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 2020 Annual Report on Form 10-K. For more detailed information regarding the basis of presentation for the following financial information, see the Condensed Consolidated Financial Statements and related notes that are contained in Part I, Item 1 of this Quarterly Report on Form 10-Q.
Our discussion and analysis includes the following:
•Executive Summary •Results of Operations •Liquidity and Capital Resources •Off-Balance Sheet Arrangements •Recent Accounting Pronouncements •Critical Accounting Policies and Estimates •Forward-Looking Statements Executive Summary Company Overview Our business model integrates large-scale supply aggregation capabilities with the ownership and operation of critical midstream infrastructure systems that connect major producing regions to key demand centers and export terminals. As one of the largest midstream service providers inNorth America , we own an extensive network of pipeline transportation, terminalling, storage and gathering assets in key crude oil and NGL producing basins (including thePermian Basin ) 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, NGL and natural gas. Our business activities are conducted through three operating segments: Transportation, Facilities and Supply and Logistics. See "-Results of Operations-Analysis of Operating Segments" for further discussion.
Overview of Operating Results, Capital Investments and Other Significant Activities
During the first six months of 2021, we recognized net income of$207 million as compared to a net loss of$2.701 billion recognized during the first six months of 2020. The net loss for the 2020 period was primarily driven by goodwill impairment losses and non-cash impairment charges related to the write-down of certain pipeline and other long-lived assets, certain of our investments in unconsolidated entities, and assets upon classification as held for sale totaling approximately$3.24 billion . In addition, we recognized approximately$232 million of inventory valuation adjustments due to declines in commodity prices during the first quarter of 2020. The comparable six month 2021 period includes a net loss on asset sales and asset impairments of$370 million . Results from our reporting segments during the first six months of 2021 decreased from the comparable 2020 period driven primarily by the impact of less favorable crude oil market conditions combined with lower realized NGL margins in our Supply and Logistics segment. In addition, our Facilities segment was unfavorably impacted by reduced NGL capacity utilization and market rates as well as the impact of asset sales. These unfavorable results were partially offset by favorable Transportation segment results that benefited from the collection of deficiency payments associated with minimum volume commitments and lower operating costs. 36
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See further discussion of our operating results in the "-Results of Operations-Analysis of Operating Segments" and "-Other Income and Expenses" sections below.
We invested
We paid cash distributions of approximately$260 million to our common unitholders, approximately$74 million to our Series A preferred unitholders and$25 million to our Series B preferred unitholders during the six months endedJune 30, 2021 . We repurchased 5,290,592 common units for$53 million during the six months endedJune 30, 2021 , including$3 million associated with repurchases executed inDecember 2020 that settled inJanuary 2021 . See "-Liquidity and Capital Resources-Financing Activities-Common Equity Repurchase Program" for additional information. Recent Events InJuly 2021 , we entered into a definitive agreement with Oryx Midstream pursuant to which we and Oryx Midstream intend to merge our respectivePermian Basin assets, operations and commercial activities into a newly formed strategic joint venture,Plains Oryx Permian Basin . The transaction will include all ofOryx's Permian Basin assets and, with the exception of our long-haul pipeline systems and certain of our intra-basin terminal assets, the vast majority of our assets located within thePermian Basin . We will own 65% ofPlains Oryx Permian Basin , operate the combined assets, and consolidate the financial results of the joint venture into our financial statements. Structured as a debt-free joint venture entity through a cashless transaction, this aligns with our financial and portfolio optimization strategies, is near-term free cash flow accretive, and reinforces our ability to maximize free cash flow for our investors, while enhancing our overall credit profile. Subject to satisfaction of customary and other closing conditions and receipt of regulatory approvals, the transactions contemplated by the merger agreement are expected to close in the fourth quarter of 2021. OnAugust 2, 2021 , we completed the sale of ourPine Prairie and Southern Pines natural gas storage facilities for$850 million , subject to certain adjustments. See Note 12 to our Condensed Consolidated Financial Statements for additional information. 37 -------------------------------------------------------------------------------- Table of Contents Results of Operations
The following table sets forth an overview of our consolidated financial results calculated in accordance with GAAP (in millions, except per unit data):
Three Months Ended Six Months Ended
June 30, Variance June 30, Variance
2021 2020 $ % 2021 2020 $ %
Transportation Segment Adjusted EBITDA
(1) $ 433 $ 346 $ 87 25 % $ 821 $ 788 $ 33 4 %
Facilities Segment Adjusted EBITDA (1) 140 174 (34) (20) % 311 384 (73) (19) %
Supply and Logistics Segment Adjusted
EBITDA (1) 5 3 2 67 % (8) 144 (152) (106) %
Adjustments:
Depreciation and amortization of unconsolidated entities (68) (16) (52) (325) % (88) (33) (55) (167) % Selected items impacting comparability - Segment Adjusted EBITDA (148) (51) (97) ** 119 (189) 308 ** Depreciation and amortization (196) (166) (30) (18) % (374) (333) (41) (12) % Gains/(losses) on asset sales and asset impairments, net (369) 1 (370) ** (370) (618) 248 40 % Goodwill impairment losses - - - N/A - (2,515) 2,515 100 % Gain on/(impairment of) investments in unconsolidated entities, net - (69) 69 100 % - (91) 91 100 % Interest expense, net (107) (108) 1 1 % (213) (215) 2 1 % Other income/(expense), net 84 18 66 367 % 23 (13) 36 277 % Income tax (expense)/benefit 10 12 (2) (17) % (14) (10) (4) (40) % Net income/(loss) (216) 144 (360) (250) % 207 (2,701) 2,908 108 % Net income attributable to noncontrolling interests (4) (2) (2) (100) % (5) (4) (1) (25) % Net income/(loss) attributable to PAA$ (220) $ 142 $ (362) (255) %$ 202 $ (2,705) $ 2,907 107 % Basic and diluted net income/(loss) per common unit$ (0.37) $ 0.13 $ (0.50) **$ 0.14 $ (3.85) $ 3.99 ** Basic and diluted weighted average common units outstanding 720 728 (8) ** 721 728 (7) **
** Indicates that variance as a percentage is not meaningful. (1)Segment Adjusted EBITDA is the measure of segment performance that is utilized by our CODM to assess performance and allocate resources among our operating segments. This measure is adjusted for certain items, including those that our CODM believes impact comparability of results across periods. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments.
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Non-GAAP Financial Measures
To supplement our financial information presented in accordance with GAAP,
management uses additional measures known as "non-GAAP financial measures" in
its evaluation of past performance and prospects for the future and to assess
the amount of cash that is available for distributions, debt repayments, common
equity repurchases and other general partnership purposes.
The primary additional measures used by management are earnings before interest,
taxes, depreciation and amortization (including our proportionate share of
depreciation and amortization, including write-downs related to cancelled
projects, of unconsolidated entities), gains and losses on asset sales and asset
impairments, goodwill impairment losses and gains on and impairments of
investments in unconsolidated entities, adjusted for certain selected items
impacting comparability ("Adjusted EBITDA"), Implied distributable cash flow
("DCF"), Free Cash Flow and Free Cash Flow after Distributions.
