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)

05/10/2022 | 06:09am EDT

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 2021 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

•Recent Accounting Pronouncements

•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.

Segment Changes


During the fourth quarter of 2021, we reorganized our historical operating
segments into two operating segments: Crude Oil and NGL. Additionally, during
the fourth quarter of 2021, we modified our definition of Segment Adjusted
EBITDA to exclude amounts attributable to noncontrolling interests. See Note 20
to our Consolidated Financial Statements included in Part IV of our 2021 Annual
Report on Form 10-K for additional information. All segment data and related
disclosures for earlier periods presented herein have been recast to reflect the
new segment reporting structure and the modification to our definition of
Segment Adjusted EBITDA.

Overview of Operating Results


During the first three months of 2022, we recognized net income attributable to
PAA of $187 million compared to net income attributable to PAA of $422 million
recognized during the first three months of 2021. Results for the first three
months of 2022 decreased from the comparable 2021 period driven primarily by the
impact of the mark-to-market of certain derivative instruments, and, to a lesser
extent, the sale of our natural gas storage facilities and higher field
operating costs primarily from (i) an increase in estimated costs associated
with the Line 901 incident and (ii) gains related to hedged power costs
resulting from the extreme winter weather event that occurred in February 2021
("Winter Storm Uri") recognized in the first quarter of 2021. These items were
partially offset by more favorable margins in our NGL segment and increased
earnings from higher tariff volumes on our pipelines.

See the "Results of Operations" section below for further discussion.

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Results of Operations

Consolidated Results

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
                                                                          March 31,                       Variance
                                                                                                   2022              2021                $                 %
Product sales revenues                                                                          $ 13,381          $  8,083          $  5,298                 66  %
Services revenues                                                                                    313               300                13                  4  %
Purchases and related costs                                                                      (12,785)           (7,392)           (5,393)               (73) %
Field operating costs                                                                               (346)             (219)             (127)               (58) %
General and administrative expenses                                                                  (82)              (67)              (15)               (22) %
Depreciation and amortization                                                                       (230)             (177)              (53)               (30) %
Gains/(losses) on asset sales and asset
impairments, net                                                                                      42                (2)               44            

**

Equity earnings in unconsolidated entities                                                            97                88                 9                 10  %

Interest expense, net                                                                               (107)             (107)                -                  -  %
Other expense, net                                                                                   (37)              (60)               23                 38  %
Income tax expense                                                                                   (21)              (24)                3                 13  %
Net income                                                                                           225               423              (198)               (47) %
Net income attributable to noncontrolling
interests                                                                                            (38)               (1)              (37)           

**

Net income attributable to PAA                                                                  $    187          $    422          $   (235)           

(56) %


Basic and diluted net income per common unit                                                    $   0.19          $   0.51          $  (0.32)           

**


Basic and diluted weighted average common units
outstanding                                                                                          705               722               (17)                   **




**  Indicates that variance as a percentage is not meaningful.


Revenues and Purchases


Fluctuations in our consolidated revenues and purchases and related costs are
primarily associated with our merchant activities and generally explained in
large part by changes in commodity prices. Our crude oil and NGL merchant
activities 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. Both product sales revenues and purchases and related costs will
fluctuate with market prices; however, the absolute margins related to those
sales and purchases will not necessarily have a corresponding increase or
decrease. Additionally, product sales revenues include the impact of gains and
losses related to derivative instruments used to manage our exposure to
commodity price risk associated with such sales and purchases.

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       Average
              Three Months Ended March 31, 2022   $   76      $ 124      $     95
              Three Months Ended March 31, 2021   $   48      $  66      $     58



Product sales revenues and purchases increased for the three months ended March
31, 2022, compared to the same period in 2021 primarily due to higher prices and
volumes in the 2022 period.

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Revenues from services increased for the three months ended March 31, 2022,
compared to the same period in 2021 primarily due to higher prices and volumes
in the 2022 period, partially offset by the impact of the sale of our natural
gas storage facilities in the third quarter of 2021.

See further discussion of our net revenues in the "-Analysis of Operating Segments" section below.

Field Operating Costs

See discussion of field operating costs in the "-Analysis of Operating Segments" section below.

