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OFFON

PLAINS ALL AMERICAN PIPELINE, L.P.

(PAA)
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PLAINS ALL AMERICAN PIPELINE LP MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

11/08/2021 | 05:24pm EST

Introduction


The following discussion is intended to provide investors with an understanding
of our financial condition and results of our operations and should be read in
conjunction with our historical Consolidated Financial Statements and
accompanying notes and Management's Discussion and Analysis of Financial
Condition and Results of Operations as presented in our 2020 Annual Report on
Form 10-K. For more detailed information regarding the basis of presentation for
the following financial information, see the Condensed Consolidated Financial
Statements and related notes that are contained in Part I, Item 1 of this
Quarterly Report on Form 10-Q.

Our discussion and analysis includes the following:


•Executive Summary
•Results of Operations
•Liquidity and Capital Resources
•Off-Balance Sheet Arrangements
•Recent Accounting Pronouncements
•Critical Accounting Policies and Estimates
•Forward-Looking Statements

Executive Summary

Company Overview


Our business model integrates large-scale supply aggregation capabilities with
the ownership and operation of critical midstream infrastructure systems that
connect major producing regions to key demand centers and export terminals. As
one of the largest midstream service providers in North America, we own an
extensive network of pipeline transportation, terminalling, storage and
gathering assets in key crude oil and NGL producing basins (including the
Permian Basin) and transportation corridors and at major market hubs in the
United States and Canada. Our assets and the services we provide are primarily
focused on crude oil and NGL. Our business activities are conducted through
three operating segments: Transportation, Facilities and Supply and Logistics.

Recent Developments


On August 2, 2021, we completed the sale of our Pine Prairie and Southern Pines
natural gas storage facilities for net proceeds of approximately $850 million,
including working capital adjustments. In connection with the sale, we repaid
term loans totaling $200 million.

On October 5, 2021, we and Oryx Midstream completed the merger of our respective
Permian Basin assets, operations and commercial activities into a newly formed
strategic joint venture, Plains Oryx Permian Basin. Plains Oryx Permian Basin
includes all of Oryx Midstream's Permian Basin assets and, with the exception of
our long-haul pipeline systems and certain of our intra-basin terminal assets,
the vast majority of our assets located within the Permian Basin. We own 65% of
Plains Oryx Permian Basin, operate the combined assets and will reflect Plains
Oryx Permian Basin as a consolidated subsidiary in our consolidated financial
statements. Structured as a debt-free joint venture entity through a cashless
transaction, this aligns with our financial and portfolio optimization
strategies and is expected to be near-term free cash flow accretive.

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Overview of Operating Results

During the first nine months of 2021, we recognized net income of $152 million
compared to a net loss of $2.555 billion recognized during the first nine months
of 2020. The net loss for the 2020 period was primarily driven by goodwill
impairment losses and non-cash impairment charges related to the write-down of
certain pipeline and other long-lived assets, certain of our investments in
unconsolidated entities, and assets upon classification as held for sale
totaling approximately $3.33 billion. In addition, we recognized approximately
$233 million of inventory valuation adjustments due to declines in commodity
prices during the first quarter of 2020. The comparable nine-month 2021 period
includes a net loss on asset sales and asset impairments of $592 million.

Results from our reporting segments during the first nine months of 2021
decreased from the comparable 2020 period driven primarily by the impact of less
favorable crude oil market conditions combined with lower realized NGL margins
in our Supply and Logistics segment. In addition, our Facilities segment was
unfavorably impacted by reduced NGL capacity utilization and market rates as
well as the impact of asset sales. These unfavorable results were partially
offset by favorable Transportation segment results that benefited from the
collection of deficiency payments associated with minimum volume commitments and
lower operating costs.

See further discussion of our operating results in the "-Results of Operations-Analysis of Operating Segments" and "-Other Income and Expenses" sections below.

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Results of Operations

The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit data):

                                                Three Months Ended                                                             Nine Months Ended
                                                  September 30,                           Variance                               September 30,                         Variance
                                               2021                2020              $                %                      2021              2020               $                %
Transportation Segment Adjusted EBITDA
(1)                                     $       427              $  444          $   (17)              (4) %             $   1,248          $  1,233          $    15                1  %
Facilities Segment Adjusted EBITDA (1)          114                 176              (62)             (35) %                   425               560             (135)             (24) %
Supply and Logistics Segment Adjusted
EBITDA (1)                                      (23)                 61              (84)            (138) %                   (31)              205             (236)            (115) %

Adjustments:

Depreciation and amortization of
unconsolidated entities                         (21)                (18)              (3)             (17) %                  (109)              (51)             (58)            (114) %
Selected items impacting comparability
- Segment Adjusted EBITDA                       (67)               (163)              96                  **                    52              (352)             404                  **
Depreciation and amortization                  (178)               (160)             (18)             (11) %                  (551)             (493)             (58)             (12) %
Gains/(losses) on asset sales and asset
impairments, net                               (221)                  2             (223)                 **                  (592)             (617)              25                4  %
Goodwill impairment losses                        -                   -                -                 N/A                     -            (2,515)           2,515              100  %
Gain on/(impairment of) investments in
unconsolidated entities, net                      -                 (91)              91              100  %                     -              (182)             182              100  %
Interest expense, net                          (106)               (113)               7                6  %                  (319)             (329)              10                3  %
Other income/(expense), net                     (10)                  5              (15)                 **                    13                (7)              20                  **
Income tax (expense)/benefit                     30                   3               27                  **                    16                (7)              23                  **
Net income/(loss)                               (55)                146             (201)            (138) %                   152            (2,555)           2,707              106  %
Net income attributable to
noncontrolling interests                         (4)                 (3)              (1)             (33) %                    (9)               (7)              (2)             (29) %
Net income/(loss) attributable to PAA   $       (59)             $  143          $  (202)            (141) %             $     143          $ (2,562)         $ 2,705              106  %

Basic and diluted net income/(loss) per
common unit                             $     (0.15)             $ 0.13          $ (0.28)                 **             $   (0.01)         $  (3.72)         $  3.71                  **

Basic and diluted weighted average
common units outstanding                        715                 728              (13)                 **                   719               728               (9)                 **



** Indicates that variance as a percentage is not meaningful. (1)Segment Adjusted EBITDA is the measure of segment performance that is utilized by our CODM to assess performance and allocate resources among our operating segments. This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.

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Non-GAAP Financial Measures

To supplement our financial information presented in accordance with GAAP,
management uses additional measures known as "non-GAAP financial measures" in
its evaluation of past performance and prospects for the future and to assess
the amount of cash that is available for distributions, debt repayments, common
equity repurchases and other general partnership purposes.

The primary additional measures used by management are earnings before interest,
taxes, depreciation and amortization (including our proportionate share of
depreciation and amortization, including write-downs related to cancelled
projects, of unconsolidated entities), gains and losses on asset sales and asset
impairments, goodwill impairment losses and gains on and impairments of
investments in unconsolidated entities, adjusted for certain selected items
impacting comparability ("Adjusted EBITDA"), Implied distributable cash flow
("DCF"), Free Cash Flow and Free Cash Flow after Distributions.

Our definition and calculation of certain non-GAAP financial measures may not be
comparable to similarly-titled measures of other companies. Adjusted EBITDA and
Implied DCF are reconciled to Net Income/(Loss), and Free Cash Flow and Free
Cash Flow after Distributions are reconciled to Net Cash Provided by Operating
Activities, the most directly comparable measures as reported in accordance with
GAAP, and should be viewed in addition to, and not in lieu of, our Condensed
Consolidated Financial Statements and accompanying notes. See "-Liquidity and
Capital Resources-Liquidity Measures" for additional information regarding Free
Cash Flow and Free Cash Flow after Distributions.

