PLAINS ALL AMERICAN PIPELINE, L.P. 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 inNorth America , we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins and transportation corridors and at major market hubs inthe United States andCanada . 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 nine months of 2022, we recognized net income attributable to PAA of$774 million compared to net income attributable to PAA of$143 million recognized during the first nine months of 2021. Results from our operations increased for the first nine months of 2022 over the comparable 2021 period driven primarily by more favorable margins in our NGL segment, as well as increased earnings from our crude oil pipelines due to higher tariff volumes and higher loss allowance revenue attributable to higher commodity prices. However, these items were partially offset by the impact of the monetization of contango hedges that benefited the 2021 period, the sale of our natural gas storage facilities in the third quarter of 2021 and higher field operating costs in the 2022 period 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 inFebruary 2021 ("Winter Storm Uri") recognized in the first quarter of 2021. Additionally, results for the first nine months of 2022 included a net gain on asset sales of$46 million , compared to a net loss on asset sales and asset impairments of$592 million included in results for the first nine months of 2021. 35 -------------------------------------------------------------------------------- Table of Contents See the "Results of Operations" section below for further discussion.
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 Nine Months Ended
September 30, Variance September 30, Variance
2022 2021 $ % 2022 2021 $ %
Product sales revenues $ 14,001 $ 10,515 $ 3,486 33 % $ 43,390 $ 28,221 $ 15,169 54 %
Services revenues 335 261 74 28 % 1,000 868 132 15 %
Purchases and related costs (13,071) (10,074) (2,997) (30) % (41,181) (26,743) (14,438) (54) %
Field operating costs (318) (274) (44) (16) % (971) (746) (225) (30) %
General and administrative expenses (83) (67) (16) (24) % (243) (205) (38) (19) %
Depreciation and amortization (238) (178) (60) (34) % (711) (551) (160) (29) %
Gains/(losses) on asset sales and asset
impairments, net - (221) 221 100 % 46 (592) 638 108 %
Equity earnings in unconsolidated
entities 105 69 36 52 % 306 190 116 61 %
Gain on investment in unconsolidated
entities 1 - 1 N/A 1 - 1 N/A
Interest expense, net (99) (106) 7 7 % (305) (319) 14 4 %
Other income/(expense), net (82) (10) (72) ** (237) 13 (250) **
Income tax (expense)/benefit (109) 30 (139) ** (177) 16 (193) **
Net income/(loss) 442 (55) 497 ** 918 152 766 **
Net income attributable to
noncontrolling interests (58) (4) (54) ** (144) (9) (135) **
Net income/(loss) attributable to PAA
$ 443 **$ 774 $ 143 $ 631 441 % Basic and diluted net income/(loss) per common unit$ 0.48 $ (0.15) $ 0.63 **$ 0.89 $ (0.01) $ 0.90 ** Basic and diluted weighted average common units outstanding 698 715 (17) ** 702 719 (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.
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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 September 30, 2022 $ 77 $ 108 $ 91
Three Months Ended September 30, 2021 $ 62 $ 75 $ 71
Nine Months Ended September 30, 2022 $ 76 $ 124 $ 98
Nine Months Ended September 30, 2021 $ 48 $ 75 $ 65
Product sales revenues and purchases increased for the three and nine months
ended September 30, 2022 , compared to the same periods in 2021 primarily due to
higher prices and volumes in the 2022 periods.
Revenues from services increased for the three and nine months ended
September 30, 2022 , compared to the same periods in 2021 primarily due to higher
prices and volumes in the 2022 periods, 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 and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was primarily due to (i) 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) and liability-classified awards due to changes in plan assumptions and a higher common unit price and (ii) higher office rent due to an operating cost abatement in the prior year. For the nine months endedSeptember 30, 2022 , the increase was also attributed to (i) costs associated with the formation of the Permian JV, a portion of which are related to the provision of transition services, and (ii) reduced wage subsidies received by our Canadian subsidiary.