General and Administrative Expenses


The increase in general and administrative expenses for the three months ended
March 31, 2022 compared to the same period in 2021 was primarily due to (i)
costs associated with the formation of the Permian JV, a portion of which are
transition related, (ii) employee related costs, including an increase in
equity-indexed compensation expense on equity-classified awards (which is
excluded in the calculation of Adjusted EBITDA and Segment Adjusted EBITDA) due
to changes in plan assumptions, and (iii) higher office rent due to a cost
abatement in the prior year.

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

During the first quarter of 2022, we recognized a gain of $40 million related to the sale of land and buildings in California.

Depreciation and Amortization


The increase in depreciation and amortization expense for the three months ended
March 31, 2022 compared to the same period in 2021 was driven by depreciation
expense on the assets contributed by Oryx Midstream Holdings LLC ("Oryx
Midstream") upon formation of the Permian JV.

Other Expense, Net


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

                                                                                  Three Months Ended
                                                                                       March 31,
                                                                                             2022               2021

Loss related to mark-to-market adjustment of Preferred Distribution Rate Reset Option (1)

                                                                    $     (44)         $     (67)
Net gain on foreign currency revaluation (2)                                                     7                  7

                                                                                         $     (37)         $     (60)



(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.


Noncontrolling Interests

The increase in amounts attributable to noncontrolling interests for the three
months ended March 31, 2022 compared to the same period in 2021 was primarily
due to the formation of the Permian JV in October 2021. See Note 7 to our
Consolidated Financial Statements included in Part IV of our 2021 Annual Report
on Form 10-K for additional information.

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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 Adjusted EBITDA, Adjusted EBITDA
attributable to PAA, Implied distributable cash flow ("DCF"), Free Cash Flow and
Free Cash Flow after Distributions.

Adjusted EBITDA is defined as 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. Our definition and calculation of certain non-GAAP financial
measures may not be comparable to similarly-titled measures of other companies.
Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF are
reconciled to Net Income, 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, Adjusted EBITDA
attributable to PAA 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 either related to investing
activities (such as the purchase of linefill) or purchases of long-term
inventory, 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.
We also adjust for amounts billed by our equity method investees related to
deficiencies under minimum volume commitments. 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, Adjusted EBITDA attributable to PAA and
Implied DCF from Net Income (in millions):

                                                                           Three Months Ended
                                                                               March 31,                      Variance
                                                                                                        2022             2021              $                 %

Net income                                                                                           $   225          $   423          $  (198)              (47) %
Interest expense, net                                                                                    107              107                -                 -  %
Income tax expense                                                                                        21               24               (3)              (13) %
Depreciation and amortization                                                                            230              177               53                30  %
(Gains)/losses on asset sales and asset
impairments, net                                                                                         (42)               2              (44)         

**


Depreciation and amortization of unconsolidated
entities (1)                                                                                              20               20                -                 -  %
Selected Items Impacting Comparability:
(Gains)/losses from derivative activities and
inventory valuation adjustments                                                                           88             (198)             286          

**

Long-term inventory costing adjustments                                                                  (92)             (41)             (51)         

**

Deficiencies under minimum volume commitments,
net                                                                                                        6              (32)              38          

**

Equity-indexed compensation expense                                                                        7                5                2          

**

Net gain on foreign currency revaluation                                                                  (2)              (1)              (1)                  **
Line 901 incident                                                                                         85                -               85                   **

Selected Items Impacting Comparability - Segment
Adjusted EBITDA (2)                                                                                       92             (267)             359          

**

Losses from derivative activities (3)                                                                     44               67              (23)         

**

Net gain on foreign currency revaluation (4)                                                              (7)              (7)               -          

**


Selected Items Impacting Comparability - Adjusted
EBITDA (5)                                                                                               129             (207)             336                   **
Adjusted EBITDA (5)                                                                                  $   690          $   546          $   144                26  %
Adjusted EBITDA attributable to noncontrolling
interests (6)                                                                                            (76)              (3)             (73)         

**

Adjusted EBITDA attributable to PAA                                                                  $   614          $   543          $    71                13  %

