QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
ý | Accelerated filer | ☐ | ||
Non-accelerated filer | ¨ | Smaller reporting company | ||
Emerging growth company |
Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||
/d | per day | ||
AOCI | accumulated other comprehensive income (loss) | ||
BBtu | billion British thermal units | ||
Btu | British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content | ||
CDM | CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively | ||
Citrus | Citrus, LLC, which owns 100% of FGT | ||
DOJ | U.S. Department of Justice | ||
EPA | U.S. Environmental Protection Agency | ||
ETC Sunoco | ETC Sunoco Holdings LLC (formerly Sunoco, Inc.) | ||
ETO | Energy Transfer Operating, L.P. (formerly Energy Transfer Partners, L.P.) | ||
ETP GP | Energy Transfer Partners GP, L.P., the general partner of ETO | ||
ETO Series A Preferred Units | ETO’s 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
ETO Series B Preferred Units | ETO’s 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
ETO Series C Preferred Units | ETO’s 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
ETO Series D Preferred Units | ETO’s 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
ETO Series E Preferred Units | ETO’s 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units | ||
Exchange Act | Securities Exchange Act of 1934 | ||
FEP | Fayetteville Express Pipeline LLC | ||
FERC | Federal Energy Regulatory Commission | ||
FGT | Florida Gas Transmission Company, LLC | ||
GAAP | accounting principles generally accepted in the United States of America | ||
IDRs | incentive distribution rights | ||
Lake Charles LNG | Lake Charles LNG Company, LLC | ||
LIBOR | London Interbank Offered Rate | ||
MBbls | thousand barrels | ||
MEP | Midcontinent Express Pipeline LLC | ||
MTBE | methyl tertiary butyl ether | ||
NGL | natural gas liquid, such as propane, butane and natural gasoline | ||
NYMEX | New York Mercantile Exchange | ||
OSHA | Federal Occupational Safety and Health Act | ||
OTC | over-the-counter | ||
Panhandle | Panhandle Eastern Pipe Line Company, LP | ||
PES | Philadelphia Energy Solutions Refining and Marketing LLC | ||
Regency | Regency Energy Partners LP | ||
RIGS | Regency Interstate Gas LP | ||
Rover | Rover Pipeline LLC | ||
SEC | Securities and Exchange Commission | ||
SemGroup | SemGroup Corporation | ||
Series A Convertible Preferred Units | ET Series A convertible preferred units | ||
SPLP | Sunoco Pipeline L.P. | ||
Sunoco LP Series A Preferred Units | Sunoco LP Series A Preferred Units previously held by ET | ||
Sunoco R&M | Sunoco (R&M), LLC (formerly Sunoco, Inc. (R&M)) | ||
Southwest Gas | Pan Gas Storage LLC (d.b.a. Southwest Gas Storage Company) | ||
Transwestern | Transwestern Pipeline Company, LLC | ||
Trunkline | Trunkline Gas Company, LLC | ||
USAC | USA Compression Partners, LP | ||
USAC Preferred Units | USAC Series A Preferred Units |
September 30, 2019 | December 31, 2018 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | $ | |||||
Accounts receivable, net | |||||||
Accounts receivable from related companies | |||||||
Inventories | |||||||
Income taxes receivable | |||||||
Derivative assets | |||||||
Other current assets | |||||||
Total current assets | |||||||
Property, plant and equipment | |||||||
Accumulated depreciation and depletion | ( | ) | ( | ) | |||
Advances to and investments in unconsolidated affiliates | |||||||
Lease right-of-use assets, net | |||||||
Other non-current assets, net | |||||||
Intangible assets, net | |||||||
Goodwill | |||||||
Total assets | $ | $ |
September 30, 2019 | December 31, 2018 | ||||||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | $ | |||||
Accounts payable to related companies | |||||||
Derivative liabilities | |||||||
Operating lease current liabilities | |||||||
Accrued and other current liabilities | |||||||
Current maturities of long-term debt | |||||||
Total current liabilities | |||||||
Long-term debt, less current maturities | |||||||
Non-current derivative liabilities | |||||||
Non-current operating lease liabilities | |||||||
Deferred income taxes | |||||||
Other non-current liabilities | |||||||
Commitments and contingencies | |||||||
Redeemable noncontrolling interests | |||||||
Equity: | |||||||
Limited Partners: | |||||||
Common Unitholders | |||||||
General Partner | ( | ) | ( | ) | |||
Accumulated other comprehensive loss | ( | ) | ( | ) | |||
Total partners’ capital | |||||||
Noncontrolling interests | |||||||
Total equity | |||||||
Total liabilities and equity | $ | $ |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
REVENUES: | |||||||||||||||
Refined product sales | $ | $ | $ | $ | |||||||||||
Crude sales | |||||||||||||||
NGL sales | |||||||||||||||
Gathering, transportation and other fees | |||||||||||||||
Natural gas sales | |||||||||||||||
Other | |||||||||||||||
Total revenues | |||||||||||||||
COSTS AND EXPENSES: | |||||||||||||||
Cost of products sold | |||||||||||||||
Operating expenses | |||||||||||||||
Depreciation, depletion and amortization | |||||||||||||||
Selling, general and administrative | |||||||||||||||
Impairment losses | |||||||||||||||
Total costs and expenses | |||||||||||||||
OPERATING INCOME | |||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||
Interest expense, net of interest capitalized | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Equity in earnings of unconsolidated affiliates | |||||||||||||||
Losses on extinguishments of debt | ( | ) | ( | ) | |||||||||||
Gains (losses) on interest rate derivatives | ( | ) | ( | ) | |||||||||||
Other, net | |||||||||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | |||||||||||||||
Income tax expense (benefit) from continuing operations | ( | ) | |||||||||||||
INCOME FROM CONTINUING OPERATIONS | |||||||||||||||
Loss from discontinued operations, net of income taxes | ( | ) | ( | ) | |||||||||||
NET INCOME | |||||||||||||||
Less: Net income attributable to noncontrolling interests | |||||||||||||||
Less: Net income attributable to redeemable noncontrolling interests | |||||||||||||||
NET INCOME ATTRIBUTABLE TO PARTNERS | |||||||||||||||
Series A Convertible Preferred Unitholders' interest in income | |||||||||||||||
General Partner’s interest in net income | |||||||||||||||
Limited Partners’ interest in net income | $ | $ | $ | $ | |||||||||||
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | |||||||||||||||
Basic | $ | $ | $ | $ | |||||||||||
Diluted | $ | $ | $ | $ | |||||||||||
NET INCOME PER LIMITED PARTNER UNIT: | |||||||||||||||
Basic | $ | $ | $ | $ | |||||||||||
Diluted | $ | $ | $ | $ |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Net income | $ | $ | $ | $ | |||||||||||
Other comprehensive income, net of tax: | |||||||||||||||
Change in value of available-for-sale securities | |||||||||||||||
Actuarial gain (loss) related to pension and other postretirement benefit plans | ( | ) | ( | ) | |||||||||||
Change in other comprehensive income from unconsolidated affiliates | ( | ) | ( | ) | |||||||||||
( | ) | ||||||||||||||
Comprehensive income | |||||||||||||||
Less: Comprehensive income attributable to noncontrolling interests | |||||||||||||||
Less: Comprehensive income attributable to redeemable noncontrolling interests | |||||||||||||||
Comprehensive income attributable to partners | $ | $ | $ | $ |
Common Unitholders | General Partner | AOCI | Noncontrolling Interests | Total | |||||||||||||||
Balance, December 31, 2018 | $ | $ | ( | ) | $ | ( | ) | $ | $ | ||||||||||
Distributions to partners | ( | ) | ( | ) | ( | ) | |||||||||||||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||||||||||||||
Capital contributions from noncontrolling interests | |||||||||||||||||||
Sale of noncontrolling interest in subsidiary | |||||||||||||||||||
Other comprehensive income, net of tax | |||||||||||||||||||
Other, net | |||||||||||||||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | |||||||||||||||||||
Balance, March 31, 2019 | ( | ) | ( | ) | |||||||||||||||
Distributions to partners | ( | ) | ( | ) | ( | ) | |||||||||||||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||||||||||||||
Units issued | |||||||||||||||||||
Capital contributions from noncontrolling interests | |||||||||||||||||||
Subsidiary units issued for cash | |||||||||||||||||||
Other comprehensive income, net of tax | |||||||||||||||||||
Other, net | |||||||||||||||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | |||||||||||||||||||
Balance, June 30, 2019 | ( | ) | ( | ) | |||||||||||||||
Distributions to partners | ( | ) | ( | ) | |||||||||||||||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||||||||||||||
Units issued | |||||||||||||||||||
Capital contributions from noncontrolling interests | |||||||||||||||||||
Other comprehensive loss, net of tax | ( | ) | ( | ) | |||||||||||||||
Other, net | |||||||||||||||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | |||||||||||||||||||
Balance, September 30, 2019 | ( | ) | ( | ) |
Series A Convertible Preferred Units | Common Unitholders | General Partner | Noncontrolling Interests | Total | |||||||||||||||
Balance, December 31, 2017 | $ | $ | ( | ) | $ | ( | ) | $ | $ | ||||||||||
Distributions to partners | ( | ) | ( | ) | ( | ) | |||||||||||||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||||||||||||||
Distributions reinvested | ( | ) | |||||||||||||||||
Subsidiary units repurchased | ( | ) | ( | ) | ( | ) | |||||||||||||
Subsidiary units issued | |||||||||||||||||||
Capital contributions from noncontrolling interests | |||||||||||||||||||
Other comprehensive income, net of tax | |||||||||||||||||||
Cumulative effect adjustment due to change in accounting principle | ( | ) | ( | ) | |||||||||||||||
Other, net | ( | ) | ( | ) | ( | ) | |||||||||||||
Net income | |||||||||||||||||||
Balance, March 31, 2018 | ( | ) | ( | ) | |||||||||||||||
Distributions to partners | ( | ) | ( | ) | ( | ) | |||||||||||||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||||||||||||||
Distributions reinvested | ( | ) | |||||||||||||||||
Subsidiary units repurchased | ( | ) | ( | ) | |||||||||||||||
Subsidiary units issued | |||||||||||||||||||
Capital contributions from noncontrolling interests | |||||||||||||||||||
Other comprehensive income, net of tax | |||||||||||||||||||
Acquisition of USAC | |||||||||||||||||||
Series A Convertible Preferred Units conversion | ( | ) | |||||||||||||||||
Other, net | ( | ) | |||||||||||||||||
Net income | |||||||||||||||||||
Balance, June 30, 2018 | ( | ) | ( | ) | |||||||||||||||
Distributions to partners | ( | ) | ( | ) | ( | ) | |||||||||||||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||||||||||||||
Subsidiary units issued | |||||||||||||||||||
Capital contributions from noncontrolling interests | |||||||||||||||||||
Other comprehensive income, net of tax | |||||||||||||||||||
Other, net | |||||||||||||||||||
Net income, excluding amounts attributable to redeemable noncontrolling interests | |||||||||||||||||||
Balance, September 30, 2018 | $ | $ | ( | ) | $ | ( | ) | $ | $ |
Nine Months Ended September 30, | |||||||
2019 | 2018 | ||||||
OPERATING ACTIVITIES | |||||||
Net income | $ | $ | |||||
Reconciliation of net income to net cash provided by operating activities: | |||||||
Loss from discontinued operations | |||||||
Depreciation, depletion and amortization | |||||||
Deferred income taxes | |||||||
Inventory valuation adjustments | ( | ) | ( | ) | |||
Non-cash compensation expense | |||||||
Impairment losses | |||||||
Loss on extinguishments of debt | |||||||
Distributions on unvested awards | ( | ) | ( | ) | |||
Equity in earnings of unconsolidated affiliates | ( | ) | ( | ) | |||
Distributions from unconsolidated affiliates | |||||||
Other non-cash | ( | ) | |||||
Net change in operating assets and liabilities, net of effects of acquisitions | ( | ) | |||||
Net cash provided by operating activities | |||||||
INVESTING ACTIVITIES | |||||||
Cash proceeds from sale of noncontrolling interest in subsidiary | |||||||
Cash proceeds from USAC acquisition, net of cash received | |||||||
Cash paid for all other acquisitions, net of cash received | ( | ) | ( | ) | |||
Capital expenditures, excluding allowance for equity funds used during construction | ( | ) | ( | ) | |||
Contributions in aid of construction costs | |||||||
Contributions to unconsolidated affiliates | ( | ) | ( | ) | |||
Distributions from unconsolidated affiliates in excess of cumulative earnings | |||||||
Proceeds from the sale of other assets | |||||||
Other | ( | ) | |||||
Net cash used in investing activities | ( | ) | ( | ) | |||
FINANCING ACTIVITIES | |||||||
Proceeds from borrowings | |||||||
Repayments of debt | ( | ) | ( | ) | |||
Subsidiary units issued for cash | |||||||
Capital contributions from noncontrolling interests | |||||||
Distributions to partners | ( | ) | ( | ) | |||
Distributions to noncontrolling interests | ( | ) | ( | ) | |||
Distributions to redeemable noncontrolling interest | ( | ) | |||||
Subsidiary repurchases of common units | ( | ) | |||||
Debt issuance costs | ( | ) | ( | ) | |||
Other, net | ( | ) | |||||
Net cash used in financing activities | ( | ) | ( | ) | |||
DISCONTINUED OPERATIONS | |||||||
Operating activities | ( | ) | |||||
Investing activities | |||||||
Changes in cash included in current assets held for sale | |||||||
Net increase in cash and cash equivalents of discontinued operations | |||||||
Increase (decrease) in cash and cash equivalents | ( | ) | |||||
Cash and cash equivalents, beginning of period | |||||||
Cash and cash equivalents, end of period | $ | $ |
1. | ORGANIZATION AND BASIS OF PRESENTATION |
• | the IDRs in ETO were converted into |
• | the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued |
• | ET contributed its |
• | ET contributed its |
• | ET contributed its |
• | activities of the Parent Company; and |
• | certain operations and investments that are not separately reflected as reportable segments. |
