NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1—Organization and Basis of Consolidation and Presentation
Organization
Plains All American Pipeline, L.P. (“PAA”) is a Delaware limited partnership formed in 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-Q and unless the context indicates otherwise, the terms “Partnership,” “we,” “us,” “our,” “ours” and similar terms refer to PAA and its subsidiaries.
We own and operate midstream energy infrastructure and provide logistics services primarily for crude oil, natural gas liquids (“NGL”) and natural gas. We own 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 14
for further discussion of our operating segments.
Our non-economic general partner interest is held by PAA GP LLC (“PAA GP”), a Delaware limited liability company, whose sole member is Plains AAP, L.P. (“AAP”), a Delaware limited partnership. In addition to its ownership of PAA GP, as of
September 30, 2018
, AAP also owned a limited partner interest in us through its ownership of approximately
281.0
million of our common units (approximately
35%
of our total outstanding common units and Series A preferred units combined). Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. Plains GP Holdings, L.P. (“PAGP”) is the sole and managing member of GP LLC, and, at
September 30, 2018
, owned an approximate
57%
limited partner interest in AAP. PAA GP Holdings LLC (“PAGP GP”) is the general partner of PAGP.
As the sole member of GP LLC, PAGP has responsibility for conducting our business and managing our operations; however, the board of directors of PAGP GP has ultimate responsibility for managing the business and affairs of PAGP, AAP and us. GP LLC employs our domestic officers and personnel; our Canadian officers and personnel are employed by our subsidiary, Plains Midstream Canada ULC.
References to our “general partner,” as the context requires, include any or all of PAGP GP, PAGP, GP LLC, AAP and PAA GP.
Definitions
Additional defined terms are used in this Form 10-Q and shall have the meanings indicated below:
|
|
|
|
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
|
DERs
|
=
|
Distribution equivalent rights
|
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
|
ISDA
|
=
|
International Swaps and Derivatives Association
|
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 2017 Annual Report on Form 10-K. The accompanying condensed consolidated financial statements include the accounts of PAA and all of its wholly owned subsidiaries and those entities that it controls. Investments in entities over which we have significant influence but not control are accounted for by the equity method. We apply proportionate consolidation for pipelines and other assets in which we own undivided joint interests. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation, and certain reclassifications have been made to information from previous years to conform to the current presentation. The condensed consolidated balance sheet data as of
December 31, 2017
was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the
three and nine
months ended
September 30, 2018
should not be taken as indicative of results to be expected for the entire year.
Subsequent events have been evaluated through the financial statements issuance date and have been included in the following footnotes where applicable.
Note 2
—Recent Accounting Pronouncements
Except as discussed below and in our
2017
Annual Report on Form 10-K, there have been no new accounting pronouncements that have become effective or have been issued during the
nine months ended September 30, 2018
that are of significance or potential significance to us.
Accounting Standards Updates Adopted During the Period
In February 2017, the FASB issued ASU 2017-05,
Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets
. The ASU clarifies what type of transactions involving nonfinancial assets are covered by the scope of the standard and provides guidance on how to account for those transactions, including partial sales of real estate. Within this guidance, all sales and partial sales of businesses, which may have previously been accounted for using the in-substance real estate guidance, should follow the consolidation guidance. This guidance is effective for interim and annual periods beginning after December 15, 2017, and must be adopted at the same time as Topic 606 (defined below). We adopted this ASU on January 1, 2018, using the modified retrospective approach. The cumulative effect of our adoption resulted in increases in both the carrying value of investments in unconsolidated entities and retained earnings of
$113 million
related to the retained noncontrolling interest in those entities from partial sales of businesses accounted for under in-substance real estate guidance during 2016 and 2017.
In November 2016, the FASB issued ASU 2016-18,
Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)
, requiring that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual periods beginning after December 15, 2017. We adopted this ASU on January 1, 2018. Our adoption did not have an impact on our statement of cash flows.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers
,
followed by a series of related accounting standard updates (collectively referred to as “Topic 606”) with the underlying principle that an entity will recognize revenue to reflect amounts expected to be received in exchange for the provision of goods and services to customers upon the transfer of control of those goods or services. We adopted Topic 606 on January 1, 2018, and applied the modified retrospective approach. See Note 3 for additional information.
Accounting Standards Updates Issued During the Period
In August 2018, the FASB issued ASU 2018-15,
Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (a consensus of the FASB Emerging Issues Task Force),
to address the accounting for implementation costs of a hosting arrangement that is a service contract and to align the accounting for implementation costs for hosting arrangements, regardless of whether they convey a license to the hosted software. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows.
In August 2018, the FASB issued ASU 2018-13,
Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement
, modifying the disclosure requirements on fair value measurements in Topic 820. This guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. We expect to adopt this guidance on January 1, 2020, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows.
In July 2018, the FASB issued ASU 2018-09,
Codification Improvements
, which makes updates for clarifications, technical corrections and other minor improvements to a wide variety of Topics to make the ASC easier to understand and to apply. The transition and effective date is based on the facts and circumstances of each amendment with some amendments effective upon issuance. The remaining amendments are effective for annual periods beginning after December 15, 2018. We expect to adopt the remaining applicable amendments within this guidance on January 1, 2019, and we are currently evaluating the effect that our adoption of this guidance will have on our financial position, results of operations and cash flows.
In June 2018, the FASB issued ASU 2018-07,
Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting
, which expands the scope of Topic 718 to include share-based payment awards to nonemployees and eliminates the classification differences for employee and nonemployee share-based payment awards. 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 we do not currently anticipate that our adoption will have a material impact on our financial position, results of operations or cash flows.
Other Accounting Standards Updates
In February 2016, the FASB issued ASU 2016-02,
Leases (Topic 842),
that revises the current accounting model for leases. The most significant changes are the clarification of the definition of a lease and required lessee recognition on the balance sheet of lease assets and liabilities with lease terms of more than 12 months (with the election of the practical expedient to exclude short-term leases on the balance sheet), including extensive quantitative and qualitative disclosures. This guidance will become effective for interim and annual periods beginning after December 15, 2018, with a modified retrospective application required. Early adoption is permitted, including adoption in an interim period. We expect to adopt this guidance on January 1, 2019. We have implemented a process to evaluate the impact of adopting this guidance on each type of lease contract we have entered into with counterparties. 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. Although our evaluation and implementation procedures are ongoing, we currently estimate that there will be a material impact on our financial position (both lease assets and lease liabilities), as well as an increase in disclosures related to leases. However, the determination of the ultimate impact of adopting this guidance will not be known until our implementation procedures are complete and will depend on our lease portfolio as of the adoption date.
Note 3
—Revenues
Revenue Recognition
On January 1, 2018, we adopted Topic 606 using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605,
Revenue Recognition
.
There was no material impact to opening retained earnings as of January 1, 2018 due to the adoption of Topic 606. There also was no material impact to revenues, or any other financial statement line items, for the
three and nine
months ended
September 30, 2018
as a result of applying Topic 606.
Under Topic 606, we disaggregate our revenues by segment and type of activity. These categories depict how the nature, amount, timing and uncertainty of revenues and cash flows are affected by economic factors.
Supply and Logistics Segment Revenues from Contracts with Customers.
The following table presents our Supply and Logistics segment revenues from contracts with customers disaggregated by type of activity (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
Supply and Logistics segment revenues from contracts with customers
|
|
|
|
Crude oil transactions
|
$
|
7,978
|
|
|
$
|
22,651
|
|
NGL and other transactions
|
556
|
|
|
2,181
|
|
Total Supply and Logistics segment revenues from contracts with customers
|
$
|
8,534
|
|
|
$
|
24,832
|
|
Revenues from sales of crude oil, NGL and natural gas are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and NGL consist of outright sales contracts. The consideration received under these contracts is variable based on commodity prices. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges which are excluded from Supply and Logistics segment revenues in our Condensed Consolidated Statements of Operations. Revenues recognized by our Supply and Logistics segment primarily represent margin based activities.
In addition, we have certain crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. The revenues under these agreements are deferred until all performance obligations associated with the related agreements are completed. The inventory that has been sold under these crude oil sales agreements is reflected in “Other Current Assets” on our Condensed Consolidated Balance Sheet until all of our performance obligations are complete. At that time, the inventory that has been sold is removed from our Condensed Consolidated Balance Sheet and recorded as “Purchases and Related Costs” in our Condensed Consolidated Statement of Operations. At
September 30, 2018
, other current assets and deferred revenue associated with these agreements was approximately
$157 million
and
$159 million
, respectively. See Contract Balances below for further discussion of contract liabilities associated with these agreements.
We may also utilize derivatives in connection with the transactions described above. Derivative revenue is not included as a component of revenue from contracts with customers, but is included in other items in revenue. The change in the fair value of derivatives that are not designated or do not qualify for hedge accounting is recognized in revenues each period.
Transportation Segment Revenues from Contracts with Customers.
The following table presents our Transportation segment revenues from contracts with customers disaggregated by type of activity (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
Transportation segment revenues from contracts with customers
|
|
|
|
Tariff activities:
|
|
|
|
Crude oil pipelines
|
$
|
435
|
|
|
$
|
1,237
|
|
NGL pipelines
|
25
|
|
|
76
|
|
Total tariff activities
|
460
|
|
|
1,313
|
|
Trucking
|
36
|
|
|
103
|
|
Total Transportation segment revenues from contracts with customers
|
$
|
496
|
|
|
$
|
1,416
|
|
Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems and trucks. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and NGL at a published tariff. We primarily recognize pipeline tariff and fee revenues over time as services are rendered, based on the volumes transported. As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We recognize the allowance volumes collected as part of the transaction price and record this non-cash consideration at fair value, measured as of the contract inception date.