Our definition and calculation of certain non-GAAP financial measures may not be
comparable to similarly-titled measures of other companies. Adjusted EBITDA and
Implied DCF are reconciled to Net Income/(Loss), and Free Cash Flow and Free
Cash Flow after Distributions are reconciled to Net Cash Provided by Operating
Activities, the most directly comparable measures as reported in accordance with
GAAP, and should be viewed in addition to, and not in lieu of, our Condensed
Consolidated Financial Statements and accompanying notes. See "-Liquidity and
Capital Resources-Liquidity Measures" for additional information regarding Free
Cash Flow and Free Cash Flow after Distributions.
Performance Measures
Management believes that the presentation of Adjusted EBITDA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our core operating performance and ability to fund distributions to our unitholders through cash generated by our operations, (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions and (iii) present measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our core operating results and/or (v) other items that we believe should be excluded in understanding our core operating performance. These measures may further be adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in "Other current liabilities" in our Condensed Consolidated Financial Statements. Such amounts are presented net of applicable amounts subsequently recognized into revenue. We have defined all such items as "selected items impacting comparability." We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects.
Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors as discussed, as applicable, in "-Analysis of Operating Segments."
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The following tables set forth the reconciliation of the non-GAAP financial
performance measures Adjusted EBITDA and Implied DCF from Net Income/(Loss) (in
millions):
Three Months Ended Six Months Ended
June 30, Variance June 30, Variance
2021 2020 $ % 2021 2020 $ %
Net income/(loss) $ (216) $ 144 $ (360) (250) % $ 207 $ (2,701) $ 2,908 108 %
Add/(Subtract):
Interest expense, net 107 108 (1) (1) % 213 215 (2) (1) % Income tax expense/(benefit) (10) (12) 2 17 % 14 10 4 40 % Depreciation and amortization 196 166 30 18 % 374 333 41 12 % (Gains)/losses on asset sales and asset impairments, net 369 (1) 370 ** 370 618 (248) (40) % Goodwill impairment losses - - - N/A - 2,515 (2,515) (100) % (Gain on)/impairment of investments in unconsolidated entities, net - 69 (69) (100) % - 91 (91) (100) % Depreciation and amortization of unconsolidated entities (1) 68 16 52 325 % 88 33 55 167 % Selected Items Impacting Comparability: (Gains)/losses from derivative activities and inventory valuation adjustments 163 90 73 ** (35) 121 (156) ** Long-term inventory costing adjustments (27) (51) 24 ** (68) 64 (132) ** Deficiencies under minimum volume commitments, net 6 7 (1) ** (26) 6 (32) ** Equity-indexed compensation expense 4 5 (1) ** 9 8 1 ** Net gain on foreign currency revaluation (1) - (1) ** (2) (13) 11 ** Significant transaction-related expenses 3 - 3 ** 3 3 - ** Selected Items Impacting Comparability - Segment Adjusted EBITDA (2) 148 51 97 ** (119) 189 (308) ** (Gains)/losses from derivative activities (3) (77) 9 (86) ** (9) (17) 8 ** Net (gain)/loss on foreign currency revaluation (4) (6) (23) 17 ** (13) 36 (49) ** Net gain on early repayment of senior notes (5) - (3) 3 ** - (3) 3 ** Selected Items Impacting Comparability - Adjusted EBITDA (6) 65 34 31 ** (141) 205 (346) ** Adjusted EBITDA (6)$ 579 $ 524 $ 55 10 %$ 1,125 $ 1,319 $ (194) (15) % 40
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Three Months Ended Six Months Ended
June 30, Variance June 30, Variance
2021 2020 $ % 2021 2020 $ %
Adjusted EBITDA (6) $ 579 $ 524 $ 55 10 % $ 1,125 $ 1,319 $ (194) (15) %
Interest expense, net of certain
non-cash items (7) (101) (103) 2 2 % (202) (206) 4 2 %
Maintenance capital (8) (37) (54) 17 31 % (73) (104) 31 30 %
Current income tax expense (1) (15) 14 93 % (3) (22) 19 86 %
Distributions from unconsolidated
entities in excess of/(less than)
adjusted equity earnings (9) (5) 11 (16) ** 1 9 (8) **
Distributions to noncontrolling
interests (10) - (4) 4 100 % (6) (4) (2) (50) %
Implied DCF $ 435 $ 359 $ 76 21 % $ 842 $ 992 $ (150) (15) %
Preferred unit distributions (10) (62) (62) - - % (99) (99) - - %
Implied DCF Available to Common
Unitholders $ 373 $ 297 $ 76 26 % $ 743 $ 893 $ (150) (17) %
Common unit cash distributions (10) (130) (131) (260) (393)
Implied DCF Excess (11) $ 243 $ 166 $ 483 $ 500
** 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 the
Canadian dollar ("CAD") to the U.S. dollar ("USD"), resulting in the realization
of foreign exchange gains and losses on the settlement of foreign currency
transactions as well as the revaluation of monetary assets and liabilities
denominated in a foreign currency. The associated gains and losses are not
integral to our results and were thus classified as a selected item impacting
comparability.
(5)Includes net gains recognized in connection with the repurchase of our
outstanding senior notes on the open market.
(6)Other income/(expense), net per our Condensed Consolidated Statements of
Operations, adjusted for selected items impacting comparability ("Adjusted Other
income/(expense), net") is included in Adjusted EBITDA and excluded from Segment
Adjusted EBITDA.
(7)Excludes certain non-cash items impacting interest expense such as
amortization of debt issuance costs and terminated interest rate swaps.
(8)Maintenance capital expenditures are defined as capital expenditures for the
replacement and/or refurbishment of partially or fully depreciated assets in
order to maintain the operating and/or earnings capacity of our existing assets.
(9)Comprised of cash distributions received from unconsolidated entities less
equity earnings in unconsolidated entities (adjusted for our proportionate share
of depreciation and amortization, including write-downs related to cancelled
projects, and selected items impacting comparability of unconsolidated
entities).
(10)Cash distributions paid during the period presented.
(11)Excess DCF is retained to establish reserves for future distributions,
capital expenditures and other partnership purposes.
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Analysis of Operating Segments
We manage our operations through three operating segments: Transportation, Facilities and Supply and Logistics. Our CODM (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Adjusted EBITDA, segment volumes, Segment Adjusted EBITDA per barrel and maintenance capital investment.
We define Segment Adjusted EBITDA as revenues and equity earnings in
unconsolidated entities less (a) purchases and related costs, (b) field
operating costs and (c) segment general and administrative expenses, plus our
proportionate share of the depreciation and amortization expense (including
write-downs related to cancelled projects) of unconsolidated entities, and
further adjusted for certain selected items including (i) the mark-to-market of
derivative instruments that are related to underlying activities in another
period (or the reversal of such adjustments from a prior period), gains and
losses on derivatives that are related to investing activities (such as the
purchase of linefill) and inventory valuation adjustments, as applicable, (ii)
long-term inventory costing adjustments, (iii) charges for obligations that are
expected to be settled with the issuance of equity instruments, (iv) amounts
related to deficiencies associated with minimum volume commitments, net of
applicable amounts subsequently recognized into revenue and (v) other items that
our CODM believes are integral to understanding our core segment operating
performance. See Note 11 to our Condensed Consolidated Financial Statements for
a reconciliation of Segment Adjusted EBITDA to Net income/(loss) attributable to
PAA.