• | the Parent Company; |
• | our controlled subsidiary, Energy Transfer Operating, L.P. (“ETO”); and |
• | ETP GP and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP. |
Balance at December 31, 2018, as previously reported | Adjustments due to Topic 842 (Leases) | Balance at January 1, 2019 | |||||||||
Assets: | |||||||||||
Property, plant and equipment, net | $ | $ | ( | ) | $ | ||||||
Lease right-of-use assets, net | |||||||||||
Liabilities: | |||||||||||
Operating lease current liabilities | $ | $ | $ | ||||||||
Accrued and other current liabilities | ( | ) | |||||||||
Current maturities of long-term debt | |||||||||||
Long-term debt, less current maturities | |||||||||||
Non-current operating lease liabilities | |||||||||||
Other non-current liabilities | ( | ) |
2. | ACQUISITIONS AND OTHER INVESTING TRANSACTIONS |
Three Months Ended September 30, 2018 | Nine Months Ended September 30, 2018 | ||||||
REVENUES | $ | $ | |||||
COSTS AND EXPENSES | |||||||
Cost of products sold | |||||||
Operating expenses | |||||||
Depreciation, depletion and amortization | |||||||
Impairment losses | |||||||
Selling, general and administrative | |||||||
Total costs and expenses | |||||||
OPERATING LOSS | ( | ) | |||||
Interest expense, net | ( | ) | |||||
Loss on extinguishment of debt and other | ( | ) | |||||
Other, net | ( | ) | |||||
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE | ( | ) | |||||
Income tax expense | |||||||
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES | $ | ( | ) | $ | ( | ) | |
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ET | $ | $ | ( | ) |
3. | CASH AND CASH EQUIVALENTS |
Nine Months Ended September 30, | |||||||
2019 | 2018 | ||||||
Accounts receivable | $ | ( | ) | $ | |||
Accounts receivable from related companies | ( | ) | |||||
Inventories | ( | ) | |||||
Other current assets | ( | ) | |||||
Other non-current assets, net | ( | ) | ( | ) | |||
Accounts payable | ( | ) | |||||
Accounts payable to related companies | ( | ) | ( | ) | |||
Accrued and other current liabilities | |||||||
Other non-current liabilities | ( | ) | |||||
Derivative assets and liabilities, net | |||||||
Net change in operating assets and liabilities, net of effects of acquisitions | $ | ( | ) | $ |
Nine Months Ended September 30, | |||||||
2019 | 2018 | ||||||
NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||||||
Accrued capital expenditures | $ | $ | |||||
Losses from subsidiary common unit transactions | ( | ) | |||||
Lease assets obtained in exchange for new lease liabilities | |||||||
NON-CASH FINANCING ACTIVITIES: | |||||||
Distribution reinvestment | $ | $ | |||||
Conversion of Series A Convertible Preferred Units to common units |
4. | INVENTORIES |
September 30, 2019 | December 31, 2018 | ||||||
Natural gas, NGLs and refined products | $ | $ | |||||
Crude oil | |||||||
Spare parts and other | |||||||
Total inventories | $ | $ |
5. | FAIR VALUE MEASURES |
Fair Value Measurements at September 30, 2019 | |||||||||||
Fair Value Total | Level 1 | Level 2 | |||||||||
Assets: | |||||||||||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | $ | $ | $ | ||||||||
Swing Swaps IFERC | |||||||||||
Fixed Swaps/Futures | |||||||||||
Forward Physical Contracts | |||||||||||
Power: | |||||||||||
Forwards | |||||||||||
Futures | |||||||||||
NGLs – Forwards/Swaps | |||||||||||
Refined Products – Futures | |||||||||||
Crude – Forwards/Swaps | |||||||||||
Total commodity derivatives | |||||||||||
Other non-current assets | |||||||||||
Total assets | $ | $ | $ | ||||||||
Liabilities: | |||||||||||
Interest rate derivatives | $ | ( | ) | $ | $ | ( | ) | ||||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | ( | ) | ( | ) | |||||||
Swing Swaps IFERC | ( | ) | ( | ) | |||||||
Fixed Swaps/Futures | ( | ) | ( | ) | |||||||
Forward Physical Contracts | ( | ) | ( | ) | |||||||
Power: | |||||||||||
Forwards | ( | ) | ( | ) | |||||||
Futures | ( | ) | ( | ) | |||||||
Options – Calls | ( | ) | ( | ) | |||||||
NGLs – Forwards/Swaps | ( | ) | ( | ) | |||||||
Refined Products – Futures | ( | ) | ( | ) | |||||||
Crude – Forwards/Swaps | ( | ) | ( | ) | |||||||
Total commodity derivatives | ( | ) | ( | ) | ( | ) | |||||
Total liabilities | $ | ( | ) | $ | ( | ) | $ | ( | ) |
Fair Value Measurements at December 31, 2018 | |||||||||||
Fair Value Total | Level 1 | Level 2 | |||||||||
Assets: | |||||||||||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | $ | $ | $ | ||||||||
Swing Swaps IFERC | |||||||||||
Fixed Swaps/Futures | |||||||||||
Forward Physical Contracts | |||||||||||
Power: | |||||||||||
Forwards | |||||||||||
Futures | |||||||||||
Options – Calls | |||||||||||
NGLs – Forwards/Swaps | |||||||||||
Refined Products – Futures | |||||||||||
Crude – Forwards/Swaps | |||||||||||
Total commodity derivatives | |||||||||||
Other non-current assets | |||||||||||
Total assets | $ | $ | $ | ||||||||
Liabilities: | |||||||||||
Interest rate derivatives | $ | ( | ) | $ | $ | ( | ) | ||||
Commodity derivatives: | |||||||||||
Natural Gas: | |||||||||||
Basis Swaps IFERC/NYMEX | ( | ) | ( | ) | |||||||
Swing Swaps IFERC | ( | ) | ( | ) | |||||||
Fixed Swaps/Futures | ( | ) | ( | ) | |||||||
Forward Physical Contracts | ( | ) | ( | ) | |||||||
Power: | |||||||||||
Forwards | ( | ) | ( | ) | |||||||
Futures | ( | ) | ( | ) | |||||||
NGLs – Forwards/Swaps | ( | ) | ( | ) | |||||||
Refined Products – Futures | ( | ) | ( | ) | |||||||
Crude – Forwards/Swaps | ( | ) | ( | ) | |||||||
Total commodity derivatives | ( | ) | ( | ) | ( | ) | |||||
Total liabilities | $ | ( | ) | $ | ( | ) | $ | ( | ) |
6. | NET INCOME PER LIMITED PARTNER UNIT |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Income from continuing operations | $ | $ | $ | $ | |||||||||||
Less: Income from continuing operations attributable to noncontrolling interests | |||||||||||||||
Less: Net income attributable to redeemable noncontrolling interests | |||||||||||||||
Income from continuing operations, net of noncontrolling interests | |||||||||||||||
Less: Series A Convertible Preferred Unitholders’ interest in income | |||||||||||||||
Less: General Partner’s interest in income | |||||||||||||||
Income from continuing operations available to Limited Partners | $ | $ | $ | $ | |||||||||||
Basic Income from Continuing Operations per Limited Partner Unit: | |||||||||||||||
Weighted average limited partner units | |||||||||||||||
Basic income from continuing operations per Limited Partner unit | $ | $ | $ | $ | |||||||||||
Basic income (loss) from discontinued operations per Limited Partner unit | $ | $ | $ | $ | ( | ) | |||||||||
Diluted Income from Continuing Operations per Limited Partner Unit: | |||||||||||||||
Income from continuing operations available to Limited Partners | $ | $ | $ | $ | |||||||||||
Dilutive effect of distributions to Series A Convertible Preferred Unitholders | |||||||||||||||
Diluted income from continuing operations available to Limited Partners | $ | $ | $ | $ | |||||||||||
Weighted average limited partner units | |||||||||||||||
Dilutive effect of Series A Convertible Preferred Units | |||||||||||||||
Dilutive effect of unvested unit awards | |||||||||||||||
Weighted average limited partner units, assuming dilutive effect of unvested unit awards | |||||||||||||||
Diluted income from continuing operations per Limited Partner unit | $ | $ | $ | $ | |||||||||||
Diluted income (loss) from discontinued operations per Limited Partner unit | $ | $ | $ | $ | ( | ) |
7. | DEBT OBLIGATIONS |
8. | REDEEMABLE NONCONTROLLING INTERESTS |
9. | EQUITY |
Nine Months Ended September 30, 2019 | ||
Number of Common Units, beginning of period | ||
Common Units issued in connection with the distribution reinvestment plan | ||
Common Units issued under equity incentive plans and other | ||
Number of Common Units, end of period |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2018 | February 8, 2019 | February 19, 2019 | $ | |||||
March 31, 2019 | May 7, 2019 | May 20, 2019 | ||||||
June 30, 2019 | August 6, 2019 | August 19, 2019 | ||||||
September 30, 2019 | November 5, 2019 | November 19, 2019 |
Period Ended | Record Date | Payment Date | Series A (1) | Series B (1) | Series C | Series D | Series E (2) | |||||||||||||||||
December 31, 2018 | February 1, 2019 | February 15, 2019 | $ | $ | $ | $ | $ | |||||||||||||||||
March 31, 2019 | May 1, 2019 | May 15, 2019 | ||||||||||||||||||||||
June 30, 2019 | August 1, 2019 | August 15, 2019 | ||||||||||||||||||||||
September 30, 2019 | November 1, 2019 | November 15, 2019 |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2018 | February 6, 2019 | February 14, 2019 | $ | |||||
March 31, 2019 | May 7, 2019 | May 15, 2019 | ||||||
June 30, 2019 | August 6, 2019 | August 14, 2019 | ||||||
September 30, 2019 | November 5, 2019 | November 19, 2019 |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2018 | January 28, 2019 | February 8, 2019 | $ | |||||
March 31, 2019 | April 29, 2019 | May 10, 2019 | ||||||
June 30, 2019 | July 29, 2019 | August 9, 2019 | ||||||
September 30, 2019 | October 28, 2019 | November 8, 2019 |
September 30, 2019 | December 31, 2018 | ||||||
Available-for-sale securities | $ | $ | |||||
Foreign currency translation adjustment | ( | ) | ( | ) | |||
Actuarial loss related to pensions and other postretirement benefits | ( | ) | ( | ) | |||
Investments in unconsolidated affiliates, net | ( | ) | |||||
Total AOCI, net of tax | $ | ( | ) | $ | ( | ) |
10. | INCOME TAXES |
11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
ROW expense | $ | $ | $ | $ |
• | certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. |
• | certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. |
• | legacy sites related to ETC Sunoco that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that ETC Sunoco no longer operates, closed and/or sold refineries and other formerly owned sites. |
• | ETC Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of September 30, 2019, ETC Sunoco had been named as a PRP at approximately |
September 30, 2019 | December 31, 2018 | ||||||
Current | $ | $ | |||||
Non-current | |||||||
Total environmental liabilities | $ | $ |
12. | REVENUE |
Contract Liabilities | |||
Balance, December 31, 2018 | $ | ||
Additions | |||
Revenue recognized | ( | ) | |
Balance, September 30, 2019 | $ | ||
Balance, January 1, 2018 | $ | ||
Additions | |||
Revenue recognized | ( | ) | |
Balance, September 30, 2018 | $ |
September 30, 2019 | December 31, 2018 | ||||||
Contract balances: | |||||||
Contract asset | $ | $ | |||||
Accounts receivable from contracts with customers |
Years Ending December 31, | ||||||||||||||||||||
2019 (remainder) | 2020 | 2021 | Thereafter | Total | ||||||||||||||||
Revenue expected to be recognized on contracts with customers existing as of September 30, 2019 | $ | $ | $ | $ | $ |
13. | LEASE ACCOUNTING |
September 30, 2019 | |||
Operating leases: | |||
Lease right-of-use assets, net | $ | ||
Operating lease current liabilities | |||
Accrued and other current liabilities | |||
Non-current operating lease liabilities | |||
Finance leases: | |||
Property, plant and equipment, net | $ | ||
Lease right-of-use assets, net | |||
Accrued and other current liabilities | |||
Current maturities of long-term debt | |||
Long-term debt, less current maturities | |||
Other non-current liabilities |
Income Statement Location | Three Months Ended September 30, 2019 | Nine Months Ended September 30, 2019 | ||||||||
Operating lease costs: | ||||||||||
Operating lease cost | Cost of goods sold | $ | $ | |||||||
Operating lease cost | Operating expenses | |||||||||
Operating lease cost | Selling, general and administrative | |||||||||
Total operating lease costs | ||||||||||
Finance lease costs: | ||||||||||
Amortization of lease assets | Depreciation, depletion and amortization | |||||||||
Interest on lease liabilities | Interest expense, net of capitalized interest | |||||||||
Total finance lease costs | ||||||||||
Short-term lease cost | Operating expenses | |||||||||
Variable lease cost | Operating expenses | |||||||||
Lease costs, gross | ||||||||||
Less: Sublease income | Other revenue | |||||||||
Lease costs, net | $ | $ |
September 30, 2019 | ||
Weighted-average remaining lease term (years): | ||
Operating leases | ||
Finance leases | ||
Weighted-average discount rate (%): | ||
Operating leases | % | |
Finance leases | % |
Nine Months Ended September 30, 2019 | |||
Operating cash flows from operating leases | $ | ( | ) |
Lease assets obtained in exchange for new finance lease liabilities | |||
Lease assets obtained in exchange for new operating lease liabilities |
Operating Leases | Finance Leases | Total | |||||||||
2019 (remainder) | $ | $ | $ | ||||||||
2020 | |||||||||||
2021 | |||||||||||
2022 | |||||||||||
2023 | |||||||||||
Thereafter | |||||||||||
Total lease payments | |||||||||||
Less: present value discount | |||||||||||
Present value of lease liabilities | $ | $ | $ |
Lease Receivables | |||
2019 (remainder) | $ | ||
2020 | |||
2021 | |||
2022 | |||
2023 | |||
Thereafter | |||
Total undiscounted cash flows | $ |
14. | DERIVATIVE ASSETS AND LIABILITIES |
September 30, 2019 | December 31, 2018 | ||||||||
Notional Volume | Maturity | Notional Volume | Maturity | ||||||
Mark-to-Market Derivatives | |||||||||
(Trading) | |||||||||
Natural Gas (BBtu): | |||||||||
Basis Swaps IFERC/NYMEX (1) | 2019-2024 | 2019-2020 | |||||||
Fixed Swaps/Futures | 2019-2020 | 2019 | |||||||
Options – Puts | — | 2019 | |||||||
Power (Megawatt): | |||||||||
Forwards | 2019-2029 | 2019 | |||||||
Futures | 2019-2020 | 2019-2021 | |||||||
Options – Puts | 2019-2020 | 2019 | |||||||
Options – Calls | ( | ) | 2019-2021 | 2019 | |||||
(Non-Trading) | |||||||||
Natural Gas (BBtu): | |||||||||
Basis Swaps IFERC/NYMEX | ( | ) | 2019-2022 | ( | ) | 2019-2021 | |||
Swing Swaps IFERC | 2019-2020 | 2019-2020 | |||||||
Fixed Swaps/Futures | 2019-2021 | ( | ) | 2019-2021 | |||||
Forward Physical Contracts | ( | ) | 2019-2021 | ( | ) | 2019-2020 | |||