Facilities Segment Revenues from Contracts with Customers.
The following table presents our Facilities segment revenues from contracts with customers disaggregated by type of activity (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
Facilities segment revenues from contracts with customers
|
|
|
|
Crude oil, NGL and other terminalling and storage
|
$
|
174
|
|
|
$
|
511
|
|
NGL and natural gas processing and fractionation
|
87
|
|
|
278
|
|
Rail load / unload
|
24
|
|
|
56
|
|
Total Facilities segment revenues from contracts with customers
|
$
|
285
|
|
|
$
|
845
|
|
Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. Revenues generated in this segment include (i) fees that are generated from storage capacity agreements, (ii) terminal throughput fees that are generated when we receive liquids from one connecting source and deliver the applicable product to another connecting carrier, (iii) fees from NGL fractionation and isomerization services, (iv) fees from natural gas and condensate processing services, (v) fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services (“natural gas storage related activities”) and (vi) loading and unloading fees at our rail terminals.
We generate revenue through a combination of month-to-month and multi-year agreements and processing arrangements. Storage fees are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized as our performance obligation is to make available storage capacity for a period of time. Terminal fees (including throughput and rail fees) are recognized as the liquids enter or exit the terminal and are received from or delivered to the connecting carrier or third-party terminal, as applicable. Fees from NGL fractionation and isomerization services and gas processing services are recognized in the period when the services are performed. Natural gas storage related activities fees are recognized in the period the natural gas moves across our header system. We recognize rail loading and unloading fees when the volumes are delivered or received.
Reconciliation to Total Revenues of Reportable Segments.
Topic 606 requires us to provide information about the relationship between the disaggregated revenues presented above and segment revenues. These disclosures only include information regarding revenues associated with consolidated entities, and revenues from entities accounted for by the equity method are not included in the disclosures. The following table presents the reconciliation of our revenues from contracts with customers (as described above for each segment) to segment revenues and total revenues as disclosed in our Condensed Consolidated Statement of Operations (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Total
|
Revenues from contracts with customers
|
|
$
|
496
|
|
|
$
|
285
|
|
|
$
|
8,534
|
|
|
$
|
9,315
|
|
Other items in revenues
|
|
2
|
|
|
4
|
|
|
(51
|
)
|
|
(45
|
)
|
Total revenues of reportable segments
|
|
$
|
498
|
|
|
$
|
289
|
|
|
$
|
8,483
|
|
|
$
|
9,270
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
(478
|
)
|
Total revenues
|
|
|
|
|
|
|
|
$
|
8,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Total
|
Revenues from contracts with customers
|
|
$
|
1,416
|
|
|
$
|
845
|
|
|
$
|
24,832
|
|
|
$
|
27,093
|
|
Other items in revenues
|
|
11
|
|
|
21
|
|
|
(456
|
)
|
|
(424
|
)
|
Total revenues of reportable segments
|
|
$
|
1,427
|
|
|
$
|
866
|
|
|
$
|
24,376
|
|
|
$
|
26,669
|
|
Intersegment revenues
|
|
|
|
|
|
|
|
(1,400
|
)
|
Total revenues
|
|
|
|
|
|
|
|
$
|
25,269
|
|
Trade Accounts Receivable and Other Receivables.
We generally invoice customers in the month following that in which products or services were provided and generally require payment within
30 days
of the invoice date. The following is a reconciliation of trade accounts receivable from revenues from contracts with customers to total Trade accounts receivable and other receivables, net as presented on our Condensed Consolidated Balance Sheet (in millions):
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31, 2017
|
Trade accounts receivable arising from revenues from contracts with customers
|
$
|
2,910
|
|
|
$
|
2,584
|
|
Other trade accounts receivables and other receivables
(1)
|
3,482
|
|
|
3,709
|
|
Impact due to contractual rights of offset with counterparties
|
(3,438
|
)
|
|
(3,264
|
)
|
Trade accounts receivable and other receivables, net
|
$
|
2,954
|
|
|
$
|
3,029
|
|
|
|
(1)
|
The balance is comprised primarily of accounts receivable associated with buy/sell arrangements that are not within the scope of Topic 606.
|
Minimum Volume Commitments.
We have certain agreements that require counterparties to transport or throughput a minimum volume over an agreed upon period. These contracts are within the scope of Topic 606. In addition, we have certain buy/sell agreements that require customers to deliver a minimum volume over an agreed upon period that are within the scope of ASC Topic 845,
Nonmonetary Transactions
(“Topic 845”). Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty’s make-up right as a contract liability and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty’s ability to utilize the make-up right is remote.
At
September 30, 2018
and
December 31, 2017
, counterparty deficiencies associated with agreements (under Topic 606 and Topic 845) that include minimum volume commitments totaled
$62 million
and
$57 million
, respectively, of which
$42 million
and
$37 million
, respectively, was recorded as a contract liability, which we refer to as deferred revenue. The remaining balance of
$20 million
at both
September 30, 2018
and
December 31, 2017
was related to deficiencies for which the counterparties had not met their contractual minimum commitments and were not reflected in our Condensed Consolidated Financial Statements as we had not yet billed or collected such amounts.
Contract Balances
. Our contract balances consist of amounts received associated with services or sales for which we have not yet completed the related performance obligation. The following table presents the change in the contract liability balance during the
nine months ended September 30, 2018
(in millions):
|
|
|
|
|
|
|
|
Contract Liabilities
|
Balance at December 31, 2017
|
|
$
|
90
|
|
Amounts recognized as revenue
|
|
(78
|
)
|
Additions
(1) (2)
|
|
384
|
|
Other
|
|
(3
|
)
|
Balance at September 30, 2018
|
|
$
|
393
|
|
|
|
(1)
|
Includes approximately
$159 million
associated with crude oil sales agreements that are entered into in conjunction with storage arrangements and future inventory exchanges. Such amount is expected to be recognized as revenue in the
fourth quarter of 2018
.
|
|
|
(2)
|
Includes
$100 million
associated with long-term capacity agreements with Cactus II Pipeline LLC. See
Note 12
for additional information.
|
Remaining Performance Obligations
. Topic 606 requires a presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The information includes the amount of consideration allocated to those remaining performance obligations and the timing of revenue recognition of those remaining performance obligations. Certain contracts meet the requirements for the presentation as remaining performance obligations. These arrangements include a fixed minimum level of service, typically a set volume of service, and do not contain any variability other than expected timing within a limited range. These contracts are all within the scope of Topic 606. The following table presents the amount of consideration associated with remaining performance obligations for the population of contracts with external customers meeting the presentation requirements as of
September 30, 2018
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remainder of 2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 and Thereafter
|
Pipeline revenues supported by minimum volume commitments and long-term capacity agreements
(1)
|
$
|
34
|
|
|
$
|
158
|
|
|
$
|
199
|
|
|
$
|
190
|
|
|
$
|
188
|
|
|
$
|
831
|
|
Long-term storage, terminalling and throughput agreements revenues
|
118
|
|
|
374
|
|
|
296
|
|
|
214
|
|
|
162
|
|
|
573
|
|
Total
|
$
|
152
|
|
|
$
|
532
|
|
|
$
|
495
|
|
|
$
|
404
|
|
|
$
|
350
|
|
|
$
|
1,404
|
|
|
|
(1)
|
Includes revenues from certain contracts for which the amount and timing of revenue is subject to the completion of underlying construction projects.
|
The presentation above does not include (i) expected revenues from legacy shippers not underpinned by minimum volume commitments, including pipelines where there are no or limited alternative pipeline transportation options, (ii) intersegment revenues and (iii) the amount of consideration associated with certain income generating contracts, which include a fixed minimum level of service, that are either not within the scope of Topic 606 or do not meet the requirements for presentation as remaining performance obligations under Topic 606. The following are examples of contracts that are not included in the table above because they are not within the scope of Topic 606 or do not meet the Topic 606 requirements for presentation:
|
|
•
|
Minimum volume commitments related to the assets of equity method investees — Contracts include those related to the Eagle Ford, BridgeTex, STACK, Caddo, Saddlehorn, White Cliffs, Cheyenne, Diamond and Cactus II pipeline systems;
|
|
|
•
|
Acreage dedications — Contracts include those related to the Permian Basin, Eagle Ford, Central, Rocky Mountain and Canada regions;
|
|
|
•
|
Supply and Logistics contracts within the scope of Topic 845 — Contracts include buy/sell arrangements with future committed volumes on certain Permian Basin, Eagle Ford, Central and Canada region systems;
|
|
|
•
|
All other Supply and Logistics contracts, due to the election of practical expedients related to variable consideration and short-term contracts, as discussed below;
|
|
|
•
|
Transportation and Facilities contracts that are short-term, as discussed below;
|
|
|
•
|
Contracts within the scope of ASC Topic 840,
Leases
; and
|
|
|
•
|
Contracts within the scope of ASC Topic 815,
Derivatives and Hedging
.
|
We have elected practical expedients to exclude the presentation of remaining performance obligations for variable consideration which relates to wholly unsatisfied performance obligations. Certain contracts do not meet the requirements for presentation of remaining performance obligations under Topic 606 due to variability in amount of performance obligation remaining, variability in the timing of recognition or variability in consideration. Acreage dedications do require us to perform future services but do not contain a minimum level of services and are therefore excluded from this presentation. Long-term supply and logistics arrangements contain variable timing, volumes and/or consideration and are excluded from this presentation. The duration of these contracts varies across the periods presented above.
