Delaware
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16-1616605
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(State of organization)
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(I.R.S. Employer Identification No.)
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1722 Routh St., Suite 1300
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Dallas, Texas
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75201
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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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Name of Exchange on which Registered
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None.
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None.
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Large accelerated filer
x
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Accelerated filer
¨
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Non-accelerated filer
¨
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Smaller reporting company
¨
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Emerging growth company
¨
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Item
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Description
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Page
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PART I
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1.
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1A.
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1B.
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2.
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3.
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4.
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PART II
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5.
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6.
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7.
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7A.
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8.
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9.
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9A.
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9B.
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PART III
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10.
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11.
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12.
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13.
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14.
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PART IV
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15.
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Defined Term
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Definition
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/d
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Per day.
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2017 EDA
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Equity Distribution Agreement entered into by ENLK in August 2017 with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc., and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program.
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Acacia
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Acacia Natural Gas Corp. I, Inc.
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AMZ
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Alerian MLP Index for Master Limited Partnerships.
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ASC
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The FASB Accounting Standards Codification.
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ASC 606
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ASC 606,
Revenue from Contracts with Customers.
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ASC 842
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ASC 842,
Leases.
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Ascension JV
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Ascension Pipeline Company, LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Marathon Petroleum Corporation in which ENLK owns a 50% interest and Marathon Petroleum Corporation owns a 50% interest. The Ascension JV, which began operations in April 2017, owns an NGL pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
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ASU
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The FASB Accounting Standards Update.
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Avenger
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Avenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.
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Bbls
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Barrels.
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Bcf
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Billion cubic feet.
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Black Coyote
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Black Coyote crude oil gathering system, a crude oil gathering system in the STACK.
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BLM
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Bureau of Land Management.
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Cedar Cove JV
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Cedar Cove Midstream LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Kinder Morgan, Inc. in which ENLK owns a 30% interest and Kinder Morgan, Inc. owns a 70% interest. The Cedar Cove JV, which was formed in November 2016, owns gathering and compression assets in Blaine County, Oklahoma, located in the STACK play.
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CFTC
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U.S. Commodity Futures Trading Commission.
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CNOW
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Central Northern Oklahoma Woodford Shale.
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CO
2
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Carbon dioxide.
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Consolidated Credit Facility
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A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility was available upon closing of the Merger, and is guaranteed by ENLK.
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CPI
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Consumer Price Index.
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Delaware Basin JV
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Delaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities located in the Delaware Basin in Texas.
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Devon
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Devon Energy Corporation.
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ECP System
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EnLink Crude Purchasing System. The ECP System includes assets that were acquired through the acquisition of LPC Crude Oil Marketing LLC in January 2015.
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EMI
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EnLink Midstream, Inc.
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Enfield
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Enfield Holdings, L.P.
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ENLC
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EnLink Midstream, LLC.
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ENLC Class C common Units
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A class of non-economic ENLC common units issued to Enfield immediately prior to the Merger equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC.
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ENLK
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EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
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ENLK Credit Facility
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A $1.5 billion unsecured revolving credit facility entered into by ENLK that would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
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EOGP
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EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. As of January 31, 2019, EOGP is wholly-owned by the Operating Partnership.
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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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GAAP
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Generally accepted accounting principles in the United States of America.
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Gal
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Gallons.
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GCF
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Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
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GHG
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Greenhouse gas.
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GIP
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Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.
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GIP Transaction
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On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP.
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Goldman Sachs
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Goldman Sachs Group, Inc.
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Greater Chickadee
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Crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin.
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Gross Operating Margin
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Revenue less cost of sales. Gross Operating Margin is a non-GAAP financial measure. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for other information.
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HEP
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Howard Energy Partners, LP. ENLK sold its 31% ownership interest in HEP in March 2017.
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ISDAs
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International Swaps and Derivatives Association Agreements.
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Mcf
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Thousand cubic feet.
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MEGA system
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Midland Energy Gathering Area system in Midland, Martin, and Glasscock counties, Texas.
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Merger
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On January 25, 2019, NOLA Merger Sub merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
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Merger Agreement
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The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, the general partner of ENLK, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger.
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Midstream Holdings
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EnLink Midstream Holdings, LP.
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MMbbls
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One million barrels.
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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.
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MVC
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Minimum volume commitment.
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NGL
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Natural gas liquid.
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NGP
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NGP Natural Resources XI, LP.
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NOLA Merger Sub
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NOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.
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NTPL
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North Texas Pipeline, a pipeline in North Texas that the Operating Partnership sold in December 2016.
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NYSE
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New York Stock Exchange.
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Operating Partnership
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EnLink Midstream Operating, LP, a Delaware limited partnership and wholly-owned subsidiary of ENLK.
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ORV
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ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
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OTC
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Over-the-counter.
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Permian Basin
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A large sedimentary basin that includes the Midland and Delaware Basins primarily in West Texas and New Mexico.
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POL contracts
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Percentage-of-liquids contracts.
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POP contracts
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Percentage-of-proceeds contracts.
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Redbud
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Redbud crude oil gathering system, a crude oil gathering system in the STACK.
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Series B Preferred Units
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ENLK’s Series B Cumulative Convertible Preferred Units.
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Series C Preferred Units
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ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
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STACK
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Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
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Term Loan
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An $850.0 million term loan entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guarantees.
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Thunderbird Plant
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A gas processing plant in Central Oklahoma.
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TPG
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TPG Global, LLC.
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VEX
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ENLK’s Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas.
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•
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GIP, through GIP III Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the
managing member of ENLC
, which, as of the closing date, amounted to
100%
of the outstanding limited liability company interests in the
managing member of ENLC and approximately
23.1%
of the outstanding limited partner interests in ENLK;
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•
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GIP, through GIP III Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which, as of the closing date, amounted to approximately
63.8%
of the outstanding limited liability company interests in ENLC; and
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•
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Through this transaction, GIP acquired control of
(i) the managing member of ENLC,
(ii) ENLC, and (iii) ENLK, as a result of ENLC’s ownership of
ENLK’s general partner.
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(1)
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The general partner (“GP”) ownership percentage for ENLK accounts for general partner units, while the limited partner (“LP”) ownership percentages for ENLK account for ENLK common units and Series B Preferred Units.
Subsequent to the closing of the Merger, Series B Preferred Units are exchangeable into ENLC common units on a 1-for-1.15 basis, subject to certain adjustments.
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(2)
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Series C Preferred Units are perpetual preferred units that are not convertible into other equity interests, and therefore, are not factored into the ENLK ownership calculations for the limited partner and general partner ownership percentages presented.
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(1)
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Subsequent to the closing of the Merger, Series B Preferred Units are exchangeable into ENLC common units on a 1-for-1.15 basis, subject to certain adjustments.
Upon the exchange of any Series B Preferred Units into ENLC common units, an equal number of the ENLC Class C Common Units will be canceled. As of February 1, 2019, the outstanding ENLC Class C Common Units represent a 10.8% membership interest in ENLC.
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(2)
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All ENLK common units are held by ENLC. The Series B Preferred Units are entitled to vote, on a one-for-one basis (subject to certain adjustments) as a single class with ENLC, on all matters that require approval of the ENLK unitholders.
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(3)
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Series C Preferred Units are perpetual preferred units that are not convertible into other equity interests, and therefore, are not factored into the ENLK ownership calculations for the limited partner and general partner ownership percentages presented.
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•
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gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
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•
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fractionating, transporting, storing, and selling NGLs; and
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•
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gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.
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•
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Texas Segment
. The Texas segment includes our natural gas gathering, processing, and transmission operations in North Texas and the Permian Basin;
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•
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Oklahoma Segment
. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities in the Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK, and CNOW shale areas;
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•
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Louisiana Segment
. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana;
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•
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Crude and Condensate Segment
. The Crude and Condensate segment includes ORV, our crude oil operations in the Permian Basin and Central Oklahoma, and our crude oil activities associated with VEX; and
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•
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Corporate Segment
. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, and our general corporate property
and expenses.
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•
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Execute in our core growth areas.
We believe our assets are positioned in some of the most economically advantageous basins in the U.S., as well as key demand centers with growing end-use customers.
We expect to grow certain of our systems organically over time by meeting our customers’ midstream service needs that result from their
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•
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Maintain a strong financial position.
We believe that maintaining a conservative and balanced capital structure, appropriate leverage, and other key financial metrics will afford us better access to the capital markets at a competitive cost of capital. We also believe a strong financial position provides us the opportunity to grow our business in a prudent manner throughout the cycles in our industry.
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•
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Maintain stable cash flows supported by long-term, fee-based contracts.
We will seek to generate cash flows pursuant to long-term, firm contracts with creditworthy customers. We will continue to pursue opportunities to increase the fee-based components of our contract portfolio to minimize our direct commodity price exposure.
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•
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Strategically-located assets
. The majority of our assets are strategically located in economically advantageous regions with the potential for increasing throughput volume and cash flow generation. Our asset portfolio includes gathering, transmission, fractionation, and processing systems that are located in the areas in which producer activity is focused on crude oil, condensate, and NGLs, as well as natural gas. We have established platforms in Texas, Oklahoma, and Louisiana, and we are focused on growing our operations in Central Oklahoma, the Permian Basin, and southern Louisiana through organic development and acquisitions.
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•
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Stable cash flows
. Approximately
88.3%
of our gross operating margin for the year ended
December 31, 2018
was generated from fee-based contract arrangements with minimal direct commodity price exposure. In addition, our cash flows are generated across a variety of products, services, and geographic locations and through transactions with a strong portfolio of customers with investment-grade credit ratings. We have approximately 10 years remaining on fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which we provide gathering, treating, compression, dehydration, stabilization, processing, and fractionation services, as applicable, for natural gas delivered by Devon to our gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide us with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas, and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Additionally, our EOGP assets are supported by Devon with acreage dedications and MVCs for gathering and processing on Devon’s STACK acreage through the end of 2020. We will continue to focus on contract structures that reduce volatility and support long-term stability of cash flows.
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•
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Integrated midstream services
. We span the energy value chain by providing natural gas, NGL, crude oil, and condensate services across a diverse customer base. These services include gathering, compressing, treating, processing, transporting, storing, and selling natural gas, fractionating, transporting, storing, and selling NGLs, and gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate. We believe our ability to provide all of these services gives us an advantage in competing for new opportunities because we can provide substantially all services that producers, marketers, and others require to move natural gas, NGLs, crude oil, and condensate from the wellhead to the market on a cost-effective basis.
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•
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Experienced management team
. Our management team has deep experience in the energy industry and has a proven track record of creating value through the development, acquisition, optimization, and integration of midstream assets. We believe this team provides us with a strong foundation for evaluating growth opportunities and operating our assets in a safe, reliable, and efficient manner.
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Year Ended
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December 31, 2018
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Gathering and Transmission Pipelines
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Approximate Length (Miles)
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Compression (HP) (1)
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Estimated Capacity (2)
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Average Throughput (3)
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Gas Pipelines
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Texas assets:
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Bridgeport rich and lean gathering systems
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2,800
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186,300
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861
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775,000
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Johnson County gathering system
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390
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53,800
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589
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120,200
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Silver Creek gathering system
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600
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69,000
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522
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303,300
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Acacia transmission system
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130
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16,000
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920
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534,600
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North Texas assets
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3,920
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325,100
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2,892
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1,733,100
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MEGA System gathering facilities
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730
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115,400
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413
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330,400
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Lobo gathering system (4)
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155
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30,200
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155
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192,300
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Permian Basin gas assets (4)
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885
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145,600
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568
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522,700
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Texas assets
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4,805
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470,700
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3,460
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2,255,800
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Oklahoma assets:
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Central Oklahoma gathering system
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1,755
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258,700
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1,137
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1,168,300
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Northridge gathering system
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140
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14,000
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65
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36,400
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Oklahoma assets
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1,895
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272,700
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1,202
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1,204,700
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Louisiana assets:
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Louisiana gas gathering and transmission system
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3,220
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97,400
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3,975
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2,196,200
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Total Gas Pipelines
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9,920
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840,800
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8,637
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5,656,700
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NGL, Crude Oil and Condensate Pipelines
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Louisiana assets:
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Cajun-Sibon NGL pipeline system
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760
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—
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130,000
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139,800
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Ascension NGL pipeline (5)
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35
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—
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50,000
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21,700
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Louisiana assets
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795
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—
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180,000
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161,500
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||||
Crude and condensate assets:
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Central Oklahoma crude oil gathering systems
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85
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—
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160,000
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10,100
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Ohio River Valley (6)
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210
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|
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—
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25,650
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18,600
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Victoria Express Pipeline
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60
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|
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—
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90,000
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|
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14,600
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Permian Basin gathering (7)
|
|
390
|
|
|
—
|
|
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136,500
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115,300
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Total NGL, Crude Oil and Condensate Pipelines
|
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1,540
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—
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592,150
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320,100
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(1)
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Includes power generation units.
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(2)
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Estimated capacity for gas pipelines is MMcf/d. A volume capacity of 100 MMcf/d correlates to an approximate energy content of 100,000 MMBtu/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.
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(3)
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Average throughput for gas pipelines is MMBtu/d. Average throughput for NGL, crude, and condensate pipelines is Bbls/d.
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(4)
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Includes gross mileage, compression, capacity, and throughput for the Delaware Basin JV, which is owned 50.1% by us. Estimated capacity on our Lobo gathering system includes only the Delaware Basin JV’s compression capacity and does not include gas compressed by third parties on our system.
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(5)
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Includes gross mileage, capacity, and throughput for the Ascension JV, which is owned 50% by us.
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(6)
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Estimated capacity is comprised of trucking capacity only.
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(7)
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Estimated capacity is comprised of 86,500 Bbls/d of pipeline capacity and 50,000 Bbls/d of trucking capacity. Our Permian Basin gathering crude and condensate assets include the ECP system, Greater Chickadee system, and Avenger system.
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Year Ended
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December 31, 2018
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||
Processing Facilities
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Processing Capacity (MMcf/d)
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Average Throughput (MMBtu/d)
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||
Texas assets:
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Bridgeport processing facility
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800
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576,300
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Silver Creek processing system
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280
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171,100
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North Texas assets
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1,080
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747,400
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MEGA system processing facilities
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408
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344,800
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Lobo processing facilities
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275
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186,900
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Permian Basin assets
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683
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531,700
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Texas assets
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1,763
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1,279,100
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|
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Oklahoma Assets:
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Central Oklahoma processing facilities
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1,045
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1,102,000
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Northridge processing facility
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200
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93,300
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Oklahoma assets
|
|
1,245
|
|
|
1,195,300
|
|
|
|
|
|
|
||
Louisiana assets:
|
|
|
|
|
||
Louisiana gas processing facilities
|
|
1,903
|
|
|
431,200
|
|
Total Processing Facilities
|
|
4,911
|
|
|
2,905,600
|
|
|
|
|
|
Year Ended
|
||
|
|
|
|
December 31, 2018
|
||
Fractionation Facilities
|
|
Estimated NGL Fractionation Capacity (Bbls/d)
|
|
Average Throughput (Bbls/d)
|
||
Louisiana assets:
|
|
|
|
|
||
Plaquemine fractionation facility (1)
|
|
117,000
|
|
|
70,100
|
|
Plaquemine processing plant
|
|
11,000
|
|
|
5,000
|
|
Eunice fractionation facility
|
|
65,000
|
|
|
50,800
|
|
Riverside fractionation facility (1)
|
|
—
|
|
|
30,900
|
|
Louisiana assets
|
|
193,000
|
|
|
156,800
|
|
|
|
|
|
|
||
Texas assets:
|
|
|
|
|
||
Bridgeport processing facility (2)
|
|
15,000
|
|
|
—
|
|
Mesquite terminal (2)
|
|
15,000
|
|
|
—
|
|
Texas assets
|
|
30,000
|
|
|
—
|
|
|
|
|
|
|
||
Gulf Coast Fractionators (3)
|
|
56,000
|
|
|
45,100
|
|
Total Fractionation Facilities
|
|
279,000
|
|
|
201,900
|
|
(1)
|
The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to the Riverside fractionation facility for further processing. The Plaquemine fractionation facility and the Riverside fractionation facility have an aggregate fractionation capacity of 117 MBbls/d.
|
(2)
|
We have two fractionation facilities with capacity of 15 MBbls/d each. Our Mesquite terminal in the Permian Basin and our Bridgeport processing plant in North Texas provide operational flexibility for the related processing plants but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under our current contracts, we do not earn fractionation fees for operating these facilities, so throughput volumes through these facilities are not captured on a routine basis and are not significant to our gross operating margins.
|
(3)
|
Volumes shown reflect our 38.75% ownership in Gulf Coast Fractionators.
|
Storage Assets
|
|
Estimated Storage Capacity (1)
|
|
Gas storage:
|
|
|
|
Belle Rose gas storage facility
|
|
11.9
|
|
Sorrento gas storage facility
|
|
7.3
|
|
Total gas storage
|
|
19.2
|
|
|
|
|
|
NGL storage:
|
|
|
|
Napoleonville NGL storage facility
|
|
5.0
|
|
|
|
|
|
Crude oil storage:
|
|
|
|
ORV storage
|
|
0.5
|
|
Permian storage
|
|
0.1
|
|
Central Oklahoma storage
|
|
0.2
|
|
VEX storage
|
|
0.2
|
|
Total crude oil storage
|
|
1.0
|
|
(1)
|
Estimated capacity for gas storage is Bcf and includes linefill capacity necessary to operate storage facilities. Estimated capacity for NGL and crude oil storage is MMbbls.
|
•
|
Acacia Transmission System.
The Acacia transmission system is a pipeline that connects production from the Barnett Shale to markets in North Texas accessed by Atmos Energy, Brazos Electric, Enbridge Energy Partners, Energy Transfer Partners, Enterprise Product Partners, and GDF Suez. Devon is the largest customer on the Acacia pipeline with approximately five years remaining on a fixed-fee transportation agreement that covers transmission services and includes annual rate escalators.
|
•
|
Processing and Fractionation Facilities.
Our processing facilities in Texas include 11 gas processing plants and consist of the following:
|
•
|
North Texas Assets.
Our North Texas processing systems include the following:
|
•
|
Bridgeport processing facility
. Our Bridgeport natural gas processing facility, located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas, is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants. Devon is the Bridgeport facility’s largest customer, providing substantially all of the natural gas processed for the year ended December 31, 2018. We have extended our fixed-fee processing agreement with Devon, which was effective after the GIP Transaction, and currently have approximately 10 years remaining on our agreement with Devon pursuant to which we provide processing services for natural gas delivered by Devon to the Bridgeport processing facility.
|
•
|
Silver Creek processing system
. Our Silver Creek processing system, located in Weatherford, Azle, and Fort Worth, Texas, includes three processing plants: the Azle plant, the Silver Creek plant, and the Goforth plant, which account for 50 MMcf/d, 200 MMcf/d, and 30 MMcf/d of processing capacity, respectively. During 2018, we idled the Azle and GoForth plants due to decreased volumes. Currently, the processing capacity at the Silver Creek plant is sufficient to process all gas on the Silver Creek processing system.
|
•
|
Permian Basin Assets
. Our Permian Basin processing facilities consist of the following:
|
•
|
MEGA system processing facilities.
Our MEGA system natural gas processing facilities are located in Midland, Martin, and Glasscock counties, Texas and operate as a connected system. These assets consist of the Bearkat processing facility with a capacity of 75 MMcf/d, the Deadwood processing
|
•
|
Lobo processing facilities
. Our Lobo natural gas processing facilities are located in Loving County, Texas and include three processing plants, Lobo I, Lobo II, and Lobo III, which account for 35 MMcf/d, 140 MMcf/d, and 100 MMcf/d of processing capacity, respectively. The Lobo processing facilities and the connected gathering system are owned by the Delaware Basin JV.
|
•
|
Gathering Systems.
Our gathering systems in Texas are connected to our North Texas or Permian Basin processing assets.
|
•
|
North Texas Assets.
Our North Texas gathering systems include the following:
|
•
|
Bridgeport rich gas gathering system.
A substantial majority of the natural gas gathered on the Bridgeport rich gas gathering system is delivered to the Bridgeport processing facility. Devon is the largest customer on the Bridgeport rich gas gathering system contributing substantially all of the natural gas gathered for the year ended December 31, 2018. As described above, we have extended our fixed-fee gathering agreement with Devon, which was effective after the GIP Transaction, and currently have approximately 10 years remaining on a fixed-fee gathering agreement with Devon pursuant to which we provide gathering services on the Bridgeport system.
|
•
|
Bridgeport lean gas gathering system.
Natural gas gathered on the Bridgeport lean gas gathering system is primarily attributable to Devon and is delivered to the Acacia transmission system and to intrastate pipelines without processing. As described above, we are party to a fixed-fee gathering and processing agreement with Devon that covers gathering services on the Bridgeport system.
|
•
|
Johnson County gathering system
. Natural gas gathered on this system is primarily attributable to one customer with whom we have a fixed-fee processing agreement that currently has approximately five years remaining.
|
•
|
Silver Creek gathering system
. Our Silver Creek gathering system is located primarily in Hood, Parker, and Johnson counties, Texas, and connects to the Silver Creek processing system.
|
•
|
Permian Basin assets
. Our Permian Basin gathering systems include the following:
|
•
|
MEGA system gathering facilities
. This gathering system in the Permian Basin serves as an interconnected system of pipelines and compressors to deliver gas from wellheads in the Permian Basin to the MEGA system processing facilities.
|
•
|
Lobo gathering system.
