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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
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December 31, 2019
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☐
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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72-1252419
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer Identification No.)
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499 West Sheridan Avenue,
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Suite 1500
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Oklahoma City,
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Oklahoma
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73102
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Trading symbol(s)
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Name of each exchange on which registered
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Common Units Representing Limited Partner Interests
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ENBL
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New York Stock Exchange
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Large accelerated filer
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☒
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Accelerated filer
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☐
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Non-accelerated filer
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☐
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Smaller reporting company
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☐
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Emerging growth company
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☐
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Page
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EGT.
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Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates a 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex Basins in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas.
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Enable GP.
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Enable GP, LLC, the general partner of Enable Midstream Partners, LP.
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Enable Midstream Services.
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Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
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EOCS.
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Enable Oklahoma Crude Services, LLC, formerly Velocity Holdings, LLC, a wholly owned subsidiary of the Partnership that provides crude oil and condensate gathering services to customers in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.
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EOIT.
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Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates a 2,300-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
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EOIT Senior Notes.
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$250 million aggregate principal amount of the EOIT’s 6.25% senior notes due 2020.
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EPA.
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Environmental Protection Agency.
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EPAct of 2005.
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Energy Policy Act of 2005.
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ERISA.
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Employee Retirement Income Security Act of 1974.
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ESCP.
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Enable South Central Pipeline, LLC, formerly Velocity Pipeline Partners, LLC, in which the Partnership, through EOCS, owns a 60% joint venture interest in a 26-mile pipeline system with a third party which owns and operates a refinery connected to the EOCS system.
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ETGP.
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Enable Texola Gathering & Processing, LLC, formerly Align Midstream, LLC, a wholly owned subsidiary of the Partnership that provides natural gas gathering and processing services to customers in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin in Texas.
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Exchange Act.
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Securities Exchange Act of 1934, as amended.
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FASB.
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Financial Accounting Standards Board.
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FERC.
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Federal Energy Regulatory Commission.
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Fractionation.
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The separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale.
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GAAP.
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Accounting principles generally accepted in the United States of America.
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Gas imbalance.
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The difference between the actual amounts of natural gas delivered from or received by a pipeline, as compared to the amounts scheduled to be delivered or received.
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General partner.
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Enable GP, LLC, the general partner of Enable Midstream Partners, LP.
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GHG.
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Greenhouse gas.
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Gross margin.
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Please read “Measures We Use to Evaluate Results of Operations” under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the definition.
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HLPSA.
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Hazardous Liquid Pipeline Safety Act of 1979.
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ICA.
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Interstate Commerce Act.
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ICE.
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Intercontinental Exchange.
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IPO.
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Initial public offering of Enable Midstream Partners, LP.
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IRS.
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Internal Revenue Service.
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LDC.
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Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
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Lean gas.
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Natural gas that is primarily methane.
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LIBOR.
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London Interbank Offered Rate.
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LNG.
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Liquefied natural gas.
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MAOP.
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Maximum allowable operating pressure for gas pipelines.
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MBbl.
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Thousand barrels.
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MBbl/d.
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Thousand barrels per day.
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MMBtu.
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Million British thermal units.
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MMcf.
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Million cubic feet of natural gas.
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•
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changes in general economic conditions;
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competitive conditions in our industry;
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actions taken by our customers and competitors;
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the supply and demand for natural gas, NGLs, crude oil and midstream services;
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our ability to successfully implement our business plan;
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our ability to complete internal growth projects on time and on budget;
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the price and availability of debt and equity financing;
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strategic decisions by CenterPoint Energy and OGE Energy regarding their ownership of us and Enable GP;
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operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, NGLs, crude oil and midstream products;
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natural disasters, weather-related delays, casualty losses and other matters beyond our control;
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interest rates;
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the timing and extent of changes in labor and material prices;
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labor relations;
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large customer defaults;
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changes in the availability and cost of capital;
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changes in tax status;
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the effects of existing and future laws and governmental regulations;
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changes in insurance markets impacting costs and the level and types of coverage available;
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the timing and extent of changes in commodity prices;
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the suspension, reduction or termination of our customers’ obligations under our commercial agreements;
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disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;
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the effects of current or future litigation; and
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other factors set forth in this report and our other filings with the SEC.
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Capitalize on Organic Growth and Asset Optimization Opportunities Associated with Our Strategically Located Assets: We own and operate assets servicing four major producing basins and key natural gas and crude oil demand centers in the United States. We intend to grow our business by utilizing a disciplined approach emphasizing capital efficiency when operating our existing assets and developing new midstream energy infrastructure projects to support new and existing customers in these areas.
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Maintain Strong Customer Relationships to Attract New Volumes and Expand Beyond Our Existing Asset Footprint and Business Lines: Management believes that we have built a strong and loyal customer base through exemplary customer service and reliable project execution. We have invested in organic growth projects in support of our existing and new customers. We work to build and maintain relationships with key customers both on the supply and demand sides of the natural gas and crude oil value chain, in an effort to attract new volumes and to expand our asset footprint and business lines.
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Continue to Minimize Direct Commodity Price Exposure Through Fee-Based Contracts: We continually seek ways to minimize our exposure to commodity price risk. Management believes that focusing on fee-based revenues reduces
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Grow Through Accretive Acquisitions: We continually evaluate potential acquisitions of complementary assets with the potential for attractive returns in new and existing operating areas and midstream business lines. We will continue to analyze acquisition opportunities using disciplined financial and operating practices, including evaluating and managing risks to cash available for distribution.
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Anadarko Basin (Oklahoma, Texas Panhandle). We have natural gas gathering and processing operations in those portions of the Anadarko Basin located in Oklahoma and the Texas Panhandle where, as of December 31, 2019, we served approximately 210 producers. Our operations include gathering and processing natural gas produced from the SCOOP, STACK, Granite Wash, Cleveland, Marmaton, Tonkawa, Cana Woodford and Mississippi Lime plays. The current focus of our Anadarko Basin gathering and processing operations is primarily on rich gas production.
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Arkoma Basin (Oklahoma, Arkansas). In the Arkoma Basin, our operations primarily serve the Woodford Shale play located in Oklahoma and the Fayetteville Shale play located in Arkansas. Our Arkoma Basin gathering and processing operations serve both rich and lean gas production. As of December 31, 2019, we served approximately 80 producers in the Arkoma Basin.
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Ark-La-Tex Basin (Arkansas, Louisiana and Texas). We have gathering and processing operations in the Ark-La-Tex Basin located in Arkansas, Louisiana and Texas. Our Ark-La-Tex gathering and processing operations primarily serve the Haynesville, Cotton Valley and the lower Bossier plays. As of December 31, 2019, we served approximately 90 producers in the Ark-La-Tex Basin where our gathering and processing operations provide service for both rich and lean gas production.
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Anadarko Basin (Oklahoma). In the Anadarko Basin, we have operations that are located in Oklahoma. Our operations in the Anadarko Basin include the gathering of crude oil and condensate from producers in the SCOOP and STACK plays (including the area where the SCOOP and STACK come together known as the Merge play). As of December 31, 2019, our customers included five producers and one refinery.
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Williston Basin (North Dakota). In the Williston Basin, we have operations in the Bakken Shale that are located in North Dakota. The focus of our operations in the Williston Basin is the gathering of crude oil and produced water for XTO Energy Inc. (XTO), an affiliate of ExxonMobil Corporation, with pipeline gathering systems in Dunn, McKenzie, Williams and Mountrail Counties of North Dakota.
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Asset/Basin
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Approximate Length
(miles)
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Approximate Compression
(Horsepower)
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Average
Gathered
Volume
(TBtu/d)
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Number of
Processing
Plants
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Processing
Capacity
(MMcf/d)
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NGLs
Produced
(MBbl/d) (1)
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Anadarko Basin (2)
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8,700
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889,700
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2.34
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11
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1,845
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113.20
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Arkoma Basin
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3,000
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139,800
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0.47
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1
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60
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5.42
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Ark-La-Tex Basin (3)
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1,800
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158,400
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1.75
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3
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645
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9.96
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Total
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13,500
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1,187,900
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4.56
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15
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2,550
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128.58
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(1)
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Excludes condensate.
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(2)
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Anadarko Basin processing capacity does not include firm contracted capacity of 400 MMcf/d at Energy Transfer’s Godley plant.
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(3)
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Ark-La-Tex Basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.
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Processing Plant Assets (1)
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Year
Installed
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Type of Plant
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Average
Daily Inlet
Volumes
(MMcf/d)
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Inlet
Capacity
(MMcf/d)
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NGL Production Capacity (Bbl/d)(2)
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Anadarko
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Bradley II
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2016
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Cryogenic
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151
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200
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28,000
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Bradley
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2015
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Cryogenic
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184
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200
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28,000
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McClure
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2013
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Cryogenic
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206
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200
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22,000
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Wheeler
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2012
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Cryogenic
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137
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200
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22,000
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South Canadian
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2011
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Cryogenic
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194
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200
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26,000
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Clinton
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2009
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Cryogenic
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111
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120
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14,000
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Roger Mills
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2008
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Refrigeration
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26
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100
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—
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Canute
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1996
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Cryogenic
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29
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60
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4,300
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Cox City
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1994
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Cryogenic
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138
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180
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14,500
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Thomas
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1981
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Cryogenic
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99
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135
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9,900
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Calumet
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1969
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Lean Oil
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138
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250
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8,000
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Arkoma
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Wetumka
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1983
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Cryogenic
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43
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60
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5,000
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Ark-La-Tex
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Panola
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2007
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Cryogenic
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47
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100
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8,000
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Sligo (3)
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2004
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Refrigeration
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20
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225
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1,400
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Waskom
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1995
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(4)
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Cryogenic
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247
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320
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14,500
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Total
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1,770
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2,550
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205,600
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(1)
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In addition to the processing plants listed above, the Partnership is a party to a 10-year gathering and processing agreement, which became effective on July 1, 2018, and provides for 400 MMcf/d of deliveries to Energy Transfer, LP’s Godley Plant in Johnson County, Texas.
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(2)
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Excludes condensate.
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(3)
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Average daily inlet volumes and inlet capacity includes 20 MMcf/d and 25 MMcf/d, respectively, related to a separate cryogenic unit.
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(4)
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A processing plant has been in operation on the Waskom plant site since 1940. The Waskom plant was upgraded to cryogenic in 1995.
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Asset/Basin
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Approximate Length
(miles)
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Design Capacity (MBbls/d)
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Average
Throughput Volume (MBbls/d) |
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Anadarko Basin crude oil and condensate
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175
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275
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92.70
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Williston Basin crude oil
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175
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58
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35.76
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Williston Basin produced water
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150
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19
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13.95
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Total
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500
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352
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142.41
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•
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Under a typical fee-based processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs from the producer less a fee, return the processed natural gas to the producer and sell the NGLs for our own account.
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Under a typical percent-of-liquids processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs, less the value of the percentage of NGLs retained on our own account, from the producer, return the processed natural gas to the producer and sell the NGLs for our own account.
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Under a typical percent-of-proceeds processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs, less the value of the percentage of natural gas and NGLs retained on our own account, return the remaining percentage of processed natural gas to the producer and sell the purchased natural gas and NGLs for our own account.
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•
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Under a typical keep-whole arrangement, we process raw natural gas to extract the NGLs, return a quantity of the processed natural gas to the producer that is equivalent to the raw natural gas on a Btu basis and retain and sell the NGLs for our own account.
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Anadarko Basin
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Arkoma Basin
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Ark-La-Tex Basin
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Williston Basin (2)
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Total
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Percentage of gathering and processing gross margin attributable to gathering contracts with minimum volume commitments
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4
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%
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6
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%
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11
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%
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1
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%
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22
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%
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Percentage attributable to shortfall payments (1)
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5
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%
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83
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%
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19
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%
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—
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%
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33
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%
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Natural gas volume commitment-weighted average remaining contract term (in years) (3)
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7.4
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4.7
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0.5
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—
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3.3
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Crude oil and condensate volume commitment-weighted average remaining contract term (in years) (3)
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—
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—
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—
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9.2
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9.2
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(1)
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Represents the percentage of gathering and processing gross margin from gathering contracts with minimum volume commitments that were attributable to shortfall payments.
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(2)
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Under the Williston Basin contracts, if the customer ships in excess of the minimum volume, this volume commitment could end before the expiration of the contract term.
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(3)
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Weighted-average is based upon volumes for the year ended December 31, 2019.
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Anadarko Basin
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Arkoma Basin
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Ark-La-Tex Basin
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Williston Basin
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Total
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Gross acreage dedication (in millions)
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5.0
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1.7
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1.2
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0.3
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8.2
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Natural gas volume-weighted average remaining contract term (in years)
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5.4
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1.8
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3.8
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—
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4.3
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Crude oil and condensate volume-weighted average remaining contract term (in years)
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12.6
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—
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—
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10.4
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11.8
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Transportation and Storage
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Asset
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Length
(miles)
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Compression
(Horsepower)
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Average
Throughput
(TBtu/d)
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Transportation
Capacity
(Bcf/d) (1)
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Transportation
Firm Contracted Capacity (Bcf/d) (2) |
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Storage Capacity
(Bcf)
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Storage Firm Contracted Capacity
(Bcf/d) |
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|||||||
EGT
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5,900
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391,300
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3.24
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6.3
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4.73
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29.0
|
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22.92
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MRT
|
|
1,600
|
|
|
119,700
|
|
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0.80
|
|
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1.7
|
|
|
1.58
|
|
|
31.5
|
|
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24.41
|
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EOIT
|
|
2,300
|
|
|
218,800
|
|
|
2.14
|
|
(3)
|
—
|
|
(3)
|
—
|
|
|
24.0
|
|
|
10.08
|
|
|
Subtotal
|
|
9,800
|
|
|
729,800
|
|
|
6.18
|
|
|
8.0
|
|
|
6.31
|
|
|
84.5
|
|
|
57.41
|
|
|
SESH
|
|
290
|
|
|
107,800
|
|
|
—
|
|
(5)
|
—
|
|
(4)
|
—
|
|
(5)
|
—
|
|
(5)
|
—
|
|
(5)
|
Total
|
|
10,090
|
|
|
837,600
|
|
|
6.18
|
|
|
8.0
|
|
|
6.31
|
|
|
84.5
|
|
|
57.41
|
|
|
(1)
|
Actual volumes transported per day may be less than total firm contracted capacity based on demand.
|
(2)
|
Transportation Firm Contracted Capacity includes contracts with affiliates and our subsidiaries.
|
(3)
|
Our EOIT pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits our ability to determine an overall system capacity. During the year ended December 31, 2019, the peak daily throughput was 2.3 TBtu/d or, on a volumetric basis, 2.3 Bcf/d.
|
(4)
|
SESH has 1.09 Bcf/d of transportation capacity from Perryville, Louisiana to its endpoint in Mobile County, Alabama.
|
(5)
|
We own a 50% interest in SESH and as such, do not include certain information regarding its transportation and storage assets in the table set forth above.
|
•
|
rates, terms and conditions of service and service contracts;
|
•
|
certification and construction of new facilities or expansion of existing facilities;
|
•
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abandonment of facilities;
|
•
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maintenance of accounts and records;
|
•
|
acquisition and disposition of facilities;
|
•
|
initiation, extension or abandonment of services;
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•
|
accounting, depreciation and amortization policies;
|
•
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conduct and relationship with certain affiliates;
|
•
|
market manipulation in connection with the purchase or sale of natural gas or transportation in interstate commerce; and
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•
|
various other matters.
|
•
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the overall cost of service, including operating costs and overhead;
|
•
|
the allocation of overhead and other administrative and general expenses to the regulated entity;
|
•
|
the appropriate capital structure to be utilized in calculating rates;
|
•
|
the appropriate rate of return on equity and interest rates on debt;
|
•
|
the rate base, including the proper starting rate base; and
|
•
|
the throughput underlying the rate.
|
•
|
the fees and gross margins we realize with respect to the volume of natural gas, NGLs and crude oil that we handle;
|
•
|
the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;
|
•
|
the volume of natural gas, NGLs and crude oil we gather, compress, treat, dehydrate, process, fractionate, transport and store;
|
•
|
the relationship among prices for natural gas, NGLs and crude oil;
|
•
|
cash calls and settlements of hedging positions;
|
•
|
margin requirements on open price risk management assets and liabilities;
|
•
|
the level of competition from other companies offering midstream services;
|
•
|
adverse effects of governmental and environmental regulation;
|
•
|
the level of our operation and maintenance expenses and general and administrative costs; and
|
•
|
prevailing economic conditions.
|
•
|
the level and timing of capital expenditures we make;
|
•
|
the cost of acquisitions;
|
•
|
our debt service requirements and other liabilities;
|
•
|
fluctuations in working capital needs;
|
•
|
our ability to borrow funds and access capital markets;
|
•
|
restrictions contained in our debt agreements;
|
•
|
the amount of cash reserves established by our general partner;
|
•
|
distributions paid on our Series A Preferred Units; and
|
•
|
other business risks affecting our cash levels.
|
•
|
the availability and cost of capital;
|
•
|
prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;
|
•
|
demand for natural gas, NGLs and crude oil;
|
•
|
levels of reserves;
|
•
|
geological considerations;
|
•
|
environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing, and the regulation of air emissions; and
|
•
|
the availability of drilling rigs and other costs of production and equipment.
|
•
|
our joint venture partners may share certain approval rights over major decisions;
|
•
|
our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;
|
•
|
we may be unable to control the amount of cash we will receive from the joint venture;
|
•
|
we may incur liabilities as a result of an action taken by our joint venture partners;
|
•
|
we may be required to devote significant management time to the requirements of and matters relating to the joint ventures;
|
•
|
our insurance policies may not fully cover loss or damage incurred by both us and our joint venture partners in certain circumstances;
|
•
|
our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and
|
•
|
disputes between us and our joint venture partners may result in delays, litigation or operational impasses.
|
•
|
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;
|
•
|
inadvertent damage from construction, vehicles and farm and utility equipment;
|
•
|
leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;
|
•
|
ruptures, fires and explosions; and
|
•
|
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
|
•
|
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
|
•
|
acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
|
•
|
we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;
|
•
|
we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and
|
•
|
acquisitions, or the pursuit of acquisitions, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.
|
•
|
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;
|
•
|
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;
|
•
|
our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
|
our debt level may limit our flexibility in responding to changing business and economic conditions.
|
•
|
permit our subsidiaries to incur or guarantee additional debt;
|
•
|
incur or permit to exist certain liens on assets;
|
•
|
dispose of assets;
|
•
|
merge or consolidate with another company or engage in a change of control;
|
•
|
enter into transactions with affiliates on non-arm’s length terms; and
|
•
|
change the nature of our business.
|
•
|
rates, operating terms, conditions of service and service contracts;
|
•
|
certification and construction of new facilities;
|
•
|
extension or abandonment of services and facilities or expansion of existing facilities;
|
•
|
maintenance of accounts and records;
|
•
|
acquisition and disposition of facilities;
|
•
|
initiation and discontinuation of services;
|
•
|
depreciation and amortization policies;
|
•
|
conduct and relationship with certain affiliates;
|
•
|
market manipulation in connection with interstate sales, purchases or natural gas transportation; and
|
•
|
various other matters.
|
•
|
perform ongoing assessments of pipeline integrity;
|
•
|
develop a baseline plan to prioritize the assessment of a covered pipeline segment;
|
•
|
identify and characterize applicable threats that could impact a high consequence area;
|
•
|
improve data collection, integration, and analysis;
|
•
|
repair and remediate pipelines as necessary; and
|
•
|
implement preventive and mitigating action.
