|
|
$
|
(17
|
)
|
|
|
|
$
|
462
|
|
Maintenance capital
|
|
$
|
29
|
|
|
$
|
15
|
|
|
$
|
3
|
|
|
|
|
$
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
(1)
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
757
|
|
|
$
|
410
|
|
|
$
|
17,749
|
|
|
$
|
(298
|
)
|
|
$
|
18,618
|
|
Intersegment
(2)
|
|
503
|
|
|
463
|
|
|
8
|
|
|
298
|
|
|
1,272
|
|
Total revenues of reportable segments
|
|
$
|
1,260
|
|
|
$
|
873
|
|
|
$
|
17,757
|
|
|
$
|
—
|
|
|
$
|
19,890
|
|
Equity earnings in unconsolidated entities
|
|
$
|
201
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
201
|
|
Segment adjusted EBITDA
|
|
$
|
933
|
|
|
$
|
550
|
|
|
$
|
(32
|
)
|
|
|
|
$
|
1,451
|
|
Maintenance capital
|
|
$
|
89
|
|
|
$
|
94
|
|
|
$
|
11
|
|
|
|
|
$
|
194
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2016
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
(1)
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
711
|
|
|
$
|
405
|
|
|
$
|
13,344
|
|
|
$
|
(229
|
)
|
|
$
|
14,231
|
|
Intersegment
(2)
|
|
477
|
|
|
412
|
|
|
9
|
|
|
229
|
|
|
1,127
|
|
Total revenues of reportable segments
|
|
$
|
1,188
|
|
|
$
|
817
|
|
|
$
|
13,353
|
|
|
$
|
—
|
|
|
$
|
15,358
|
|
Equity earnings in unconsolidated entities
|
|
$
|
133
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
133
|
|
Segment adjusted EBITDA
|
|
$
|
863
|
|
|
$
|
497
|
|
|
$
|
208
|
|
|
|
|
$
|
1,568
|
|
Maintenance capital
|
|
$
|
86
|
|
|
$
|
32
|
|
|
$
|
10
|
|
|
|
|
$
|
128
|
|
|
|
(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 2
to our Consolidated Financial Statements included in Part IV of our 2016 Annual Report on Form 10-K 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 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
September 30,
|
|
Nine Months Ended
September 30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Segment adjusted EBITDA
|
$
|
489
|
|
|
$
|
462
|
|
|
$
|
1,451
|
|
|
$
|
1,568
|
|
Adjustments
(1)
:
|
|
|
|
|
|
|
|
Depreciation and amortization of unconsolidated entities
(2)
|
(13
|
)
|
|
(13
|
)
|
|
(31
|
)
|
|
(38
|
)
|
Gains/(losses) from derivative activities net of inventory valuation adjustments
(3)
|
(216
|
)
|
|
52
|
|
|
86
|
|
|
(189
|
)
|
Long-term inventory costing adjustments
(4)
|
16
|
|
|
(38
|
)
|
|
2
|
|
|
6
|
|
Deficiencies under minimum volume commitments, net
(5)
|
(8
|
)
|
|
(25
|
)
|
|
(5
|
)
|
|
(59
|
)
|
Equity-indexed compensation expense
(6)
|
(7
|
)
|
|
(8
|
)
|
|
(18
|
)
|
|
(23
|
)
|
Net gain/(loss) on foreign currency revaluation
(7)
|
14
|
|
|
(2
|
)
|
|
27
|
|
|
(4
|
)
|
Line 901 incident
(8)
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
Significant acquisition-related expenses
(9)
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
Unallocated general and administrative expenses
|
—
|
|
|
(1
|
)
|
|
(3
|
)
|
|
(2
|
)
|
Depreciation and amortization
|
(152
|
)
|
|
(33
|
)
|
|
(403
|
)
|
|
(352
|
)
|
Interest expense, net
|
(134
|
)
|
|
(116
|
)
|
|
(390
|
)
|
|
(349
|
)
|
Other income/(expense), net
|
(1
|
)
|
|
17
|
|
|
(6
|
)
|
|
46
|
|
Income/(loss) before tax
|
(12
|
)
|
|
295
|
|
|
692
|
|
|
604
|
|
Income tax benefit/(expense)
|
43
|
|
|
(16
|
)
|
|
(85
|
)
|
|
(66
|
)
|
Net income
|
31
|
|
|
279
|
|
|
607
|
|
|
538
|
|
Net income attributable to noncontrolling interests
|
(27
|
)
|
|
(255
|
)
|
|
(538
|
)
|
|
(436
|
)
|
Net income attributable to PAGP
|
$
|
4
|
|
|
$
|
24
|
|
|
$
|
69
|
|
|
$
|
102
|
|
|
|
(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 costs recognized during the period related to the Line 901 incident that occurred in May 2015, net of amounts we believe are probable of recovery from insurance. See
Note 12
for additional information regarding the Line 901 incident.
|
|
|
(9)
|
Includes acquisition-related expenses associated with the ACC Acquisition. See Note 6 for additional discussion. An adjustment for these non-recurring expenses is included in the calculation of segment adjusted EBITDA for the
three and nine
months ended
September 30, 2017
as our CODM does not view such expenses as integral to understanding our core segment operating performance. Acquisition-related expenses for the 2016 period were not significant to segment adjusted EBITDA.
|