Adjusted EBITDA (5)                                                                                  $   690          $   546          $   144                26  %
Interest expense, net of certain non-cash items
(7)                                                                                                     (101)            (101)               -                 -  %
Maintenance capital (8)                                                                                  (27)             (35)               8                23  %
Investment capital of noncontrolling interests
(9)                                                                                                      (15)               -              (15)                 N/A
Current income tax expense                                                                               (19)              (1)             (18)                  **
Distributions from unconsolidated entities in
excess of/(less than) adjusted equity earnings
(10)                                                                                                     (31)               5              (36)         

**

Distributions to noncontrolling interests (11)                                                           (59)              (6)             (53)                  **
Implied DCF                                                                                          $   438          $   408          $    30                 7  %
Preferred unit distributions (11)                                                                        (37)             (37)               -                 -  %
Implied DCF Available to Common Unitholders                                                          $   401          $   371          $    30                 8  %
Common unit cash distributions (11)                                                                     (127)            (130)
Implied DCF Excess (12)                                                                              $   274          $   241




**  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.

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(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)Other 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.

(6)Reflects amounts attributable to noncontrolling interests in the Permian JV and Red River LLC.

(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)Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders.


(10)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).

(11)Cash distributions paid during the period presented.

(12)Excess DCF is retained to establish reserves for debt repayment, future distributions, common unit repurchases, capital expenditures and other partnership purposes.

Analysis of Operating Segments


We manage our operations through two operating segments: Crude Oil and NGL. Our
CODM (our Chief Executive Officer) evaluates segment performance based on a
variety of measures including Segment Adjusted EBITDA, segment volumes and
maintenance capital investment. See Note 11 to our Condensed Consolidated
Financial Statements for our definition of Segment Adjusted EBITDA and a
reconciliation of Segment Adjusted EBITDA to Net income attributable to PAA. See
Note 20 to our Consolidated Financial Statements included in Part IV of our 2021
Annual Report on Form 10-K for our definition of maintenance capital.

Crude Oil Segment


Our Crude Oil segment operations generally consist of gathering and transporting
crude oil using pipelines, gathering systems, trucks and at times on barges or
railcars, in addition to providing terminalling, storage and other
facilities-related services utilizing our integrated assets across the United
States and Canada. Our assets serve third parties and are also supported by our
merchant activities. Our merchant activities include the purchase of crude oil
supply and the movement of this supply on primarily our assets to sales
locations, including our terminals, third-party connecting carriers, regional
hubs or to refineries. Our merchant activities are subject to our risk
management policies and may include the use of derivative instruments to hedge
our exposure.

Our Crude Oil segment generates revenue through a combination of tariffs,
pipeline capacity agreements and other transportation fees, month-to-month and
multi-year storage and terminalling agreements and the sale of gathered and
bulk-purchased crude oil. Tariffs and other fees on our pipeline systems are
typically based on volumes transported and vary by receipt point and delivery
point. Fees for our terminalling and storage services are based on capacity
leases and throughput volumes. Generally, results from our merchant activities
are impacted by (i) increases or decreases in our lease gathering crude
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oil purchases volumes and (ii) the overall strength, weakness and volatility of
market conditions, including regional differentials and time spreads. In
addition, the execution of our risk management strategies in conjunction with
our assets can provide upside in certain markets. The segment results also
include the direct fixed and variable field costs of operating the crude oil
assets, as well as an allocation of indirect operating costs.

The following tables set forth our operating results from our Crude Oil segment:

                                                                          Three Months Ended
Operating Results (1)                                                         March 31,                       Variance
(in millions)                                                                                          2022              2021              $                 %
Revenues                                                                                            $ 13,079          $ 7,853          $ 5,226                 67  %
Purchases and related costs                                                                          (12,393)          (7,047)          (5,346)               (76) %
Field operating costs                                                                                   (282)            (165)            (117)               (71) %
Segment general and administrative expenses (2)                                                          (63)             (50)             (13)               (26) %
Equity earnings in unconsolidated entities                                                                97               88                9          

10 %


Adjustments (3):
Depreciation and amortization of unconsolidated
entities                                                                                                  20               20                -                  -  %
(Gains)/losses from derivative activities and
inventory valuation adjustments                                                                           59             (159)             218                137  %
Long-term inventory costing adjustments                                                                  (85)             (35)             (50)              (143) %
Deficiencies under minimum volume commitments,
net                                                                                                        6              (32)              38                119  %
Equity-indexed compensation expense                                                                        7                5                2                 40  %
Net gain on foreign currency revaluation                                                                  (1)              (1)               -                  -  %
Line 901 incident                                                                                         85                -               85                   N/A