Performance Measures


Management believes that the presentation of Adjusted EBITDA and Implied DCF
provides useful information to investors regarding our performance and results
of operations because these measures, when used to supplement related GAAP
financial measures, (i) provide additional information about our core operating
performance and ability to fund distributions to our unitholders through cash
generated by our operations, (ii) provide investors with the same financial
analytical framework upon which management bases financial, operational,
compensation and planning/budgeting decisions and (iii) present measures that
investors, rating agencies and debt holders have indicated are useful in
assessing us and our results of operations. These non-GAAP measures may exclude,
for example, (i) charges for obligations that are expected to be settled with
the issuance of equity instruments, (ii) 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, (iii) long-term
inventory costing adjustments, (iv) items that are not indicative of our core
operating results and/or (v) other items that we believe should be excluded in
understanding our core operating performance. These measures may further be
adjusted to include amounts related to deficiencies associated with minimum
volume commitments whereby we have billed the counterparties for their
deficiency obligation and such amounts are recognized as deferred revenue in
"Other current liabilities" in our Condensed Consolidated Financial Statements.
Such amounts are presented net of applicable amounts subsequently recognized
into revenue. We have defined all such items as "selected items impacting
comparability." We do not necessarily consider all of our selected items
impacting comparability to be non-recurring, infrequent or unusual, but we
believe that an understanding of these selected items impacting comparability is
material to the evaluation of our operating results and prospects.

Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in "-Analysis of Operating Segments."

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The following tables set forth the reconciliation of the non-GAAP financial
performance measures Adjusted EBITDA and Implied DCF from Net Income/(Loss) (in
millions):
                                               Three Months Ended                                                          Nine Months Ended
                                                 September 30,                        Variance                               September 30,                         Variance
                                              2021              2020             $                %                      2021              2020               $                %

Net income/(loss)                         $      (55)         $ 146          $  (201)            (138) %             $     152          $ (2,555)         $ 2,707              106  %
Interest expense, net                            106            113               (7)              (6) %                   319               329              (10)              (3) %
Income tax expense/(benefit)                     (30)            (3)             (27)                 **                   (16)                7              (23)                 **
Depreciation and amortization                    178            160               18               11  %                   551               493               58               12  %
(Gains)/losses on asset sales and asset
impairments, net                                 221             (2)             223                  **                   592               617              (25)              (4) %
Goodwill impairment losses                         -              -                -                 N/A                     -             2,515           (2,515)            (100) %
(Gain on)/impairment of investments in
unconsolidated entities, net                       -             91              (91)            (100) %                     -               182             (182)            (100) %
Depreciation and amortization of
unconsolidated entities (1)                       21             18                3               17  %                   109                51               58              114  %
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities
and inventory valuation adjustments               13             88              (75)                 **                   (23)              210             (233)                 **
Long-term inventory costing adjustments          (13)             2              (15)                 **                   (81)               66             (147)                 **
Deficiencies under minimum volume
commitments, net                                  56             64               (8)                 **                    31                69              (38)                 **
Equity-indexed compensation expense                6              5                1                  **                    14                13                1                  **
Net (gain)/loss on foreign currency
revaluation                                        3              4               (1)                 **                     2                (9)              11                  **

Significant transaction-related expenses           2              -                2                  **                     5                 3                2                  **
Selected Items Impacting Comparability -
Segment Adjusted EBITDA (2)                       67            163              (96)                 **                   (52)              352             (404)                 **
(Gains)/losses from derivative activities
(3)                                               (4)            10              (14)                 **                   (13)               (7)              (6)                 **
Net (gain)/loss on foreign currency
revaluation (4)                                   15            (14)              29                  **                     1                20              (19)                 **
Net gain on early repayment of senior
notes (5)                                          -              -                -                  **                     -                (3)               3                  **
Selected Items Impacting Comparability -
Adjusted EBITDA (6)                               78            159              (81)                 **                   (64)              362             (426)                 **
Adjusted EBITDA (6)                       $      519          $ 682          $  (163)             (24) %             $   1,643          $  2,001          $  (358)             (18) %
Interest expense, net of certain non-cash
items (7)                                        (99)          (107)               8                7  %                  (301)             (313)              12                4  %
Maintenance capital (8)                          (43)           (53)              10               19  %                  (116)             (157)              41               26  %
Current income tax expense                        (8)           (17)               9               53  %                   (11)              (39)              28               72  %
Distributions from unconsolidated
entities in excess of/(less than)
adjusted equity earnings (9)                       9             (1)              10                  **                    11                 7                4                  **
Distributions to noncontrolling interests
(10)                                              (4)            (2)              (2)            (100) %                   (10)               (6)              (4)             (67) %
Implied DCF                               $      374          $ 502          $  (128)             (25) %             $   1,216          $  1,493          $  (277)             (19) %
Preferred unit distributions (10)                (37)           (37)               -                -  %                  (137)             (137)               -                -  %
Implied DCF Available to Common
Unitholders                               $      337          $ 465          $  (128)             (28) %             $   1,079          $  1,356          $  (277)             (20) %
Common unit cash distributions (10)             (129)          (131)                                                      (389)             (524)
Implied DCF Excess (11)                   $      208          $ 334                                                  $     690          $    832


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**  Indicates that variance as a percentage is not meaningful.
(1)We exclude our proportionate share of the depreciation and amortization
expense (including write-downs related to cancelled projects) of such
unconsolidated entities when reviewing Adjusted EBITDA, similar to our
consolidated assets.
(2)For a more detailed discussion of these selected items impacting
comparability, see the footnotes to the Segment Adjusted EBITDA Reconciliation
table in Note 11 to our Condensed Consolidated Financial Statements.
(3)The Preferred Distribution Rate Reset Option of our Series A preferred units
is accounted for as an embedded derivative and recorded at fair value in our
Condensed Consolidated Financial Statements. The associated gains and losses are
not integral to our results and were thus classified as a selected item
impacting comparability. See Note 8 to our Condensed Consolidated Financial
Statements for additional information regarding the Preferred Distribution Rate
Reset Option.
(4)During the periods presented, there were fluctuations in the value of CAD to
USD, resulting in the realization of foreign exchange gains and losses on the
settlement of foreign currency transactions as well as the revaluation of
monetary assets and liabilities denominated in a foreign currency. The
associated gains and losses are not integral to our results and were thus
classified as a selected item impacting comparability.
(5)Includes net gains recognized in connection with the repurchase of our
outstanding senior notes on the open market.
(6)Other income/(expense), net per our Condensed Consolidated Statements of
Operations, adjusted for selected items impacting comparability ("Adjusted Other
income/(expense), net") is included in Adjusted EBITDA and excluded from Segment
Adjusted EBITDA.
(7)Excludes certain non-cash items impacting interest expense such as
amortization of debt issuance costs and terminated interest rate swaps.
(8)Maintenance capital expenditures are defined as 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.
(9)Comprised of cash distributions received from unconsolidated entities less
equity earnings in unconsolidated entities (adjusted for our proportionate share
of depreciation and amortization, including write-downs related to cancelled
projects, and selected items impacting comparability of unconsolidated
entities).
(10)Cash distributions paid during the period presented.
(11)Excess DCF is retained to establish reserves for future distributions,
capital expenditures and other partnership purposes.

Analysis of Operating Segments

We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes, Segment Adjusted EBITDA per barrel 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 (including
write-downs related to cancelled projects) of unconsolidated entities, and
further adjusted for certain selected items including (i) the mark-to-market of
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
applicable amounts subsequently recognized into revenue and (v) other items that
our CODM believes are integral to understanding our core segment operating
performance. See Note 11 to our Condensed Consolidated Financial Statements for
a reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to
PAA.

Revenues and expenses from our Canadian based subsidiaries, which use CAD as
their functional currency, are translated at the prevailing average exchange
rates for the month.

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Transportation Segment

Our Transportation segment operations generally consist of fee-based activities
associated with transporting crude oil and NGL on pipelines, gathering systems
and trucks. The Transportation segment generates revenue through a combination
of tariffs, pipeline capacity agreements and other transportation fees. Tariffs
and other fees on our pipeline systems vary by receipt point and delivery point.
The segment results generated by our tariff and other fee-related activities
depend on the volumes transported on the pipeline and the level of the tariff
and other fees charged, as well as the fixed and variable field costs of
operating the pipeline.