|
•
|
Neither the Partnership Agreement nor any other agreement requires CenterPoint Energy or OGE Energy to pursue a business strategy that favors us. The directors and officers of CenterPoint Energy and OGE Energy have a fiduciary duty to make decisions in the best interests of the stockholders of their respective companies, which may be contrary to our interests. CenterPoint Energy and OGE Energy may choose to shift the focus of their investment and growth to areas not served by our assets. In addition, CenterPoint Energy is the holder of our Series A Preferred Units and may favor its interests in voting in favor of actions relating to such units, including voting in favor of making distributions on such Series A Preferred Units even if no distributions are made on the common units.
|
•
|
Our general partner is allowed to take into account the interests of parties other than us, such as CenterPoint Energy and OGE Energy, in resolving conflicts of interest.
|
•
|
Some of the directors of our general partner are also officers and/or directors of CenterPoint Energy or OGE Energy and will owe fiduciary duties to their respective companies. These individuals may also devote significant time to the business of CenterPoint Energy or OGE Energy, respectively.
|
•
|
The Partnership Agreement replaces the fiduciary duties that would otherwise be owed to us by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.
|
•
|
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
|
•
|
Disputes may arise under our commercial agreements with CenterPoint Energy and OGE Energy.
|
•
|
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of distributable cash flow.
|
•
|
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders.
|
•
|
Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
|
•
|
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
|
•
|
The Partnership Agreement permits us to classify up to $300 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the incentive distribution rights.
|
•
|
The Partnership Agreement does not prohibit our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
|
•
|
Our general partner intends to limit its liability regarding our contractual and other obligations.
|
•
|
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 90% of the common units. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%.
|
•
|
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
|
•
|
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
Our general partner may transfer its incentive distribution rights without unitholder approval.
|
•
|
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the Board of Directors or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
|
•
|
how to allocate corporate opportunities among us and its other affiliates;
|
•
|
whether to exercise its limited call right;
|
•
|
whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors;
|
•
|
whether to elect to reset target distribution levels;
|
•
|
whether to transfer the incentive distribution rights to a third party; and
|
•
|
whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.
|
•
|
whenever our general partner, the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of the Partnership, and, except as specifically provided by our Partnership Agreement, will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;
|
•
|
our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
our general partner will not be in breach of its obligations under the Partnership Agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
|
•
|
approved by the conflicts committee of the Board of Directors, although our general partner is not obligated to seek such approval;
|
•
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
|
•
|
determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
|
•
|
determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
•
|
our existing unitholders’ proportionate ownership interest in us will decrease;
|
•
|
the amount of distributable cash flow on each unit may decrease;
|
•
|
because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
•
|
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
|
•
|
a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitutes “control” of our business.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions, except for per unit data)
|
||||||||||||||||||
Results of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues (1)
|
$
|
2,960
|
|
|
$
|
3,431
|
|
|
$
|
2,803
|
|
|
$
|
2,272
|
|
|
$
|
2,418
|
|
Cost of natural gas and natural gas liquids, excluding depreciation and amortization (1)
|
1,279
|
|
|
1,819
|
|
|
1,381
|
|
|
1,017
|
|
|
1,097
|
|
|||||
Operation and maintenance, General and administrative
|
526
|
|
|
501
|
|
|
464
|
|
|
465
|
|
|
522
|
|
|||||
Depreciation and amortization
|
433
|
|
|
398
|
|
|
366
|
|
|
338
|
|
|
318
|
|
|||||
Impairments
|
86
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
1,134
|
|
|||||
Taxes other than income tax
|
67
|
|
|
65
|
|
|
64
|
|
|
58
|
|
|
59
|
|
|||||
Operating income (loss)
|
569
|
|
|
648
|
|
|
528
|
|
|
385
|
|
|
(712
|
)
|
|||||
Interest expense
|
(190
|
)
|
|
(152
|
)
|
|
(120
|
)
|
|
(99
|
)
|
|
(90
|
)
|
|||||
Equity in earnings of equity method affiliates
|
17
|
|
|
26
|
|
|
28
|
|
|
28
|
|
|
29
|
|
|||||
Other, net
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|||||
Income (loss) before income taxes
|
399
|
|
|
522
|
|
|
436
|
|
|
314
|
|
|
(771
|
)
|
|||||
Income tax (benefit) expense
|
(1
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
|||||
Net income (loss)
|
$
|
400
|
|
|
$
|
523
|
|
|
$
|
437
|
|
|
$
|
313
|
|
|
$
|
(771
|
)
|
Less: Net income (loss) attributable to noncontrolling interests
|
4
|
|
|
2
|
|
|
1
|
|
|
1
|
|
|
(19
|
)
|
|||||
Net income (loss) attributable to limited partners
|
$
|
396
|
|
|
$
|
521
|
|
|
$
|
436
|
|
|
$
|
312
|
|
|
$
|
(752
|
)
|
Less: Series A Preferred Unit distributions
|
36
|
|
|
36
|
|
|
36
|
|
|
22
|
|
|
—
|
|
|||||
Net income (loss) attributable to common and subordinated units
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
400
|
|
|
$
|
290
|
|
|
$
|
(752
|
)
|
Basic earnings (loss) per common limited partner unit
|
$
|
0.83
|
|
|
$
|
1.12
|
|
|
$
|
0.92
|
|
|
$
|
0.69
|
|
|
$
|
(1.78
|
)
|
Diluted earnings (loss) per common limited partner unit
|
$
|
0.82
|
|
|
$
|
1.11
|
|
|
$
|
0.92
|
|
|
$
|
0.69
|
|
|
$
|
(1.78
|
)
|
Basic and diluted earnings (loss) per subordinated limited
partner unit (2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.93
|
|
|
$
|
0.68
|
|
|
$
|
(1.78
|
)
|
Distributions declared per unit (3)
|
$
|
1.3095
|
|
|
$
|
1.2720
|
|
|
$
|
1.2720
|
|
|
$
|
1.2720
|
|
|
$
|
1.2645
|
|
(1)
|
Revenues and Cost of natural gas and natural gas liquids, excluding depreciation and amortization are shown under the guidance of ASC 606 for 2019 and 2018 and under ASC 605 for 2017 and prior.
|
(2)
|
Basic and diluted earnings per subordinated unit reflect net income (loss) attributable to the Partnership. The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017.
|
(3)
|
Distributions are in accordance with the Partnership Agreement. Distributions declared per unit relate to common and subordinated units.
|
|
December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
||||||||||
Property, plant and equipment, net
|
$
|
10,870
|
|
|
$
|
10,871
|
|
|
$
|
10,355
|
|
|
$
|
10,143
|
|
|
$
|
10,131
|
|
Total assets
|
12,266
|
|
|
12,444
|
|
|
11,593
|
|
|
11,212
|
|
|
11,226
|
|
|||||
Total debt
|
4,375
|
|
|
4,278
|
|
|
3,450
|
|
|
2,993
|
|
|
3,270
|
|
|||||
Partners’ Equity
|
7,409
|
|
|
7,618
|
|
|
7,654
|
|
|
7,794
|
|
|
7,531
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions, except for operating data)
|
||||||||||||||||||
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
$
|
942
|
|
|
$
|
924
|
|
|
$
|
834
|
|
|
$
|
721
|
|
|
$
|
726
|
|
Investing activities
|
(430
|
)
|
|
(1,154
|
)
|
|
(706
|
)
|
|
(367
|
)
|
|
(946
|
)
|
|||||
Financing activities
|
(530
|
)
|
|
233
|
|
|
(132
|
)
|
|
(335
|
)
|
|
212
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Other Financial Data (1):
|
|
|
|
|
|
|
|
|
|
||||||||||
Gross margin
|
$
|
1,681
|
|
|
$
|
1,612
|
|
|
$
|
1,422
|
|
|
$
|
1,255
|
|
|
$
|
1,321
|
|
Adjusted EBITDA
|
1,147
|
|
|
1,074
|
|
|
924
|
|
|
873
|
|
|
801
|
|
|||||
DCF
|
784
|
|
|
760
|
|
|
660
|
|
|
639
|
|
|
538
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Natural gas gathered volumes—TBtu
|
1,666
|
|
|
1,637
|
|
|
1,300
|
|
|
1,143
|
|
|
1,148
|
|
|||||
Natural gas gathered volumes—TBtu/d
|
4.56
|
|
|
4.48
|
|
|
3.56
|
|
|
3.13
|
|
|
3.14
|
|
|||||
Natural gas processed volumes—TBtu (2)
|
925
|
|
|
877
|
|
|
715
|
|
|
658
|
|
|
651
|
|
|||||
Natural gas processed volumes—TBtu/d (2)
|
2.53
|
|
|
2.40
|
|
|
1.96
|
|
|
1.80
|
|
|
1.78
|
|
|||||
NGLs produced—MBbl/d (2)(3)
|
128.58
|
|
|
129.98
|
|
|
90.11
|
|
|
78.70
|
|
|
73.55
|
|
|||||
NGLs sold—MBbl/d (3)(4)
|
131.59
|
|
|
132.06
|
|
|
92.21
|
|
|
78.16
|
|
|
75.55
|
|
|||||
Condensate sold—MBbl/d
|
7.41
|
|
|
5.90
|
|
|
4.79
|
|
|
5.27
|
|
|
5.13
|
|
|||||
Crude oil and condensate gathered volumes—MBbl/d
|
128.46
|
|
|
41.07
|
|
|
25.56
|
|
|
25.00
|
|
|
13.86
|
|
|||||
Transported volumes—TBtu
|
2,254
|
|
|
2,028
|
|
|
1,838
|
|
|
1,788
|
|
|
1,814
|
|
|||||
Transported volumes—TBtu/d
|
6.18
|
|
|
5.56
|
|
|
5.04
|
|
|
4.88
|
|
|
4.97
|
|
|||||
Interstate firm contracted capacity—Bcf/d
|
6.31
|
|
|
5.94
|
|
|
6.21
|
|
|
7.04
|
|
|
7.19
|
|
|||||
Intrastate average deliveries—TBtu/d
|
2.14
|
|
|
2.08
|
|
|
1.88
|
|
|
1.72
|
|
|
1.84
|
|
(1)
|
See “Reconciliations of Non-GAAP Financial Measures” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a reconciliation of Gross margin, Adjusted EBITDA and DCF to their most directly comparable financial measure calculated and presented in accordance with GAAP.
|
(2)
|
Includes volumes provided under third-party processing arrangements.
|
(3)
|
Excludes condensate.
|
(4)
|
NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.
|
December 31, 2019
|
Gathering and
Processing
|
|
Transportation
and Storage
|
|
Eliminations
|
|
Enable
Midstream
Partners, LP
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Product sales
|
$
|
1,449
|
|
|
$
|
487
|
|
|
$
|
(403
|
)
|
|
$
|
1,533
|
|
Service revenues
|
889
|
|
|
551
|
|
|
(13
|
)
|
|
1,427
|
|
||||
Total Revenues
|
2,338
|
|
|
1,038
|
|
|
(416
|
)
|
|
2,960
|
|
||||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
|
1,203
|
|
|
491
|
|
|
(415
|
)
|
|
1,279
|
|
||||
Gross margin (1)
|
1,135
|
|
|
547
|
|
|
(1
|
)
|
|
1,681
|
|
||||
Operation and maintenance, General and administrative
|
320
|
|
|
207
|
|
|
(1
|
)
|
|
526
|
|
||||
Depreciation and amortization
|
308
|
|
|
125
|
|
|
—
|
|
|
433
|
|
||||
Impairments
|
86
|
|
|
—
|
|
|
—
|
|
|
86
|
|
||||
Taxes other than income tax
|
41
|
|
|
26
|
|
|
—
|
|
|
67
|
|
||||
Operating income
|
$
|
380
|
|
|
$
|
189
|
|
|
$
|
—
|
|
|
$
|
569
|
|
Equity in earnings of equity method affiliate
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
—
|
|
|
$
|
17
|
|
December 31, 2018
|
Gathering and
Processing
|
|
Transportation
and Storage
|
|
Eliminations
|
|
Enable
Midstream
Partners, LP
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Product sales
|
$
|
2,016
|
|
|
$
|
625
|
|
|
$
|
(535
|
)
|
|
$
|
2,106
|
|
Service revenues
|
802
|
|
|
537
|
|
|
(14
|
)
|
|
1,325
|
|
||||
Total Revenues
|
2,818
|
|
|
1,162
|
|
|
(549
|
)
|
|
3,431
|
|
||||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
|
1,741
|
|
|
628
|
|
|
(550
|
)
|
|
1,819
|
|
||||
Gross margin (1)
|
1,077
|
|
|
534
|
|
|
1
|
|
|
1,612
|
|
||||
Operation and maintenance, General and administrative
|
312
|
|
|
189
|
|
|
—
|
|
|
501
|
|
||||
Depreciation and amortization
|
263
|
|
|
135
|
|
|
—
|
|
|
398
|
|
||||
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Taxes other than income tax
|
38
|
|
|
27
|
|
|
—
|
|
|
65
|
|
||||
Operating income
|
$
|
464
|
|
|
$
|
183
|
|
|
$
|
1
|
|
|
$
|
648
|
|
Equity in earnings of equity method affiliate
|
$
|
—
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
26
|
|
(1)
|
Gross margin is a non-GAAP measure and is defined and reconciled to its most directly comparable financial measures calculated and presented below under the caption Reconciliations of Non-GAAP Financial Measures.
|
|
Year Ended December 31,
|
||||
|
2019
|
|
2018
|
||
Operating Data:
|
|
|
|
||
Natural gas gathered volumes—TBtu
|
1,666
|
|
|
1,637
|
|
Natural gas gathered volumes—TBtu/d
|
4.56
|
|
|
4.48
|
|
Natural gas processed volumes—TBtu
|
925
|
|
|
877
|
|
Natural gas processed volumes—TBtu/d
|
2.53
|
|
|
2.40
|
|
NGLs produced—MBbl/d (1)
|
128.58
|
|
|
129.98
|
|
NGLs sold—MBbl/d (1)(2)
|
131.59
|
|
|
132.06
|
|
Condensate sold—MBbl/d
|
7.41
|
|
|
5.90
|
|
Crude oil and condensate gathered volumes—MBbl/d
|
128.46
|
|
|
41.07
|
|
Transported volumes—TBtu
|
2,254
|
|
|
2,028
|
|
Transported volumes—TBtu/d
|
6.18
|
|
|
5.56
|
|
Interstate firm contracted capacity—Bcf/d
|
6.31
|
|
|
5.94
|
|
Intrastate average deliveries—TBtu/d
|
2.14
|
|
|
2.08
|
|
|
Year Ended December 31,
|
||||
|
2019
|
|
2018
|
||
Operating Data By Basin:
|
|
|
|
||
Anadarko
|
|
|
|
||
Natural gas gathered volumes—TBtu/d
|
2.34
|
|
|
2.21
|
|
Natural gas processed volumes—TBtu/d
|
2.10
|
|
|
1.99
|
|
NGLs produced—MBbl/d (1)
|
113.20
|
|
|
113.63
|
|
Crude oil and condensate gathered volumes—MBbl/d
|
92.70
|
|
|
12.14
|
|
Arkoma
|
|
|
|
||
Natural gas gathered volumes—TBtu/d
|
0.47
|
|
|
0.55
|
|
Natural gas processed volumes—TBtu/d
|
0.09
|
|
|
0.10
|
|
NGLs produced—MBbl/d (1)
|
5.42
|
|
|
6.55
|
|
Ark-La-Tex
|
|
|
|
||
Natural gas gathered volumes—TBtu/d
|
1.75
|
|
|
1.72
|
|
Natural gas processed volumes—TBtu/d
|
0.34
|
|
|
0.31
|
|
NGLs produced—MBbl/d (1)
|
9.96
|
|
|
9.80
|
|
Williston
|
|
|
|
||
Crude oil gathered volumes—MBbl/d
|
35.76
|
|
|
28.93
|
|
(1)
|
Excludes condensate.
|
(2)
|
NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.
|
•
|
revenues from NGL sales decreased $462 million primarily due to a decrease in the average realized sales price from lower average market prices for all NGL products and higher volumes subject to fee deductions for NGLs sold under certain third-party processing arrangements, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins,
|
•
|
revenues from natural gas sales decreased $112 million due to lower average natural gas sales prices and lower sales volumes, and
|
•
|
changes in the fair value of natural gas, condensate and NGL derivatives decreased $37 million.
|
•
|
realized gains on natural gas, condensate and NGL derivatives increased $44 million.
|
•
|
processing service revenues decreased $19 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins.
|
•
|
natural gas gathering revenues increased $65 million due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins and higher revenue associated with the amendment of certain minimum volume commitment contracts in the Arkoma Basin, partially offset by lower gathered volumes in the Arkoma Basin and lower shortfall payments associated with the expiration of certain minimum volume commitment contracts in the Arkoma Basin,
|
•
|
crude oil, condensate and produced water gathering revenues increased $40 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average gathering rates in the Williston Basin, and
|
•
|
natural gas gathering fees increased $65 million due to higher fees and gathered volumes in the Anadarko and Ark-La-Tex Basins and higher revenue associated with the amendment of certain minimum volume commitment contracts in the Arkoma Basin, partially offset by lower gathered volumes in the Arkoma Basin and lower shortfall payments associated with the expiration of certain minimum volume commitment contracts in the Arkoma Basin,
|
•
|
realized gains on natural gas, condensate and NGL derivatives increased $44 million,
|
•
|
crude oil, condensate and produced water gathering revenues increased $40 million primarily due to an increase related to the November 2018 acquisition of EOCS and an increase in volumes in the Williston Basin, partially offset by lower average gathering rates in the Williston Basin, and
|
•
|
a $1 million increase in intercompany management fees.
|
•
|
changes in the fair value of natural gas, condensate and NGL derivatives decreased $37 million,
|
•
|
revenues from NGL sales less the cost of NGLs decreased $22 million due to lower average sales prices for all NGL products, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins,
|
•
|
processing service fees decreased $19 million due to lower consideration received from percent-of-proceeds, percent-of-liquids and keep-whole processing arrangements due to a decrease in the average realized price, partially offset by higher processed volumes in the Anadarko and Ark-La-Tex Basins, and
|
•
|
revenues from natural gas sales less the cost of natural gas decreased approximately $14 million due to lower average natural gas sales prices and lower sales volumes.
|
•
|
revenues from natural gas sales decreased $126 million primarily due to lower sales volumes and lower average sales price,
|
•
|
revenues from NGL sales decreased $11 million due to lower average sales prices and lower volumes, and
|
•
|
volume-dependent transportation revenues decreased $3 million due to a decrease in off-system intrastate transportation offset by new off-system interstate transportation contracts.
|
•
|
firm transportation and storage services increased $17 million due to new intrastate and interstate transportation contracts partially offset by lower revenue due to the reduction of contracted interstate storage capacity.
|
•
|
firm transportation and storage services increased $17 million due to new intrastate and interstate transportation contracts partially offset by lower revenue due to the reduction of contracted interstate storage capacity, and
|
•
|
system management activities increased $11 million.