Additionally, we have elected practical expedients to exclude contracts with terms of one year or less, and therefore exclude the presentation of remaining performance obligations for short-term transportation, storage and processing services, supply and logistics arrangements, including the non-cancelable period of evergreen arrangements, and any other types of arrangements with terms of one year or less.
Note 4
—Net Income/(Loss) Per Common Unit
We calculate basic and diluted net income/(loss) per common unit by dividing net income attributable to PAA (after deducting amounts allocated to preferred unitholders and participating securities) by the basic and diluted weighted average number of common units outstanding during the period. Participating securities include LTIP awards that have vested DERs, which entitle the grantee to a cash payment equal to the cash distribution paid on our outstanding common units.
The diluted weighted average number of common units is computed based on the weighted average number of common units plus the effect of potentially dilutive securities outstanding during the period, which include (i) our Series A preferred units and (ii) our equity-indexed compensation plan awards (which include LTIP awards and AAP Management Units). When applying the if-converted method prescribed by FASB guidance, the possible conversion of our Series A preferred units was excluded from the calculation of diluted net income/(loss) per common unit for the nine months ended
September 30, 2018
and the
three and nine
months ended
September 30, 2017
as the effect was antidilutive. Our LTIP awards that contemplate the issuance of common units and certain AAP Management Units that contemplate the issuance of common units to AAP when such AAP Management Units become earned are considered dilutive unless (i) they become vested or earned only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards and AAP Management Units that were deemed to be dilutive during the
three and nine
months ended
September 30, 2018
and the nine months ended September 30,
2017
were reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. LTIP Awards and AAP Management Units were excluded from the computation of diluted net loss per common unit from the three months ended September 30, 2017 as the effect was antidilutive. See Note 16 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for a complete discussion of our LTIP awards and the AAP Management Units.
The following table sets forth the computation of basic and diluted net income/(loss) per common unit (in millions, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Basic Net Income/(Loss) per Common Unit
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
1,099
|
|
|
665
|
|
Distributions to Series A preferred unitholders
|
(37
|
)
|
|
(36
|
)
|
|
(112
|
)
|
|
(105
|
)
|
Distributions to Series B preferred unitholders
|
(12
|
)
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
Distributions to participating securities
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
Other
|
(2
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|
(11
|
)
|
Net income/(loss) allocated to common unitholders
(1)
|
$
|
658
|
|
|
$
|
(8
|
)
|
|
$
|
946
|
|
|
$
|
547
|
|
|
|
|
|
|
|
|
|
Basic weighted average common units outstanding
|
726
|
|
|
725
|
|
|
726
|
|
|
714
|
|
|
|
|
|
|
|
|
|
Basic net income/(loss) per common unit
|
$
|
0.91
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.30
|
|
|
$
|
0.77
|
|
|
|
|
|
|
|
|
|
Diluted Net Income/(Loss) per Common Unit
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
$
|
1,099
|
|
|
$
|
665
|
|
Distributions to Series A preferred unitholders
|
—
|
|
|
(36
|
)
|
|
(112
|
)
|
|
(105
|
)
|
Distributions to Series B preferred unitholders
|
(12
|
)
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
Distributions to participating securities
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
Other
|
—
|
|
|
(4
|
)
|
|
(1
|
)
|
|
(11
|
)
|
Net income/(loss) allocated to common unitholders
(1)
|
$
|
697
|
|
|
$
|
(8
|
)
|
|
$
|
947
|
|
|
$
|
547
|
|
|
|
|
|
|
|
|
|
Basic weighted average common units outstanding
|
726
|
|
|
725
|
|
|
726
|
|
|
714
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
Series A preferred units
|
71
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity-indexed compensation plan awards
|
2
|
|
|
—
|
|
|
2
|
|
|
1
|
|
Diluted weighted average common units outstanding
|
799
|
|
|
725
|
|
|
728
|
|
|
715
|
|
|
|
|
|
|
|
|
|
Diluted net income/(loss) per common unit
|
$
|
0.87
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.30
|
|
|
$
|
0.76
|
|
|
|
(1)
|
We calculate net income/(loss) allocated to common unitholders based on the distributions pertaining to the current period’s net income (whether paid in cash or in-kind). After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method.
|
Note 5
—Accounts Receivable, Net
Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of NGL and natural gas. To mitigate credit risk related to our accounts receivable, we utilize a rigorous credit review process. We closely monitor market conditions and perform credit reviews of each customer to make a determination with respect to the amount, if any, of open credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of advance cash payments, standby letters of credit, credit insurance or parental guarantees. As of
September 30, 2018
and
December 31, 2017
, we had received
$136 million
and
$117 million
, respectively, of advance cash payments from third parties to mitigate credit risk. We also received
$36 million
and
$54 million
as of
September 30, 2018
and
December 31, 2017
, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. Additionally, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Furthermore, we also enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for the majority of our net-cash arrangements.
We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At
September 30, 2018
and
December 31, 2017
, substantially all of our trade accounts receivable (net of allowance for doubtful accounts) were less than
30 days
past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled
$3 million
at both
September 30, 2018
and
December 31, 2017
. Although we consider our allowance for doubtful accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.
Note 6—Inventory, Linefill and Base Gas and Long-term Inventory
Inventory, linefill and base gas and long-term inventory consisted of the following (barrels and natural gas volumes in thousands and carrying value in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
|
December 31, 2017
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
|
|
Volumes
|
|
Unit of
Measure
|
|
Carrying
Value
|
|
Price/
Unit
(1)
|
Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
7,020
|
|
|
barrels
|
|
$
|
389
|
|
|
$
|
55.41
|
|
|
|
7,800
|
|
|
barrels
|
|
$
|
402
|
|
|
$
|
51.54
|
|
NGL
|
15,122
|
|
|
barrels
|
|
422
|
|
|
$
|
27.91
|
|
|
|
10,774
|
|
|
barrels
|
|
294
|
|
|
$
|
27.29
|
|
Other
|
N/A
|
|
|
|
|
13
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
17
|
|
|
N/A
|
|
Inventory subtotal
|
|
|
|
|
|
824
|
|
|
|
|
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Linefill and base gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
13,033
|
|
|
barrels
|
|
756
|
|
|
$
|
58.01
|
|
|
|
12,340
|
|
|
barrels
|
|
719
|
|
|
$
|
58.27
|
|
NGL
|
1,764
|
|
|
barrels
|
|
50
|
|
|
$
|
28.34
|
|
|
|
1,597
|
|
|
barrels
|
|
45
|
|
|
$
|
28.18
|
|
Natural gas
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
|
|
24,976
|
|
|
Mcf
|
|
108
|
|
|
$
|
4.32
|
|
Linefill and base gas subtotal
|
|
|
|
|
|
914
|
|
|
|
|
|
|
|
|
|
|
|
872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
1,882
|
|
|
barrels
|
|
112
|
|
|
$
|
59.51
|
|
|
|
1,870
|
|
|
barrels
|
|
105
|
|
|
$
|
56.15
|
|
NGL
|
2,351
|
|
|
barrels
|
|
67
|
|
|
$
|
28.50
|
|
|
|
2,167
|
|
|
barrels
|
|
59
|
|
|
$
|
27.23
|
|
Long-term inventory subtotal
|
|
|
|
|
|
179
|
|
|
|
|
|
|
|
|
|
|
|
164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
1,917
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,749
|
|
|
|
|
|
|
(1)
|
Price per unit of measure is comprised of a weighted average associated with various grades, qualities and locations. Accordingly, these prices may not coincide with any published benchmarks for such products.
|
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” on our accompanying Condensed Consolidated Statements of Operations. See
Note 11
for discussion of our derivative and risk management activities. We did not record such charges during 2018.
Note 7
—Divestitures
During the
nine
months ended
September 30, 2018
, we received proceeds from asset sales of
$1.298 billion
.
BridgeTex
. During the third quarter of 2018, we sold a
30%
interest in BridgeTex Pipeline Company, LLC (“BridgeTex”) for proceeds of
$868 million
, including working capital adjustments, and have retained a
20%
interest. We recorded a gain of
$210 million
related to this sale, which is included in “Gain on sale of investment in unconsolidated entities” on our Condensed Consolidated Statement of Operations. We continue to account for our remaining interest under the equity method of accounting.
Other
. The other assets sold during the
nine
months ended
September 30, 2018
primarily included non-core property and equipment or are associated with the formation of strategic joint ventures and were previously reported in our Facilities and Transportation segments. We recognized losses related to these asset sales of
$2 million
for the three months ended
September 30, 2018
. For the nine months ended
September 30, 2018
, we recognized a net gain of
$79 million
, which is comprised of gains of
$105 million
and losses of
$26 million
. Such amounts are included in “Depreciation and amortization” on our Condensed Consolidated Statements of Operations.
Note 8—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, 2017
|
$
|
1,070
|
|
|
$
|
988
|
|
|
$
|
508
|
|
|
$
|
2,566
|
|
Foreign currency translation adjustments
|
(8
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(13
|
)
|
Dispositions
|
(10
|
)
|
|
(3
|
)
|
|
—
|
|
|
(13
|
)
|
Balance at September 30, 2018
|
$
|
1,052
|
|
|
$
|
982
|
|
|
$
|
506
|
|
|
$
|
2,540
|
|
We completed our goodwill impairment test as of June 30, 2018 and determined that there was
no
impairment of goodwill.