The following tables set forth our operating results from our Transportation
segment:

                                                                  Three Months Ended                                                            Nine Months Ended
Operating Results (1)                                               September 30,                           Variance                              September 30,                         Variance
(in millions, except per barrel data)                            2021                2020              $                %                     2021               2020              $                %
Revenues                                                  $      529               $  494          $    35               7  %             $    1,568          $ 1,530          $    38                2  %
Purchases and related costs                                      (75)                 (60)             (15)            (25) %                   (181)            (184)               3                2  %
Field operating costs                                           (149)                (139)             (10)             (7) %                   (394)            (440)              46               10  %
Segment general and administrative expenses (2)                  (25)                 (22)              (3)            (14) %                    (79)             (73)              (6)              (8) %
Equity earnings in unconsolidated entities                        67                   87              (20)            (23) %                    185              276              (91)             (33) %

Adjustments: (3)
Depreciation and amortization of unconsolidated
entities                                                          20                   17                3              18  %                    107               49               58              118  %
Losses from derivative activities and inventory
valuation adjustments                                              -                    -                -                 **                     (1)               -               (1)                 **
Deficiencies under minimum volume commitments, net                56                   64               (8)                **                     33               64              (31)                 **
Equity-indexed compensation expense                                3                    3                -                 **                      8                8                -                  **

Significant transaction-related expenses                           1                    -                1                 **                      2                3               (1)                 **
Segment Adjusted EBITDA                                   $      427               $  444          $   (17)             (4) %             $    1,248          $ 1,233          $    15                1  %
Maintenance capital                                       $       22               $   34          $   (12)            (35) %             $       68          $    98          $   (30)             (31) %
Segment Adjusted EBITDA per barrel                        $     0.73               $ 0.79          $ (0.06)             (8) %             $     0.75          $  0.70          $  0.05                7  %



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                                                                    Three Months Ended                                                                      Nine Months Ended
Average Daily Volumes                                                 September 30,                               Variance                                    September 30,                               Variance
(in thousands of barrels per day) (4)                          2021                   2020                Volumes               %                      2021                   2020                Volumes               %
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (5)                                              4,394                  4,200                    194                5  %                 4,114                  4,507                   (393)              (9) %
South Texas / Eagle Ford (5)                                     311                    370                    (59)             (16) %                   315                    383                    (68)             (18) %
Central (5)                                                      483                    388                     95               24  %                   441                    383                     58               15  %
Gulf Coast                                                       176                    137                     39               28  %                   161                    133                     28               21  %
Rocky Mountain (5)                                               344                    238                    106               45  %                   320                    251                     69               27  %
Western                                                          224                    232                     (8)              (3) %                   239                    217                     22               10  %
Canada                                                           230                    303                    (73)             (24) %                   279                    291                    (12)              (4) %
Crude oil pipelines                                            6,162                  5,868                    294                5  %                 5,869                  6,165                   (296)              (5) %
NGL pipelines                                                    165                    180                    (15)              (8) %                   176                    187                    (11)              (6) %
Tariff activities total volumes                                6,327                  6,048                    279                5  %                 6,045                  6,352                   (307)              (5) %
Trucking volumes                                                  58                     67                     (9)             (13) %                    62                     75                    (13)             (17) %
Transportation segment total volumes                           6,385                  6,115                    270                4  %                 6,107                  6,427                   (320)              (5) %




**  Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable
to each segment and an allocation of other expenses to the segments. The
proportional allocations by segment require judgment by management and are based
on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our
CODM in the evaluation of segment results. See Note 11 to our Condensed
Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes are calculated as the total volumes (attributable to
our interest) for the period divided by the number of days in the period.
(5)Region includes volumes (attributable to our interest) from pipelines owned
by unconsolidated entities.

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Table of Contents The following is a discussion of items impacting Transportation segment operating results for the periods indicated.

Revenues, Purchases and Related Costs, Equity Earnings in Unconsolidated Entities and Volumes. The following table presents variances in revenues, purchases and related costs and equity earnings in unconsolidated entities by region:


                                                                            Favorable/(Unfavorable) Variance                                                         Favorable/(Unfavorable) Variance
                                                                            Three Months Ended September 30,                                                         Nine Months Ended September 30,
                                                                                        2021-2020                                                                               2021-2020
                                                                                               Purchases and            Equity                                                          Purchases and            Equity
(in millions)                                                     Revenues                     Related Costs           Earnings                            Revenues                     Related Costs           Earnings
Permian Basin region                                   $        14                           $          (14)         $      (16)               $        21                            $           (7)         $      (34)
South Texas / Eagle Ford region                                 (3)                                       -                  (2)                       (10)                                        -                 (14)
Central region                                                   5                                        -                   1                          8                                         1                 (23)
Gulf Coast region                                                3                                        -                   -                          5                                         -                 (10)
Rocky Mountain region                                            9                                        -                  (3)                        21                                         -                 (10)

Other regions, NGL pipelines, trucking and
pipeline loss allowance revenue                                  7                                       (1)                  -                         (7)                                        9                   -
Total variance                                         $        35                           $          (15)         $      (20)               $        38                            $            3          $      (91)



•Permian Basin region. Revenues, net of purchases and related costs, ("net
revenues") increased by $14 million for the nine months ended September 30,
2021, compared to the same period in 2020 primarily due to the recognition of
revenue associated with minimum volume commitments in the first and second
quarters of 2021. Such favorable impacts were partially offset by lower volumes
of crude oil produced in the Permian Basin in the first quarter of 2021, driven
by the COVID-19 pandemic-related reset to production and compounded by shut-ins
from the extreme winter weather event that occurred in February of 2021 ("Winter
Storm Uri").

Equity earnings decreased for the three and nine months ended September 30, 2021
compared to the same periods in 2020 primarily due to depreciation expense and
transition costs associated with phase one of the Wink to Webster pipeline being
placed into service during the first quarter of 2021, long-haul volumes shipped
at lower rates and our proportionate share of the write-off of costs associated
with a capital project canceled during the second quarter of 2021, partially
offset by lower power costs related to Winter Storm Uri.

•South Texas / Eagle Ford region. Revenues and volumes decreased for the three
and nine months ended September 30, 2021 compared to the same periods in 2020
due to lower production, including, for the nine-month period, the impact of
curtailments from Winter Storm Uri in the first quarter of 2021.

Equity earnings decreased for the nine months ended September 30, 2021 compared
to the same period in 2020 due to a combination of lower joint tariff volumes
from our Permian Basin long-haul system, and to a lesser extent, lower regional
receipts, partially offset by the recognition of previously deferred revenue
associated with minimum volume commitments.

•Central region. Revenues increased for the three and nine months ended September 30, 2021 compared to the same periods in 2020 primarily due to higher volumes on certain of our pipelines in the region, including the Red River pipeline, as a result of (i) additional volume commitments beginning in the third quarter of 2020 and the second quarter of 2021 and (ii) an expansion placed into service in October 2020.


Equity earnings decreased for the nine months ended September 30, 2021 compared
to the same period in 2020 primarily due to our proportionate share of Diamond
Pipeline's write-off of costs associated with the cancellation of the project to
connect Diamond Pipeline to Capline Pipeline (the Byhalia Connection) during the
second quarter of 2021.

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•Gulf Coast region. Revenues increased slightly for the three and nine months
ended September 30, 2021 compared to the same periods in 2020 due to higher
movements on a low tariff pipeline.

Equity earnings decreased for the nine months ended September 30, 2021 compared
to the same period in 2020 primarily due to our proportionate share of Capline
Pipeline's write-off of costs associated with the cancellation of the project to
connect Diamond Pipeline to Capline Pipeline (the Byhalia Connection) during the
second quarter of 2021.

•Rocky Mountain region. Revenues increased for the three and nine months ended
September 30, 2021 compared to the same periods in 2020 primarily due to (i)
increased movements on our cross-border pipelines and (ii) a new joint tariff
movement to Cushing, Oklahoma.

Equity earnings decreased for the nine months ended September 30, 2021 compared
to the same period in 2020 primarily due to the expiration of higher-tariff
volume commitments in the current period on the White Cliffs pipeline, partially
offset by higher volumes from committed shippers on the Saddlehorn pipeline.

Adjustments: Deficiencies under minimum volume commitments, net. Many industry
infrastructure projects developed and completed over the last several years were
underpinned by long-term minimum volume commitment contracts whereby the shipper
agreed to either: (i) ship and pay for certain stated volumes or (ii) pay the
agreed upon price for a minimum contract quantity. Some of these agreements
include make-up rights if the minimum volume is not met. If a counterparty has a
make-up right associated with a deficiency, we bill the counterparty and defer
the revenue attributable to the counterparty's make-up right but record an
adjustment to reflect such amount associated with the current period activity in
Segment Adjusted EBITDA. We subsequently recognize the revenue, and record a
corresponding reversal of the adjustment, 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.

For each of the three and nine month periods ended September 30, 2021 and 2020,
we billed and deferred amounts from counterparties associated with deficiencies
under minimum volume commitments. In each of the periods presented, the amount
we billed was in excess of the amount we recognized into revenue.

