ENERGY TRANSFER LP (Tabular dollar and unit amounts, except per unit data, are in millions) The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management's discussion and analysis of financial condition and results of operations included in the Partnership's Annual Report on Form 10-K for the year endedDecember 31, 2019 filed with theSEC onFebruary 21, 2020 . This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in "Part I - Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year endedDecember 31, 2019 filed with theSEC onFebruary 21, 2020 and "Part II - Item 1A. Risk Factors" in this Quarterly Report on Form 10-Q. Additional information on forward-looking statements is discussed below in "Forward-Looking Statements." Unless the context requires otherwise, references to "we," "us," "our," the "Partnership" and "ET" meanEnergy Transfer LP (formerlyEnergy Transfer Equity, L.P. ) and its consolidated subsidiaries, which include ETO. References to the "Parent Company" meanEnergy Transfer LP on a stand-alone basis. RECENT DEVELOPMENTS COVID-19 In the first quarter of 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions. As a provider of critical energy infrastructure, our business has been designated as a "critical infrastructure sector" and our employees as "essential critical infrastructure workers" pursuant to theDepartment of Homeland Security Guidance on Essential Critical Infrastructure Workforce (s). To date, our field operations have continued largely uninterrupted, and remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the magnitude or duration of current and potential future COVID-19 mitigation measures. As an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities and we will continue to operate in accordance with federal and state health guidelines and safety protocols. We have implemented several new policies and provided employee training to help maintain the health and safety of our workforce. ET Contribution of SemGroup Assets to ETO OnDecember 5, 2019, ET completed the acquisition ofSemGroup . During the first quarter of2020, ET contributed certainSemGroup assets to ETO through sale and contribution transactions. ETO Series F and Series G Preferred Units Issuance OnJanuary 22, 2020 , ETO issued 500,000 of its Series F Preferred Units at a price of$1,000 per unit and 1,100,000 of its Series G Preferred Units at a price of$1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO's revolving credit facility and for general partnership purposes. ETOJanuary 2020 Senior Notes Offering and Redemption OnJanuary 22, 2020 , ETO completed a registered offering (the "January 2020 Senior Notes Offering") of$1.00 billion aggregate principal amount of the Partnership's 2.900% Senior Notes due 2025,$1.50 billion aggregate principal amount of the Partnership's 3.750% Senior Notes due 2030 and$2.00 billion aggregate principal amount of the Partnership's 5.000% Senior Notes due 2050 (collectively, the "Notes"). The Notes are fully and unconditionally guaranteed by the Partnership's wholly-owned subsidiary, Sunoco Logistics Operations, on a senior unsecured basis. Using proceeds from theJanuary 2020 Senior Notes Offering, ETO redeemed its$400 million aggregate principal amount of 5.75% Senior Notes dueSeptember 1, 2020 , its$1.05 billion aggregate principal amount of 4.15% Senior Notes dueOctober 1, 2020 , its$1.14 billion aggregate principal amount of 7.50% Senior Notes dueOctober 15, 2020 , its$250 million aggregate principal amount of 5.50% Senior Notes dueFebruary 15, 2020, ET 's$52 million aggregate principal amount of 7.50% Senior Notes dueOctober 15, 2020 and Transwestern's$175 million aggregate principal amount of 5.36% Senior Notes dueDecember 9, 2020 . 35
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Lake Charles LNG OnMarch 30, 2020 ,Shell Royal Dutch Plc announced that it would not proceed with a proposed equity interest in theLake Charles LNG liquefaction project due to adverse market factors affecting Shell's business and its desire to preserve cash in light of the current environment. We intend to continue to develop the project, possibly in conjunction with one or more equity partners, and we plan to evaluate a variety of alternatives to advance the project, including the possibility of reducing the size of the project from three trains (16.45 million tonnes per annum of LNG capacity) to two trains (11.0 million tonnes per annum). The project is fully permitted by federal, state and local authorities, has all necessary export licenses and benefits from the infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. In light of the existing brownfield infrastructure and the advanced state of the development of the project, we plan to continue to pursue the project on a disciplined, cost effective basis, and ultimately we will determine whether to make a final investment decision to proceed with the project based on market conditions, capital expenditure considerations and our success in securing equity participation by third parties as well as long-term LNG offtake commitments on satisfactory terms. Quarterly Cash Distribution InMarch 2020, ET announced its quarterly distribution of$0.3050 per unit ($1.22 annualized) on ET common units for the quarter endedMarch 31, 2020 . Regulatory Update Interstate Natural Gas Transportation Regulation Rate Regulation EffectiveJanuary 2018 , the 2017 Tax and Jobs Act (the "Tax Act") changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. OnMarch 15, 2018 , in a set of related proposals, theFERC addressed treatment of federal income tax allowances in regulated entity rates. TheFERC issued a Revised Policy Statement on Treatment of Income Taxes ("Revised Policy Statement") stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. TheFERC issued the Revised Policy Statement in response to a remand from theUnited States Court of Appeals for the District of Columbia Circuit in United Airlines v.FERC , in which the court determined that theFERC had not justified its conclusion that a pipeline organized as a master limited partnership would not "double recover" its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. OnJuly 18, 2018 , theFERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, theFERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors' income tax costs. In light of the rehearing order, the impacts of theFERC's policy on the treatment of income taxes may have on the rates ETO can charge for theFERC regulated transportation services are unknown at this time. TheFERC also issued a Notice of Inquiry ("2017 Tax Law NOI") onMarch 15, 2018 , requesting comments on the effect of the Tax Act onFERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to theFERC is whether, and if so how, theFERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or beforeMay 21, 2018 . InMarch 2019 , following the decision of the D.C. Circuit in Emera Maine v.Federal Energy Regulatory Commission , theFERC issued a Notice of Inquiry regarding its policy for determining return on equity ("ROE"). TheFERC specifically sought information and stakeholder views to help theFERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. TheFERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due inJune 2019 , and reply comments were due inJuly 2019 . TheFERC has not taken any further action with respect to the Notice of Inquiry as of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the future. By order issuedJanuary 16, 2019 , theFERC initiated a review ofPanhandle 's existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged byPanhandle are just and reasonable and set the matter for hearing.Panhandle filed a cost and revenue study onApril 1, 2019 .Panhandle filed a NGA Section 4 rate case onAugust 30, 2019 . Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, theFERC or our shippers may challenge the cost of service rates we charge. TheFERC's establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income 36