Adjusted EBITDA attributable to noncontrolling
interests                                                                                                (76)              (3)             (73)                   **
Segment Adjusted EBITDA                                                                             $    453          $   474          $   (21)                (4) %

Maintenance capital                                                                                 $     19          $    28          $    (9)               (32) %



                                                                     Three Months Ended
                                                                         March 31,                         Variance
Average Volumes                                                                                    2022                2021              Volumes        

%

Tariff activities volumes (4)
Crude oil pipelines tariff volumes (by
region):
Permian Basin (5)                                                                                   5,214              3,753              1,461                  39  %
South Texas / Eagle Ford (5)                                                                          365                320                 45                  14  %
Mid-Continent (5)                                                                                     472                373                 99                  27  %
Gulf Coast                                                                                            196                145                 51                  35  %
Rocky Mountain (5)                                                                                    346                287                 59                  21  %
Western                                                                                               235                237                 (2)                 (1) %
Canada                                                                                                331                315                 16                   5  %
Crude oil pipelines tariff activities total
volumes                                                                                             7,159              5,430              1,729         

32 %


Commercial crude oil storage capacity (5)
(6)                                                                                                    72                 73                 (1)        

(1) %


Crude oil lease gathering purchases (4)                                                             1,361              1,174                187                  16  %




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** 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 in thousands of barrels per day calculated as the total
volumes (attributable to our interest for pipelines owned by unconsolidated
entities or undivided joint interests) for the year divided by the number of
days in the year. Volumes associated with acquisitions represent total volumes
for the number of days we actually owned the assets divided by the number of
days in the period.

(5)Includes volumes (attributable to our interest) from assets owned by unconsolidated entities.

(6)Average monthly capacity in millions of barrels per day calculated as total volumes for the period divided by the number of months in the period.

Segment Adjusted EBITDA


Crude Oil Segment Adjusted EBITDA decreased for the three months ended March 31,
2022 compared to the same period in 2021 primarily due to (i) the sale of our
natural gas storage facilities in August of 2021 and (ii) gains related to
hedged power costs resulting from Winter Storm Uri recognized in the first
quarter of 2021. These items were partially offset by increased earnings in the
first quarter of 2022 from higher tariff volumes on our pipelines.

Variances in the components impacting Segment Adjusted EBITDA are discussed in more detail below.


Revenues, Net of Purchases and Related Costs ("net revenues") and Equity
Earnings in Unconsolidated Entities. The following is a discussion of the
significant factors impacting net revenues and equity earnings in unconsolidated
entities that contributed to the variance in Segment Adjusted EBITDA for the
first quarter of 2022 compared to the first quarter of 2021.

•Production and Market Impacts. Since the trough in demand for crude oil in 2020
related to the COVID-19 pandemic, we have seen steady growth in our volumes,
commensurate with the growth in total U.S. crude oil production, resulting in a
favorable impact on our earnings in the first quarter of 2022 compared to the
first quarter of 2021. This was partially offset by the impact of less favorable
crude oil differentials, including contango profits that benefited the 2021
period.

•Joint Venture Formation and Divestiture Transactions. In October of 2021, we
closed on the transaction with Oryx Midstream to merge our respective Permian
Basin assets, with the exception of our long-haul pipeline systems and certain
of our intra-basin assets into the Permian JV. The pipelines contributed by Oryx
Midstream upon formation of the Permian JV resulted in approximately 640
thousand barrels per day of additional tariff volumes in the Permian Basin in
the first quarter of 2022. We deduct the portion of the financial results
attributable to Oryx Midstream's 35% interest in the Permian JV in determining
Segment Adjusted EBITDA, which offset the favorable impact of the additional
volumes for the first quarter of 2022.

We sold our natural gas storage facilities in August 2021, which was a
significant driver of the decrease in our results for the first quarter of 2022
compared to the first quarter of 2021 as net revenues from our natural gas
storage facilities in the first quarter of 2021 were approximately $42 million,
which included the benefit of favorable margins from hub activities related to
Winter Storm Uri, as mentioned below.