Field Operating Costs. The decrease in field operating costs for the nine months
ended September 30, 2021 compared to the same period in 2020 was primarily due
to (i) lower power costs, including the impact of gains related to hedged power
costs resulting from Winter Storm Uri and (ii) streamlining efforts which have
resulted in decreases in variable costs and maintenance and chemicals and
additives costs. These favorable impacts were partially offset by increased
field operating costs for the three months ended September 30, 2021 compared to
the three months ended September 30, 2020 due to (i) higher compensation costs,
including lower wage subsidies received by our Canadian subsidiary, and (ii) an
increase in power costs due to higher volumes.

Segment General and Administrative Expenses. The increase in segment general and
administrative expenses for the three and nine months ended September 30, 2021
compared to the same periods in 2020 was primarily due to increased information
systems costs and reduced wage subsidies received by our Canadian subsidiary in
the current periods. The nine-month comparative period was further unfavorably
impacted by an increase in equity-indexed compensation expense on
liability-classified awards (which are not included as an "Adjustment" in the
table above) due to an increase in our common unit price.

Maintenance Capital. 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 decrease in maintenance capital spending for the three and nine months ended
September 30, 2021 compared to the same periods in 2020 was primarily due to
timing changes, the completion of multi-year reliability improvement programs
and application of updated regulatory guidance, among other factors.

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Facilities Segment

Our Facilities segment operations generally consist of fee-based activities
associated with providing storage, terminalling and throughput services
primarily for crude oil and NGL, as well as NGL fractionation and isomerization
services and natural gas and condensate processing services. The Facilities
segment generates revenue through a combination of month-to-month and multi-year
agreements.

The following tables set forth our operating results from our Facilities
segment:

                                                                Three Months Ended                                                              Nine Months Ended
Operating Results (1)                                             September 30,                           Variance                                September 30,                          Variance
(in millions, except per barrel data)                          2021                2020              $                %                       2021                2020              $                %
Revenues                                                $      226               $  271          $   (45)            (17) %             $      741              $  860          $  (119)            (14) %
Purchases and related costs                                     (1)                  (2)               1              50  %                     (7)                (12)               5              42  %
Field operating costs                                          (86)                 (73)             (13)            (18) %                   (238)               (233)              (5)             (2) %
Segment general and administrative expenses (2)                (20)                 (18)              (2)            (11) %                    (60)                (63)               3               5  %
Equity earnings in unconsolidated entities                       2                    2                -               -  %                      5                   4                1              25  %

Adjustments: (3)
Depreciation and amortization of unconsolidated
entities                                                         1                    1                -                 **                      2                   2                -                 **
(Gains)/losses from derivative activities                       (9)                  (6)              (3)                **                    (19)                 (5)             (14)                **
Deficiencies under minimum volume commitments,
net                                                              -                    -                -                 **                     (2)                  5               (7)                **

Equity-indexed compensation expense                              1                    1                -                 **                      3                   2                1                 **
Segment Adjusted EBITDA                                 $      114               $  176          $   (62)            (35) %             $      425              $  560          $  (135)            (24) %
Maintenance capital                                     $       18               $   10          $     8              80  %             $       39              $   40          $    (1)             (3) %
Segment Adjusted EBITDA per barrel                      $     0.35               $ 0.47          $ (0.12)            (26) %             $     0.42              $ 0.50          $ (0.08)            (16) %



                                                Three Months Ended                                                                Nine Months Ended
                                                  September 30,                            Variance                                 September 30,                            Variance
Volumes (4)                                 2021                 2020              Volumes               %                    2021                 2020              Volumes               %
Liquids storage (average monthly
capacity in millions of barrels)
(5)                                          100                  111                   (11)            (10) %                 100                  110                   (10)             (9) %
Natural gas storage (average
monthly working capacity in
billions of cubic feet)                       23                   67                   (44)            (66) %                  54                   66                   (12)            (18) %
NGL fractionation (average volumes
in thousands of barrels per day)             119                  110                     9               8  %                 130                  129                     1               1  %
Facilities segment total volumes
(average monthly volumes in
millions of barrels) (6)                     108                  125                   (17)            (14) %                 113                  125                   (12)            (10) %




**  Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable
to each segment and an allocation of other expenses to the segments. The
proportional allocations by segment require judgment by management and are based
on the business activities that exist during each period.
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(3)Represents adjustments included in the performance measure utilized by our
CODM in the evaluation of segment results. See Note 11 to our Condensed
Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average monthly volumes are calculated as total volumes for the period
divided by the number of months in the period.
(5)Includes volumes (attributable to our interest) from facilities owned by
unconsolidated entities.
(6)Facilities segment total volumes are calculated as the sum of: (i) liquids
storage capacity; (ii) natural gas storage working capacity divided by 6 to
account for the 6:1 Mcf of natural gas to crude Btu equivalent ratio and further
divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL
fractionation volumes multiplied by the number of days in the period and divided
by the number of months in the period.

The following is a discussion of items impacting Facilities segment operating results.

Revenues, Purchases and Related Costs and Volumes. Variances in net revenues and average monthly volumes were primarily driven by the following:


•NGL Operations. Revenues from our NGL operations decreased by $13 million and
$70 million for the three and nine months ended September 30, 2021,
respectively, compared to the same periods in 2020 primarily due to reduced
intersegment facility fees to reflect lower utilization and market rates at
certain of our NGL facilities (which had an offsetting favorable impact on our
Supply and Logistics segment). The nine-month comparative period was further
unfavorably impacted by (i) a benefit in the 2020 comparative period from the
receipt of a deficiency payment of approximately $20 million upon the expiration
of a multi-year contract and (ii) the sale of certain NGL terminals in the
second quarter of 2020. Such unfavorable impacts were partially offset for the
three- and nine-month comparative periods by more favorable foreign exchange
impacts in 2021 of approximately $6 million and $25 million, respectively, and,
for the nine-month comparative period, gains at certain of our fractionation
facilities in the first quarter of 2021.

•Crude Oil Operations. Revenues from our crude oil storage operations decreased
by $8 million and $39 million for the three and nine months ended September 30,
2021, respectively, compared to the same periods in 2020 primarily due to the
sale of our Los Angeles Basin terminals in October of 2020, partially offset by
increased capacity and activity at certain of our Mid-Continent area terminals.
In addition, revenues from our crude oil rail operations decreased by $4 million
and $11 million for the three and nine months ended September 30, 2021,
respectively, compared to the same periods in 2020 due to decreased movements
and expiration of contracts.

•Natural Gas Storage. Net revenues decreased by $18 million for the three months
ended September 30, 2021 compared to the three months ended September 30, 2020
due to the sale of our natural gas storage facilities in August 2021. The impact
on net revenues of the sale of these facilities was nearly entirely offset for
the nine months ended September 30, 2021 compared to the same period in 2020
primarily due to increased margins from hub activities in the first quarter of
2021 related to Winter Storm Uri.

Field Operating Costs. The increase in field operating costs for the three and
nine months ended September 30, 2021 compared to the same periods in 2020 was
primarily due to (i) higher compensation costs, including lower wage subsidies
received by our Canadian subsidiary in the 2021 periods, (ii) costs associated
with a fire at our Fort Saskatchewan facility, and (iii) higher power costs due
to increased volumes at our NGL fractionation plants. These unfavorable impacts
were partially offset for the (i) three and nine months due to the sale of our
Los Angeles Basin terminals in October 2020 and natural gas storage facilities
in August 2021 and reduced activity at our rail terminals and (ii) nine months
due to the sale of certain NGL terminals in the second quarter of 2020.

Maintenance Capital. The increase in maintenance capital spending for the three months ended September 30, 2021 compared to the same period in 2020 was primarily due to timing of certain projects across multiple facilities.

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Supply and Logistics Segment

Revenues from our Supply and Logistics segment activities reflect the sale of
gathered and bulk-purchased crude oil, as well as sales of NGL volumes.
Generally, our segment results are impacted by (i) increases or decreases in our
Supply and Logistics segment volumes (which consist of lease gathering crude oil
purchases volumes and NGL sales volumes), (ii) the overall strength, weakness
and volatility of market conditions, including regional differentials, (iii) the
relationship between NGL prices and natural gas prices and (iv) the effects of
competition on our lease gathering and NGL margins. In addition, the execution
of our risk management strategies in conjunction with our assets can provide
upside in certain markets.