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taxes, while other pipeline costs also will continue to affect theFERC's determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such asETC Tiger Pipeline, LLC , MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern andPanhandle , have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from theMarch 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETO's cost of service components and the outcomes of any challenges to our rates by theFERC or our shippers. Pipeline Certification TheFERC issued a Notice of Inquiry onApril 19, 2018 ("Pipeline Certification NOI"), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or beforeJuly 25, 2018 . We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating inthe United States . Interstate Common Carrier Regulation TheFERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. TheFERC's indexing methodology is subject to review every five years. During the five-year period commencingJuly 1, 2016 and endingJune 30, 2021 , common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize theFERC liquids index to change transportation rates annually everyJuly 1 . With respect to liquids and refined products pipelines subject toFERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by theFERC in its next five year review of the liquids pipeline index to generate the index level to be effectiveJuly 1, 2021 , thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effectiveJuly 1, 2021 . TheFERC's establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect theFERC's determination of the appropriate pipeline index. Accordingly, depending on theFERC's application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates. Trends and Outlook Recent crude oil market disruptions involving foreign oil-producing nations and the COVID-19 pandemic may have a negative impact on our earnings and cash flows from operations. Reduced demand for natural gas, NGLs, refined products and/or crude oil caused by the COVID-19 pandemic and a continuation of low WTI crude oil prices caused by the actions of foreign oil-producing nations may result in the shut-in of production fromU.S. oil and gas wells, which in turn may result in decreased volumes transported on our pipeline systems and decreased overall utilization of our midstream services. With respect to commodity prices, natural gas prices have remained comparatively low in recent months as associated gas from shale oil resources has provided additional supply to the market. Meanwhile, crude oil prices have seen sharp declines as a result of actions by foreign oil-producing nations and a decrease in global demand as result of the COVID-19 pandemic. Global oil and natural gas demand growth is likely to remain flat or decline in the near term and will likely result in lowerU.S. production levels. The outlook for commodity prices is mixed and could have a varying impact on our business. Reduced demand and increased supply of crude oil has resulted in an increase in worldwide crude oil storage inventories, which is expected to keep crude oil prices suppressed for the foreseeable future. With respect to natural gas markets, a relatively more moderate decrease in demand, coupled with anticipated decreases in gas production associated with wells drilled to produce crude oil, have counterbalanced 37
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softness in pricing. The overall outlook for our midstream services will depend, in part, on the timing and extent of recovery in the commodity markets. While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the region, customer, type of service, contract term and other factors. As a result of the current commodity price environment, a small number of counterparties to our commercial contracts have made force majeure claims in an effort to terminate or modify existing agreements with us, and in the future we expect more counterparties to do the same. To the extent our counterparties are successful in those claims, we may not receive the full payments or other benefits of those contracts during the pendency of the force majeure event. While the vast majority of our counterparties are investment grade rated companies, some of our counterparties may be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court. In this case, we expect that we would attempt to negotiate replacement contracts with those counterparties and, depending on the availability of alternatives to our services, these contracts may have terms that are less favorable to us than the contracts rejected in bankruptcy court. Ultimately, the extent to which our business will be impacted by recent market developments depends on the factors described above as well as future developments beyond our control, which are highly uncertain and cannot be predicted. In response to these market events and uncertainties, we have cut our already reduced 2020 growth capital spending budget by$400 million and reduced planned operating expenses by$200 million to$250 million ; and we are prepared to cut spending further should the need arise. While current market volatility makes the near-term unpredictable, we believe that overall the long-term demand for our services will continue given the essential nature of the midstream natural gas, NGLs, refined products and crude oil business, although we cannot predict any possible changes in such demand with reasonable certainty. We currently have ample liquidity to fund our business and we do not anticipate any liquidity concerns in the immediate future (see "Liquidity and Capital Resources" below). In addition, while the trading price of ET common units declined significantly during the first quarter of 2020, thereby making equity capital market transactions less attractive in the near term, we continue to have access to the debt capital markets on generally favorable terms. In the event we seek additional equity or debt capital, our blended cost of capital for equity and debt is expected to be modestly higher in the near term; however, we will continue to evaluate growth projects and acquisitions as such opportunities may be identified in the future in light of this higher cost of capital. Results of Operations We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly. Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled "Segment Operating Results." Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership's fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. As discussed in Note 1 of the Partnership's consolidated financial statements included in "Item 1. Financial Statements," during the first quarter of 2020, the Partnership elected to change its inventory accounting policy related to certain barrels of crude oil that were previously accounting for as inventory. These changes have been applied retrospectively to all prior periods, and the prior period amounts reflected below have been adjusted from those amounts previously reported. 38
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Consolidated Results
Three Months Ended
March 31,
2020 2019* Change
Segment Adjusted EBITDA:
Intrastate transportation and storage $ 240 $ 252 $ (12 )
Interstate transportation and storage 404 456 (52 )
Midstream 383 382 1
NGL and refined products transportation and services 663 612 51
Crude oil transportation and services 591 744 (153 )
Investment in Sunoco LP 209 153 56
Investment in USAC 106 101 5
All other 39 35 4
Adjusted EBITDA (consolidated) 2,635 2,735 (100 )
Depreciation, depletion and amortization (867 ) (774 ) (93 )
Interest expense, net of interest capitalized (602 ) (590 ) (12 )
Impairment losses (1,325 ) (50 ) (1,275 )
Losses on interest rate derivatives (329 ) (74 ) (255 )
Non-cash compensation expense (22 ) (29 ) 7
Unrealized gains on commodity risk management activities 51
49 2
Losses on extinguishments of debt (62 ) (18 ) (44 )
Inventory valuation adjustments (227 ) 93 (320 )
Adjusted EBITDA related to unconsolidated affiliates (154 ) (146 ) (8 )
Equity in earnings (losses) of unconsolidated affiliates (7 ) 65 (72 )
Other, net (27 ) (17 ) (10 )
Income (loss) before income tax expense (936 ) 1,244 (2,180 )
Income tax expense (28 ) (126 ) 98
Net income (loss) $ (964 ) $ 1,118 $ (2,082 )
*As adjusted.
Adjusted EBITDA (consolidated). For the three months ended March 31, 2020
compared to the same period last year, Adjusted EBITDA decreased $100 million ,
or 4%. The decrease was primarily due to a net impact of $240 million from crude
oil, NGL and refined products inventory valuation adjustments ($213 million of
negative adjustments in the current period compared to $27 million of favorable
adjustments in the prior period). This decrease was partially offset by a net
increase of approximately $138 million in Adjusted EBITDA from recent
acquisitions and assets placed in service.