Revenues and expenses from our Canadian based subsidiaries, which use CAD as
their functional currency, are translated at the prevailing average exchange
rates for the month.
Transportation Segment
Our Transportation segment operations generally consist of fee-based activities
associated with transporting crude oil and NGL on pipelines, gathering systems
and trucks. The Transportation segment generates revenue through a combination
of tariffs, pipeline capacity agreements and other transportation fees. Tariffs
and other fees on our pipeline systems vary by receipt point and delivery point.
The segment results generated by our tariff and other fee-related activities
depend on the volumes transported on the pipeline and the level of the tariff
and other fees charged, as well as the fixed and variable field costs of
operating the pipeline.
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The following tables set forth our operating results from our Transportation
segment:
Three Months Ended Six Months Ended
Operating Results (1) June 30, Variance June 30, Variance
(in millions, except per barrel data) 2021 2020 $ % 2021 2020 $ %
Revenues $ 553 $ 457 $ 96 21 % $ 1,039 $ 1,036 $ 3 - %
Purchases and related costs (60) (44) (16) (36) % (106) (124) 18 15 %
Field operating costs (140) (140) - - % (245) (302) 57 19 %
Segment general and administrative expenses (2) (28) (24) (4) (17) % (54) (51) (3) (6) %
Equity earnings in unconsolidated entities 31 81 (50) (62) % 117 189 (72) (38) %
Adjustments: (3)
Depreciation and amortization of unconsolidated
entities 67 15 52 347 % 87 32 55 172 %
Losses from derivative activities and inventory
valuation adjustments (1) (6) 5 ** (1) - (1) **
Deficiencies under minimum volume commitments, net 7 4 3 ** (23) - (23) **
Equity-indexed compensation expense 2 3 (1) ** 5 5 - **
Significant transaction-related expenses 2 - 2 ** 2 3 (1) **
Segment Adjusted EBITDA $ 433 $ 346 $ 87 25 % $ 821 $ 788 $ 33 4 %
Maintenance capital $ 20 $ 31 $ (11) (35) % $ 47 $ 64 $ (17) (27) %
Segment Adjusted EBITDA per barrel $ 0.76 $ 0.64 $ 0.12 19 % $ 0.76 $ 0.66 $ 0.10 15 %
Three Months Ended Six Months Ended
Average Daily Volumes June 30 , Variance June 30 , Variance
(in thousands of barrels per day) (4) 2021 2020 Volumes % 2021 2020 Volumes %
Tariff activities volumes
Crude oil pipelines (by region):
Permian Basin (5) 4,189 4,161 28 1 % 3,972 4,663 (691) (15) %
South Texas / Eagle Ford (5) 314 321 (7) (2) % 317 389 (72) (19) %
Central (5) 467 355 112 32 % 420 380 40 11 %
Gulf Coast 159 118 41 35 % 152 131 21 16 %
Rocky Mountain (5) 327 244 83 34 % 307 258 49 19 %
Western 256 215 41 19 % 246 209 37 18 %
Canada 294 242 52 21 % 305 285 20 7 %
Crude oil pipelines 6,006 5,656 350 6 % 5,719 6,315 (596) (9) %
NGL pipelines 181 194 (13) (7) % 182 190 (8) (4) %
Tariff activities total volumes 6,187 5,850 337 6 % 5,901 6,505 (604) (9) %
Trucking volumes 61 64 (3) (5) % 65 80 (15) (19) %
Transportation segment total volumes 6,248 5,914 334 6 % 5,966 6,585 (619) (9) %
** 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 are calculated as the total volumes (attributable to
our interest) for the period divided by the number of days in the period.
(5)Region includes volumes (attributable to our interest) from pipelines owned
by unconsolidated entities.
The following is a discussion of items impacting Transportation segment operating results for the periods indicated.
Revenues, Purchases and Related Costs, Equity Earnings in Unconsolidated Entities and Volumes. The following table presents variances in revenues, purchases and related costs and equity earnings in unconsolidated entities by region:
Favorable/(Unfavorable) Variance Favorable/(Unfavorable) Variance
Three Months Ended June 30, Six Months Ended June 30,
2021-2020 2021-2020
Purchases and Equity Purchases and Equity
(in millions) Revenues Related Costs Earnings Revenues Related Costs Earnings
Permian Basin region $ 60 $ (16) $ (11) $ 7 $ 7 $ (17)
South Texas / Eagle Ford region (1) - (2) (8) - (12)
Central region 8 - (21) 3 1 (24)
Gulf Coast region 2 - (12) 2 - (11)
Rocky Mountain region 8 - (2) 12 - (8)
Canada region 10 - - 5 - -
Other regions, NGL pipelines, trucking and
pipeline loss allowance revenue 9 - (2) (18) 10 -
Total variance $ 96 $ (16) $ (50) $ 3 $ 18 $ (72)
•Permian Basin region. Revenues, net of purchases and related costs, ("net
revenues") increased by $44 million and $14 million for the three and six months
ended June 30, 2021 , respectively, compared to the same periods in 2020
primarily due to the recognition of revenue associated with minimum volume
commitments. The recognition of previously deferred revenue associated with
minimum volume commitments is reflected as an "Adjustment" in the table above as
discussed further below under "-Adjustments: Deficiencies under minimum volume
commitments, net." The three-month comparative period was further favorably
impacted by higher long-haul movements to Cushing, Oklahoma in the second
quarter of 2021, as well as an increase in volumes on our gathering pipelines as
a result of new connections and increased production, partially offset by lower
volumes on our intra-basin pipelines. The six-month comparative period was
further unfavorably impacted by lower volumes of crude oil produced in the
Permian Basin in the first quarter of 2021, driven by the COVID-19
pandemic-related reset to production and compounded by shut-ins from the extreme
winter weather event that occurred in February of 2021 ("Winter Storm Uri").
Equity earnings decreased for the three and six months ended June 30, 2021
compared to the same periods in 2020 primarily due to our proportionate share of
the write-off of costs associated with a capital project canceled during the
second quarter of 2021, which is included in the table above as an "Adjustment"
in "Depreciation and amortization of unconsolidated entities." The six-month
comparative period was further unfavorably impacted by depreciation expense and
transition costs associated with phase one of the Wink to Webster pipeline being
placed into service during the first quarter of 2021, partially offset by lower
power costs related to Winter Storm Uri.
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•South Texas / Eagle Ford region. Revenues decreased for the six months ended
June 30, 2021 compared to the same periods in 2020 due to lower production,
including curtailments from Winter Storm Uri.
Equity earnings from our 50% interest in Eagle Ford Pipeline LLC decreased for
the six months ended June 30, 2021 compared to the same period in 2020 due to a
combination of lower joint tariff volumes from the Permian Basin via our Cactus
I pipeline, and to a lesser extent, lower regional receipts, partially offset by
the recognition of previously deferred revenue associated with minimum volume
commitments. The recognition of such revenue is reflected as an "Adjustment" in
the table above as discussed further below under "-Adjustments: Deficiencies
under minimum volume commitments, net."