Note 9
—Debt
Debt consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
SHORT-TERM DEBT
|
|
|
|
|
|
Commercial paper notes, bearing a weighted-average interest rate of 3.3%
(1)
|
$
|
60
|
|
|
$
|
—
|
|
Senior secured hedged inventory facility, bearing a weighted-average interest rate of 3.2% and 2.6%, respectively
(1)
|
300
|
|
|
664
|
|
Other
|
69
|
|
|
73
|
|
Total short-term debt
(2)
|
429
|
|
|
737
|
|
|
|
|
|
LONG-TERM DEBT
|
|
|
|
Senior notes, net of unamortized discounts and debt issuance costs of $61 and $67, respectively
|
8,939
|
|
|
8,933
|
|
Commercial paper notes and senior secured hedged inventory facility borrowings
(3)
|
—
|
|
|
247
|
|
GO Zone term loans, net of debt issuance costs of $2, bearing a weighted-average interest rate of 2.9%
|
198
|
|
|
—
|
|
Other
|
3
|
|
|
3
|
|
Total long-term debt
|
9,140
|
|
|
9,183
|
|
Total debt
(4)
|
$
|
9,569
|
|
|
$
|
9,920
|
|
|
|
(1)
|
We classified these commercial paper notes and credit facility borrowings as short-term as of
September 30, 2018
and
December 31, 2017
, as these notes and borrowings were primarily designated as working capital borrowings, were required to be repaid within one year and were primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.
|
|
|
(2)
|
As of
September 30, 2018
and
December 31, 2017
, balance includes borrowings for cash margin deposits with NYMEX and ICE, which are associated with financial derivatives used for hedging purposes.
|
|
|
(3)
|
As of
December 31, 2017
, we classified a portion of our commercial paper notes and credit facility borrowings as long-term based on our ability and intent to refinance such amounts on a long-term basis.
|
|
|
(4)
|
Our fixed-rate senior notes had a face value of approximately
$9.0 billion
at both
September 30, 2018
and
December 31, 2017
. We estimated the aggregate fair value of these notes as of
September 30, 2018
and
December 31, 2017
to be approximately
$8.8 billion
and
$9.1 billion
, respectively. Our 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 our credit facilities and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for our senior notes, credit facilities and commercial paper program are based upon observable market data and are classified in Level 2 of the fair value hierarchy.
|
Credit Agreements
Go Zone term loans
. In August 2018, we entered into an agreement for
two
$100 million
term loans (the “GO Zone term loans”) from the remarketing of our $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2009 and our $100,000,000 Mississippi Business Finance Corporation Gulf Opportunity Zone Industrial Development Revenue Bonds (SG Resources Mississippi, LLC Project), Series 2010 (collectively, the “GO Bonds”). The GO Zone term loans accrue interest in accordance with the interest payable on the related GO Bonds as provided in the GO Bonds Indenture pursuant to which such GO Bonds are issued and governed. The purchasers of the
two
GO Zone term loans have the right to put, at par, the GO Zone term loans in July 2023. The GO Bonds mature by their terms in May 2032 and August 2035, respectively.
Credit Facilities.
In August 2018, we extended the maturity dates of our senior unsecured revolving credit facility and senior secured hedged inventory facility by
one year
to August 2023 and August 2021, respectively, for each extending lender. Our 364-day senior unsecured revolving credit facility, which had a borrowing capacity of
$1.0 billion
, matured in August 2018.
Borrowings and Repayments
Total borrowings under our credit facilities and commercial paper program for the
nine
months ended
September 30, 2018
and
2017
were approximately
$38.6 billion
and
$52.6 billion
, respectively. Total repayments under our credit facilities and commercial paper program were approximately
$39.2 billion
and
$52.7 billion
for the
nine
months ended
September 30, 2018
and
2017
, respectively. The variance in total gross borrowings and repayments is impacted by various business and financial factors including, but not limited to, the timing, average term and method of general partnership borrowing activities.
Letters of Credit
In connection with our supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions including hedging related margin obligations and construction activities. At
September 30, 2018
and
December 31, 2017
, we had outstanding letters of credit of
$181 million
and
$166 million
, respectively.
Note 10
—Partners’ Capital and Distributions
Units Outstanding
The following tables present the activity for our preferred and common units:
|
|
|
|
|
|
|
|
|
|
|
Limited Partners
|
|
Series A Preferred Units
|
|
Series B Preferred Units
|
|
Common Units
|
Outstanding at December 31, 2017
|
69,696,542
|
|
|
800,000
|
|
|
725,189,138
|
|
Issuance of Series A preferred units in connection with in-kind distribution
|
1,393,926
|
|
|
—
|
|
|
—
|
|
Other
|
—
|
|
|
—
|
|
|
899,251
|
|
Outstanding at September 30, 2018
|
71,090,468
|
|
|
800,000
|
|
|
726,088,389
|
|
|
|
|
|
|
|
|
|
Limited Partners
|
|
Series A
Preferred Units
|
|
Common Units
|
Outstanding at December 31, 2016
|
64,388,853
|
|
|
669,194,419
|
|
Issuances of Series A preferred units in connection with in-kind distributions
|
3,941,096
|
|
|
—
|
|
Sales of common units
|
—
|
|
|
54,119,893
|
|
Issuance of common units in connection with acquisition of interest in Advantage Joint Venture
|
—
|
|
|
1,252,269
|
|
Other
|
—
|
|
|
622,557
|
|
Outstanding at September 30, 2017
|
68,329,949
|
|
|
725,189,138
|
|
Distributions
Series A Preferred Unit Distributions
. The following table details distributions to our Series A preferred unitholders paid during or pertaining to the first
nine
months of
2018
(in millions, except unit and per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A Preferred Unitholders
|
|
|
Distribution
(2)
|
|
|
Distribution per Unit
|
Distribution Payment Date
|
|
Cash
|
|
Units
|
|
|
November 14, 2018
(1)
|
|
$
|
37
|
|
|
—
|
|
|
|
$
|
0.525
|
|
August 14, 2018
|
|
$
|
37
|
|
|
—
|
|
|
|
$
|
0.525
|
|
May 15, 2018
|
|
$
|
37
|
|
|
—
|
|
|
|
$
|
0.525
|
|
February 14, 2018
|
|
$
|
—
|
|
|
1,393,926
|
|
|
|
$
|
0.525
|
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
October 31, 2018
for the period from
July 1, 2018
through
September 30, 2018
. At
September 30, 2018
, such amount was accrued to distributions payable in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.
|
|
|
(2)
|
On February 14, 2018, we issued additional Series A preferred units in lieu of a cash distribution of
$37 million
. With respect to quarters ending on or prior to December 31, 2017 (the “Initial Distribution Period”), we elected to pay distributions on our Series A preferred units in additional Series A preferred units. The Initial Distribution Period ended with the February 2018 distribution; as such, with respect to quarters ending after the Initial Distribution Period, distributions on our Series A preferred units are paid in cash.
|
Series B Preferred Unit Distributions
. Distributions on our Series B preferred units are payable semiannually in arrears on the 15th day of May and November. The following table details distributions paid or to be paid to our Series B preferred unitholders (in millions, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
Series B Preferred Unitholders
|
Distribution Payment Date
|
|
Cash Distribution
|
|
|
Distribution per Unit
|
November 15, 2018
(1)
|
|
$
|
24.5
|
|
|
|
$
|
30.625
|
|
May 15, 2018
|
|
$
|
24.5
|
|
|
|
$
|
30.625
|
|
|
|
(1)
|
Payable to unitholders of record at the close of business on November 1, 2018 for the period from May 15, 2018 through November 14, 2018.
|
As of
September 30, 2018
, we had accrued approximately
$18 million
of distributions payable to our Series B preferred unitholders in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.
Common Unit Distributions
. The following table details distributions to our common unitholders paid during or pertaining to the first
nine
months of
2018
(in millions, except per unit data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
Cash Distribution per Common Unit
|
|
|
Common Unitholders
|
|
Total Cash Distribution
|
|
|
Distribution Payment Date
|
|
Public
|
|
AAP
|
|
|
|
November 14, 2018
(1)
|
|
$
|
134
|
|
|
$
|
84
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
August 14, 2018
|
|
$
|
133
|
|
|
$
|
85
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
May 15, 2018
|
|
$
|
133
|
|
|
$
|
85
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
February 14, 2018
|
|
$
|
133
|
|
|
$
|
85
|
|
|
$
|
218
|
|
|
|
$
|
0.30
|
|
|
|
(1)
|
Payable to unitholders of record at the close of business on
October 31, 2018
for the period from
July 1, 2018
through
September 30, 2018
.
|
Note 11
—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, 2018
, net derivative positions related to these activities included:
|
|
•
|
A net long position of
5.8 million
barrels associated with our crude oil purchases, which was unwound ratably during
October 2018
to match monthly average pricing.
|
|
|
•
|
A net short time spread position of
15.4 million
barrels, which hedges a portion of our anticipated crude oil lease gathering purchases through
December 2019
.
|
|
|
•
|
A crude oil grade basis position of
68.6 million
barrels through
December 2020
. These derivatives allow us to lock in grade basis differentials.
|
|
|
•
|
A net short position of
16.5 million
barrels through
February 2020
related to anticipated net sales of our crude oil and NGL inventory.
|
Pipeline Loss Allowance Oil
— As is common in the pipeline transportation industry, our tariffs incorporate a loss allowance factor. We utilize derivative instruments to hedge a portion of the anticipated sales of the loss allowance oil that is to be collected under our tariffs. As of
September 30, 2018
, our PLA hedges included a short position consisting of crude oil futures of
1.5 million
barrels through
December 2019
and a long call option position of
1.6 million
barrels through
December 2020
.