Additional discussion of these and other factors affecting Adjusted EBITDA is
included in the analysis of Segment Adjusted EBITDA in the "Segment Operating
Results" section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased for the three months ended March 31, 2020 compared to the
same period last year due to the acquisition of SemGroup on December 5, 2019 , as
well as incremental depreciation related to assets recently placed in service.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest
capitalized, increased for the three months ended March 31, 2020 compared to the
same period last year primarily due to the following:
• an increase of $7 million recognized by the Partnership primarily
attributable to the higher consolidated debt balance following the
acquisition and related debt refinancing, the impact of which was partially
offset by lower borrowing costs from floating rate debt;
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• an increase of
of interest expense incurred in the current period on its senior notes 2027
issued in
agreement, partially offset by the reduced borrowings and lower weighted
average interest rates under the credit agreement; and
• an increase of
Sunoco LP's total long-term debt.
Impairment Losses. During the three months endedMarch 31, 2020 , the Partnership performed an interim impairment test on certain reporting units within midstream, interstate, crude, NGL and all other operations. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of$483 million related to our Arklatex andSouth Texas operations within the midstream segment, a goodwill impairment of$183 million related to ourLake Charles LNG regasification operations with the interstate transportation and storage segment, and a goodwill impairment of$40 million related to our all other operations primarily due to decreases in projected future revenues and cash flows as a result of the overall market demand decline. In addition, USAC recognized a goodwill impairment of$619 million , during the three months endedMarch 31, 2020 , which is included in the Partnership's consolidated results of operations. During the three months endedMarch 31, 2019 , USAC recorded$3 million impairment of compression equipment as a result of its evaluations of the future deployment of USAC's idle fleet under then-current market conditions. Gains (Losses) on Interest Rate Derivatives. Losses on interest rate derivatives during the three months endedMarch 31, 2020 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value. Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in "Segment Operating Results" below. Losses on Extinguishments of Debt. During the three months endedMarch 31, 2020 , amounts were related to ETO senior notes redemption inJanuary 2020 . Inventory Valuation Adjustments. Inventory valuation adjustments were recorded for the inventory associated with Sunoco LP due to changes in fuel prices between periods. Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in "Supplemental Information on Unconsolidated Affiliates" and "Segment Operating Results" below. Other, net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts. Income Tax (Expense) Benefit. For the three months endedMarch 31, 2020 compared to the same period in the prior year, income tax expense decreased due to the recognition of a taxable gain on the sale of assets at our corporate subsidiaries in the prior period. 40
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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated
affiliates:
Three Months Ended
March 31,
2020 2019 Change
Equity in earnings (losses) of unconsolidated
affiliates:
Citrus $ 35 $ 32 $ 3
FEP (70 ) 14 (84 )
MEP - 7 (7 )
White Cliffs 8 - 8
Other 20 12 8Total equity in earnings (losses) of unconsolidated affiliates
$ (7 ) $
65
Adjusted EBITDA related to unconsolidated affiliates(1): Citrus$ 79 $ 81 $ (2 ) FEP 19 19 - MEP 8 19 (11 ) White Cliffs 14 - 14 Other 34 27 7 Total Adjusted EBITDA related to unconsolidated affiliates$ 154 $
146
Distributions received from unconsolidated affiliates: Citrus$ 49 $ 35 $ 14 FEP 18 17 1 MEP 11 11 - White Cliffs 13 - 13 Other 19 16 3 Total distributions received from unconsolidated affiliates$ 110 $ 79 $ 31 (1) These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or
losses of our unconsolidated affiliates adjusted for our proportionate share
of the unconsolidated affiliates' interest, depreciation, depletion,
amortization, non-cash items and taxes.
Segment Operating Results We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments. The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows: • Segment margin, operating expenses, and selling, general and administrative
expenses. These amounts represent the amounts included in our consolidated
financial statements that are attributable to each segment.
• Unrealized gains or losses on commodity risk management activities and
inventory valuation adjustments. These are the unrealized amounts that are
included in cost of products sold to calculate segment margin. These amounts
are not included in Segment Adjusted EBITDA; therefore, the unrealized losses
are added back and the unrealized gains are subtracted to calculate the
segment measure.
• Non-cash compensation expense. These amounts represent the total non-cash
compensation recorded in operating expenses and selling, general and
administrative expenses. This expense is not included in Segment Adjusted
EBITDA and therefore is added back to calculate the segment measure.
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• Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related
to unconsolidated affiliates excludes the same items with respect to the
unconsolidated affiliate as those excluded from the calculation of Segment
Adjusted EBITDA, such as interest, taxes, depreciation, depletion,
amortization and other non-cash items. Although these amounts are excluded
from Adjusted EBITDA related to unconsolidated affiliates, such exclusion
should not be understood to imply that we have control over the operations
and resulting revenues and expenses of such affiliates. We do not control our
unconsolidated affiliates; therefore, we do not control the earnings or cash
flows of such affiliates.
In the following analysis of segment operating results, a measure of segment
margin is reported for segments with sales revenues. Segment margin is a
non-GAAP financial measure and is presented herein to assist in the analysis of
segment operating results and particularly to facilitate an understanding of the
impacts that changes in sales revenues have on the segment performance measure
of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of
gross margin, except that segment margin excludes charges for depreciation,
depletion and amortization. Among the GAAP measures reported by the Partnership,
the most directly comparable measure to segment margin is Segment Adjusted
EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is
included in the following tables for each segment where segment margin is
presented.
In addition, for certain segments, the sections below include information on the
components of segment margin by sales type, which components are included in
order to provide additional disaggregated information to facilitate the analysis
of segment margin and Segment Adjusted EBITDA. For example, these components
include transportation margin, storage margin and other margin. These components
of segment margin are calculated consistent with the calculation of segment
margin; therefore, these components also exclude charges for depreciation,
depletion and amortization.
Intrastate Transportation and Storage
Three Months Ended
March 31,
2020 2019 Change
Natural gas transported (BBtu/d) 13,135 11,982 1,153
Withdrawals from storage natural gas inventory
(BBtu) 6,975 - 6,975
Revenues $ 593 $ 856 $ (263 )
Cost of products sold 303 572 (269 )
Segment margin 290 284 6
Unrealized (gains) losses on commodity risk
management activities (6 ) 10 (16 )
Operating expenses, excluding non-cash compensation expense
(41 ) (42 ) 1
Selling, general and administrative expenses,
excluding non-cash compensation expense (9 ) (6 ) (3 )
Adjusted EBITDA related to unconsolidated
affiliates 6 6 -
Segment Adjusted EBITDA $ 240 $ 252 $ (12 )
Volumes. For the three months ended March 31, 2020 compared to the same period
last year, transported volumes increased primarily due to increased utilization
of our Texas pipelines.