•Central region. Revenues increased for the three and six months ended June 30,
2021 compared to the same periods in 2020 primarily due to higher volumes on
certain of our pipelines in the region, including the Red River pipeline, as a
result of an increase in committed volumes and an expansion placed into service
in October 2020 .
Equity earnings decreased for the three and six months ended June 30, 2021
compared to the same periods in 2020 primarily due our proportionate share of
Diamond Pipeline's write-off of costs associated with the cancellation of the
Byhalia Connection construction project during the second quarter of 2021, which
is included in the table above as an "Adjustment" in "Depreciation and
amortization of unconsolidated entities."
•Gulf Coast region. Equity earnings decreased for the three and six months ended
June 30, 2021 compared to the same periods in 2020 primarily due to our
proportionate share of Capline Pipeline's write-off of costs associated with the
cancellation of the Byhalia Connection construction project during the second
quarter of 2021, which is included in the table above as an "Adjustment" in
"Depreciation and amortization of unconsolidated entities."
•Rocky Mountain region. Revenues increased for the three and six months ended
Equity earnings decreased for the three and six months ended
•Canada region. Revenues increased for the three and six months endedJune 30, 2021 compared to the same periods in 2020 primarily due to higher volumes from increased production and favorable foreign exchange impacts. Such favorable impacts were partially offset by a decrease in intersegment fees to reflect lower utilization and market rates, which had an offsetting favorable impact on our Supply and Logistics segment. •Other regions, NGL pipelines, trucking and pipeline loss allowance revenue. The increase in net revenues for the three months endedJune 30, 2021 compared to the same period in 2020 was primarily due to higher pipeline loss allowance revenue in 2021 primarily due to higher prices. The decrease in net revenues for the six months endedJune 30, 2021 compared to the same period in 2020 was primarily due to lower pipeline loss allowance revenue due to lower volumes, partially offset by higher prices. Such unfavorable impacts were offset by lower trucking costs driven by lower volumes. Adjustments: Deficiencies under minimum volume commitments, net. Many industry infrastructure projects developed and completed over the last several years were underpinned by long-term minimum volume commitment contracts whereby the shipper agreed to either: (i) ship and pay for certain stated volumes or (ii) pay the agreed upon price for a minimum contract quantity. Some of these agreements include make-up rights if the minimum volume is not met. If a counterparty has a make-up right associated with a deficiency, we bill the counterparty and defer the revenue attributable to the counterparty's make-up right but record an adjustment to reflect such amount associated with the current period activity in Segment Adjusted EBITDA. We subsequently recognize the revenue, and record a corresponding reversal of the adjustment, at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty's ability to utilize the make-up right is remote. For the three months endedJune 30, 2021 and 2020, amounts billed to counterparties exceeded revenue recognized during the periods that was previously deferred. For the six months endedJune 30, 2021 , the recognition of previously deferred revenue exceeded amounts billed to counterparties associated with deficiencies under minimum volume commitments. 45 -------------------------------------------------------------------------------- Table of Contents Field Operating Costs. The decrease in field operating costs for the six months endedJune 30, 2021 compared to the same period in 2020 was primarily due to (i) lower power costs, including the impact of gains related to hedged power costs resulting from Winter Storm Uri and (ii) streamlining efforts which have resulted in decreases in variable costs and maintenance and chemicals and additives costs. Segment General and Administrative Expenses. The increase in segment general and administrative expenses for the three and six months endedJune 30, 2021 compared to the same periods in 2020 was primarily due to increased information systems costs and reduced wage subsidies received by our Canadian subsidiary in the current periods.Maintenance Capital . Maintenance capital consists of capital expenditures for the replacement and/or refurbishment of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The decrease in maintenance capital spending for the three and six months endedJune 30, 2021 compared to the same periods in 2020 was primarily due to timing changes, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors. 46 -------------------------------------------------------------------------------- Table of Contents Facilities Segment Our Facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Facilities segment generates revenue through a combination of month-to-month and multi-year agreements. The following tables set forth our operating results from our Facilities segment: Three Months Ended Six Months Ended Operating Results (1) June 30, Variance June 30, Variance (in millions, except per barrel data) 2021 2020 $ % 2021 2020 $ % Revenues$ 244 $ 276 $ (32) (12) %$ 515 $ 589 $ (74) (13) % Purchases and related costs (3) (7) 4 57 % (6) (10) 4 40 % Field operating costs (74) (72) (2) (3) % (151) (159) 8 5 % Segment general and administrative expenses (2) (21) (27) 6 22 % (41) (46) 5 11 % Equity earnings in unconsolidated entities 2 - 2 N/A 4 2 2 100 % Adjustments: (3) Depreciation and amortization of unconsolidated entities 1 1 - ** 1 1 - ** (Gains)/losses from derivative activities (9) (1) (8) ** (10) - (10) ** Deficiencies under minimum volume commitments, net (1) 3 (4) ** (3) 6 (9) ** Equity-indexed compensation expense 1 1 - ** 2 1 1 ** Segment Adjusted EBITDA$ 140 $ 174 $ (34) (20) %$ 311 $ 384 $ (73) (19) % Maintenance capital$ 14 $ 15 $ (1) (7) %$ 20 $ 29 $ (9) (31) % Segment Adjusted EBITDA per barrel$ 0.40 $ 0.47 $ (0.07) (15) %$ 0.45 $ 0.51 $ (0.06) (12) % Three Months Ended Six Months Ended June 30, Variance June 30, Variance Volumes (4) 2021 2020 Volumes % 2021 2020 Volumes % Liquids storage (average monthly capacity in millions of barrels) (5) 100 109 (9) (8) % 100 110 (10) (9) % Natural gas storage (average monthly working capacity in billions of cubic feet) 70 67 3 4 % 69 65 4 6 % NGL fractionation (average volumes in thousands of barrels per day) 129 122 7 6 % 136 138 (2) (1) % Facilities segment total volumes (average monthly volumes in millions of barrels) (6) 115 124 (9) (7) % 115 125 (10) (8) % ** 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. 47 -------------------------------------------------------------------------------- Table of Contents (3)Represents adjustments included in the performance measure utilized by our CODM in the evaluation of segment results. See Note 11 to our Condensed Consolidated Financial Statements for additional discussion of such adjustments. (4)Average monthly volumes are calculated as total volumes for the period divided by the number of months in the period. (5)Includes volumes (attributable to our interest) from facilities owned by unconsolidated entities. (6)Facilities segment total volumes are calculated as the sum of: (i) liquids storage capacity; (ii) natural gas storage working capacity divided by 6 to account for the 6:1 mcf of natural gas to crude Btu equivalent ratio and further divided by 1,000 to convert to monthly volumes in millions; and (iii) NGL fractionation volumes multiplied by the number of days in the period and divided by the number of months in the period.
The following is a discussion of items impacting Facilities segment operating results.