|
•
|
revenues from NGL sales less the cost of NGLs decreased $7 million due to a decrease in average NGL prices and lower volumes,
|
•
|
natural gas storage inventory decreased $4 million due to additional lower of cost or net realizable value adjustments,
|
•
|
volume-dependent transportation revenues decreased $3 million due to a decrease in off-system intrastate transportation offset by new off-system interstate transportation contracts, and
|
•
|
realized gains on natural gas derivatives decreased $1 million.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Operating Income
|
$
|
569
|
|
|
$
|
648
|
|
Other Income (Expense):
|
|
|
|
||||
Interest expense
|
(190
|
)
|
|
(152
|
)
|
||
Equity in earnings of equity method affiliate
|
17
|
|
|
26
|
|
||
Other, net
|
3
|
|
|
—
|
|
||
Total Other Expense
|
(170
|
)
|
|
(126
|
)
|
||
Income Before Income Taxes
|
399
|
|
|
522
|
|
||
Income tax benefit
|
(1
|
)
|
|
(1
|
)
|
||
Net Income
|
$
|
400
|
|
|
$
|
523
|
|
Less: Net income attributable to noncontrolling interests
|
4
|
|
|
2
|
|
||
Net Income attributable to limited partners
|
$
|
396
|
|
|
$
|
521
|
|
Less: Series A Preferred Unit distributions
|
36
|
|
|
36
|
|
||
Net Income attributable to common units
|
$
|
360
|
|
|
$
|
485
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Reconciliation of Gross Margin to Total Revenues:
|
|
|
|
||||
Consolidated
|
|
|
|
||||
Product sales
|
$
|
1,533
|
|
|
$
|
2,106
|
|
Service revenues
|
1,427
|
|
|
1,325
|
|
||
Total Revenues
|
2,960
|
|
|
3,431
|
|
||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)
|
1,279
|
|
|
1,819
|
|
||
Gross margin
|
$
|
1,681
|
|
|
$
|
1,612
|
|
|
|
|
|
||||
Reportable Segments
|
|
|
|
||||
Gathering and Processing
|
|
|
|
||||
Product sales
|
$
|
1,449
|
|
|
$
|
2,016
|
|
Service revenues
|
889
|
|
|
802
|
|
||
Total Revenues
|
2,338
|
|
|
2,818
|
|
||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)
|
1,203
|
|
|
1,741
|
|
||
Gross margin
|
$
|
1,135
|
|
|
$
|
1,077
|
|
|
|
|
|
||||
Transportation and Storage
|
|
|
|
||||
Product sales
|
$
|
487
|
|
|
$
|
625
|
|
Service revenues
|
551
|
|
|
537
|
|
||
Total Revenues
|
1,038
|
|
|
1,162
|
|
||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization)
|
491
|
|
|
628
|
|
||
Gross margin
|
$
|
547
|
|
|
$
|
534
|
|
|
Fee-Based
|
|
|
||||||||
|
Demand/
Commitment/
Guaranteed
Return
|
|
Volume
Dependent
|
|
Commodity-
Based
|
|
Total
|
||||
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
||||
Gathering and Processing Segment
|
24
|
%
|
|
56
|
%
|
|
20
|
%
|
|
100
|
%
|
Transportation and Storage Segment
|
89
|
%
|
|
12
|
%
|
|
(1
|
)%
|
|
100
|
%
|
Partnership Weighted Average
|
45
|
%
|
|
41
|
%
|
|
14
|
%
|
|
100
|
%
|
|
Fee-Based
|
|
|
||||||||
|
Demand/
Commitment/
Guaranteed
Return
|
|
Volume
Dependent
|
|
Commodity-
Based
|
|
Total
|
||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
||||
Gathering and Processing Segment
|
23
|
%
|
|
49
|
%
|
|
28
|
%
|
|
100
|
%
|
Transportation and Storage Segment
|
88
|
%
|
|
12
|
%
|
|
—
|
%
|
|
100
|
%
|
Partnership Weighted Average
|
45
|
%
|
|
36
|
%
|
|
19
|
%
|
|
100
|
%
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions, except Distribution coverage ratio)
|
||||||
Reconciliation of Adjusted EBITDA and DCF to net income attributable to limited partners and calculation of Distribution coverage ratio:
|
|
|
|
||||
Net income attributable to limited partners
|
$
|
396
|
|
|
$
|
521
|
|
Depreciation and amortization expense
|
433
|
|
|
398
|
|
||
Interest expense, net of interest income
|
188
|
|
|
152
|
|
||
Income tax benefit
|
(1
|
)
|
|
(1
|
)
|
||
Distributions received from equity method affiliate in excess of equity earnings
|
8
|
|
|
7
|
|
||
Non-cash equity-based compensation
|
16
|
|
|
16
|
|
||
Change in fair value of derivatives (1)
|
11
|
|
|
(26
|
)
|
||
Other non-cash losses (2)
|
12
|
|
|
7
|
|
||
Impairments
|
86
|
|
|
—
|
|
||
Noncontrolling Interest Share of Adjusted EBITDA
|
(2
|
)
|
|
—
|
|
||
Adjusted EBITDA
|
$
|
1,147
|
|
|
$
|
1,074
|
|
Series A Preferred Unit distributions (3)
|
(36
|
)
|
|
(36
|
)
|
||
Distributions for phantom and performance units (4)
|
(10
|
)
|
|
(5
|
)
|
||
Adjusted interest expense (5)
|
(191
|
)
|
|
(159
|
)
|
||
Maintenance capital expenditures
|
(126
|
)
|
|
(114
|
)
|
||
Current income taxes
|
—
|
|
|
—
|
|
||
DCF
|
$
|
784
|
|
|
$
|
760
|
|
|
|
|
|
||||
Distributions related to common unitholders (6)
|
$
|
570
|
|
|
$
|
552
|
|
|
|
|
|
||||
Distribution coverage ratio
|
1.38
|
|
|
1.38
|
|
(1)
|
Change in fair value of derivatives includes changes in the fair value of derivatives that are not designated as hedging instruments.
|
(2)
|
Other non-cash losses primarily include net loss on sale of assets.
|
(3)
|
This amount represents the quarterly cash distributions on the Series A Preferred Units declared for the years ended December 31, 2019, 2018 and 2017. In accordance with the Partnership Agreement, the Series A Preferred Unit distributions are deemed to have been paid out of available cash with respect to the quarter immediately preceding the quarter in which the distribution is made.
|
(4)
|
Distributions for phantom and performance units represent distribution equivalent rights paid in cash. Phantom unit distribution equivalent rights are paid during the vesting period and performance unit distribution equivalent rights are paid at vesting.
|
(5)
|
See below for a reconciliation of Adjusted interest expense to Interest expense.
|
(6)
|
Represents cash distributions declared for common units outstanding as of each respective period. Amounts for 2019 reflect estimated cash distributions for common units outstanding for the quarter ended December 31, 2019.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
|
|
|
|
||||
Net cash provided by operating activities
|
$
|
942
|
|
|
$
|
924
|
|
Interest expense, net of interest income
|
188
|
|
|
152
|
|
||
Net income attributable to noncontrolling interests
|
(4
|
)
|
|
(2
|
)
|
||
Other non-cash items
|
2
|
|
|
7
|
|
||
Proceeds from insurance
|
1
|
|
|
2
|
|
||
Changes in operating working capital which (provided) used cash:
|
|
|
|
||||
Accounts receivable
|
(37
|
)
|
|
11
|
|
||
Accounts payable
|
78
|
|
|
(6
|
)
|
||
Other, including changes in noncurrent assets and liabilities
|
(42
|
)
|
|
5
|
|
||
Return of investment in equity method affiliate
|
8
|
|
|
7
|
|
||
Change in fair value of derivatives
|
11
|
|
|
(26
|
)
|
||
Adjusted EBITDA
|
$
|
1,147
|
|
|
$
|
1,074
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Reconciliation of Adjusted interest expense to Interest expense:
|
|
|
|
||||
Interest Expense
|
$
|
190
|
|
|
$
|
152
|
|
Interest Income
|
(2
|
)
|
|
—
|
|
||
Amortization of premium on long-term debt
|
6
|
|
|
6
|
|
||
Capitalized interest on expansion capital
|
2
|
|
|
6
|
|
||
Amortization of debt expense and discount
|
(5
|
)
|
|
(5
|
)
|
||
Adjusted interest expense
|
$
|
191
|
|
|
$
|
159
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Net cash provided by operating activities
|
$
|
942
|
|
|
$
|
924
|
|
Net cash used in investing activities
|
(430
|
)
|
|
(1,154
|
)
|
||
Net cash (used in) provided by financing activities
|
(530
|
)
|
|
233
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
(Decrease) increase in short-term debt
|
$
|
(494
|
)
|
|
$
|
244
|
|
Net proceeds (repayments) of term loans
|
800
|
|
|
(450
|
)
|
||
Net (repayments) proceeds of Revolving Credit Facility
|
(250
|
)
|
|
250
|
|
||
Repayment of 2019 Notes
|
(500
|
)
|
|
—
|
|
||
Proceeds from 2029 Notes, net of issuance costs
|
544
|
|
|
—
|
|
||
Proceeds from 2028 Notes, net of issuance costs
|
—
|
|
|
787
|
|
||
Proceeds from issuance of common units, net of issuance costs
|
—
|
|
|
2
|
|
||
Distributions
|
(605
|
)
|
|
(591
|
)
|
||
Cash paid for employee equity-based compensation
|
(25
|
)
|
|
(9
|
)
|
•
|
cash on hand;
|
•
|
cash generated from operations;
|
•
|
proceeds from commercial paper issuances;
|
•
|
borrowings under our Revolving Credit facility; and
|
•
|
capital raised through debt and equity markets.
|
•
|
maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and
|
•
|
expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long-term.
|
•
|
less, the amount of cash reserves established by our general partner to:
|
•
|
provide for the proper conduct of our business (including cash reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
|
•
|
comply with applicable law, any of our debt instruments or other agreements;
|
•
|
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter); or
|
•
|
provide funds for distributions on our preferred units;
|
•
|
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
|
|
Total Quarterly
Distribution Per Unit
Target Amount
|
|
Marginal Percentage
Interest in Distributions
|
||||
|
Unitholders
|
|
General
Partner
|
||||
Minimum Quarterly Distribution
|
$0.2875
|
|
100.0
|
%
|
|
—
|
%
|
First Target Distribution
|
up to $0.330625
|
|
100.0
|
%
|
|
—
|
%
|
Second Target Distribution
|
above $0.330625 up to $0.359375
|
|
85.0
|
%
|
|
15.0
|
%
|
Third Target Distribution
|
above $0.359375 up to $0.431250
|
|
75.0
|
%
|
|
25.0
|
%
|
Thereafter
|
above $0.431250
|
|
50.0
|
%
|
|
50.0
|
%
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Per Unit Distribution
|
|
Total Cash Distribution
|
||||
2019
|
|
|
|
|
|
|
|
|
||||
December 31, 2019 (1)
|
|
February 18, 2020
|
|
February 25, 2020
|
|
$
|
0.3305
|
|
|
$
|
144
|
|
September 30, 2019
|
|
November 19, 2019
|
|
November 26, 2019
|
|
$
|
0.3305
|
|
|
$
|
144
|
|
June 30, 2019
|
|
August 20, 2019
|
|
August 27, 2019
|
|
$
|
0.3305
|
|
|
$
|
144
|
|
March 31, 2019
|
|
May 21, 2019
|
|
May 29, 2019
|
|
$
|
0.318
|
|
|
$
|
138
|
|
|
|
|
|
|
|
|
|
|
||||
2018
|
|
|
|
|
|
|
|
|
||||
December 31, 2018
|
|
February 19, 2019
|
|
February 26, 2019
|
|
$
|
0.318
|
|
|
$
|
138
|
|
September 30, 2018
|
|
November 16, 2018
|
|
November 29, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
June 30, 2018
|
|
August 21, 2018
|
|
August 28, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
March 31, 2018
|
|
May 22, 2018
|
|
May 29, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
(1)
|
The Board of Directors declared this $0.3305 per common unit cash distribution on February 7, 2020, to be paid on February 25, 2020, to unitholders of record at the close of business on February 18, 2020.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Per Unit Distribution
|
|
Total Cash Distribution
|
||||
2019
|
|
|
|
|
|
|
|
|
||||
December 31, 2019 (1)
|
|
February 7, 2020
|
|
February 14, 2020
|
|
$
|
0.625
|
|
|
$
|
9
|
|
September 30, 2019
|
|
November 5, 2019
|
|
November 14, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
June 30, 2019
|
|
August 2, 2019
|
|
August 14, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
March 31, 2019
|
|
April 29, 2019
|
|
May 15, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
||||
2018
|
|
|
|
|
|
|
|
|
||||
December 31, 2018
|
|
February 8, 2019
|
|
February 14, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
September 30, 2018
|
|
November 6, 2018
|
|
November 14, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 14, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
March 31, 2018
|
|
May 1, 2018
|
|
May 15, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
(1)
|
The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020, to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020.
|
|
2020
|
|
2021-2022
|
|
2023-2024
|
|
After 2024
|
|
Total
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Maturities of outstanding debt (1)(2)
|
$
|
405
|
|
|
$
|
800
|
|
|
$
|
600
|
|
|
$
|
2,600
|
|
|
$
|
4,405
|
|
Noncancellable operating leases
|
11
|
|
|
13
|
|
|
10
|
|
|
10
|
|
|
44
|
|
|||||
Purchase obligations (3):
|
|
|
|
|
|
|
|
|
|
||||||||||
Minimum volume commitments (4)
|
66
|
|
|
132
|
|
|
132
|
|
|
90
|
|
|
420
|
|
|||||
Other purchase obligations (5)
|
27
|
|
|
6
|
|
|
2
|
|
|
—
|
|
|
35
|
|
|||||
Total contractual obligations
|
$
|
509
|
|
|
$
|
951
|
|
|
$
|
744
|
|
|
$
|
2,700
|
|
|
$
|
4,904
|
|
(1)
|
Contractual interest payments associated with long-term debt are $152 million, $288 million, $277 million and $866 million in 2020, 2021 through 2022, 2023 through 2024 and after 2024, respectively.
|
(2)
|
Excludes premium (discount) on long-term debt of $7 million.
|
(3)
|
A purchase obligation represents an agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms, including: fixed minimum or variable prices provisions; and the approximate timing of the transaction. Purchase obligations require estimation and actual amounts may vary depending on prices and volume at the time of delivery.
|
(4)
|
Includes minimum volume commitment fees related to certain third party gathering, processing and fractionation agreements.
|
(5)
|
Includes (i) commitments for capital expenditures, operating expenses, service contracts and utilities, (ii) noncancellable commitments to purchase physical quantities of commodities in future periods and (iii) unconditional payment obligations under firm pipeline transportation contracts.
|
•
|
We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair value of Anadarko, such as controls related to management’s selection of the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate.
|
•
|
We evaluated management’s ability to accurately forecast future revenues by comparing actual results to management’s historical forecasts.
|
•
|
We evaluated the reasonableness of management’s revenue forecasts by comparing the forecasts to:
|
–
|
Historical revenues.
|
–
|
Internal communications to management and the Board of Directors.
|
–
|
Forecasted information included in Partnership press releases as well as in analyst and industry reports for the Partnership and certain of its peer companies.
|
•
|
With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology and (2) weighted average cost of capital and revenue growth rate by:
|
–
|
Testing the source information underlying the determination of the weighted average cost of capital and revenue growth rate and the mathematical accuracy of the calculation.
|
–
|
Developing a range of independent estimates and comparing those to the weighted average cost of capital and revenue growth rate selected by management.