NGLs (MBbls) – Forwards/Swaps | ( | ) | 2019-2021 | ( | ) | 2019 | |||
Refined Products (MBbls) – Futures | ( | ) | 2019-2021 | ( | ) | 2019 | |||
Crude (MBbls) – Forwards/Swaps | 2019-2020 | 2019 | |||||||
Corn (thousand bushels) | ( | ) | 2019 | ( | ) | 2019 | |||
Fair Value Hedging Derivatives | |||||||||
(Non-Trading) | |||||||||
Natural Gas (BBtu): | |||||||||
Basis Swaps IFERC/NYMEX | ( | ) | 2019-2020 | ( | ) | 2019 | |||
Fixed Swaps/Futures | ( | ) | 2019-2020 | ( | ) | 2019 | |||
Hedged Item – Inventory | 2019-2020 | 2019 |
(1) |
Term | Type(1) | Notional Amount Outstanding | ||||||||
September 30, 2019 | December 31, 2018 | |||||||||
July 2019(2) | $ | $ | ||||||||
July 2020(2) | ||||||||||
July 2021(2) | ||||||||||
July 2022(2) | ||||||||||
March 2019 |
(1) |
(2) |
Fair Value of Derivative Instruments | ||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||
September 30, 2019 | December 31, 2018 | September 30, 2019 | December 31, 2018 | |||||||||||||
Derivatives designated as hedging instruments: | ||||||||||||||||
Commodity derivatives (margin deposits) | $ | $ | $ | $ | ( | ) | ||||||||||
Derivatives not designated as hedging instruments: | ||||||||||||||||
Commodity derivatives (margin deposits) | ( | ) | ( | ) | ||||||||||||
Commodity derivatives | ( | ) | ( | ) | ||||||||||||
Interest rate derivatives | ( | ) | ( | ) | ||||||||||||
( | ) | ( | ) | |||||||||||||
Total derivatives | $ | $ | $ | ( | ) | $ | ( | ) |
Asset Derivatives | Liability Derivatives | |||||||||||||||||
Balance Sheet Location | September 30, 2019 | December 31, 2018 | September 30, 2019 | December 31, 2018 | ||||||||||||||
Derivatives without offsetting agreements | Derivative liabilities | $ | $ | $ | ( | ) | $ | ( | ) | |||||||||
Derivatives in offsetting agreements: | ||||||||||||||||||
OTC contracts | Derivative assets (liabilities) | ( | ) | ( | ) | |||||||||||||
Broker cleared derivative contracts | Other current assets (liabilities) | ( | ) | ( | ) | |||||||||||||
Total gross derivatives | ( | ) | ( | ) | ||||||||||||||
Offsetting agreements: | ||||||||||||||||||
Counterparty netting | Derivative assets (liabilities) | ( | ) | ( | ) | |||||||||||||
Counterparty netting | Other current assets (liabilities) | ( | ) | ( | ) | |||||||||||||
Total net derivatives | $ | $ | $ | ( | ) | $ | ( | ) |
Location of Gain Recognized in Income on Derivatives | Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||||
Derivatives in fair value hedging relationships (including hedged item): | |||||||||||||||||
Commodity derivatives | Cost of products sold | $ | $ | $ | $ |
Location of Gain (Loss) Recognized in Income on Derivatives | Amount of Gain (Loss) Recognized in Income on Derivatives | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||
Commodity derivatives – Trading | Cost of products sold | $ | $ | $ | $ | ||||||||||||
Commodity derivatives – Non-trading | Cost of products sold | ( | ) | ( | ) | ||||||||||||
Interest rate derivatives | Gains (losses) on interest rate derivatives | ( | ) | ( | ) | ||||||||||||
Total | $ | ( | ) | $ | $ | ( | ) | $ | ( | ) |
15. | RELATED PARTY TRANSACTIONS |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Revenues from related companies | $ | $ | $ | $ |
September 30, 2019 | December 31, 2018 | ||||||
Accounts receivable from related companies: | |||||||
FGT | $ | $ | |||||
Phillips 66 | |||||||
Traverse | |||||||
Other | |||||||
Total accounts receivable from related companies | $ | $ |
16. | REPORTABLE SEGMENTS |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Revenues: | |||||||||||||||
Intrastate transportation and storage: | |||||||||||||||
Revenues from external customers | $ | $ | $ | $ | |||||||||||
Intersegment revenues | |||||||||||||||
Interstate transportation and storage: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
Midstream: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
NGL and refined products transportation and services: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
Crude oil transportation and services: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
Investment in Sunoco LP: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
Investment in USAC: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
All other: | |||||||||||||||
Revenues from external customers | |||||||||||||||
Intersegment revenues | |||||||||||||||
Eliminations | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Total revenues | $ | $ | $ | $ |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Segment Adjusted EBITDA: | |||||||||||||||
Intrastate transportation and storage | $ | $ | $ | $ | |||||||||||
Interstate transportation and storage | |||||||||||||||
Midstream | |||||||||||||||
NGL and refined products transportation and services | |||||||||||||||
Crude oil transportation and services | |||||||||||||||
Investment in Sunoco LP | |||||||||||||||
Investment in USAC | |||||||||||||||
All other | ( | ) | |||||||||||||
Adjusted EBITDA (consolidated) | |||||||||||||||
Depreciation, depletion and amortization | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Interest expense, net of interest capitalized | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Impairment losses | ( | ) | ( | ) | |||||||||||
Gains (losses) on interest rate derivatives | ( | ) | ( | ) | |||||||||||
Non-cash compensation expense | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Unrealized gains (losses) on commodity risk management activities | ( | ) | |||||||||||||
Losses on extinguishments of debt | ( | ) | ( | ) | |||||||||||
Inventory valuation adjustments | ( | ) | ( | ) | |||||||||||
Adjusted EBITDA related to unconsolidated affiliates | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Equity in earnings of unconsolidated affiliates | |||||||||||||||
Adjusted EBITDA related to discontinued operations | |||||||||||||||
Other, net | |||||||||||||||
Income from continuing operations before income tax expense | |||||||||||||||
Income tax (expense) benefit from continuing operations | ( | ) | ( | ) | ( | ) | |||||||||
Income from continuing operations | |||||||||||||||
Loss from discontinued operations, net of income taxes | ( | ) | ( | ) | |||||||||||
Net income | $ | $ | $ | $ |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Segment Adjusted EBITDA: | |||||||||||||||||||||||
Intrastate transportation and storage | $ | 235 | $ | 221 | $ | 14 | $ | 777 | $ | 621 | $ | 156 | |||||||||||
Interstate transportation and storage | 442 | 459 | (17 | ) | 1,358 | 1,200 | 158 | ||||||||||||||||
Midstream | 411 | 434 | (23 | ) | 1,205 | 1,225 | (20 | ) | |||||||||||||||
NGL and refined products transportation and services | 667 | 498 | 169 | 1,923 | 1,410 | 513 | |||||||||||||||||
Crude oil transportation and services | 700 | 682 | 18 | 2,257 | 1,694 | 563 | |||||||||||||||||
Investment in Sunoco LP | 192 | 208 | (16 | ) | 497 | 457 | 40 | ||||||||||||||||
Investment in USAC | 104 | 90 | 14 | 310 | 185 | 125 | |||||||||||||||||
All other | 35 | (15 | ) | 50 | 80 | 49 | 31 | ||||||||||||||||
Adjusted EBITDA (consolidated) | 2,786 | 2,577 | 209 | 8,407 | 6,841 | 1,566 | |||||||||||||||||
Depreciation, depletion and amortization | (784 | ) | (750 | ) | (34 | ) | (2,343 | ) | (2,109 | ) | (234 | ) | |||||||||||
Interest expense, net of interest capitalized | (579 | ) | (535 | ) | (44 | ) | (1,747 | ) | (1,511 | ) | (236 | ) | |||||||||||
Impairment losses | (12 | ) | — | (12 | ) | (62 | ) | — | (62 | ) | |||||||||||||
Gains (losses) on interest rate derivatives | (175 | ) | 45 | (220 | ) | (371 | ) | 117 | (488 | ) | |||||||||||||
Non-cash compensation expense | (27 | ) | (27 | ) | — | (85 | ) | (82 | ) | (3 | ) | ||||||||||||
Unrealized gains (losses) on commodity risk management activities | 64 | 97 | (33 | ) | 90 | (255 | ) | 345 | |||||||||||||||
Losses on extinguishments of debt | — | — | — | (18 | ) | (106 | ) | 88 | |||||||||||||||
Inventory valuation adjustments | (26 | ) | (7 | ) | (19 | ) | 71 | 50 | 21 | ||||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | (161 | ) | (179 | ) | 18 | (470 | ) | (503 | ) | 33 | |||||||||||||
Equity in earnings of unconsolidated affiliates | 82 | 87 | (5 | ) | 224 | 258 | (34 | ) | |||||||||||||||
Adjusted EBITDA related to discontinued operations | — | — | — | — | 25 | (25 | ) | ||||||||||||||||
Other, net | 47 | 33 | 14 | 67 | 59 | 8 | |||||||||||||||||
Income from continuing operations before income tax expense | 1,215 | 1,341 | (126 | ) | 3,763 | 2,784 | 979 | ||||||||||||||||
Income tax (expense) benefit from continuing operations | (54 | ) | 52 | (106 | ) | (214 | ) | (6 | ) | (208 | ) | ||||||||||||
Income from continuing operations | 1,161 | 1,393 | (232 | ) | 3,549 | 2,778 | 771 | ||||||||||||||||
Loss from discontinued operations, net of income taxes | — | (2 | ) | 2 | — | (265 | ) | 265 | |||||||||||||||
Net income | $ | 1,161 | $ | 1,391 | $ | (230 | ) | $ | 3,549 | $ | 2,513 | $ | 1,036 |
• | increases of $27 million and $168 million, respectively, recognized by the Partnership (excluding Sunoco LP and USAC, which are discussed below) primarily due to to increases in ETO’s long-term debt. The increases also reflect higher interest rates on floating rate borrowings, as well as the impact of reductions of $10 million and $77 million, respectively, in capitalized interest due to the completion of major projects in 2018; |
• | an increase of $7 million for the three months ended September 30, 2019 recognized by USAC primarily due to its senior notes issuance in March 2019 and an increase of $43 million for the nine months ended September 30, 2019 primarily due to the consolidation of USAC beginning April 2, 2018, the date ET obtained control of USAC; and |
• | increases of $10 million and $25 million, respectively, recognized by Sunoco LP primarily related to an increase in Sunoco LP’s total long-term debt. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Equity in earnings of unconsolidated affiliates: | |||||||||||||||||||||||
Citrus | $ | 44 | $ | 42 | $ | 2 | $ | 115 | $ | 102 | $ | 13 | |||||||||||
FEP | 15 | 14 | 1 | 43 | 41 | 2 | |||||||||||||||||
MEP | 1 | 7 | (6 | ) | 15 | 24 | (9 | ) | |||||||||||||||
Other | 22 | 24 | (2 | ) | 51 | 91 | (40 | ) | |||||||||||||||
Total equity in earnings of unconsolidated affiliates | $ | 82 | $ | 87 | $ | (5 | ) | $ | 224 | $ | 258 | $ | (34 | ) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates: | |||||||||||||||||||||||
Citrus | $ | 92 | $ | 96 | $ | (4 | ) | $ | 260 | $ | 256 | $ | 4 | ||||||||||
FEP | 19 | 19 | — | 56 | 56 | — | |||||||||||||||||
MEP | 13 | 20 | (7 | ) | 52 | 62 | (10 | ) | |||||||||||||||
Other | 37 | 44 | (7 | ) | 102 | 129 | (27 | ) | |||||||||||||||
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 161 | $ | 179 | $ | (18 | ) | $ | 470 | $ | 503 | $ | (33 | ) | |||||||||
Distributions received from unconsolidated affiliates: | |||||||||||||||||||||||
Citrus | $ | 54 | $ | 52 | $ | 2 | $ | 128 | $ | 125 | $ | 3 | |||||||||||
FEP | 20 | 18 | 2 | 53 | 50 | 3 | |||||||||||||||||
MEP | 7 | 9 | (2 | ) | 33 | 40 | (7 | ) | |||||||||||||||
Other | 22 | 34 | (12 | ) | 80 | 76 | 4 | ||||||||||||||||
Total distributions received from unconsolidated affiliates | $ | 103 | $ | 113 | $ | (10 | ) | $ | 294 | $ | 291 | $ | 3 |
• | 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. |
• | 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. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Natural gas transported (BBtu/d) | 12,560 | 12,146 | 414 | 12,221 | 10,592 | 1,629 | |||||||||||||||||
Withdrawals from storage natural gas inventory (BBtu) | — | — | — | — | 17,703 | (17,703 | ) | ||||||||||||||||
Revenues | $ | 764 | $ | 922 | $ | (158 | ) | $ | 2,385 | $ | 2,610 | $ | (225 | ) | |||||||||
Cost of products sold | 501 | 638 | (137 | ) | 1,473 | 1,888 | (415 | ) | |||||||||||||||
Segment margin | 263 | 284 | (21 | ) | 912 | 722 | 190 | ||||||||||||||||
Unrealized (gains) losses on commodity risk management activities | 19 | (12 | ) | 31 | 3 | 33 | (30 | ) | |||||||||||||||
Operating expenses, excluding non-cash compensation expense | (48 | ) | (51 | ) | 3 | (137 | ) | (141 | ) | 4 | |||||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (7 | ) | (7 | ) | — | (20 | ) | (20 | ) | — | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 7 | 6 | 1 | 18 | 26 | (8 | ) | ||||||||||||||||
Other | 1 | 1 | — | 1 | 1 | — | |||||||||||||||||
Segment Adjusted EBITDA | $ | 235 | $ | 221 | $ | 14 | $ | 777 | $ | 621 | $ | 156 |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Transportation fees | $ | 150 | $ | 141 | $ | 9 | $ | 452 | $ | 392 | $ | 60 | |||||||||||
Natural gas sales and other (excluding unrealized gains and losses) | 112 | 110 | 2 | 405 | 309 | 96 | |||||||||||||||||
Retained fuel revenues (excluding unrealized gains and losses) | 14 | 16 | (2 | ) | 37 | 42 | (5 | ) | |||||||||||||||
Storage margin (excluding unrealized gains and losses) | 6 | 5 | 1 | 21 | 12 | 9 | |||||||||||||||||
Unrealized gains (losses) on commodity risk management activities | (19 | ) | 12 | (31 | ) | (3 | ) | (33 | ) | 30 | |||||||||||||
Total segment margin | $ | 263 | $ | 284 | $ | (21 | ) | $ | 912 | $ | 722 | $ | 190 |
• | an increase of $9 million in transportation fees primarily due to increased utilization of our Texas pipelines; |
• | an increase of $2 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and |
• | an increase of $1 million in realized storage margin primarily due to higher storage fees; partially offset by |
• | a decrease of $2 million in retained fuel revenue primarily due to lower gas prices. |
• | an increase of $96 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; |
• | an increase of $36 million in transportation fees, excluding the impact of consolidating RIGS as discussed below, primarily due to new contracts, as well as the impact of the Red Bluff Express pipeline coming online in May 2018, as well as new contracts; |