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•Winter Storm Uri. During the first quarter of 2021, Winter Storm Uri had a
negative impact on our volumes; however, this impact was more than offset during
the 2021 period by gains related to hedged power costs, which are reflected in
equity earnings and field operating costs, and favorable margins from hub
activities at our natural gas storage facilities resulting from Winter Storm
Uri.

•Pipeline Loss Allowance Revenue. Pipeline loss allowance revenues increased for
the three months ended March 31, 2022 compared to the three months ended March
31, 2021 primarily due to higher prices and volumes during the 2022 period.

•Minimum Volume Commitments. For the three months ended March 31, 2022 and 2021,
Segment Adjusted EBITDA includes approximately $43 million and $26 million,
respectively, associated with deficiencies under minimum volume commitments
under contracts that have make-up rights. Although the payments have been
received associated with the volume deficiencies, the revenues are not
recognized until future periods when either the shortfall is made up or when the
shipper's make-up rights expire or it is determined that their ability to
utilize the make-up right is remote. During the three months ended March 31,
2022 and 2021, we recognized approximately $37 million and $58 million,
respectively, associated with deficiencies under minimum volume commitments that
were previously deferred. The amount presented as an "Adjustment" in the table
above reflects the net adjustment for revenues deferred during the period and
the reversal of previously deferred revenues that were recognized during the
period.

•Project Completions. The Capline pipeline reversal project and phase two of the
Wink to Webster pipeline project have been completed and were placed in service
in the first quarter of 2022, which favorably impacted equity earnings in
unconsolidated entities and our tariff volumes for the 2022 period.

Field Operating Costs. The increase in field operating costs for the three months ended March 31, 2022 compared to the same period in 2021 was primarily due to (i) the impact of gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021, (ii) additional estimated costs associated with the Line 901 incident (which impact field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an "Adjustment" in the table above), and (iii) incremental operating costs from the Permian JV.

Segment General and Administrative Expenses. See the "-Consolidated Results" section above for a discussion of general and administrative expenses.


Maintenance Capital. The decrease in maintenance capital spending for the three
months ended March 31, 2022 compared to the same period in 2021 was primarily
due to timing.

NGL Segment

Our NGL segment operations involve natural gas processing and NGL fractionation,
storage, transportation and terminalling. Our NGL revenues are primarily derived
from a combination of (i) providing gathering, fractionation, storage, and/or
terminalling services to third-party customers for a fee, and (ii) extracting
NGL mix supply from the gas stream processed at our Empress straddle plant
facility as well as acquiring NGL mix supply, which mix supply is then
transported, stored and fractionated into finished products and sold to
customers.
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The following tables set forth our operating results from our NGL segment:


                                                                                      Three Months Ended
Operating Results (1)                                                                     March 31,                      Variance
(in millions, except per barrel data)                                                                              2022             2021              $                 %
Revenues                                                                                                        $   735          $   639          $    96                15  %
Purchases and related costs                                                                                        (512)            (454)             (58)              (13) %
Field operating costs                                                                                               (64)             (54)             (10)              (19) %
Segment general and administrative expenses (2)                                                                     (19)             (17)              (2)              (12) %

Adjustments (3): (Gains)/losses from derivative activities and inventory valuation adjustments

                                                                                                29              (39)              68               174  %
Long-term inventory costing adjustments                                                                              (7)              (6)              (1)              (17) %

Net gain on foreign currency revaluation                                                                             (1)               -               (1)                 N/A
Segment Adjusted EBITDA                                                                                         $   161          $    69          $    92               133  %

Maintenance capital                                                                                             $     8          $     7          $     1                14  %



                                                                          Three Months Ended
                                                                              March 31,                        Variance
Average Volumes (in thousands of barrels per
day) (4)                                                                                                2022              2021              Volumes                %
NGL fractionation                                                                                         134               144                (10)                 (7) %

NGL pipeline tariff                                                                                       176               183                 (7)                 (4) %

NGL sales                                                                                                 168               220                (52)                (24) %



** 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 total volumes (attributable to our interest for pipelines and facilities in which we have undivided joint interests) for the period divided by the number of days in the period.