Revenues, Purchases and Related Costs and Volumes. Variances in net revenues and average monthly volumes were primarily driven by the following:
•NGL Operations. Revenues from our NGL operations decreased by$16 million and$57 million for the three and six months endedJune 30, 2021 , respectively, compared to the same periods in 2020 primarily due to lower intersegment facility fee revenues due to rate decreases at certain of our storage, fractionation and processing facilities to reflect lower utilization and market rates (which had an offsetting favorable impact on our Supply and Logistics segment). The six-month comparative period was further unfavorably impacted by (i) a benefit in the 2020 comparative period from the receipt of a deficiency payment of approximately$20 million upon the expiration of a multi-year contract and (ii) the sale of certain NGL terminals in the second quarter of 2020. Such unfavorable impacts were partially offset for the three- and six-month comparative periods by more favorable foreign exchange impacts in 2021 of approximately$13 million and$19 million , respectively, and, for the six-month comparative period, gains at certain of our fractionation facilities in the first quarter of 2021. •Crude Oil Storage. Revenues from our crude oil storage operations decreased by$16 million and$31 million for the three and six months endedJune 30, 2021 , respectively, compared to the same periods in 2020 primarily due to the sale of ourLos Angeles Basin terminals in October of 2020. •Natural Gas Storage. Net revenues increased by$17 million for the six months endedJune 30, 2021 compared to the same period in 2020 primarily due to increased margins from hub activities in the first quarter of 2021 related to Winter Storm Uri. Field Operating Costs. The decrease in field operating costs for the six months endedJune 30, 2021 compared to the same period in 2020 was primarily due to (i) the sale of ourLos Angeles Basin terminals and certain NGL terminals, (ii) decreased power costs related to derivative activity and (iii) reduced activity at our rail terminals. Segment General and Administrative Expenses. The decrease in segment general and administrative expenses for the three and six months endedJune 30, 2021 compared to the same periods in 2020 was primarily due to the impact of 2020 legal costs, partially offset by reduced wage subsidies received by our Canadian subsidiary in the current period.Maintenance Capital . The decrease in maintenance capital spending for the three and six months endedJune 30, 2021 compared to the same periods in 2020 was primarily due to timing changes, the impact of asset sales, the completion of multi-year reliability improvement programs and application of updated regulatory guidance, among other factors.
Supply and Logistics Segment
Revenues from our Supply and Logistics segment activities reflect the sale of
gathered and bulk-purchased crude oil, as well as sales of NGL volumes.
Generally, our segment results are impacted by (i) increases or decreases in our
Supply and Logistics segment volumes (which consist of lease gathering crude oil
purchases volumes and NGL sales volumes), (ii) the overall strength, weakness
and volatility of market conditions, including regional differentials, (iii) the
relationship between NGL prices and natural gas prices and (iv) the effects of
competition on our lease gathering and NGL margins. In addition, the execution
of our risk management strategies in conjunction with our assets can provide
upside in certain markets.
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The following tables set forth our operating results from our Supply and
Logistics segment:
Three Months Ended Six Months Ended
Operating Results (1) June 30, Variance June 30, Variance
(in millions, except per barrel data) 2021 2020 $ % 2021 2020 $ %
Revenues $ 9,623 $ 2,925 $ 6,698 229 % $ 17,707 $ 10,834 $ 6,873 63 %
Purchases and related costs (9,700) (2,903) (6,797) (234) % (17,497) (10,717) (6,780) (63) %
Field operating costs (42) (45) 3 7 % (83) (103) 20 19 %
Segment general and administrative expenses (2) (23) (21) (2) (10) % (44) (44) - - %
Adjustments: (3)
(Gains)/losses from derivative activities and
inventory valuation adjustments 173 97 76 ** (24) 121 (145) **
Long-term inventory costing adjustments (27) (51) 24 ** (68) 64 (132) **
Equity-indexed compensation expense 1 1 - ** 2 2 - **
Net (gain)/loss on foreign currency revaluation (1) - (1) ** (2) (13) 11 **
Significant transaction-related expenses 1 - 1 ** 1 - 1 **
Segment Adjusted EBITDA $ 5 $ 3 $ 2 67 % $ (8) $ 144 $ (152) (106) %
Maintenance capital $ 3 $ 8 $ (5) (63) % $ 6 $ 11 $ (5) (45) %
Segment Adjusted EBITDA per barrel $ 0.04 $ 0.03 $ 0.01 33 % $ (0.03) $ 0.58 $ (0.61) (105) %
Three Months Ended Six Months Ended
Average Daily Volumes (4) June 30 , Variance June 30 , Variance
(in thousands of barrels per day) 2021 2020 Volumes % 2021 2020 Volumes %
Crude oil lease gathering purchases 1,352 1,077 275 26 % 1,264 1,198 66 6 %
NGL sales 112 94 18 19 % 165 156 9 6 %
Supply and Logistics segment total volumes 1,464 1,171 293 25 % 1,429 1,354 75 6 %
** Indicates that variance as a percentage is not meaningful.
(1)Revenues and costs include intersegment amounts.
(2)Segment general and administrative expenses reflect direct costs attributable
to each segment and an allocation of other expenses to the segments. The
proportional allocations by segment require judgment by management and are based
on the business activities that exist during each period.
(3)Represents adjustments included in the performance measure utilized by our
CODM in the evaluation of segment results. See Note 11 to our Condensed
Consolidated Financial Statements for additional discussion of such adjustments.
(4)Average daily volumes are calculated as the total volumes for the period
divided by the number of days in the period.
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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
Three Months Ended June 30, 2021 $ 59 $ 74
Three Months Ended June 30, 2020 $ (38) $ 40
Six Months Ended June 30, 2021 $ 48 $ 74
Six Months Ended June 30, 2020 $ (38) $ 63
Our crude oil and NGL supply, logistics and distribution operations are not
directly affected by the absolute level of prices. Because the commodities that
we buy and sell are generally indexed to the same pricing indices for both sales
and purchases, revenues and costs related to purchases will fluctuate with
market prices. However, the margins related to those sales and purchases will
not necessarily have a corresponding increase or decrease. Additionally, net
revenues are impacted by net gains and losses from certain derivative activities
and inventory valuation and costing adjustments.
Our NGL operations are sensitive to weather-related demand, particularly during
the approximate five-month peak heating season of November through March, and
temperature differences from period-to-period may have a significant effect on
NGL demand and thus our financial performance.