• | a net increase of $11 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million, and $6 million, respectively, and a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates; and |
• | an increase of $9 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018, and higher storage fees, partially offset by a $13 million decrease primarily due to no physical withdrawals and a $5 million decrease in realized derivative gains; partially offset by |
• | a decrease of $5 million in retained fuel revenues primarily due to lower natural gas prices. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Natural gas transported (BBtu/d) | 11,407 | 10,155 | 1,252 | 11,254 | 9,029 | 2,225 | |||||||||||||||||
Natural gas sold (BBtu/d) | 17 | 18 | (1 | ) | 18 | 17 | 1 | ||||||||||||||||
Revenues | $ | 479 | $ | 445 | $ | 34 | $ | 1,470 | $ | 1,187 | $ | 283 | |||||||||||
Operating expenses, excluding non-cash compensation, amortization and accretion expenses | (141 | ) | (104 | ) | (37 | ) | (425 | ) | (312 | ) | (113 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (17 | ) | (20 | ) | 3 | (49 | ) | (55 | ) | 6 | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 124 | 135 | (11 | ) | 368 | 374 | (6 | ) | |||||||||||||||
Other | (3 | ) | 3 | (6 | ) | (6 | ) | 6 | (12 | ) | |||||||||||||
Segment Adjusted EBITDA | $ | 442 | $ | 459 | $ | (17 | ) | $ | 1,358 | $ | 1,200 | $ | 158 |
• | an increase of $37 million in operating expenses primarily due to an increase to ad valorem expenses of $48 million on the Rover pipeline system due to placing the final portions of this asset into service, partially offset by $5 million in lower maintenance expenditures and $4 million in lower storage lease expenses on our Panhandle system due to lower leased capacity; and |
• | a decrease in EBITDA from unconsolidated affiliates of $11 million primarily resulting from a $7 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted and lower rates on expiring contracts, and a $3 million decrease due to Citrus resulting from the Texas Brine settlement being received in 2018; partially offset by |
• | an increase of $24 million in reservation fees from placing the Rover pipeline fully in-service and $7 million from increased utilization of our Transwestern and Trunkline pipelines; and |
• | an increase of $4 million in interruptible transportation volumes due to improved market conditions on our Rover, Transwestern, Trunkline and Panhandle pipeline systems. |
• | an increase of $228 million from placing the Rover pipeline in-service; |
• | an increase of $39 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Rover, Transwestern, Tiger and Panhandle systems; |
• | an increase of $8 million on our Panhandle pipeline system primarily from additional gas processing revenues; |
• | an increase of $4 million from increased rates and additional volume delivered from the Sea Robin pipeline as a result of fewer third-party supply interruptions compared to the prior period; and |
• | a decrease of $6 million in selling, general and administrative expenses primarily due to lower excise tax on our Rover system; partially offset by |
• | an increase of $113 million in operating expense primarily due to a reverse to ad valorem taxes on the Rover pipeline system due to placing the final portions of this asset into service; and |
• | a decrease of $6 million in Adjusted EBITDA from unconsolidated affiliates primarily due to a $10 million decrease in earnings from MEP as a result of lower capacity being re-contracted and lower rates on expiring contracts, offset by a $3 million increase from new fixed transportation contracts on Citrus. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Gathered volumes (BBtu/d) | 13,955 | 12,774 | 1,181 | 13,278 | 11,890 | 1,388 | |||||||||||||||||
NGLs produced (MBbls/d) | 574 | 583 | (9 | ) | 567 | 533 | 34 | ||||||||||||||||
Equity NGLs (MBbls/d) | 30 | 32 | (2 | ) | 32 | 31 | 1 | ||||||||||||||||
Revenues | $ | 1,580 | $ | 2,253 | $ | (673 | ) | $ | 4,496 | $ | 5,741 | $ | (1,245 | ) | |||||||||
Cost of products sold | 953 | 1,631 | (678 | ) | 2,678 | 3,973 | (1,295 | ) | |||||||||||||||
Segment margin | 627 | 622 | 5 | 1,818 | 1,768 | 50 | |||||||||||||||||
Operating expenses, excluding non-cash compensation expense | (202 | ) | (179 | ) | (23 | ) | (574 | ) | (512 | ) | (62 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (21 | ) | (19 | ) | (2 | ) | (63 | ) | (59 | ) | (4 | ) | |||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 6 | 9 | (3 | ) | 21 | 25 | (4 | ) | |||||||||||||||
Other | 1 | 1 | — | 3 | 3 | — | |||||||||||||||||
Segment Adjusted EBITDA | $ | 411 | $ | 434 | $ | (23 | ) | $ | 1,205 | $ | 1,225 | $ | (20 | ) |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Gathering and processing fee-based revenues | $ | 517 | $ | 458 | $ | 59 | $ | 1,488 | $ | 1,319 | $ | 169 | |||||||||||
Non-fee-based contracts and processing | 110 | 164 | (54 | ) | 330 | 449 | (119 | ) | |||||||||||||||
Total segment margin | $ | 627 | $ | 622 | $ | 5 | $ | 1,818 | $ | 1,768 | $ | 50 |
• | a decrease of $54 million in non-fee-based margin due to lower NGL prices of $51 million and lower gas prices of $14 million, partially offset by an increase of $11 million from increased throughput volumes in the Permian region; |
• | an increase of $2 million in selling, general and administrative expenses due to an increase in allocated overhead costs; and |
• | an increase of $23 million in operating expenses primarily due to increases in outside services, maintenance project costs, and employee costs; partially offset by |
• | an increase of $59 million in fee-based margin due to volume growth in the Northeast, Permian and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions. |
• | a decrease of $119 million in non fee-based margin due primarily to lower NGL prices of $123 million and lower gas prices of $37 million, partially offset by an increase of $41 million due to increased throughput volume in the North Texas, South Texas and Permian regions; |
• | an increase of $62 million in operating expenses primarily due to increases of $27 million in outside services, $12 million in maintenance project costs, and $12 million in employee costs; and |
• | an increase of $4 million in selling, general and administrative expenses primarily due to an insurance payment received in the prior period; partially offset by |
• | an increase of $169 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
NGL transportation volumes (MBbls/d) | 1,346 | 1,086 | 260 | 1,277 | 997 | 280 | |||||||||||||||||
Refined products transportation volumes (MBbls/d) | 552 | 627 | (75 | ) | 599 | 628 | (29 | ) | |||||||||||||||
NGL and refined products terminal volumes (MBbls/d) | 963 | 858 | 105 | 948 | 784 | 164 | |||||||||||||||||
NGL fractionation volumes (MBbls/d) | 713 | 567 | 146 | 697 | 505 | 192 | |||||||||||||||||
Revenues | $ | 2,878 | $ | 3,063 | $ | (185 | ) | $ | 8,521 | $ | 8,177 | $ | 344 | ||||||||||
Cost of products sold | 1,962 | 2,429 | (467 | ) | 6,136 | 6,356 | (220 | ) | |||||||||||||||
Segment margin | 916 | 634 | 282 | 2,385 | 1,821 | 564 | |||||||||||||||||
Unrealized losses on commodity risk management activities | (81 | ) | 26 | (107 | ) | 15 | 26 | (11 | ) | ||||||||||||||
Operating expenses, excluding non-cash compensation expense | (167 | ) | (168 | ) | 1 | (471 | ) | (448 | ) | (23 | ) | ||||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (22 | ) | (17 | ) | (5 | ) | (67 | ) | (52 | ) | (15 | ) | |||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 24 | 23 | 1 | 63 | 63 | — | |||||||||||||||||
Other | (3 | ) | — | (3 | ) | (2 | ) | — | (2 | ) | |||||||||||||
Segment Adjusted EBITDA | $ | 667 | $ | 498 | $ | 169 | $ | 1,923 | $ | 1,410 | $ | 513 |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Transportation margin | $ | 474 | $ | 322 | $ | 152 | $ | 1,259 | $ | 878 | $ | 381 | |||||||||||
Fractionators and refinery services margin | 171 | 141 | 30 | 491 | 365 | 126 | |||||||||||||||||
Terminal services margin | 175 | 130 | 45 | 478 | 353 | 125 | |||||||||||||||||
Storage margin | 57 | 50 | 7 | 166 | 154 | 12 | |||||||||||||||||
Marketing margin | (42 | ) | 17 | (59 | ) | 6 | 97 | (91 | ) | ||||||||||||||
Unrealized losses on commodity risk management activities | 81 | (26 | ) | 107 | (15 | ) | (26 | ) | 11 | ||||||||||||||
Total segment margin | $ | 916 | $ | 634 | $ | 282 | $ | 2,385 | $ | 1,821 | $ | 564 |
• | an increase of $152 million in transportation margin primarily due to an $87 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $54 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, and an $11 million increase due to higher throughput volumes received from the Barnett and Southeast Texas regions; |
• | an increase of $45 million in terminal services margin primarily due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018; |
• | an increase of $30 million in fractionation and refinery services margin primarily resulting from the commissioning of our sixth fractionator in February 2019 and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $3 million decrease resulting from a reclassification between our fractionation and storage margins; and |
• | an increase of $7 million in storage margin primarily due to a $3 million increase from throughput pipeline fees collected at our Mont Belvieu storage facility, a $3 million increase resulting from a reclassification between our storage and fractionation margins; partially offset by |
• | a decrease of $59 million in marketing margin primarily due to lower optimization gains resulting from less favorable market conditions and an $8 million write down on the value of stored NGL inventory; and |
• | an increase of $5 million in selling, general and administrative expenses due to a $3 million increase in allocated overhead costs and a $2 million increase in legal fees. |
• | an increase of $381 million in transportation margin primarily due to a $180 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $177 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, and a $21 million increase due to higher throughput volumes from the Barnett and Southeast Texas regions; |
• | an increase of $126 million in fractionation and refinery services margin primarily due to a $142 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $10 million decrease resulting from a reclassification between our fractionation and storage margins and an $8 million decrease in refinery services margin primarily due to lower pricing spreads; |
• | an increase of $125 million in terminal services margin primarily due to a $130 million increase due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018 and a $10 million increase due to higher throughput at our refined product terminals in the Northeast. These increases were partially offset by a $16 million decrease due to lower volumes from third party pipeline, truck and rail delivered into our Marcus Hook terminal; and |
• | an increase of $12 million in storage margin primarily due to a $10 million increase resulting from a reclassification between our storage and fractionation margins; partially offset by |
• | a decrease of $91 million in marketing margin primarily due to lower optimization gains resulting from less favorable market conditions and an $8 million write down on the value of stored NGL inventory; |
• | an increase of $23 million in operating expenses primarily due to an $18 million increase in employee and ad valorem expenses on our terminals and fractionation assets and a $15 million increase in utility costs to operate our pipelines and fifth and sixth fractionators, which commenced service in July 2018 and February 2019, respectively. These increases were partially offset by an $11 million decrease in outside services on our transportation and terminal assets; and |
• | an increase of $15 million iin selling, general and administrative expenses due to a $6 million increase in allocated overhead costs, a $4 million increase in legal fees, a $2 million increase in insurance expenses, a $2 million increase in employee costs, and a $2 million increase in management fees. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Crude transportation volumes (MBbls/d) | 4,661 | 4,276 | 385 | 4,638 | 4,119 | 519 | |||||||||||||||||
Crude terminals volumes (MBbls/d) | 1,905 | 2,134 | (229 | ) | 2,125 | 2,060 | 65 | ||||||||||||||||
Revenues | $ | 4,453 | $ | 4,438 | $ | 15 | $ | 13,685 | $ | 12,986 | $ | 699 | |||||||||||
Cost of products sold | 3,620 | 3,494 | 126 | 10,857 | 11,032 | (175 | ) | ||||||||||||||||
Segment margin | 833 | 944 | (111 | ) | 2,828 | 1,954 | 874 | ||||||||||||||||
Unrealized (gains) losses on commodity risk management activities | (2 | ) | (118 | ) | 116 | (100 | ) | 187 | (287 | ) | |||||||||||||
Operating expenses, excluding non-cash compensation expense | (110 | ) | (126 | ) | 16 | (410 | ) | (397 | ) | (13 | ) | ||||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (21 | ) | (22 | ) | 1 | (61 | ) | (64 | ) | 3 | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 1 | 4 | (3 | ) | — | 14 | (14 | ) | |||||||||||||||
Other | (1 | ) | — | (1 | ) | — | — | — | |||||||||||||||
Segment Adjusted EBITDA | $ | 700 | $ | 682 | $ | 18 | $ | 2,257 | $ | 1,694 | $ | 563 |
• | an increase of $5 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $63 million increase from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region, a $50 million increase from higher throughput on the Bakken pipeline, and a $6 million increase from higher ship loading and tank rental fees at our Nederland terminal; partially offset by a $106 million decrease (excluding a net change of $116 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from non-cash inventory valuation adjustments and lower basis differentials between the Permian producing region and the Nederland terminal on the Gulf Coast, as well as a $5 million decrease due to lower throughput volumes at our refinery terminal in the Northeast. The remainder of the offsetting decrease |