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Segment Adjusted EBITDA

NGL Segment Adjusted EBITDA increased for the three months ended March 31, 2022
compared to the same period in 2021 primarily due to the favorable impact of
higher realized fractionation spreads between the price of natural gas and the
extracted NGL ("frac spreads") and higher NGL sales prices, partially offset by
lower NGL sales volumes.

Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below.


Net Revenues. Net revenues from our NGL activities increased for the three
months ended March 31, 2022 compared to the same period in 2021 due to higher
realized frac spreads and higher NGL sales prices, partially offset by lower NGL
sales volumes. Additionally, net revenues for the 2022 period compared to 2021
include the benefit of our increased ownership in the Empress straddle plants
effective June 2021.

Field Operating Costs. The increase in field operating costs for the three
months ended March 31, 2022 compared to the same period in 2021 was primarily
due to (i) increased power costs related to our increased ownership in the
Empress straddle plants and (ii) higher compensation costs including lower wage
subsidies received by our Canadian subsidiary.

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 asset sales, and in the past 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 March 31, 2022, although we had a working capital deficit of $473 million,
we had approximately $2.4 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
                                                                                   March 31, 2022
Availability under senior unsecured revolving credit facility (1) (2)             $        1,321
Availability under senior secured hedged inventory facility (1) (2)                        1,345
Amounts outstanding under commercial paper program                                          (382)
Subtotal                                                                                   2,284
Cash and cash equivalents                                                                    114
Total                                                                             $        2,398



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


(2)Available capacity under our senior unsecured revolving credit facility and
senior secured hedged inventory facility was reduced by outstanding letters of
credit of $29 million and $5 million, respectively.

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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 March 31, 2022.

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 2021 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 provided by/(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, net of proceeds from the sales of assets and
further impacted by distributions to and contributions from 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.

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
                                                                              March 31,
                                                                                    2022              2021
Net cash provided by operating activities                                        $    340          $    791
Adjustments to reconcile net cash provided by operating activities
to free cash flow:
Net cash used in investing activities                                                 (81)             (108)
Cash contributions from noncontrolling interests                                        -                 1
Cash distributions paid to noncontrolling interests (1)                               (59)               (6)

Free Cash Flow                                                                   $    200          $    678
Cash distributions (2)                                                               (164)             (167)
Free Cash Flow after Distributions                                               $     36          $    511



(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 2021 Annual Report on Form 10-K.

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Net cash provided by operating activities for the first three months of 2022 and
2021 was $340 million and $791 million, respectively, and primarily resulted
from earnings from our operations. During the three months ended March 31, 2022,
our cash provided by operating activities was negatively impacted by working
capital changes. During the three months ended March 31, 2021, our cash provided
by operating activities was positively impacted by working capital changes,
including decreases in the volume of inventory that we held, primarily due to
the sale of crude oil inventory that had been stored during the contango market
and the sale of NGL inventory related to demand for heating during the winter
season. The net proceeds from the liquidation of such inventory were used to
repay borrowings under our commercial paper program and credit facilities.

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 asset sales. 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):

                                                  Three Months Ended
                                                       March 31,
                                                    2022             2021
               Investment capital (1) (2)   $      109              $  85
               Maintenance capital (1)              27                 35

                                            $      136              $ 120




(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.



2022 Investment and Maintenance Capital. Total investment capital for the year
ended December 31, 2022 is projected to be approximately $330 million ($275
million net to our interest). Approximately half of our projected investment
capital expenditures are expected to be invested in the Permian JV assets.
Additionally, maintenance capital for the full year of 2022 is projected to be
$220 million ($210 million net to our interest). We expect to fund our 2022
investment and maintenance capital expenditures primarily with retained cash
flow.

Divestitures

Proceeds from the sale of assets have generally been used to fund our investment
capital projects and reduce debt levels. The following table summarizes the
proceeds received during the first three months of 2022 and 2021 from sales of
assets (in millions):

                                                        Three Months Ended
                                                            March 31,
                                                          2022              2021
             Proceeds from divestitures (1)      $       53                $ 21



(1)Represents proceeds, including working capital adjustments, net of transaction costs.