The following tables set forth our operating results from our Supply and
Logistics segment:

                                                                   Three Months Ended                                                             Nine Months Ended
Operating Results (1)                                                 September 30,                          Variance                               September 30,                          Variance
(in millions, except per barrel data)                             2021               2020              $                 %                      2021              2020                $                 %
Revenues                                                     $    10,515          $ 5,537          $ 4,978                90  %             $  28,222          $ 16,371          $ 11,851                72  %
Purchases and related costs                                      (10,488)          (5,510)          (4,978)              (90) %               (27,985)          (16,227)          (11,758)              (72) %
Field operating costs                                                (43)             (46)               3                 7  %                  (126)             (149)               23                15  %
Segment general and administrative expenses (2)                      (22)             (21)              (1)               (5) %                   (66)              (65)               (1)               (2) %

Adjustments: (3)
(Gains)/losses from derivative activities and
inventory valuation adjustments                                       22               94              (72)                  **                    (3)              215              (218)                  **
Long-term inventory costing adjustments                              (13)               2              (15)                  **                   (81)               66              (147)                  **
Equity-indexed compensation expense                                    2                1                1                   **                     3                 3                 -                   **
Net (gain)/loss on foreign currency revaluation                        3                4               (1)                  **                     2                (9)               11                   **
Significant transaction-related expenses                               1                -                1                   **                     3                 -                 3                   **
Segment Adjusted EBITDA                                      $       (23)         $    61          $   (84)             (138) %             $     (31)         $    205          $   (236)             (115) %
Maintenance capital                                          $         3          $     9          $    (6)              (67) %             $       9          $     19          $    (10)              (53) %
Segment Adjusted EBITDA per barrel                           $     (0.17)         $  0.54          $ (0.71)             (131) %             $   (0.08)         $   0.57          $  (0.65)             (114) %



                                                                   Three Months Ended                                                                      Nine Months Ended
Average Daily Volumes (4)                                            September 30,                               Variance                                    September 30,                               Variance
(in thousands of barrels per day)                             2021                   2020                Volumes               %                      2021                   2020                Volumes               %
Crude oil lease gathering purchases                           1,372                  1,147                    225               20  %                 1,300                  1,181                    119               10  %
NGL sales                                                        87                     83                      4                5  %                   139                    132                      7                5  %
Supply and Logistics segment total volumes                    1,459                  1,230                    229               19  %                 1,439                  1,313                    126               10  %




**  Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable
to each segment and an allocation of other expenses to the segments. The
proportional allocations by segment require judgment by management and are based
on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our
CODM in the evaluation of segment results. See Note 11 to our Condensed
Consolidated Financial Statements for additional discussion of such adjustments.
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Table of Contents (4)Average daily volumes are calculated as the total volumes for the period divided by the number of days in the period.


The following table presents the range of the NYMEX WTI benchmark price of crude
oil (in dollars per barrel):

                                                 NYMEX WTI
                                              Crude Oil Price
                                               Low            High
Three Months Ended September 30, 2021   $      62            $ 75
Three Months Ended September 30, 2020   $      37            $ 43

Nine Months Ended September 30, 2021    $      48            $ 75
Nine Months Ended September 30, 2020    $     (38)           $ 63



Our crude oil and NGL supply, logistics and distribution operations are not
directly affected by the absolute level of prices. Because the commodities that
we buy and sell are generally indexed to the same pricing indices for both sales
and purchases, revenues and costs related to purchases will fluctuate with
market prices. However, the margins related to those sales and purchases will
not necessarily have a corresponding increase or decrease. Additionally, net
revenues are impacted by net gains and losses from certain derivative activities
and inventory valuation and costing adjustments.

Our NGL operations are sensitive to weather-related demand, particularly during
the approximate five-month peak heating season of November through March, and
temperature differences from period-to-period may have a significant effect on
NGL demand and thus our financial performance.

Segment Adjusted EBITDA and Volumes. The following summarizes the significant items impacting our Supply and Logistics Segment Adjusted EBITDA:


•Crude Oil Operations. Net revenues from our crude oil operations were lower for
the three and nine months ended September 30, 2021 compared to the same periods
in 2020 due to the impact of more favorable market conditions in 2020, primarily
on contango margins.

•NGL Operations. Net revenues from our NGL operations were higher for the three
and nine months ended September 30, 2021 compared to the same periods in 2020
due to (i) a decrease in intersegment fees in 2021 to reflect lower utilization
and market rates (which had an offsetting unfavorable impact on our Facilities
and Transportation segments) and (ii) higher realized margins associated with
NGL processing and fractionation activities in the third quarter of 2021.

•Impact from Certain Derivative Activities and Inventory Valuation Adjustments.
The impact from certain derivative activities on our net revenues includes
mark-to-market and other gains and losses resulting from certain derivative
instruments that are related to underlying activities in another period (or the
reversal of mark-to-market gains and losses 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. See
Note 8 to our Condensed Consolidated Financial Statements for a comprehensive
discussion regarding our derivatives and risk management activities. These gains
and losses impact our net revenues but are excluded from Segment Adjusted EBITDA
and thus are reflected as an "Adjustment" in the table above.

•Long-Term Inventory Costing Adjustments. Our net revenues are impacted by
changes in the weighted average cost of our crude oil and NGL inventory pools
that result from price movements during the periods. These costing adjustments
related to long-term inventory necessary to meet our minimum inventory
requirements in third-party assets and other working inventory that was 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.
These costing adjustments impact our net revenues but are excluded from Segment
Adjusted EBITDA and thus are reflected as an "Adjustment" in the table above.
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•Foreign Exchange Impacts. Our net revenues are impacted by fluctuations in the
value of CAD to USD, resulting in the realization of foreign exchange gains and
losses on the settlement of foreign currency transactions as well as the
revaluation of monetary assets and liabilities denominated in a foreign currency
within our Canadian operations. These gains and losses impact our net revenues
but are excluded from Segment Adjusted EBITDA and thus are reflected as an
"Adjustment" in the table above.

•Field Operating Costs. The decrease in field operating costs for the nine months ended September 30, 2021 compared to the same period in 2020 was primarily driven by lower trucking costs due to more supply connected to pipelines resulting in lower trucking activity in the 2021 period.

Other Income and Expenses

Depreciation and Amortization


The increase in depreciation and amortization expense for the three and nine
months ended September 30, 2021 compared to the same periods in 2020 was largely
driven by a reduction in the useful lives of certain assets. See Note 2 to our
Condensed Consolidated Financial Statements for additional information.

Gains/(Losses) on Asset Sales and Asset Impairments, Net


The net losses on asset sales and asset impairments for 2021 primarily include
(i) an approximate $220 million non-cash impairment charge recognized in the
third quarter related to the write-down of certain crude oil storage terminal
assets as a result of decreased demand for our services due to changing market
conditions, (ii) an approximate $475 million non-cash impairment charge related
to the write-down of our Pine Prairie and Southern Pines natural gas storage
facilities upon classification as held for sale during the second quarter, which
were sold on August 2, 2021, and (iii) a gain of $106 million recognized in the
second quarter related to the Asset Exchange transaction. See Note 12 to our
Condensed Consolidated Financial Statements for additional information. The net
loss on asset sales and asset impairments for the nine months ended September
30, 2020 was largely driven by (i) non-cash impairment losses of approximately
$446 million recognized in the first quarter related to the write-down of
certain pipeline and other long-lived assets due to macroeconomic and
geopolitical conditions including the collapse of oil prices driven by both the
decrease in demand caused by the COVID-19 pandemic and excess supply, as well as
changing market conditions and expected lower crude oil production in certain
regions, and (ii) approximately $167 million of impairment losses recognized on
assets upon classification as held for sale during the first quarter, which were
subsequently sold.

Goodwill Impairment Losses

During the first quarter of 2020, we recognized a goodwill impairment charge of $2.515 billion, representing the entire balance of goodwill.

Gain on/(Impairment of) Investments in Unconsolidated Entities, Net


During the three and nine months ended September 30, 2020, we recognized losses
of $91 million and $202 million, respectively, related to the write-down of
certain of our investments in unconsolidated entities. Additionally, during the
nine months ended September 30, 2020, we recognized a gain of $21 million
related to our sale of a 10% interest in Saddlehorn Pipeline Company, LLC.

Interest Expense


The decrease in interest expense for the three and nine months ended September
30, 2021 compared to the three and nine months ended September 30, 2020 was
primarily due to a lower weighted average debt balance and lower average rates
during the 2021 periods.