Segment Adjusted EBITDA and Volumes. The following summarizes the significant items impacting our Supply and Logistics Segment Adjusted EBITDA:
•Crude Oil Operations. Net revenues from our crude oil operations were slightly lower in the three-month period as contango margins were better in the 2020 period; however, this was largely offset by lease gathering margins and certain differentials that were more favorable in the 2021 period. For the six months endedJune 30, 2021 compared to the same period in 2020, net revenues from our crude oil operations were lower due to less favorable market conditions. •NGL Operations. Net revenues from our NGL operations were slightly higher for the three months endedJune 30, 2021 compared to the same period in 2020 due to a decrease in intersegment fees. Net revenues from our NGL operations decreased for the six months endedJune 30, 2021 compared to the same period in 2020, primarily due to lower realized margins on our NGL sales activities, partially offset by a decrease in intersegment fees. The intersegment fees were reduced in the 2021 periods to reflect lower utilization and market rates, and had an offsetting unfavorable impact on our Facilities and Transportation segments. •Impact from Certain Derivative Activities and Inventory Valuation Adjustments. The impact from certain derivative activities on our net revenues includes mark-to-market and other gains and losses resulting from certain derivative instruments that are related to underlying activities in another period (or the reversal of mark-to-market gains and losses from a prior period), gains and losses on derivatives that are related to investing activities (such as the purchase of linefill) and inventory valuation adjustments, as applicable. See Note 8 to our Condensed Consolidated Financial Statements for a comprehensive discussion regarding our derivatives and risk management activities. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an "Adjustment" in the table above. •Long-Term Inventory Costing Adjustments. Our net revenues are impacted by changes in the weighted average cost of our crude oil and NGL inventory pools that result from price movements during the periods. These costing adjustments related to long-term inventory necessary to meet our minimum inventory requirements in third-party assets and other working inventory that was needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. These costing adjustments impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an "Adjustment" in the table above. 50
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•Foreign Exchange Impacts. Our net revenues are impacted by fluctuations in the value of CAD to USD, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency within our Canadian operations. These gains and losses impact our net revenues but are excluded from Segment Adjusted EBITDA and thus are reflected as an "Adjustment" in the table above. •Field Operating Costs. The decrease in field operating costs for the six months endedJune 30, 2021 compared to the same period in 2020 was primarily due to lower trucking costs due to more supply connected to pipelines resulting in lower trucking activity in the 2021 period.
Other Income and Expenses
Depreciation and Amortization
The increase in depreciation and amortization expense for the three and six
months ended
Gains/(Losses) on Asset Sales and Asset Impairments, Net
The net loss on asset sales and asset impairments for the three and six months endedJune 30, 2021 , was primarily driven by 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, which were subsequently sold onAugust 2, 2021 , partially offset by a gain of$106 million related to the Asset Exchange transaction. See Note 12 to our Condensed Consolidated Financial Statements for additional information. The net loss on asset sales and asset impairments for the six months endedJune 30, 2020 was largely driven by (i) non-cash impairment losses of approximately$446 million related to the write-down of certain pipeline and other long-lived assets due to macroeconomic and geopolitical conditions including the collapse of oil prices driven by both the decrease in demand caused by the COVID-19 pandemic and excess supply, as well as changing market conditions and expected lower crude oil production in certain regions, and (ii) approximately$167 million of impairment losses recognized on assets upon classification as held for sale during the quarter, which were subsequently sold. Goodwill Impairment Losses
During the first quarter of 2020, we recognized a goodwill impairment charge of
Gain on/(Impairment of) Investments in Unconsolidated Entities, Net
During the three and six months endedJune 30, 2020 , we recognized losses of$69 million and$112 million , respectively, related to the write-down of certain of our investments in unconsolidated entities. Additionally, during the six months endedJune 30, 2020 , we recognized a gain of$21 million related to our sale of a 10% interest inSaddlehorn Pipeline Company, LLC . 51 -------------------------------------------------------------------------------- Table of Contents Other Income/(Expense), Net The following table summarizes the components impacting Other expense, net (in millions): Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020
Gain/(loss) related to mark-to-market adjustment of our Preferred Distribution Rate Reset Option (1)
$ 77 $ (9) $ 9 $ 17 Net gain/(loss) on foreign currency revaluation (2) 6 23 13 (36) Other 1 4 1 6$ 84 $ 18 $ 23 $ (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.
Liquidity and Capital Resources
General
Our primary sources of liquidity are (i) cash flow from operating activities and (ii) borrowings under our credit facilities or commercial paper program. In addition, we may supplement these primary sources of liquidity with proceeds from our divestiture program and in the past we have utilized funds received from sales of equity and debt securities. Our primary cash requirements include, but are not limited to, (i) ordinary course of business uses, such as the payment of amounts related to the purchase of crude oil, NGL and other products, other expenses and interest payments on outstanding debt, (ii) investment and maintenance capital activities, (iii) acquisitions of assets or businesses, (iv) repayment of principal on our long-term debt and (v) distributions to our unitholders. In addition, we may use cash for repurchases of common equity. We generally expect to fund our short-term cash requirements through cash flow generated from operating activities and/or borrowings under our commercial paper program or credit facilities. In addition, we generally expect to fund our long-term needs, such as those resulting from investment capital activities or acquisitions and refinancing our long-term debt, through a variety of sources (either separately or in combination), which may include the sources mentioned above as funding for short-term needs and/or the issuance of additional equity or debt securities and the sale of assets. As ofJune 30, 2021 , although we had a working capital deficit of$487 million , we had approximately$2.6 billion of liquidity available to meet our ongoing operating, investing and financing needs, subject to continued covenant compliance, as noted below (in millions): As of June 30, 2021 Availability under senior unsecured revolving credit facility (1) (2)$ 1,532 Availability under senior secured hedged inventory facility (1) (2) 1,387 Amounts outstanding under commercial paper program (388) Subtotal 2,531 Cash and cash equivalents 24 Total$ 2,555 (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$68 million and$13 million , respectively. 52 -------------------------------------------------------------------------------- Table of Contents 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 our term loans 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 ofJune 30, 2021 . We believe that we have, and will continue to have, the ability to access our commercial paper program and credit facilities, which we use to meet our short-term cash needs. We believe that our financial position remains strong and we have sufficient liquid assets, cash flow from operating activities and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow, including extended disruptions in the financial markets and/or energy price volatility resulting from current macroeconomic and geopolitical conditions associated with the COVID-19 pandemic and/or actions 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 2020 Annual Report on Form 10-K for further discussion regarding risks that may impact our liquidity and capital resources.
Liquidity Measures
Management uses the non-GAAP financial measures Free Cash Flow and Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Free Cash Flow is defined as Net Cash Provided by Operating Activities, lessNet Cash Used in Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and the impact from the purchase and sale of linefill and base gas, net of proceeds from the sales of assets and further impacted by cash received from or paid to noncontrolling interests. Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Free Cash Flow after Distributions.
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 Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net cash provided by operating activities $ 235 $ 84 $ 1,026 $ 974
Adjustments to reconcile net cash provided by
operating activities to free cash flow:
Net cash used in investing activities (175) (248) (283) (858)
Cash contributions from noncontrolling
interests - 2 1 10
Cash distributions paid to noncontrolling
interests (1) - (4) (6) (4)
Free Cash Flow $ 60 $ (166) $ 738 $ 122
Cash distributions (2) (192) (193) (359) (492)
Free Cash Flow after Distributions $ (132) $ (359) $ 379 $ (370) (1)Cash distributions paid during the period presented. (2)Cash distributions paid to our preferred and common unitholders during the period presented.
Cash Flow from Operating Activities
For a comprehensive discussion of the primary drivers of cash flow from operating activities, including the impact of varying market conditions and the timing of settlement of our derivatives, see Item 7. "Liquidity and Capital Resources-Cash Flow from Operating Activities" included in our 2020 Annual Report on Form 10-K.