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions, except per unit data)
|
||||||||||
Revenues (including revenues from affiliates (Note 16)):
|
|
|
|
|
|
||||||
Product sales
|
$
|
1,533
|
|
|
$
|
2,106
|
|
|
$
|
1,653
|
|
Service revenues
|
1,427
|
|
|
1,325
|
|
|
1,150
|
|
|||
Total Revenues
|
2,960
|
|
|
3,431
|
|
|
2,803
|
|
|||
Cost and Expenses (including expenses from affiliates (Note 16)):
|
|
|
|
|
|
||||||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
|
1,279
|
|
|
1,819
|
|
|
1,381
|
|
|||
Operation and maintenance
|
423
|
|
|
388
|
|
|
369
|
|
|||
General and administrative
|
103
|
|
|
113
|
|
|
95
|
|
|||
Depreciation and amortization
|
433
|
|
|
398
|
|
|
366
|
|
|||
Impairment (Note 10)
|
86
|
|
|
—
|
|
|
—
|
|
|||
Taxes other than income taxes
|
67
|
|
|
65
|
|
|
64
|
|
|||
Total Cost and Expenses
|
2,391
|
|
|
2,783
|
|
|
2,275
|
|
|||
Operating Income
|
569
|
|
|
648
|
|
|
528
|
|
|||
Other Income (Expense):
|
|
|
|
|
|
||||||
Interest expense
|
(190
|
)
|
|
(152
|
)
|
|
(120
|
)
|
|||
Equity in earnings of equity method affiliate
|
17
|
|
|
26
|
|
|
28
|
|
|||
Other, net
|
3
|
|
|
—
|
|
|
—
|
|
|||
Total Other Expense
|
(170
|
)
|
|
(126
|
)
|
|
(92
|
)
|
|||
Income Before Income Tax
|
399
|
|
|
522
|
|
|
436
|
|
|||
Income tax benefit
|
(1
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|||
Net Income
|
$
|
400
|
|
|
$
|
523
|
|
|
$
|
437
|
|
Less: Net income attributable to noncontrolling interests
|
4
|
|
|
2
|
|
|
1
|
|
|||
Net Income Attributable to Limited Partners
|
$
|
396
|
|
|
$
|
521
|
|
|
$
|
436
|
|
Less: Series A Preferred Unit distributions (Note 7)
|
36
|
|
|
36
|
|
|
36
|
|
|||
Net Income Attributable to Common and Subordinated Units (Note 6)
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
400
|
|
|
|
|
|
|
|
||||||
Basic earnings per unit (Note 6)
|
|
|
|
|
|
||||||
Common units
|
$
|
0.83
|
|
|
$
|
1.12
|
|
|
$
|
0.92
|
|
Subordinated units
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.93
|
|
Diluted earnings per unit (Note 6)
|
|
|
|
|
|
||||||
Common units
|
$
|
0.82
|
|
|
$
|
1.11
|
|
|
$
|
0.92
|
|
Subordinated units
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.93
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Net income
|
$
|
400
|
|
|
$
|
523
|
|
|
$
|
437
|
|
Other comprehensive loss:
|
|
|
|
|
|
||||||
Unrealized losses on derivative instruments
|
(3
|
)
|
|
—
|
|
|
—
|
|
|||
Reclassification of derivative losses to net income
|
—
|
|
|
—
|
|
|
—
|
|
|||
Other comprehensive loss
|
(3
|
)
|
|
—
|
|
|
—
|
|
|||
Comprehensive income
|
397
|
|
|
523
|
|
|
437
|
|
|||
Less: Comprehensive income attributable to noncontrolling interests
|
4
|
|
|
2
|
|
|
1
|
|
|||
Comprehensive income attributable to Limited Partners
|
$
|
393
|
|
|
$
|
521
|
|
|
$
|
436
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions, except units)
|
||||||
Current Assets:
|
|
||||||
Cash and cash equivalents
|
$
|
4
|
|
|
$
|
8
|
|
Restricted cash
|
—
|
|
|
14
|
|
||
Accounts receivable, net of allowance for doubtful accounts (Note 1)
|
244
|
|
|
290
|
|
||
Accounts receivable—affiliated companies
|
25
|
|
|
19
|
|
||
Inventory
|
46
|
|
|
50
|
|
||
Gas imbalances
|
35
|
|
|
29
|
|
||
Other current assets
|
35
|
|
|
39
|
|
||
Total current assets
|
389
|
|
|
449
|
|
||
Property, Plant and Equipment:
|
|
|
|
||||
Property, plant and equipment
|
13,161
|
|
|
12,899
|
|
||
Less accumulated depreciation and amortization
|
2,291
|
|
|
2,028
|
|
||
Property, plant and equipment, net
|
10,870
|
|
|
10,871
|
|
||
Other Assets:
|
|
|
|
||||
Intangible assets, net
|
601
|
|
|
663
|
|
||
Goodwill
|
12
|
|
|
98
|
|
||
Investment in equity method affiliate
|
309
|
|
|
317
|
|
||
Other
|
85
|
|
|
46
|
|
||
Total other assets
|
1,007
|
|
|
1,124
|
|
||
Total Assets
|
$
|
12,266
|
|
|
$
|
12,444
|
|
Current Liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
161
|
|
|
$
|
288
|
|
Accounts payable—affiliated companies
|
1
|
|
|
4
|
|
||
Short-term debt
|
155
|
|
|
649
|
|
||
Current portion of long-term debt
|
251
|
|
|
500
|
|
||
Taxes accrued
|
32
|
|
|
31
|
|
||
Gas imbalances
|
19
|
|
|
22
|
|
||
Accrued compensation
|
31
|
|
|
26
|
|
||
Customer deposits
|
17
|
|
|
38
|
|
||
Other
|
113
|
|
|
57
|
|
||
Total current liabilities
|
780
|
|
|
1,615
|
|
||
Other Liabilities:
|
|
|
|
||||
Accumulated deferred income taxes, net
|
4
|
|
|
5
|
|
||
Regulatory liabilities
|
24
|
|
|
23
|
|
||
Other
|
80
|
|
|
54
|
|
||
Total other liabilities
|
108
|
|
|
82
|
|
||
Long-Term Debt
|
3,969
|
|
|
3,129
|
|
||
Commitments and Contingencies (Note 17)
|
|
|
|
||||
Partners’ Equity:
|
|
|
|
||||
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2019 and December 31, 2018, respectively)
|
362
|
|
|
362
|
|
||
Common units (435,201,365 issued and outstanding at December 31, 2019 and 433,232,411 issued and outstanding at December 31, 2018, respectively)
|
7,013
|
|
|
7,218
|
|
||
Accumulated other comprehensive loss
|
(3
|
)
|
|
—
|
|
||
Noncontrolling interests
|
37
|
|
|
38
|
|
||
Total Partners’ Equity
|
7,409
|
|
|
7,618
|
|
||
Total Liabilities and Partners’ Equity
|
$
|
12,266
|
|
|
$
|
12,444
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Cash Flows from Operating Activities:
|
|
|
|
||||||||
Net income
|
$
|
400
|
|
|
$
|
523
|
|
|
$
|
437
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
433
|
|
|
398
|
|
|
366
|
|
|||
Deferred income taxes
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|||
Impairment
|
86
|
|
|
—
|
|
|
—
|
|
|||
Loss on sale/retirement of assets
|
8
|
|
|
1
|
|
|
7
|
|
|||
Equity in earnings of equity method affiliate
|
(17
|
)
|
|
(26
|
)
|
|
(28
|
)
|
|||
Return on investment in equity method affiliate
|
17
|
|
|
26
|
|
|
28
|
|
|||
Equity-based compensation
|
16
|
|
|
16
|
|
|
15
|
|
|||
Amortization of debt costs and discount (premium)
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|||
Changes in other assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable, net
|
43
|
|
|
(10
|
)
|
|
(23
|
)
|
|||
Accounts receivable—affiliated companies
|
(6
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|||
Inventory
|
4
|
|
|
(10
|
)
|
|
1
|
|
|||
Gas imbalance assets
|
(6
|
)
|
|
8
|
|
|
4
|
|
|||
Other current assets
|
9
|
|
|
(21
|
)
|
|
4
|
|
|||
Other assets
|
11
|
|
|
(12
|
)
|
|
1
|
|
|||
Accounts payable
|
(75
|
)
|
|
4
|
|
|
54
|
|
|||
Accounts payable—affiliated companies
|
(3
|
)
|
|
1
|
|
|
—
|
|
|||
Gas imbalance liabilities
|
(3
|
)
|
|
10
|
|
|
(23
|
)
|
|||
Other current liabilities
|
39
|
|
|
4
|
|
|
(4
|
)
|
|||
Other liabilities
|
(12
|
)
|
|
15
|
|
|
5
|
|
|||
Net cash provided by operating activities
|
942
|
|
|
924
|
|
|
834
|
|
|||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(432
|
)
|
|
(728
|
)
|
|
(416
|
)
|
|||
Acquisitions, net of cash acquired
|
—
|
|
|
(443
|
)
|
|
(298
|
)
|
|||
Proceeds from sale of assets
|
1
|
|
|
8
|
|
|
1
|
|
|||
Proceeds from insurance
|
1
|
|
|
2
|
|
|
2
|
|
|||
Return of investment in equity method affiliate
|
8
|
|
|
7
|
|
|
5
|
|
|||
Other, net
|
(8
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash used in investing activities
|
(430
|
)
|
|
(1,154
|
)
|
|
(706
|
)
|
|||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||||||
(Decrease) increase in short-term debt
|
(494
|
)
|
|
244
|
|
|
405
|
|
|||
Proceeds from long-term debt, net of issuance costs
|
1,544
|
|
|
787
|
|
|
691
|
|
|||
Repayment of long-term debt
|
(700
|
)
|
|
(450
|
)
|
|
—
|
|
|||
Proceeds from Revolving Credit Facility
|
—
|
|
|
350
|
|
|
1,200
|
|
|||
Repayment of Revolving Credit Facility
|
(250
|
)
|
|
(100
|
)
|
|
(1,836
|
)
|
|||
Proceeds from issuance of common units, net of issuance costs
|
—
|
|
|
2
|
|
|
—
|
|
|||
Distributions to common unitholders
|
(564
|
)
|
|
(551
|
)
|
|
(355
|
)
|
|||
Distributions to subordinated unitholders
|
—
|
|
|
—
|
|
|
(198
|
)
|
|||
Distributions to preferred unitholders
|
(36
|
)
|
|
(36
|
)
|
|
(36
|
)
|
|||
Distributions to non-controlling interests
|
(5
|
)
|
|
(4
|
)
|
|
(1
|
)
|
|||
Cash paid for employee equity-based compensation
|
(25
|
)
|
|
(9
|
)
|
|
(2
|
)
|
|||
Net cash (used in) provided by financing activities
|
(530
|
)
|
|
233
|
|
|
(132
|
)
|
|||
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash
|
(18
|
)
|
|
3
|
|
|
(4
|
)
|
|||
Cash, Cash Equivalents and Restricted Cash at Beginning of Period
|
22
|
|
|
19
|
|
|
23
|
|
|||
Cash, Cash Equivalents and Restricted Cash at End of Period
|
$
|
4
|
|
|
$
|
22
|
|
|
$
|
19
|
|
|
Series A Preferred Units
|
|
Common Units
|
|
Subordinated Units
|
|
Accumulated Other Comprehensive Earnings
|
|
Noncontrolling
Interest |
|
Total
Partners’
Equity
|
|||||||||||||||||||||
|
Units
|
|
Value
|
|
Units
|
|
Value
|
|
Units
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
(In millions)
|
|||||||||||||||||||||||||||||||
Balance as of December 31, 2016
|
15
|
|
|
$
|
362
|
|
|
224
|
|
|
$
|
3,737
|
|
|
208
|
|
|
$
|
3,683
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
$
|
7,794
|
|
Net income
|
—
|
|
|
36
|
|
|
—
|
|
|
266
|
|
|
—
|
|
|
134
|
|
|
—
|
|
|
1
|
|
|
437
|
|
||||||
Conversion of subordinated units
|
—
|
|
|
—
|
|
|
208
|
|
|
3,619
|
|
|
(208
|
)
|
|
(3,619
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Distributions
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(355
|
)
|
|
—
|
|
|
(198
|
)
|
|
—
|
|
|
(1
|
)
|
|
(590
|
)
|
||||||
Equity-based compensation, net of units for employee taxes
|
—
|
|
|
—
|
|
|
1
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
||||||
Balance as of December 31, 2017
|
15
|
|
|
$
|
362
|
|
|
433
|
|
|
$
|
7,280
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12
|
|
|
$
|
7,654
|
|
Net income
|
—
|
|
|
36
|
|
|
—
|
|
|
485
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
523
|
|
||||||
Issuance of common units
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Acquisition of EOCS
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28
|
|
|
28
|
|
||||||
Distributions
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(551
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(591
|
)
|
||||||
Equity-based compensation, net of units for employee taxes
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Balance as of December 31, 2018
|
15
|
|
|
$
|
362
|
|
|
433
|
|
|
$
|
7,218
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
38
|
|
|
$
|
7,618
|
|
Net income
|
—
|
|
|
36
|
|
|
—
|
|
|
360
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
400
|
|
||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
||||||
Distributions
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(564
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
(605
|
)
|
||||||
Equity-based compensation, net of units for employee taxes
|
—
|
|
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||
Balance as of December 31, 2019
|
15
|
|
|
$
|
362
|
|
|
435
|
|
|
$
|
7,013
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
$
|
37
|
|
|
$
|
7,409
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Materials and supplies
|
$
|
32
|
|
|
$
|
31
|
|
Natural gas and natural gas liquids
|
14
|
|
|
19
|
|
||
Total Inventory
|
$
|
46
|
|
|
$
|
50
|
|
|
Year Ended December 31, 2019
|
||||||||||||||
|
Gathering and
Processing |
|
Transportation
and Storage |
|
Eliminations
|
|
Total
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
||||||||
Product sales:
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
368
|
|
|
$
|
464
|
|
|
$
|
(384
|
)
|
|
$
|
448
|
|
Natural gas liquids
|
943
|
|
|
19
|
|
|
(19
|
)
|
|
943
|
|
||||
Condensate
|
126
|
|
|
—
|
|
|
—
|
|
|
126
|
|
||||
Total revenues from natural gas, natural gas liquids, and condensate
|
1,437
|
|
|
483
|
|
|
(403
|
)
|
|
1,517
|
|
||||
Gain on derivative activity
|
12
|
|
|
4
|
|
|
—
|
|
|
16
|
|
||||
Total Product sales
|
$
|
1,449
|
|
|
$
|
487
|
|
|
$
|
(403
|
)
|
|
$
|
1,533
|
|
Service revenues:
|
|
|
|
|
|
|
|
||||||||
Demand revenues
|
$
|
274
|
|
|
$
|
489
|
|
|
$
|
—
|
|
|
$
|
763
|
|
Volume-dependent revenues
|
615
|
|
|
62
|
|
|
(13
|
)
|
|
664
|
|
||||
Total Service revenues
|
$
|
889
|
|
|
$
|
551
|
|
|
$
|
(13
|
)
|
|
$
|
1,427
|
|
Total Revenues
|
$
|
2,338
|
|
|
$
|
1,038
|
|
|
$
|
(416
|
)
|
|
$
|
2,960
|
|
|
Year Ended December 31, 2018
|
||||||||||||||
|
Gathering and
Processing |
|
Transportation
and Storage |
|
Eliminations
|
|
Total
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
||||||||
Product sales:
|
|
|
|
|
|
|
|
||||||||
Natural gas
|
$
|
480
|
|
|
$
|
590
|
|
|
$
|
(506
|
)
|
|
$
|
564
|
|
Natural gas liquids
|
1,405
|
|
|
30
|
|
|
(30
|
)
|
|
1,405
|
|
||||
Condensate
|
126
|
|
|
—
|
|
|
—
|
|
|
126
|
|
||||
Total revenues from natural gas, natural gas liquids, and condensate
|
2,011
|
|
|
620
|
|
|
(536
|
)
|
|
2,095
|
|
||||
Gain on derivative activity
|
5
|
|
|
5
|
|
|
1
|
|
|
11
|
|
||||
Total Product sales
|
$
|
2,016
|
|
|
$
|
625
|
|
|
$
|
(535
|
)
|
|
$
|
2,106
|
|
Service revenues:
|
|
|
|
|
|
|
|
||||||||
Demand revenues
|
$
|
252
|
|
|
$
|
472
|
|
|
$
|
—
|
|
|
$
|
724
|
|
Volume-dependent revenues
|
550
|
|
|
65
|
|
|
(14
|
)
|
|
601
|
|
||||
Total Service revenues
|
$
|
802
|
|
|
$
|
537
|
|
|
$
|
(14
|
)
|
|
$
|
1,325
|
|
Total Revenues
|
$
|
2,818
|
|
|
$
|
1,162
|
|
|
$
|
(549
|
)
|
|
$
|
3,431
|
|
•
|
Under a firm arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.
|
•
|
Under a minimum volume commitment arrangement, a customer agrees to pay the contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of
|
|
December 31,
2019 |
|
December 31,
2018 |
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Accounts Receivable:
|
|
|
|
||||
Customers
|
$
|
239
|
|
|
$
|
297
|
|
Contract assets (1)
|
18
|
|
|
6
|
|
||
Non-customers
|
12
|
|
|
6
|
|
||
Total Accounts Receivable (2)
|
$
|
269
|
|
|
$
|
309
|
|
(1)
|
Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include $6 million of contract assets related to firm transportation contracts with tiered rates, which are reflected in Other Assets.
|
(2)
|
Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.
|
•
|
Under certain firm arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other current liabilities on the Consolidated Balance Sheets.
|
•
|
Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Consolidated Balance Sheets.
|
|
December 31,
2019 |
|
December 31,
2018 |
|
Amounts recognized in revenues
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Deferred revenues (1)
|
$
|
48
|
|
|
$
|
48
|
|
|
$
|
24
|
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024 and After
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Deferred revenues (1)
|
$
|
25
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
6
|
|
(1)
|
Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024 and After
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Transportation and Storage (1)
|
$
|
461
|
|
|
$
|
298
|
|
|
$
|
238
|
|
|
$
|
225
|
|
|
$
|
699
|
|
Gathering and Processing
|
137
|
|
|
121
|
|
|
123
|
|
|
121
|
|
|
313
|
|
|||||
Total remaining performance obligations
|
$
|
598
|
|
|
$
|
419
|
|
|
$
|
361
|
|
|
$
|
346
|
|
|
$
|
1,012
|
|
(1)
|
The remaining performance obligations include certain obligations for MRT, which are calculated based on rates that are subject to FERC rate case approval.
|
|
Year Ended December 31, 2019
|
||||||||||
|
Gathering and
Processing |
|
Transportation
and Storage |
|
Total
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Lease Cost:
|
|
|
|
|
|
||||||
Operating lease cost
|
$
|
11
|
|
|
$
|
—
|
|
|
$
|
11
|
|
Short-term lease cost
|
22
|
|
|
2
|
|
|
24
|
|
|||
Variable lease cost
|
1
|
|
|
—
|
|
|
1
|
|
|||
Total Lease Cost
|
$
|
34
|
|
|
$
|
2
|
|
|
$
|
36
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025 and After
|
|
Total
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
|
(In millions)
|
||||||||||||||||||||||||||
Noncancellable operating leases
|
$
|
11
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
10
|
|
|
$
|
44
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
After 2023
|
|
Total
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Noncancellable operating leases
|
$
|
14
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
14
|
|
|
$
|
40
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions, except per unit data)
|
||||||||||
Net income
|
$
|
400
|
|
|
$
|
523
|
|
|
$
|
437
|
|
Net income attributable to noncontrolling interests
|
4
|
|
|
2
|
|
|
1
|
|
|||
Series A Preferred Unit distributions
|
36
|
|
|
36
|
|
|
36
|
|
|||
General partner interest in net income
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income available to common and subordinated units
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
400
|
|
|
|
|
|
|
|
||||||
Net income allocable to common units
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
273
|
|
Net income allocable to subordinated units
|
—
|
|
|
—
|
|
|
127
|
|
|||
Net income available to common and subordinated units
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
400
|
|
|
|
|
|
|
|
||||||
Net income allocable to common units
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
273
|
|
Dilutive effect of Series A Preferred Unit distribution
|
—
|
|
|
—
|
|
|
—
|
|
|||
Diluted net income allocable to common units
|
360
|
|
|
485
|
|
|
273
|
|
|||
Diluted net income allocable to subordinated units
|
—
|
|
|
—
|
|
|
127
|
|
|||
Total
|
$
|
360
|
|
|
$
|
485
|
|
|
$
|
400
|
|
|
|
|
|
|
|
||||||
Basic weighted average number of outstanding
|
|
|
|
|
|
||||||
Common units (1)
|
436
|
|
|
434
|
|
|
296
|
|
|||
Subordinated units
|
—
|
|
|
—
|
|
|
137
|
|
|||
Total
|
436
|
|
|
434
|
|
|
433
|
|
|||
|
|
|
|
|
|
||||||
Basic earnings per unit
|
|
|
|
|
|
||||||
Common units
|
$
|
0.83
|
|
|
$
|
1.12
|
|
|
$
|
0.92
|
|
Subordinated units
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.93
|
|
|
|
|
|
|
|
||||||
Basic weighted average number of outstanding common units (1)
|
436
|
|
|
434
|
|
|
296
|
|
|||
Dilutive effect of Series A Preferred Units
|
—
|
|
|
—
|
|
|
—
|
|
|||
Dilutive effect of performance units
|
1
|
|
|
2
|
|
|
1
|
|
|||
Diluted weighted average number of outstanding common units
|
437
|
|
|
436
|
|
|
297
|
|
|||
Diluted weighted average number of outstanding subordinated units
|
—
|
|
|
—
|
|
|
137
|
|
|||
Total
|
437
|
|
|
436
|
|
|
434
|
|
|||
|
|
|
|
|
|
||||||
Diluted earnings per unit
|
|
|
|
|
|
||||||
Common units
|
$
|
0.82
|
|
|
$
|
1.11
|
|
|
$
|
0.92
|
|
Subordinated units
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.93
|
|
(1)
|
Basic weighted average number of outstanding common units for the years ended December 31, 2019, 2018, and 2017 includes approximately one million time-based phantom units.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Per Unit Distribution
|
|
Total Cash Distribution
|
||||
2019
|
|
|
|
|
|
|
|
|
||||
December 31, 2019 (1)
|
|
February 18, 2020
|
|
February 25, 2020
|
|
$
|
0.3305
|
|
|
$
|
144
|
|
September 30, 2019
|
|
November 19, 2019
|
|
November 26, 2019
|
|
$
|
0.3305
|
|
|
$
|
144
|
|
June 30, 2019
|
|
August 20, 2019
|
|
August 27, 2019
|
|
$
|
0.3305
|
|
|
$
|
144
|
|
March 31, 2019
|
|
May 21, 2019
|
|
May 29, 2019
|
|
$
|
0.318
|
|
|
$
|
138
|
|
|
|
|
|
|
|
|
|
|
||||
2018
|
|
|
|
|
|
|
|
|
||||
December 31, 2018
|
|
February 19, 2019
|
|
February 26, 2019
|
|
$
|
0.318
|
|
|
$
|
138
|
|
September 30, 2018
|
|
November 16, 2018
|
|
November 29, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
June 30, 2018
|
|
August 21, 2018
|
|
August 28, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
March 31, 2018
|
|
May 22, 2018
|
|
May 29, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
|
|
|
|
|
|
|
|
|
||||
2017
|
|
|
|
|
|
|
|
|
||||
December 31, 2017
|
|
February 20, 2018
|
|
February 27, 2018
|
|
$
|
0.318
|
|
|
$
|
138
|
|
September 30, 2017
|
|
November 14, 2017
|
|
November 21, 2017
|
|
$
|
0.318
|
|
|
$
|
138
|
|
June 30, 2017
|
|
August 22, 2017
|
|
August 29, 2017
|
|
$
|
0.318
|
|
|
$
|
138
|
|
March 31, 2017
|
|
May 23, 2017
|
|
May 30, 2017
|
|
$
|
0.318
|
|
|
$
|
137
|
|
(1)
|
The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020, to be paid on February 25, 2020, to common unitholders of record at the close of business on February 18, 2020.