Segment Margin. The components of our intrastate transportation and storage
segment margin were as follows:
Three Months Ended
March 31,
2020 2019 Change
Transportation fees $ 161 $ 154 $ 7
Natural gas sales and other (excluding unrealized
gains and losses) 88 120 (32 )
Retained fuel revenues (excluding unrealized gains and losses)
9 11 (2 )
Storage margin (excluding unrealized gains and
losses) 26 9 17
Unrealized gains (losses) on commodity risk
management activities 6 (10 ) 16
Total segment margin $ 290 $ 284 $ 6
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Segment Adjusted EBITDA. For the three months endedMarch 31, 2020 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment decreased due to the net effects of the following: • a decrease of$32 million in realized natural gas sales and other primarily
due to lower realized gains from pipeline optimization activity;
• a decrease of
prices; and
• an increase of
primarily due to higher allocated corporate costs; partially offset by
• an increase of
storage optimization;
• an increase of
ramp-ups on the Red Bluff Express pipeline and new contracts; and
• a decrease of
cost of fuel consumption resulting from lower natural gas prices.
Interstate Transportation and Storage
Three Months Ended
March 31,
2020 2019 Change
Natural gas transported (BBtu/d) 10,630 11,532 (902 )
Natural gas sold (BBtu/d) 15 19 (4 )
Revenues $ 464 $ 498 $ (34 )
Operating expenses, excluding non-cash
compensation, amortization and accretion expenses (143 ) (146 ) 3
Selling, general and administrative expenses,
excluding non-cash compensation, amortization and
accretion expenses (21 ) (14 ) (7 )
Adjusted EBITDA related to unconsolidated
affiliates 106 119 (13 )
Other (2 ) (1 ) (1 )
Segment Adjusted EBITDA $ 404 $ 456 $ (52 )
Volumes. For the three months ended March 31, 2020 compared to the same period
last year, transported volumes decreased primarily due to lower utilization of
contracted capacity on our Panhandle and Trunkline pipelines.
Segment Adjusted EBITDA. For the three months ended March 31, 2020 compared to
the same period last year, Segment Adjusted EBITDA related to our interstate
transportation and storage segment decreased due to the net impacts of the
following:
• a decrease of $34 million in revenues primarily due to a $16 million decrease
resulting from a contractual rate adjustment on commitments at our Lake
Charles LNG facility and a
and volumes as a result of less favorable market conditions on our Rover,
• an increase of
primarily due to higher overhead costs; and
• a decrease of
affiliates primarily due to an
Express Pipeline joint venture as a result of less capacity sold and lower
rates received following the expiration of certain contracts and a
net decrease from our Citrus joint venture resulting from higher allocated
expenses; partially offset by
• a decrease of
valorem taxes.
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Midstream
Three Months Ended
March 31,
2020 2019 Change
Gathered volumes (BBtu/d) 13,346 12,718 628
NGLs produced (MBbls/d) 610 563 47
Equity NGLs (MBbls/d) 36 35 1
Revenues $ 1,170 $ 1,718 $ (548 )
Cost of products sold 575 1,141 (566 )
Segment margin 595 577 18Operating expenses, excluding non-cash compensation expense
(193 ) (183 ) (10 )
Selling, general and administrative expenses,
excluding non-cash compensation expense (26 ) (19 ) (7 )
Adjusted EBITDA related to unconsolidated
affiliates 7 6 1
Other - 1 (1 )
Segment Adjusted EBITDA $ 383 $ 382 $ 1
Volumes. Gathered volumes increased during the three months ended March 31, 2020
compared to the same period last year primarily due to increases in the
Mid-Continent/Panhandle , Ark-La-Tex , Permian, South Texas and Northeast regions.
NGL production increased due to increases in the Permian and
Mid-Continent/Panhandle region, partially offset by ethane rejection in the
South Texas region.
Segment Margin. The table below presents the components of our midstream segment
margin. For the prior period included in the table below, the amounts previously
reported for fee-based and non-fee-based margin have been adjusted to reflect
reclassification of certain contractual minimum fees in order to conform to the
current period classification:
Three Months Ended
March 31,
2020 2019 Change
Gathering and processing fee-based revenues$ 530 $ 502 $ 28 Non-fee-based contracts and processing 65 75 (10 ) Total segment margin$ 595 $ 577 $ 18
Segment Adjusted EBITDA. For the three months ended
Permian, Mid-Continent/
• an increase of
throughput volume in the Permian region; partially offset by
• a decrease of
• an increase of
million in maintenance project costs and
• an increase of
to an increase in overhead costs allocated to the segment.
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NGL and Refined Products Transportation and Services
Three Months Ended
March 31,
2020 2019 Change
NGL transportation volumes (MBbls/d) 1,398 1,178 220 Refined products transportation volumes (MBbls/d) 533 617 (84 ) NGL and refined products terminal volumes (MBbls/d) 847 777 70 NGL fractionation volumes (MBbls/d) 804 678 126 Revenues$ 2,715 $ 3,031 $ (316 ) Cost of products sold 1,836 2,326 (490 ) Segment margin 879 705 174 Unrealized (gains) losses on commodity risk management activities (55 )
57 (112 ) Operating expenses, excluding non-cash compensation expense
(159 ) (149 ) (10 )
Selling, general and administrative expenses,
excluding non-cash compensation expense (25 ) (19 ) (6 )
Adjusted EBITDA related to unconsolidated
affiliates 23 18 5
Segment Adjusted EBITDA $ 663 $ 612 $ 51
Volumes. For the three months ended March 31, 2020 compared to the same period
last year, throughput barrels on our Texas NGL pipeline system increased due to
higher receipt of liquids production from both wholly-owned and third-party gas
plants primarily in the Permian and North Texas regions. In addition, NGL
transportation volumes increased on our Mariner East pipeline system.
Refined products transportation volumes decreased for the three months ended
March 31, 2020 compared to the same period last year due to the closure of a
third-party refinery during the third quarter of 2019 and various turnarounds
performed at third party refineries, which negatively impacted supply to our
refined products transportation system. These decreases in volumes were
partially offset by the initiation of service on our JC Nolan diesel fuel
pipeline in the third quarter of 2019.