This rich natural gas gathering system consists of gathering pipeline and compression assets in the Delaware Basin in Texas and New Mexico. The Lobo gathering system is owned by the Delaware Basin JV.
|
•
|
Oklahoma processing system.
Our processing facilities include the following:
|
•
|
Central Oklahoma processing facilities.
The Central Oklahoma plants include the Chisholm plants, the Battle Ridge plant, and the Cana processing facilities (collectively, the “Central Oklahoma processing system”), which account for 560 MMcf/d, 85 MMcf/d, and 400 MMcf/d of processing capacity, respectively. The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners, LP and an affiliate of ONEOK, Inc. (“ONEOK”). The unprocessed NGLs from the Chisholm facilities are transported by ONEOK to NGL transmission lines, which then transport the NGLs to our fractionators in Louisiana. Devon is the primary customer of the Cana processing facilities. We have extended our fixed-fee processing agreement with Devon, which was effective after the GIP Transaction, and currently have approximately 10 years remaining on a fixed-fee gathering and processing agreement with us pursuant to which we provide processing services for natural gas delivered by Devon to the Cana processing facility. Additionally, we have
|
•
|
Northridge processing facility.
Our Northridge processing plant is located in Hughes County in the Arkoma-Woodford Shale in Southeastern Oklahoma. The residue natural gas from the Northridge processing facility is delivered to CenterPoint Energy, Inc., Enable Midstream Partners, LP, and MPLX LP.
|
•
|
Oklahoma gathering system.
Our Oklahoma gathering systems include the following:
|
•
|
Central Oklahoma gathering system.
The Central Oklahoma gathering system serves the STACK and CNOW plays. In addition, our contractual arrangement with Devon includes an MVC that will remain in effect until December 2020. For 2019, the MVC dictates that approximately 185 MMcf/d of natural gas will be delivered through the Chisholm gathering system. The MVC escalates quarterly, resulting in approximately 230 MMcf/d to be delivered in 2020.
|
•
|
Northridge gathering system.
Our Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma.
|
•
|
Louisiana Gas Pipeline and Processing Systems.
The Louisiana gas pipeline system includes gathering and transmission systems, processing facilities, and underground gas storage.
|
•
|
Gas Transmission and Gathering Systems
. Our transmission system consists of a portfolio of large capacity interconnections with the Gulf Coast pipeline grid that provides customers with supply access to multiple domestic production basins for redelivery to major industrial market consumption located primarily in the Mississippi River Corridor between Baton Rouge, Louisiana and New Orleans, Louisiana. Our natural gas transmission services are supplemented by fully integrated, high deliverability salt dome storage capacity strategically located in the natural gas consumption corridor. In combination with our transmission system, our gathering systems provide a fully integrated wellhead to burner tip value chain that includes local gathering, processing, and treating services to Louisiana producers.
|
•
|
Gas Processing and Storage Facilities
. Our processing facilities in Louisiana include six gas processing plants, of which three are currently operational.
|
•
|
Plaquemine Processing Plant
. The Plaquemine processing plant has 225 MMcf/d of processing capacity and is connected to the Plaquemine fractionation facility.
|
•
|
Gibson Processing Plant.
The Gibson processing plant has 110 MMcf/d of processing capacity and is located in Gibson, Louisiana. The Gibson processing plant is connected to our Louisiana gathering system.
|
•
|
Pelican Processing Plant
. The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. The Pelican processing plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline. This plant has an interconnection with the Louisiana gas pipeline system allowing us to process natural gas from this system at our Pelican processing plant when markets are favorable.
|
•
|
Blue Water Gas Processing Plant
. We operate and own a 64.29% interest in the Blue Water gas processing plant. The Blue Water gas processing plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. Our share of the plant’s capacity is approximately 193 MMcf/d. The plant is not expected to operate in the near future unless fractionation spreads are favorable, and volumes are sufficient to run the plant.
|
•
|
Eunice Processing Plant
. The Eunice processing plant is located in south central Louisiana and has a capacity of 475 MMcf/d of natural gas. In August 2013, we shut down the Eunice processing plant. The plant is not expected to operate in the near future unless fractionation spreads are favorable, and volumes are sufficient to run the plant.
|
•
|
Sabine Pass Processing Plant.
The Sabine Pass processing plant is located east of the Sabine River in Johnson's Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. In 2013, we shut down the Sabine Pass processing plant and do not anticipate reopening the plant based on current market conditions.
|
•
|
Belle Rose Gas Storage Facility
. The Belle Rose storage facility is located in Assumption Parish, Louisiana. This facility was placed in service in May 2016 and is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.
|
•
|
Sorrento Gas Storage Facility
. The Sorrento gas storage facility is located in Assumption Parish, Louisiana. This facility is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.
|
•
|
Louisiana Liquids Pipeline System.
Our Louisiana liquids pipeline system includes NGL transport lines, fractionation assets, and underground NGL storage.
|
•
|
Cajun-Sibon Pipeline System
. The Cajun-Sibon pipeline system transports unfractionated NGLs from areas such as the Liberty, Texas interconnects near Mont Belvieu, Texas, and, from time to time, our Gibson and Pelican processing plants in South Louisiana to either the Plaquemine or Eunice fractionators or to third-party fractionators when necessary
.
|
•
|
Ascension Pipeline.
The Ascension JV is an NGL pipeline that connects our Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery and is owned 50% by Marathon Petroleum Corporation.
|
•
|
Fractionation Facilities.
There are four fractionation facilities located in Louisiana that are connected to our processing facilities and to Mont Belvieu, Texas and other hubs through our Cajun-Sibon pipeline system.
|
•
|
Plaquemine Fractionation Facility
. The Plaquemine fractionator is located at our Plaquemine gas processing plant complex and is connected to our Cajun-Sibon pipeline. The Plaquemine fractionation facility produces purity ethane and propane for sale to markets via pipeline, while butane and heavier products are sent to our Riverside facility for further processing. The Plaquemine fractionator, collectively with the Riverside Fractionation Facility, has an approximate capacity of 117,000 Bbls/d of raw-make NGL products.
|
•
|
Plaquemine Gas Processing Plant.
In addition to the Plaquemine fractionation facility, the adjacent Plaquemine gas processing plant also has an on-site fractionator.
|
•
|
Eunice Fractionation Facility
. The Eunice fractionation facility is located in south central Louisiana. Liquids are delivered to the Eunice fractionation facility by the Cajun-Sibon pipeline system. The Eunice fractionation facility fractionates butane and heavier products from our Riverside facility and is directly connected to NGL markets and to a third-party storage facility.
|
•
|
Riverside Fractionation Facility
. The Riverside fractionator and loading facility are located on the Mississippi River upriver from Geismar, Louisiana. Liquids are delivered to the Riverside fractionator by pipeline from the Eunice and Pelican processing plants or by third-party truck and rail assets. The loading/unloading facility has the capacity to transload 15,000 Bbls/d of crude oil and condensate from rail cars to barges.
|
•
|
Napoleonville Storage Facility.
The Napoleonville NGL storage facility is connected to the Riverside facility and is comprised of two existing caverns. The caverns are currently operated in butane service, and space is leased to customers for a fee.
|
•
|
Ohio River Valley
. Our ORV operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot crude oil and condensate rail loading terminal on the Ohio Central Railroad network, crude oil and condensate pipelines in Ohio and West Virginia, above ground crude oil storage, a trucking fleet comprised of both semi and straight trucks, trailers for hauling NGL volumes, and seven existing brine disposal wells. Additionally, our ORV operations include eight condensate stabilization and natural gas compression stations that are supported by long-term, fee-based contracts with multiple producers.
|
•
|
Permian Crude and Condensate.
Our Permian Crude and Condensate assets
have crude oil gathering, transportation, and marketing operations in the Permian Basin. These assets include:
|
•
|
ECP System.
The ECP System includes trucking and crude gathering pipelines that were acquired in 2015.
|
•
|
Avenger Crude Oil Gathering System.
During 2018, we constructed a new crude oil gathering system in the northern Delaware Basin called Avenger. Avenger is supported by a long-term contract with Devon on dedicated acreage in their Todd and Potato Basin development areas in Eddy and Lea counties in New Mexico. We commenced initial operations on Avenger during the third quarter of 2018 and expect to begin full-service operations during the third quarter of 2019.
|
•
|
Greater Chickadee Gathering system.
Greater Chickadee was placed into service in March 2017 and delivers crude oil for customers to Enterprise Product Partners L.P.’s crude oil terminal in West Texas. Greater Chickadee also includes multiple central tank batteries with pump, truck injection, and storage stations to maximize shipping and delivery options for producers.
|
•
|
Central Oklahoma Crude Oil Gathering Systems.
Black Coyote was built primarily on acreage dedicated from Devon, which is the main shipper on the system. In addition, we further expanded our crude oil gathering operations in the STACK through the construction of Redbud, which is supported by a contract with Marathon Oil Company. We commenced initial operations on Redbud during the third quarter of 2018.
|
•
|
Victoria Express Pipeline.
VEX includes a multi-grade crude oil pipeline with terminals in Cuero and the Port of Victoria and barge docks. The Cuero truck unloading terminal at the origin of the VEX system contains eight unloading bays and above-ground storage capacity for receipt from, and delivery to, the VEX pipeline. The VEX pipeline terminates at the Port of Victoria Terminal, which has an eight-bay truck unloading dock and above-ground storage capacity. The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria. We have an agreement with Devon to ship on VEX, which includes an MVC of 30,000 Bbls/d, that will remain in effect until July 2019.
|
•
|
Gulf Coast Fractionators
. We own a 38.75% interest in GCF, with the remaining interests owned 22.5% by Phillips 66, and 38.75% by Targa Resources Partners, LP. GCF owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66 is the operator of the fractionator. GCF receives raw mix NGLs from customers, fractionates the raw mix, and redelivers the finished products to the customers for a fee.
|
•
|
Cedar Cove JV.
On November 9, 2016, we formed a joint venture with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma, which tie into our existing Oklahoma assets. All gas gathered by the Cedar Cove JV is processed by our Central Oklahoma processing facilities. We own 30% of the Cedar Cove JV.
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Devon
|
10.4
|
%
|
|
14.4
|
%
|
|
18.5
|
%
|
Dow Hydrocarbons and Resources LLC
|
11.1
|
%
|
|
11.2
|
%
|
|
10.8
|
%
|
Marathon Petroleum Corporation
|
11.5
|
%
|
|
(1)
|
|
|
(1)
|
|
(1)
|
Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the years ended
December 31, 2017
and
2016
.
|
•
|
potential changes in the supply of and demand for oil, natural gas and NGLs. and related products and services;
|
•
|
risks relating to exploration and drilling programs, including potential environmental liabilities;
|
•
|
adverse effects of governmental and environmental regulation; and
|
•
|
general economic and financial market conditions.
|
•
|
continued fluctuations in commodity prices, including the prices of natural gas, NGLs, crude oil, and condensate;
|
•
|
environmental or other governmental regulations;
|
•
|
weather conditions;
|
•
|
increases in storage levels of natural gas, NGLs, crude oil, and condensate;
|
•
|
increased use of alternative energy sources;
|
•
|
decreased demand for natural gas, NGLs, crude oil, and condensate;
|
•
|
economic conditions;
|
•
|
supply disruptions;
|
•
|
availability of supply connected to our systems; and
|
•
|
availability and adequacy of infrastructure to gather and process supply into and out of our systems.
|
•
|
additional or more restrictive covenants that impose operating and financial restrictions on us and our subsidiaries;
|
•
|
our subsidiaries to guarantee such debt and certain other debt;
|
•
|
us and our subsidiaries to provide collateral to secure such debt; and
|
•
|
us or our subsidiaries to post cash collateral or letters of credit under our hedging arrangements or in order to purchase commodities or obtain trade credit.
|
•
|
the impact of weather on the supply and demand for crude oil and natural gas;
|
•
|
the level of domestic crude oil, condensate, and natural gas production;
|
•
|
technology, including improved production techniques (particularly with respect to shale development);
|
•
|
the level of domestic industrial and manufacturing activity;
|
•
|
the availability of imported crude oil, natural gas, and NGLs;
|
•
|
international demand for crude oil and NGLs;
|
•
|
actions taken by foreign crude oil and gas producing nations;
|
•
|
the continued threat of terrorism and the impact of military action and civil unrest;
|
•
|
the availability of local, intrastate, and interstate transportation systems;
|
•
|
the availability of downstream NGL fractionation facilities;
|
•
|
the availability and marketing of competitive fuels;
|
•
|
the impact of energy conservation efforts; and
|
•
|
the extent of governmental regulation and taxation, including the regulation of hydraulic fracturing and “greenhouse gases.”
|
•
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or such financing may not be available on favorable terms;
|
•
|
our debt level will make us more vulnerable to general adverse economic and industry conditions;
|
•
|
our ability to plan for, or react to, changes in our business and the industry in which we operate; and
|
•
|
our risk that we may default on our debt obligations.
|
•
|
incur subsidiary indebtedness;
|
•
|
engage in transactions with our affiliates;
|
•
|
consolidate, merge, or sell substantially all of our assets;
|
•
|
incur liens;
|
•
|
enter into sale and lease back transactions; and
|
•
|
change business activities we conduct.
|
•
|
adverse weather conditions, including hurricanes and tropical storms;
|
•
|
delays or decreases in production, the availability of equipment, facilities, or services; and
|
•
|
changes in the regulatory environment.
|
•
|
Ethane.
Ethane is typically supplied as purity ethane or as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream. Such “ethane rejection” reduces the volume of NGLs delivered for fractionation and marketing
.
|
•
|
Propane.
Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine, and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.
|
•
|
Normal Butane.
Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting
|
•
|
Isobutane.
Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
|
•
|
Natural Gasoline.
Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.
|
•
|
the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;
|
•
|
the diversion of management’s attention from other business concerns;
|
•
|
the failure to realize expected volumes, revenues, profitability, or growth;
|
•
|
the failure to realize any expected synergies and cost savings;
|
•
|
the coordination of geographically disparate organizations, systems, and facilities;
|
•
|
the assumption of unknown liabilities;
|
•
|
the loss of customers or key employees from the acquired businesses;
|
•
|
a significant increase in our indebtedness; and
|
•
|
potential environmental or regulatory liabilities and title problems.
|
•
|
damage to pipelines, facilities, storage caverns, equipment, and surrounding properties caused by hurricanes, floods, sink holes, fires, and other natural disasters and acts of terrorism;
|
•
|
inadvertent damage to our assets from construction or farm equipment;
|
•
|
leaks of natural gas, NGLs, crude oil, condensate, and other hydrocarbons;
|
•
|
induced seismicity;
|
•
|
rail accidents, barge accidents, and truck accidents;
|
•
|
equipment failure; and
|
•
|
fires and explosions.
|
•
|
hedging can be expensive, particularly during periods of volatile prices;
|
•
|
our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and
|
•
|
available hedges may not correspond directly with the risks against which we seek protection. For example:
|
•
|
the duration of a hedge may not match the duration of the risk against which we seek protection;
|
•
|
variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); and
|
•
|
we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity, which could adversely affect our liquidity.
|
•
|
how to allocate business opportunities among us and its other affiliates;
|
•
|
whether or not to consent to any merger or consolidation of us or any amendment to our partnership agreement; and
|
•
|
whether or not the general partner should elect to seek the approval of the unitholders in connection with any conflicted transaction.
|
•
|
provide for the proper conduct of our business;
|
•
|
comply with applicable law, our debt instruments, or other agreements; and
|
•
|
provide funds for distributions to the holders of the Series B Preferred Units and the Series C Preferred Units.
|
Period
|
|
Total Number of Units Purchased (1)
|
|
Average Price Paid Per Unit
|
|
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Number of Units that May Yet Be Purchased under the Plans or Programs
|
|||||
January 1, 2018 to January 31, 2018
|
|
153,512
|
|
|
$
|
15.86
|
|
|
—
|
|
|
—
|
|
February 1, 2018 to February 28, 2018
|
|
1,034
|
|
|
17.48
|
|
|
—
|
|
|
—
|
|
|
March 1, 2018 to March 31, 2018
|
|
61,482
|
|
|
14.80
|
|
|
—
|
|
|
—
|
|
|
April 1, 2018 to April 30, 2018
|
|
4,449
|
|
|
13.64
|
|
|
—
|
|
|
—
|
|
|
May 1, 2018 to May 31, 2018
|
|
69
|
|
|
15.01
|
|
|
—
|
|
|
—
|
|
|
June 1, 2018 to June 30, 2018
|
|
3,107
|
|
|
17.14
|
|
|
—
|
|
|
—
|
|
|
July 1, 2018 to July 31, 2018
|
|
79,700
|
|
|
14.95
|
|
|
—
|
|
|
—
|
|
|
August 1, 2018 to August 31, 2018
|
|
61,808
|
|
|
17.15
|
|
|
—
|
|
|
—
|
|
|
September 1, 2018 to September 30, 2018
|
|
2,593
|
|
|
18.67
|
|
|
—
|
|
|
—
|
|
|
October 1, 2018 to October 31, 2018
|
|
194
|
|
|
18.64
|
|
|
—
|
|
|
—
|
|
|
November 1, 2018 to November 30, 2018
|
|
1,442
|
|
|
13.73
|
|
|
—
|
|
|
—
|
|
|
December 1, 2018 to December 31, 2018
|
|
3,774
|
|
|
12.65
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
373,164
|
|
|
$
|
15.67
|
|
|
—
|
|
|
—
|
|
|
EnLink Midstream Partners, LP
|
||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014 (1)
|
||||||||||
|
(In millions, except per unit data)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Product sales
|
$
|
6,512.3
|
|
|
$
|
4,358.4
|
|
|
$
|
3,008.9
|
|
|
$
|
3,253.7
|
|
|
$
|
2,159.3
|
|
Product sales—related parties
|
41.0
|
|
|
144.9
|
|
|
134.3
|
|
|
119.4
|
|
|
505.6
|
|
|||||
Midstream services
|
763.3
|
|
|
552.3
|
|
|
467.2
|
|
|
451.0
|
|
|
253.4
|
|
|||||
Midstream services—related parties
|
377.2
|
|
|
688.2
|
|
|
653.1
|
|
|
618.6
|
|
|
567.4
|
|
|||||
Gain (loss) on derivative activity
|
5.2
|
|
|
(4.2
|
)
|
|
(11.1
|
)
|
|
9.4
|
|
|
22.1
|
|
|||||
Total revenues
|
7,699.0
|
|
|
5,739.6
|
|
|
4,252.4
|
|
|
4,452.1
|
|
|
3,507.8
|
|
|||||
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of sales (2)
|
6,008.0
|
|
|
4,361.5
|
|
|
3,015.5
|
|
|
3,245.3
|
|
|
2,494.5
|
|
|||||
Operating expenses (3)
|
453.4
|
|
|
418.7
|
|
|
398.5
|
|
|
419.9
|
|
|
283.6
|
|
|||||
General and administrative (4)
|
130.2
|
|
|
123.5
|
|
|
119.3
|
|
|
132.4
|
|
|
94.5
|
|
|||||
(Gain) loss on disposition of assets
|
0.4
|
|
|
—
|
|
|
13.2
|
|
|
1.2
|
|
|
(0.1
|
)
|
|||||
Depreciation and amortization
|
577.3
|
|
|
545.3
|
|
|
503.9
|
|
|
387.3
|
|
|
284.3
|
|
|||||
Impairments
|
365.8
|
|
|
17.1
|
|
|
566.3
|
|
|
1,563.4
|
|
|
—
|
|
|||||
Gain on litigation settlement
|
—
|
|
|
(26.0
|
)
|
|
—
|
|
|
—
|
|
|
(6.1
|
)
|
|||||
Total operating costs and expenses
|
7,535.1
|
|
|
5,440.1
|
|
|
4,616.7
|
|
|
5,749.5
|
|
|
3,150.7
|
|
|||||
Operating income (loss)
|
163.9
|
|
|
299.5
|
|
|
(364.3
|
)
|
|
(1,297.4
|
)
|
|
357.1
|
|
|||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net of interest income
|
(178.3
|
)
|
|
(187.9
|
)
|
|
(188.1
|
)
|
|
(102.5
|
)
|
|
(47.4
|
)
|
|||||
Gain on extinguishment of debt
|
—
|
|
|
9.0
|
|
|
—
|
|
|
—
|
|
|
3.2
|
|
|||||
Income (loss) from unconsolidated affiliates
|
13.3
|
|
|
9.6
|
|
|
(19.9
|
)
|
|
20.4
|
|
|
18.9
|
|
|||||
Other income (expense)
|
0.6
|
|
|
0.6
|
|
|
0.3
|
|
|
0.8
|
|
|
(0.5
|
)
|
|||||
Total other expense
|
(164.4
|
)
|
|
(168.7
|
)
|
|
(207.7
|
)
|
|
(81.3
|
)
|
|
(25.8
|
)
|
|||||
Income (loss) from continuing operations before non-controlling interest and income taxes
|
(0.5
|
)
|
|
130.8
|
|
|
(572.0
|
)
|
|
(1,378.7
|
)
|
|
331.3
|
|
|||||
Income tax (provision) benefit
|
2.1
|
|
|
24.0
|
|
|
(1.3
|
)
|
|
0.5
|
|
|
(22.0
|
)
|
|||||
Net income (loss) from continuing operations
|
1.6
|
|
|
154.8
|
|
|
(573.3
|
)
|
|
(1,378.2
|
)
|
|
309.3
|
|
|||||
Discontinued operations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|||||
Discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|||||
Net income (loss)
|
1.6
|
|
|
154.8
|
|
|
(573.3
|
)
|
|
(1,378.2
|
)
|
|
310.3
|
|
|||||
Less: Net income (loss) from continuing operations attributable to the non-controlling interest
|
29.6
|
|
|
5.9
|
|
|
(8.1
|
)
|
|
(0.4
|
)
|
|
(0.2
|
)
|
|||||
Net income (loss) attributable to ENLK
|
$
|
(28.0
|
)
|
|
$
|
148.9
|
|
|
$
|
(565.2
|
)
|
|
$
|
(1,377.8
|
)
|
|
$
|
310.5
|
|
Predecessor interest in net income
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
35.5
|
|
General partner interest in net income
|
$
|
38.6
|
|
|
$
|
38.3
|
|
|
$
|
39.5
|
|
|
$
|
58.0
|
|
|
$
|
138.3
|
|
Limited partners' interest in net income (loss) attributable to ENLK
|
$
|
(180.8
|
)
|
|
$
|
17.9
|
|
|
$
|
(662.1
|
)
|
|
$
|
(1,405.2
|
)
|
|
$
|
136.7
|
|
Class C partners' interest in net loss attributable to ENLK
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(12.5
|
)
|
|
$
|
(30.6
|
)
|
|
$
|
—
|
|
Series B preferred interest in net income attributable to ENLK
|
$
|
90.2
|
|
|
$
|
86.0
|
|
|
$
|
69.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Series C preferred interest in net income attributable to ENLK
|
$
|
24.0
|
|
|
$
|
6.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net income (loss) attributable to ENLK per limited partners' unit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic and diluted common unit
|
$
|
(0.51
|
)
|
|
$
|
0.05
|
|
|
$
|
(1.99
|
)
|
|
$
|
(4.66
|
)
|
|
$
|
0.59
|
|
Distributions declared per limited partner unit
|
$
|
1.560
|
|
|
$
|
1.560
|
|
|
$
|
1.560
|
|
|
$
|
1.545
|
|
|
$
|
1.470
|
|
(1)
|
Prior to March 7, 2014, our financial results only included the assets, liabilities, and operations of our Predecessor. Beginning on March 7, 2014, our financial results also consolidated the assets, liabilities, and operations of the legacy business of ENLK prior to giving effect to the Business Combination.