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Other Income/(Expense), Net

The following table summarizes the components impacting Other expense, net (in
millions):

                                                                     Three Months Ended                   Nine Months Ended
                                                                        September 30,                       September 30,
                                                                    2021              2020              2021              2020

Gain/(loss) related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option (1)

                    $        4  

$ (10) $ 13 $ 7 Net gain/(loss) on foreign currency revaluation (2)

                    (15)             14                  (1)            (20)
Other                                                                    1               1                   1               6
                                                                $      (10)         $    5          $       13          $   (7)




(1)See Note 8 to our Condensed Consolidated Financial Statements for additional
information.
(2)The activity during the periods presented was primarily related to the impact
from the change in the United States dollar to Canadian dollar exchange rate on
the portion of our intercompany net investment that is not long-term in nature.

Income Tax (Expense)/Benefit

The net favorable income tax variance for the three and nine months ended September 30, 2021 compared to the three and nine months ended September 30, 2020 was primarily a result of activity within our Canadian operations.

Liquidity and Capital Resources

General


Our primary sources of liquidity are (i) cash flow from operating activities and
(ii) borrowings under our credit facilities or commercial paper program. In
addition, we may supplement these primary sources of liquidity with proceeds
from our divestiture program and in the past we have utilized funds received
from sales of equity and debt securities. Our primary cash requirements include,
but are not limited to, (i) ordinary course of business uses, such as the
payment of amounts related to the purchase of crude oil, NGL and other products,
other expenses and interest payments on outstanding debt, (ii) investment and
maintenance capital activities, (iii) acquisitions of assets or businesses,
(iv) repayment of principal on our long-term debt and (v) distributions to our
unitholders. In addition, we may use cash for repurchases of common equity. We
generally expect to fund our short-term cash requirements through cash flow
generated from operating activities and/or borrowings under our commercial paper
program or credit facilities. In addition, we generally expect to fund our
long-term needs, such as those resulting from investment capital activities or
acquisitions and refinancing our long-term debt, through a variety of sources
(either separately or in combination), which may include the sources mentioned
above as funding for short-term needs and/or the issuance of additional equity
or debt securities and the sale of assets.

As of September 30, 2021, although we had a working capital deficit of $523
million, we had approximately $2.8 billion of liquidity available to meet our
ongoing operating, investing and financing needs, subject to continued covenant
compliance, as noted below (in millions):
                                                                                       As of
                                                                                   September 30,
                                                                                        2021

Availability under senior unsecured revolving credit facility (1) (2)

       $       1,293
Availability under senior secured hedged inventory facility (1) (2)                       1,343
Amounts outstanding under commercial paper program                                            -
Subtotal                                                                                  2,636
Cash and cash equivalents                                                                   191
Total                                                                             $       2,827



(1)Represents availability prior to giving effect to borrowings outstanding under our commercial paper program, which reduce available capacity under the facilities.

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(2)Available capacity under our senior unsecured revolving credit facility and
senior secured hedged inventory facility was reduced by outstanding letters of
credit of $57 million and $7 million, respectively.

In August 2021, we entered into new and amended credit agreements to facilitate
the renewal and extension of our credit facilities. Our $1.6 billion senior
unsecured revolving credit facility with a maturity date of August 2024 was
replaced with a $1.35 billion senior unsecured revolving credit facility with an
initial maturity in August 2026 and our $1.4 billion senior secured hedged
inventory facility with a maturity date of August 2022 was replaced with a $1.35
billion senior secured hedged inventory facility with an initial maturity in
August 2024. The credit agreements provide for one or more one-year extensions
and have accordion features which, subject to receipt of incremental lender
approval and other terms and conditions, permit us to increase borrowing
capacity under the senior unsecured revolving credit facility and senior secured
hedged inventory facility to $2.1 billion and $1.9 billion, respectively. The
covenants and events of default under the new and amended credit agreements
remain substantially unchanged from the previous agreements. See Note 6 to our
Condensed Consolidated Financial Statements for additional information.

Usage of our credit facilities, and, in turn, our commercial paper program, is
subject to ongoing compliance with covenants. The credit agreements for our
revolving credit facilities (which impact our ability to access our commercial
paper program because they provide the financial backstop that supports our
short-term credit ratings) and the indentures governing our senior notes contain
cross-default provisions. A default under our credit agreements or indentures
would permit the lenders to accelerate the maturity of the outstanding debt.
Additionally, lack of compliance with the provisions in our credit agreements
may restrict our ability to make distributions of available cash. We were in
compliance with the covenants contained in our credit agreements and indentures
as of September 30, 2021.

We believe that we have, and will continue to have, the ability to access our
commercial paper program and credit facilities, which we use to meet our
short-term cash needs. We believe that our financial position remains strong and
we have sufficient liquid assets, cash flow from operating activities and
borrowing capacity under our credit agreements to meet our financial
commitments, debt service obligations, contingencies and anticipated capital
expenditures. We are, however, subject to business and operational risks that
could adversely affect our cash flow, including extended disruptions in the
financial markets and/or energy price volatility resulting from current
macroeconomic and geopolitical conditions associated with the COVID-19 pandemic
and/or actions by Organization of Petroleum Exporting Countries ("OPEC"). A
prolonged material decrease in our cash flows would likely produce an adverse
effect on our borrowing capacity and cost of borrowing. Our borrowing capacity
and borrowing costs are also impacted by our credit rating. See Item 1A. "Risk
Factors" included in our 2020 Annual Report on Form 10-K for further discussion
regarding risks that may impact our liquidity and capital resources.

Liquidity Measures


Management uses the non-GAAP financial measures Free Cash Flow and Free Cash
Flow after Distributions to assess the amount of cash that is available for
distributions, debt repayments, common equity repurchases and other general
partnership purposes. Free Cash Flow is defined as Net Cash Provided by
Operating Activities, less Net Cash Used in Investing Activities, which
primarily includes acquisition, investment and maintenance capital expenditures,
investments in unconsolidated entities and the impact from the purchase and sale
of linefill and base gas, net of proceeds from the sales of assets and further
impacted by cash received from or paid to noncontrolling interests. Free Cash
Flow is further reduced by cash distributions paid to our preferred and common
unitholders to arrive at Free Cash Flow after Distributions.

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The following table sets forth the reconciliation of the non-GAAP financial
liquidity measures Free Cash Flow and Free Cash Flow after Distributions from
Net Cash Provided by Operating Activities (in millions):

                                                         Three Months Ended                        Nine Months Ended
                                                            September 30,                            September 30,
                                                       2021                  2020               2021               2020
Net cash provided by operating activities       $       336               $    282          $    1,361          $  1,256
Adjustments to reconcile net cash provided by
operating activities to free cash flow:
Net cash provided by/(used in) investing
activities                                              761                   (208)                478            (1,066)
Cash contributions from noncontrolling
interests                                                 -                      1                   1                11
Cash distributions paid to noncontrolling
interests (1)                                            (4)                    (2)                (10)               (6)

Free Cash Flow                                  $     1,093               $     73          $    1,830          $    195
Cash distributions (2)                                 (166)                  (168)               (526)             (661)
Free Cash Flow after Distributions              $       927               $    (95)         $    1,304          $   (466)



(1)Cash distributions paid during the period presented. (2)Cash distributions paid to our preferred and common unitholders during the period presented.

Cash Flow from Operating Activities

For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. "Liquidity and Capital Resources-Cash Flow from Operating Activities" included in our 2020 Annual Report on Form 10-K.


Net cash provided by operating activities for the first nine months of 2021 and
2020 was $1.361 billion and $1.256 billion, respectively, and primarily resulted
from earnings from our operations. During the nine months ended September 30,
2020, we increased the volume of our crude oil inventory to be stored during the
contango market; however, this increase was offset by lower prices for our
inventory stored at the end of the current period compared to the end of 2019.