NGL and refined products terminal volumes increased for the three months ended
March 31, 2020 compared to the same period last year primarily due to higher
volumes from our Mariner East system, the initiation of service on our JC Nolan
diesel fuel pipeline in the third quarter of 2019, additional cargoes shipped
out of our Nederland terminal, and the initiation of natural gasoline exports in
July of 2019. These increases were partially offset by the closure of a
third-party refinery during the third quarter of 2019 and various turnarounds
performed at third-party refineries. For the three months ended March 31, 2019 ,
NGL and refined products terminal volumes have been adjusted from amounts
previously reported to be consistent with the current period presentation;
specifically, those volumes were adjusted to exclude terminal volumes for which
fees are attributable to storage capacity rather than terminal throughput.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility
increased 19% for the three months ended March 31, 2020 compared to the same
period last year primarily due to the commissioning of our sixth and seventh
fractionators in February 2019 and February 2020 , respectively.
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Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
Three Months Ended
March 31,
2020 2019 Change
Transportation margin $ 476 $ 363 $ 113
Fractionators and refinery services margin 179 168 11
Terminal services margin 151 135 16
Storage margin 63 56 7
Marketing margin (45 ) 40 (85 )
Unrealized gains (losses) on commodity risk
management activities 55 (57 ) 112
Total segment margin $ 879 $ 705 $ 174
Segment Adjusted EBITDA. For the three months ended March 31, 2020 compared to
the same period last year, Segment Adjusted EBITDA related to our NGL and
refined products transportation and services segment increased due to the net
impacts of the following:
• an increase of $113 million in transportation margin primarily due to a $74 million increase from higher throughput volumes on our
system, a
the Permian region on our Texas NGL pipelines, a
the initiation of service on our JC Nolan diesel fuel pipeline in the third
quarter of 2019, and a
from the Barnett region. These increases were partially offset by a
million decrease resulting from the closure of a third-party refinery during
the third quarter of 2019;
• an increase of
partially offset by a
refinery;
• an increase of
primarily due to a
and seventh fractionators in
and higher NGL volumes from the Permian region feeding our
fractionation facility; and
• an increase of
increase in fees generated from exported volumes and a
from higher throughput; partially offset by
• a decrease of
decrease from inventory valuation adjustments and a
capacity lease fees incurred by our marketing affiliate on our
pipeline system;
• an increase of
totaling
well as an increase in throughput volumes, partially offset by a
decrease in power costs; and
• an increase of
primarily due to a
segment.
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Crude Oil Transportation and Services
Three Months Ended
March 31,
2020 2019 Change
Crude transportation volumes (MBbls/d) 4,454 4,048 406
Crude terminals volumes (MBbls/d) 2,996 2,560 436
Revenues $ 4,213 $ 4,186 $ 27
Cost of products sold 3,458 3,162 296
Segment margin 755 1,024 (269 )
Unrealized (gains) losses on commodity risk
management activities 10 (109 ) 119 Operating expenses, excluding non-cash compensation expense
(158 ) (150 ) (8 )
Selling, general and administrative expenses,
excluding non-cash compensation expense (28 ) (20 ) (8 )
Adjusted EBITDA related to unconsolidated affiliates 12 (2 ) 14
Other - 1 (1 )
Segment Adjusted EBITDA $ 591 $ 744 $ (153 )
Volumes. For the three and nine months ended March 31, 2020 compared to the same
periods last year, crude transportation and terminal volumes benefited from an
increase in barrels through our existing Texas pipelines, our Bakken pipeline,
the initiation of service on phase 2 of our Bayou Bridge pipeline in the second
quarter of 2019, as well as the acquisition of pipeline assets during the fourth
quarter of 2019. For the three months ended March 31, 2019 , certain volumes have
been reclassified from crude transportation volumes to crude terminal volumes to
be consistent with the current period presentation.
Segment Adjusted EBITDA. For the three months ended March 31, 2020 compared to
the same period last year, Segment Adjusted EBITDA related to our crude oil
transportation and services segment decreased due to the net impacts of the
following:
• a decrease of $150 million in segment margin (excluding unrealized gains and
losses on commodity risk management activities) primarily due to a
million decrease (excluding a net change of
and losses on commodity risk management activities) from our crude oil
acquisition and marketing business that was primarily from inventory
valuation adjustments (a loss of
to a gain of
our
partially offset by a
primarily due to assets acquired in 2019, a
higher volumes on our Bakken Pipeline, and an
higher volumes on our Bayou Bridge Pipeline;
• an increase of
related to assets acquired in 2019, partly offset by lower crude trucking
expenses; and
• an increase of
primarily due to a
increase in costs related to assets acquired in 2019, and a
increase in legal expenses; partially offset by
• an increase of
affiliates due to assets acquired in 2019 and improved jet fuels sales by our
joint ventures.
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Investment in Sunoco LP
Three Months Ended
March 31,
2020 2019 Change
Revenues $ 3,272 $ 3,692 $ (420 )
Cost of products sold 3,164 3,322 (158 )
Segment margin 108 370 (262 )
Unrealized (gains) losses on commodity risk
management activities 6 (6 ) 12 Operating expenses, excluding non-cash compensation expense
(109 ) (98 ) (11 )
Selling, general and administrative expenses,
excluding non-cash compensation expense (30 ) (24 ) (6 )
Adjusted EBITDA related to unconsolidated
affiliates 2 - 2
Inventory valuation adjustments 227 (93 ) 320
Other 5 4 1
Segment Adjusted EBITDA $ 209 $ 153 $ 56
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco
LP.
Segment Adjusted EBITDA. For the three months ended March 31, 2020 compared to
the same period last year, Segment Adjusted EBITDA related to our investment in
Sunoco LP segment increased due to the net impacts of the following:
• an increase of $70 million in gross profit on motor fuel sales, primarily due
to a 32.6% increase in gross profit per gallon sold and the receipt of a
million make-up payment under a fuel supply agreement; partially offset by a
2.2% decrease in gallons sold;
• an increase in non-motor fuel sales gross profit of
• an increase in unconsolidated affiliate adjusted EBITDA of
partially offset by
• an increase of
administrative expenses, excluding non-cash compensation, primarily
attributable to a
Sunoco LP's accounts receivable in connection with the financial impact from COVID-19. Investment in USAC Three Months Ended March 31, 2020 2019 Change Revenues$ 179 $ 171 $ 8 Cost of products sold 24 22 2 Segment margin 155 149 6
Operating expenses, excluding non-cash compensation expense
(35 ) (35 ) -
Selling, general and administrative expenses,
excluding non-cash compensation expense (14 ) (13 ) (1 )
Segment Adjusted EBITDA $ 106 $ 101 $ 5
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended March 31, 2020 compared to
the same period last year, Segment Adjusted EBITDA related to our investment in
USAC segment increased due to the net impacts of the following:
• an increase of $6 million in segment margin primarily due to an increase
revenues as a result of the increase in average revenue generating
horsepower; partially offset by
• an increase of
primarily due to an increase in the provision for expected credit losses.