|
(2)
|
Includes related party cost of sales of
$114.1 million
,
$211.0 million
,
$150.1 million
,
$141.3 million
, and
$354.3 million
for the years ended
December 31, 2018
,
2017
,
2016
,
2015
, and
2014
, respectively.
|
(3)
|
Includes related party operating expense of
$0.4 million
,
$0.6 million
,
$0.5 million
,
$0.5 million
, and
$5.9 million
for the years ended
December 31, 2018
,
2017
,
2016
,
2015
, and
2014
, respectively.
|
(4)
|
Includes related party general and administrative expenses of
$11.6 million
for the year ended December 31,
2014
. Related party general and administrative expenses, if any, subsequent to December 31, 2014, were not material.
|
|
EnLink Midstream Partners, LP
|
||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Balance Sheet Data (end of period):
|
|
|
|
|
|
|
|
|
|
||||||||||
Property and equipment, net
|
$
|
6,846.7
|
|
|
$
|
6,587.0
|
|
|
$
|
6,256.7
|
|
|
$
|
5,666.8
|
|
|
$
|
5,042.8
|
|
Total assets
|
9,571.3
|
|
|
9,414.0
|
|
|
9,153.4
|
|
|
8,092.8
|
|
|
8,702.0
|
|
|||||
Long-term debt (including current maturities)
|
4,319.6
|
|
|
3,467.8
|
|
|
3,268.0
|
|
|
3,066.8
|
|
|
2,022.5
|
|
|||||
Partners' equity including non-controlling interest
|
4,284.1
|
|
|
4,805.5
|
|
|
4,640.4
|
|
|
4,434.5
|
|
|
6,025.9
|
|
•
|
gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
|
•
|
fractionating, transporting, storing, and selling NGLs; and
|
•
|
gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.
|
•
|
Texas Segment
. The Texas segment includes our natural gas gathering, processing, and transmission operations in North Texas and the Permian Basin;
|
•
|
Oklahoma Segment
. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities in the Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK, and CNOW shale areas;
|
•
|
Louisiana Segment
. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana;
|
•
|
Crude and Condensate Segment
. The Crude and Condensate segment includes ORV, our crude oil operations in the Permian Basin and Central Oklahoma, and our crude oil activities associated with VEX; and
|
•
|
Corporate Segment
. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, and our general corporate property
and expenses.
|
•
|
gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own;
|
•
|
processing natural gas at our processing plants;
|
•
|
fractionating and marketing recovered NGLs;
|
•
|
providing compression services;
|
•
|
providing crude oil and condensate transportation and terminal services;
|
•
|
providing condensate stabilization services;
|
•
|
providing brine disposal services; and
|
•
|
providing natural gas, crude oil, and NGL storage.
|
•
|
natural gas gathered, transported, purchased, and sold through our pipeline systems;
|
•
|
natural gas processed at our processing facilities;
|
•
|
NGLs handled at our fractionation facilities or transported through our pipeline systems;
|
•
|
crude oil and condensate handled at our crude terminals;
|
•
|
crude oil and condensate gathered, transported, purchased, and sold;
|
•
|
condensate stabilized;
|
•
|
brine disposed; and
|
•
|
natural gas, crude oil, and NGLs stored.
|
•
|
In January 2016, ENLK and ENLC acquired an 83.9% and 16.1% interest, respectively, in EOGP for aggregate consideration of approximately $1.4 billion. The EOGP assets serve gathering and processing needs in the growing STACK and CNOW plays in Central Oklahoma and are supported by long-term, fixed-fee contracts with acreage dedications that, at the time of acquisition, had a weighted-average term of approximately 15 years.
|
•
|
In April 2016, we completed construction of the 100 MMcf/d Riptide processing plant in the Permian Basin.
|
•
|
In August 2016, we formed the Delaware Basin JV with NGP to operate and expand our natural gas, natural gas liquids, and crude oil midstream assets in the Delaware Basin. The Delaware Basin JV is owned 50.1% by us and 49.9% by NGP.
|
•
|
In October 2016, we completed construction of 60 MMcf/d of processing facilities for the initial phase of Lobo II. In the second quarter of 2017, we completed construction of an expansion of the Lobo II processing facility, which provided an additional 60 MMcf/d of processing capacity.
|
•
|
In November 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma. We hold a 30% ownership interest of the Cedar Cove JV, and Kinder Morgan, Inc. holds the remaining 70% ownership interest.
|
•
|
In December 2016, we sold NTPL, a 140-mile natural gas transportation pipeline, for $84.6 million. We maintain capacity on the NTPL at competitive rates and at levels sufficient to support current and expected operations. As a result of the sale, we recorded a loss of $13.4 million for the year ended December 31, 2016.
|
•
|
In March 2017, we completed construction and began operations of the Greater Chickadee crude oil gathering system.
|
•
|
In March 2017, we completed the sale of our ownership interest in HEP for net proceeds of $189.7 million. For the year ended December 31, 2016, we recorded an impairment of $20.1 million to reduce the carrying value of our investment to the expected sales price. Upon the sale of HEP in March 2017, we recorded an additional loss of $3.4 million for the year ended December 31, 2017 based on the adjusted sales price at closing.
|
•
|
In April 2017, we completed construction and began operating a new NGL pipeline through the Ascension JV. This NGL pipeline is a bolt-on project to our Cajun-Sibon NGL pipeline system and is supported by long-term, fee-based contracts with an affiliate of Marathon Petroleum Corporation.
|
•
|
In June 2017, we entered into a long-term, fee-based arrangement with an affiliate of ONEOK, Inc. (“ONEOK”) under which ONEOK transports NGLs from our Chisholm processing facility to the Gulf Coast and our Cajun-Sibon NGL pipeline system.
|
•
|
In 2017, we completed construction of two new cryogenic gas processing plants, which included the Chisholm II plant completed in April 2017 and the Chisholm III plant completed in December 2017.
|
•
|
the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;
|
•
|
the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders and our general partner;
|
•
|
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and
|
•
|
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Reconciliation of net income (loss) to adjusted EBITDA
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
1.6
|
|
|
$
|
154.8
|
|
|
$
|
(573.3
|
)
|
Interest expense, net of interest income
|
178.3
|
|
|
187.9
|
|
|
188.1
|
|
|||
Depreciation and amortization
|
577.3
|
|
|
545.3
|
|
|
503.9
|
|
|||
Impairments
|
365.8
|
|
|
17.1
|
|
|
566.3
|
|
|||
(Income) loss from unconsolidated affiliate investments (1)
|
(13.3
|
)
|
|
(9.6
|
)
|
|
19.9
|
|
|||
Distributions from unconsolidated affiliate investments (2)
|
22.7
|
|
|
13.5
|
|
|
25.0
|
|
|||
Loss on disposition of assets
|
0.4
|
|
|
—
|
|
|
13.2
|
|
|||
Gain on extinguishment of debt
|
—
|
|
|
(9.0
|
)
|
|
—
|
|
|||
Unit-based compensation
|
40.8
|
|
|
47.8
|
|
|
30.0
|
|
|||
Income tax provision (benefit)
|
(2.1
|
)
|
|
(24.0
|
)
|
|
1.3
|
|
|||
(Gain) loss on non-cash derivatives
|
(10.1
|
)
|
|
(4.7
|
)
|
|
20.1
|
|
|||
Payments under onerous performance obligation offset to other current and long-term liabilities
|
(17.9
|
)
|
|
(17.9
|
)
|
|
(17.9
|
)
|
|||
Non-cash revenue from contract restructuring (3)
|
(45.5
|
)
|
|
—
|
|
|
—
|
|
|||
Other (4)
|
3.3
|
|
|
4.6
|
|
|
6.9
|
|
|||
Adjusted EBITDA before non-controlling interest
|
1,101.3
|
|
|
905.8
|
|
|
783.5
|
|
|||
Non-controlling interest share of adjusted EBITDA (5)
|
(59.5
|
)
|
|
(33.0
|
)
|
|
(8.9
|
)
|
|||
Adjusted EBITDA, net to ENLK
|
$
|
1,041.8
|
|
|
$
|
872.8
|
|
|
$
|
774.6
|
|
(1)
|
Includes losses of
$3.4 million
and
$20.1 million
for the years ended December 31, 2017 and 2016
, respectively, related to the sale of our HEP interests
.
|
(2)
|
Distributions for the year ended December 31, 2016 do not include
$32.7
million of distributions received from HEP during the third quarter of 2016 attributable to the redemption of preferred units in HEP. The preferred units were issued to us by HEP during the second and third quarters of 2016 for contributions of
$29.5 million
and
$3.2 million
, respectively.
|
(3)
|
In May 2018, we restructured a natural gas gathering and processing contract, and, as a result, recognized non-cash revenue representing the discounted present value of a secured term loan receivable.
For more information, see “Item 8. Financial Statements
—
Note 2—Significant Accounting Policies
.”
|
(4)
|
Includes accretion expense associated with asset retirement obligations; reimbursed employee costs from Devon and LPC Crude Oil Marketing LLC; successful transaction costs, which we do not consider in determining adjusted EBITDA because operating cash flows are not used to fund such costs; and non-cash rent, which relates to lease incentives pro-rated over the lease term.
|
(5)
|
Non-controlling interest share of adjusted EBITDA includes ENLC’s
16.1%
share of adjusted EBITDA from EOGP, which was acquired in January 2016, NGP’s
49.9%
share of adjusted EBITDA from the Delaware Basin JV, which was formed in August 2016, Marathon Petroleum Corporation’s
50%
share of adjusted EBITDA from the Ascension JV, which began operations in April 2017, and other minor non-controlling interests
.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net cash provided by operating activities
|
$
|
856.8
|
|
|
$
|
706.5
|
|
|
$
|
662.6
|
|
Interest expense (1)
|
177.9
|
|
|
158.8
|
|
|
135.3
|
|
|||
Current income tax expense
|
1.8
|
|
|
2.6
|
|
|
1.9
|
|
|||
Distributions from unconsolidated affiliate investment in excess of earnings (2)
|
6.9
|
|
|
0.2
|
|
|
21.9
|
|
|||
Other (3)
|
4.4
|
|
|
6.3
|
|
|
4.2
|
|
|||
Changes in operating assets and liabilities which (provided) used cash:
|
|
|
|
|
|
||||||
Accounts receivable, accrued revenues, inventories, and other
|
126.8
|
|
|
213.2
|
|
|
107.7
|
|
|||
Accounts payable, accrued gas and crude oil purchases, and other (4)
|
(73.3
|
)
|
|
(181.8
|
)
|
|
(150.1
|
)
|
|||
Adjusted EBITDA before non-controlling interest
|
1,101.3
|
|
|
905.8
|
|
|
783.5
|
|
|||
Non-controlling interest share of adjusted EBITDA (5)
|
(59.5
|
)
|
|
(33.0
|
)
|
|
(8.9
|
)
|
|||
Adjusted EBITDA, net to EnLink Midstream Partners, LP
|
$
|
1,041.8
|
|
|
$
|
872.8
|
|
|
$
|
774.6
|
|
Interest expense, net of interest income
|
(178.3
|
)
|
|
(187.9
|
)
|
|
(188.1
|
)
|
|||
Amortization of EOGP installment payable discount included in interest expense (6)
|
0.5
|
|
|
26.4
|
|
|
52.3
|
|
|||
Litigation settlement adjustment (7)
|
—
|
|
|
(18.1
|
)
|
|
—
|
|
|||
Non-cash adjustment for redeemable non-controlling interest
|
—
|
|
|
—
|
|
|
0.3
|
|
|||
Interest rate swap (8)
|
—
|
|
|
—
|
|
|
0.4
|
|
|||
Current taxes and other
|
(4.7
|
)
|
|
(2.5
|
)
|
|
(1.9
|
)
|
|||
Maintenance capital expenditures, net to ENLK (9)
|
(42.0
|
)
|
|
(30.9
|
)
|
|
(30.5
|
)
|
|||
Preferred unit accrued cash distributions (10)
|
(89.4
|
)
|
|
(38.7
|
)
|
|
—
|
|
|||
Distributable cash flow
|
$
|
727.9
|
|
|
$
|
621.1
|
|
|
$
|
607.1
|
|
(1)
|
Excludes non-cash interest income and amortization of debt issuance costs and discount and premium.
|
(2)
|
Distributions for the year ended December 31, 2016 do not include $32.7 million of distributions received from HEP during the third quarter of 2016 attributable to the redemption of preferred units in HEP. The preferred units were issued to us by HEP during the second and third quarters of 2016 for contributions of $29.5 million and $3.2 million, respectively.
|
(3)
|
Includes non-cash rent, which relates to lease incentives pro-rated over the lease term, accruals for settled commodity swap transactions, gains and losses on settled interest rate swaps designated as hedges related to debt issuances, which are recorded in other comprehensive income (loss), and successful transaction costs.
|
(4)
|
Net of payments under onerous performance obligation offset to other current and long-term liabilities.
|
(5)
|
Non-controlling interest share of adjusted EBITDA includes ENLC’s
16.1%
share of adjusted EBITDA from EOGP, which was acquired in January 2016, NGP’s
49.9%
share of adjusted EBITDA from the Delaware Basin JV, which was formed in August 2016, Marathon Petroleum Corporation’s
50%
share of adjusted EBITDA from the Ascension JV, which began operations in April 2017, and other minor non-controlling interests
|
(6)
|
Amortization of the EOGP installment payable discount was considered non-cash interest under the ENLK Credit Facility since the payment under the payable is consideration for the acquisition of the EOGP assets.
|
(7)
|
Represents recoveries from a lawsuit settled in 2017 for amounts not previously deducted from distributable cash flow.
See “Item 8. Financial Statements—
Note 13—Commitments and Contingencies
” for additional information.
|
(8)
|
During the third quarter of 2016, we entered into interest rate swap arrangement to mitigate our exposure to interest rate movements prior to our note issuances. The gain on settlement of the interest rate swaps was considered excess proceeds for the note issuance and is therefore excluded from distributable cash flow.
|
(9)
|
Excludes maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.
|
(10)
|
Represents the cash distributions earned by the Series B Preferred Units of
$65.4 million
and
$32.0 million
for the years ended
December 31, 2018
and 2017 respectively, and
$24.0 million
and
$6.7 million
earned by the Series C Preferred Units for the year ended
December 31, 2018
and 2017, respectively
. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.
See “Item 8. Financial Statements—
Note 8—Partners' Capital
” for additional information.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Operating income (loss)
|
$
|
163.9
|
|
|
$
|
299.5
|
|
|
$
|
(364.3
|
)
|
|
|
|
|
|
|
||||||
Add (deduct):
|
|
|
|
|
|
||||||
Operating expenses
|
453.4
|
|
|
418.7
|
|
|
398.5
|
|
|||
General and administrative expenses
|
130.2
|
|
|
123.5
|
|
|
119.3
|
|
|||
Loss on disposition of assets
|
0.4
|
|
|
—
|
|
|
13.2
|
|
|||
Depreciation and amortization
|
577.3
|
|
|
545.3
|
|
|
503.9
|
|
|||
Impairments
|
365.8
|
|
|
17.1
|
|
|
566.3
|
|
|||
Gain on litigation settlement
|
—
|
|
|
(26.0
|
)
|
|
—
|
|
|||
Gross operating margin
|
$
|
1,691.0
|
|
|
$
|
1,378.1
|
|
|
$
|
1,236.9
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Texas Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
1,394.6
|
|
|
$
|
1,365.9
|
|
|
$
|
1,068.3
|
|
Cost of sales
|
(753.9
|
)
|
|
(772.3
|
)
|
|
(483.4
|
)
|
|||
Total gross operating margin
|
$
|
640.7
|
|
|
$
|
593.6
|
|
|
$
|
584.9
|
|
Louisiana Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
3,501.2
|
|
|
$
|
2,931.6
|
|
|
$
|
2,001.5
|
|
Cost of sales
|
(3,158.7
|
)
|
|
(2,618.1
|
)
|
|
(1,729.0
|
)
|
|||
Total gross operating margin
|
$
|
342.5
|
|
|
$
|
313.5
|
|
|
$
|
272.5
|
|
Oklahoma Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
1,297.7
|
|
|
$
|
874.8
|
|
|
$
|
437.0
|
|
Cost of sales
|
(744.0
|
)
|
|
(522.9
|
)
|
|
(184.9
|
)
|
|||
Total gross operating margin
|
$
|
553.7
|
|
|
$
|
351.9
|
|
|
$
|
252.1
|
|
Crude and Condensate Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
2,745.3
|
|
|
$
|
1,453.6
|
|
|
$
|
1,176.5
|
|
Cost of sales
|
(2,596.4
|
)
|
|
(1,330.3
|
)
|
|
(1,038.0
|
)
|
|||
Total gross operating margin
|
$
|
148.9
|
|
|
$
|
123.3
|
|
|
$
|
138.5
|
|
Corporate Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
(1,239.8
|
)
|
|
$
|
(886.3
|
)
|
|
$
|
(430.9
|
)
|
Cost of sales
|
1,245.0
|
|
|
882.1
|
|
|
419.8
|
|
|||
Total gross operating margin
|
$
|
5.2
|
|
|
$
|
(4.2
|
)
|
|
$
|
(11.1
|
)
|
Total
|
|
|
|
|
|
||||||
Revenues
|
$
|
7,699.0
|
|
|
$
|
5,739.6
|
|
|
$
|
4,252.4
|
|
Cost of sales
|
(6,008.0
|
)
|
|
(4,361.5
|
)
|
|
(3,015.5
|
)
|
|||
Total gross operating margin
|
$
|
1,691.0
|
|
|
$
|
1,378.1
|
|
|
$
|
1,236.9
|
|
|
|
|
|
|
|
||||||
Midstream Volumes:
|
|
|
|
|
|
||||||
Texas Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
2,255,800
|
|
|
2,262,900
|
|
|
2,622,600
|
|
|||
Processing (MMBtu/d)
|
1,279,100
|
|
|
1,184,400
|
|
|
1,173,100
|
|
|||
Louisiana Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
2,196,200
|
|
|
1,995,800
|
|
|
1,676,600
|
|
|||
Processing (MMBtu/d)
|
431,200
|
|
|
453,300
|
|
|
490,300
|
|
|||
NGL Fractionation (Gals/d)
|
6,584,400
|
|
|
5,772,800
|
|
|
5,197,100
|
|
|||
Oklahoma Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
1,204,700
|
|
|
829,300
|
|
|
626,300
|
|
|||
Processing (MMBtu/d)
|
1,195,300
|
|
|
810,300
|
|
|
574,900
|
|
|||
Crude and Condensate Segment
|
|
|
|
|
|
||||||
Crude Oil Handling (Bbls/d)
|
155,400
|
|
|
108,200
|
|
|
94,000
|
|
|||
Brine Disposal (Bbls/d)
|
3,200
|
|
|
4,200
|
|
|
3,600
|
|
•
|
Texas Segment.