Gains/(Losses) on Asset Sales and Asset Impairments, Net
During the first quarter of 2022, we recognized a gain of
The net loss on asset sales and asset impairments for 2021 primarily consisted of (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 ourPine Prairie and Southern Pines natural gas storage facilities upon classification as held for sale during the second quarter (these assets were sold inAugust 2021 ) and (iii) a gain of$106 million recognized in the second quarter related to the asset exchange agreement (the "Asset Exchange") involving the sale of one of our crude oil pipelines inCanada in exchange for additional interests in certain Empress natural gas processing plants.
Depreciation and Amortization
The increase in depreciation and amortization expense for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was driven by depreciation expense on the assets contributed byOryx Midstream Holdings LLC ("Oryx Midstream") upon formation of the Permian JV. 37 -------------------------------------------------------------------------------- Table of Contents Interest Expense, Net The decrease in interest expense for the three and nine months endedSeptember 30, 2022 compared to the three and nine months endedSeptember 30, 2021 was primarily due to (i) a lower weighted average debt balance during the 2022 periods largely driven by the repayment of$750 million of senior notes inMarch 2022 and (ii) gains of$2 million and$6 million recognized during the three and nine months endedSeptember 30, 2022 , respectively, due to anticipated hedged transactions being probable of not occurring. These decreases were partially offset by lower capitalized interest in the 2022 periods resulting from fewer capital projects under construction.
Other Income/(Expense), Net
The following table summarizes the components impacting Other income/(expense),
net (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
2022 2021 2022 2021Gain/(loss) related to mark-to-market adjustment of Preferred Distribution Rate Reset Option (1)
$ (49)
(34) (15) (43) (1)
Other 1 1 2 1
$ (82) $ (10) $ (237) $ 13 (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 inthe 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 unfavorable income tax variance for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was primarily a result of higher year-over-year income as impacted by fluctuations of the derivative mark-to-market valuations in our Canadian operations.
Noncontrolling Interests
The increase in amounts attributable to noncontrolling interests for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was primarily due to the formation of the Permian JV inOctober 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.
Outlook for Certain Idled and Underutilized Assets
During the third quarter of 2022, we temporarily ceased service on Line 2000 inCalifornia as a precautionary measure following a routine inspection and initiated a program of additional tests and inspections. We are in the process of assessing the results of such tests; however, possible outcomes could include a reduction in the remaining useful life of the pipeline and/or a partial impairment of the carrying value of the associated asset group, which was approximately$540 million , exclusive of linefill, as ofSeptember 30, 2022 . 38 -------------------------------------------------------------------------------- Table of Contents 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 Nine Months Ended
September 30, Variance September 30, Variance
2022 2021 $ % 2022 2021 $ %
Net income/(loss) $ 442 $ (55) $ 497 ** $ 918 $ 152 $ 766 **
Interest expense, net 99 106 (7) (7) % 305 319 (14) (4) %
Income tax expense/(benefit) 109 (30) 139 ** 177 (16) 193 **
Depreciation and amortization 238 178 60 34 % 711 551 160 29 %
(Gains)/losses on asset sales and asset
impairments, net - 221 (221) (100) % (46) 592 (638) (108) %
Gain on investment in unconsolidated
entities (1) - (1) N/A (1) - (1) N/A
Depreciation and amortization of
unconsolidated entities (1) 21 21 - - % 58 109 (51) (47) %
Selected Items Impacting Comparability:
(Gains)/losses from derivative
activities and inventory valuation
adjustments (376) 13 (389) ** (363) (23) (340) **