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All Other
Three Months Ended
March 31,
2020 2019 Change
Revenues $ 513 $ 497 $ 16
Cost of products sold 415 455 (40 )
Segment margin 98 42 56
Unrealized gains on commodity risk management
activities (5 ) (1 ) (4 )
Operating expenses, excluding non-cash compensation expense
(38 ) (7 ) (31 )
Selling, general and administrative expenses,
excluding non-cash compensation expense (35 ) (11 ) (24 )
Adjusted EBITDA related to unconsolidated
affiliates - (1 ) 1
Other and eliminations 19 13 6
Segment Adjusted EBITDA $ 39 $ 35 $ 4 Amounts reflected in our all other segment primarily include: • our natural gas marketing operations;
• our wholly-owned natural gas compression operations;
• a noncontrolling interest in PES. Prior to PES's reorganization in August
2018, ETO's 33% interest in PES was reflected as an unconsolidated affiliate;
subsequent to the
interest in PES and no longer reflects PES as an affiliate; and
• our investment in coal handling facilities; and
• our Canadian operations, which were acquired in the
Segment Adjusted EBITDA. For the three months ended
• an increase of
ownership of PES; and
• an increase of
• a decrease of
• a decrease of
our compression services business;
• a decrease of
business;
• a decrease of
resulting from lower cost recoveries and higher allocated costs;
• a decrease of
• a decrease of
amounts, the net impacts of which are reflected in the all other segment; and
• a decrease of
LIQUIDITY AND CAPITAL RESOURCES OverviewThe Parent Company's principal sources of cash flow are derived from distributions related to its investment in ETO, which derives its cash flows from its subsidiaries, including ETO's investments in Sunoco LP and USAC.The Parent Company's primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners.The Parent Company currently expects to fund its short-term needs for such items with cash flows 49
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from its direct and indirect investments in ETO.The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.The Parent Company expects ETO and its respective subsidiaries and investments in Sunoco LP and USAC to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes. Our ability to satisfy obligations and pay distributions to unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management's control. We currently expect capital expenditures in 2020 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC): Growth Maintenance Low High Low High Intrastate transportation and storage$ 10 $ 20 $ 40 $ 45 Interstate transportation and storage (1) 75 100 125 130 Midstream 400 425 105 110 NGL and refined products transportation and services 2,550 2,700 85 95 Crude oil transportation and services (1) 275 300 140 150 All other (including eliminations) 75 100 55 60 Total capital expenditures$ 3,385 $ 3,645 $ 550 $ 590
(1) Includes capital expenditures related to our proportionate ownership of the
Bakken, Rover and
The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of factors, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control; however, we have included these factors in our anticipated growth capital expenditures for each year. We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally fund growth capital expenditures with borrowings under credit facilities, long-term debt, the issuance of additional preferred units or a combination thereof. Sunoco LP Sunoco LP currently expects to spend approximately$30 million on growth capital and$75 million on maintenance capital for the full year 2020. USAC USAC currently plans to spend approximately$30 million in maintenance capital expenditures during 2020, including parts consumed from inventory. Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between$80 million and$90 million in expansion capital expenditures during 2020. As ofMarch 31, 2020 , USAC has binding commitments to purchase$34 million of additional compression units and serialized parts, all of which USAC expects to be delivered throughout 2020. Cash Flows Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of our subsidiaries' products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors. 50
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Operating Activities Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in "Results of Operations" above), excluding the impacts of non-cash items and changes in operating assets and liabilities (net of effects of acquisitions). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when ETO has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchases and sales of inventories and the timing of advances and deposits received from customers. Three months endedMarch 31, 2020 compared to three months endedMarch 31, 2019 . Cash provided by operating activities during 2020 was$1.82 billion as compared to$1.82 billion for 2019, and net loss was$964 million for 2020 and net income was$1.12 billion for 2019. The difference between net loss and net cash provided by operating activities for the three months endedMarch 31, 2020 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of$164 million and other non-cash items totaling$2.56 billion . The non-cash activity in 2020 and 2019 consisted primarily of depreciation, depletion and amortization of$867 million and$774 million , respectively, non-cash compensation expense of$22 million and$29 million , respectively, inventory valuation adjustments of$227 million and$93 million , respectively, and deferred income taxes of$42 million and$98 million , respectively. Non-cash activity also included losses on extinguishments of debt in 2020 and 2019 of$62 million and$18 million , respectively, impairment losses of$1,325 million and$50 million in 2020 and 2019, respectively. Unconsolidated affiliate activity in 2020 consisted of equity in losses of$7 million and equity in earnings of$65 million in 2019. Cash distributions were received in 2020 and 2019 of$58 million and$66 million , respectively. Cash paid for interest, net of interest capitalized, was$535 million and$638 million for the three months endedMarch 31, 2020 and 2019, respectively. Interest capitalized was$38 million and$43 million for the three months endedMarch 31, 2020 and 2019, respectively. Investing Activities Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions to our joint ventures, and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership's investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects. Three months endedMarch 31, 2020 compared to three months endedMarch 31, 2019 . Cash used in investing activities during 2020 was$1.56 billion as compared to$1.10 billion for 2019. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2020 were$1.60 billion compared to$1.14 billion for 2019. Additional detail related to our capital expenditures is provided in the table below. During 2019, we received$93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary and paid$5 million in cash for all other acquisitions. 51
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The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover andBayou Bridge pipeline projects and net of contributions in aid of construction costs) for the three months endedMarch 31, 2020 : Capital
Expenditures Recorded During Period
Growth Maintenance Total
Intrastate transportation and storage $ 2 $ 24 $ 26
Interstate transportation and storage 8 7 15
Midstream 128 23 151
NGL and refined products transportation and services 774 16 790
Crude oil transportation and services 83 12 95
Investment in Sunoco LP 36 5 41
Investment in USAC 47 9 56
All other (including eliminations) 24 7 31
Total capital expenditures $ 1,102 $ 103 $ 1,205
Financing Activities
Changes in cash flows from financing activities between periods primarily result
from changes in the levels of borrowings and equity issuances, which are
primarily used to fund our acquisitions and growth capital expenditures.