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Per Unit Distribution
|
|
Total Cash Distribution
|
||||
2019
|
|
|
|
|
|
|
|
|
||||
December 31, 2019 (1)
|
|
February 7, 2020
|
|
February 14, 2020
|
|
$
|
0.625
|
|
|
$
|
9
|
|
September 30, 2019
|
|
November 5, 2019
|
|
November 14, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
June 30, 2019
|
|
August 2, 2019
|
|
August 14, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
March 31, 2019
|
|
April 29, 2019
|
|
May 15, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
||||
2018
|
|
|
|
|
|
|
|
|
||||
December 31, 2018
|
|
February 8, 2019
|
|
February 14, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
September 30, 2018
|
|
November 6, 2018
|
|
November 14, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 14, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
March 31, 2018
|
|
May 1, 2018
|
|
May 15, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
||||
2017
|
|
|
|
|
|
|
|
|
||||
December 31, 2017
|
|
February 9, 2018
|
|
February 15, 2018
|
|
$
|
0.625
|
|
|
$
|
9
|
|
September 30, 2017
|
|
October 31, 2017
|
|
November 14, 2017
|
|
$
|
0.625
|
|
|
$
|
9
|
|
June 30, 2017
|
|
July 31, 2017
|
|
August 14, 2017
|
|
$
|
0.625
|
|
|
$
|
9
|
|
March 31, 2017
|
|
May 2, 2017
|
|
May 12, 2017
|
|
$
|
0.625
|
|
|
$
|
9
|
|
(1)
|
The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020, to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020.
|
•
|
rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;
|
•
|
have no stated maturity;
|
•
|
are not subject to any sinking fund; and
|
•
|
will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.
|
|
Weighted Average Useful Lives
(Years)
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
|||||
|
|
|
|
|
|
||||
|
|
|
(In millions)
|
||||||
Property, plant and equipment, gross:
|
|
|
|
|
|
||||
Gathering and Processing
|
33
|
|
$
|
8,252
|
|
|
$
|
8,011
|
|
Transportation and Storage
|
39
|
|
4,778
|
|
|
4,740
|
|
||
Construction work-in-progress
|
|
|
131
|
|
|
148
|
|
||
Total
|
|
|
$
|
13,161
|
|
|
$
|
12,899
|
|
Accumulated depreciation:
|
|
|
|
|
|
||||
Gathering and Processing
|
|
|
1,252
|
|
|
1,063
|
|
||
Transportation and Storage
|
|
|
1,039
|
|
|
965
|
|
||
Total accumulated depreciation
|
|
|
2,291
|
|
|
2,028
|
|
||
Property, plant and equipment, net
|
|
|
$
|
10,870
|
|
|
$
|
10,871
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Customer relationships:
|
|
|
|
||||
Total intangible assets (1)
|
$
|
840
|
|
|
$
|
840
|
|
Accumulated amortization
|
239
|
|
|
177
|
|
||
Net intangible assets
|
$
|
601
|
|
|
$
|
663
|
|
(1)
|
See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Expected amortization of intangible assets
|
$
|
62
|
|
|
$
|
62
|
|
|
$
|
62
|
|
|
$
|
62
|
|
|
$
|
62
|
|
|
Gathering and Processing
|
|
Transportation and Storage
|
|
Total
|
||||||
|
|
|
|
|
|
||||||
|
(in millions)
|
||||||||||
Balance as of December 31, 2017
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
12
|
|
EOCS Acquisition (1)
|
86
|
|
|
—
|
|
|
86
|
|
|||
Balance as of December 31, 2018
|
$
|
98
|
|
|
$
|
—
|
|
|
$
|
98
|
|
Goodwill impairment
|
$
|
(86
|
)
|
|
$
|
—
|
|
|
$
|
(86
|
)
|
Balance as of December 31, 2019
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
12
|
|
(1)
|
See Note 5 for further discussion.
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Equity in Earnings of Equity Method Affiliate
|
$
|
17
|
|
|
$
|
26
|
|
|
$
|
28
|
|
Distributions from Equity Method Affiliate (1)
|
25
|
|
|
33
|
|
|
33
|
|
(1)
|
Distributions from equity method affiliate includes a $17 million, $26 million and $28 million return on investment and a $8 million, $7 million and $5 million return of investment for the years ended December 31, 2019, 2018 and 2017, respectively.
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Balance Sheets:
|
|
|
|
||||
Current assets
|
$
|
49
|
|
|
$
|
30
|
|
Property, plant and equipment, net
|
1,060
|
|
|
1,078
|
|
||
Total assets
|
$
|
1,109
|
|
|
$
|
1,108
|
|
Current liabilities
|
$
|
30
|
|
|
$
|
13
|
|
Long-term debt
|
398
|
|
|
397
|
|
||
Members’ equity
|
681
|
|
|
698
|
|
||
Total liabilities and members’ equity
|
$
|
1,109
|
|
|
$
|
1,108
|
|
Reconciliation:
|
|
|
|
||||
Investment in SESH
|
$
|
309
|
|
|
$
|
317
|
|
Less: Capitalized interest on investment in SESH
|
(1
|
)
|
|
(1
|
)
|
||
Add: Basis differential, net of amortization
|
33
|
|
|
33
|
|
||
The Partnership’s share of members’ equity
|
$
|
341
|
|
|
$
|
349
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Income Statements:
|
|
|
|
|
|
||||||
Revenues
|
$
|
109
|
|
|
$
|
112
|
|
|
$
|
113
|
|
Operating income
|
50
|
|
|
67
|
|
|
72
|
|
|||
Net income
|
33
|
|
|
50
|
|
|
54
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||||||||||
|
Outstanding Principal
|
|
Premium (Discount)(1)
|
|
Total Debt
|
|
Outstanding Principal
|
|
Premium (Discount)(1)
|
|
Total Debt
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
(In millions)
|
||||||||||||||||||||||
Commercial Paper
|
$
|
155
|
|
|
$
|
—
|
|
|
$
|
155
|
|
|
$
|
649
|
|
|
$
|
—
|
|
|
$
|
649
|
|
Revolving Credit Facility
|
—
|
|
|
—
|
|
|
—
|
|
|
250
|
|
|
—
|
|
|
250
|
|
||||||
2019 Term Loan Agreement
|
800
|
|
|
—
|
|
|
800
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
2019 Notes
|
—
|
|
|
—
|
|
|
—
|
|
|
500
|
|
|
—
|
|
|
500
|
|
||||||
2024 Notes
|
600
|
|
|
—
|
|
|
600
|
|
|
600
|
|
|
—
|
|
|
600
|
|
||||||
2027 Notes
|
700
|
|
|
(2
|
)
|
|
698
|
|
|
700
|
|
|
(2
|
)
|
|
698
|
|
||||||
2028 Notes
|
800
|
|
|
(5
|
)
|
|
795
|
|
|
800
|
|
|
(6
|
)
|
|
794
|
|
||||||
2029 Notes
|
550
|
|
|
(1
|
)
|
|
549
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
2044 Notes
|
550
|
|
|
—
|
|
|
550
|
|
|
550
|
|
|
—
|
|
|
550
|
|
||||||
EOIT Senior Notes
|
250
|
|
|
1
|
|
|
251
|
|
|
250
|
|
|
7
|
|
|
257
|
|
||||||
Total debt
|
$
|
4,405
|
|
|
$
|
(7
|
)
|
|
$
|
4,398
|
|
|
$
|
4,299
|
|
|
$
|
(1
|
)
|
|
$
|
4,298
|
|
Less: Short-term debt (2)
|
|
|
|
|
155
|
|
|
|
|
|
|
649
|
|
||||||||||
Less: Current portion of long-term debt (3)
|
|
|
|
|
251
|
|
|
|
|
|
|
500
|
|
||||||||||
Less: Unamortized debt expense (4)
|
|
|
|
|
23
|
|
|
|
|
|
|
20
|
|
||||||||||
Total long-term debt
|
|
|
|
|
$
|
3,969
|
|
|
|
|
|
|
$
|
3,129
|
|
(1)
|
Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.
|
(2)
|
Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.
|
(3)
|
As of December 31, 2019, Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018, Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019.
|
(4)
|
As of December 31, 2019 and 2018, there was an additional $4 million and $6 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.
|
2020
|
$
|
405
|
|
2021
|
—
|
|
|
2022
|
800
|
|
|
2023
|
—
|
|
|
2024
|
600
|
|
|
Thereafter
|
$
|
2,600
|
|
•
|
NGL put options, NGL futures and swaps, and WTI crude oil futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;
|
•
|
natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||
|
Gross Notional Volume
|
||||||||||
|
Purchases
|
|
Sales
|
|
Purchases
|
|
Sales
|
||||
Natural gas— TBtu (1)
|
|
|
|
|
|
|
|
||||
Financial fixed futures/swaps
|
10
|
|
|
19
|
|
|
16
|
|
|
28
|
|
Financial basis futures/swaps
|
11
|
|
|
30
|
|
|
18
|
|
|
29
|
|
Financial swaptions (2)
|
—
|
|
|
2
|
|
|
—
|
|
|
1
|
|
Physical purchases/sales
|
—
|
|
|
6
|
|
|
—
|
|
|
11
|
|
Crude oil (for condensate)— MBbl (3)
|
|
|
|
|
|
|
|
||||
Financial futures/swaps
|
—
|
|
|
990
|
|
|
—
|
|
|
945
|
|
Financial swaptions (2)
|
—
|
|
|
225
|
|
|
—
|
|
|
30
|
|
Natural gas liquids— MBbl (4)
|
|
|
|
|
|
|
|
||||
Financial futures/swaps
|
2,490
|
|
|
2,415
|
|
|
270
|
|
|
2,535
|
|
(1)
|
As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more than two years.
|
(2)
|
The notional value contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.
|
(3)
|
As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.
|
(4)
|
As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years. As of December 31, 2018, 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.
|
|
December 31, 2019
|
December 31, 2018
|
|||||
|
Gross Notional Value
|
||||||
|
(In millions)
|
||||||
Interest rate swaps
|
$
|
300
|
|
|
$
|
—
|
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||
|
|
|
Fair Value
|
||||||||||||||
Instrument
|
Balance Sheet Location
|
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
(In millions)
|
||||||||||||||
Natural gas
|
|
|
|
|
|
|
|
|
|
||||||||
Financial futures/swaps
|
Other Current
|
|
$
|
7
|
|
|
$
|
5
|
|
|
$
|
3
|
|
|
$
|
5
|
|
Financial futures/swaps
|
Other
|
|
—
|
|
|
1
|
|
|
—
|
|
|
2
|
|
||||
Physical purchases/sales
|
Other Current
|
|
5
|
|
|
—
|
|
|
3
|
|
|
—
|
|
||||
Physical purchases/sales
|
Other
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
||||
Crude oil (for condensate)
|
|
|
|
|
|
|
|
|
|
||||||||
Financial futures/swaps
|
Other Current
|
|
1
|
|
|
19
|
|
|
9
|
|
|
3
|
|
||||
Financial futures/swaps
|
Other
|
|
—
|
|
|
8
|
|
|
2
|
|
|
—
|
|
||||
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
||||||||
Financial futures/swaps
|
Other Current
|
|
25
|
|
|
3
|
|
|
10
|
|
|
1
|
|
||||
Financial futures/swaps
|
Other
|
|
11
|
|
|
2
|
|
|
2
|
|
|
—
|
|
||||
Total gross derivatives (1)
|
|
|
$
|
49
|
|
|
$
|
38
|
|
|
$
|
33
|
|
|
$
|
11
|
|
(1)
|
See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018.
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||
|
|
|
Fair Value
|
||||||||||||||
Instrument
|
Balance Sheet Location
|
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
(In millions)
|
||||||||||||||
Interest rate swaps
|
Other Current
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest rate swaps
|
Other
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
||||
Total gross interest rate derivatives (1)
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2019.
|
|
Amounts Recognized in Income
|
||||||||||
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Natural Gas
|
|
|
|
|
|
||||||
Financial futures/swaps gains (losses)
|
$
|
13
|
|
|
$
|
(8
|
)
|
|
$
|
20
|
|
Physical purchases/sales gains
|
2
|
|
|
7
|
|
|
9
|
|
|||
Crude oil (for condensate)
|
|
|
|
|
|
||||||
Financial futures/swaps (losses) gains
|
(41
|
)
|
|
6
|
|
|
(1
|
)
|
|||
Natural gas liquids
|
|
|
|
|
|
||||||
Financial futures/swaps gains (losses)
|
42
|
|
|
6
|
|
|
(9
|
)
|
|||
Total
|
$
|
16
|
|
|
$
|
11
|
|
|
$
|
19
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Change in fair value of derivatives
|
$
|
(11
|
)
|
|
$
|
26
|
|
|
$
|
28
|
|
Realized gain (loss) on derivatives
|
27
|
|
|
(15
|
)
|
|
(9
|
)
|
|||
Gain on derivative activity
|
$
|
16
|
|
|
$
|
11
|
|
|
$
|
19
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Debt
|
|
|
|
|
|
|
|
||||||||
Revolving Credit Facility (Level 2) (1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
250
|
|
|
$
|
250
|
|
2019 Term Loan Agreement (Level 2)
|
800
|
|
|
800
|
|
|
—
|
|
|
—
|
|
||||
2019 Notes (Level 2)
|
—
|
|
|
—
|
|
|
500
|
|
|
497
|
|
||||
2024 Notes (Level 2)
|
600
|
|
|
614
|
|
|
600
|
|
|
571
|
|
||||
2027 Notes (Level 2)
|
698
|
|
|
698
|
|
|
698
|
|
|
642
|
|
||||
2028 Notes (Level 2)
|
795
|
|
|
811
|
|
|
794
|
|
|
764
|
|
||||
2029 Notes (Level 2)
|
549
|
|
|
526
|
|
|
—
|
|
|
—
|
|
||||
2044 Notes (Level 2)
|
550
|
|
|
506
|
|
|
550
|
|
|
445
|
|
||||
EOIT Senior Notes (Level 2)
|
251
|
|
|
252
|
|
|
257
|
|
|
256
|
|
(1)
|
Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018, respectively.
|
December 31, 2019
|
Commodity Contracts
|
|
Gas Imbalances (1)
|
||||||||||||
|
Assets
|
|
Liabilities
|
|
Assets (2)
|
|
Liabilities (3)
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Quoted market prices in active market for identical assets (Level 1)
|
$
|
5
|
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Significant other observable inputs (Level 2)
|
44
|
|
|
7
|
|
|
14
|
|
|
11
|
|
||||
Unobservable inputs (Level 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total fair value
|
49
|
|
|
38
|
|
|
14
|
|
|
11
|
|
||||
Netting adjustments
|
(37
|
)
|
|
(37
|
)
|
|
—
|
|
|
—
|
|
||||
Total
|
$
|
12
|
|
|
$
|
1
|
|
|
$
|
14
|
|
|
$
|
11
|
|
December 31, 2018
|
Commodity Contracts
|
|
Gas Imbalances (1)
|
||||||||||||
|
Assets
|
|
Liabilities
|
|
Assets (2)
|
|
Liabilities (3)
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Quoted market prices in active market for identical assets (Level 1)
|
$
|
4
|
|
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Significant other observable inputs (Level 2)
|
29
|
|
|
2
|
|
|
18
|
|
|
17
|
|
||||
Unobservable inputs (Level 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total fair value
|
33
|
|
|
11
|
|
|
18
|
|
|
17
|
|
||||
Netting adjustments
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
||||
Total
|
$
|
24
|
|
|
$
|
2
|
|
|
$
|
18
|
|
|
$
|
17
|
|
(1)
|
The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2019 and 2018.
|
(2)
|
Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
|
(3)
|
Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $8 million and $5 million at December 31, 2019 and 2018, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.
|
|
Commodity Contracts
|
||
|
Natural gas liquids
financial futures/swaps
|
||
|
(In millions)
|
||
Balance as of December 31, 2017
|
$
|
(5
|
)
|
Losses included in earnings
|
(23
|
)
|
|
Settlements
|
7
|
|
|
Transfers out of Level 3
|
21
|
|
|
Balance as of December 31, 2018
|
$
|
—
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
|
|
||||||
Cash Payments:
|
|
|
|
|
|
||||||
Interest, net of capitalized interest
|
$
|
185
|
|
|
$
|
148
|
|
|
$
|
114
|
|
Income taxes, net of refunds
|
1
|
|
|
3
|
|
|
—
|
|
|||
Non-cash transactions:
|
|
|
|
|
|
||||||
Accounts payable related to capital expenditures
|
10
|
|
|
54
|
|
|
39
|
|
|||
Lease liabilities arising from the application of ASC 842
|
45
|
|
|
—
|
|
|
—
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Cash and cash equivalents
|
$
|
4
|
|
|
$
|
8
|
|
Restricted cash
|
—
|
|
|
14
|
|
||
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows
|
$
|
4
|
|
|
$
|
22
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Gas transportation and storage service revenues — CenterPoint Energy
|
$
|
108
|
|
|
$
|
111
|
|
|
$
|
110
|
|
Natural gas product sales — CenterPoint Energy
|
8
|
|
|
11
|
|
|
6
|
|
|||
Gas transportation and storage service revenues — OGE Energy
|
41
|
|
|
37
|
|
|
35
|
|
|||
Natural gas product sales — OGE Energy
|
10
|
|
|
4
|
|
|
2
|
|
|||
Total revenues — affiliated companies
|
$
|
167
|
|
|
$
|
163
|
|
|
$
|
153
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Cost of natural gas purchases — CenterPoint Energy
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
1
|
|
Cost of natural gas purchases — OGE Energy
|
33
|
|
|
23
|
|
|
19
|
|
|||
Total cost of natural gas purchases — affiliated companies
|
$
|
33
|
|
|
$
|
26
|
|
|
$
|
20
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Corporate Services — CenterPoint Energy
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
3
|
|
Operating Lease — CenterPoint Energy
|
1
|
|
|
1
|
|
|
1
|
|
|||
Seconded Employee Costs — OGE Energy
|
18
|
|
|
29
|
|
|
31
|
|
|||
Corporate Services — OGE Energy
|
—
|
|
|
1
|
|
|
3
|
|
|||
Total corporate services, operating lease and seconded employee expense
|
$
|
19
|
|
|
$
|
32
|
|
|
$
|
38
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Provision for current income taxes
|
|
|
|
|
|
||||||
Federal
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
State
|
—
|
|
|
—
|
|
|
1
|
|
|||
Total provision for current income taxes
|
—
|
|
|
—
|
|
|
2
|
|
|||
Benefit for deferred income taxes, net
|
|
|
|
|
|
||||||
Federal
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
State
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Total benefit for deferred income taxes, net
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|||
Total income tax benefit
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In millions)
|
||||||
Deferred tax liabilities, net:
|
|
|
|
||||
Non-current:
|
|
|
|
||||
Intercompany management fee
|
$
|
17
|
|
|
$
|
16
|
|
Depreciation
|
6
|
|
|
5
|
|
||
Accrued compensation
|
(19
|
)
|
|
(16
|
)
|
||
Total deferred tax liabilities, net
|
$
|
4
|
|
|
$
|
5
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Performance units
|
$
|
9
|
|
|
$
|
9
|
|
|
$
|
10
|
|
Restricted units
|
—
|
|
|
1
|
|
|
2
|
|
|||
Phantom units
|
7
|
|
|
6
|
|
|
3
|
|
|||
Total equity-based compensation expense
|
$
|
16
|
|
|
$
|
16
|
|
|
$
|
15
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
Number of units granted
|
638,798
|
|
|
551,742
|
|
|
468,626
|
|
|||
Fair value of units granted
|
$
|
19.95
|
|
|
$
|
17.70
|
|
|
$
|
19.27
|
|
Expected price volatility
|
34.2
|
%
|
|
44.2
|
%
|
|
47.3
|
%
|
|||
Risk-free interest rate
|
2.54
|
%
|
|
2.36
|
%
|
|
1.57
|
%
|
|||
Distribution yield
|
8.38
|
%
|
|
8.56
|
%
|
|
9.10
|
%
|
|||
Expected life of units (in years)
|
3
|
|
|
3
|
|
|
3
|
|
|
2019
|
|
2018
|
|
2017
|
|||
Phantom units granted
|
695,486
|
|
|
546,708
|
|
|
392,338
|
|
Fair value of phantom units granted
|
$8.95 - $15.04
|
|
|
$13.74 - $17.00
|
|
|
$15.44 - $16.93
|
|
|
2019
|
|
2018
|
|
2017
|
||||||
Common units granted
|
28,221
|
|
|
16,335
|
|
|
16,653
|
|
|||
Fair value of common units granted
|
$
|
10.43
|
|
|
$
|
14.94
|
|
|
$
|
15.03
|
|
|
Performance Units
|
|
Phantom Units
|
||||||||||||
|
Number
of Units
|
|
Weighted Average
Grant-Date
Fair Value,
Per Unit
|
|
Number
of Units
|
|
Weighted Average
Grant-Date
Fair Value,
Per Unit
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions, except unit data)
|
||||||||||||||
Units outstanding at 12/31/2018
|
2,109,835
|
|
|
$
|
14.33
|
|
|
1,447,590
|
|
|
$
|
12.38
|
|
||
Granted (1)
|
638,798
|
|
|
19.95
|
|
|
695,486
|
|
|
14.26
|
|
||||
Vested (2)(3)
|
(1,174,597
|
)
|
|
11.09
|
|
|
(608,755
|
)
|
|
8.71
|
|
||||
Forfeited
|
(180,707
|
)
|
|
18.96
|
|
|
(141,761
|
)
|
|
14.89
|
|
||||
Units outstanding at 12/31/2019
|
1,393,329
|
|
|
19.04
|
|
|
1,392,560
|
|
|
14.65
|
|
||||
Aggregate intrinsic value of units outstanding at December 31, 2019
|
$
|
14
|
|
|
|
|
$
|
14
|
|
|
|
(1)
|
For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.