Long-term inventory costing adjustments 83 (13) 96 ** (22) (81) 59 **
Deficiencies under minimum volume
commitments, net 16 56 (40) ** 31 31 - **
Equity-indexed compensation expense 9 6 3 ** 24 14 10 **
Net (gain)/loss on foreign currency
revaluation (2) 3 (5) ** (1) 2 (3) **
Line 901 incident - - - ** 85 - 85 **
Significant transaction-related expenses - 2 (2) ** - 5 (5) **
Selected Items Impacting Comparability -
Segment Adjusted EBITDA (2) (270) 67 (337) ** (246) (52) (194) **
(Gain)/loss on Preferred Distribution
Rate Reset Option embedded derivative
(3) 49 (4) 53 ** 196 (13) 209 **
Net loss on foreign currency revaluation
(4) 34 15 19 ** 43 1 42 **
Selected Items Impacting Comparability -
Adjusted EBITDA (5) (187) 78 (265) ** (7) (64) 57 **
Adjusted EBITDA (5) $ 721 $ 519 $ 202 39 % $ 2,115 $ 1,643 $ 472 29 %
Adjusted EBITDA attributable to
noncontrolling interests (6) (98) (5) (93) ** (264) (12) (252) **
Adjusted EBITDA attributable to PAA $ 623 $ 514 $ 109 21 % $ 1,851 $ 1,631 $ 220 13 %
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Three Months Ended Nine Months Ended
September 30, Variance September 30, Variance
2022 2021 $ % 2022 2021 $ %
Adjusted EBITDA (5) $ 721 $ 519 $ 202 39 % $ 2,115 $ 1,643 $ 472 29 %
Interest expense, net of certain
non-cash items (7) (96) (99) 3 3 % (295) (301) 6 2 %
Maintenance capital (8) (76) (43) (33) (77) % (146) (116) (30) (26) %
Investment capital of
noncontrolling interests (9) (20) - (20) N/A (50) - (50) N/A
Current income tax expense (12) (8) (4) (50) % (60) (11) (49) (445) %
Distributions from unconsolidated
entities in excess of/(less than)
adjusted equity earnings (10) (22) 9 (31) ** (48) 11 (59) **
Distributions to noncontrolling
interests (11) (73) (4) (69) ** (194) (10) (184) **
Implied DCF $ 422 $ 374 $ 48 13 % $ 1,322 $ 1,216 $ 106 9 %
Preferred unit distributions (11) (37) (37) - - % (137) (137) - - %
Implied DCF Available to Common
Unitholders $ 385 $ 337 $ 48 14 % $ 1,185 $ 1,079 $ 106 10 %
Common unit cash distributions (11) (152) (129) (432) (389)
Implied DCF Excess (12) $ 233 $ 208 $ 753 $ 690
** 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)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.
(6)Reflects amounts attributable to noncontrolling interests in the
(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).
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(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 acrossthe United States andCanada . 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 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. 42
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The following tables set forth our operating results from our Crude Oil segment:
Three Months Ended Nine Months Ended
Operating Results (1) September 30, Variance September 30, Variance
(in millions) 2022 2021 $ % 2022 2021 $ %
Revenues $ 13,675 $ 10,701 $ 2,974 28 % $ 42,694 $ 28,333 $ 14,361 51 %
Purchases and related costs (12,938) (9,971) (2,967) (30) % (40,495) (26,146) (14,349) (55) %
Field operating costs (235) (213) (22) (10) % (749) (582) (167) (29) %
Segment general and administrative
expenses (2) (64) (49) (15) (31) % (186) (151) (35) (23) %
Equity earnings in unconsolidated
entities 105 69 36 52 % 306 190 116 61 %
Adjustments (3):
Depreciation and amortization of
unconsolidated entities 21 21 - - % 58 109 (51) **
(Gains)/losses from derivative
activities and inventory valuation
adjustments (33) (158) 125 ** (3) (242) 239 **
Long-term inventory costing
adjustments 80 (3) 83 ** (18) (65) 47 **
Deficiencies under minimum volume
commitments, net 16 56 (40) ** 31 31 - **
Equity-indexed compensation
expense 9 6 3 ** 24 14 10 **
Net (gain)/loss on foreign
currency revaluation (2) 3 (5) ** (1) 2 (3) **
Line 901 incident - - - ** 85 - 85 **
Significant transaction-related
expenses - 2 (2) ** - 5 (5) **
Adjusted EBITDA attributable to
noncontrolling interests (98) (5) (93) ** (264) (12) (252) **
Segment Adjusted EBITDA $ 536 $ 459 $ 77 17 % $ 1,482 $ 1,486 $ (4) - %
Maintenance capital $ 35 $ 24 $ 11 46 % $ 80 $ 75 $ 5 7 %
Three Months Ended Nine Months Ended
September 30, Variance September 30, Variance
Average Volumes 2022 2021 Volumes % 2022 2021 Volumes %
Crude oil pipeline tariff
volumes (by region) (4)