Distributions increase between the periods based on increases in the number of
common units outstanding or increases in the distribution rate.
Three months ended March 31, 2020 compared to three months ended March 31, 2019 .
Cash used in financing activities during 2020 was $354 million as compared to
$607 million for 2019. During 2020, our subsidiaries received $1.58 billion in
net proceeds from offerings of preferred units. During 2020, we had a net
decrease in our debt level of $764 million compared to a net increase of
$562 million for 2019. In 2020 and 2019, we paid debt issuance costs of $51
million and $84 million , respectively.
In 2020 and 2019, we paid distributions of $770 million and $800 million ,
respectively, to our partners. In 2020 and 2019, we paid distributions of
$444 million and $425 million , respectively, to noncontrolling interests. In
addition, we received capital contributions of $95 million in cash from
noncontrolling interests in 2020 compared to $140 million in cash from
noncontrolling interests in 2019.
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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
March 31, 2020 December 31, 2019
Parent Company Indebtedness:
ET Senior Notes due October 2020 $ - $ 52
ET Senior Notes due March 2023 5 5
ET Senior Notes due January 2024 23 23
ET Senior Notes due June 2027 44 44
Subsidiary Indebtedness:
ETO Senior Notes 37,782 36,118
Transwestern Senior Notes 400 575
Panhandle Senior Notes 235 235
Bakken Senior Notes 2,500 2,500
Sunoco LP Senior Notes and lease-related obligations 2,932 2,935
USAC Senior Notes 1,475 1,475
Credit facilities and commercial paper:
ETO $2.00 billion Term Loan facility due October 2022 2,000 2,000
ETO
1,955 4,214
Sunoco LP
265 162
USAC
459 403
HFOTCO Tax Exempt Notes due 2050 225 225
SemCAMS Revolver due February 2024 88 92
SemCAMS Term Loan A due February 2024 244 269
Other long-term debt 13 2
Net unamortized premiums, discounts, and fair value
adjustments (10 ) 4
Deferred debt issuance costs (303 ) (279 )
Total debt 50,332 51,054
Less: current maturities of long-term debt 33 26
Long-term debt, less current maturities $ 50,299 $ 51,028
(1) Includes
Recent Transactions ETOJanuary 2020 Senior Notes Offering and Redemption OnJanuary 22, 2020 , ETO completed a registered offering (the "January 2020 Senior Notes Offering") of$1.00 billion aggregate principal amount of the Partnership's 2.900% Senior Notes due 2025,$1.50 billion aggregate principal amount of the Partnership's 3.750% Senior Notes due 2030 and$2.00 billion aggregate principal amount of the Partnership's 5.000% Senior Notes due 2050 (collectively, the "Notes"). The Notes are fully and unconditionally guaranteed by the Partnership's wholly-owned subsidiary,Sunoco Logistics Partners Operations L.P. , on a senior unsecured basis. Utilizing proceeds from theJanuary 2020 Senior Notes Offering, ETO redeemed its$400 million aggregate principal amount of 5.75% Senior Notes dueSeptember 1, 2020 , its$1.05 billion aggregate principal amount of 4.15% Senior Notes dueOctober 1, 2020 , its$1.14 billion aggregate principal amount of 7.50% Senior Notes dueOctober 15, 2020 , its$250 million aggregate principal amount of 5.50% Senior Notes dueFebruary 15, 2020, ET 's$52 million aggregate principal amount of 7.50% Senior Notes dueOctober 15, 2020 and Transwestern's$175 million aggregate principal amount of 5.36% Senior Notes dueDecember 9, 2020 . 53
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Credit Facilities and Commercial Paper ETO Term Loan ETO's term loan credit agreement provides for a$2 billion three-year term loan credit facility (the "ETO Term Loan"). Borrowings under the term loan agreement mature onOctober 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Operations. As ofMarch 31, 2020 , the ETO Term Loan had$2 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as ofMarch 31, 2020 was 1.92%. ETO Five-Year Credit Facility ETO's revolving credit facility (the "ETO Five-Year Credit Facility") allows for unsecured borrowings up to$5.00 billion and matures onDecember 1, 2023 . The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to$6.00 billion under certain conditions. As ofMarch 31, 2020 , the ETO Five-Year Credit Facility had$1.96 billion of outstanding borrowings,$113 million of which was commercial paper. The amount available for future borrowings was$2.97 billion after taking into account letters of credit of$72 million . The weighted average interest rate on the total amount outstanding as ofMarch 31, 2020 was 2.24%. ETO 364-Day Facility ETO's 364-day revolving credit facility (the "ETO 364-Day Facility") allows for unsecured borrowings up to$1.00 billion and matures onNovember 27, 2020 . As ofMarch 31, 2020 , the ETO 364-Day Facility had no outstanding borrowings. Sunoco LP Credit Facility Sunoco LP maintains a$1.50 billion revolving credit facility (the "Sunoco LP Credit Facility"), which matures inJuly 2023 . As ofMarch 31, 2020 , the Sunoco LP Credit Facility had$265 million of outstanding borrowings and$8 million in standby letters of credit. As ofMarch 31, 2020 Sunoco LP had$1.23 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as ofMarch 31, 2020 was 2.63%. USAC Credit Facility USAC maintains a$1.60 billion revolving credit facility (the "USAC Credit Facility"), with a further potential increase of$400 million , which matures inApril 2023 . As ofMarch 31, 2020 , the USAC Credit Facility had$459 million of outstanding borrowings and no outstanding letters of credit. As ofMarch 31, 2020 , USAC had$1.14 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of$186 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as ofMarch 31, 2020 was 3.67%. Covenants Related to Our Credit Agreements We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as ofMarch 31, 2020 . CASH DISTRIBUTIONS Cash Distributions Paid by the Parent Company Under the Parent Company partnership agreement, the Parent Company will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for future cash requirements. Distributions declared and/or paid subsequent toDecember 31, 2019 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2019 February 7, 2020 February 19, 2020$ 0.3050 March 31, 2020 May 7, 2020 May 19, 2020 0.3050 54
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Cash Distributions Paid by Subsidiaries ETO, Sunoco LP and USAC are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners. Cash Distributions Paid by ETO Distributions on ETO preferred units declared and/or paid by ETO subsequent toDecember 31, 2019 were as follows: Period Ended Record Date Payment Date Series A (1) Series B (1) Series C Series D Series E Series F (2) Series G (2) December 31, 2019 February 3, 2020 February 18, 2020$ 31.25 $ 33.125 $ 0.4609 $ 0.4766 $ 0.4750 $ - $ - March 31, 2020 May 1, 2020 May 15, 2020 - - 0.4609 0.4766 0.4750 21.19 22.36
(1) ETO Series A Preferred Unit and ETO Series B Preferred Unit distributions
are paid on a semi-annual basis.