• | a decrease of $16 million in operating expenses primarily due to the impact of certain intrasegment transactions discussed above, partially offset by a $17 million increase in ad valorem taxes; and |
• | a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures. |
• | an increase of $587 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $355 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers, a $216 million favorable variance resulting from increased throughput on the Bakken pipeline, a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland terminal, and an $8 million increase (excluding a net change of $287 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from improved basis differentials between the Permian and Bakken producing regions to our Nederland terminal on the Texas Gulf Coast, partially offset by a $6 million decrease due to lower throughput volumes at our refinery terminal in the Northeast. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; and |
• | an increase of $13 million in operating expenses primarily due to a $34 million increase in throughput related costs on existing assets, and a $7 million increase in ad valorem taxes, partially offset by a$10 million decrease in management fees, as well as the impact of certain intrasegment transactions discussed above; and |
• | a decrease of $14 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Revenues | $ | 4,331 | $ | 4,761 | $ | (430 | ) | $ | 12,498 | $ | 13,117 | $ | (619 | ) | |||||||||
Cost of products sold | 4,039 | 4,428 | (389 | ) | 11,567 | 12,178 | (611 | ) | |||||||||||||||
Segment margin | 292 | 333 | (41 | ) | 931 | 939 | (8 | ) | |||||||||||||||
Unrealized gains on commodity risk management activities | (1 | ) | — | (1 | ) | (4 | ) | — | (4 | ) | |||||||||||||
Operating expenses, excluding non-cash compensation expense | (94 | ) | (106 | ) | 12 | (281 | ) | (324 | ) | 43 | |||||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (36 | ) | (30 | ) | (6 | ) | (91 | ) | (93 | ) | 2 | ||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 1 | — | 1 | 1 | — | 1 | |||||||||||||||||
Inventory valuation adjustments | 26 | 7 | 19 | (71 | ) | (50 | ) | (21 | ) | ||||||||||||||
Adjusted EBITDA related to discontinued operations | — | — | — | — | (25 | ) | 25 | ||||||||||||||||
Other | 4 | 4 | — | 12 | 10 | 2 | |||||||||||||||||
Segment Adjusted EBITDA | $ | 192 | $ | 208 | $ | (16 | ) | $ | 497 | $ | 457 | $ | 40 |
• | a decrease of $23 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier in the prior period, partially offset by an increase in motor fuel gallons sold; partially offset by |
• | a net decrease of $6 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation, primarily as a result of lower lease expense and utilities. |
• | an aggregate decrease of $45 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation, primarily due to the conversion of 207 retail sites to commission agent sites in April 2018; and |
• | an increase of $25 million in Adjusted EBITDA from discontinued operations due to Sunoco LP’s retail divestment in January 2018; partially offset by |
• | a decrease of $33 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier in the prior period and an $8 million one-time charge related to a reserve for an open contractual dispute in the current period, partially offset by an increase in motor fuel gallons sold. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Revenues | $ | 175 | $ | 169 | $ | 6 | $ | 520 | $ | 336 | $ | 184 | |||||||||||
Cost of products sold | 23 | 24 | (1 | ) | 69 | 44 | 25 | ||||||||||||||||
Segment margin | 152 | 145 | 7 | 451 | 292 | 159 | |||||||||||||||||
Operating expenses, excluding non-cash compensation expense | (35 | ) | (42 | ) | 7 | (102 | ) | (80 | ) | (22 | ) | ||||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (13 | ) | (15 | ) | 2 | (39 | ) | (34 | ) | (5 | ) | ||||||||||||
Other | — | 2 | (2 | ) | — | 7 | (7 | ) | |||||||||||||||
Segment Adjusted EBITDA | $ | 104 | $ | 90 | $ | 14 | $ | 310 | $ | 185 | $ | 125 |
• | an increase of $7 million in segment margin primarily due to an increase in demand for compression services driven by increased U.S. production of crude oil and natural gas; |
• | a decrease of $7 million in operating expenses primarily due to a $3 million decrease in outside maintenance services, a $2 million decrease in ad valorem taxes primarily due to prior year refunds received in the current period, a $2 million decrease in direct labor costs, and a $1 million decrease in indirect expenses, such as transportation and freight, partially offset by a $3 million increase in parts and fluids expenses as a result of higher revenue generating horsepower; and |
• | a decrease of $2 million in selling, general and administrative expenses primarily due to transaction related expenses as a result of transactions completed during 2018. |
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
Revenues | $ | 441 | $ | 525 | $ | (84 | ) | $ | 1,276 | $ | 1,599 | $ | (323 | ) | |||||||||
Cost of products sold | 393 | 500 | (107 | ) | 1,138 | 1,421 | (283 | ) | |||||||||||||||
Segment margin | 48 | 25 | 23 | 138 | 178 | (40 | ) | ||||||||||||||||
Unrealized (gains) losses on commodity risk management activities | 1 | 7 | (6 | ) | (4 | ) | 9 | (13 | ) | ||||||||||||||
Operating expenses, excluding non-cash compensation expense | (39 | ) | (9 | ) | (30 | ) | (52 | ) | (50 | ) | (2 | ) | |||||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (11 | ) | (35 | ) | 24 | (45 | ) | (83 | ) | 38 | |||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | — | 2 | (2 | ) | 1 | 1 | — | ||||||||||||||||
Other and eliminations | 36 | (5 | ) | 41 | 42 | (6 | ) | 48 | |||||||||||||||
Segment Adjusted EBITDA | $ | 35 | $ | (15 | ) | $ | 50 | $ | 80 | $ | 49 | $ | 31 |
• | 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 August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate; and |
• | our investment in coal handling facilities. |
• | an increase of $3 million from power trading activities; |
• | an increase of $5 million in optimized gains on residue gas sales; |
• | an increase of $5 million from settled derivatives; |
• | an increase of $6 million from the recognition of deferred revenue related to a bankruptcy; and |
• | a decrease of $24 million in selling, general and administrative expenses, which includes a decrease of $9 million in merger and acquisition expenses, a decrease of $6 million in professional fees, and a decrease of $4 million in insurance expenses. |
• | an increase of $13 million in gains from park and loan and storage activity; |
• | an increase of $9 million in optimized gains on residue gas sales; |
• | an increase of $6 million from the recognition of deferred revenue related to a bankruptcy; and |
• | a decrease of $38 million in selling, general and administrative expenses primarily due to lower merger and acquisition and other expenses; partially offset by |
• | a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC Segment; and |
• | a decrease of $5 million due to lower revenue from our compressor equipment business. |
Growth | Maintenance | ||||||||||||||
Low | High | Low | High | ||||||||||||
Intrastate transportation and storage | $ | 75 | $ | 100 | $ | 35 | $ | 40 | |||||||
Interstate transportation and storage (1) | 250 | 275 | 145 | 150 | |||||||||||
Midstream | 675 | 700 | 145 | 150 | |||||||||||
NGL and refined products transportation and services | 2,475 | 2,500 | 90 | 100 | |||||||||||
Crude oil transportation and services (1) | 300 | 325 | 100 | 110 | |||||||||||
All other (including eliminations) | 150 | 175 | 50 | 55 | |||||||||||
Total capital expenditures | $ | 3,925 | $ | 4,075 | $ | 565 | $ | 605 |
(1) | Includes capital expenditures related to ETO’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects. |
Capital Expenditures Recorded During Period | |||||||||||
Growth | Maintenance | Total | |||||||||
Intrastate transportation and storage (1) | $ | 61 | $ | 39 | $ | 100 | |||||
Interstate transportation and storage | 194 | 95 | 289 | ||||||||
Midstream | 535 | 105 | 640 | ||||||||
NGL and refined products transportation and services | 1,956 | 69 | 2,025 | ||||||||
Crude oil transportation and services | 239 | 58 | 297 | ||||||||
Investment in Sunoco LP | 80 | 23 | 103 | ||||||||
Investment in USAC | 137 | 22 | 159 | ||||||||
All other (including eliminations) | 134 | 29 | 163 | ||||||||
Total capital expenditures | $ | 3,336 | $ | 440 | $ | 3,776 |
(1) | For the nine months ended September 30, 2019, growth capital expenditures for the intrastate transportation and storage segment reflect the proceeds received from the sale of a noncontrolling interest in the Red Bluff Express pipeline, which was based on capital expenditures from prior periods. |
September 30, 2019 | December 31, 2018 | ||||||
Parent Company Indebtedness: | |||||||
ET Senior Notes due October 2020 | $ | 52 | $ | 1,187 | |||
ET Senior Notes due March 2023 | 5 | 1,000 | |||||
ET Senior Notes due January 2024 | 23 | 1,150 | |||||
ET Senior Notes due June 2027 | 44 | 1,000 | |||||
ET Senior Secured Term Loan | — | 1,220 | |||||
Subsidiary Indebtedness: | |||||||
ETO Senior Notes (1) | 36,117 | 28,755 | |||||
Transwestern Senior Notes | 575 | 575 | |||||
Panhandle Senior Notes | 236 | 385 | |||||
Bakken Senior Notes | 2,500 | — | |||||
Sunoco LP Senior Notes and lease-related obligations | 2,946 | 2,307 | |||||
USAC Senior Notes | 1,475 | 725 | |||||
Credit facilities and commercial paper: | |||||||
ETO $5.00 billion Revolving Credit Facility due December 2023 (2) | 2,608 | 3,694 | |||||
Bakken Project $2.50 billion Credit Facility due August 2019 | — | 2,500 | |||||
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 | 154 | 700 | |||||
USAC $1.60 billion Revolving Credit Facility due April 2023 | 395 | 1,050 | |||||
Other long-term debt | 4 | 7 | |||||
Unamortized premiums, net of discounts and fair value adjustments | 6 | 21 | |||||
Deferred debt issuance costs | (286 | ) | (248 | ) | |||
Total debt | 46,854 | 46,028 | |||||
Less: current maturities of long-term debt | 14 | 2,655 | |||||
Long-term debt, less current maturities | $ | 46,840 | $ | 43,373 |
(1) | The increase in ETO Senior Notes during nine months ended September 30, 2019 includes $4.21 billion issued in connection with the ET-ETO senior notes exchange and $4.00 billion issued in the January 2019 senior notes offering, both of which are discussed below. The September 30, 2019 balance also includes a $250 million aggregate principal amount of 5.50% senior notes due February 15, 2020 and a $400 million aggregate principal amount of 5.75% note due September 1, 2020 that were classified as long-term as of September 30, 2019 as management has the intent and ability to refinance the borrowing on a long-term basis. |
(2) | Includes $2.15 billion and $2.34 billion of commercial paper outstanding at September 30, 2019 and December 31, 2018, respectively. |
• | $52 million aggregate principal amount of 7.50% senior notes due 2020; |
• | $5 million aggregate principal amount of 4.25% senior notes due 2023; |
• | $23 million aggregate principal amount of 5.875% senior notes due 2024; and |
• | $44 million aggregate principal amount of 5.50% senior notes due 2027. |
• | $1.14 billion aggregate principal amount of 7.50% senior notes due 2020; |
• | $995 million aggregate principal amount of 4.25% senior notes due 2023; |
• | $1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and |
• | $956 million aggregate principal amount of 5.50% senior notes due 2027. |
• | $750 million aggregate principal amount of 4.50% senior notes due 2024; |
• | $1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and |
• | $1.75 billion aggregate principal amount of 6.25% senior notes due 2049. |
• | ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019; |
• | ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and |
• | Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019. |
• | $650 million aggregate principal amount of 3.625% senior notes due 2022; |
• | $1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and |
• | $850 million aggregate principal amount of 4.625% senior notes due 2029. |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2018 | February 8, 2019 | February 19, 2019 | $ | 0.3050 | ||||
March 31, 2019 | May 7, 2019 | May 20, 2019 | 0.3050 | |||||
June 30, 2019 | August 6, 2019 | August 19, 2019 | 0.3050 | |||||
September 30, 2019 | November 5, 2019 | November 19, 2019 | 0.3050 |
Period Ended | Record Date | Payment Date | Series A (1) | Series B (1) | Series C | Series D | Series E (2) | |||||||||||||||||
December 31, 2018 | February 1, 2019 | February 15, 2019 | $ | 31.25 | $ | 33.125 | $ | 0.4609 | $ | 0.4766 | $ | — | ||||||||||||
March 31, 2019 | May 1, 2019 | May 15, 2019 | — | — | 0.4609 | 0.4766 | — | |||||||||||||||||
June 30, 2019 | August 1, 2019 | August 15, 2019 | 31.25 | 33.125 | 0.4609 | 0.4766 | 0.5806 | |||||||||||||||||
September 30, 2019 | November 1, 2019 | November 15, 2019 | — | — | 0.4609 | 0.4766 | 0.4750 |
(1) | ETO Series A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis. |
(2) | ETO Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution. |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2018 | February 6, 2019 | February 14, 2019 | $ | 0.8255 | ||||
March 31, 2019 | May 7, 2019 | May 15, 2019 | 0.8255 | |||||
June 30, 2019 | August 6, 2019 | August 14, 2019 | 0.8255 | |||||
September 30, 2019 | November 5, 2019 | November 19, 2019 | 0.8255 |
Quarter Ended | Record Date | Payment Date | Rate | |||||
December 31, 2018 | January 28, 2019 | February 8, 2019 | $ | 0.5250 | ||||
March 31, 2019 | April 29, 2019 | May 10, 2019 | 0.5250 | |||||
June 30, 2019 | July 29, 2019 | August 9, 2019 | 0.5250 | |||||
September 30, 2019 | October 28, 2019 | November 8, 2019 | 0.5250 |
September 30, 2019 | December 31, 2018 | ||||||||||||||||||||