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, 2018
, we had a long natural gas position of
64.9
Bcf which hedges a portion of our natural gas processing and operational needs through
December 2020
. We also had a short propane position of
11.3 million
barrels through
December 2020
, a short butane position of
3.1 million
barrels through
December 2020
and a short WTI position of
1.3 million
barrels through
December 2020
. 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 2020
.
Physical commodity contracts that meet the definition of a derivative but are ineligible, or not designated, for the normal purchases and normal sales scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings. We have determined that substantially all of our physical commodity contracts qualify for the normal purchases and normal sales scope exception.
Interest Rate Risk Hedging
We use interest rate derivatives to hedge the benchmark interest rate associated with interest payments occurring as a result of debt issuances. The derivative instruments we use to manage this risk consist of forward starting interest rate swaps and treasury locks. These derivatives are designated as cash flow hedges. As such, changes in fair value are deferred in AOCI and are reclassified to interest expense as we incur the interest expense associated with the underlying debt.
The following table summarizes the terms of our outstanding interest rate derivatives as of
September 30, 2018
(notional amounts in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedged Transaction
|
|
Number and Types of
Derivatives Employed
|
|
Notional
Amount
|
|
Expected
Termination Date
|
|
Average Rate
Locked
|
|
Accounting
Treatment
|
Anticipated interest payments
|
|
8 forward starting swaps (30-year)
|
|
$
|
200
|
|
|
6/14/2019
|
|
2.83
|
%
|
|
Cash flow hedge
|
Anticipated interest payments
|
|
8 forward starting swaps
(30-year)
|
|
$
|
200
|
|
|
6/15/2020
|
|
3.06
|
%
|
|
Cash flow hedge
|
Currency Exchange Rate Risk Hedging
Because a significant portion of our Canadian business is conducted in CAD we use foreign currency derivatives to minimize the risk of unfavorable changes in exchange rates. These instruments include foreign currency exchange contracts, forwards and options.
As of
September 30, 2018
, our outstanding foreign currency derivatives include (i) derivatives we use to hedge currency exchange risk created by the use of USD-denominated commodity derivatives to hedge commodity price risk associated with CAD-denominated commodity purchases and sales and (ii) foreign currency exchange contracts we use to manage our Canadian business cash requirements.
The following table summarizes our open forward exchange contracts as of
September 30, 2018
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
USD
|
|
CAD
|
|
Average Exchange Rate
USD to CAD
|
Forward exchange contracts that exchange CAD for USD:
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
174
|
|
|
$
|
227
|
|
|
$1.00 - $1.30
|
|
|
|
|
|
|
|
|
|
Forward exchange contracts that exchange USD for CAD:
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
$
|
418
|
|
|
$
|
543
|
|
|
$1.00 - $1.30
|
|
|
2019
|
|
$
|
120
|
|
|
$
|
155
|
|
|
$1.00 - $1.30
|
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 our Series A preferred units is an embedded derivative that must be bifurcated from the related host contract, our 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. See Note 11 to our Consolidated Financial Statements included in Part IV of our 2017 Annual Report on Form 10-K for additional information regarding our Series A preferred units and Preferred Distribution Rate Reset Option.
Summary of Financial Impact
We record all open derivatives on the balance sheet as either assets or liabilities measured at fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify as cash flow hedges, changes in fair value of the effective portion of the hedges are deferred in AOCI and recognized in earnings in the periods during which the underlying physical transactions are recognized in earnings. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of the hedged items are recognized in earnings each period. Cash settlements associated with our derivative activities are classified within the same category as the related hedged item in our Condensed Consolidated Statements of Cash Flows.
A summary of the impact of our derivatives recognized in earnings is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
|
Three Months Ended September 30, 2017
|
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
|
|
Derivatives in
Hedging
Relationships
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
$
|
—
|
|
|
$
|
(59
|
)
|
|
$
|
(59
|
)
|
|
|
$
|
—
|
|
|
$
|
(226
|
)
|
|
$
|
(226
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating costs
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
—
|
|
|
5
|
|
|
5
|
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income/(expense), net
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(2
|
)
|
|
$
|
(57
|
)
|
|
$
|
(59
|
)
|
|
|
$
|
(10
|
)
|
|
$
|
(225
|
)
|
|
$
|
(235
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
|
Nine Months Ended September 30, 2017
|
Location of Gain/(Loss)
|
|
Derivatives in
Hedging
Relationships
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
|
|
Derivatives in
Hedging
Relationships
|
|
Derivatives
Not Designated
as a Hedge
|
|
Total
|
Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
$
|
—
|
|
|
$
|
(443
|
)
|
|
$
|
(443
|
)
|
|
|
$
|
—
|
|
|
$
|
(31
|
)
|
|
$
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
|
(16
|
)
|
|
—
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and Logistics segment revenues
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income/(expense), net
|
|
—
|
|
|
3
|
|
|
3
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gain/(Loss) on Derivatives Recognized in Net Income
|
|
$
|
(3
|
)
|
|
$
|
(447
|
)
|
|
$
|
(450
|
)
|
|
|
$
|
(19
|
)
|
|
$
|
(34
|
)
|
|
$
|
(53
|
)
|
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of
September 30, 2018
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
Balance Sheet
Location
|
|
Fair
Value
|
|
|
Balance Sheet
Location
|
|
Fair
Value
|
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
Other current assets
|
|
$
|
12
|
|
|
|
|
|
|
|
|
Other long-term assets, net
|
|
3
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments
|
|
|
$
|
15
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
Other current assets
|
|
$
|
146
|
|
|
|
Other current assets
|
|
$
|
(358
|
)
|
|
Other long-term assets, net
|
|
54
|
|
|
|
Other long-term assets, net
|
|
(2
|
)
|
|
Other current liabilities
|
|
60
|
|
|
|
Other current liabilities
|
|
(211
|
)
|
|
Other long-term liabilities and deferred credits
|
|
9
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
Other current assets
|
|
4
|
|
|
|
Other current assets
|
|
(1
|
)
|
|
|
|
|
|
|
Other current liabilities
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(19
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
273
|
|
|
|
|
|
$
|
(631
|
)
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
$
|
288
|
|
|
|
|
|
$
|
(631
|
)
|
The following table summarizes the derivative assets and liabilities on our Condensed Consolidated Balance Sheet on a gross basis as of
December 31, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
Balance Sheet
Location
|
|
Fair
Value
|
|
|
Balance Sheet
Location
|
|
Fair
Value
|
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Interest rate derivatives
|
Other current liabilities
|
|
$
|
2
|
|
|
|
Other current liabilities
|
|
$
|
(27
|
)
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(11
|
)
|
Total derivatives designated as hedging instruments
|
|
|
$
|
2
|
|
|
|
|
|
$
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
Other current assets
|
|
$
|
73
|
|
|
|
Other current assets
|
|
$
|
(227
|
)
|
|
Other long-term assets, net
|
|
1
|
|
|
|
Other current liabilities
|
|
(131
|
)
|
|
Other current liabilities
|
|
5
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(5
|
)
|
|
Other long-term liabilities and deferred credits
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency derivatives
|
Other current assets
|
|
6
|
|
|
|
Other current assets
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
Preferred Distribution Rate Reset Option
|
|
|
|
|
|
|
Other long-term liabilities and deferred credits
|
|
(22
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
$
|
88
|
|
|
|
|
|
$
|
(387
|
)
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
$
|
90
|
|
|
|
|
|
$
|
(425
|
)
|
Our derivative transactions (other than the Preferred Distribution Rate Reset Option) are governed through ISDA master agreements and clearing brokerage agreements. These agreements include stipulations regarding the right of set off in the event that we or our counterparty default on performance obligations. If a default were to occur, both parties have the right to net amounts payable and receivable into a single net settlement between parties.
Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through clearing brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. The following table provides the components of our net broker receivable:
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
Initial margin
|
$
|
139
|
|
|
$
|
48
|
|
Variation margin posted
|
222
|
|
|
164
|
|
Letters of credit
|
(102
|
)
|
|
—
|
|
Net broker receivable
|
$
|
259
|
|
|
$
|
212
|
|
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, 2018
|
|
|
December 31, 2017
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
|
|
Derivative
Asset Positions
|
|
Derivative
Liability Positions
|
Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross position - asset/(liability)
|
$
|
288
|
|
|
$
|
(631
|
)
|
|
|
$
|
90
|
|
|
$
|
(425
|
)
|
Netting adjustment
|
(430
|
)
|
|
430
|
|
|
|
(239
|
)
|
|
239
|
|
Cash collateral paid
|
259
|
|
|
—
|
|
|
|
212
|
|
|
—
|
|
Net position - asset/(liability)
|
$
|
117
|
|
|
$
|
(201
|
)
|
|
|
$
|
63
|
|
|
$
|
(186
|
)
|
|
|
|
|
|
|
|
|
|
Balance Sheet Location After Netting Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
$
|
62
|
|
|
$
|
—
|
|
|
|
$
|
62
|
|
|
$
|
—
|
|
Other long-term assets, net
|
55
|
|
|
—
|
|
|
|
1
|
|
|
—
|
|
Other current liabilities
|
—
|
|
|
(152
|
)
|
|
|
—
|
|
|
(151
|
)
|
Other long-term liabilities and deferred credits
|
—
|
|
|
(49
|
)
|
|
|
—
|
|
|
(35
|
)
|
|
$
|
117
|
|
|
$
|
(201
|
)
|
|
|
$
|
63
|
|
|
$
|
(186
|
)
|
As of
September 30, 2018
, there was a net loss of
$157 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 transactions or (ii) interest expense accruals associated with underlying debt instruments. Of the total net loss deferred in AOCI at
September 30, 2018
, we expect to reclassify a net loss of
$7 million
to earnings in the next twelve months. We estimate that substantially all of the remaining deferred loss will be reclassified to earnings through 2050 as the underlying hedged transactions impact earnings. A portion of these amounts is based on market prices as of
September 30, 2018
; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.