Gross operating margin in the Texas segment
increased
$47.1 million
, which was primarily due to a $42.7 million increase from our Permian Basin processing assets as a result of higher volumes due to continued development by our customers. In addition, there was a $4.4 million increase in gross operating margin from our North Texas processing, gathering, and transmission assets due to volume increases associated with new development in the Barnett Shale. For the year ended December 31, 2018, the shortfall revenue from Devon-related MVCs was
$84.3 million
compared to
$59.2 million
for the year ended December 31, 2017.
|
•
|
Louisiana Segment.
Gross operating margin in the Louisiana segment
increased
$29.0 million
, which was primarily due to an increase in our NGL transmission and fractionation gross operating margin due to additional NGL volumes received from our Oklahoma and Permian Basin assets and fees earned from the start-up of our Ascension JV assets in April 2017.
|
•
|
Oklahoma Segment.
Gross operating margin in the Oklahoma segment
increased
$201.8 million
, which was primarily due to a $156.3 million increase from higher volumes as a result of continued development by our customers. In addition, during the year ended December 31, 2018, we restructured a contract with a customer, which resulted in the recognition of $45.5 million in revenue for the year ended December 31, 2018 (as discussed in “Item 8. Financial Statements
—
Note 2—Significant Accounting Policies
”). For the year ended December 31, 2018, the shortfall revenue from Devon-related MVCs was
$1.2 million
compared to
$13.8 million
for the year ended December 31, 2017.
|
•
|
Crude and Condensate Segment
. Gross operating margin in the Crude and Condensate segment
increased
$25.6 million
, which was partially due to a $14.9 million increase from ORV due to higher condensate stabilization volumes and improved margins from contract renegotiations. In addition, there was a $5.9 million increase from our Permian Basin crude business as a result of increased trucking volumes, higher trucking fees, higher volumes due to continued expansion of our customer base on the Greater Chickadee gathering system, and the start of initial operations of Avenger. Additionally, gross operating margin increased $2.5 million from the start of initial operations of our Central Oklahoma crude oil gathering systems and trucking business, and $2.3 million due to higher volumes on VEX.
|
•
|
Corporate Segment.
Gross operating margin in the Corporate segment
increased
$9.4 million
, due to the changes in fair value of our commodity swaps between the periods. For the
year ended December 31, 2018
, there were
realized losses
of
$4.9 million
that were offset by
unrealized gains
of
$10.1 million
. For the
year ended December 31, 2017
, there were
realized losses
of
$8.9 million
that were partially offset by
unrealized gains
of
$4.7 million
.
|
|
Texas
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Total
|
||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
||||||||
Midstream services (1)
|
$
|
41.0
|
|
|
$
|
53.4
|
|
|
$
|
5.2
|
|
|
$
|
99.6
|
|
Midstream services—related parties
|
43.3
|
|
|
1.2
|
|
|
6.3
|
|
|
50.8
|
|
||||
Total
|
$
|
84.3
|
|
|
$
|
54.6
|
|
|
$
|
11.5
|
|
|
$
|
150.4
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
$
|
0.8
|
|
|
$
|
16.1
|
|
|
$
|
—
|
|
|
$
|
16.9
|
|
Midstream services—related parties
|
59.2
|
|
|
13.8
|
|
|
8.9
|
|
|
81.9
|
|
||||
Total
|
$
|
60.0
|
|
|
$
|
29.9
|
|
|
$
|
8.9
|
|
|
$
|
98.8
|
|
(1)
|
We restructured a natural gas gathering and processing contract that contained MVCs. As a result, we recognized
$45.5 million
of midstream services revenue in the Oklahoma segment for the year ended December 31, 2018. For more information, see “See “Item 8. Financial Statements and Supplementary Data
—
Note 2—Significant Accounting Policies
.”
|
|
Year Ended December 31,
|
|
Change
|
|||||||||||
|
2018
|
|
2017
|
|
$
|
|
%
|
|||||||
Texas Segment
|
$
|
180.6
|
|
|
$
|
172.7
|
|
|
$
|
7.9
|
|
|
4.6
|
%
|
Louisiana Segment
|
108.3
|
|
|
101.3
|
|
|
7.0
|
|
|
6.9
|
%
|
|||
Oklahoma Segment
|
89.2
|
|
|
64.6
|
|
|
24.6
|
|
|
38.1
|
%
|
|||
Crude and Condensate Segment
|
75.3
|
|
|
80.1
|
|
|
(4.8
|
)
|
|
(6.0
|
)%
|
|||
Total
|
$
|
453.4
|
|
|
$
|
418.7
|
|
|
$
|
34.7
|
|
|
8.3
|
%
|
•
|
Texas Segment.
Operating expenses in the Texas segment
increased
$7.9 million
primarily due to expanded operations and higher utilities expense in the Permian Basin.
|
•
|
Louisiana Segment.
Operating expenses in the Louisiana segment
increased
$7.0 million
primarily due to increased utilities, operational fees and services, labor and benefits charges, and materials and supplies expenses as a result of the start-up of the Ascension JV in April 2017 and higher volumes across our Louisiana assets.
|
•
|
Oklahoma Segment.
Operating expenses in the Oklahoma segment
increased
$24.6 million
due to labor and benefit expenses from increased headcount, as well as an increase in materials and supplies, operational fees and services, treater rentals, ad valorem tax, and compression service expenses as a result of expanded operations.
|
•
|
Crude and Condensate Segment.
Operating expenses in the Crude and Condensate segment
decreased
$4.8 million
primarily due to decreases in third-party transportation charges and lower labor and benefit expenses.
|
•
|
Wages and salaries increased due to a $9.3 million increase in bonus expense as a result of strong financial performance and $2.8 million in severance expense related to an organizational realignment in 2018;
|
•
|
Transaction costs increased
$3.1 million
due to costs we incurred in 2018 related to the GIP Transaction and the Merger;
|
•
|
Unit-based compensation expense decreased $7.0 million due to bonuses paid in the form of units, which vested immediately in March 2017, and was partially offset by accelerated vesting of units related to the GIP Transaction and an organizational realignment in 2018; and
|
•
|
Professional service fees decreased $1.0 million.
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Senior notes
|
$
|
160.0
|
|
|
$
|
155.0
|
|
Term Loan
|
1.9
|
|
|
—
|
|
||
ENLK Credit Facility
|
22.3
|
|
|
9.5
|
|
||
Capitalized interest
|
(7.0
|
)
|
|
(6.3
|
)
|
||
Amortization of debt issue costs and net discount
|
4.0
|
|
|
29.1
|
|
||
Other
|
(2.9
|
)
|
|
0.6
|
|
||
Total interest expense, net of interest income
|
$
|
178.3
|
|
|
$
|
187.9
|
|
•
|
Texas Segment
. Gross operating margin in the Texas segment increased $8.7 million, which was primarily due to a $25.9 million increase in gross operating margin due to higher volumes from our expansion in the Permian Basin. This increase was partially offset by a $17.2 million decrease in gross operating margin from our North Texas processing, gathering, and transmission assets due to volume declines across our North Texas system, including an $11.5 million decrease due to the sale of the NTPL assets in December 2016. Although we experienced volume declines for certain of our Barnett-Shale assets, the impact of these volume declines on gross operating margin was offset by an increase in revenue earned from MVCs (as discussed in more detail below) under our contracts with Devon. For the year ended December 31, 2017 the shortfall revenue from Devon-related MVCs was $59.2 million compared to $26.4 million for the year ended December 31, 2016.
|
•
|
Louisiana Segment
. Gross operating margin in the Louisiana segment increased $41.0 million, which was primarily due to a $34.2 million increase in gross operating margin from our NGL transmission and fractionation assets and a $6.8 million increase in gross operating margin from our Louisiana gathering and transmission assets. The increase from our NGL business was primarily due to additional NGL volumes fractionated, including volumes received from our Oklahoma and Permian Basin assets, together with a $9.3 million gross operating margin contribution from fees earned on our Ascension JV assets, which commenced operations in April 2017. The increase from our transmission assets was primarily due to volume increases on our Louisiana Intrastate Gas and Gulf Coast pipeline systems.
|
•
|
Oklahoma Segment
. Gross operating margin in the Oklahoma segment increased $99.8 million, which was primarily driven by a $104.8 million increase from our Central Oklahoma assets as a result of higher volumes due to continued producer development in Oklahoma. This increase was partially offset by a $5.1 million decrease in gross operating margin from our Northridge gathering and processing assets due to price and volume reductions under a third-party contract.
|
•
|
Crude and Condensate Segment
. Gross operating margin in the Crude and Condensate segment decreased $15.2 million, which was primarily due to a $12.8 million decrease as a result of condensate stabilization volume declines and transportation rate decreases on our ORV assets and a decrease of $8.4 million as a result of volume declines in our Permian Basin trucking business. The volume and rate declines throughout our Crude and Condensate segment were primarily attributable to increased competition due to lower crude prices. These declines were partially offset by a $4.8 million increase due to the Greater Chickadee gathering system, which became fully operational in the first quarter of 2017.
|
•
|
Corporate Segment
. Gross operating margin in the Corporate segment increased $6.9 million, which was due to the changes in fair value of our commodity swaps between periods. For the year ended December 31, 2017, there were unrealized gains of $4.7 million, offset by realized losses of $8.9 million. For the year ended December 31, 2016, there were unrealized losses of $20.1 million, partially offset by realized gains of $9.0 million.
|
|
Year Ended December 31,
|
|
Change
|
|||||||||||
|
2017
|
|
2016
|
|
$
|
|
%
|
|||||||
Texas Segment
|
$
|
172.7
|
|
|
$
|
168.5
|
|
|
$
|
4.2
|
|
|
2.5
|
%
|
Louisiana Segment
|
101.3
|
|
|
96.6
|
|
|
4.7
|
|
|
4.9
|
%
|
|||
Oklahoma Segment
|
64.6
|
|
|
52.1
|
|
|
12.5
|
|
|
24.0
|
%
|
|||
Crude and Condensate Segment
|
80.1
|
|
|
81.3
|
|
|
(1.2
|
)
|
|
(1.5
|
)%
|
|||
Total
|
$
|
418.7
|
|
|
$
|
398.5
|
|
|
$
|
20.2
|
|
|
5.1
|
%
|
•
|
Louisiana Segment
. Operating expenses in the Louisiana segment increased $4.7 million primarily due to increases in materials and supplies expense of $2.7 million, labor and benefits expense of $1.7 million, utilities expense of $1.3 million, and regulatory expense of $1.0 million as a result of increased activity on our Louisiana systems, partially offset by reduced compressor rental expense of $2.2 million resulting from the purchase of compressors.
|
•
|
Oklahoma Segment
. Operating expenses in the Oklahoma segment increased $12.5 million primarily due to increased property insurance costs of $5.4 million, increased labor and benefits expense of $3.5 million attributable to higher headcount, and to increased materials and supplies expense of $3.7 million as a result of expanded operations.
|
•
|
Unit-based compensation expense increased $13.7 million due to bonuses paid in the form of units, which vested immediately in March 2017, and the accrual of annual bonuses for 2017;
|
•
|
Transaction costs decreased $3.8 million and transition service fees decreased $1.5 million due to the costs incurred during 2016 related to the EOGP acquisition, with no transaction or transition costs incurred for the year ended December 31, 2017;
and
|
•
|
Wages and salaries expense decreased $3.6 million due to severance payments made during 2016 and a decrease in bonus expenses for the year ended December 31, 2017
.
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Senior notes
|
$
|
155.0
|
|
|
$
|
131.1
|
|
ENLK Credit facility
|
9.5
|
|
|
11.7
|
|
||
Capitalized interest
|
(6.3
|
)
|
|
(7.2
|
)
|
||
Amortization of debt issue costs and net discount
|
29.1
|
|
|
53.1
|
|
||
Cash settlements on interest rate swaps
|
—
|
|
|
(0.4
|
)
|
||
Mandatory redeemable non-controlling interest
|
—
|
|
|
0.3
|
|
||
Other
|
0.6
|
|
|
(0.5
|
)
|
||
Total interest expense, net of interest income
|
$
|
187.9
|
|
|
$
|
188.1
|
|
|
|
Increase (Decrease) in Revenue Due to
ASC 606 Adoption |
||
|
|
Year Ended December 31, 2018
|
||
Product sales
|
|
$
|
(235
|
)
|
Product sales—related parties
|
|
(52
|
)
|
|
Midstream services
|
|
(357
|
)
|
|
Midstream services—related parties
|
|
(27
|
)
|
|
Total
|
|
$
|
(671
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Operating cash flows before working capital
|
$
|
928.2
|
|
|
$
|
755.8
|
|
|
$
|
638.1
|
|
Changes in working capital
|
(71.4
|
)
|
|
(49.3
|
)
|
|
24.5
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Growth capital expenditures
|
$
|
(800.3
|
)
|
|
$
|
(758.4
|
)
|
|
$
|
(632.5
|
)
|
Maintenance capital expenditures
|
(42.8
|
)
|
|
(32.4
|
)
|
|
(30.5
|
)
|
|||
Acquisition of business, net of cash acquired
|
—
|
|
|
—
|
|
|
791.5
|
|
|||
Proceeds from sale of unconsolidated affiliate investment
|
—
|
|
|
189.7
|
|
|
—
|
|
|||
Proceeds from sale of property
|
1.9
|
|
|
2.3
|
|
|
93.1
|
|
|||
Investment in unconsolidated affiliates
|
(0.1
|
)
|
|
(12.6
|
)
|
|
(73.8
|
)
|
|||
Distribution from unconsolidated affiliates in excess of earnings
|
6.9
|
|
|
0.2
|
|
|
54.6
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net repayments on the ENLK Credit Facility
|
$
|
—
|
|
|
$
|
(120.0
|
)
|
|
$
|
(294.2
|
)
|
Unsecured senior notes borrowings, net of notes extinguished
|
—
|
|
|
331.6
|
|
|
499.3
|
|
|||
Proceeds from the Term Loan
|
850.0
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from issuance of common units
|
46.1
|
|
|
106.9
|
|
|
167.5
|
|
|||
Proceeds from issuance of Series B Preferred Units
|
—
|
|
|
—
|
|
|
724.1
|
|
|||
Proceeds from issuance of Series C Preferred Units
|
—
|
|
|
394.0
|
|
|
—
|
|
|||
Contributions by non-controlling partners
|
156.4
|
|
|
126.4
|
|
|
207.4
|
|
|||
Payment of installment payable for EOGP acquisition
|
(250.0
|
)
|
|
(250.0
|
)
|
|
—
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Common units
|
$
|
551.6
|
|
|
$
|
543.6
|
|
|
$
|
520.3
|
|
General partner interest (including incentive distribution rights)
|
61.9
|
|
|
61.2
|
|
|
58.7
|
|
|||
Distributions to non-controlling interests (1)
|
54.5
|
|
|
27.5
|
|
|
10.0
|
|
|||
Distributions to Series B Preferred Unitholders
|
65.0
|
|
|
15.9
|
|
|
—
|
|
|||
Distributions to Series C Preferred Unitholders
|
24.0
|
|
|
5.6
|
|
|
—
|
|
(1)
|
Distributions to non-controlling interests included
distributions to ENLC for its ownership in EOGP,
distributions to NGP for its ownership in the Delaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to the non-controlling interest in one of our joint ventures in ORV.
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||||
Long-term debt obligations (1)
|
$
|
3,500.0
|
|
|
$
|
400.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,100.0
|
|
Term Loan
|
850.0
|
|
|
—
|
|
|
—
|
|
|
850.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Interest payable on senior unsecured notes
|
2,413.5
|
|
|
154.5
|
|
|
149.2
|
|
|
149.2
|
|
|
149.2
|
|
|
149.2
|
|
|
1,662.2
|
|
|||||||
Capital lease obligations
|
2.7
|
|
|
1.5
|
|
|
1.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Operating lease obligations
|
100.3
|
|
|
14.1
|
|
|
10.3
|
|
|
8.7
|
|
|
8.6
|
|
|
8.8
|
|
|
49.8
|
|
|||||||
Purchase obligations
|
29.3
|
|
|
29.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Delivery contract obligation
|
9.0
|
|
|
9.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Pipeline and trucking capacity and deficiency agreements (2)
|
201.8
|
|
|
40.5
|
|
|
32.9
|
|
|
32.8
|
|
|
28.1
|
|
|
25.5
|
|
|
42.0
|
|
|||||||
Inactive easement commitment (3)
|
10.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
|
—
|
|
|
—
|
|
|||||||
Total contractual obligations
|
$
|
7,116.6
|
|
|
$
|
648.9
|
|
|
$
|
193.6
|
|
|
$
|
1,040.7
|
|
|
$
|
195.9
|
|
|
$
|
183.5
|
|
|
$
|
4,854.0
|
|
(1)
|
$400.0 million in aggregate principal amount of our 2.7% senior unsecured notes mature on April 1, 2019.
|
(2)
|
Consists of pipeline capacity payments for firm transportation and deficiency agreements.
|
(3)
|
Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.
|
1.
|
Fee-based contracts:
Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of volume processed or (2) arrangements where we purchase and resell commodities in connection with providing the related processing service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities.
|
2.
|
Processing margin contracts:
Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the year ended
December 31, 2018
, approximately
1%
of our contracts, based on gross operating margin, were under processing margin contracts.
|
3.
|
POL contracts:
Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under POL contracts, but they do decline during periods of low liquids prices.
|
4.
|
POP contracts:
Under these contracts, we receive a fee in the form of a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under POP contracts, but they do decline during periods of low natural gas and liquids prices.
|
Period
|
|
Underlying
|
|
Notional Volume
|
|
We Pay
|
|
We Receive (1)
|
|
Fair Value
Asset/(Liability) (In millions)
|
||
January 2019 - June 2019
|
|
Ethane
|
|
183 (MBbls)
|
|
$0.3048/gal
|
|
Index
|
|
$
|
0.1
|
|
January 2019 - September 2019
|
|
Propane
|
|
479 (MBbls)
|
|
Index
|
|
$0.6370/gal
|
|
2.4
|
|
|
January 2019 - September 2019
|
|
Normal Butane
|
|
127 (MBbls)
|
|
Index
|
|
$0.7214/gal
|
|
0.8
|
|
|
January 2019 - September 2019
|
|
Natural Gasoline
|
|
85 (MBbls)
|
|
Index
|
|
$0.9602/gal
|
|
1.3
|
|
|
January 2019 - October 2019
|
|
Natural Gas
|
|
65,382 (MMBtu/d)
|
|
Index
|
|
$2.5946/MMBtu
|
|
(3.1
|
)
|
|
January 2019 - December 2022
|
|
Crude and condensate
|
|
13,870 (MBbls)
|
|
Index
|
|
$52.09/bbl
|
|
7.0
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8.5
|
|
(1)
|
Weighted average.