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Net cash provided by operating activities for the first six months of 2021 and
2020 was $1.026 billion and $974 million , respectively, and primarily resulted
from earnings from our operations. Additionally, during the six months ended
June 30, 2020 , we increased the volume of our crude oil inventory to be stored
during the contango market; however, this increase was offset by lower prices
for our inventory stored at the end of the current period compared to the end of
2019.
Investing Activities
Capital Expenditures
In addition to our operating needs, we also use cash for our investment capital
projects, maintenance capital activities and acquisition activities. We fund
these expenditures with cash generated by operating activities, financing
activities and/or proceeds from our divestiture program. In the near term, we do
not plan to issue common equity to fund such expenditures. The following table
summarizes our investment, maintenance and acquisition capital expenditures (in
millions):
Six Months Ended
June 30,
2021 2020
Investment capital (1) (2) $ 142 $ 654
Maintenance capital (1) 73 104
Acquisition capital (3) 32 308
$ 247 $ 1,066
(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.
(3)Acquisition capital for 2021 represents the cash consideration paid as part
of the Asset Exchange transaction. See Note 12 to our Condensed Consolidated
Financial Statements for additional information. Acquisition capital for 2020
primarily includes Felix Midstream LLC , a crude oil gathering system located in
the Delaware Basin .
2021 Investment and Maintenance Capital . Total projected investment capital for
the year ended December 31, 2021 is $325 million , a majority of which will be
invested in our fee-based Transportation and Facilities segments. Additionally,
maintenance capital for the full year of 2021 is projected to be $180 million .
We expect to fund our 2021 investment and maintenance capital expenditures with
retained cash flow and proceeds from assets sold as part of our divestiture
program.
Divestitures
We continue to evaluate potential sales of non-core assets and/or sales of
partial interests in assets to strategic joint venture partners. The following
table summarizes the proceeds received during the first six months of 2021 and
2020 from sales of assets, which were previously reported in our Transportation
and Facilities segments (in millions):
Six Months Ended
June 30,
2021 2020
Proceeds from divestitures $ 22 $ 245 Proceeds from divestitures were used to reduce debt levels and fund our investment capital projects.
OnAugust 2, 2021 , we closed the sale of ourPine Prairie and Southern Pines natural gas storage facilities for$850 million , subject to certain adjustments. See Note 12 to our Condensed Consolidated Financial Statements for additional information. 54 -------------------------------------------------------------------------------- Table of Contents Ongoing Activities Related to Strategic Transactions We are continuously engaged in the evaluation of potential transactions that support our current business strategy. While in the past such transactions have included acquisitions and large capital projects, consistent with our current strategic focus on capital discipline, leverage reduction, portfolio optimization and free cash flow generation, we are currently primarily focused on evaluating whether we should (i) sell assets that we regard as non-core or that we believe might be a better fit with the business and/or assets of a third-party buyer or (ii) sell partial interests in assets to strategic joint venture partners, in each case to optimize our asset portfolio and strengthen our balance sheet and leverage metrics. With respect to a potential divestiture, we may also conduct an auction process or may negotiate a transaction with one or a limited number of potential buyers. Such transactions could involve assets that, if sold or put into a joint venture or joint ownership arrangement, could have a material effect on our financial condition and results of operations. We typically do not announce a transaction until after we have executed a definitive agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of a transaction until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future efforts with respect to any such transactions will be successful, and we can provide no assurance that our financial expectations with respect to such transactions will ultimately be realized. See Item 1A. "Risk Factors-Risks Related to Our Business-Divestitures, joint ventures, joint ownership arrangements and acquisitions involve risks that may adversely affect our business" included in our 2020 Annual Report on Form 10-K.
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 six months endedJune 30, 2021 , we had net repayments on our credit facilities and commercial paper program of$326 million . The net repayments resulted primarily from cash flow from operating activities and proceeds from asset sales, which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes. During the six months endedJune 30, 2020 , we had net repayments on our credit facilities and commercial paper program of$418 million . The net repayments resulted primarily from cash flow from operating activities, proceeds from asset sales and the issuance of$750 million , 3.80% senior notes inJune 2020 , which offset borrowings during the period related to funding needs for capital investments, inventory purchases and other general partnership purposes. In connection with the sale of ourPine Prairie and Southern Pines natural gas storage facilities onAugust 2, 2021 , we repaid our twoGO Zone term loans totaling$200 million . See Note 12 for additional information regarding the sale of our natural gas storage facilities.
Common Equity Repurchase Program
We repurchased 5,290,592 common units under the Program through open market purchases that settled during the six months endedJune 30, 2021 . The total purchase price of these repurchases was$53 million , including commissions and fees. AtJune 30, 2021 , the remaining available capacity under the Program was$397 million . 55 -------------------------------------------------------------------------------- Table of Contents 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 atJune 30, 2021 . We also have access to a universal shelf registration statement ("WKSI Shelf"), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. We did not conduct any offerings under our Traditional Shelf or WKSI Shelf during the six months endedJune 30, 2021 .
Distributions to Our Unitholders
In accordance with our partnership agreement, after making distributions to holders of our outstanding preferred units, we distribute the remainder of our available cash to our common unitholders of record within 45 days following the end of each quarter. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Our levels of financial reserves are established by our general partner and include reserves for the proper conduct of our business (including future capital expenditures and anticipated credit needs), compliance with legal or contractual obligations and funding of future distributions to our Series A and Series B preferred unitholders. Our available cash also includes cash on hand resulting from borrowings made after the end of the quarter. See Item 5. "Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities-Cash Distribution Policy" included in our 2020 Annual Report on Form 10-K for additional discussion regarding distributions.
See Note 7 to our Condensed Consolidated Financial Statements for details of distributions paid during or pertaining to the first six months of 2021.
Contingencies
For a discussion of contingencies that may impact us, see Note 10 to our Condensed Consolidated Financial Statements.
Commitments
Contractual Obligations. In the ordinary course of doing business, we purchase crude oil and NGL from third parties under contracts, the majority of which range in term from thirty-day evergreen to five years, with a limited number of contracts with remaining terms extending up to 13 years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with our counterparties (including giving effect to netting buy/sell contracts and those subject to a net settlement arrangement). We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to entities that we deem creditworthy or who have provided credit support we consider adequate.