Investing Activities

Capital Expenditures

In addition to our operating needs, we also use cash for our investment capital
projects, maintenance capital activities and acquisition activities. We fund
these expenditures with cash generated by operating activities, financing
activities and/or proceeds from our divestiture program. In the near term, we do
not plan to issue common equity to fund such expenditures. The following table
summarizes our investment, maintenance and acquisition capital expenditures (in
millions):

                                  Nine Months Ended
                                    September 30,
                                  2021            2020
Investment capital (1) (2)   $    182           $   785
Maintenance capital (1)           116               157
Acquisition capital (3)            32               310
                             $    330           $ 1,252




(1)Capital expenditures made to expand the existing operating and/or earnings
capacity of our assets are classified as "Investment capital." 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 are classified as "Maintenance capital."
(2)Includes contributions to unconsolidated entities, accounted for under the
equity method of accounting, related to investment capital projects by such
entities.
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(3)Acquisition capital for 2021 represents the cash consideration paid as part
of the Asset Exchange transaction. See Note 12 to our Condensed Consolidated
Financial Statements for additional information. Acquisition capital for 2020
primarily includes Felix Midstream LLC, a crude oil gathering system located in
the Delaware Basin.

2021 Investment and Maintenance Capital. Total projected investment capital for
the year ended December 31, 2021 is $275 million, a majority of which will be
invested in our fee-based Transportation and Facilities segments. Additionally,
maintenance capital for the full year of 2021 is projected to be $180 million.
We expect to fund our 2021 investment and maintenance capital expenditures with
retained cash flow and proceeds from assets sold as part of our divestiture
program.

Divestitures


We continue to evaluate potential sales of non-core assets and/or sales of
partial interests in assets to strategic joint venture partners. The following
table summarizes the proceeds received during the first nine months of 2021 and
2020 from sales of assets, which were previously reported in our Transportation
and Facilities segments (in millions):

                                          Nine Months Ended
                                            September 30,
                                           2021            2020
Proceeds from divestitures (1)      $     878             $ 246




(1)Represents gross proceeds, including working capital adjustments, before deducting transaction costs.


The proceeds from divestitures in 2021 are primarily from the sale of our Pine
Prairie and Southern Pines natural gas storage facilities on August 2, 2021. See
Note 12 to our Condensed Consolidated Financial Statements for additional
information. Proceeds from divestitures were used to reduce debt levels and fund
our investment capital projects.

Ongoing Activities Related to Strategic Transactions


We are continuously engaged in the evaluation of potential transactions that
support our current business strategy. While in the past such transactions have
included acquisitions and large capital projects, consistent with our current
strategic focus on capital discipline, leverage reduction, portfolio
optimization and free cash flow generation, we are currently primarily focused
on evaluating whether we should (i) sell assets that we regard as non-core or
that we believe might be a better fit with the business and/or assets of a
third-party buyer or (ii) sell partial interests in assets to strategic joint
venture partners, in each case to optimize our asset portfolio and strengthen
our balance sheet and leverage metrics. With respect to a potential divestiture,
we may also conduct an auction process or may negotiate a transaction with one
or a limited number of potential buyers. Such transactions could involve assets
that, if sold or put into a joint venture or joint ownership arrangement, could
have a material effect on our financial condition and results of operations.

We typically do not announce a transaction until after we have executed a
definitive agreement. However, in certain cases in order to protect our business
interests or for other reasons, we may defer public announcement of a
transaction until closing or a later date. Past experience has demonstrated that
discussions and negotiations regarding a potential transaction can advance or
terminate in a short period of time. Moreover, the closing of any transaction
for which we have entered into a definitive agreement may be subject to
customary and other closing conditions, which may not ultimately be satisfied or
waived. Accordingly, we can give no assurance that our current or future efforts
with respect to any such transactions will be successful, and we can provide no
assurance that our financial expectations with respect to such transactions will
ultimately be realized. See Item 1A. "Risk Factors-Risks Related to Our
Business-Divestitures, joint ventures, joint ownership arrangements and
acquisitions involve risks that may adversely affect our business" included in
our 2020 Annual Report on Form 10-K.

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Financing Activities

Our financing activities primarily relate to funding investment capital projects, acquisitions and refinancing of our debt maturities, as well as short-term working capital (including borrowings for NYMEX and ICE margin deposits) and hedged inventory borrowings related to our NGL business and contango market activities.

Borrowings and Repayments Under Credit Arrangements


During the nine months ended September 30, 2021, we had net repayments on our
credit facilities and commercial paper program of $713 million. The net
repayments resulted primarily from cash flow from operating activities and
proceeds from asset sales, which offset borrowings during the period related to
funding needs for capital investments, inventory purchases and other general
partnership purposes.

During the nine months ended September 30, 2020, we had net repayments on our
credit facilities and commercial paper program of $306 million. The net
repayments resulted primarily from cash flow from operating activities, proceeds
from asset sales and the issuance of $750 million, 3.80% senior notes in June
2020, which offset borrowings during the period related to funding needs for
capital investments, inventory purchases and other general partnership purposes.

In connection with the sale of our Pine Prairie and Southern Pines natural gas
storage facilities on August 2, 2021, we repaid our two GO Zone term loans
totaling $200 million. See Note 12 for additional information regarding the sale
of our natural gas storage facilities.

Common Equity Repurchase Program


We repurchased 11,917,303 common units under the Program through open market
purchases that settled during the nine months ended September 30, 2021. The
total purchase price of these repurchases was $117 million, including
commissions and fees. At September 30, 2021, the remaining available capacity
under the Program was $333 million.

Registration Statements


We periodically access the capital markets for both equity and debt financing.
We have filed with the SEC a universal shelf registration statement that,
subject to effectiveness at the time of use, allows us to issue, in the
aggregate, up to a specified amount of debt or equity securities ("Traditional
Shelf"), under which we had approximately $1.1 billion of unsold securities
available at September 30, 2021. We also have access to a universal shelf
registration statement ("WKSI Shelf"), which provides us with the ability to
offer and sell an unlimited amount of debt and equity securities, subject to
market conditions and our capital needs. We did not conduct any offerings under
our Traditional Shelf or WKSI Shelf during the nine months ended September 30,
2021.

Distributions to Our Unitholders


In accordance with our partnership agreement, after making distributions to
holders of our outstanding preferred units, we distribute the remainder of our
available cash to our common unitholders of record within 45 days following the
end of each quarter. Available cash is generally defined as all of our cash and
cash equivalents on hand at the end of each quarter less reserves established in
the discretion of our general partner for future requirements. Our levels of
financial reserves are established by our general partner and include reserves
for the proper conduct of our business (including future capital expenditures
and anticipated credit needs), compliance with legal or contractual obligations
and funding of future distributions to our Series A and Series B preferred
unitholders. Our available cash also includes cash on hand resulting from
borrowings made after the end of the quarter. See Item 5. "Market for
Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of
Equity Securities-Cash Distribution Policy" included in our 2020 Annual Report
on Form 10-K for additional discussion regarding distributions.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first nine months of 2021.

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Contingencies

For a discussion of contingencies that may impact us, see Note 10 to our Condensed Consolidated Financial Statements.

Commitments


Contractual Obligations. In the ordinary course of doing business, we purchase
crude oil and NGL from third parties under contracts, the majority of which
range in term from thirty-day evergreen to five years, with a limited number of
contracts with remaining terms extending up to 12 years. We establish a margin
for these purchases by entering into various types of physical and financial
sale and exchange transactions through which we seek to maintain a position that
is substantially balanced between purchases on the one hand and sales and future
delivery obligations on the other. The table below includes purchase obligations
related to these activities. Where applicable, the amounts presented represent
the net obligations associated with our counterparties (including giving effect
to netting buy/sell contracts and those subject to a net settlement
arrangement). We do not expect to use a significant amount of internal capital
to meet these obligations, as the obligations will be funded by corresponding
sales to entities that we deem creditworthy or who have provided credit support
we consider adequate.