|
|
/s/ KPMG LLP
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
99.5
|
|
|
$
|
30.8
|
|
Accounts receivable:
|
|
|
|
||||
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively
|
126.3
|
|
|
50.1
|
|
||
Accrued revenue and other
|
705.9
|
|
|
576.6
|
|
||
Related party
|
2.1
|
|
|
102.7
|
|
||
Fair value of derivative assets
|
28.6
|
|
|
6.8
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
72.8
|
|
|
39.7
|
|
||
Total current assets
|
1,035.2
|
|
|
806.7
|
|
||
Property and equipment, net of accumulated depreciation of $2,967.4 and $2,533.0, respectively
|
6,846.7
|
|
|
6,587.0
|
|
||
Intangible assets, net of accumulated amortization of $422.2 and $298.7, respectively
|
1,373.6
|
|
|
1,497.1
|
|
||
Goodwill
|
190.3
|
|
|
422.3
|
|
||
Investment in unconsolidated affiliates
|
80.1
|
|
|
89.4
|
|
||
Fair value of derivative assets
|
4.1
|
|
|
—
|
|
||
Other assets, net
|
41.3
|
|
|
11.5
|
|
||
Total assets
|
$
|
9,571.3
|
|
|
$
|
9,414.0
|
|
LIABILITIES AND PARTNERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and drafts payable
|
$
|
105.5
|
|
|
$
|
66.9
|
|
Accounts payable to related party
|
4.3
|
|
|
18.4
|
|
||
Accrued gas, NGLs, condensate, and crude oil purchases
|
500.4
|
|
|
476.1
|
|
||
Fair value of derivative liabilities
|
21.8
|
|
|
8.4
|
|
||
Installment payable, net of discount of $0.5 at December 31, 2017
|
—
|
|
|
249.5
|
|
||
Current maturities of long-term debt
|
399.8
|
|
|
—
|
|
||
Other current liabilities
|
246.7
|
|
|
222.4
|
|
||
Total current liabilities
|
1,278.5
|
|
|
1,041.7
|
|
||
Long-term debt
|
3,919.8
|
|
|
3,467.8
|
|
||
Asset retirement obligations
|
14.8
|
|
|
14.2
|
|
||
Other long-term liabilities
|
20.0
|
|
|
33.9
|
|
||
Deferred tax liability
|
42.4
|
|
|
46.3
|
|
||
Fair value of derivative liabilities
|
2.4
|
|
|
—
|
|
||
|
|
|
|
||||
Redeemable non-controlling interest
|
9.3
|
|
|
4.6
|
|
||
|
|
|
|
||||
Partners’ equity:
|
|
|
|
||||
Common unitholders (353,117,434 and 349,702,372 units issued and outstanding, respectively)
|
2,117.0
|
|
|
2,791.6
|
|
||
Series B preferred unitholders (58,728,994 and 57,056,281 units issued and outstanding, respectively)
|
889.3
|
|
|
864.1
|
|
||
Series C preferred unitholders (400,000 units outstanding)
|
395.1
|
|
|
395.1
|
|
||
General partner interest (1,594,974 equivalent units outstanding)
|
204.4
|
|
|
207.3
|
|
||
Accumulated other comprehensive loss
|
(2.1
|
)
|
|
(2.1
|
)
|
||
Non-controlling interest
|
680.4
|
|
|
549.5
|
|
||
Total partners’ equity
|
4,284.1
|
|
|
4,805.5
|
|
||
Commitments and contingencies (Note 13)
|
|
|
|
|
|
||
Total liabilities and partners’ equity
|
$
|
9,571.3
|
|
|
$
|
9,414.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Product sales
|
$
|
6,512.3
|
|
|
$
|
4,358.4
|
|
|
$
|
3,008.9
|
|
Product sales—related parties
|
41.0
|
|
|
144.9
|
|
|
134.3
|
|
|||
Midstream services
|
763.3
|
|
|
552.3
|
|
|
467.2
|
|
|||
Midstream services—related parties
|
377.2
|
|
|
688.2
|
|
|
653.1
|
|
|||
Gain (loss) on derivative activity
|
5.2
|
|
|
(4.2
|
)
|
|
(11.1
|
)
|
|||
Total revenues
|
7,699.0
|
|
|
5,739.6
|
|
|
4,252.4
|
|
|||
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales (1)
|
6,008.0
|
|
|
4,361.5
|
|
|
3,015.5
|
|
|||
Operating expenses
|
453.4
|
|
|
418.7
|
|
|
398.5
|
|
|||
General and administrative
|
130.2
|
|
|
123.5
|
|
|
119.3
|
|
|||
Loss on disposition of assets
|
0.4
|
|
|
—
|
|
|
13.2
|
|
|||
Depreciation and amortization
|
577.3
|
|
|
545.3
|
|
|
503.9
|
|
|||
Impairments
|
365.8
|
|
|
17.1
|
|
|
566.3
|
|
|||
Gain on litigation settlement
|
—
|
|
|
(26.0
|
)
|
|
—
|
|
|||
Total operating costs and expenses
|
7,535.1
|
|
|
5,440.1
|
|
|
4,616.7
|
|
|||
Operating income (loss)
|
163.9
|
|
|
299.5
|
|
|
(364.3
|
)
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense, net of interest income
|
(178.3
|
)
|
|
(187.9
|
)
|
|
(188.1
|
)
|
|||
Gain on extinguishment of debt
|
—
|
|
|
9.0
|
|
|
—
|
|
|||
Income (loss) from unconsolidated affiliates
|
13.3
|
|
|
9.6
|
|
|
(19.9
|
)
|
|||
Other income
|
0.6
|
|
|
0.6
|
|
|
0.3
|
|
|||
Total other expense
|
(164.4
|
)
|
|
(168.7
|
)
|
|
(207.7
|
)
|
|||
Income (loss) before non-controlling interest and income taxes
|
(0.5
|
)
|
|
130.8
|
|
|
(572.0
|
)
|
|||
Income tax benefit (provision)
|
2.1
|
|
|
24.0
|
|
|
(1.3
|
)
|
|||
Net income (loss)
|
1.6
|
|
|
154.8
|
|
|
(573.3
|
)
|
|||
Net income (loss) attributable to non-controlling interest
|
29.6
|
|
|
5.9
|
|
|
(8.1
|
)
|
|||
Net income (loss) attributable to ENLK
|
$
|
(28.0
|
)
|
|
$
|
148.9
|
|
|
$
|
(565.2
|
)
|
General partner interest in net income
|
$
|
38.6
|
|
|
$
|
38.3
|
|
|
$
|
39.5
|
|
Limited partners’ interest in net income (loss) attributable to ENLK
|
$
|
(180.8
|
)
|
|
$
|
17.9
|
|
|
$
|
(662.1
|
)
|
Class C partners’ interest in net loss attributable to ENLK
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(12.5
|
)
|
Series B preferred interest in net income attributable to ENLK
|
$
|
90.2
|
|
|
$
|
86.0
|
|
|
$
|
69.9
|
|
Series C preferred interest in net income attributable to ENLK
|
$
|
24.0
|
|
|
$
|
6.7
|
|
|
$
|
—
|
|
Net income (loss) attributable to ENLK per limited partners’ unit:
|
|
|
|
|
|
||||||
Basic common unit
|
$
|
(0.51
|
)
|
|
$
|
0.05
|
|
|
$
|
(1.99
|
)
|
Diluted common unit
|
$
|
(0.51
|
)
|
|
$
|
0.05
|
|
|
$
|
(1.99
|
)
|
(1)
|
Includes related party cost of sales of
$114.1 million
,
$211.0 million
, and
$150.1 million
for the years ended
December 31, 2018
,
2017
,
and
2016
, respectively.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Net income (loss)
|
$
|
1.6
|
|
|
$
|
154.8
|
|
|
$
|
(573.3
|
)
|
Loss on designated cash flow hedge, net of amortization to interest expense
|
—
|
|
|
(2.1
|
)
|
|
—
|
|
|||
Comprehensive income (loss)
|
1.6
|
|
|
152.7
|
|
|
(573.3
|
)
|
|||
Comprehensive income (loss) attributable to non-controlling interest
|
29.6
|
|
|
5.9
|
|
|
(8.1
|
)
|
|||
Comprehensive income (loss) attributable to ENLK
|
$
|
(28.0
|
)
|
|
$
|
146.8
|
|
|
$
|
(565.2
|
)
|
|
Common Units
|
|
Class C Common Units
|
|
Series B Preferred Units
|
|
Series C Preferred Units
|
|
General
Partner Interest
|
|
Accumulated Other Comprehensive Loss
|
|
Non-Controlling Interest
|
|
Total
|
|
Redeemable Non-Controlling Interest (Temporary Equity)
|
|||||||||||||||||||||||||||||||||
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
$
|
|
$
|
|
$
|
|||||||||||||||||||||||
Balance, December 31, 2015
|
$
|
4,055.8
|
|
|
325.2
|
|
|
$
|
149.4
|
|
|
7.1
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
213.4
|
|
|
1.6
|
|
|
$
|
—
|
|
|
$
|
15.9
|
|
|
$
|
4,434.5
|
|
|
$
|
7.0
|
|
Issuance of common units
|
167.5
|
|
|
10.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
167.5
|
|
|
—
|
|
|||||||||
Issuance of Series B Preferred Units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
724.1
|
|
|
50.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
724.1
|
|
|
—
|
|
|||||||||
Contribution from ENLC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237.1
|
|
|
237.1
|
|
|
—
|
|
|||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(1.2
|
)
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.2
|
)
|
|
—
|
|
|||||||||
Unit-based compensation
|
15.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.0
|
|
|
—
|
|
|||||||||
Contribution from Devon
|
1.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|||||||||
Distributions
|
(520.3
|
)
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
3.2
|
|
|
—
|
|
|
—
|
|
|
(58.7
|
)
|
|
—
|
|
|
—
|
|
|
(8.2
|
)
|
|
(587.2
|
)
|
|
(1.8
|
)
|
|||||||||
Conversion of Class C Common Units to common units
|
136.9
|
|
|
7.5
|
|
|
(136.9
|
)
|
|
(7.5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Non-controlling interest contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
207.4
|
|
|
207.4
|
|
|
—
|
|
|||||||||
Net income (loss)
|
(662.1
|
)
|
|
—
|
|
|
(12.5
|
)
|
|
—
|
|
|
69.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39.5
|
|
|
—
|
|
|
—
|
|
|
(8.1
|
)
|
|
(573.3
|
)
|
|
—
|
|
|||||||||
Balance, December 31, 2016
|
$
|
3,193.2
|
|
|
342.9
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
794.0
|
|
|
53.2
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
209.1
|
|
|
1.6
|
|
|
$
|
—
|
|
|
$
|
444.1
|
|
|
$
|
4,640.4
|
|
|
$
|
5.2
|
|
|
Common Units
|
|
Class C Common Units
|
|
Series B Preferred Units
|
|
Series C Preferred Units
|
|
General
Partner Interest |
|
Accumulated Other Comprehensive Loss
|
|
Non-Controlling Interest
|
|
Total
|
|
Redeemable Non-Controlling Interest (Temporary Equity)
|
|||||||||||||||||||||||||||||||||
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
Units
|
|
$
|
|
$
|
|
$
|
|
$
|
|||||||||||||||||||||||
Balance, December 31, 2016
|
$
|
3,193.2
|
|
|
342.9
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
794.0
|
|
|
53.2
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
209.1
|
|
|
1.6
|
|
|
$
|
—
|
|
|
$
|
444.1
|
|
|
$
|
4,640.4
|
|
|
$
|
5.2
|
|
Issuance of common units
|
106.9
|
|
|
6.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
106.9
|
|
|
—
|
|
|||||||||
Issuance of Series C Preferred Units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
394.0
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
394.0
|
|
|
—
|
|
|||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(5.3
|
)
|
|
0.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5.3
|
)
|
|
—
|
|
|||||||||
Unit-based compensation
|
21.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42.3
|
|
|
—
|
|
|||||||||
Contribution from Devon
|
1.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.3
|
|
|
—
|
|
|||||||||
Distributions
|
(543.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15.9
|
)
|
|
3.9
|
|
|
(5.6
|
)
|
|
—
|
|
|
(61.2
|
)
|
|
—
|
|
|
—
|
|
|
(26.9
|
)
|
|
(653.2
|
)
|
|
(0.6
|
)
|
|||||||||
Non-controlling interest contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
126.4
|
|
|
126.4
|
|
|
—
|
|
|||||||||
Unrealized loss on derivatives, net of amortization to interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.1
|
)
|
|
—
|
|
|
(2.1
|
)
|
|
—
|
|
|||||||||
Net income
|
17.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
86.0
|
|
|
—
|
|
|
6.7
|
|
|
—
|
|
|
38.3
|
|
|
—
|
|
|
—
|
|
|
5.9
|
|
|
154.8
|
|
|
—
|
|
|||||||||
Balance, December 31, 2017
|
2,791.6
|
|
|
349.7
|
|
|
—
|
|
|
—
|
|
|
864.1
|
|
|
57.1
|
|
|
395.1
|
|
|
0.4
|
|
|
207.3
|
|
|
1.6
|
|
|
(2.1
|
)
|
|
549.5
|
|
|
4,805.5
|
|
|
4.6
|
|
|||||||||
Issuance of common units
|
46.1
|
|
|
2.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46.1
|
|
|
—
|
|
|||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(5.6
|
)
|
|
0.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5.6
|
)
|
|
—
|
|
|||||||||
Unit-based compensation
|
21.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41.8
|
|
|
—
|
|
|||||||||
Distributions
|
(551.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(65.0
|
)
|
|
1.6
|
|
|
(24.0
|
)
|
|
—
|
|
|
(61.9
|
)
|
|
—
|
|
|
—
|
|
|
(54.5
|
)
|
|
(757.0
|
)
|
|
—
|
|
|||||||||
Non-controlling interest contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156.4
|
|
|
156.4
|
|
|
—
|
|
|||||||||
Fair value adjustment related to redeemable non-controlling interest
|
(4.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.1
|
)
|
|
4.1
|
|
|||||||||
Net income (loss)
|
(180.8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
90.2
|
|
|
—
|
|
|
24.0
|
|
|
—
|
|
|
38.6
|
|
|
—
|
|
|
—
|
|
|
29.0
|
|
|
1.0
|
|
|
0.6
|
|
|||||||||
Balance, December 31, 2018
|
$
|
2,117.0
|
|
|
353.1
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
889.3
|
|
|
58.7
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
204.4
|
|
|
1.6
|
|
|
$
|
(2.1
|
)
|
|
$
|
680.4
|
|
|
$
|
4,284.1
|
|
|
$
|
9.3
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
1.6
|
|
|
$
|
154.8
|
|
|
$
|
(573.3
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Impairments
|
365.8
|
|
|
17.1
|
|
|
566.3
|
|
|||
Depreciation and amortization
|
577.3
|
|
|
545.3
|
|
|
503.9
|
|
|||
Loss on disposition of assets
|
0.4
|
|
|
—
|
|
|
13.2
|
|
|||
Non-cash unit-based compensation
|
40.8
|
|
|
47.8
|
|
|
30.0
|
|
|||
Deferred tax benefit
|
(3.9
|
)
|
|
(26.6
|
)
|
|
(0.6
|
)
|
|||
(Gain) loss on derivatives recognized in net income (loss)
|
(5.2
|
)
|
|
4.2
|
|
|
11.1
|
|
|||
Cash settlements on derivatives
|
(7.0
|
)
|
|
(11.2
|
)
|
|
10.5
|
|
|||
Gain on extinguishment of debt
|
—
|
|
|
(9.0
|
)
|
|
—
|
|
|||
Amortization of debt issue costs, net (premium) discount of notes and installment payable
|
4.0
|
|
|
29.1
|
|
|
53.1
|
|
|||
Distribution of earnings from unconsolidated affiliates
|
15.8
|
|
|
13.3
|
|
|
3.1
|
|
|||
(Income) loss from unconsolidated affiliates
|
(13.3
|
)
|
|
(9.6
|
)
|
|
19.9
|
|
|||
Non-cash revenue from contract restructuring
|
(45.5
|
)
|
|
—
|
|
|
—
|
|
|||
Other operating activities
|
(2.6
|
)
|
|
0.6
|
|
|
0.9
|
|
|||
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
|
|
|
|
|
|
||||||
Accounts receivable, accrued revenue, and other
|
(114.6
|
)
|
|
(189.5
|
)
|
|
(117.9
|
)
|
|||
Natural gas and NGLs inventory, prepaid expenses, and other
|
(12.2
|
)
|
|
(23.7
|
)
|
|
10.2
|
|
|||
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities
|
55.4
|
|
|
163.9
|
|
|
132.2
|
|
|||
Net cash provided by operating activities
|
856.8
|
|
|
706.5
|
|
|
662.6
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Additions to property and equipment
|
(843.1
|
)
|
|
(790.8
|
)
|
|
(663.0
|
)
|
|||
Acquisition of business, net of cash acquired
|
—
|
|
|
—
|
|
|
(769.3
|
)
|
|||
Proceeds from sale of unconsolidated affiliate investment
|
—
|
|
|
189.7
|
|
|
—
|
|
|||
Proceeds from sale of property
|
1.9
|
|
|
2.3
|
|
|
93.1
|
|
|||
Investment in unconsolidated affiliates
|
(0.1
|
)
|
|
(12.6
|
)
|
|
(73.8
|
)
|
|||
Distribution from unconsolidated affiliates in excess of earnings
|
6.9
|
|
|
0.2
|
|
|
54.6
|
|
|||
Other investing activities
|
8.1
|
|
|
0.4
|
|
|
0.3
|
|
|||
Net cash used in investing activities
|
(826.3
|
)
|
|
(610.8
|
)
|
|
(1,358.1
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from borrowings
|
3,904.0
|
|
|
2,315.9
|
|
|
2,057.8
|
|
|||
Payments on borrowings
|
(3,054.0
|
)
|
|
(2,104.3
|
)
|
|
(1,852.7
|
)
|
|||
Payment of installment payable for EOGP acquisition
|
(250.0
|
)
|
|
(250.0
|
)
|
|
—
|
|
|||
Debt financing costs
|
(1.7
|
)
|
|
(5.5
|
)
|
|
(4.6
|
)
|
|||
Proceeds from issuance of common units
|
46.1
|
|
|
106.9
|
|
|
167.5
|
|
|||
Proceeds from issuance of Series B Preferred Units
|
—
|
|
|
—
|
|
|
724.1
|
|
|||
Proceeds from issuance of Series C Preferred Units
|
—
|
|
|
394.0
|
|
|
—
|
|
|||
Distribution to common unitholders and to general partner
|
(613.5
|
)
|
|
(604.8
|
)
|
|
(579.0
|
)
|
|||
Distributions to Series B Preferred Unitholders
|
(65.0
|
)
|
|
(15.9
|
)
|
|
—
|
|
|||
Distributions to Series C Preferred Unitholders
|
(24.0
|
)
|
|
(5.6
|
)
|
|
—
|
|
|||
Distributions to non-controlling interests
|
(54.5
|
)
|
|
(27.5
|
)
|
|
(10.0
|
)
|
|||
Contributions by non-controlling interests, including contributions from affiliates of $66.2, $69.1, and $39.5, respectively
|
156.4
|
|
|
126.4
|
|
|
207.4
|
|
|||
Other financing activities
|
(5.6
|
)
|
|
(6.1
|
)
|
|
(9.3
|
)
|
|||
Net cash provided by (used in) financing activities
|
38.2
|
|
|
(76.5
|
)
|
|
701.2
|
|
|||
Net increase in cash and cash equivalents
|
68.7
|
|
|
19.2
|
|
|
5.7
|
|
|||
Cash and cash equivalents, beginning of period
|
30.8
|
|
|
11.6
|
|
|
5.9
|
|
|||
Cash and cash equivalents, end of period
|
$
|
99.5
|
|
|
$
|
30.8
|
|
|
$
|
11.6
|
|
•
|
GIP, through GIP III Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the
managing member of ENLC
, which, as of the closing date, amounted to
100%
of the outstanding limited liability company interests in the
managing member of ENLC and approximately
23.1%
of the outstanding limited partner interests in ENLK;
|
•
|
GIP, through GIP III Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which, as of the closing date, amounted to approximately
63.8%
of the outstanding limited liability company interests in ENLC; and
|
•
|
Through this transaction, GIP acquired control of
(i) the managing member of ENLC,
(ii) ENLC, and (iii) ENLK, as a result of ENLC’s ownership of
ENLK’s general partner.
|
•
|
gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
|
•
|
fractionating, transporting, storing, and selling NGLs; and
|
•
|
gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.
|
•
|
Product sales—P
roduct sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above.
|
•
|
Midstream services—
Midstream services represent all other revenue generated as a result of performing our midstream services outlined above.
|
•
|
promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and
|
•
|
promises to sell a specified volume of commodities to our customers.
|
|
Increase (Decrease) in Revenue Due to
ASC 606 Adoption |
||
|
Year Ended December 31, 2018
|
||
Product sales
|
$
|
(235
|
)
|
Product sales—related parties
|
(52
|
)
|
|
Midstream services
|
(357
|
)
|
|
Midstream services—related parties
|
(27
|
)
|
|
Total
|
$
|
(671
|
)
|
•
|
For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.
|
•
|
For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations.
|
2019
|
$
|
252.1
|
|
2020
|
247.9
|
|
|
2021
|
104.5
|
|
|
2022
|
95.0
|
|
|
2023
|
92.9
|
|
|
Thereafter
|
281.9
|
|
|
Total
|
$
|
1,074.3
|
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Transmission assets
|
$
|
1,329.4
|
|
|
$
|
1,338.7
|
|
Gathering systems
|
4,410.5
|
|
|
4,040.9
|
|
||
Gas processing plants
|
3,590.5
|
|
|
3,401.8
|
|
||
Other property and equipment
|
171.7
|
|
|
157.8
|
|
||
Construction in process
|
312.0
|
|
|
180.8
|
|
||
Property and equipment
|
9,814.1
|
|
|
9,120.0
|
|
||
Accumulated depreciation
|
(2,967.4
|
)
|
|
(2,533.0
|
)
|
||
Property and equipment, net of accumulated depreciation
|
$
|
6,846.7
|
|
|
$
|
6,587.0
|
|
|
Useful Lives
|
Transmission assets
|
20 - 25 years
|
Gathering systems
|
20 - 25 years
|
Gas processing plants
|
20 - 25 years
|
Other property and equipment
|
3 - 15 years
|
•
|
the future fee-based rate of new business or contract renewals;
|
•
|
the purchase and resale margins on natural gas, NGLs, crude oil, and condensate;
|
•
|
the volume of natural gas, NGLs, crude oil, and condensate available to the asset;
|
•
|
markets available to the asset;
|
•
|
operating expenses; and
|
•
|
future natural gas, NGLs, crude oil, and condensate prices.
|
•
|
changes in general economic conditions in regions in which our markets are located;
|
•
|
the availability and prices of natural gas, NGLs, crude oil, and condensate supply;
|
•
|
our ability to negotiate favorable sales agreements;
|
•
|
the risks that natural gas, NGLs, crude oil, and condensate exploration and production activities will not occur or be successful;
|
•
|
our dependence on certain significant customers, producers, and transporters of natural gas, NGLs, crude oil, and condensate; and
|
•
|
competition from other midstream companies, including major energy companies.