Notional Volume | Fair Value Asset (Liability) | Effect of Hypothetical 10% Change | Notional Volume | Fair Value Asset (Liability) | Effect of Hypothetical 10% Change | ||||||||||||||||
Mark-to-Market Derivatives | |||||||||||||||||||||
(Trading) | |||||||||||||||||||||
Natural Gas (BBtu): | |||||||||||||||||||||
Basis Swaps IFERC/NYMEX (1) | 20,563 | $ | (2 | ) | $ | 5 | 16,845 | $ | 7 | $ | 1 | ||||||||||
Fixed Swaps/Futures | 1,723 | — | — | 468 | — | — | |||||||||||||||
Options – Puts | — | — | — | 10,000 | — | — | |||||||||||||||
Power (Megawatt): | |||||||||||||||||||||
Forwards | 2,847,350 | 7 | 7 | 3,141,520 | 6 | 8 | |||||||||||||||
Futures | 222,440 | (1 | ) | — | 56,656 | — | — | ||||||||||||||
Options – Puts | 515,317 | — | — | 18,400 | — | — | |||||||||||||||
Options – Calls | (756,153 | ) | (1 | ) | — | 284,800 | 1 | — | |||||||||||||
(Non-Trading) | |||||||||||||||||||||
Natural Gas (BBtu): | |||||||||||||||||||||
Basis Swaps IFERC/NYMEX | (23,653 | ) | (26 | ) | 16 | (30,228 | ) | (52 | ) | 13 | |||||||||||
Swing Swaps IFERC | 22,365 | (4 | ) | 2 | 54,158 | 12 | — | ||||||||||||||
Fixed Swaps/Futures | 2,323 | 1 | — | (1,068 | ) | 19 | 1 | ||||||||||||||
Forward Physical Contracts | (29,492 | ) | 3 | 7 | (123,254 | ) | (1 | ) | 32 | ||||||||||||
NGLs (MBbls) – Forwards/Swaps | (9,687 | ) | 50 | 46 | (2,135 | ) | 67 | 67 | |||||||||||||
Refined Products (MBbls) – Futures | (906 | ) | (2 | ) | 5 | (1,403 | ) | (8 | ) | 6 | |||||||||||
Crude (MBbls) – Forwards/Swaps | 9,510 | 42 | 4 | 20,888 | (60 | ) | 29 | ||||||||||||||
Corn (thousand bushels) | (1,760 | ) | — | 1 | (1,920 | ) | — | 1 | |||||||||||||
Fair Value Hedging Derivatives | |||||||||||||||||||||
(Non-Trading) | |||||||||||||||||||||
Natural Gas (BBtu): | |||||||||||||||||||||
Basis Swaps IFERC/NYMEX | (31,703 | ) | 1 | 8 | (17,445 | ) | (4 | ) | — | ||||||||||||
Fixed Swaps/Futures | (31,703 | ) | 14 | 8 | (17,445 | ) | (10 | ) | 6 |
(1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Term | Type(1) | Notional Amount Outstanding | ||||||||
September 30, 2019 | December 31, 2018 | |||||||||
July 2019(2) | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | $ | — | $ | 400 | |||||
July 2020(2) | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | 400 | 400 | |||||||
July 2021(2) | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | 400 | 400 | |||||||
July 2022(2) | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | 400 | — | |||||||
March 2019 | Pay a floating rate and receive a fixed rate of 1.42% | — | 300 |
(1) | Floating rates are based on 3-month LIBOR. |
(2) | Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. |
Exhibit Number | Description | |
Exhibit Number | Description | |
101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.CAL* | XBRL Taxonomy Calculation Linkbase Document | |
101.DEF* | XBRL Taxonomy Extension Definitions Document | |
101.LAB* | XBRL Taxonomy Label Linkbase Document | |
101.PRE* | XBRL Taxonomy Presentation Linkbase Document | |
104 | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) | |
* | Filed herewith. | |
** | Furnished herewith. |
ENERGY TRANSFER LP | ||||
By: | LE GP, LLC, its general partner | |||
Date: | November 7, 2019 | By: | /s/ A. Troy Sturrock | |
A. Troy Sturrock | ||||
Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant) |
1. | I have reviewed this quarterly report on Form 10-Q of Energy Transfer LP; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Kelcy L. Warren |
Kelcy L. Warren |
Chief Executive Officer |
1. | I have reviewed this quarterly report on Form 10-Q of Energy Transfer LP; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Thomas E. Long |
Thomas E. Long Chief Financial Officer |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
/s/ Kelcy L. Warren |
Kelcy L. Warren |
Chief Executive Officer |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
/s/ Thomas E. Long |
Thomas E. Long Chief Financial Officer |
Redeemable Noncontrolling Interest (Details) - USD ($) $ / shares in Units, $ in Millions |
1 Months Ended | |||
---|---|---|---|---|
Apr. 30, 2018 |
Sep. 30, 2019 |
Dec. 31, 2018 |
Apr. 02, 2018 |
|
Redeemable noncontrolling interests | $ 499 | $ 499 | ||
USAC [Member] | ||||
Redeemable noncontrolling interests | 477 | |||
ETO [Member] | ||||
Redeemable noncontrolling interests | $ 22 | |||
Preferred Units [Member] | USAC [Member] | ||||
Preferred Units, Issued | 500,000 | |||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 24.375 | |||
Shares Issued, Price Per Share | $ 1,000 | |||
Proceeds from Issuance of Preferred Limited Partners Units | $ 500 |
Fair Value Measurements Narrative (Details) - USD ($) $ in Millions |
9 Months Ended | |
---|---|---|
Sep. 30, 2019 |
Dec. 31, 2018 |
|
Fair Value Measurements [Abstract] | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net | $ 0 | |
Debt obligations, fair value | 50,790 | $ 45,060 |
Long-term Debt | $ 46,850 | $ 46,030 |
Equity Table - Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions |
9 Months Ended | 12 Months Ended |
---|---|---|
Sep. 30, 2019 |
Dec. 31, 2018 |
|
Partners' Capital Notes [Abstract] | ||
Available-for-sale securities | $ 10 | $ 2 |
Foreign currency translation adjustment | (5) | (5) |
Actuarial gain related to pensions and other postretirement benefits | (41) | (48) |
AOCI attributable to equity method investments | (4) | 9 |
Total AOCI, net of tax | $ (40) | $ (42) |
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters, Commitments, Contingencies And Environmental Liabilities | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES FERC Proceedings By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the order dated October 1, 2019. A hearing in the combined proceedings is scheduled for August, 2020, with an initial decision expected in early 2021. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest Gas filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 29, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue. In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of Settlement in this Section 4 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 17, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue. Commitments In the normal course of business, ETO purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. ETO’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations:
PES Refinery Fire and Bankruptcy We own an approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia. In addition, the Partnership provides logistics services to PES under commercial contracts and Sunoco LP has historically purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex. On July 21, 2019 (the "Petition Date"), PES Holdings, LLC and seven of its subsidiaries (collectively, the "Debtors") filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have announced an intent to temporarily cease refinery operations. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. The Partnership has not recorded a valuation allowance related to the note receivable as of September 30, 2019, because management is not yet able to determine the collectability of the note in bankruptcy. In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of September 30, 2019, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such claims, and these liabilities are included in the total environmental liabilities discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future; however, management is not currently able to estimate such additional liabilities. PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time, as the Debtors have expressed an intent to rebuild the refinery with the proceeds of insurance claims while concurrently running a sale process for its assets and operations. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward. Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Dakota Access Pipeline On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access, LLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“the Court”) against the USACE and challenged the legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). SRST also sought a preliminary injunction to rescind the USACE permits while the case was pending, which the Court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. SRST filed an amended complaint and added claims based on treaties between SRST and CRST and the United States and statutes governing the use of government property. In February 2017, in response to a Presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which motion was denied, and raised claims based on the religious rights of CRST. In June 2017, SRST and CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala Sioux and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes. On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court concluded that the USACE had not violated trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the Court on December 29, 2017 and February 28, 2018, respectfully. On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions sought an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access and the USACE opposed both motions. On April 16, 2018, the Court denied both motions. On March 19, 2018, the Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST. On May 3, 2018, the Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they would conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they would need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. On October 1, 2018, the USACE produced a detailed remand analysis document supporting that determination. The Tribes and certain of the individuals sought leave of the Court to amend their complaints to challenge the remand process and the USACE’s decision on remand. On January 3, 2019, the Court granted the Tribes’ requests to supplement their respective complaints challenging the remand process, subject to defendants’ right to argue later that such supplementation may be overbroad and not permitted by law. On January 10, 2019, the Court denied the Oglala Sioux Tribe’s motion to amend its complaint to expand one of its pre-remand claims. On January 17, 2019, the DOJ, on behalf of the USACE, moved to stay the litigation in light of the lapse in appropriations for the DOJ. The Tribes and individual plaintiffs opposed that request. On January 28, 2019, the USACE moved to withdraw this motion because appropriations for the DOJ had been restored. The Court granted this motion the next day. On January 31, 2019, the USACE notified the Court that it had provided the administrative record for the remand to all parties. On February 27, 2019, the four Tribes filed a joint motion challenging the completeness of the record. The USACE opposed this motion in part, and Dakota Access opposed in full. On May 8, 2019, the Court issued an order on Plaintiffs’ motion to complete the administrative record, requiring the parties to submit additional information so that the Court can determine what documents, if any, should be added to the record. Following submittal of additional information by the parties, the Court issued an order on June 11, 2019 that determined which documents were to be added to the record. Plaintiffs filed motions for summary judgment on August 16, 2019, and Defendants filed their opposition and cross motions on October 9, 2019. Briefing is scheduled to conclude by November 20, 2019. While we believe that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. Energy Transfer cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL LLC’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has obtained, and will continue to seek, reimbursement for these losses. MTBE Litigation ETC Sunoco and Sunoco (R&M) (collectively, “Sunoco”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of September 30, 2019, Sunoco is a defendant in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. (“SPMT”). It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETO merger (the “Regency Merger”). All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP LP, Regency GP LLC, ET, ETO, ETP GP, and the members of Regency’s board of directors. The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith or fair to Regency. On March 29, 2016, the Delaware Court of Chancery granted the defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. On April 26, 2019, the Court of Chancery granted Dieckman’s unopposed motion for class certification. On May 14, 2019, the Regency Defendants filed a motion for summary judgment arguing that Dieckman’s claims fail because the Regency Defendants relied on the advice of their financial advisor in approving the Regency Merger. Also on May 14, 2019, Dieckman filed a motion for partial summary judgment arguing, among other things, that Regency’s conflicts committee was not properly formed. On October 29, 2019, the court granted Plaintiff’s summary judgment motion, holding that Regency failed (1) to form a valid conflicts committee such that Regency failed to satisfy the Special Approval safe harbor in connection with the merger, and (2) to issue a proxy that was not materially misleading such that Regency failed to satisfy the Unitholder Approval safe harbor in connection with the merger. The court denied Defendants’ summary judgment motion which argued that Defendants approved the merger in good faith because they relied upon the fairness opinion of an investment bank. The court held that fact questions existed regarding whether Defendants actually relied upon the fairness opinion given by JP Morgan when voting in favor of the merger. Trial is currently set for December 10-16, 2019. The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETO against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETO. The jury also found that ETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETO and awarded ETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETO shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETO’s motion for rehearing to the Court of Appeals was denied. On November 27, 2017, ETO filed a Petition for Review with the Texas Supreme Court. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. On June 28, 2019, the Texas Supreme Court granted ETO’s petition for review and oral argument was heard on October 8, 2019. The parties now await a decision. Litigation Filed By or Against Williams On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ET and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the issuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance. On May 3, 2016, ET and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the ET-Williams merger agreement (the “Merger Agreement”) by (a) blocking ET’s attempts to complete a public offering of the Series A Convertible Preferred Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause. On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ET and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ET breached the Merger Agreement, (b) enjoin ET from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ET from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ET to close the merger or take various other affirmative actions. ET filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ET asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ET for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ET sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016. After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ET on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ET could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ET’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee, and Defendants filed amended counterclaims and affirmative defenses. In response, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial, and as a result, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending. On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. On April 16, 2018, the Court denied ET’s motion for re-argument of the Court’s decision granting Williams’ motion to dismiss in part. Discovery is ongoing, and a trial is currently set for June 2020. Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them. Unitholder Litigation Relating to the Issuance On April 12, 2016, two purported ET unitholders (together with plaintiff Chester County Employees’ Retirement Fund, the “Plaintiffs”) filed putative class action lawsuits against ET, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Defendants”) in the Delaware Court of Chancery (the “Issuance Litigation”). Another purported ET unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation. The Plaintiffs allege that the Issuance breached various provisions of ET’s partnership agreement. The Plaintiffs sought, among other things, preliminary and permanent injunctive relief that (a) prevents ET from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of the Series A Convertible Preferred Units (“Issuance”). On August 29, 2016, the Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance. The matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ET’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages or any other form of relief. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Defendants, which the Defendants opposed. On May 6, 2019, the Court entered an Order and Final Judgment consistent with its May 2018 post-trial opinion. The Court ordered that Energy Transfer pay $4.5 million in attorneys’ fees and expenses and also granted Plaintiffs’ Motion for Class Certification. On June 5, 2019, Plaintiffs filed a notice of appeal to the Supreme Court of Delaware from, among other things, the May 17, 2018 Memorandum Opinion and the May 6, 2019 Order and Final Judgment. Plaintiffs filed their opening brief on July 22, 2019, the Defendants filed their answering brief on August 21, 2019, and the Plaintiffs filed their reply brief on September 5, 2019. The case is set for oral argument before the Supreme Court of Delaware on November 13, 2019. The Defendants cannot predict the outcome of this appeal or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve this lawsuit. The Defendants believe that the Plaintiffs’ claims are without merit and intend to defend vigorously against them. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018. Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition. The State’s opposition to those motions was filed on October 12, 2018. Rover and other Defendants filed their replies on November 2, 2018. On March 13, 2019, the court granted Rover and the other Defendants’ motion to dismiss on all counts. On April 10, 2019, the Ohio EPA filed a notice of appeal. The Ohio EPA’s appeal is now pending before the Fifth District court of appeals. Briefing was completed in August of 2019 and oral argument has been set for November 5, 2019. In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24, 2018 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Construction of Rover is now complete and the pipeline is fully operational. Bayou Bridge On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint. On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order. On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the district court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the district court. Construction is ongoing. On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 18, 2018. On September 18, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the USACE’s analysis of the risks of an oil spill once the pipeline is in operation. On November 6, 2018, the court struck plaintiffs’ motion as premature. At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiffs’ original complaint, which it has done. Challenges to the completeness of the record have been briefed and are currently pending before the court. At the October 18, 2018 conference, the court also scheduled summary judgment briefing on Plaintiffs’ original complaint; briefing is scheduled to conclude by the end of 2019. On December 28, 2018, Judge Dick issued a General Order for the Middle District of Louisiana holding in abeyance all civil matters where the United States is a party. Notwithstanding the General Order, on January 11, 2019, Plaintiffs prematurely filed a Motion for Summary Judgment on its National Environmental Policy Act and Clean Waters Act claims. On January 23, 2019, Plaintiffs filed a Second Motion for Preliminary Injunction based on alleged permit violations, which the court later denied. On February 11, 2019, the court denied Plaintiffs’ August 14, 2018 motion for leave to amend their complaint. On February 14, 2019, Judge Dick ordered that all summary judgment briefing is stayed until the court rules on the motions challenging the completeness of the administrative record. Judge Dick further ordered that once those motions are decided, the parties will be allowed to update any summary judgment briefs they have already filed, if necessary, and that the court will set new briefing deadlines. On April 26, 2019, Plaintiffs filed a motion seeking reconsideration of Judge Dick’s February 14, 2019 order staying summary judgment briefing. Defendants filed their oppositions on May 6, 2019. On May 14, 2019, Judge Dick issued orders denying the outstanding record motions and Plaintiffs’ motion seeking reconsideration of the February 14, 2019 order. On May 22, 2019, in a telephonic status conference, Judge Dick set a schedule for summary judgment briefing. Plaintiffs filed their motion for summary judgment on July 8, 2019 and Defendants filed their oppositions and cross-motions on August 9, 2019. Briefing is now concluded and the motions are before the court. Revolution On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line, in the vicinity of Ivy Lane located in Center Township, Beaver County, Pennsylvania. There were no injuries, but there were evacuations of local residents as a precautionary measure. The Pennsylvania Department of Environmental Protection (“PADEP”) and the Pennsylvania Public Utility Commission (“PUC”) are investigating the incident. On October 29, 2018, PADEP issued a Compliance Order requiring our subsidiary, ETC Northeast Pipeline, LLC (“ETC Northeast”), to cease all earth disturbance activities at the site (except as necessary to repair and maintain existing Best Management Practices (“BMPs”) and temporarily stabilize disturbed areas), implement and/or maintain the Erosion and Sediment BMPs at the site, stake the limit of disturbance, identify and report all areas of non-compliance, and submit an updated Erosion and Sediment Control Plan, a Temporary Stabilization Plan, and an updated Post Construction Stormwater Management Plan. The scope of the Compliance Order has been expanded to include the disclosure to PADEP of alleged violations of environmental permits with respect to various construction and post-construction activities and restoration obligations along the 42-mile route of the Revolution line. ETC Northeast filed an appeal of the Compliance Order with the Pennsylvania Environmental Hearing Board. On February 8, 2019, PADEP filed a Petition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The court issued an Order on February 14, 2019 requiring the submission of an answer to the Petition on or before March 12, 2019, and scheduled a hearing on the Petition for March 26, 2019. On March 12, 2019, ETC Northeast answered the Petition. ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019. On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board on March 11, 2019. On May 14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on June 14, 2019. On August 5, 2019, ETC Northeast and the Partnership received a Subpoena to Compel Documents and Information related to the Revolution pipeline and the Incident. ETC Northeast and the Partnership filed an appeal of the Subpoena on September 4, 2019. The Partnership continues to work through these issues with PADEP during the pendency of these appeals. The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time. Chester County, Pennsylvania Investigation In December 2018, the Chester County District Attorney sent a letter to the Partnership stating that it was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines. Subsequently, the matter was submitted to an Investigating grand Jury in Chester County, Pennsylvania. As part of the Grand Jury proceedings, since April and August 2019, the Partnership was served with a total of forty-one grand jury subpoenas seeking a variety of documents and records sought by the Chester County Investigation Grand Jury. On September 24, 2019, the Chester County District Attorney sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership intends to respond to the notice of Intent within the proscribed time period. Delaware County, Pennsylvania Investigation On March 11, 2019, the Delaware County District Attorney’s Office (“Delaware County D.A.”) announced that the Delaware County D.A. and the Pennsylvania Attorney General’s Office, at the request of the Delaware County D.A., are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. The Partnership has not been appraised of the specific conduct under investigation. This investigation is ongoing. While the Partnership will cooperate with the investigation, it intends to vigorously defend itself against these allegations. Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2019 and December 31, 2018, accruals of approximately $61 million and $55 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against SPLP before the PUC. Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township. Following a hearing on May 7 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the PADEP has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018, the PUC entered an Order lifting the stay of construction on ME2 and ME2x in the Township with respect to four of the eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining construction sites, the PUC lifted the construction stay on those two sites as well. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue this matter. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition. Briefing in the Commonwealth Court has been completed. On June 3, 2019, the Commonwealth Court heard argument on whether Senator Dinniman has standing. On September 9, 2019, the Commonwealth Court issued an Opinion finding that Senator Dinniman did not have standing in either his personal or representational capacity. The Commonwealth Court’s Order remanded the case to the PUC to dissolve the interim emergency injunction and dismiss the Complaint. Senator Dinniman has not sought to appeal the ruling. Previously, on March 29, 2019, SPLP filed a supplemental affidavit with the PUC in accordance with the established procedure to request the PUC lift the stay of construction of ME2 for one of the remaining work locations in the Township - Shoen Road. That same day, Senator Dinniman filed a letter objecting to SPLP’s request, arguing the Commonwealth Court’s order staying all proceedings barred the PUC from issuing an approval to lift the stay of construction of ME2 at Shoen Road. Given the Commonwealth Court’s September 9 opinion, the PUC dissolved the injunction on September 19, 2019 and work on Shoen Road commenced. No amounts have been recorded in our September 30, 2019 or December 31, 2018 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. In February 2017, we received letters from the DOJ on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees. On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018. In October 2018, Pipeline Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan. On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. During the three months ended September 30, 2019 and 2018, the Partnership recorded $16 million and $17 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2019 and 2018, the Partnership recorded $31 million and $32 million, respectively, of expenditures related to environmental cleanup programs. Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