The following table summarizes the net unrealized gain/(loss) recognized in AOCI for derivatives (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Interest rate derivatives, net
|
$
|
15
|
|
|
$
|
(3
|
)
|
|
$
|
60
|
|
|
$
|
(15
|
)
|
At
September 30, 2018
and
December 31, 2017
, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our 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, 2018
|
|
|
Fair Value as of December 31, 2017
|
Recurring Fair Value Measures
(1)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Commodity derivatives
|
|
$
|
(11
|
)
|
|
$
|
(326
|
)
|
|
$
|
(4
|
)
|
|
$
|
(341
|
)
|
|
|
$
|
5
|
|
|
$
|
(278
|
)
|
|
$
|
(8
|
)
|
|
$
|
(281
|
)
|
Interest rate derivatives
|
|
—
|
|
|
15
|
|
|
—
|
|
|
15
|
|
|
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(36
|
)
|
Foreign currency derivatives
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Preferred Distribution Rate Reset Option
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
Total net derivative asset/(liability)
|
|
$
|
(11
|
)
|
|
$
|
(309
|
)
|
|
$
|
(23
|
)
|
|
$
|
(343
|
)
|
|
|
$
|
5
|
|
|
$
|
(310
|
)
|
|
$
|
(30
|
)
|
|
$
|
(335
|
)
|
|
|
(1)
|
Derivative assets and liabilities are presented above on a net basis but do not include related cash margin deposits.
|
Level 1
Level 1 of the fair value hierarchy includes exchange-traded commodity derivatives and over-the-counter commodity contracts such as futures and options. The fair value of exchange-traded commodity derivatives and over-the-counter commodity contracts are 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 observable markets with less volume and transaction frequency than active markets. In addition, it includes certain physical commodity contracts. The fair value of these derivatives is based on broker price quotations which are corroborated with market observable inputs.
Level 3
Level 3 of the fair value hierarchy includes certain physical commodity contracts, over-the-counter financial commodity contracts, and the Preferred Distribution Rate Reset Option contained in our partnership agreement which is classified as an embedded derivative.
The fair value of our Level 3 physical commodity contracts and over-the-counter financial commodity contracts are based on valuation models utilizing significant unobservable pricing inputs and timing estimates, which involve management judgment. Significant deviations from these inputs and estimates could result in a material change in fair value to our physical commodity contracts and over-the-counter financial commodity contracts. We report unrealized gains and losses associated with these physical commodity contracts in our Condensed Consolidated Statements of Operations as Supply and Logistics segment revenues. Unrealized gains and losses associated with the over-the counter financial commodity contracts are reported in our Condensed Consolidated Statements of Operations as Field operating costs.
The fair value of the embedded derivative feature contained in our partnership agreement is based on a valuation model that estimates the fair value of the Series A preferred units with and without the Preferred Distribution Rate Reset Option. This model contains inputs, including our common unit price, ten-year U.S. treasury rates, default probabilities and timing estimates which involve management judgment. A significant change in these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Condensed Consolidated Statements of Operations in “Other 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,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Beginning Balance
|
$
|
(18
|
)
|
|
$
|
(30
|
)
|
|
$
|
(30
|
)
|
|
$
|
(36
|
)
|
Net gains/(losses) for the period included in earnings
|
(5
|
)
|
|
(8
|
)
|
|
2
|
|
|
(1
|
)
|
Settlements
|
—
|
|
|
(1
|
)
|
|
7
|
|
|
4
|
|
Derivatives entered into during the period
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|
(8
|
)
|
Ending Balance
|
$
|
(23
|
)
|
|
$
|
(41
|
)
|
|
$
|
(23
|
)
|
|
$
|
(41
|
)
|
|
|
|
|
|
|
|
|
Change in unrealized gains/(losses) included in earnings relating to Level 3 derivatives still held at the end of the period
|
$
|
(5
|
)
|
|
$
|
(10
|
)
|
|
$
|
—
|
|
|
$
|
(8
|
)
|
Note 12
—Related Party Transactions
See Note 15 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for a complete discussion of our related party transactions.
Ownership of PAGP Class C Shares
As of
September 30, 2018
and December 31, 2017, we owned
516,138,000
and
510,925,432
, respectively, Class C shares of PAGP. The Class C shares represent a non-economic limited partner interest in PAGP that provides us, as the sole holder, a “pass-through” voting right through which our common unitholders and Series A preferred unitholders have the effective right to vote, pro rata with the holders of Class A and Class B shares of PAGP, for the election of eligible PAGP GP directors.
Transactions with Oxy
As of
September 30, 2018
, Oxy had a representative on the board of directors of PAGP GP and owned approximately
11%
of the limited partner interests in AAP (which represents an approximate
4%
indirect ownership interest in PAA). During the
three and nine
months ended
September 30, 2018
and
2017
, we recognized sales and transportation revenues and purchased petroleum products from Oxy. These transactions were conducted at posted tariff rates or prices that we believe approximate market. Included in these transactions was a crude oil buy/sell agreement that includes a multi-year minimum volume commitment. The impact to our Condensed Consolidated Statements of Operations from those transactions is included below (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Revenues
|
$
|
260
|
|
|
$
|
204
|
|
|
$
|
818
|
|
|
$
|
657
|
|
|
|
|
|
|
|
|
|
Purchases and related costs
(1)
|
$
|
(22
|
)
|
|
$
|
(68
|
)
|
|
$
|
(184
|
)
|
|
$
|
(169
|
)
|
|
|
(1)
|
Crude oil purchases that are part of inventory exchanges under buy/sell transactions are netted with the related sales, with any margin presented in “Purchases and related costs” in our Condensed Consolidated Statements of Operations.
|
We currently have a netting arrangement with Oxy. Our gross receivable and payable amounts with Oxy were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
Trade accounts receivable and other receivables
|
$
|
1,039
|
|
|
$
|
1,075
|
|
|
|
|
|
Accounts payable
|
$
|
976
|
|
|
$
|
990
|
|
Transactions with Equity Method Investees
We also have transactions with companies in which we hold an investment accounted for under the equity method of accounting. We recorded revenues of
$3 million
and
$1 million
during the
three months ended September 30, 2018
and
2017
, respectively, and
$9 million
and
$3 million
during the
nine months ended September 30, 2018
and
2017
, respectively, primarily related to transportation services. In addition, we utilized transportation services and purchased petroleum products provided by these companies. Costs related to these services and product purchases totaled
$146 million
and $
124 million
for the
three months ended September 30, 2018
and
2017
, respectively, and
$411 million
and
$318 million
for the
nine months ended September 30, 2018
and
2017
, respectively. These costs include amounts associated with a joint tariff administered by an equity method investee, of which
$74 million
and
$57 million
for the
three months ended September 30, 2018
and
2017
, respectively, and
$213 million
and
$150 million
for the
nine months ended September 30, 2018
and
2017
, respectively, were associated with a PAA wholly-owned pipeline. These transactions were conducted at posted tariff rates or contracted rates or prices that we believe approximate market.
Receivables from our equity method investees totaled
$41 million
and
$26 million
at
September 30, 2018
and December 31, 2017, respectively, and primarily included amounts related to transportation services and amounts owed to us related to expansion projects where we serve as construction manager. Accounts payable to our equity method investees were
$112 million
and
$41 million
at
September 30, 2018
and December 31, 2017, respectively, and primarily included amounts related to transportation services utilized and amounts advanced to us related to expansion projects where we serve as construction manager.
In addition, we have an agreement to transport crude oil at posted tariff rates on a pipeline that is owned by an equity method investee, in which we own a
50%
interest. Our commitment to transport is supported by crude oil buy/sell agreements with third parties (including Oxy) with commensurate quantities.
During the
nine months ended September 30, 2018
, we made net investments in our equity method investees of
$300 million
(including amounts contributed to and received from Cactus II Pipeline LLC subsequent to its formation, as discussed further below). Such net investments are primarily related to funding our portion of the development, construction or capital expansion projects of such entities and are reflected in “Investments in unconsolidated entities” on our Condensed Consolidated Statement of Cash Flows.
Cactus II JV Formation.
In the second quarter of 2018, a subsidiary of Oxy and another third party each exercised their purchase options for a
20%
interest and a
15%
interest, respectively, in Cactus II Pipeline LLC (“Cactus II”), which owns the Cactus II pipeline system that is currently under construction. Although we own a majority of Cactus II’s equity, we do not have a controlling financial interest in Cactus II because the other members have substantive participating rights. Therefore, we account for our ownership interest in Cactus II as an equity method investment. Following the exercise of the purchase options, we deconsolidated Cactus II resulting in a reduction of property and equipment of
$74 million
(which was representative of the costs incurred to date to construct the pipeline and equivalent to fair value), and we received
$26 million
of cash from Cactus II, which represented the other members’ portion of the property and equipment.