Permian Basin (5) 5,698 4,394 1,304 30 % 5,450 4,114 1,336 32 %
Other (5) 1,883 1,768 115 7 % 1,937 1,755 182 10 %
Total crude oil pipeline
tariff volumes 7,581 6,162 1,419 23 % 7,387 5,869 1,518 26 %
Commercial crude oil
storage capacity (5)(6) 72 73 (1) (1) % 72 73 (1) (1) %
Crude oil lease gathering
purchases (4) 1,390 1,372 18 1 % 1,373 1,300 73 6 %
** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs and expenses include intersegment amounts.
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(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 assets 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 was favorably impacted for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 by higher volumes on our pipelines, favorable Canadian crude oil differentials and higher loss allowance revenue. These favorable impacts were offset for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 by (i) the monetization of contango hedges that benefited the 2021 period, (ii) the sale of our natural gas storage facilities in August of 2021 (which were reported in our Crude Oil Segment) and (iii) gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021. The following is a more detailed discussion of the significant factors impacting Segment Adjusted EBITDA for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021. •Natural Gas Storage Assets. We sold our natural gas storage facilities inAugust 2021 , impacting the comparison of our results for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 . Net revenues from our natural gas storage facilities were approximately$76 million for the nine months endedSeptember 30, 2021 , which included the benefit of favorable margins from hub activities related to Winter Storm Uri, as mentioned below. •Market Opportunities. Our results for the three months endedSeptember 30, 2022 include the impact of more favorable Canadian crude oil differentials compared to the three months endedSeptember 30, 2021 . The nine month period endedSeptember 30, 2022 benefited from favorable Canadian crude oil differentials and the sale of excess linefill in a higher crude oil price environment, however, in comparison to the nine months endedSeptember 30, 2021 , these favorable variances were offset by the benefit of the monetization of contango hedges during the nine months endedSeptember 30, 2021 . •Permian JV. In October of 2021, we closed on the transaction with Oryx Midstream to merge our respectivePermian Basin assets, with the exception of our long-haul pipeline systems and certain of our intra-basin assets, into the Permian JV. The significant year-over-year growth in our tariff volumes in thePermian Basin region was primarily from the Permian JV assets, largely due to additional volumes from the pipelines contributed by Oryx Midstream as well as increased production and new connections. 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 partially offset the favorable impact of the volume growth when comparing Segment Adjusted EBITDA for the first nine months of 2022 compared to 2021. •Pipeline Projects. TheCapline 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 first nine months of 2022. 44
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The variance in equity earnings in unconsolidated entities for the nine months endedSeptember 30, 2022 compared to the same period in 2021 was also driven by the unfavorable impact to the prior period of the recognition of our proportionate share of the write-off of costs associated with a capital project canceled during the second quarter of 2021 (which impacted equity earnings in unconsolidated entities but is excluded from Segment Adjusted EBITDA and thus is reflected as an "Adjustment" as "Depreciation and amortization of unconsolidated entities" in the table above). •Pipeline Loss Allowance Revenue. Pipeline loss allowance revenues increased for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 primarily due to higher prices and volumes during the 2022 periods. •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. •Minimum Volume Commitments. "Deficiencies under minimum volume commitments, net" in the table above is a net adjustment to (i) include in Segment Adjusted EBITDA amounts billed to counterparties during the period that are deferred and therefore not reflected in revenues or equity earnings and (ii) exclude from Segment Adjusted EBITDA amounts recognized in revenue and equity earnings during the period that were previously deferred as they were included in Segment Adjusted EBITDA when those amounts were billed. A majority of the variance in "Deficiencies under minimum volume commitments, net" for the three months endedSeptember 30, 2022 compared to the three months endedSeptember 31, 2021 relates to the recognition of previously deferred amounts, which do not have an impact on Segment Adjusted EBITDA. •Field Operating Costs. The increase in field operating costs for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was primarily due to (i) incremental operating costs from the Permian JV, (ii) increased utilities as a result of higher volumes, (iii) increased costs resulting from higher third-party trucked volumes and (iv) higher fuel prices, partially offset by (v) the sale of our natural gas storage facilities. For the nine months endedSeptember 30, 2022 , the increase compared to 2021 was also attributable to 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 the impact of gains related to hedged power costs resulting from Winter Storm Uri recognized in the first quarter of 2021.