The following table includes our best estimate of the amount and timing of these
payments as well as other amounts due under the specified contractual
obligations as of
Remainder of 2026 and
2021 2022 2023 2024 2025 Thereafter Total
Long-term debt and related
interest payments (1) $ 402 $ 1,137 $ 1,461 $ 1,083 $ 1,300 $ 8,337 $ 13,720
Leases (2) 54 102 78 64 49 299 646
Other obligations (3) 197 408 329 282 269 935 2,420
Subtotal 653 1,647 1,868 1,429 1,618 9,571 16,786
Crude oil, NGL and other purchases
(4) 11,039 19,545 18,494 17,483 14,182 54,615 135,358
Total $ 11,692 $ 21,192 $ 20,362 $ 18,912 $ 15,800 $ 64,186 $ 152,144
56-------------------------------------------------------------------------------- Table of Contents (1)Includes debt service payments, interest payments due on senior notes and the commitment fee on assumed available capacity under our credit facilities, as well as long-term borrowings under our credit agreements and commercial paper program, if any. Although there may be short-term borrowings under our credit agreements and commercial paper program, we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no short-term borrowings were outstanding on the credit agreements or commercial paper program) in the amounts above. For additional information regarding our debt obligations, see Note 6 to our Condensed Consolidated Financial Statements. (2)Includes both operating and finance leases as defined by FASB guidance. Leases are primarily for (i) railcars, (ii) land, (iii) office space, (iv) storage tanks, (v) tractor trailers and (vi) vehicles. See Note 14 to our Consolidated Financial Statements included in Part IV of our 2020 Annual Report on Form 10-K for additional information. (3)Includes (i) other long-term liabilities, (ii) storage, processing and transportation agreements (including certain agreements for which the amount and timing of expected payments is subject to the completion of underlying construction projects), (iii) certain rights-of-way easements and (iv) noncancelable commitments related to our investment capital projects, including projected contributions for our share of the capital spending of our equity method investments. The storage, processing and transportation agreements include approximately$1.9 billion associated with agreements to store crude oil at facilities and transport crude oil or utilize capacity on pipelines owned by equity method investees at posted tariff rates or prices that we believe approximate market. A portion of our commitment to transport is supported by crude oil buy/sell or other agreements with third parties with commensurate quantities. (4)Amounts are primarily based on estimated volumes and market prices based on average activity duringJune 2021 . The actual physical volume purchased and actual settlement prices will vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control. Letters of Credit. In connection with supply and logistics activities, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase and transportation of crude oil, NGL and natural gas. Additionally, we issue letters of credit to support insurance programs, derivative transactions, including hedging-related margin obligations, and construction activities. AtJune 30, 2021 andDecember 31, 2020 , we had outstanding letters of credit of approximately$81 million and$129 million , respectively.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as defined by Item 303 of Regulation S-K.
Recent Accounting Pronouncements
See Note 2 to our Condensed Consolidated Financial Statements.
Critical Accounting Policies and Estimates
For a discussion regarding our critical accounting policies and estimates, see "Critical Accounting Policies and Estimates" under Item 7 of our 2020 Annual Report on Form 10-K.
Change in Accounting Estimate
In early 2021, we conducted a review to assess the useful lives of our property and equipment. Based on this review, we modified the useful lives of certain of our Pipelines and related facilities and Storage, terminal and rail facilities to useful lives of 10 to 50 years from useful lives of 10 to 70 years to reflect current expectations given our future operating and commercial outlook. This change in accounting estimate was effectiveJanuary 1, 2021 . Based on the net carrying amount of this property and equipment as ofJanuary 1, 2021 , we currently estimate that these useful life reductions will prospectively increase annual depreciation expense by approximately$72 million . 57
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Table of Contents
FORWARD-LOOKING STATEMENTS
All statements included in this report, other than statements of historical
fact, are forward-looking statements, including but not limited to statements
incorporating the words "anticipate," "believe," "estimate," "expect," "plan,"
"intend" and "forecast," as well as similar expressions and statements regarding
our business strategy, plans and objectives for future operations. The absence
of such words, expressions or statements, however, does not mean that the
statements are not forward-looking. Any such forward-looking statements reflect
our current views with respect to future events, based on what we believe to be
reasonable assumptions. Certain factors could cause actual results or outcomes
to differ materially from the results or outcomes anticipated in the
forward-looking statements. The most important of these factors include, but are
not limited to:
•declines in global crude oil demand and crude oil prices (whether due to the
COVID-19 pandemic, future pandemics or other factors) that correspondingly lead
to a significant reduction of North American crude oil, natural gas liquids
("NGL") and natural gas production (whether due to reduced producer cash flow to
fund drilling activities or the inability of producers to access capital, or
both, the unavailability of pipeline and/or storage capacity, the shutting-in of
production by producers, government-mandated pro-ration orders, or other
factors), which in turn could result in significant declines in the actual or
expected volume of crude oil and NGL shipped, processed, purchased, stored,
fractionated and/or gathered at or through the use of our assets and/or the
reduction of commercial opportunities that might otherwise be available to us;
•the effects of competition and capacity overbuild in areas where we operate,
including contract renewal risk and the risk of loss of business to other
midstream operators who are willing or under pressure to aggressively reduce
transportation rates in order to capture or preserve customers;
•negative societal sentiment regarding the hydrocarbon energy industry and the
continued development and consumption of hydrocarbons, which could influence
consumer preferences and governmental or regulatory actions that adversely
impact our business;
•unanticipated changes in crude oil and NGL market structure, grade
differentials and volatility (or lack thereof);
•environmental liabilities or events that are not covered by an indemnity,
insurance or existing reserves;
•fluctuations in refinery capacity in areas supplied by our mainlines and other
factors affecting demand for various grades of crude oil, NGL and natural gas
and resulting changes in pricing conditions or transportation throughput
requirements;
•the availability of, and our ability to consummate, divestitures, joint
ventures, acquisitions or other strategic opportunities;
•maintenance of our credit rating and ability to receive open credit from our
suppliers and trade counterparties;
•the occurrence of a natural disaster, catastrophe, terrorist attack (including
eco-terrorist attacks) or other event that materially impacts our operations,
including cyber or other attacks on our electronic and computer systems;
•weather interference with business operations or project construction,
including the impact of extreme weather events or conditions;
•the refusal or inability of our customers or counterparties to perform their
obligations under their contracts with us (including commercial contracts, asset
sale agreements and other agreements), whether justified or not and whether due
to financial constraints (such as reduced creditworthiness, liquidity issues or
insolvency), market constraints, legal constraints (including governmental
orders or guidance), the exercise of contractual or common law rights that
allegedly excuse their performance (such as force majeure or similar claims) or
other factors;
•our inability to perform our obligations under our contracts, whether due to
non-performance by third parties, including our customers or counterparties,
market constraints, third-party constraints, legal constraints (including
governmental orders or guidance), or other factors;
•the incurrence of costs and expenses related to unexpected or unplanned capital
expenditures, third-party claims or other factors;
•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;
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Table of Contents •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; •disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies; •shortages or cost increases of supplies, materials or labor; •the impact of current and future laws, rulings, governmental regulations, trade policies, accounting standards and statements, and related interpretations, including legislation or regulatory initiatives that prohibit, restrict or regulate hydraulic fracturing or that prohibit the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines; •tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness; •inability of producers, who have made commitments to our pipelines, to access capital to fund their drilling and completion activities; •general economic, market or business conditions inthe United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels and the timing, pace and extent of economic recovery) that impact demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and commercial opportunities available to us; •the amplification of other risks caused by volatile financial markets, capital constraints, liquidity concerns and inflation; •the use or availability of third-party assets upon which our operations depend and over which we have little or no control; •the currency exchange rate of the Canadian dollar tothe United States dollar; •inability to recognize current revenue attributable to deficiency payments received from customers who fail to ship or move more than minimum contracted volumes until the related credits expire or are used; •significant under-utilization of our assets and facilities; •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 storage of natural gas and the processing, transportation, fractionation, storage and marketing of natural gas liquids. Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read "Risk Factors" discussed in Item 1A of our 2020 Annual Report on Form 10-K. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
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