The following table includes our best estimate of the amount and timing of these payments as well as other amounts due under the specified contractual obligations as of September 30, 2021 (in millions):

                                    Remainder of                                                                                   2026 and
                                        2021               2022              2023              2024              2025             Thereafter             Total
Long-term debt and related
interest payments (1)              $       101          $  1,138          $  1,463          $  1,085          $  1,303          $      8,339          $  13,429
Leases (2)                                  28               106                86                73                58                   331                682
Other obligations (3)                       82               337               338               282               267                   943              2,249
Subtotal                                   211             1,581             1,887             1,440             1,628                 9,613             16,360
Crude oil, NGL and other purchases
(4)                                      6,868            21,598            19,989            18,909            15,882                61,185            144,431
Total                              $     7,079          $ 23,179          $ 21,876          $ 20,349          $ 17,510          $     70,798          $ 160,791




(1)Includes debt service payments, interest payments due on senior notes and the
commitment fee on assumed available capacity under our credit facilities, as
well as long-term borrowings under our credit agreements and commercial paper
program, if any. Although there may be short-term borrowings under our credit
agreements and commercial paper program, we historically repay and borrow at
varying amounts. As such, we have included only the maximum commitment fee (as
if no short-term borrowings were outstanding on the credit agreements or
commercial paper program) in the amounts above. For additional information
regarding our debt obligations, see Note 6 to our Condensed Consolidated
Financial Statements.
(2)Includes both operating and finance leases as defined by FASB guidance.
Leases are primarily for (i) railcars, (ii) land, (iii) office space, (iv)
storage tanks, (v) tractor trailers and (vi) vehicles. See Note 14 to our
Consolidated Financial Statements included in Part IV of our 2020 Annual Report
on Form 10-K for additional information.
(3)Includes (i) other long-term liabilities, (ii) storage, processing and
transportation agreements (including certain agreements for which the amount and
timing of expected payments is subject to the completion of underlying
construction projects), (iii) certain rights-of-way easements and
(iv) noncancelable commitments related to our investment capital projects,
including projected contributions for our share of the capital spending of our
equity method investments. The storage, processing and transportation agreements
include approximately $1.8 billion associated with agreements to store crude oil
at facilities and transport crude oil or utilize capacity on pipelines owned by
equity method investees at posted tariff rates or prices that we believe
approximate market. A portion of our commitment to transport is supported by
crude oil buy/sell or other agreements with third parties with commensurate
quantities.
(4)Amounts are primarily based on estimated volumes and market prices based on
average activity during September 2021. The actual physical volume purchased and
actual settlement prices will vary from the assumptions used in the table.
Uncertainties involved in these estimates include levels of production at the
wellhead, weather conditions, changes in market prices and other conditions
beyond our control.

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Letters of Credit. In connection with 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, 2021 and December 31, 2020, we had
outstanding letters of credit of approximately $64 million and $129 million,
respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.

Recent Accounting Pronouncements

See Note 2 to our Condensed Consolidated Financial Statements.

Critical Accounting Policies and Estimates


For a discussion regarding our critical accounting policies and estimates, see
"Critical Accounting Policies and Estimates" under Item 7 of our 2020 Annual
Report on Form 10-K.

Change in Accounting Estimate


In early 2021, we conducted a review to assess the useful lives of our property
and equipment. Based on this review, we modified the useful lives of certain of
our Pipelines and related facilities and Storage, terminal and rail facilities
to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect
current expectations given our future operating and commercial outlook. This
change in accounting estimate was effective January 1, 2021. Based on the net
carrying amount of this property and equipment as of January 1, 2021, we
currently estimate that these useful life reductions will prospectively increase
annual depreciation expense by approximately $72 million.

                           FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical
fact, are forward-looking statements, including but not limited to statements
incorporating the words "anticipate," "believe," "estimate," "expect," "plan,"
"intend" and "forecast," as well as similar expressions and statements regarding
our business strategy, plans and objectives for future operations. The absence
of such words, expressions or statements, however, does not mean that the
statements are not forward-looking. Any such forward-looking statements reflect
our current views with respect to future events, based on what we believe to be
reasonable assumptions. Certain factors could cause actual results or outcomes
to differ materially from the results or outcomes anticipated in the
forward-looking statements. The most important of these factors include, but are
not limited to:

•declines in global crude oil demand and crude oil prices (whether due to the
COVID-19 pandemic, future pandemics or other factors) that correspondingly lead
to a significant reduction of North American crude oil, natural gas liquids
("NGL") and natural gas production (whether due to reduced producer cash flow to
fund drilling activities or the inability of producers to access capital, or
both, the unavailability of pipeline and/or storage capacity, the shutting-in of
production by producers, government-mandated pro-ration orders, or other
factors), which in turn could result in significant declines in the actual or
expected volume of crude oil and NGL shipped, processed, purchased, stored,
fractionated and/or gathered at or through the use of our assets and/or the
reduction of commercial opportunities that might otherwise be available to us;
•the effects of competition and capacity overbuild in areas where we operate,
including contract renewal risk and the risk of loss of business to other
midstream operators who are willing or under pressure to aggressively reduce
transportation rates in order to capture or preserve customers;
•negative societal sentiment regarding the hydrocarbon energy industry and the
continued development and consumption of hydrocarbons, which could influence
consumer preferences and governmental or regulatory actions that adversely
impact our business;
•unanticipated changes in crude oil and NGL market structure, grade
differentials and volatility (or lack thereof);
•environmental liabilities or events that are not covered by an indemnity,
insurance or existing reserves;
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•fluctuations in refinery capacity in areas supplied by our mainlines and other
factors affecting demand for various grades of crude oil, NGL and natural gas
and resulting changes in pricing conditions or transportation throughput
requirements;
•the availability of, and our ability to consummate, divestitures, joint
ventures, acquisitions or other strategic opportunities;
•the successful operation of joint ventures and joint operating arrangements we
enter into from time to time, whether relating to assets operated by us or by
third parties, and the successful integration and future performance of acquired
assets or businesses;
•maintenance of our credit rating and ability to receive open credit from our
suppliers and trade counterparties;
•the occurrence of a natural disaster, catastrophe, terrorist attack (including
eco-terrorist attacks) or other event that materially impacts our operations,
including cyber or other attacks on our electronic and computer systems;
•weather interference with business operations or project construction,
including the impact of extreme weather events or conditions;
•the refusal or inability of our customers or counterparties to perform their
obligations under their contracts with us (including commercial contracts, asset
sale agreements and other agreements), whether justified or not and whether due
to financial constraints (such as reduced creditworthiness, liquidity issues or
insolvency), market constraints, legal constraints (including governmental
orders or guidance), the exercise of contractual or common law rights that
allegedly excuse their performance (such as force majeure or similar claims) or
other factors;
•our inability to perform our obligations under our contracts, whether due to
non-performance by third parties, including our customers or counterparties,
market constraints, third-party constraints, legal constraints (including
governmental orders or guidance), or other factors;
•the incurrence of costs and expenses related to unexpected or unplanned capital
expenditures, third-party claims or other factors;
•disruptions to futures markets for crude oil, NGL and other petroleum products,
which may impair our ability to execute our commercial or hedging strategies;
•failure to implement or capitalize, or delays in implementing or capitalizing,
on investment capital projects, whether due to permitting delays, permitting
withdrawals or other factors;
•shortages or cost increases of supplies, materials or labor;
•the impact of current and future laws, rulings, governmental regulations, trade
policies, accounting standards and statements, and related interpretations,
including legislation or regulatory initiatives that prohibit, restrict or
regulate hydraulic fracturing or that prohibit the development of oil and gas
resources and the related infrastructure on lands dedicated to or served by our
pipelines;
•tightened capital markets or other factors that increase our cost of capital or
limit our ability to obtain debt or equity financing on satisfactory terms to
fund additional acquisitions, investment capital projects, working capital
requirements and the repayment or refinancing of indebtedness;
•general economic, market or business conditions in the United States and
elsewhere (including the potential for a recession or significant slowdown in
economic activity levels and the timing, pace and extent of economic recovery)
that impact demand for crude oil, drilling and production activities and
therefore the demand for the midstream services we provide and commercial
opportunities available to us;
•the amplification of other risks caused by volatile financial markets, capital
constraints, liquidity concerns and inflation;
•the use or availability of third-party assets upon which our operations depend
and over which we have little or no control;
•the currency exchange rate of the Canadian dollar to the United States dollar;
•inability to recognize current revenue attributable to deficiency payments
received from customers who fail to ship or move more than minimum contracted
volumes until the related credits expire or are used;
•significant under-utilization of our assets and facilities;
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•increased costs, or lack of availability, of insurance;
•the effectiveness of our risk management activities;
•fluctuations in the debt and equity markets, including the price of our units
at the time of vesting under our long-term incentive plans;
•risks related to the development and operation of our assets; and
•other factors and uncertainties inherent in the transportation, storage,
terminalling and marketing of crude oil, as well as in the processing,
transportation, fractionation, storage and marketing of NGL.

Other factors described herein, as well as factors that are unknown or
unpredictable, could also have a material adverse effect on future results.
Please read "Risk Factors" discussed in Item 1A of our 2020 Annual Report on
Form 10-K. Except as required by applicable securities laws, we do not intend to
update these forward-looking statements and information.

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