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Devon
|
10.4
|
%
|
|
14.4
|
%
|
|
18.5
|
%
|
Dow Hydrocarbons and Resources LLC
|
11.1
|
%
|
|
11.2
|
%
|
|
10.8
|
%
|
Marathon Petroleum Corporation
|
11.5
|
%
|
|
(1)
|
|
|
(1)
|
|
(1)
|
Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the years ended
December 31, 2017
and
2016
.
|
Consideration:
|
|
||
Cash
|
$
|
783.6
|
|
Total installment payable, net of discount of $79.1 million
|
420.9
|
|
|
Contribution from ENLC
|
237.1
|
|
|
Total consideration
|
$
|
1,441.6
|
|
|
|
||
Purchase Price Allocation:
|
|
||
Assets acquired:
|
|
||
Current assets (including $12.8 million in cash)
|
$
|
23.0
|
|
Property and equipment
|
406.1
|
|
|
Intangibles
|
1,051.3
|
|
|
Liabilities assumed:
|
|
||
Current liabilities
|
(38.8
|
)
|
|
Total identifiable net assets
|
$
|
1,441.6
|
|
|
Texas
|
|
Oklahoma
|
|
Totals
|
||||||
Year Ended December 31, 2018
|
|
|
|
|
|
||||||
Balance, beginning of period
|
$
|
232.0
|
|
|
$
|
190.3
|
|
|
$
|
422.3
|
|
Impairment
|
(232.0
|
)
|
|
—
|
|
|
(232.0
|
)
|
|||
Balance, end of period
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
190.3
|
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
||||||
Year Ended December 31, 2018
|
|
|
|
|
|
||||||
Customer relationships, beginning of period
|
$
|
1,795.8
|
|
|
$
|
(298.7
|
)
|
|
$
|
1,497.1
|
|
Amortization expense
|
—
|
|
|
(123.5
|
)
|
|
(123.5
|
)
|
|||
Customer relationships, end of period
|
$
|
1,795.8
|
|
|
$
|
(422.2
|
)
|
|
$
|
1,373.6
|
|
|
|
|
|
|
|
||||||
Year Ended December 31, 2017
|
|
|
|
|
|
||||||
Customer relationships, beginning of period
|
$
|
1,795.8
|
|
|
$
|
(171.6
|
)
|
|
$
|
1,624.2
|
|
Amortization expense
|
—
|
|
|
(127.1
|
)
|
|
(127.1
|
)
|
|||
Customer relationships, end of period
|
$
|
1,795.8
|
|
|
$
|
(298.7
|
)
|
|
$
|
1,497.1
|
|
|
|
|
|
|
|
||||||
Year Ended December 31, 2016
|
|
|
|
|
|
||||||
Customer relationships, beginning of period
|
$
|
744.5
|
|
|
$
|
(54.6
|
)
|
|
$
|
689.9
|
|
Acquisitions
|
1,051.3
|
|
|
—
|
|
|
1,051.3
|
|
|||
Amortization expense
|
—
|
|
|
(117.0
|
)
|
|
(117.0
|
)
|
|||
Customer relationships, end of period
|
$
|
1,795.8
|
|
|
$
|
(171.6
|
)
|
|
$
|
1,624.2
|
|
2019
|
$
|
123.7
|
|
2020
|
123.7
|
|
|
2021
|
123.7
|
|
|
2022
|
123.7
|
|
|
2023
|
123.6
|
|
|
Thereafter
|
755.2
|
|
|
Total
|
$
|
1,373.6
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
||||||||||||
2.70% Senior unsecured notes due 2019 (1)
|
$
|
400.0
|
|
|
$
|
—
|
|
|
$
|
400.0
|
|
|
$
|
400.0
|
|
|
$
|
(0.1
|
)
|
|
$
|
399.9
|
|
Term Loan due 2021 (2)
|
850.0
|
|
|
—
|
|
|
850.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
4.40% Senior unsecured notes due 2024
|
550.0
|
|
|
1.8
|
|
|
551.8
|
|
|
550.0
|
|
|
2.2
|
|
|
552.2
|
|
||||||
4.15% Senior unsecured notes due 2025
|
750.0
|
|
|
(0.9
|
)
|
|
749.1
|
|
|
750.0
|
|
|
(1.0
|
)
|
|
749.0
|
|
||||||
4.85% Senior unsecured notes due 2026
|
500.0
|
|
|
(0.5
|
)
|
|
499.5
|
|
|
500.0
|
|
|
(0.6
|
)
|
|
499.4
|
|
||||||
5.60% Senior unsecured notes due 2044
|
350.0
|
|
|
(0.2
|
)
|
|
349.8
|
|
|
350.0
|
|
|
(0.2
|
)
|
|
349.8
|
|
||||||
5.05% Senior unsecured notes due 2045
|
450.0
|
|
|
(6.2
|
)
|
|
443.8
|
|
|
450.0
|
|
|
(6.5
|
)
|
|
443.5
|
|
||||||
5.45% Senior unsecured notes due 2047
|
500.0
|
|
|
(0.1
|
)
|
|
499.9
|
|
|
500.0
|
|
|
(0.1
|
)
|
|
499.9
|
|
||||||
Debt classified as long-term
|
$
|
4,350.0
|
|
|
$
|
(6.1
|
)
|
|
4,343.9
|
|
|
$
|
3,500.0
|
|
|
$
|
(6.3
|
)
|
|
3,493.7
|
|
||
Debt issuance cost (3)
|
|
|
|
|
(24.3
|
)
|
|
|
|
|
|
(25.9
|
)
|
||||||||||
Less: Current maturities of long-term debt (1)
|
|
|
|
|
(399.8
|
)
|
|
|
|
|
|
—
|
|
||||||||||
Long-term debt, net of unamortized issuance cost
|
|
|
|
|
$
|
3,919.8
|
|
|
|
|
|
|
$
|
3,467.8
|
|
(1)
|
The
2.70%
senior unsecured notes mature on April 1, 2019. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of
December 31, 2018
.
|
(2)
|
In December 2018, ENLK entered into an
$850.0 million
, three-year unsecured Term Loan. Borrowings under the Term Loan bear interest based on Prime and/or LIBOR plus an applicable margin.
The effective interest rate was
3.9%
at
December 31, 2018
.
|
(3)
|
Net of amortization of
$15.3 million
and
$12.0 million
at
December 31, 2018
and
2017
, respectively.
|
2019
|
$
|
400.0
|
|
2020
|
—
|
|
|
2021
|
850.0
|
|
|
2022
|
—
|
|
|
2023
|
—
|
|
|
Thereafter
|
3,100.0
|
|
|
Subtotal
|
4,350.0
|
|
|
Less: net discount
|
(6.1
|
)
|
|
Less: debt issuance cost
|
(24.3
|
)
|
|
Less: current maturities of long-term debt
|
(399.8
|
)
|
|
Long-term debt, net of unamortized issuance cost
|
$
|
3,919.8
|
|
Issuance
|
|
Maturity Date of Notes
|
|
Early Redemption Date
|
|
Basis Point Premium
|
2019 Notes
|
|
April 1, 2019
|
|
Prior to March 1, 2019
|
|
20 Basis Points
|
2024 Notes
|
|
April 1, 2024
|
|
Prior to January 1, 2024
|
|
25 Basis Points
|
2025 Notes
|
|
June 1, 2025
|
|
Prior to March 1, 2025
|
|
30 Basis Points
|
2026 Notes
|
|
July 15, 2026
|
|
Prior to April 15, 2026
|
|
50 Basis Points
|
2044 Notes
|
|
April 1, 2044
|
|
Prior to October 1, 2043
|
|
30 Basis Points
|
2045 Notes
|
|
April 1, 2045
|
|
Prior to October 1, 2044
|
|
30 Basis Points
|
2047 Notes
|
|
June 1, 2047
|
|
Prior to June 1, 2047
|
|
40 Basis Points
|
•
|
failure to pay any principal or interest when due;
|
•
|
failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures; and
|
•
|
bankruptcy or other insolvency events involving
us.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Current income tax provision
|
$
|
1.8
|
|
|
$
|
2.6
|
|
|
$
|
1.9
|
|
Deferred tax benefit
|
(3.9
|
)
|
|
(26.6
|
)
|
|
(0.6
|
)
|
|||
Total income tax provision (benefit)
|
$
|
(2.1
|
)
|
|
$
|
(24.0
|
)
|
|
$
|
1.3
|
|
Declaration period
|
|
Distribution
paid as additional Series B Preferred Units |
|
Cash distribution
(in millions) |
|
Date paid/payable
|
|||
2018
|
|
|
|
|
|
|
|||
First Quarter of 2018
|
|
416,657
|
|
|
$
|
16.2
|
|
|
May 14, 2018
|
Second Quarter of 2018
|
|
419,678
|
|
|
$
|
16.3
|
|
|
August 13, 2018
|
Third Quarter of 2018
|
|
422,720
|
|
|
$
|
16.4
|
|
|
November 13, 2018
|
Fourth Quarter of 2018
|
|
425,785
|
|
|
$
|
16.5
|
|
|
February 13, 2019
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|||
First Quarter of 2017
|
|
1,154,147
|
|
|
$
|
—
|
|
|
May 12, 2017
|
Second Quarter of 2017
|
|
1,178,672
|
|
|
$
|
—
|
|
|
August 11, 2017
|
Third Quarter of 2017
|
|
410,681
|
|
|
$
|
15.9
|
|
|
November 13, 2017
|
Fourth Quarter of 2017
|
|
413,658
|
|
|
$
|
16.1
|
|
|
February 13, 2018
|
|
|
|
|
|
|
|
|||
2016
|
|
|
|
|
|
|
|||
First Quarter of 2016
|
|
992,445
|
|
|
$
|
—
|
|
|
May 12, 2016
|
Second Quarter of 2016
|
|
1,083,589
|
|
|
$
|
—
|
|
|
August 11, 2016
|
Third Quarter of 2016
|
|
1,106,616
|
|
|
$
|
—
|
|
|
November 10, 2016
|
Fourth Quarter of 2016
|
|
1,130,131
|
|
|
$
|
—
|
|
|
February 13, 2017
|
Declaration period
|
|
Distribution/unit
|
|
Date paid/payable
|
||
2018
|
|
|
|
|
||
First Quarter of 2018
|
|
$
|
0.390
|
|
|
May 14, 2018
|
Second Quarter of 2018
|
|
$
|
0.390
|
|
|
August 13, 2018
|
Third Quarter of 2018
|
|
$
|
0.390
|
|
|
November 13, 2018
|
Fourth Quarter of 2018
|
|
$
|
0.390
|
|
|
February 13, 2019
|
|
|
|
|
|
||
2017
|
|
|
|
|
||
First Quarter of 2017
|
|
$
|
0.390
|
|
|
May 12, 2017
|
Second Quarter of 2017
|
|
$
|
0.390
|
|
|
August 11, 2017
|
Third Quarter of 2017
|
|
$
|
0.390
|
|
|
November 13, 2017
|
Fourth Quarter of 2017
|
|
$
|
0.390
|
|
|
February 13, 2018
|
|
|
|
|
|
||
2016
|
|
|
|
|
||
First Quarter of 2016
|
|
$
|
0.390
|
|
|
May 12, 2016
|
Second Quarter of 2016
|
|
$
|
0.390
|
|
|
August 11, 2016
|
Third Quarter of 2016
|
|
$
|
0.390
|
|
|
November 11, 2016
|
Fourth Quarter of 2016
|
|
$
|
0.390
|
|
|
February 13, 2017
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Distributed earnings allocated to:
|
|
|
|
|
|
||||||
Common units (1)
|
$
|
548.1
|
|
|
$
|
541.2
|
|
|
$
|
520.0
|
|
Unvested restricted units (1)
|
4.4
|
|
|
4.0
|
|
|
3.5
|
|
|||
Total distributed earnings
|
$
|
552.5
|
|
|
$
|
545.2
|
|
|
$
|
523.5
|
|
Undistributed loss allocated to:
|
|
|
|
|
|
||||||
Common units
|
$
|
(727.5
|
)
|
|
$
|
(523.5
|
)
|
|
$
|
(1,177.6
|
)
|
Unvested restricted units
|
(5.8
|
)
|
|
(3.8
|
)
|
|
(8.0
|
)
|
|||
Total undistributed loss
|
$
|
(733.3
|
)
|
|
$
|
(527.3
|
)
|
|
$
|
(1,185.6
|
)
|
Net income (loss) allocated to:
|
|
|
|
|
|
||||||
Common units
|
$
|
(179.4
|
)
|
|
$
|
17.7
|
|
|
$
|
(657.6
|
)
|
Unvested restricted units
|
(1.4
|
)
|
|
0.2
|
|
|
(4.5
|
)
|
|||
Total limited partners’ interest in net income (loss)
|
$
|
(180.8
|
)
|
|
$
|
17.9
|
|
|
$
|
(662.1
|
)
|
Basic and diluted net income (loss) per unit:
|
|
|
|
|
|
||||||
Basic
|
$
|
(0.51
|
)
|
|
$
|
0.05
|
|
|
$
|
(1.99
|
)
|
Diluted
|
$
|
(0.51
|
)
|
|
$
|
0.05
|
|
|
$
|
(1.99
|
)
|
(1)
|
Represents distribution activity consistent with the distribution activity table in section “(e) Common Unit Distributions” above.
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Basic weighted average units outstanding:
|
|
|
|
|
|
|||
Weighted average limited partner basic common units outstanding (1)
|
351.3
|
|
|
346.9
|
|
|
333.3
|
|
|
|
|
|
|
|
|||
Diluted weighted average units outstanding:
|
|
|
|
|
|
|||
Weighted average limited partner basic common units outstanding (1)
|
351.3
|
|
|
346.9
|
|
|
333.3
|
|
Dilutive effect of non-vested restricted units (2)
|
—
|
|
|
1.4
|
|
|
—
|
|
Total weighted average limited partner diluted common units outstanding
|
351.3
|
|
|
348.3
|
|
|
333.3
|
|
(1)
|
Weighted average limited partner basic common units outstanding for the years ended December 31, 2016 included the weighted average impact of
2,740,273
Class C Units, which converted into common units on May 13, 2016.
|
(2)
|
All common unit equivalents were antidilutive for the years ended
December 31, 2018
and
2016
because the limited partners were allocated a net loss.
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Income allocation for incentive distributions
|
$
|
59.5
|
|
|
$
|
58.9
|
|
|
$
|
56.8
|
|
Unit-based compensation attributable to ENLC’s restricted units
|
(20.3
|
)
|
|
(21.0
|
)
|
|
(14.7
|
)
|
|||
General partner share of net income (loss)
|
(0.6
|
)
|
|
0.4
|
|
|
(2.6
|
)
|
|||
General partner interest in net income
|
$
|
38.6
|
|
|
$
|
38.3
|
|
|
$
|
39.5
|
|
•
|
a
38.75%
ownership interest in GCF at
December 31, 2018
,
2017
,
and
2016
;
|
•
|
an approximate
30.0%
ownership in the Cedar Cove JV at
December 31, 2018
, 2017, and 2016. On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc.; and
|
•
|
an approximate
31%
ownership interest in HEP at
December 31, 2016
, which was sold in March 2017 for aggregate net proceeds of
$189.7 million
.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
GCF
|
|
|
|
|
|
|
||||||
Distributions
|
|
$
|
22.3
|
|
|
$
|
12.7
|
|
|
$
|
7.5
|
|
Equity in income
|
|
$
|
15.8
|
|
|
$
|
12.6
|
|
|
$
|
3.4
|
|
|
|
|
|
|
|
|
||||||
HEP
|
|
|
|
|
|
|
||||||
Contributions (1)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
45.0
|
|
Distributions (2)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
50.2
|
|
Equity in income (loss) (3)
|
|
$
|
—
|
|
|
$
|
(3.4
|
)
|
|
$
|
(23.3
|
)
|
|
|
|
|
|
|
|
||||||
Cedar Cove JV
|
|
|
|
|
|
|
||||||
Contributions
|
|
$
|
0.1
|
|
|
$
|
12.6
|
|
|
$
|
28.8
|
|
Distributions
|
|
$
|
0.4
|
|
|
$
|
0.8
|
|
|
$
|
—
|
|
Equity in income
|
|
$
|
(2.5
|
)
|
|
$
|
0.4
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||||||
Total
|
|
|
|
|
|
|
||||||
Contributions (1)
|
|
$
|
0.1
|
|
|
$
|
12.6
|
|
|
$
|
73.8
|
|
Distributions (2)
|
|
$
|
22.7
|
|
|
$
|
13.5
|
|
|
$
|
57.7
|
|
Equity in income (loss) (3)
|
|
$
|
13.3
|
|
|
$
|
9.6
|
|
|
$
|
(19.9
|
)
|
(1)
|
Contributions for the year ended
December 31, 2016
included
$32.7 million
of contributions to HEP for preferred units issued by HEP. These preferred units were redeemed during the third quarter 2016.
|
(2)
|
Distributions for the year ended
December 31, 2016
included a redemption of
$32.7 million
of preferred units issued by HEP.
|
(3)
|
Included losses of
$3.4 million
and
$20.1 million
for the years ended
December 31, 2017
and
2016
, respectively, related to the sale of our HEP interests.
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
GCF
|
$
|
41.9
|
|
|
$
|
48.4
|
|
Cedar Cove JV
|
38.2
|
|
|
41.0
|
|
||
Total investments in unconsolidated affiliates
|
$
|
80.1
|
|
|
$
|
89.4
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cost of unit-based compensation charged to general and administrative expense
|
$
|
30.0
|
|
|
$
|
37.1
|
|
|
$
|
23.4
|
|
Cost of unit-based compensation charged to operating expense
|
10.8
|
|
|
10.7
|
|
|
6.6
|
|
|||
Total unit-based compensation expense
|
$
|
40.8
|
|
|
$
|
47.8
|
|
|
$
|
30.0
|
|
|
|
Year Ended December 31, 2018
|
||||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
Number of Units
|
|
Weighted Average
Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
1,980,224
|
|
|
$
|
15.81
|
|
|
Granted (1)
|
|
1,590,100
|
|
|
15.27
|
|
||
Vested (1)(2)
|
|
(835,115
|
)
|
|
19.68
|
|
||
Forfeited
|
|
(178,939
|
)
|
|
12.75
|
|
||
Non-vested, end of period
|
|
2,556,270
|
|
|
$
|
14.43
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
28.1
|
|
|
|
(1)
|
Restricted incentive units typically vest at the end of three years. In March 2018,
our general partner granted
200,753
restricted incentive units with a fair value of
$3.0 million
to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
|
(2)
|
Vested units include
261,063
units withheld for payroll taxes paid on behalf of employees.
|
|
|
Year Ended December 31,
|
||||||||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
2018
|
|
2017
|
|
2016
|
||||||
Aggregate intrinsic value of units vested
|
|
$
|
13.1
|
|
|
$
|
16.6
|
|
|
$
|
4.1
|
|
Fair value of units vested
|
|
$
|
16.4
|
|
|
$
|
22.6
|
|
|
$
|
9.5
|
|
EnLink Midstream Partners, LP Performance Units:
|
|
March 2018
|
|
March 2017
|
|
October 2016
|
|
February 2016
|
|
January 2016
|
|||||
TSR price
|
|
$15.44
|
|
$17.55
|
|
$17.71
|
|
$14.82
|
|
$14.82
|
|||||
Risk-free interest rate
|
|
2.38
|
%
|
|
1.62
|
%
|
|
0.91
|
%
|
|
0.89
|
%
|
|
1.10
|
%
|
Volatility factor
|
|
43.85
|
%
|
|
43.94
|
%
|
|
44.62
|
%
|
|
42.33
|
%
|
|
39.71
|
%
|
Distribution yield
|
|
10.50
|
%
|
|
8.70
|
%
|
|
8.80
|
%
|
|
19.20
|
%
|
|
12.10
|
%
|
|
|
Year Ended December 31, 2018
|
||||||
EnLink Midstream Partners, LP Performance Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
585,285
|
|
|
$
|
20.52
|
|
|
Granted
|
|
256,345
|
|
|
19.24
|
|
||
Vested (1)
|
|
(313,610
|
)
|
|
24.43
|
|
||
Forfeited
|
|
(76,351
|
)
|
|
16.62
|
|
||
Non-vested, end of period
|
|
451,669
|
|
|
$
|
17.74
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
5.0
|
|
|
|
(1)
|
Vested units included
112,101
units withheld for payroll taxes paid on behalf of employees and
120,250
units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.