|
(2)
|
Performance units vested as of December 31, 2019 include 1,097,846 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200%, or 2,195,692 units on March 1, 2019 and 53,972 units on September 6, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018.
|
(3)
|
Performance units outstanding as of December 31, 2019 include 378,109 units from the 2017 annual grants, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2017 through December 31, 2019, will not vest. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.
|
|
Year Ended December 31, 2019
|
||||||||||
|
Performance Units
|
|
Restricted Stock
|
|
Phantom Units
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Aggregate intrinsic value of units vested
|
$
|
34
|
|
|
$
|
—
|
|
|
$
|
9
|
|
Fair value of units vested
|
13
|
|
|
—
|
|
|
5
|
|
|
Year Ended December 31, 2018
|
||||||||||
|
Performance Units
|
|
Restricted Stock
|
|
Phantom Units
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Aggregate intrinsic value of units vested
|
$
|
11
|
|
|
$
|
3
|
|
|
$
|
1
|
|
Fair value of units vested
|
7
|
|
|
4
|
|
|
—
|
|
|
Year Ended December 31, 2017
|
||||||||||
|
Performance Units
|
|
Restricted Stock
|
|
Phantom Units
|
||||||
|
|
|
|
|
|
||||||
|
(In millions)
|
||||||||||
Aggregate intrinsic value of units vested
|
$
|
5
|
|
|
$
|
2
|
|
|
$
|
—
|
|
Fair value of units vested
|
10
|
|
|
4
|
|
|
—
|
|
|
December 31, 2019
|
||||
|
Unrecognized Compensation Cost
(In millions)
|
|
Weighted Average to be Recognized
(In years)
|
||
Performance Units
|
$
|
12
|
|
|
1.32
|
Phantom Units
|
9
|
|
|
1.24
|
|
Total
|
$
|
21
|
|
|
|
Year Ended December 31, 2019
|
Gathering and
Processing |
|
Transportation
and Storage (1) |
|
Eliminations
|
|
Total
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Product sales
|
$
|
1,449
|
|
|
$
|
487
|
|
|
$
|
(403
|
)
|
|
$
|
1,533
|
|
Service revenues
|
889
|
|
|
551
|
|
|
(13
|
)
|
|
1,427
|
|
||||
Total Revenues
|
2,338
|
|
|
1,038
|
|
|
(416
|
)
|
|
2,960
|
|
||||
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately
|
1,203
|
|
|
491
|
|
|
(415
|
)
|
|
1,279
|
|
||||
Operation and maintenance, General and administrative
|
320
|
|
|
207
|
|
|
(1
|
)
|
|
526
|
|
||||
Depreciation and amortization
|
308
|
|
|
125
|
|
|
—
|
|
|
433
|
|
||||
Impairments
|
86
|
|
|
—
|
|
|
—
|
|
|
86
|
|
||||
Taxes other than income tax
|
41
|
|
|
26
|
|
|
—
|
|
|
67
|
|
||||
Operating Income
|
$
|
380
|
|
|
$
|
189
|
|
|
$
|
—
|
|
|
$
|
569
|
|
Total Assets
|
$
|
9,739
|
|
|
$
|
5,886
|
|
|
$
|
(3,359
|
)
|
|
$
|
12,266
|
|
Capital expenditures
|
$
|
314
|
|
|
$
|
118
|
|
|
$
|
—
|
|
|
$
|
432
|
|
Year Ended December 31, 2018
|
Gathering and
Processing |
|
Transportation
and Storage (1) |
|
Eliminations
|
|
Total
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Product sales
|
$
|
2,016
|
|
|
$
|
625
|
|
|
$
|
(535
|
)
|
|
$
|
2,106
|
|
Service revenues
|
802
|
|
|
537
|
|
|
(14
|
)
|
|
1,325
|
|
||||
Total Revenues
|
2,818
|
|
|
1,162
|
|
|
(549
|
)
|
|
3,431
|
|
||||
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately
|
1,741
|
|
|
628
|
|
|
(550
|
)
|
|
1,819
|
|
||||
Operation and maintenance, General and administrative
|
312
|
|
|
189
|
|
|
—
|
|
|
501
|
|
||||
Depreciation and amortization
|
263
|
|
|
135
|
|
|
—
|
|
|
398
|
|
||||
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Taxes other than income tax
|
38
|
|
|
27
|
|
|
—
|
|
|
65
|
|
||||
Operating Income
|
$
|
464
|
|
|
$
|
183
|
|
|
$
|
1
|
|
|
$
|
648
|
|
Total Assets
|
$
|
9,874
|
|
|
$
|
5,805
|
|
|
$
|
(3,235
|
)
|
|
$
|
12,444
|
|
Capital expenditures, including acquisitions
|
$
|
981
|
|
|
$
|
190
|
|
|
$
|
—
|
|
|
$
|
1,171
|
|
Year Ended December 31, 2017
|
Gathering and
Processing
|
|
Transportation
and Storage (1)
|
|
Eliminations
|
|
Total
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(In millions)
|
||||||||||||||
Product sales
|
$
|
1,538
|
|
|
$
|
621
|
|
|
$
|
(506
|
)
|
|
$
|
1,653
|
|
Service revenues
|
632
|
|
|
525
|
|
|
(7
|
)
|
|
1,150
|
|
||||
Total Revenues
|
2,170
|
|
|
1,146
|
|
|
(513
|
)
|
|
2,803
|
|
||||
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately
|
1,285
|
|
|
604
|
|
|
(508
|
)
|
|
1,381
|
|
||||
Operation and maintenance, General and administrative
|
289
|
|
|
179
|
|
|
(4
|
)
|
|
464
|
|
||||
Depreciation and amortization
|
232
|
|
|
134
|
|
|
—
|
|
|
366
|
|
||||
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Taxes other than income tax
|
37
|
|
|
27
|
|
|
—
|
|
|
64
|
|
||||
Operating Income
|
$
|
327
|
|
|
$
|
202
|
|
|
$
|
(1
|
)
|
|
$
|
528
|
|
Total Assets
|
$
|
9,079
|
|
|
$
|
5,616
|
|
|
$
|
(3,102
|
)
|
|
$
|
11,593
|
|
Capital expenditures
|
$
|
601
|
|
|
$
|
113
|
|
|
$
|
—
|
|
|
$
|
714
|
|
(1)
|
Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019, 2018 and 2017.
|
|
Quarters Ended
|
||||||||||||||
|
March 31, 2019
|
|
June 30, 2019
|
|
September 30, 2019
|
|
December 31, 2019
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(in millions, except per unit data)
|
||||||||||||||
Total Revenues
|
$
|
795
|
|
|
$
|
735
|
|
|
$
|
699
|
|
|
$
|
731
|
|
Cost of natural gas and natural gas liquids
|
378
|
|
|
317
|
|
|
263
|
|
|
321
|
|
||||
Operating income (1)
|
165
|
|
|
167
|
|
|
175
|
|
|
62
|
|
||||
Net income
|
123
|
|
|
124
|
|
|
133
|
|
|
20
|
|
||||
Net income attributable to limited partners
|
122
|
|
|
124
|
|
|
132
|
|
|
18
|
|
||||
Net income attributable to common units
|
113
|
|
|
115
|
|
|
123
|
|
|
9
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Basic earnings per unit
|
|
|
|
|
|
|
|
||||||||
Common units
|
$
|
0.26
|
|
|
$
|
0.26
|
|
|
$
|
0.28
|
|
|
$
|
0.02
|
|
Diluted earnings per unit
|
|
|
|
|
|
|
|
||||||||
Common units
|
$
|
0.26
|
|
|
$
|
0.26
|
|
|
$
|
0.28
|
|
|
$
|
0.02
|
|
|
|
|
|
|
|
|
|
||||||||
|
Quarters Ended
|
||||||||||||||
|
March 31, 2018
|
|
June 30, 2018
|
|
September 30, 2018
|
|
December 31, 2018
|
||||||||
|
|
|
|
|
|
|
|
||||||||
|
(in millions, except per unit data)
|
||||||||||||||
Total Revenues
|
$
|
748
|
|
|
$
|
805
|
|
|
$
|
928
|
|
|
$
|
950
|
|
Cost of natural gas and natural gas liquids
|
375
|
|
|
444
|
|
|
516
|
|
|
484
|
|
||||
Operating income
|
139
|
|
|
126
|
|
|
171
|
|
|
212
|
|
||||
Net income
|
114
|
|
|
95
|
|
|
139
|
|
|
175
|
|
||||
Net income attributable to limited partners
|
114
|
|
|
95
|
|
|
138
|
|
|
174
|
|
||||
Net income attributable to common units
|
105
|
|
|
86
|
|
|
129
|
|
|
165
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Basic earnings per unit
|
|
|
|
|
|
|
|
||||||||
Common Units
|
$
|
0.24
|
|
|
$
|
0.20
|
|
|
$
|
0.30
|
|
|
$
|
0.38
|
|
Diluted earnings per unit
|
|
|
|
|
|
|
|
||||||||
Common Units
|
$
|
0.24
|
|
|
$
|
0.20
|
|
|
$
|
0.30
|
|
|
$
|
0.38
|
|
(1)
|
The Partnership recorded an impairment to goodwill of $86 million during the fourth quarter related to the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. See Note 10 for further information.
|
•
|
possesses appropriate skills and professional experience;
|
•
|
has a reputation for integrity and other qualities;
|
•
|
possesses expertise, including industry knowledge, determined in the context of the needs of the Board of Directors;
|
•
|
has experience in positions with a high degree of responsibility;
|
•
|
is a leader in the organizations with which he or she is affiliated;
|
•
|
is diverse in terms of geography, gender, ethnicity and age;
|
•
|
has the time, energy, interest and willingness to serve as a member of the Board of Directors; and
|
•
|
meets such standards of independence and financial knowledge as may be required or desirable.
|
Name
|
|
Age
|
|
Title
|
Scott M. Prochazka (1)
|
|
53
|
|
Director and Chairman
|
Xia Liu (1)
|
|
50
|
|
Director
|
Sean Trauschke (2)
|
|
52
|
|
Director
|
Stephen E. Merrill (2)
|
|
55
|
|
Director
|
Alan N. Harris (3)
|
|
66
|
|
Director
|
Ronnie K. Irani (3)
|
|
63
|
|
Director
|
Peter H. Kind (3)
|
|
63
|
|
Director
|
Rodney J. Sailor (3)
|
|
61
|
|
Director, President and Chief Executive Officer
|
John P. Laws (3)
|
|
45
|
|
Executive Vice President, Chief Financial Officer and Treasurer
|
Tina V. Faraca (4)
|
|
55
|
|
Senior Vice President and Chief Commercial Officer
|
Deanna J. Farmer (3)
|
|
54
|
|
Executive Vice President and Chief Administrative Officer
|
Mark C. Schroeder (4)
|
|
63
|
|
Executive Vice President, General Counsel and Chief Ethics & Compliance Officer
|
(1)
|
1111 Louisiana Street, Houston, Texas 77002
|
(2)
|
321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101
|
(3)
|
499 West Sheridan Ave, Suite 1500, Oklahoma City, Oklahoma 73102
|
(4)
|
910 Louisiana Street, Houston, Texas 77002
|
Company
|
Ticker
|
|
1.
|
Buckeye Partners LP
|
BPL
|
2.
|
Crestwood Equity Partners LP
|
CEQP
|
3.
|
DCP Midstream, LP
|
DCP
|
4.
|
EnLink Midstream Partners, LP
|
ENLK
|
5.
|
Magellan Midstream Partners, L.P.
|
MMP
|
6.
|
ONEOK Inc.
|
OKE
|
7.
|
MPLX LP
|
MPLX
|
8.
|
NuStar Energy L.P.
|
NS
|
9.
|
Spectra Energy Partners, LP
|
SEP
|
10.
|
Summit Midstream Partners, LP
|
SMLP
|
11.
|
SemGroup Corporation
|
SEMG
|
12.
|
Targa Resources Corp.
|
TRGP
|
13.
|
Western Gas Equity Partners, LP
|
WGP
|
14.
|
The Williams Companies, Inc.
|
WMB
|
Name
|
|
Base Salary
|
|
Short-Term
Incentive Target
|
|
Long-Term
Incentive Target |
|||
Rodney J. Sailor
|
|
725,004
|
|
|
100
|
%
|
|
365
|
%
|
John P. Laws
|
|
450,965
|
|
|
75
|
%
|
|
250
|
%
|
Tina V. Faraca
|
|
345,010
|
|
|
60
|
%
|
|
105
|
%
|
Deanna J. Farmer
|
|
368,222
|
|
|
70
|
%
|
|
160
|
%
|
Mark C. Schroeder
|
|
366,995
|
|
|
70
|
%
|
|
160
|
%
|
|
|
Minimum
|
|
Target
|
|
Maximum
|
|
Actual Performance
|
|
Payout % of Target
|
DCF
|
|
$740 million
|
|
$775 million
|
|
$810 million
|
|
$784 million
|
|
56.20%
|
O&M and G&A
|
|
$540 million
|
|
$520 million
|
|
$500 million
|
|
$519 million
|
|
15.41%
|
CROIC
|
|
9.3%
|
|
9.6%
|
|
9.9%
|
|
9.7%
|
|
16.55%
|
Safety Targets
|
|
|
|
|
|
|
|
|
|
|
TRI
|
Q1
|
3
|
|
2
|
|
1
|
|
7
|
|
—%
|
|
Q2
|
3
|
|
2
|
|
1
|
|
3
|
|
1.25%
|
|
Q3
|
3
|
|
2
|
|
1
|
|
5
|
|
—%
|
|
Q4
|
3
|
|
2
|
|
1
|
|
3
|
|
1.25%
|
PVI
|
Q1
|
5
|
|
4
|
|
2
|
|
5
|
|
1.25%
|
|
Q2
|
5
|
|
4
|
|
2
|
|
3
|
|
3.13%
|
|
Q3
|
5
|
|
4
|
|
2
|
|
5
|
|
1.25%
|
|
Q4
|
5
|
|
4
|
|
2
|
|
3
|
|
3.13%
|
Name
|
|
Performance Award
|
|
Phantom Award
|
||
Rodney J. Sailor
|
|
114,063
|
|
|
61,419
|
|
John P. Laws
|
|
48,596
|
|
|
26,167
|
|
Tina V. Faraca
|
|
34,795
|
|
|
53,736
|
|
Deanna J. Farmer
|
|
25,394
|
|
|
13,675
|
|
Mark C. Schroeder
|
|
25,310
|
|
|
13,629
|
|
Company
|
Ticker
|
|
1.
|
Altus Midstream Company
|
ALTM
|
2.
|
Antero Midstream GP LP
|
AMGP
|
3.
|
CNX Midstream Partners LP
|
CNXM
|
4.
|
Crestwood Equity Partners LP
|
CEQP
|
5.
|
DCP Midstream, LP
|
DCP
|
6.
|
Energy Transfer LP
|
ET
|
7.
|
EnLink Midstream, LLC
|
ENLC
|
8.
|
Equitrans Midstream Corporation
|
ETRN
|
9.
|
Hess Midstream Partners LP
|
HESM
|
10.
|
MPLX LP
|
MPLX
|
11.
|
Noble Midstream Partners LP
|
NBLX
|
12.
|
ONEOK, Inc.
|
OKE
|
13.
|
Summit Midstream Partners, LP
|
SMLP
|
14.
|
Tallgrass Energy, LP
|
TGE
|
15.
|
Targa Resources Corp.
|
TRGP
|
16.
|
TC PipeLines, LP
|
TCP
|
17.
|
Western Gas Equity Partners, LP
|
WGP
|
18.
|
The Williams Companies, Inc.
|
WMB
|
Name and Principal Position
|
|
Year
|
|
Salary
($) |
|
Bonus
($) |
|
Stock Awards
($) (1) |
|
Option Awards ($)
|
|
Non-Equity Incentive
Plan Compensation ($) (2) |
|
All Other Compensation
($) (4)
|
|
Total
($) |
|||||||
(a)
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|
(g)
|
|
(i)
|
|
(j)
|
|||||||
Rodney J. Sailor
|
|
2019
|
|
719,235
|
|
|
—
|
|
|
3,199,299
|
|
|
—
|
|
|
715,085
|
|
|
1,930,912
|
|
|
6,564,531
|
|
President and Chief Executive Officer
|
|
2018
|
|
686,346
|
|
|
—
|
|
|
2,367,948
|
|
|
—
|
|
|
625,965
|
|
|
820,553
|
|
|
4,500,812
|
|
|
|
2017
|
|
636,538
|
|
|
—
|
|
|
2,159,419
|
|
|
—
|
|
|
789,324
|
|
|
394,932
|
|
|
3,980,213
|
|
John P. Laws
|
|
2019
|
|
446,445
|
|
|
—
|
|
|
1,363,042
|
|
|
—
|
|
|
332,902
|
|
|
641,368
|
|
|
2,783,757
|
|
Executive Vice President, Chief Financial Officer and Treasurer
|
|
2018
|
|
414,920
|
|
|
—
|
|
|
924,700
|
|
|
—
|
|
|
283,813
|
|
|
186,470
|
|
|
1,809,903
|
|
|
|
2017
|
|
349,529
|
|
|
—
|
|
|
742,140
|
|
|
—
|
|
|
336,463
|
|
|
124,267
|
|
|
1,552,399
|
|
Tina V. Faraca
|
|
2019
|
|
318,866
|
|
|
100,000
|
|
(3)
|
1,222,143
|
|
|
|
|
195,557
|
|
|
60,818
|
|
|
1,897,384
|
|
|
Senior Vice President and Chief Commercial Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Deanna J. Farmer
|
|
2019
|
|
365,334
|
|
|
—
|
|
|
712,282
|
|
|
—
|
|
|
254,259
|
|
|
468,041
|
|
|
1,799,916
|
|
Executive Vice President and Chief Administrative Officer
|
|
2018
|
|
350,593
|
|
|
—
|
|
|
534,846
|
|
|
—
|
|
|
220,088
|
|
|
278,466
|
|
|
1,383,993
|
|
|
|
2017
|
|
335,688
|
|
|
—
|
|
|
507,728
|
|
|
—
|
|
|
291,383
|
|
|
92,890
|
|
|
1,227,689
|
|
Mark C. Schroeder
|
|
2019
|
|
364,279
|
|
|
—
|
|
|
709,915
|
|
|
—
|
|
|
342,263
|
|
|
469,612
|
|
|
1,886,069
|
|
Executive Vice President, General Counsel and Chief Ethics & Compliance Officer
|
|
2018
|
|
350,168
|
|
|
—
|
|
|
534,355
|
|
|
—
|
|
|
219,821
|
|
|
280,128
|
|
|
1,384,472
|
|
|
|
2017
|
|
335,094
|
|
|
—
|
|
|
506,528
|
|
|
—
|
|
|
290,867
|
|
|
140,693
|
|
|
1,273,182
|
|
(1)
|
Amounts in this column reflect the aggregate grant date fair value amount of the Partnership equity-based unit awards granted to each named executive officer. The grant date fair value amount of performance unit awards is computed in accordance with FASB ASC Topic 718 based on the probable achievement level of the underlying performance conditions as of the grant date. Please refer to the Grants of Plan-Based Awards table for 2019 and the accompanying footnotes. Assuming achievement of the performance goals at the maximum level, the grant date fair value of the performance units granted in 2019 and included in this column would be $4,551,114 for Mr. Sailor, $1,938,980 for Mr. Laws, $1,388,320 for Ms. Faraca, $1,013,221 for Ms. Farmer, and $1,009,869 for Mr. Schroeder. Assuming achievement of the performance goals at the maximum level, the grant date fair value of the performance units granted in 2018 and included in this column would be $3,318,502 for Mr. Sailor, $1,295,888 for Mr. Laws, $749,524 for Ms. Farmer, and $748,852 for Mr. Schroeder. Assuming achievement of the performance goals at the maximum level, the grant date fair value of the performance units granted in 2017 and included in this column would be $2,969,584 for Mr. Sailor, $1,020,578 for Mr. Laws, $698,191 for Ms. Farmer, and $696,572 for Mr. Schroeder. The grant date fair value amount of phantom unit awards is computed in accordance with FASB ASC Topic 718. See Note 19 to the financial statements for a discussion of the valuation assumptions used for these awards.