In addition, during the second quarter of 2018, we received a
$100 million
advance cash payment from Cactus II associated with pipeline capacity agreements, which is recorded as long-term deferred revenue within “Other long-term liabilities and deferred credits” on our Condensed Consolidated Balance Sheet. Such amount will be recognized in revenue ratably over the life of the contracts beginning once the Cactus II pipeline system has been placed into service.
Note 13
—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, 2018
, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident, as discussed further below) totaled
$126 million
, of which
$46 million
was classified as short-term and
$80 million
was classified as long-term. At
December 31, 2017
, our estimated undiscounted reserve for environmental liabilities (including liabilities related to the Line 901 incident) totaled
$162 million
, of which
$72 million
was classified as short-term and
$90 million
was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our Condensed Consolidated Balance Sheets. At
September 30, 2018
, we had recorded receivables totaling
$49 million
for amounts probable of recovery under insurance and from third parties under indemnification agreements, of which
$23 million
was reflected in “Trade accounts receivable and other receivables, net” and
$26 million
was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet. At
December 31, 2017
, we had recorded
$55 million
of such receivables, of which
$29 million
was reflected in “Trade accounts receivable and other receivables, net” and
$26 million
was reflected in “Other long-term assets, net” on our Condensed Consolidated Balance Sheet.
In some cases, the actual cash expenditures associated with these liabilities may not occur for three years or longer. Our estimates used in determining these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing or future legal claims giving rise to additional liabilities. Therefore, although we believe that the reserve is adequate, actual costs incurred (which may ultimately include costs for contingencies that are currently not reasonably estimable or costs for contingencies where the likelihood of loss is currently believed to be only reasonably possible or remote) may be in excess of the reserve and may potentially have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Specific Legal, Environmental or Regulatory Matters
Line 901 Incident
. In May 2015, we experienced a crude oil release from our Las Flores to Gaviota Pipeline (Line 901) in Santa Barbara County, California. A portion of the released crude oil reached the Pacific Ocean at Refugio State Beach through a drainage culvert. Following the release, we shut down the pipeline and initiated our emergency response plan. A Unified Command, which included the United States Coast Guard, the EPA, the California Office of Spill Prevention and Response and the Santa Barbara Office of Emergency Management, was established for the response effort. Clean-up and remediation operations with respect to impacted shoreline and other areas has been determined by the Unified Command to be complete, and the Unified Command has been dissolved. Our estimate of the amount of oil spilled, based on relevant facts, data and information, is approximately
2,934
barrels; of this amount, we estimate that
598
barrels reached the Pacific Ocean.
As a result of the Line 901 incident, several governmental agencies and regulators initiated investigations into the Line 901 incident, various claims have been made against us and a number of lawsuits have been filed against us. We may be subject to additional claims, investigations and lawsuits, which could materially impact the liabilities and costs we currently expect to incur as a result of the Line 901 incident. Set forth below is a brief summary of actions and matters that are currently pending:
On May 21, 2015, we received a corrective action order from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the governmental agency with jurisdiction over the operation of Line 901 as well as over a second stretch of pipeline extending from Gaviota Pump Station in Santa Barbara County to Emidio Pump Station in Kern County, California (Line 903), requiring us to shut down, purge, review, remediate and test Line 901. The corrective action order was subsequently amended on June 3, 2015; November 13, 2015; and June 16, 2016 to require us to take additional corrective actions with respect to both Lines 901 and 903 (as amended, the “CAO”). Among other requirements, the CAO obligated us to conduct a root cause failure analysis with respect to Line 901 and present remedial work plans and restart plans to PHMSA prior to returning Line 901 and 903 to service; the CAO also imposed a pressure restriction on the section of Line 903 between Pentland Pump Station and Emidio Pump Station and required us to take other specified actions with respect to both Lines 901 and 903. We intend to continue to comply with the CAO and to cooperate with any other governmental investigations relating to or arising out of the release. Excavation and removal of the affected section of the pipeline was completed on May 28, 2015. Line 901 and Line 903 have been purged and are not currently operational, with the exception of the Pentland to Emidio segment of Line 903, which remains in service under a pressure restriction. No timeline has been established for the restart of Line 901 or Line 903.
On February 17, 2016, PHMSA issued a Preliminary Factual Report of the Line 901 failure, which contains PHMSA’s preliminary findings regarding factual information about the events leading up to the accident and the technical analysis that has been conducted to date. On May 19, 2016, PHMSA issued its final Failure Investigation Report regarding the Line 901 incident. PHMSA’s findings indicate that the direct cause of the Line 901 incident was external corrosion that thinned the pipe wall to a level where it ruptured suddenly and released crude oil. PHMSA also concluded that there were numerous contributory causes of the Line 901 incident, including ineffective protection against external corrosion, failure to detect and mitigate the corrosion and a lack of timely detection and response to the rupture. The report also included copies of various engineering and technical reports regarding the incident. By virtue of its statutory authority, PHMSA has the power and authority to impose fines and penalties on us and cause civil or criminal charges to be brought against us. While to date PHMSA has not imposed any such fines or penalties or brought any such civil or criminal charges with respect to the Line 901 release, their investigation is still open and we are likely to have fines or penalties imposed upon us, and we may have civil or criminal charges brought against us, in the future.
In late May of 2015, the California Attorney General’s Office and the District Attorney’s office for the County of Santa Barbara began investigating the Line 901 incident to determine whether any applicable state or local laws had been violated. On May 16, 2016, PAA and
one
of its employees were charged by a California state grand jury, pursuant to an indictment filed in California Superior Court, Santa Barbara County (the “May 2016 Indictment”), with alleged violations of California law in connection with the Line 901 incident. The May 2016 Indictment included a total of
46
counts against PAA. On July 28, 2016, at an arraignment hearing held in California Superior Court in Santa Barbara County, PAA pled not guilty to all counts. Between May of 2016 and May of 2018,
31
of the criminal charges against PAA (including
one
felony charge) and all of the criminal charges against our employee, were dismissed. The remaining
15
charges were the subject of a jury trial in California Superior Court in Santa Barbara County that began in May of 2018. The jury returned a verdict on September 7, 2018, pursuant to which we were (i) found guilty on
one
felony discharge count and
eight
misdemeanor counts (which included
one
reporting count,
one
strict liability discharge count and
six
strict liability animal takings counts) and (ii) found not guilty on
one
strict liability animal takings count. The jury deadlocked on
three
counts (including
two
felony discharge counts and
one
strict liability animal takings count), and
two
misdemeanor discharge counts were dropped. We are in the process of pursuing and evaluating our post-trial options, which include the possibility of an appeal. We do not anticipate that the fines or penalties imposed as a result of the jury’s decision will have a material adverse impact on the financial position or operations of the Partnership.
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 have cooperated with the DOJ’s investigation by responding to their requests for documents and access to our employees. Consistent with the terms of our governing organizational documents, we are funding our employees’ defense costs, including the costs of separate counsel engaged to represent such individuals. On August 26, 2015, we received a Request for Information from the EPA relating to Line 901. We have provided various responsive materials to date and we will continue to do so in the future in cooperation with the EPA. While to date no civil actions or criminal charges with respect to the Line 901 release, other than those brought pursuant to the May 2016 Indictment and a separate civil claim brought by the California Attorney General on
behalf of the California State Lands Commission, have been brought against PAA or any of its affiliates, officers or employees by PHMSA, DOJ, EPA, the California Attorney General, the Santa Barbara District Attorney or the California Department of Fish and Wildlife, and
no
fines or penalties have been imposed by such governmental agencies, the investigations being conducted by such agencies are still open and we may have fines or penalties imposed upon us, our officers or our employees, or civil actions or criminal charges brought against us, our officers or our employees in the future, whether by those or other governmental agencies.
Shortly following the Line 901 incident, we established a claims line and encouraged any parties that were damaged by the release to contact us to discuss their damage claims. We have received a number of claims through the claims line and we have been processing those claims and making payments as appropriate. In addition, we have also had
nine
class action lawsuits filed against us,
six
of which have been administratively consolidated into a single proceeding in the United States District Court for the Central District of California. In general, the plaintiffs are seeking to establish different classes of claimants that have allegedly been damaged by the release. To date, the court has certified three sub-classes of claimants and denied certification of the other proposed sub-class. The sub-classes that have been certified include (i) commercial fishermen who landed fish in certain specified fishing blocks in the waters adjacent to Santa Barbara County or persons or businesses who resold commercial seafood landed in such areas; (ii) individuals or businesses who were employed by or had contracts with certain designated oil platforms and related onshore processing facilities in the vicinity of the release as of the date of the release and (iii) beachfront property and easement owners whose properties were oiled. The Ninth Circuit Court of Appeals has granted our petition for leave to appeal the oil industry class certification. 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 the Partnership and/or PAGP against the Partnership, 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 the Partnership’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 the Partnership and PAGP, which they attribute to the alleged wrongful acts of the defendants. The Partnership and PAGP, and the other defendants, denied the allegations in, and moved to dismiss these lawsuits. On March 29, 2017, the Court ruled in our favor dismissing all claims against all defendants. Plaintiffs refiled their complaint. On April 2, 2018, the Court dismissed all of the refiled claims against all defendants with prejudice. Plaintiffs have appealed the dismissal. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we have indemnified and funded the defense costs of our officers and directors in connection with this lawsuit; we have also indemnified and funded the defense costs of our underwriters pursuant to the terms of the underwriting agreements we previously entered into with such underwriters.