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Ongoing Activities Related to Strategic Transactions

We are continuously engaged in the evaluation of potential transactions that
support our current business strategy. In the past, such transactions have
included the sale on non-core assets, the sale of partial interests in assets to
strategic joint venture partners, acquisitions and large investment capital
projects. With respect to a potential divestiture or acquisition, we may conduct
an auction process or participate in an auction process conducted by a third
party or we may negotiate a transaction with one or a limited number of
potential buyers (in the case of a divestiture) or sellers (in the case of an
acquisition). Such transactions 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. 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 and acquisitions involve risks that may adversely affect
our business" included in our 2021 Annual Report on Form 10-K.

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 three months ended March 31, 2022, we had net borrowings on our credit facilities and commercial paper program of $382 million. The net borrowings resulted primarily from borrowings during the period related to funding needs for capital investments, inventory purchases, senior notes repayments and other general partnership purposes, partially offset by cash flow from operating activities and proceeds from asset sales.


During the three months ended March 31, 2021, we had net repayments on our
credit facilities and commercial paper program of $576 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.

Repayment of Senior Notes

During the three months ended March 31, 2022, we redeemed our 3.65%, $750 million senior notes due June 2022. We utilized cash on hand and borrowings under our commercial paper program to repay these senior notes.

Common Equity Repurchase Program


We repurchased 2.4 million and 0.4 million common units under the Program
through open market purchases that settled during the three months ended March
31, 2022 and 2021, respectively, for a total purchase price of $25 million and
$3 million, respectively, including commissions and fees. At March 31, 2022, the
remaining available capacity under the Program was $247 million.
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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 March 31, 2022. 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 three months ended March 31,
2022.

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 2021 Annual Report
on Form 10-K for additional discussion.

On May 13, 2022, we will pay a quarterly cash distribution of $0.2175 per common
unit ($0.87 per unit on an annualized basis) to unitholders of record at the
close of business on April 29, 2022 for the period from January 1, 2022 through
March 31, 2022, which represents a $0.0375 per unit increase from the
distribution paid in February 2022.

See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first three months of 2022, including distributions to our preferred unitholders.

Distributions to Noncontrolling Interests


Distributions to noncontrolling interests represent amounts paid on interests in
consolidated entities that are not owned by us. As of March 31, 2022,
noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in
the Permian JV and (ii) a 33% interest in Red River LLC. See Note 7 to our
Condensed Consolidated Financial Statements for details of distributions paid to
noncontrolling interests during the three months ended March 31, 2022.

Contingencies

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

Commitments


Purchase 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. 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 March 31, 2022 (in millions):

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                                    Remainder of                                                                                   2027 and
                                        2022               2023              2024              2025              2026             Thereafter             Total
Crude oil, NGL and other purchases
(1)                                 $   23,259          $ 26,253          $ 25,271          $ 24,414          $ 23,148          $     72,905          $ 195,250




(1)Amounts are primarily based on estimated volumes and market prices based on
average activity during March 2022. 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.


Letters of Credit. In connection with merchant 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 March 31, 2022 and December 31, 2021, we had
outstanding letters of credit of approximately $34 million and $98 million,
respectively.

Recent Accounting Pronouncements

See Note 2 to our Condensed Consolidated Financial Statements.

                           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 and natural gas liquids
("NGL") 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 downward pressure on rates and margins, 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);


•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, the risk of persistently high inflation and continued
supply chain issues, the impact of coronavirus variants on demand and growth,
and the timing, pace and extent of economic recovery) that impact (i) demand for
crude oil, drilling and production activities and therefore the demand for the
midstream services we provide and (ii) commercial opportunities available to us;

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•the impact of current and future laws, rulings, governmental regulations,
executive orders, trade policies, accounting standards and statements, and
related interpretations, including legislation, executive orders or regulatory
initiatives that arise out of pandemic related concerns 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;

•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;

•loss of key personnel and inability to attract and retain new talent;


•fluctuations in refinery capacity in areas supplied by our mainlines and other
factors affecting demand for various grades of crude oil and NGL and resulting
changes in pricing conditions or transportation throughput requirements;

•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;

•the availability of, and our ability to consummate, divestitures, joint ventures, acquisitions or other strategic opportunities;

•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;

•significant under-utilization of our assets and facilities;


•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, supply chain issues, legal
constraints (including governmental orders or guidance), or other factors or
events;

•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;


•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;

•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;

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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 2021 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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