|
(2)
|
Amounts in this column reflect amounts earned under the Partnership’s Short-Term Incentive Plan.
|
(3)
|
This amount represents a discretionary bonus.
|
(4)
|
The following table sets forth the elements of All Other Compensation for 2019, 2018 and 2017.
|
Name
|
|
401(k) Plan Employer Contributions ($)
|
|
Non-Qualified Matching Contributions ($)
|
|
Distribution Equivalent Rights
($) |
|
Supplemental Life Insurance
($)
|
|
Long Term Disability ($)
|
|
Other
($) (5)
|
|
Total
($) |
|||||||
Rodney J. Sailor
|
2019
|
30,800
|
|
|
117,172
|
|
|
1,779,485
|
|
|
2,735
|
|
|
720
|
|
|
—
|
|
|
1,930,912
|
|
|
2018
|
30,250
|
|
|
132,074
|
|
|
655,703
|
|
|
1,806
|
|
|
720
|
|
|
—
|
|
|
820,553
|
|
|
2017
|
29,700
|
|
|
118,834
|
|
|
243,824
|
|
|
1,806
|
|
|
768
|
|
|
—
|
|
|
394,932
|
|
John P. Laws
|
2019
|
30,800
|
|
|
49,528
|
|
|
559,698
|
|
|
622
|
|
|
720
|
|
|
—
|
|
|
641,368
|
|
|
2018
|
30,250
|
|
|
52,402
|
|
|
102,678
|
|
|
420
|
|
|
720
|
|
|
—
|
|
|
186,470
|
|
|
2017
|
29,700
|
|
|
37,381
|
|
|
55,998
|
|
|
420
|
|
|
768
|
|
|
—
|
|
|
124,267
|
|
Tina V. Faraca
|
2019
|
30,800
|
|
|
4,642
|
|
|
22,882
|
|
|
1,774
|
|
|
720
|
|
|
—
|
|
|
60,818
|
|
Deanna J. Farmer
|
2019
|
30,800
|
|
|
33,596
|
|
|
401,959
|
|
|
966
|
|
|
720
|
|
|
—
|
|
|
468,041
|
|
|
2018
|
30,250
|
|
|
40,367
|
|
|
206,163
|
|
|
966
|
|
|
720
|
|
|
—
|
|
|
278,466
|
|
|
2017
|
29,700
|
|
|
37,256
|
|
|
24,200
|
|
|
966
|
|
|
768
|
|
|
—
|
|
|
92,890
|
|
Mark C. Schroeder
|
2019
|
30,800
|
|
|
33,451
|
|
|
401,869
|
|
|
2,772
|
|
|
720
|
|
|
—
|
|
|
469,612
|
|
|
2018
|
30,250
|
|
|
40,264
|
|
|
206,122
|
|
|
2,772
|
|
|
720
|
|
|
—
|
|
|
280,128
|
|
|
2017
|
29,700
|
|
|
37,190
|
|
|
70,263
|
|
|
2,772
|
|
|
768
|
|
|
—
|
|
|
140,693
|
|
(5)
|
None of our named executive officers received perquisites valued in excess of $10,000 in 2019.
|
Name
|
|
Grant Date
|
|
Board Approval
Date
|
|
Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)
|
|
Estimated Future Payouts Under Equity Incentive Plan Awards (2)
|
|
All Other Stock Awards: Number of Shares of Stock or Units (#) (3)
|
|
Grant Date Fair Value of Stock Awards
($) (4) |
||||||||||||||||
|
|
|
|
|
|
Threshold
($) |
|
Target
($) |
|
Maximum
($) |
|
Threshold
(#) |
|
Target
(#) |
|
Maximum
(#) |
|
|
|
|
||||||||
(a)
|
|
(b)
|
|
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|
(g)
|
|
(h)
|
|
(i)
|
|
(l)
|
||||||||
Rodney J. Sailor
|
|
02/13/2019
|
|
02/13/2019
|
|
359,615
|
|
|
719,235
|
|
|
1,438,470
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57,031
|
|
|
114,063
|
|
|
228,126
|
|
|
—
|
|
|
2,275,557
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61,419
|
|
|
923,742
|
|
John P. Laws
|
|
02/13/2019
|
|
02/13/2019
|
|
167,417
|
|
334,834
|
|
|
669,668
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,298
|
|
|
48,596
|
|
|
97,192
|
|
|
—
|
|
|
969,490
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26,167
|
|
|
393,552
|
|
Tina V. Faraca
|
|
02/13/2019
|
|
02/13/2019
|
|
89,011
|
|
|
178,021
|
|
|
356,042
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,173
|
|
|
14,346
|
|
|
28,692
|
|
|
—
|
|
|
286,203
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,725
|
|
|
116,184
|
|
|
|
12/03/2019
|
|
11/04/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,224
|
|
|
20,449
|
|
|
40,898
|
|
|
—
|
|
|
407,958
|
|
|
|
12/03/2019
|
|
11/04/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,562
|
|
|
228,780
|
|
|
|
12/03/2019
|
|
11/04/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,449
|
|
|
183,019
|
|
Deanna J. Farmer
|
|
02/13/2019
|
|
02/13/2019
|
|
127,867
|
|
|
255,734
|
|
|
511,468
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,697
|
|
|
25,394
|
|
|
50,788
|
|
|
—
|
|
|
506,610
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,675
|
|
|
205,672
|
|
Mark C. Schroeder
|
|
02/13/2019
|
|
02/13/2019
|
|
127,498
|
|
|
254,995
|
|
|
509,990
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,655
|
|
|
25,310
|
|
|
50,620
|
|
|
—
|
|
|
504,935
|
|
|
|
03/01/2019
|
|
02/14/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,629
|
|
|
204,980
|
|
(1)
|
Amounts in columns (c), (d) and (e) of the Grants of Plan-Based Awards Table for 2019 above represent the threshold, target and maximum amounts that would be payable to named executive officers pursuant to the 2019 annual incentive awards made under the Enable Midstream Partners, LP Short-Term Incentive Plan. The Short-Term Incentive Plan was designed with a funding trigger that requires threshold performance for the plan to payout. If threshold performance is not met, no payments will be made. For each performance measure, established thresholds were set (at which 50% payout would be made), a target level of performance (at which a 100% payout would be made) and a maximum level of performance (at or above which a 150% payout would be made) based on eligible earnings. The award may be increased or decreased at the Compensation Committee’s discretion based on the performance of the named executive officer, but the award may not exceed 200% of the named executive officer’s target. As discussed in the Compensation Discussion and Analysis above, the amount that each executive officer will receive is dependent upon Partnership performance against DCF (50%), O&M and G&A (15%), CROIC (15%), and safety (20%) targets.
|
(2)
|
Amounts in columns (f), (g) and (h) above represent awards of performance units under Enable Midstream Partners, LP Long-Term Incentive Plan. All payouts of such performance units will be made in units and any accumulated distribution equivalent rights will be paid in cash to the extent earned. Due to their variable nature, accumulated distribution equivalent rights are not disclosed in the table above. The conditions of the 2019 award provide that the executive officer will receive from 0% to 200% of the performance units awarded depending upon the Partnership’s total unitholder return of a group of 18 peer companies over a performance period from January 1, 2019 through December 31, 2021. Total unit holder return includes both price appreciation and cash distributions over the performance period. Price appreciation is determined by comparing the average closing price of units of the Partnership or any company in the peer group for the 20 trading days preceding the performance period and for the last 20 trading days during the performance period. Cash distributions for the Partnership or any company in the peer group are assumed to have been reinvested in additional units on the date two days prior to the distribution record date. At the end of the performance period, the terms of these performance units provide for payout of 100% of the performance units initially granted if the Partnership’s total unitholder return is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200% of the performance units granted if total unitholder return is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100% of the performance units granted if the Partnership’s total unitholder return is below the 50th percentile of the peer group, with no payout for performance below the 30th percentile.
|
(3)
|
Amounts in column (i) above represent the number of phantom unit awards granted to each of our named executive officers under the Enable Midstream Partners, LP Long-Term Incentive Plan.
|
(4)
|
Amounts reflect the grant date fair value computed in accordance with FASB ASC Topic 718 based on a probable value of these awards or target value, of 100% payout. See Note 19 to the financial statements for further information.
|
|
|
Unit Awards
|
||||||||||||
Name
|
|
Number of Units That Have Not Vested
(#)
|
|
|
Market Value of Units That Have Not Vested
($)
|
|
Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested
(#)
|
|
|
Equity Incentive Plan Awards: Market Value of Unearned Units or Other Rights That Have Not Vested
($)
|
||||
(a)
|
|
(g)
|
|
|
(h)
|
|
(i)
|
|
|
(j)
|
||||
Rodney J. Sailor
|
|
61,419
|
|
(1)
|
|
616,033
|
|
|
114,063
|
|
(4)
|
|
1,144,052
|
|
|
|
50,477
|
|
(2)
|
|
506,284
|
|
|
93,743
|
|
(5)
|
|
940,242
|
|
|
|
41,490
|
|
(3)
|
|
416,145
|
|
|
38,526
|
|
(6)
|
|
386,416
|
|
John P. Laws
|
|
26,167
|
|
(1)
|
|
262,455
|
|
|
48,596
|
|
(4)
|
|
487,418
|
|
|
|
19,712
|
|
(2)
|
|
197,711
|
|
|
36,607
|
|
(5)
|
|
367,168
|
|
|
|
14,259
|
|
(3)
|
|
143,018
|
|
|
13,240
|
|
(6)
|
|
132,797
|
|
Tina V. Faraca
|
|
7,725
|
|
(1)
|
|
77,482
|
|
|
14,346
|
|
(4)
|
|
143,890
|
|
|
|
52,779
|
|
(7)
|
|
529,373
|
|
|
20,449
|
|
(9)
|
|
205,103
|
|
|
|
|
|
|
|
|
13,537
|
|
(10)
|
|
135,776
|
|
||
Deanna J. Farmer
|
|
13,675
|
|
(1)
|
|
137,160
|
|
|
25,394
|
|
(4)
|
|
254,702
|
|
|
|
11,402
|
|
(2)
|
|
114,362
|
|
|
21,173
|
|
(5)
|
|
212,365
|
|
|
|
9,756
|
|
(3)
|
|
97,853
|
|
|
9,058
|
|
(6)
|
|
90,852
|
|
Mark C. Schroeder
|
|
13,629
|
|
(8)
|
|
136,699
|
|
|
25,310
|
|
(4)
|
|
253,859
|
|
|
|
11,391
|
|
(2)
|
|
114,252
|
|
|
21,154
|
|
(5)
|
|
212,175
|
|
|
|
9,732
|
|
(3)
|
|
97,612
|
|
|
9,037
|
|
(6)
|
|
90,641
|
|
(1)
|
This amount represents a time-based phantom unit award under the Enable Midstream Partners Long-Term Incentive Plan scheduled to vest on March 1, 2022. Values were calculated based on a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019.
|
(2)
|
This amount represents a time-based phantom unit award under the Enable Midstream Partners Long-Term Incentive Plan scheduled to vest on March 1, 2021. Values were calculated based on a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019.
|
(3)
|
This amount represents a time-based phantom unit award under the Enable Midstream Partners Long-Term Incentive Plan scheduled to vest on March 1, 2020. Values were calculated based on a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019.
|
(4)
|
This amount represents a performance unit award under the Enable Midstream Partners Long-Term Incentive Plan. The performance cycle began on January 1, 2019 and ends December 31, 2021. The number of units listed reflects the number of units paid at target performance. The value of the awards was calculated based on target payout of 100% and a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019. This award will vest on March 1, 2022.
|
(5)
|
This amount represents a performance unit award under the Enable Midstream Partners Long-Term Incentive Plan. The performance cycle began on January 1, 2018 and ends December 31, 2020. The number of units listed reflects the number of units paid at target performance. The value of the awards was calculated based on target payout of 100% and a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019. This award will vest on March 1, 2021.
|
(6)
|
This amount represents a performance unit award under the Enable Midstream Partners Long-Term Incentive Plan. The performance cycle began on January 1, 2017 and ended December 31, 2019. The number of units listed reflects the number of units paid at threshold performance. The value of the awards was calculated based on threshold payout of 50% and a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019. On February 13, 2020, the Compensation Committee determined that, based on the performance level attained, this award will not vest.
|
(7)
|
This amount represents three time-based phantom unit awards under the Enable Midstream Partners Long-Term Incentive Plan, of which 6,768 units will vest on October 15, 2020, 25,562 units will vest on December 3, 2020, and 20,449 units will vest on December 2, 2021. Values were calculated based on a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019.
|
(8)
|
This amount represents a time-based phantom unit award under the Enable Midstream Partners Long-Term Incentive Plan, of which 4,543 units will vest on March 1, 2020, 4,543 units will vest on March 1, 2021 and 4,543 units will vest on March 1, 2022. Values were calculated based on a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019.
|
(9)
|
This amount represents a performance unit award under the Enable Midstream Partners Long-Term Incentive Plan. The performance cycle began on January 1, 2019 and ends December 31, 2021. The number of units listed reflects the number of units paid at target performance. The value of the award was calculated based on target payout of 100% and a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019. This award will vest on December 3, 2022.
|
(10)
|
This amount represents a performance unit award under the Enable Midstream Partners Long-Term Incentive Plan. The performance cycle began on January 1, 2018 and ends December 31, 2020. The number of units listed reflects the number of units paid at target performance. The value of the awards was calculated based on target payout of 100% and a $10.03 closing price of the Partnership’s common units, as reported on the NYSE at December 31, 2019. This award will vest on October 15, 2021.
|
|
|
Stock Awards
|
|||||
Name
|
|
Number of Shares Acquired on Vesting
(#)
|
|
|
Value Realized on Vesting
($) (1)
|
||
(a)
|
|
(d)
|
|
|
(e)
|
||
Rodney J. Sailor
|
|
414,984
|
|
(2)
|
|
6,241,359
|
|
|
|
51,874
|
|
(3)
|
|
780,185
|
|
John P. Laws
|
|
127,088
|
|
(2)
|
|
1,911,404
|
|
|
|
15,887
|
|
(3)
|
|
238,940
|
|
Tina V. Faraca
|
|
6,768
|
|
(4)
|
|
72,485
|
|
Deanna J. Farmer
|
|
93,660
|
|
(2)
|
|
1,408,646
|
|
|
|
11,708
|
|
(3)
|
|
176,088
|
|
Mark C. Schroeder
|
|
93,660
|
|
(2)
|
|
1,408,646
|
|
|
|
11,708
|
|
(3)
|
|
176,088
|
|
(1)
|
The value of the awards was calculated based on the closing price of the Partnership’s common units, as reported on the NYSE on the date of vesting.
|
(2)
|
These amounts reflect the payout of performance units granted on April 1, 2016. The units vested on March 1, 2019. Performance was based on the Partnership’s total unitholder return over a period of January 1, 2016 to December 31, 2018.
|
(3)
|
These amounts reflect the payout of time-based phantom units granted on April 1, 2016. The units vested on March 1, 2019.
|
(4)
|
These amounts reflect the distribution of time-based phantom units granted on October 15, 2018. The units vested on October 15, 2019.
|
Name
|
|
Executive Contributions in Last FY
($) (1)
|
|
Registrant Contributions in Last FY
($) (2)
|
|
Aggregate Earnings in Last FY
($) (3)
|
|
Aggregate Withdrawals/Distributions
($)
|
|
Aggregate Balance at Last FYE
($) (4) |
|||||
(a)
|
|
(b)
|
|
(c)
|
|
(d)
|
|
(e)
|
|
(f)
|
|||||
Rodney J. Sailor
|
|
—
|
|
|
117,172
|
|
|
78,245
|
|
|
—
|
|
|
587,727
|
|
John P. Laws
|
|
—
|
|
|
49,528
|
|
|
26,570
|
|
|
—
|
|
|
187,322
|
|
Tina V. Faraca
|
|
31,887
|
|
|
4,642
|
|
|
8,652
|
|
|
—
|
|
|
72,162
|
|
Deanna J. Farmer
|
|
—
|
|
|
33,596
|
|
|
22,914
|
|
|
—
|
|
|
166,396
|
|
Mark C. Schroeder
|
|
—
|
|
|
33,451
|
|
|
28,313
|
|
|
—
|
|
|
180,887
|
|
(1)
|
The amounts disclosed in this column reflect named executive officer contributions to the plan during the fiscal year and are reported as compensation in the “Salary” column of the Summary Compensation Table.
|
(2)
|
The amounts disclosed in this column reflect registrant contributions to the plan during the fiscal year and are reported as compensation in the “Non-Qualified Matching Contributions” column of the All Other Compensation Table included in footnote 4 to the Summary Compensation Table.
|
(3)
|
Represents earnings on invested funds in each named executive officer’s individual account. Earnings are not above-market or preferential.
|
(4)
|
The amounts disclosed in this column include the aggregate balance at the end of the last completed fiscal year end of the named executive officer’s account and amounts that will be credited to the named executive officer’s account in February 2020 with respect to the last completed fiscal year. Of the amounts disclosed, the following amounts were reported as compensation to the named executive officer in the Summary Compensation Table for previous years: Mr. Sailor, $250,908; Mr. Laws, $89,783; Ms. Faraca, $0; Ms. Farmer, $77,623; and Mr. Schroeder, $77,454. Of the amounts disclosed, no amounts were reported as compensation to Ms. Faraca in the Summary Compensation Table for previous years because she was not a named executive officer in previous years.
|
•
|
for the President and Chief Executive Officer, a lump-sum cash payment of 2.99 times his annual base salary and short-term incentive plan award target;
|
•
|
for each Executive Vice President, a lump-sum cash payment of 2.0 times his or her annual base salary and short-term incentive plan award target; and
|
•
|
for any other officer who is not an Executive Vice President, a lump-sum cash payment of 1.5 times his or her annual base salary and short-term incentive plan award target.