Segment General and Administrative Expenses. See the "-Consolidated Results" section above for a discussion of general and administrative expenses.
Maintenance Capital . The increase in maintenance capital spending for the nine months endedSeptember 30, 2022 compared to the same period in 2021 was primarily due to ongoing station upgrades, integrity projects and tank maintenance, partially offset by lower costs due to the completion of certain projects. 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. 45
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The following tables set forth our operating results from our NGL segment:
Three Months Ended Nine Months Ended
Operating Results (1) September 30, Variance September 30, Variance
(in millions, except per barrel data) 2022 2021 $ % 2022 2021 $ %
Revenues $ 770 $ 166 $ 604 364 % $ 2,075 $ 1,034 $ 1,041 101 %
Purchases and related costs (242) (194) (48) (25) % (1,065) (875) (190) (22) %
Field operating costs (83) (61) (22) (36) % (222) (164) (58) (35) %
Segment general and administrative expenses (2) (19) (18) (1) (6) % (57) (54) (3) (6) %
Adjustments (3):
(Gains)/losses from derivative activities and
inventory valuation adjustments (343) 171 (514) ** (360) 219 (579) **
Long-term inventory costing adjustments 3 (10) 13 ** (4) (16) 12 **
Segment Adjusted EBITDA $ 86 $ 54 $ 32 59 % $ 367 $ 144 $ 223 155 %
Maintenance capital $ 41 $ 19 $ 22 116 % $ 66 $ 41 $ 25 61 %
Three Months Ended Nine Months Ended
September 30, Variance September 30, Variance
Average Volumes
(in thousands of barrels per day)
(4) 2022 2021 Volumes % 2022 2021 Volumes %
NGL fractionation 121 119 2 2 % 131 130 1 1 %
NGL pipeline tariff 182 165 17 10 % 182 176 6 3 %
NGL sales 96 87 9 10 % 121 139 (18) (13) %
** 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 and nine months ended
September 30, 2022 compared to the same periods 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 increased NGL mix supply
produced at our straddle plants.
Significant variances in the components of Segment Adjusted EBITDA are discussed in more detail below.
Net Revenues. Net revenues from our NGL sales activities, excluding the impact of derivative activities and inventory valuation and long-term inventory costing adjustments, increased for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 primarily due to higher realized frac spreads, increased NGL mix supply produced at our straddle plants and higher ethane prices due to higher utility operating costs at our straddle plants. This was partially offset for the nine months endedSeptember 30, 2022 compared to the nine months endedSeptember 30, 2021 by lower NGL sales volumes during the first half of 2022 due to a reduction in lower margin hub activity. Additionally, net revenues for the nine months endedSeptember 30, 2022 compared to the same period in 2021 include the benefit of our increased ownership in the Empress straddle plants effectiveJune 2021 and higher product gains at certain of our NGL fractionation facilities. Field Operating Costs. The increase in field operating costs for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was primarily due to increased utilities-related costs associated with (i) our increased ownership in the Empress straddle plants, (ii) higher prices in the 2022 periods, and (iii) a reduction in unrealized mark-to-market gains (which impact our field operating costs but are excluded from Segment Adjusted EBITDA and thus are reflected as an "Adjustment" in the table above). The increase in utilities-related costs was largely offset by the benefit to net revenues of ethane recoveries.Maintenance Capital . The increase in maintenance capital spending for the three and nine months endedSeptember 30, 2022 compared to the same periods in 2021 was primarily due to a turnaround at one of our Empress facilities during 2022.
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 and noncontrolling interests. 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
As of
September 30,
2022 Availability under senior unsecured revolving credit facility (1) (2)
$ 1,321 Availability under senior secured hedged inventory facility (1) (2) 1,321 Amounts outstanding under commercial paper program - Subtotal 2,642 Cash and cash equivalents 623 Total$ 3,265 47
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(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$29 million , respectively.
In
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 ofSeptember 30, 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 byOrganization 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.