|
EnLink Midstream Partners, LP Performance Units:
|
|
Year Ended December 31, 2018
|
||
Aggregate intrinsic value of units vested
|
|
$
|
5.0
|
|
Fair value of units vested
|
|
$
|
7.7
|
|
|
|
Year Ended December 31, 2018
|
||||||
EnLink Midstream, LLC Restricted Incentive Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
1,889,310
|
|
|
$
|
16.33
|
|
|
Granted (1)
|
|
1,473,195
|
|
|
15.76
|
|
||
Vested (1)(2)
|
|
(769,848
|
)
|
|
21.40
|
|
||
Forfeited
|
|
(166,790
|
)
|
|
12.74
|
|
||
Non-vested, end of period
|
|
2,425,867
|
|
|
$
|
14.62
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
23.0
|
|
|
|
(1)
|
Restricted incentive units typically vest at the end of three years. In March 2018, ENLC granted
194,185
restricted incentive units with a fair value of
$3.0 million
to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
|
(2)
|
Vested units include
244,123
units withheld for payroll taxes paid on behalf of employees.
|
|
|
Year Ended December 31,
|
||||||||||
EnLink Midstream, LLC Restricted Incentive Units:
|
|
2018
|
|
2017
|
|
2016
|
||||||
Aggregate intrinsic value of units vested
|
|
$
|
12.8
|
|
|
$
|
15.3
|
|
|
$
|
4.1
|
|
Fair value of units vested
|
|
$
|
16.5
|
|
|
$
|
22.2
|
|
|
$
|
12.4
|
|
EnLink Midstream, LLC Performance Units:
|
|
March 2018
|
|
March 2017
|
|
October 2016
|
|
February 2016
|
|
January 2016
|
||||||||||
TSR price
|
|
$
|
16.55
|
|
|
$
|
18.29
|
|
|
$
|
16.75
|
|
|
$
|
15.38
|
|
|
$
|
15.38
|
|
Risk-free interest rate
|
|
2.38
|
%
|
|
1.62
|
%
|
|
0.91
|
%
|
|
0.89
|
%
|
|
1.10
|
%
|
|||||
Volatility factor
|
|
51.36
|
%
|
|
52.07
|
%
|
|
52.89
|
%
|
|
52.05
|
%
|
|
46.02
|
%
|
|||||
Distribution yield
|
|
6.70
|
%
|
|
5.40
|
%
|
|
6.10
|
%
|
|
14.00
|
%
|
|
8.60
|
%
|
|
|
Year Ended December 31, 2018
|
||||||
EnLink Midstream, LLC Performance Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
548,839
|
|
|
$
|
22.14
|
|
|
Granted
|
|
223,865
|
|
|
21.63
|
|
||
Vested (1)
|
|
(283,637
|
)
|
|
27.25
|
|
||
Forfeited
|
|
(70,918
|
)
|
|
17.75
|
|
||
Non-vested, end of period
|
|
418,149
|
|
|
$
|
19.15
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
4.0
|
|
|
|
(1)
|
Vested units included
100,109
units withheld for payroll taxes paid on behalf of employees and
109,819
units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.
|
EnLink Midstream, LLC Performance Units:
|
|
Year Ended December 31, 2018
|
||
Aggregate intrinsic value of units vested
|
|
$
|
4.7
|
|
Fair value of units vested
|
|
$
|
7.7
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Change in fair value of derivatives
|
$
|
10.1
|
|
|
$
|
4.7
|
|
|
$
|
(20.1
|
)
|
Realized gain (loss) on derivatives
|
(4.9
|
)
|
|
(8.9
|
)
|
|
9.0
|
|
|||
Gain (loss) on derivative activity
|
$
|
5.2
|
|
|
$
|
(4.2
|
)
|
|
$
|
(11.1
|
)
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Fair value of derivative assets — current
|
$
|
28.6
|
|
|
$
|
6.8
|
|
Fair value of derivative assets — long-term
|
4.1
|
|
|
—
|
|
||
Fair value of derivative liabilities — current
|
(21.8
|
)
|
|
(8.4
|
)
|
||
Fair value of derivative liabilities — long-term
|
(2.4
|
)
|
|
—
|
|
||
Net fair value of derivatives
|
$
|
8.5
|
|
|
$
|
(1.6
|
)
|
|
|
|
|
December 31, 2018
|
|||||||
Commodity
|
|
Instruments
|
|
Unit
|
|
Volume
|
|
|
Fair Value
|
||
NGL (short contracts)
|
|
Swaps
|
|
Gallons
|
|
(29.0
|
)
|
|
$
|
4.5
|
|
NGL (long contracts)
|
|
Swaps
|
|
Gallons
|
|
7.7
|
|
|
0.1
|
|
|
Natural Gas (short contracts)
|
|
Swaps
|
|
MMBtu
|
|
(9.0
|
)
|
|
(1.6
|
)
|
|
Natural Gas (long contracts)
|
|
Swaps
|
|
MMBtu
|
|
14.9
|
|
|
(1.5
|
)
|
|
Crude and Condensate (short contracts)
|
|
Swaps
|
|
MMbbls
|
|
(12.9
|
)
|
|
23.6
|
|
|
Crude and Condensate (long contracts)
|
|
Swaps
|
|
MMbbls
|
|
1.0
|
|
|
(16.6
|
)
|
|
Total fair value of derivatives
|
|
|
|
|
|
|
|
$
|
8.5
|
|
|
Level 2
|
||||||
|
December 31, 2018
|
|
December 31, 2017
|
||||
Commodity Swaps (1)
|
$
|
8.5
|
|
|
$
|
(1.6
|
)
|
(1)
|
The fair values of derivative contracts included in assets or liabilities for risk management activities represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
||||||||
Long-term debt, including current maturities of long-term debt (1)
|
$
|
4,319.6
|
|
|
$
|
3,953.6
|
|
|
$
|
3,467.8
|
|
|
$
|
3,575.6
|
|
Installment Payables
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
249.5
|
|
|
$
|
249.6
|
|
Obligations under capital lease
|
$
|
2.5
|
|
|
$
|
2.2
|
|
|
$
|
4.1
|
|
|
$
|
3.4
|
|
Secured term loan receivable
|
$
|
51.1
|
|
|
$
|
51.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of
$24.3 million
and
$25.9 million
at
December 31, 2018
and
2017
, respectively. The respective fair values do not factor in debt issuance costs.
|
2019
|
$
|
14.1
|
|
2020
|
10.3
|
|
|
2021
|
8.7
|
|
|
2022
|
8.6
|
|
|
2023
|
8.8
|
|
|
Thereafter
|
49.8
|
|
|
Total
|
$
|
100.3
|
|
|
Texas
|
|
Louisiana
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
292.9
|
|
|
$
|
531.1
|
|
|
$
|
189.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,013.7
|
|
NGL sales
|
28.6
|
|
|
2,786.3
|
|
|
25.2
|
|
|
0.9
|
|
|
—
|
|
|
2,841.0
|
|
||||||
Crude oil and condensate sales
|
—
|
|
|
0.5
|
|
|
0.7
|
|
|
2,656.4
|
|
|
—
|
|
|
2,657.6
|
|
||||||
Product sales
|
321.5
|
|
|
3,317.9
|
|
|
215.6
|
|
|
2,657.3
|
|
|
—
|
|
|
6,512.3
|
|
||||||
Natural gas sales—related parties
|
—
|
|
|
—
|
|
|
2.5
|
|
|
—
|
|
|
—
|
|
|
2.5
|
|
||||||
NGL sales—related parties
|
503.5
|
|
|
47.4
|
|
|
590.8
|
|
|
—
|
|
|
(1,104.3
|
)
|
|
37.4
|
|
||||||
Crude oil and condensate sales—related parties
|
49.3
|
|
|
0.3
|
|
|
85.6
|
|
|
3.3
|
|
|
(137.4
|
)
|
|
1.1
|
|
||||||
Product sales—related parties
|
552.8
|
|
|
47.7
|
|
|
678.9
|
|
|
3.3
|
|
|
(1,241.7
|
)
|
|
41.0
|
|
||||||
Gathering and transportation
|
177.9
|
|
|
68.8
|
|
|
149.1
|
|
|
3.1
|
|
|
—
|
|
|
398.9
|
|
||||||
Processing
|
101.0
|
|
|
3.3
|
|
|
122.8
|
|
|
—
|
|
|
—
|
|
|
227.1
|
|
||||||
NGL services
|
—
|
|
|
59.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59.6
|
|
||||||
Crude services
|
—
|
|
|
—
|
|
|
0.6
|
|
|
66.5
|
|
|
—
|
|
|
67.1
|
|
||||||
Other services
|
9.6
|
|
|
0.6
|
|
|
0.2
|
|
|
0.2
|
|
|
—
|
|
|
10.6
|
|
||||||
Midstream services
|
288.5
|
|
|
132.3
|
|
|
272.7
|
|
|
69.8
|
|
|
—
|
|
|
763.3
|
|
||||||
Gathering and transportation—related parties
|
122.7
|
|
|
—
|
|
|
80.6
|
|
|
—
|
|
|
—
|
|
|
203.3
|
|
||||||
Processing—related parties
|
108.6
|
|
|
—
|
|
|
48.4
|
|
|
—
|
|
|
—
|
|
|
157.0
|
|
||||||
NGL services—related parties
|
—
|
|
|
3.3
|
|
|
—
|
|
|
—
|
|
|
(3.3
|
)
|
|
—
|
|
||||||
Crude services—related parties
|
—
|
|
|
—
|
|
|
1.5
|
|
|
14.9
|
|
|
—
|
|
|
16.4
|
|
||||||
Other services—related parties
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
||||||
Midstream services—related parties
|
231.8
|
|
|
3.3
|
|
|
130.5
|
|
|
14.9
|
|
|
(3.3
|
)
|
|
377.2
|
|
||||||
Revenue from contracts with customers
|
1,394.6
|
|
|
3,501.2
|
|
|
1,297.7
|
|
|
2,745.3
|
|
|
(1,245.0
|
)
|
|
7,693.8
|
|
||||||
Cost of sales
|
(753.9
|
)
|
|
(3,158.7
|
)
|
|
(744.0
|
)
|
|
(2,596.4
|
)
|
|
1,245.0
|
|
|
(6,008.0
|
)
|
||||||
Operating expenses
|
(180.6
|
)
|
|
(108.3
|
)
|
|
(89.2
|
)
|
|
(75.3
|
)
|
|
—
|
|
|
(453.4
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.2
|
|
|
5.2
|
|
||||||
Segment profit
|
$
|
460.1
|
|
|
$
|
234.2
|
|
|
$
|
464.5
|
|
|
$
|
73.6
|
|
|
$
|
5.2
|
|
|
$
|
1,237.6
|
|
Depreciation and amortization
|
$
|
(216.2
|
)
|
|
$
|
(122.7
|
)
|
|
$
|
(178.1
|
)
|
|
$
|
(51.6
|
)
|
|
$
|
(8.7
|
)
|
|
$
|
(577.3
|
)
|
Impairments
|
$
|
(232.0
|
)
|
|
$
|
(24.6
|
)
|
|
$
|
—
|
|
|
$
|
(109.2
|
)
|
|
$
|
—
|
|
|
$
|
(365.8
|
)
|
Goodwill
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
Capital expenditures
|
$
|
249.4
|
|
|
$
|
47.0
|
|
|
$
|
412.5
|
|
|
$
|
135.7
|
|
|
$
|
5.3
|
|
|
$
|
849.9
|
|
Total assets
|
$
|
2,925.3
|
|
|
$
|
2,347.9
|
|
|
$
|
3,116.5
|
|
|
$
|
959.3
|
|
|
$
|
222.3
|
|
|
$
|
9,571.3
|
|
|
Texas
|
|
Louisiana
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Product sales
|
$
|
325.0
|
|
|
$
|
2,529.6
|
|
|
$
|
128.8
|
|
|
$
|
1,375.0
|
|
|
$
|
—
|
|
|
$
|
4,358.4
|
|
Product sales—related parties
|
500.3
|
|
|
45.0
|
|
|
349.4
|
|
|
0.8
|
|
|
(750.6
|
)
|
|
144.9
|
|
||||||
Midstream services
|
116.3
|
|
|
220.6
|
|
|
155.0
|
|
|
60.4
|
|
|
—
|
|
|
552.3
|
|
||||||
Midstream services—related parties
|
424.3
|
|
|
136.4
|
|
|
241.6
|
|
|
17.4
|
|
|
(131.5
|
)
|
|
688.2
|
|
||||||
Cost of sales
|
(772.3
|
)
|
|
(2,618.1
|
)
|
|
(522.9
|
)
|
|
(1,330.3
|
)
|
|
882.1
|
|
|
(4,361.5
|
)
|
||||||
Operating expenses
|
(172.7
|
)
|
|
(101.3
|
)
|
|
(64.6
|
)
|
|
(80.1
|
)
|
|
—
|
|
|
(418.7
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.2
|
)
|
|
(4.2
|
)
|
||||||
Segment profit (loss)
|
$
|
420.9
|
|
|
$
|
212.2
|
|
|
$
|
287.3
|
|
|
$
|
43.2
|
|
|
$
|
(4.2
|
)
|
|
$
|
959.4
|
|
Depreciation and amortization
|
$
|
(215.2
|
)
|
|
$
|
(116.1
|
)
|
|
$
|
(156.6
|
)
|
|
$
|
(47.5
|
)
|
|
$
|
(9.9
|
)
|
|
$
|
(545.3
|
)
|
Impairments
|
$
|
—
|
|
|
$
|
(0.8
|
)
|
|
$
|
—
|
|
|
$
|
(16.3
|
)
|
|
$
|
—
|
|
|
$
|
(17.1
|
)
|
Goodwill
|
$
|
232.0
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
145.4
|
|
|
$
|
75.1
|
|
|
$
|
442.1
|
|
|
$
|
79.1
|
|
|
$
|
26.4
|
|
|
$
|
768.1
|
|
Total assets
|
$
|
3,094.8
|
|
|
$
|
2,408.5
|
|
|
$
|
2,836.7
|
|
|
$
|
929.5
|
|
|
$
|
144.5
|
|
|
$
|
9,414.0
|
|
|
Texas
|
|
Louisiana
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Product sales
|
$
|
237.2
|
|
|
$
|
1,632.5
|
|
|
$
|
48.5
|
|
|
$
|
1,090.7
|
|
|
$
|
—
|
|
|
$
|
3,008.9
|
|
Product sales—related parties
|
287.6
|
|
|
57.8
|
|
|
120.4
|
|
|
1.5
|
|
|
(333.0
|
)
|
|
134.3
|
|
||||||
Midstream services
|
104.2
|
|
|
215.4
|
|
|
82.2
|
|
|
65.4
|
|
|
—
|
|
|
467.2
|
|
||||||
Midstream services—related parties
|
439.3
|
|
|
95.8
|
|
|
185.9
|
|
|
18.9
|
|
|
(86.8
|
)
|
|
653.1
|
|
||||||
Cost of sales
|
(483.4
|
)
|
|
(1,729.0
|
)
|
|
(184.9
|
)
|
|
(1,038.0
|
)
|
|
419.8
|
|
|
(3,015.5
|
)
|
||||||
Operating expenses
|
(168.5
|
)
|
|
(96.6
|
)
|
|
(52.1
|
)
|
|
(81.3
|
)
|
|
—
|
|
|
(398.5
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11.1
|
)
|
|
(11.1
|
)
|
||||||
Segment profit (loss)
|
$
|
416.4
|
|
|
$
|
175.9
|
|
|
$
|
200.0
|
|
|
$
|
57.2
|
|
|
$
|
(11.1
|
)
|
|
$
|
838.4
|
|
Depreciation and amortization
|
$
|
(196.9
|
)
|
|
$
|
(114.8
|
)
|
|
$
|
(140.6
|
)
|
|
$
|
(42.4
|
)
|
|
$
|
(9.2
|
)
|
|
$
|
(503.9
|
)
|
Impairments
|
$
|
(473.1
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(93.2
|
)
|
|
$
|
—
|
|
|
$
|
(566.3
|
)
|
Goodwill
|
$
|
232.0
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
217.9
|
|
|
$
|
79.1
|
|
|
$
|
295.7
|
|
|
$
|
74.3
|
|
|
$
|
9.1
|
|
|
$
|
676.1
|
|
Total assets
|
$
|
3,142.6
|
|
|
$
|
2,349.3
|
|
|
$
|
2,524.5
|
|
|
$
|
836.8
|
|
|
$
|
300.2
|
|
|
$
|
9,153.4
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Segment profit
|
$
|
1,237.6
|
|
|
$
|
959.4
|
|
|
$
|
838.4
|
|
General and administrative expenses
|
(130.2
|
)
|
|
(123.5
|
)
|
|
(119.3
|
)
|
|||
Depreciation and amortization
|
(577.3
|
)
|
|
(545.3
|
)
|
|
(503.9
|
)
|
|||
Loss on disposition of assets
|
(0.4
|
)
|
|
—
|
|
|
(13.2
|
)
|
|||
Impairments
|
(365.8
|
)
|
|
(17.1
|
)
|
|
(566.3
|
)
|
|||
Gain on litigation settlement
|
—
|
|
|
26.0
|
|
|
—
|
|
|||
Operating income (loss)
|
$
|
163.9
|
|
|
$
|
299.5
|
|
|
$
|
(364.3
|
)
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
|
Total
|
||||||||||
2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
1,761.7
|
|
|
$
|
1,764.7
|
|
|
$
|
2,114.3
|
|
|
$
|
2,058.3
|
|
|
$
|
7,699.0
|
|
Impairments
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24.6
|
|
|
$
|
341.2
|
|
|
$
|
365.8
|
|
Operating income (loss)
|
$
|
106.6
|
|
|
$
|
150.1
|
|
|
$
|
92.5
|
|
|
$
|
(185.3
|
)
|
|
$
|
163.9
|
|
Net income (loss) attributable to ENLK
|
$
|
60.1
|
|
|
$
|
98.9
|
|
|
$
|
43.2
|
|
|
$
|
(230.2
|
)
|
|
$
|
(28.0
|
)
|
General partner interest in net income
|
$
|
10.6
|
|
|
$
|
11.2
|
|
|
$
|
7.7
|
|
|
$
|
9.1
|
|
|
$
|
38.6
|
|
Limited partners' interest in net income (loss) attributable to ENLK
|
$
|
21.6
|
|
|
$
|
58.9
|
|
|
$
|
5.2
|
|
|
$
|
(266.5
|
)
|
|
$
|
(180.8
|
)
|
Net income (loss) attributable to ENLK per limited partners’ unit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic common unit
|
$
|
0.06
|
|
|
$
|
0.17
|
|
|
$
|
0.01
|
|
|
$
|
(0.75
|
)
|
|
$
|
(0.51
|
)
|
Diluted common unit
|
$
|
0.06
|
|
|
$
|
0.17
|
|
|
$
|
0.01
|
|
|
$
|
(0.75
|
)
|
|
$
|
(0.51
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
1,321.9
|
|
|
$
|
1,263.6
|
|
|
$
|
1,397.9
|
|
|
$
|
1,756.2
|
|
|
$
|
5,739.6
|
|
Impairments
|
$
|
7.0
|
|
|
$
|
—
|
|
|
$
|
1.8
|
|
|
$
|
8.3
|
|
|
$
|
17.1
|
|
Operating income
|
$
|
57.6
|
|
|
$
|
70.4
|
|
|
$
|
73.4
|
|
|
$
|
98.1
|
|
|
$
|
299.5
|
|
Net income attributable to ENLK
|
$
|
18.1
|
|
|
$
|
29.6
|
|
|
$
|
25.5
|
|
|
$
|
75.7
|
|
|
$
|
148.9
|
|
General partner interest in net income
|
$
|
5.9
|
|
|
$
|
10.8
|
|
|
$
|
10.6
|
|
|
$
|
11.0
|
|
|
$
|
38.3
|
|
Limited partners' interest in net income (loss) attributable to ENLK
|
$
|
(9.3
|
)
|
|
$
|
(0.5
|
)
|
|
$
|
(8.6
|
)
|
|
$
|
36.3
|
|
|
$
|
17.9
|
|
Net income (loss) attributable to ENLK per limited partners’ unit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic common unit
|
$
|
(0.03
|
)
|
|
$
|
—
|
|
|
$
|
(0.02
|
)
|
|
$
|
0.10
|
|
|
$
|
0.05
|
|
Diluted common unit
|
$
|
(0.03
|
)
|
|
$
|
—
|
|
|
$
|
(0.02
|
)
|
|
$
|
0.10
|
|
|
$
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
889.7
|
|
|
$
|
1,033.2
|
|
|
$
|
1,104.6
|
|
|
$
|
1,224.9
|
|
|
$
|
4,252.4
|
|
Impairments
|
$
|
566.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
566.3
|
|
Operating income (loss)
|
$
|
(515.9
|
)
|
|
$
|
46.4
|
|
|
$
|
66.9
|
|
|
$
|
38.3
|
|
|
$
|
(364.3
|
)
|
Net income (loss) attributable to ENLK
|
$
|
(560.4
|
)
|
|
$
|
5.0
|
|
|
$
|
18.8
|
|
|
$
|
(28.6
|
)
|
|
$
|
(565.2
|
)
|
General partner interest in net income
|
$
|
7.4
|
|
|
$
|
10.6
|
|
|
$
|
10.8
|
|
|
$
|
10.7
|
|
|
$
|
39.5
|
|
Limited partners' interest in net loss attributable to ENLK
|
$
|
(567.2
|
)
|
|
$
|
(23.5
|
)
|
|
$
|
(11.4
|
)
|
|
$
|
(60.0
|
)
|
|
$
|
(662.1
|
)
|
Net loss attributable to ENLK per limited partners’ unit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic common unit
|
$
|
(1.74
|
)
|
|
$
|
(0.07
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
(1.99
|
)
|
Diluted common unit
|
$
|
(1.74
|
)
|
|
$
|
(0.07
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
(1.99
|
)
|
|
|
Year Ended December 31,
|
||||||||||
Supplemental disclosures of cash flow information:
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash paid for interest
|
|
$
|
182.6
|
|
|
$
|
163.8
|
|
|
$
|
132.5
|
|
Cash paid for income taxes
|
|
$
|
1.5
|
|
|
$
|
4.8
|
|
|
$
|
2.8
|
|
|
|
|
|
|
|
|
||||||
Non-cash investing activities:
|
|
|
|
|
|
|
||||||
Non-cash accrual of property and equipment
|
|
$
|
6.8
|
|
|
$
|
(22.7
|
)
|
|
$
|
13.1
|
|
Discounted secured term loan receivable from contract restructuring
|
|
$
|
47.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||||||
Non-cash financing activities:
|
|
|
|
|
|
|
||||||
Installment payable, net of discount of $79.1 million (1)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
420.9
|
|
Contribution from ENLC (2)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
237.1
|
|
(1)
|
We
incurred installment purchase obligations, net of discount, payable to the seller in connection with the EOGP assets.