|
Name
|
|
Cash Severance Payment Upon Change in Control & Covered Termination
($) (1)
|
|
Short-Term Incentive Plan Payment Upon Change in Control & Covered Termination
($) (2)
|
|
Health and Welfare Benefit Payment Upon Change in Control & Covered Termination
($) (3)
|
|
Outplacement Assistance Payment Upon Change in Control & Covered Termination
($) (4)
|
|
Acceleration of Vesting Under Long-Term Incentive Plans Upon Change in Control & Covered Termination
($) (5)
|
|
Total
($)
|
||||||
Rodney J. Sailor
|
|
4,418,496
|
|
|
719,235
|
|
|
27,783
|
|
|
25,000
|
|
|
4,989,725
|
|
|
10,180,239
|
|
John P. Laws
|
|
1,621,747
|
|
|
334,834
|
|
|
36,992
|
|
|
25,000
|
|
|
1,946,645
|
|
|
3,965,218
|
|
Tina V. Faraca
|
|
855,788
|
|
|
191,319
|
|
|
27,744
|
|
|
25,000
|
|
|
344,044
|
|
|
1,443,895
|
|
Deanna J. Farmer
|
|
1,296,688
|
|
|
255,734
|
|
|
18,584
|
|
|
25,000
|
|
|
1,134,489
|
|
|
2,730,495
|
|
Mark C. Schroeder
|
|
1,277,426
|
|
|
254,995
|
|
|
36,992
|
|
|
25,000
|
|
|
1,131,950
|
|
|
2,726,363
|
|
(1)
|
Reflects the lump-sum cash payment of the change of control benefit, plus any accrued salary and vacation. The change of control benefit for Mr. Sailor reflects 2.99 times his base salary and short-term incentive target. The change of control benefit for Mr. Laws, Ms. Farmer and Mr. Schroeder reflects 2.00 times their base salary and short-term incentive target. The change of control benefit for Ms. Faraca reflects 1.50 times her base salary and short-term incentive target.
|
(2)
|
Reflects the lump-sum cash payment of each named executive officer’s target short-term incentive bonus.
|
(3)
|
Reflects the lump-sum cash payment for health and welfare benefit coverage. The benefit for Mr. Sailor reflects the sum of the Employer’s portion of the annual premium for medical, dental and vision times 2.99. The benefit for Mr. Laws, Ms. Farmer and Mr. Schroeder reflects the sum of the Employer’s portion of the annual premium for medical, dental and vision times 2.00. The benefit for Ms. Faraca reflects the sum of the Employer’s portion of the annual premium for medical, dental and vision times 1.50.
|
(4)
|
Reflects the lump-sum cash payment for outplacement assistance.
|
(5)
|
Amounts above include the value of all unvested phantom unit awards and, if applicable, the value of any distribution equivalent rights. All performance unit awards will vest and be paid out as if the applicable performance goals had been satisfied at target levels or actual performance, whichever is greater. The amounts above include the value of all unvested performance unit awards, assuming target level payout and, if applicable, the value of any distribution equivalent rights.
|
Name
|
|
Cash Severance
($) (1)
|
|
Total
($)
|
||
Rodney J. Sailor
|
|
1,450,008
|
|
|
1,450,008
|
|
(1)
|
Reflects the cash payment of 1.0 times his annual base salary of $725,004 and his short-term incentive plan award target of $725,004 as of December 31, 2019.
|
Name
|
|
Fees Earned or Paid in Cash
($)
|
|
Stock Awards
($) (1)
|
|
Option Awards
($)
|
|
Non-Equity Incentive Plan Compensation ($)
|
|
All Other Compensation ($)
|
|
Total
($)
|
||||||
Alan N. Harris
|
|
97,500
|
|
|
98,115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
195,615
|
|
Ronnie K. Irani
|
|
85,000
|
|
|
98,115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
183,115
|
|
Peter H. Kind
|
|
100,000
|
|
|
98,115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
198,115
|
|
(1)
|
Reflects the aggregate grant date fair value of 2019 unit awards computed in accordance with FASB ASC Topic 718. Awards granted to independent directors vested immediately. See Note 19 to the financial statements for further information.
|
|
|
Common units
beneficially owned |
|
Series A Preferred Units
beneficially owned
|
||||||||
Name of beneficial owner
|
|
Number
|
|
Percentage
|
|
Number
|
|
Percentage
|
||||
CenterPoint Energy, Inc. (1)(5)
|
|
233,856,623
|
|
|
53.7
|
%
|
|
14,520,000
|
|
|
100
|
%
|
OGE Energy Corp. (2)(6)
|
|
110,982,805
|
|
|
25.5
|
%
|
|
—
|
|
|
—
|
|
Sean Trauschke (2)
|
|
17,500
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Stephen E. Merrill (2)
|
|
560
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Scott M. Prochazka (1)
|
|
17,500
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Xia Liu (1)
|
|
—
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Alan N. Harris (3)
|
|
94,296
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Ronnie K. Irani (3)
|
|
24,789
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Peter H. Kind (3)
|
|
40,620
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Rodney J. Sailor (3)
|
|
633,225
|
|
|
*
|
|
|
—
|
|
|
—
|
|
John P. Laws (3)
|
|
170,204
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Tina V. Faraca (4)
|
|
65,623
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Deanna J. Farmer (3)
|
|
153,202
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Mark C. Schroeder (4)
|
|
153,599
|
|
|
*
|
|
|
—
|
|
|
—
|
|
All directors and executive officers as a group (12 people)
|
|
1,371,118
|
|
|
*
|
|
|
—
|
|
|
—
|
|
*
|
Less than 1%
|
(1)
|
1111 Louisiana Street, Houston, Texas 77002
|
(2)
|
321 North Harvey, P.O. Box 321, Oklahoma City, OK 73101
|
(3)
|
499 West Sheridan Ave, Suite 1500, Oklahoma City, Oklahoma 73102
|
(4)
|
910 Louisiana Street, Houston, Texas 77002
|
(5)
|
Based on a Schedule 13D/A filed with the SEC pursuant to the Exchange Act on July 31, 2019. The common units reported represent the aggregated beneficial ownership by CenterPoint Energy, together with its wholly owned subsidiaries. CenterPoint Energy may be deemed to have sole voting power with respect to 233,856,623 common units. CenterPoint Energy has no shared voting or dispositive power with respect to any of the common units shown. CenterPoint Energy also holds 14,520,000 Series A Preferred Units.
|
(6)
|
Based on a Schedule 13G filed with the SEC pursuant to the Exchange Act on February 11, 2015. The common units reported represent the aggregated beneficial ownership by OGE Energy Corp., together with its wholly owned subsidiaries. OGE Energy Corp. may be deemed to have sole voting power with respect to 110,982,805 common units. OGE Energy Corp. has no shared voting or dispositive power with respect to any of the common units shown.
|
Plan Category
|
|
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights
|
|
Weighted-Average Price of Outstanding Options, Warrants and Rights
|
|
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan (Excluding Securities Reflected in Column(a))
|
|||
|
|
(a)
|
|
(b)
|
|
(c)
|
|||
Equity Compensation Plans Approved By Security Holders (1)
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
Equity Compensation Plans Not Approved By Security Holders (2)
|
|
—
|
|
|
—
|
|
|
6,353,205
|
|
(1)
|
Our Long-Term Incentive Plan was adopted by our general partner for the benefit of our officers, directors and employees. See Item 11. “Executive Compensation-Compensation Discussion and Analysis.” The plan provides for the issuance of a total of 13,100,000 common units under the plan.
|
•
|
Such party intends to cease using the midstream operations assets of the business within 12 months of the acquisition of such business; or
|
•
|
Such party acquires a business with midstream operations having a value in excess of $50 million (or $100 million in the aggregate with any of such party’s other midstream operations assets), and it offers to us the opportunity to acquire the midstream operations assets of such business.
|
|
2019
|
|
2018
|
||||
|
|
|
|
||||
|
(In thousands)
|
||||||
Audit fees
|
$
|
1,741
|
|
|
$
|
2,003
|
|
Audit-related fees
|
237
|
|
|
290
|
|
||
Tax
|
179
|
|
|
342
|
|
||
Total
|
$
|
2,157
|
|
|
$
|
2,635
|
|
Exhibit Number
|
|
Description
|
Report or Registration Statement
|
SEC File or Registration Number
|
Exhibit
Reference
|
|
Registrant’s registration statement on Form S-1, filed on November 26, 2013
|
File No. 333-192542
|
Exhibit 2.1
|
||
|
Registrant’s registration statement on Form S-1, filed on November 26, 2013
|
File No. 333-192542
|
Exhibit 3.1
|
|
Registrant’s Form 8-K filed April 9, 2018
|
File No. 001-36413
|
Exhibit 10.1
|
||
|
Registrant’s Form 10-Q filed May 1, 2019
|
File No. 001-36413
|
Exhibit 10.1
|
||
|
Registrant’s Form 10-K filed on February 17, 2016
|
File No. 001-36413
|
Exhibit 10.21
|
||
|
Registrant’s Form 10-K filed on February 17, 2016
|
File No. 001-36413
|
Exhibit 10.22
|
||
|
Registrant’s Form 10-K filed on February 17, 2016
|
File No. 001-36413
|
Exhibit 10.23
|
||
|
Registrant’s Form 10-K filed on February 17, 2016
|
File No. 001-36413
|
Exhibit 10.24
|
||
|
Registrant’s Form 10-K filed on February 17, 2016
|
File No. 001-36413
|
Exhibit 10.25
|
||
|
Registrant’s Form 10-Q filed May 4, 2016
|
File No. 001-36413
|
Exhibit 10.2
|
||
|
Registrant’s Form 8-K filed February 1, 2016
|
File No. 001-36413
|
Exhibit 10.1
|
||
|
Registrant’s Form 10-Q filed August 3, 2016
|
File No. 001-36413
|
Exhibit 10.1
|
||
|
Registrant’s Form 8-K filed May 12, 2017
|
File No. 001-36413
|
Exhibit 1.1
|
||
|
Registrant’s Form 10-Q filed August 1, 2017
|
File No. 001-36413
|
Exhibit 10.2
|
||
|
Registrant’s Form 10-K filed on February 19, 2019
|
File No. 001-36413
|
Exhibit 10.29
|
||
|
Registrant’s Form 10-K filed on February 19, 2019
|
File No. 001-36413
|
Exhibit 10.30
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
+101.INS
|
|
XBRL Instance Document
|
|
|
|
+101.SCH
|
|
XBRL Taxonomy Schema Document
|
|
|
|
+101.PRE
|
|
XBRL Taxonomy Presentation Linkbase Document
|
|
|
|
+101.LAB
|
|
XBRL Taxonomy Label Linkbase Document
|
|
|
|
+101.CAL
|
|
XBRL Taxonomy Label Linkbase Document
|
|
|
|
+101.DEF
|
|
XBRL Definition Linkbase Document
|
|
|
|
+104
|
|
Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document contained in Exhibit 101
|
|
|
|
|
|
ENABLE MIDSTREAM PARTNERS, LP
|
||
|
|
(Registrant)
|
||
|
|
|
||
|
|
By: ENABLE GP, LLC
|
||
|
|
Its general partner
|
||
|
|
|
|
|
Date:
|
February 19, 2020
|
By:
|
|
/s/ Tom Levescy
|
|
|
|
|
Tom Levescy
|
|
|
|
|
Senior Vice President, Chief Accounting Officer and Controller
|
|
|
|
|
(Principal Accounting Officer)
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Rodney J. Sailor
|
|
President and Chief Executive Officer and Director
(Principal Executive Officer)
|
|
February 19, 2020
|
Rodney J. Sailor
|
|
|
|
|
|
|
|
|
|
/s/ John P. Laws
|
|
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
|
|
February 19, 2020
|
John P. Laws
|
|
|
|
|
|
|
|
|
|
/s/ Tom Levescy
|
|
Senior Vice President, Chief Accounting Officer and Controller
(Principal Accounting Officer) |
|
February 19, 2020
|
Tom Levescy
|
|
|
|
|
|
|
|
|
|
/s/ Scott M. Prochazka
|
|
Chairman of the Board
|
|
February 19, 2020
|
Scott M. Prochazka
|
|
|
|
|
|
|
|
|
|
/s/ Xia Liu
|
|
Director
|
|
February 19, 2020
|
Xia Liu
|
|
|
|
|
|
|
|
|
|
/s/ Sean Trauschke
|
|
Director
|
|
February 19, 2020
|
Sean Trauschke
|
|
|
|
|
|
|
|
|
|
/s/ Stephen E. Merrill
|
|
Director
|
|
February 19, 2020
|
Stephen E. Merrill
|
|
|
|
|
|
|
|
|
|
/s/ Alan N. Harris
|
|
Director
|
|
February 19, 2020
|
Alan N. Harris
|
|
|
|
|
|
|
|
|
|
/s/ Ronnie K. Irani
|
|
Director
|
|
February 19, 2020
|
Ronnie K. Irani
|
|
|
|
|
|
|
|
|
|
/s/ Peter H. Kind
|
|
Director
|
|
February 19, 2020
|
Peter H. Kind
|
|
|
|
|
•
|
will become bound and will be deemed to have agreed to be bound by the terms and conditions of our partnership agreement;
|
•
|
represents that the transferee has the capacity, power and authority to enter into our partnership agreement; and
|
•
|
makes the consents, acknowledgements and waivers contained in our partnership agreement
|
•
|
arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);
|
•
|
brought in a derivative manner on our behalf;
|
•
|
asserting a claim of breach of a duty (including a fiduciary duty) owed by any director, officer, or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;
|
•
|
asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”); or
|
•
|
asserting a claim governed by the internal affairs doctrine
|
•
|
to remove or replace our general partner;
|
•
|
to approve some amendments to our partnership agreement; or
|
•
|
to take other action under our partnership agreement
|
•
|
enlarge the obligations of any limited partner without its consent, unless it is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or
|
•
|
enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.
|
•
|
a change in our name, the location of our principal office, our registered agent or our registered office;
|
•
|
the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
|
•
|
a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to
|
•
|
a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;
|
•
|
an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;
|
•
|
an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests;
|
•
|
any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
|
•
|
an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
|
•
|
any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;
|
•
|
conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
|
•
|
any other amendments substantially similar to any of the matters described in the clauses above.
|
•
|
do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;
|
•
|
are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
|
•
|
are necessary or appropriate to facilitate the trading of limited partner interests (including the division of any class or classes of outstanding units into different classes to facilitate uniformity of tax consequence within such class of units) or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;
|
•
|
are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
|
•
|
are required to effect the intent expressed in the prospectus relating to our initial public offering or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
|
•
|
the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
|
•
|
there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
|
•
|
the entry of a decree of judicial dissolution of our partnership; or
|
•
|
the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor.
|
•
|
the action would not result in the loss of limited liability of any limited partner; and
|
•
|
neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for U.S. federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).
|
•
|
the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
|
•
|
the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.
|
•
|
a current list of the name and last known address of each record holder;
|
•
|
copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and
|
•
|
certain information regarding the status of our business and financial condition.
|
•
|
less, the amount of cash reserves established by our general partner to:
|
•
|
provide for the proper conduct of our business (including cash reserves for our future capital expenditures, future acquisitions, and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
|
•
|
comply with applicable law, any of our debt instruments or other agreements;
|
•
|
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units for the current quarter); or
|
•
|
provide funds for distributions on our preferred units;
|
•
|
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
|
•
|
$300 million; plus
|
•
|
all of our cash receipts after the closing of our initial public offering, excluding cash from interim capital transactions (as defined below) and the termination of hedge contracts, provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus
|
•
|
working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus
|
•
|
cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in our initial public offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus
|
•
|
cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in our initial public offering, to pay interest and related fees on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to in the prior bullet; less
|
•
|
all of our operating expenditures (as defined below) after April 16, 2014, the closing of our initial public offering; less
|
•
|
the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less
|
•
|
all working capital borrowings not repaid within 12 months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less
|
•
|
any cash loss realized on disposition of an investment capital expenditure.
|
•
|
repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);
|
•
|
payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;
|
•
|
expansion capital expenditures;
|
•
|
investment capital expenditures;
|
•
|
payment of transaction expenses (including taxes) relating to interim capital transactions;
|
•
|
distributions to our partners;
|
•
|
repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or
|
•
|
any expenditures made to fund certain demand fees using a portion of the proceeds of our initial public offering.
|
•
|
borrowings other than working capital borrowings;
|
•
|
sales of our equity and debt securities;
|
•
|
sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and
|
•
|
capital contributions received.
|
•
|
first, to all unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
|
•
|
thereafter, in the manner described in “—Incentive Distribution Rights” below.
|
•
|
we have distributed available cash from operating surplus to the holders of our preferred units to the extent of the distribution preference on the preferred units; and
|
•
|
we have distributed available cash from operating surplus to the common unitholders in an amount equal to the minimum quarterly distribution.
|
•
|
first, to all unitholders, pro rata, until each unitholder receives a total of $0.330625 per unit for that quarter (the first target distribution);
|
•
|
second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.359375 per unit for that quarter (the second target distribution);
|
•
|
third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.431250 per unit for that quarter (the third target distribution); and
|
•
|
thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
|
|
Total Quarterly Distribution Per Unit Target Amount
|
Marginal Percentage Interest in Distributions
|
|||||
|
Common Unitholders
|
General Partner
|
|||||
Minimum Quarterly Distribution
|
|
$0.287500
|
|
100.0
|
%
|
0.0
|
%
|
First Target Distribution
|
up to $0.330625
|
|
100.0
|
%
|
0.0
|
%
|
|
Second Target Distribution
|
above $0.330625
up to $0.359375
|
|
85.0
|
%
|
15.0
|
%
|
|
Third Target Distribution
|
above $0.359375
up to $0.431250
|
|
75.0
|
%
|
25.0
|
%
|
|
Thereafter
|
above $0.431250
|
|
50.0
|
%
|
50.0
|
%
|
•
|
first, to all unitholders, pro rata, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;
|
•
|
second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;
|
•
|
third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and
|
•
|
thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
|
•
|
first, to all unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below under “—Effect of a Distribution from Capital Surplus”; and
|
•
|
thereafter, as if such distributions were from operating surplus.
|
•
|
the minimum quarterly distribution;
|
•
|
target distribution levels; and
|
•
|
the unrecovered initial unit price.
|
•
|
first, to our general partner to the extent of any negative balance in its capital account;
|
•
|
second, to the preferred unitholders, until the capital account balance of such holders equals the stated liquidation preference with respect to such holders’ preferred units;
|
•
|
third, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
|
•
|
fourth, to all common unitholders, pro rata, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the common unitholders, pro rata, for each quarter of our existence;
|
•
|
fifth, 85.0% to all common unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the common unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;
|
•
|
sixth, 75.0% to all common unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the common unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence; and
|
•
|
thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to our general partner.
|
•
|
first, to the holders of common units in proportion to the positive balances in their capital accounts until the capital accounts of the common unitholders have been reduced to zero;
|
•
|
second, to the holders of preferred units in proportion to the positive balances in their capital accounts until the capital accounts of the holders of the preferred units have been reduced to zero; and
|
•
|
thereafter, 100.0% to our general partner.
|
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
|
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/ Rodney J. Sailor
|
|
Rodney J. Sailor
|
|
President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
|
|
(Principal Executive Officer)
|
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
|
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/ John P. Laws
|
|
John P. Laws
|
|
Executive Vice President, Chief Financial Officer and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
|
|
(Principal Financial Officer)
|
|
|
|
/s/ Rodney J. Sailor
|
|
Rodney J. Sailor
|
|
President and Chief Executive Officer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
|
|
(Principal Executive Officer)
|
|
|
|
/s/ John P. Laws
|
|
John P. Laws
|
|
Executive Vice President, Chief Financial Officer and Treasurer, Enable GP, LLC, the General Partner of Enable Midstream Partners, LP
|
|
(Principal Financial Officer)
|