In addition,
four
unitholder derivative lawsuits have been filed by certain purported investors in the Partnership against the Partnership, certain of its affiliates and certain officers and directors.
One
lawsuit was filed in State District Court in Harris County, Texas and subsequently dismissed by the Court.
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. In general, these derivative 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 the Partnership during the period of time leading up to and following the Line 901 release. The plaintiffs in the remaining lawsuit claim that the Partnership suffered unspecified damages as a result of the actions of the various defendants and seek to hold the defendants liable for such damages, in addition to other remedies. The defendants deny the allegations in this lawsuit and have responded accordingly. Consistent with and subject to the terms of our governing organizational documents (and to the extent applicable, insurance policies), we are indemnifying and funding the defense costs of our officers and directors in connection with this lawsuit.
We have also received several other individual lawsuits and complaints from companies, governmental agencies 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, 2018
, we estimate that the aggregate total costs we have incurred or will incur with respect to the Line 901 incident will be approximately
$335 million
, which estimate includes actual and projected emergency response and clean-up costs, natural resource damage assessments and certain third party claims settlements, as well as estimates for fines, penalties and certain legal fees. We accrue such estimates of aggregate total costs to “Field operating costs” in our Condensed Consolidated Statement of Operations. This estimate considers our prior experience in environmental investigation and remediation matters and available data from, and in consultation with, our environmental and other specialists, as well as currently available facts and presently enacted laws and regulations. We have made assumptions for (i) the duration of the natural resource damage assessment process and the ultimate amount of damages determined, (ii) the resolution of certain third party claims and lawsuits, but excluding claims and lawsuits with respect to which losses are not probable and reasonably estimable, and excluding future claims and lawsuits, (iii) the determination and calculation of fines and penalties, but excluding fines and penalties that are not probable and reasonably estimable and (iv) the nature, extent and cost of legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Line 901 incident. Our estimate does not include any lost revenue associated with the shutdown of Line 901 or 903 and does not include any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where we currently regard the likelihood of loss as being only reasonably possible or remote. We believe we have accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that we have made. For example, the amount of time it takes for us to resolve all of the current and future lawsuits, claims and investigations that relate to the Line 901 incident could turn out to be significantly longer than we have assumed, and as a result the costs we incur for legal services could be significantly higher than we have estimated. In addition, with respect to fines and penalties, the ultimate amount of any fines and penalties assessed against us depends on a wide variety of factors, many of which are not estimable at this time. Where fines and penalties are probable and estimable, we have included them in our estimate, although such estimates could turn out to be wrong. Accordingly, our assumptions and estimates may turn out to be inaccurate and our total costs could turn out to be materially higher; therefore, we can provide no assurance that we will not have to accrue significant additional costs in the future with respect to the Line 901 incident.
As of
September 30, 2018
, we had a remaining undiscounted gross liability of
$65 million
related to this event, of which approximately
$37 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, 2018
, we had collected, subject to customary reservations,
$180 million
out of the approximate
$220 million
of release costs that we believe are probable of recovery from insurance carriers, net of deductibles. Therefore, as of
September 30, 2018
, we have recognized a receivable of approximately
$40 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
$16 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 14
—Operating Segments
We manage our operations through
three
operating segments: Transportation, Facilities and Supply and Logistics. See
Note 3
for a summary of the types of products and services from which each segment derives its revenues. Our CODM (our Chief Executive Officer) evaluates segment performance based on measures including Segment Adjusted EBITDA (as defined below) and maintenance capital investment.
We define Segment Adjusted EBITDA as revenues and equity earnings in unconsolidated entities less (a) purchases and related costs, (b) field operating costs and (c) segment general and administrative expenses, plus our proportionate share of the depreciation and amortization expense and gains or losses on significant asset sales of unconsolidated entities, and further adjusted for certain selected items including (i) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (ii) long-term inventory costing adjustments, (iii) charges for obligations that are expected to be settled with the issuance of equity instruments, (iv) amounts related to deficiencies associated with minimum volume commitments, net of the applicable amounts subsequently recognized into revenue and (v) other items that our CODM believes are integral to understanding our core segment operating performance. Segment Adjusted EBITDA excludes depreciation and amortization.
Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets.
The following tables reflect certain financial data for each segment (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
292
|
|
|
$
|
149
|
|
|
$
|
8,482
|
|
|
$
|
(131
|
)
|
|
$
|
8,792
|
|
Intersegment
(2)
|
|
206
|
|
|
140
|
|
|
1
|
|
|
131
|
|
|
478
|
|
Total revenues of reportable segments
|
|
$
|
498
|
|
|
$
|
289
|
|
|
$
|
8,483
|
|
|
$
|
—
|
|
|
$
|
9,270
|
|
Equity earnings in unconsolidated entities
|
|
$
|
110
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
110
|
|
Segment Adjusted EBITDA
|
|
$
|
388
|
|
|
$
|
173
|
|
|
$
|
75
|
|
|
|
|
$
|
636
|
|
Maintenance capital
|
|
$
|
41
|
|
|
$
|
33
|
|
|
$
|
4
|
|
|
|
|
$
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
|
|
Total
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External customers
(1)
|
|
$
|
808
|
|
|
$
|
437
|
|
|
$
|
24,374
|
|
|
$
|
(350
|
)
|
|
$
|
25,269
|
|
Intersegment
(2)
|
|
619
|
|
|
429
|
|
|
2
|
|
|
350
|
|
|
1,400
|
|
Total revenues of reportable segments
|
|
$
|
1,427
|
|
|
$
|
866
|
|
|
$
|
24,376
|
|
|
$
|
—
|
|
|
$
|
26,669
|
|
Equity earnings in unconsolidated entities
|
|
$
|
281
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
$
|
281
|
|
Segment Adjusted EBITDA
|
|
$
|
1,083
|
|
|
$
|
530
|
|
|
$
|
120
|
|
|
|
|
$
|
1,733
|
|
Maintenance capital
|
|
$
|
102
|
|
|
$
|
74
|
|
|
$
|
10
|
|
|
|
|
$
|
186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2017
|
|
Transportation
|
|
Facilities
|
|
Supply and
Logistics
|
|
Intersegment Adjustment
|
|
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
|
|
|
|
(1)
|
Transportation revenues from external customers include certain inventory exchanges with our customers where our Supply and Logistics segment has transacted the inventory exchange and serves as the shipper on our pipeline systems. See
Note 3
for a discussion of our related accounting policy. We have included an estimate of the revenues from these inventory exchanges in our Transportation segment revenue from external customers presented above and adjusted those revenues out such that Total revenue from External customers reconciles to our Condensed Consolidated Statements of Operations. This presentation is consistent with the information provided to our CODM.
|
|
|
(2)
|
Segment revenues include intersegment amounts that are eliminated in Purchases and related costs and Field operating costs in our Condensed Consolidated Statements of Operations. Intersegment activities are conducted at posted tariff rates where applicable, or otherwise at 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 PAA (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Segment Adjusted EBITDA
|
$
|
636
|
|
|
$
|
489
|
|
|
$
|
1,733
|
|
|
$
|
1,451
|
|
Adjustments
(1)
:
|
|
|
|
|
|
|
|
Depreciation and amortization of unconsolidated entities
(2)
|
(15
|
)
|
|
(13
|
)
|
|
(44
|
)
|
|
(31
|
)
|
Gains/(losses) from derivative activities net of inventory valuation adjustments
(3)
|
110
|
|
|
(216
|
)
|
|
(107
|
)
|
|
86
|
|
Long-term inventory costing adjustments
(4)
|
10
|
|
|
16
|
|
|
18
|
|
|
2
|
|
Deficiencies under minimum volume commitments, net
(5)
|
4
|
|
|
(8
|
)
|
|
(9
|
)
|
|
(5
|
)
|
Equity-indexed compensation expense
(6)
|
(14
|
)
|
|
(7
|
)
|
|
(37
|
)
|
|
(18
|
)
|
Net gain/(loss) on foreign currency revaluation
(7)
|
3
|
|
|
14
|
|
|
(5
|
)
|
|
27
|
|
Line 901 incident
(8)
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Significant acquisition-related expenses
(9)
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Depreciation and amortization
|
(131
|
)
|
|
(151
|
)
|
|
(306
|
)
|
|
(401
|
)
|
Gain on sale of investment in unconsolidated entities
|
210
|
|
|
—
|
|
|
210
|
|
|
—
|
|
Interest expense, net
|
(110
|
)
|
|
(134
|
)
|
|
(327
|
)
|
|
(390
|
)
|
Other income/(expense), net
|
(3
|
)
|
|
(1
|
)
|
|
8
|
|
|
(6
|
)
|
Income/(loss) before tax
|
700
|
|
|
(11
|
)
|
|
1,134
|
|
|
697
|
|
Income tax (expense)/benefit
|
10
|
|
|
45
|
|
|
(35
|
)
|
|
(30
|
)
|
Net income
|
710
|
|
|
34
|
|
|
1,099
|
|
|
667
|
|
Net income attributable to noncontrolling interests
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(2
|
)
|
Net income attributable to PAA
|
$
|
710
|
|
|
$
|
33
|
|
|
$
|
1,099
|
|
|
$
|
665
|
|
|
|
(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 and 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 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 13
for additional information regarding the Line 901 incident.
|
|
|
(9)
|
Includes acquisition-related expenses associated with the acquisition of the Alpha Crude Connector Gathering System (the “ACC Acquisition”). See Note 6 to our Consolidated Financial Statements included in Part IV of our
2017
Annual Report on Form 10-K for additional discussion.
|