(2) ETO Series F and G Preferred Unit distributions related to the period ended
paid on a semi-annual basis.
Cash Distributions Paid by Sunoco LP
Distributions declared and/or paid by Sunoco LP subsequent to its common
unitholders
Quarter Ended Record Date Payment Date Rate
Cash Distributions Paid by USAC Distributions declared and/or paid by USAC to its common unitholders subsequent toDecember 31, 2019 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2019 January 27, 2020 February 7, 2020$ 0.5250 March 31, 2020 April 27, 2020 May 8, 2020 0.5250 ESTIMATES AND CRITICAL ACCOUNTING POLICIES The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership's Annual Report on Form 10-K filed with theSEC onFebruary 21, 2020 . See Note 1 in "Item 1. Financial Statements" for information regarding recent changes to the Partnership's critical accounting policies related to inventory. RECENT ACCOUNTING PRONOUNCEMENTS Currently, there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on the Partnership's financial position or results of operations. FORWARD-LOOKING STATEMENTS This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of ourGeneral Partner , as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as "anticipate," "project," "expect," "plan," "goal," "forecast," "estimate," "intend," "could," "believe," "may," "will" and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and ourGeneral Partner believe that the expectations on which such forward-looking statements are 55
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based are reasonable, neither we nor ourGeneral Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: • changes in the long-term supply of and demand for natural gas, NGLs, refined
products and/or crude oil, including as a result of uncertainty regarding the
length of time it will take for
to slow the spread of the COVID-19 virus to the point where applicable
authorities are comfortable easing current restrictions on various commercial
and economic activities; such restrictions are designed to protect public
health but also have the effect of reducing demand for natural gas, NGLs,
refined products and crude oil;
• the severity and duration of world health events, including the recent
COVID-19 pandemic, related economic repercussions, actions taken by
governmental authorities and other third parties in response to the pandemic
and the resulting severe disruption in the oil and gas industry and negative
impact on demand for natural gas, NGLs, refined products and crude oil, which
may negatively impact our business;
• changes in general economic conditions and changes in economic conditions of
the crude oil and natural gas industries specifically, including the current
significant surplus in the supply of oil and actions by foreign oil-producing
nations with respect to oil production levels and announcements of potential
changes in such levels, including the ability of those countries to agree on
and comply with supply limitation;
• uncertainty regarding the timing, pace and extent of an economic recovery in
natural gas, NGLs, refined products and crude oil and therefore the demand
for midstream services we provide and the commercial opportunities available
to us;
• the deterioration of the financial condition of our customers and the
potential renegotiation or termination of customer contracts as a result of
such deterioration;
• operational challenges relating to the COVID-19 pandemic and efforts to
mitigate the spread of the virus, including logistical challenges, protecting
the health and well-being of our employees, remote work arrangements,
performance of contracts and supply chain disruptions;
• actions taken by federal, state or local governments to require producers of
natural gas, NGL, refined products and crude oil to proration or cut their
production levels as a way to address any excess market supply situations;
• the ability of our subsidiaries to make cash distributions to us, which is
dependent on their results of operations, cash flows and financial condition;
• the actual amount of cash distributions by our subsidiaries to us;
• the volumes transported on our subsidiaries' pipelines and gathering systems;
• the level of throughput in our subsidiaries' processing and treating
facilities;
• the fees our subsidiaries charge and the margins they realize for their
gathering, treating, processing, storage and transportation services;
• the prices and market demand for, and the relationship between, natural gas
and NGLs;
• energy prices generally;
• the prices of natural gas and NGLs compared to the price of alternative and
competing fuels;
• the general level of petroleum product demand and the availability and price
of NGL supplies;
• the level of domestic natural gas, NGL, refined products and crude oil
production;
• the availability of imported natural gas, NGLs, refined products and crude
oil;
• actions taken by foreign oil and gas producing nations;
• the political and economic stability of petroleum producing nations;
• the effect of weather conditions on demand for natural gas, NGLs, refined
products and crude oil;
• availability of local, intrastate and interstate transportation systems;
• the continued ability to find and contract for new sources of natural gas
supply;
• availability and marketing of competitive fuels;
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• the impact of energy conservation efforts;
• energy efficiencies and technological trends;
• governmental regulation and taxation;
• changes to, and the application of, regulation of tariff rates and
operational requirements related to our subsidiaries' interstate and
intrastate pipelines;
• hazards or operating risks incidental to the gathering, treating, processing
and transporting of natural gas and NGLs;
• competition from other midstream companies and interstate pipeline companies;
• loss of key personnel;
• loss of key natural gas producers or the providers of fractionation services;
• reductions in the capacity or allocations of third-party pipelines that
connect with our subsidiaries pipelines and facilities;
• the effectiveness of risk-management policies and procedures and the ability
of our subsidiaries liquids marketing counterparties to satisfy their
financial commitments;
• the nonpayment or nonperformance by our subsidiaries' customers;
• regulatory, environmental, political and legal uncertainties that may affect
the timing and cost of our subsidiaries' internal growth projects, such as
our subsidiaries' construction of additional pipeline systems;
• risks associated with the construction of new pipelines and treating and
processing facilities or additions to our subsidiaries' existing pipelines
and facilities, including difficulties in obtaining permits and rights-of-way
or other regulatory approvals and the performance by third-party contractors;
• the availability and cost of capital and our subsidiaries' ability to access
certain capital sources;
• a deterioration of the credit and capital markets;
• risks associated with the assets and operations of entities in which our
subsidiaries own less than a controlling interests, including risks related
to management actions at such entities that our subsidiaries may not be able
to control or exert influence;
• the ability to successfully identify and consummate strategic acquisitions at
purchase prices that are accretive to our financial results and to
successfully integrate acquired businesses;
• changes in laws and regulations to which we are subject, including tax,
environmental, transportation and employment regulations or new
interpretations by regulatory agencies concerning such laws and regulations;
and
• the costs and effects of legal and administrative proceedings.
Many of the foregoing risks and uncertainties are, and will be, heightened by the COVID-19 pandemic and any further worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q or our Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under "Item 1A. Risk Factors" in our Annual Report on Form 10-K and "Part II, Item 1A. Risk Factors" in this Quarterly Report on Form 10-Q. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
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