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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,
2022 2021 2022 2021
Net cash provided by operating activities $ 941 $ 336 $ 2,074 $ 1,361
Adjustments to reconcile net cash provided by
operating activities to free cash flow:
Net cash (used in)/provided by investing
activities (168) 761 (291) 478
Cash contributions from noncontrolling
interests 26 - 26 1
Cash distributions paid to noncontrolling
interests (1) (73) (4) (194) (10)
Free Cash Flow $ 726 $ 1,093 $ 1,615 $ 1,830
Cash distributions (2) (189) (166) (569) (526)
Free Cash Flow after Distributions $ 537 $ 927 $ 1,046 $ 1,304 (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.
Net cash provided by operating activities for the first nine months of 2022 and 2021 was$2.074 billion and$1.361 billion , respectively, and primarily resulted from earnings from our operations.
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):
Nine Months Ended
September 30,
2022 2021
Investment capital (1) (2) $ 262 $ 182
Maintenance capital (1) 146 116
Acquisition capital 74 32
$ 482 $ 330
(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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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 nine months of 2022 and 2021 from sales of
assets (in millions):
Nine Months Ended
September 30,
2022 2021
Proceeds from divestitures (1) $ 58 $ 878 (1)Represents proceeds, including working capital adjustments, net of transaction costs.
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 of 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. OnNovember 2, 2022 , we completed a transaction to purchase an additional 5% interest inCactus II Pipeline LLC ("Cactus II") for approximately$88 million . Subsequent to the transaction, we own a 70% interest in Cactus II and as a result of certain amended governance provisions, we have obtained control over this entity. As a result, we will consolidate Cactus II at fair value at the date of acquisition and amendment, further resulting in a gain being recorded because of our remeasurement of our previously held equity interest.
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.
Repayment of Senior Notes
On
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Common Equity Repurchase Program
We repurchased 7.3 million and 11.9 million common units under the Program
through open market purchases that settled during the nine months ended
Registration Statements
We periodically access the capital markets for both equity and debt financing. We have filed with theSEC 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 atSeptember 30, 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 nine months endedSeptember 30, 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. OnNovember 14, 2022 , we will pay a quarterly cash distribution of $0.2175 per common unit ($0.87 per unit on an annualized basis) to common unitholders of record at the close of business onOctober 31, 2022 for the period fromJuly 1, 2022 throughSeptember 30, 2022 , which is unchanged from the distribution per unit paid in August of 2022.
See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first nine months of 2022, including distributions to our preferred unitholders.
Capital Allocation Framework Update
OnNovember 2, 2022 , we provided updates to our capital allocation framework and announced our intention to recommend to the Board of Directors a$0.20 per unit (annualized) increase to our distribution payable to holders of our common units with respect to the fourth quarter of 2022. If approved and declared by the Board of Directors, such increased distribution would be paid inFebruary 2023 .
Distributions to Noncontrolling Interests
Distributions to noncontrolling interests represent amounts paid on interests in consolidated entities that are not owned by us. As ofSeptember 30, 2022 , noncontrolling interests in our subsidiaries consisted of (i) a 35% interest in the Permian JV and (ii) a 33% interest inRed River LLC . See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid to noncontrolling interests during the nine months endedSeptember 30, 2022 .
Contingencies
For a discussion of contingencies that may impact us, see Note 10 to our Condensed Consolidated Financial Statements.
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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
Remainder of 2027 and
2022 2023 2024 2025 2026 Thereafter Total
Crude oil, NGL and other purchases
(1) $ 7,171 $ 21,129 $ 19,951 $ 18,678 $ 17,613 $ 54,686 $ 139,228
(1)Amounts are primarily based on estimated volumes and market prices based on
average activity during September 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 September 30, 2022 and December 31, 2021 , we had
outstanding letters of credit of approximately $58 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:
•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;
•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 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;
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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 and NGL and resulting
changes in pricing conditions or transportation throughput requirements;
•unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof);
•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;
•environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves;
•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 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 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;
•loss of key personnel and inability to attract and retain new talent;
•disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies;
•the effectiveness of our risk management activities;
•shortages or cost increases of supplies, materials or labor;
•maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;
•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 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;
•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;
•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;
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•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
•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;
•increased costs, or lack of availability, of insurance;
•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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