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Debt Obligations |
9 Months Ended |
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Sep. 30, 2019 | |
Debt Obligations [Abstract] | |
Debt Obligations | DEBT OBLIGATIONS Parent Company Indebtedness ET Term Loan Facility On January 15, 2019, ET paid in full all outstanding borrowings under its senior secured term loan agreement and thereafter terminated the term loan agreement. In connection with the termination of the term loan agreement, the collateral securing certain series of the Partnership’s outstanding senior notes was released in accordance with the terms of the applicable indentures governing such senior notes. Subsidiary Indebtedness ET-ETO Senior Notes Exchange In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”). Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. Following the exchange, the ET senior notes that were not tendered and remain outstanding as of September 30, 2019 were as follows: •$52 million aggregate principal amount of 7.50% senior notes due 2020; •$5 million aggregate principal amount of 4.25% senior notes due 2023; •$23 million aggregate principal amount of 5.875% senior notes due 2024; and •$44 million aggregate principal amount of 5.50% senior notes due 2027. In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes: •$1.14 billion aggregate principal amount of 7.50% senior notes due 2020; •$995 million aggregate principal amount of 4.25% senior notes due 2023; •$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and •$956 million aggregate principal amount of 5.50% senior notes due 2027. The senior notes were registered under the Securities Act of 1933 (as amended). ETO may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually. The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. ETO Senior Notes Offering and Redemption In January 2019, ETO issued the following senior notes: •$750 million aggregate principal amount of 4.50% senior notes due 2024; •$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and •$1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The senior notes were registered under the Securities Act of 1933 (as amended). ETO may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal on the senior notes is payable upon maturity and interest is paid semi-annually. The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following: •ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019; •ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and •Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019. Panhandle Senior Notes Redemption In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO. Bakken Senior Notes Offering In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline: •$650 million aggregate principal amount of 3.625% senior notes due 2022; •$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and •$850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated. Sunoco LP Senior Notes Offering In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms. USAC Senior Notes Offering In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes. Credit Facilities and Commercial Paper ETO Term Loan On October 17, 2019, ETO entered into a term loan credit agreement providing for a $2 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement will be unsecured and will be guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P. Borrowings under the term loan agreement will bear interest at a eurodollar rate or a base rate, at ETO’s option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates are based on the credit ratings assigned to the senior, unsecured, non-credit enhanced long-term debt of ETO. 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 on December 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 of September 30, 2019, the ETO Five-Year Credit Facility had $2.61 billion of outstanding borrowings, $2.15 billion of which was commercial paper. The amount available for future borrowings was $2.32 billion after taking into account letters of credit of $77 million. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 2.77%. 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 on November 29, 2019. As of September 30, 2019, 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 in July 2023. As of September 30, 2019, the Sunoco LP Credit Facility had $154 million of outstanding borrowings and $8 million in standby letters of credit. As of September 30, 2019, Sunoco LP had $1.34 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.04%. 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 in April 2023. As of September 30, 2019, the USAC Credit Facility had $395 million of outstanding borrowings and no outstanding letters of credit. As of September 30, 2019, USAC had $1.21 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $410 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.73%. Compliance with Our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2019.
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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities (Tables) |
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Environmental Exit Costs by Cost | The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
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Schedule of Rent Expense [Table Text Block] | We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying statements of operations:
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Derivative Assets And Liabilities Derivative Assets and Liabilities (Policies) |
9 Months Ended |
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Sep. 30, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern our portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. Our counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. We have maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
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Derivatives, Policy [Policy Text Block] | Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy. We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or non-current depending on the anticipated settlement date.
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Inventories (Tables) |
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Inventory, Net [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Inventory | Inventories consisted of the following:
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Operations And Organization |
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Operations And Organization | ORGANIZATION AND BASIS OF PRESENTATION Organization The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”). References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis. In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, ETO unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. was renamed Energy Transfer Operating, L.P. In addition, Energy Transfer Equity, L.P. was renamed Energy Transfer LP, and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on October 19, 2018. Immediately prior to the closing of the Energy Transfer Merger, the following also occurred:
Subsequent to the Energy Transfer Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived 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. Parent Company-only assets are not available to satisfy the debts and other obligations of ET’s subsidiaries. Our financial statements reflect the following reportable segments: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; •investment in USAC; and •corporate and other, including the following:
Basis of Presentation The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on February 22, 2019. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. The consolidated financial statements of ET presented herein include the results of operations of:
Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities. Certain prior period amounts have also been reclassified to conform to the current period presentation. These reclassifications had no impact on net income or total equity. Use of Estimates The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates. Change in Accounting Policy Adoption of Lease Accounting Standard In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard. To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard. To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population. Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows:
Additional disclosures related to lease accounting are included in Note 13. Goodwill The Partnership’s interstate transportation and storage segment owns Southwest Gas which owns and operates natural gas storage assets. Due to a decrease in the demand for storage on these assets, the Partnership performed an interim impairment test on the assets of Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $12 million related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s other assets were identified. The Partnership estimated the fair value of Southwest Gas by using the income approach. The income approach is based on the present value of future cash flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, a discount rate and a terminal value.
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Inventories Inventories (Policies) |
9 Months Ended |
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Sep. 30, 2019 | |
Inventory Disclosure [Abstract] | |
Inventory, Policy [Policy Text Block] | We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
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Related Party Transactions |
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Related Party Transactions | RELATED PARTY TRANSACTIONS The Partnership has related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the revenues from related companies on our consolidated statements of operations:
The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:
As of September 30, 2019 and December 31, 2018, accounts payable with unconsolidated affiliates in the Partnership’s consolidated balance sheets totaled $32 million and $59 million, respectively.
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Lease Accounting (Policies) |
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Sep. 30, 2019 | |
Leases [Abstract] | |
Lessee, Leases [Policy Text Block] | Change in Accounting Policy Adoption of Lease Accounting Standard In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard. To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard. To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population. Lessee Accounting The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet. At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term. To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives. Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance. For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
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Lessor, Leases [Policy Text Block] | Lessor Accounting Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement. Rental income included in other revenue in our consolidated statement of operations for the three and nine months ended September 30, 2019 was $39 million and $111 million, respectively.
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Cash And Cash Equivalents Net Change in Operating Assets and Liabilities (Details) - USD ($) $ in Millions |
9 Months Ended | |
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Sep. 30, 2019 |
Sep. 30, 2018 |
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Supplemental Cash Flow Elements [Abstract] | ||
Accounts receivable | $ (353) | $ 155 |
Accounts receivable from related companies | (36) | 64 |
Inventories | (66) | 78 |
Other current assets | 14 | (19) |
Other non-current assets, net | (127) | (25) |
Accounts payable | 25 | (234) |
Accounts payable to related companies | (37) | (110) |
Accrued and other current liabilities | 129 | 422 |
Other non-current liabilities | (103) | 24 |
Derivative assets and liabilities, net | 307 | 68 |
Net change in operating assets and liabilities, net of effects of acquisitions | $ 247 | $ (423) |
Lease Accounting (Tables) |
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Leases [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | The weighted average remaining lease terms and weighted average discount rates as of September 30, 2019 were as follows:
Maturities of lease liabilities as of September 30, 2019 are as follows:
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Schedule of additional lease information [Table Text Block] | Cash flows and non-cash activity related to leases for the nine months ended September 30, 2019 were as follows:
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Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block] | Future minimum operating lease payments receivable as of September 30, 2019 are as follows:
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Schedule of Property Subject to or Available for Operating Lease [Table Text Block] | The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of September 30, 2019 were as follows:
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Lease, Cost [Table Text Block] | The components of lease expense for the three and nine months ended September 30, 2019 were as follows:
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Regulatory Matters, Commitments, Contingencies And Environmental Liabilities Schedule of Right of Way Expense (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2019 |
Sep. 30, 2018 |
Sep. 30, 2019 |
Sep. 30, 2018 |
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Commitments and Contingencies Disclosure [Abstract] | ||||
Contractual Right of Way, Expense | $ 5 | $ 5 | $ 17 | $ 18 |
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