We
paid the second and final installments during January 2017 and 2018, respectively. See “
Note 3—Acquisition
” for further discussion.
|
(2)
|
Contribution from ENLC in connection with the acquisition of the EOGP assets. See “
Note 3—Acquisition
” for further discussion.
|
Other Current Assets:
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Natural gas and NGLs inventory
|
|
$
|
41.3
|
|
|
$
|
30.1
|
|
Secured term loan receivable from contract restructuring, net of discount of $1.1
|
|
19.4
|
|
|
—
|
|
||
Prepaid expenses and other
|
|
12.1
|
|
|
9.6
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
|
$
|
72.8
|
|
|
$
|
39.7
|
|
Other Current Liabilities:
|
|
December 31, 2018
|
|
|
December 31, 2017
|
|
||
Accrued interest
|
|
$
|
37.3
|
|
|
$
|
35.4
|
|
Accrued wages and benefits, including taxes
|
|
37.2
|
|
|
30.4
|
|
||
Accrued ad valorem taxes
|
|
28.1
|
|
|
27.8
|
|
||
Capital expenditure accruals
|
|
50.6
|
|
|
48.8
|
|
||
Onerous performance obligations
|
|
9.0
|
|
|
15.2
|
|
||
Other
|
|
84.5
|
|
|
64.8
|
|
||
Other current liabilities
|
|
$
|
246.7
|
|
|
$
|
222.4
|
|
•
|
Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) has been converted into the right to receive
1.15
ENLC common units.
|
•
|
Our general partner’s
incentive distribution rights in ENLK have been eliminated.
|
•
|
The Series B Preferred Units will continue to be issued and outstanding following the Merger, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership agreement of ENLK. See
“
Note 8—Partners' Capital
”
for additional information regarding the modified terms of the Series B Preferred Units.
|
•
|
ENLC issued to Enfield, the current holder of the Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled.
|
•
|
The Series C Preferred Units and all of ENLK’s senior notes continue to be issued and outstanding following the Merger.
|
•
|
All unit-based awards issued and outstanding immediately prior to the effective time of the Merger under the GP Plan have been converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time, with certain adjustments to the performance-based vesting of terms of applicable awards related to the performance of ENLC.
|
•
|
ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof.
|
Name
|
|
Age
|
|
Position with EnLink Midstream GP, LLC
|
Michael J. Garberding
|
|
50
|
|
President, Chief Executive Officer, and Director
|
Eric D. Batchelder
|
|
47
|
|
Executive Vice President and Chief Financial Officer
|
Benjamin D. Lamb
|
|
39
|
|
Executive Vice President and Chief Operating Officer
|
Alaina K. Brooks
|
|
44
|
|
Executive Vice President, Chief Legal and Administrative Officer, Secretary, and Director
|
Barry E. Davis
|
|
57
|
|
Director and Executive Chairman
|
Executive Officer
|
|
Percentage of Time Devoted to Business of ENLK
|
|
Percentage of Time Devoted to Business of ENLC
|
||
Michael J. Garberding
|
|
50
|
%
|
|
50
|
%
|
Benjamin D. Lamb (1)
|
|
70
|
%
|
|
30
|
%
|
Barry E. Davis
|
|
60
|
%
|
|
40
|
%
|
Eric Batchelder
|
|
60
|
%
|
|
40
|
%
|
Alaina K. Brooks (1)
|
|
70
|
%
|
|
30
|
%
|
McMillan Hummel (2)
|
|
90
|
%
|
|
10
|
%
|
(1)
|
In June 2018, Mr. Lamb was promoted to Executive Vice President and Chief Operating Officer and Ms. Brooks was promoted to Executive Vice President, Chief Legal and Administrative Officer, and Secretary.
|
(2)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
•
|
Base salary, short-term incentives and long-term incentives should be competitive with the market in which we compete for executive talent in order to attract, retain, and motivate highly qualified executives;
|
•
|
Equity-based awards under the long-term incentive plans should represent a significant portion of the executive’s total compensation in order to retain and incentivize highly qualified executives and to ensure all executives have a meaningful equity stake in us. Equity-based awards foster a culture of ownership and are a way to align the interests of executives with those of our unitholders;
|
•
|
The compensation program should be sufficiently flexible to address special circumstances, including retention initiatives specifically targeted to retain highly qualified executives during challenging times; and
|
•
|
The compensation program should drive performance and reward contributions in support of our business strategies and achievements.
|
•
|
base salary;
|
•
|
annual bonus awards;
|
•
|
long-term incentive plan equity awards;
|
•
|
retirement and health benefits; and
|
•
|
severance and change of control benefits.
|
|
Prior Salary
|
|
Base Salary Effective
For 2019 |
|
Percent Increase (Decrease)
|
|||||
Michael J. Garberding
|
$
|
650,000
|
|
|
$
|
675,000
|
|
|
3.8
|
%
|
Benjamin D. Lamb (1)
|
$
|
475,000
|
|
|
$
|
491,625
|
|
|
3.5
|
%
|
Barry E. Davis
|
$
|
525,000
|
|
|
$
|
425,000
|
|
|
(19.0
|
)%
|
Eric D. Batchelder
|
$
|
435,000
|
|
|
$
|
450,225
|
|
|
3.5
|
%
|
Alaina K. Brooks (1)
|
$
|
425,000
|
|
|
$
|
439,875
|
|
|
3.5
|
%
|
McMillan Hummel (2)
|
$
|
435,000
|
|
|
$
|
—
|
|
|
(100.0
|
)%
|
(1)
|
In June 2018, Mr. Lamb was promoted to Executive Vice President and Chief Operating Officer and Ms. Brooks was promoted to Executive Vice President, Chief Legal and Administrative Officer, and Secretary.
|
(2)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
Component
|
|
Description
|
|
Weighting
|
Financial
|
|
Adjusted EBITDA and cost management to maximize financial performance
|
|
50% Adjusted EBITDA
10% Cost management |
Growth
|
|
Timely and cost-effective growth pursuant to the Strategic Plan and overarching direction
|
|
10%
|
Operational
|
|
Efficient use of systems, assets and equipment for meeting contractual obligations, driving customer service and maximizing cash flow
|
|
10%
|
People
|
|
Train and develop our workforce
|
|
10%
|
Environmental and Safety
|
|
Prevent safety incidents and improve safety compliance, operations, and training
|
|
10%
|
|
|
Target Bonus Percentage (as a % of Base Salary)
|
|
2018 Bonus (as a % of Base Salary)
|
|
2018 Bonus Amount ($)
|
|||
Michael J. Garberding
|
|
100
|
%
|
|
155
|
%
|
|
1,009,247
|
|
Benjamin D. Lamb (1)
|
|
100
|
%
|
|
140
|
%
|
|
665,733
|
|
Barry E. Davis
|
|
95
|
%
|
|
149
|
%
|
|
784,367
|
|
Eric D. Batchelder
|
|
90
|
%
|
|
129
|
%
|
|
560,771
|
|
Alaina K. Brooks (1)
|
|
90
|
%
|
|
110
|
%
|
|
468,087
|
|
McMillan Hummel (2)
|
|
90
|
%
|
|
83
|
%
|
|
362,474
|
|
(1)
|
In June 2018, Mr. Lamb was promoted to Executive Vice President and Chief Operating Officer and Ms. Brooks was promoted to Executive Vice President, Chief Legal and Administrative Officer, and Secretary.
In association with a promotion, the target bonus percentage for Mr. Lamb increased from 90% to 100% and the target bonus percentage for Ms. Brooks increased from 60% to 90%.
|
(2)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
•
|
Options.
For periods preceding the effective time of the Merger, the GP Plan permits the grant of options covering
common units. These options are rights to purchase a specified number of
our
common units at a specified price. The exercise price of an option cannot be less than the fair market value per common unit on the date on which the option is granted and the term of the option cannot exceed ten years from the date of grant. Options granted become exercisable on such terms as the
Compensation Committee determined. Under no circumstances will distributions or DERs (as defined below) be granted or made with respect to option awards. For periods after the effective time of the Merger, the ENLC common units to be delivered upon the exercise of an option may be common units acquired in the open market, common units already owned by any affiliate of us or
ENLC
, common units acquired directly from any affiliate of us or
ENLC
or from any other person, or any combination of the foregoing.
|
•
|
Restricted Incentive Units.
For periods preceding the effective time of the Merger, the GP Plan permits the grant of restricted incentive units. These awards of restricted incentive units are rights that entitle the grantee to receive cash, common units, or a combination of cash and common units of ENLK upon the vesting of such restricted incentive
|
•
|
Options.
The 2014 Plan permits the grant of options covering common units. These options are rights to purchase a specified number of common units of ENLC at a specified price. The exercise price of an option cannot be less than the fair market value per common unit on the date on which the option is granted and the term of the option cannot
|
•
|
Unit Appreciation Rights or UARs.
The 2014 Plan permits the grant of UARs.
A UAR is a right to receive an amount equal to the excess of the fair market value of one common unit of ENLC on the date of exercise over the grant price of the UAR. UARs will be exercisable on such terms as the
Manager Committee
determines. The
Manager Committee
will also determine the time or times at which and the circumstances under which a UAR may be exercised in whole or in part (including based on achievement of performance goals and/or future service requirements), the method of exercise, method of settlement, form of consideration payable in settlement, method by or forms in which common units will be delivered or deemed to be delivered to participants, whether or not a UAR shall be in tandem with an option award, and any other terms and conditions of any UAR. UARs may be either freestanding or in tandem with other awards. Under no circumstances will distributions or DERs be granted or made with respect to UAR awards.
|
•
|
Restricted Units.
The 2014 Plan permits the grant of restricted units. A restricted unit is a grant of a common unit of ENLC subject to a substantial risk of forfeiture, restrictions on transferability, and any other restrictions determined by the
Manager Committee
. The
Manager Committee
may provide, in its discretion, that the distributions made by ENLC with respect to the restricted units will be subject to the same forfeiture and other restrictions as the restricted unit and, if so restricted, such distributions will be held, without interest, until the restricted unit vests or is forfeited with the unit distribution right being paid or forfeited at the same time, as the case may be. In addition, the
Manager Committee
may provide that such distributions be used to acquire additional restricted units for the participant. Under no circumstances will DERs be granted or made with respect to restricted unit awards
.
|
•
|
Restricted Incentive Units.
The 2014 Plan permits the grant of restricted incentive units. These awards of restricted incentive units are rights that entitle the grantee to receive cash, common units of ENLC, or a combination of cash and common units of ENLC upon the vesting of such restricted incentive units. Restricted incentive units may be subject to restrictions, including a risk of forfeiture, as determined by the
Manager Committee. The Manager Committee
may, in its sole discretion, grant DERs with respect to restricted incentive units. We intend for the issuance of the common units upon vesting of the restricted incentive units under the 2014 Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, under the current policy, 2014 Plan participants will not pay any consideration for the common units they receive, and ENLC will receive no remuneration for the units
.
|
•
|
Distribution Equivalent Rights or DERs
. The 2014 Plan permits the grant of DERs. DERs entitle a participant to receive cash or additional awards equal to the amount of any cash distributions made with respect to an ENLC common unit during the period the right is outstanding. DERs may be granted as a stand-alone award or with respect to awards other than restricted units, options, or UARs. Subject to Section 409A of the IRC, payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the
Manager Committee.
|
•
|
Unit Awards.
The 2014 Plan permits the grant of unit awards, which are common units of ENLC that are not subject to vesting restrictions.
|
•
|
Cash Awards.
The 2014 Plan permits the grant of cash awards, which are awards denominated and payable in cash.
|
•
|
Performance Awards.
The 2014 Plan permits the grant of performance awards.
Performance awards represent a participant’s right to receive an amount of cash, common units of ENLC, or a combination of both, contingent upon the annual attainment of specified performance measures within a specified period.
The Manager Committee
or, if applicable, the special committee that is responsible for overseeing performance awards that are intended to satisfy certain requirements of Section 162(m) of the IRC (the “Section 162(m) Committee”), will determine the applicable
|
Name and Principal Position
|
|
Year
|
|
Salary
($) |
|
Bonus
($)(1) |
|
Restricted Incentive Unit, and Performance Unit Awards
($)(5) |
|
All Other Compensation
($) |
|
Total
($) |
|
Michael J. Garberding
|
|
2018
|
|
646,600
|
|
1,009,247
|
|
|
7,975,169
|
|
727,195
|
(6)
|
10,358,211
|
President and Chief Executive Officer
|
|
2017
|
|
500,000
|
|
500,000
|
|
|
2,147,374
|
|
396,190
|
|
3,543,564
|
|
|
2016
|
|
462,885
|
|
416,000
|
|
|
3,409,650
|
|
376,304
|
|
4,664,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benjamin D. Lamb (2)
|
|
2018
|
|
447,500
|
|
665,733
|
|
|
4,272,801
|
|
703,111
|
(7)
|
6,089,145
|
Executive Vice President and Chief Operating Officer
|
|
2017
|
|
345,000
|
|
345,000
|
|
|
1,431,552
|
|
274,563
|
|
2,396,115
|
|
2016
|
|
318,558
|
|
250,000
|
|
|
2,181,257
|
|
212,310
|
|
2,962,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barry E. Davis
|
|
2018
|
|
529,000
|
|
784,367
|
|
|
3,835,864
|
|
784,034
|
(8)
|
5,933,265
|
Executive Chairman of the Board
|
|
2017
|
|
695,000
|
|
960,000
|
|
|
4,533,371
|
|
565,075
|
|
6,753,446
|
|
|
2016
|
|
660,000
|
|
650,000
|
|
|
2,498,230
|
|
570,612
|
|
4,378,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eric D. Batchelder
|
|
2018
|
|
399,200
|
|
560,771
|
|
|
3,133,675
|
|
304,836
|
(9)
|
4,398,482
|
Executive Vice President and Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Alaina K. Brooks (2)(3)
|
|
2018
|
|
393,300
|
|
468,087
|
|
|
2,410,163
|
|
204,661
|
(10)
|
3,476,211
|
Executive Vice President, Chief Legal and Administrative Officer, and Secretary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
McMillan Hummel (4)
|
|
2018
|
|
258,100
|
|
362,474
|
|
|
1,522,802
|
|
2,273,947
|
(11)
|
4,417,323
|
Executive Vice President / Business Unit President
|
|
2017
|
|
415,192
|
|
415,000
|
|
|
1,550,909
|
|
322,421
|
|
2,703,522
|
|
2016
|
|
390,000
|
|
225,000
|
|
|
1,092,502
|
|
317,871
|
|
2,025,373
|
(1)
|
Bonuses include all annual bonus payments. For 2016, the named executive officers received bonuses in the form of equity awards that immediately vest. Such equity awards were allocated 50% in restricted incentive units of ENLK and 50% in restricted incentive units of ENLC. For 2017, the named executive officers received bonuses in the form of 25% cash and 75% equity awards that immediately vest. Such equity awards were allocated 50% in restricted incentive units of ENLK and 50% in restricted incentive units of ENLC. For 2018, the named executive officers received bonuses in the form of 50% cash and 50% equity awards that immediately vest. Such equity awards were entirely allocated in restricted incentive units of ENLC. Equity awards for 2016, 2017, and 2018 represent the grant date fair value of awards computed in accordance with ASC 718.
|
(2)
|
In June 2018, Mr. Lamb was promoted to Executive Vice President and Chief Operating Officer and Ms. Brooks was promoted to Executive Vice President, Chief Legal and Administrative Officer, and Secretary.
|
(3)
|
Ms. Brooks became a named executive officer in fiscal year 2018, and, therefore, summary compensation information is presented only for fiscal year 2018.
|
(4)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
(5)
|
The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—
Note 10—Employee Incentive Plans
” for the assumptions made in our valuation of such awards.
|
(6)
|
Amount of all other compensation for Mr. Garberding includes a matching 401(k) contribution of
$18,500
, a 401(k) non-discretionary contribution of
$5,500
, a 401(k) discretionary profit-sharing contribution of
$6,600
, DERs with respect to restricted incentive units of ENLK in the amount of
$429,040
, and DERs with respect to restricted incentive units of ENLC in the amount of
$267,555
.
|
(7)
|
Amount of all other compensation for Mr. Lamb includes a matching 401(k) contribution of
$18,500
, a 401(k) non-discretionary contribution of
$5,500
, a 401(k) discretionary profit-sharing contribution of
$6,600
, DERs with respect to restricted incentive units of ENLK in the amount of
$414,345
, and DERs with respect to restricted incentive units of ENLC in the amount of
$258,166
.
|
(8)
|
Amount of all other compensation for Mr. Davis includes a matching 401(k) contribution of
$24,500
, a 401(k) non-discretionary contribution of
$5,500
, a 401(k) discretionary profit-sharing contribution of
$6,600
, DERs with respect to restricted incentive units of ENLK in the amount of
$468,090
, and DERs with respect to restricted incentive units of ENLC in the amount of
$279,344
.
|
(9)
|
Amount of all other compensation for Mr. Batchelder includes a matching 401(k) contribution of
$18,500
, a 401(k) non-discretionary contribution of
$5,500
, a 401(k) discretionary profit-sharing contribution of
$6,600
,
$140,644
toward moving expenses, DERs with respect to restricted incentive units of ENLK in the amount of
$81,986
, and DERs with respect to restricted incentive units of ENLC in the amount of
$51,606
.
|
(10)
|
Amount of all other compensation for Ms. Brooks includes a matching 401(k) contribution of
$18,500
, a 401(k) non-discretionary contribution of
$5,500
, a 401(k) discretionary profit-sharing contribution of
$6,600
, DERs with respect to restricted incentive units of ENLK in the amount of
$105,752
, and DERs with respect to restricted incentive units of ENLC in the amount of
$68,309
.
|
(11)
|
Amount of all other compensation for Mr. Hummel includes a matching 401(k) contribution of
$22,551
,
$37,832
toward temporary housing expenses, DERs with respect to restricted incentive units of ENLK in the amount of
$322,389
, and DERs with respect to restricted incentive units of ENLC in the amount of
$189,770
. Mr. Hummel received
$1,701,404
in connection with his departure.
|
|
|
|
|
Estimated Future Payouts Under Equity Incentive Plan Awards
|
|
|
|
|
|||||||||
Name
|
|
Grant Date
|
|
Threshold (#) (1)
|
|
Target (#)
(1) |
|
Maximum (#)(1)
|
|
All Other Unit Awards: Number of Units
|
|
Grant Date Fair Value of Unit Awards ($)(4)
|
|||||
Michael J. Garberding
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56,929
|
|
(2)
|
860,766
|
|
|
|
3/13/2018
|
|
56,929
|
|
|
56,929
|
|
|
113,858
|
|
|
—
|
|
|
1,452,259
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
112,323
|
|
(3)
|
1,749,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Benjamin D. Lamb
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,772
|
|
(2)
|
344,313
|
|
|
|
3/13/2018
|
|
22,772
|
|
|
22,772
|
|
|
45,544
|
|
|
—
|
|
|
438,133
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32,092
|
|
(3)
|
499,993
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56,162
|
|
(3)
|
875,004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Barry E. Davis
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48,796
|
|
(2)
|
737,796
|
|
|
|
3/13/2018
|
|
48,796
|
|
|
48,796
|
|
|
97,592
|
|
|
—
|
|
|
1,244,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Eric D. Batchelder
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,332
|
|
(2)
|
307,420
|
|
|
|
3/13/2018
|
|
20,332
|
|
|
20,332
|
|
|
40,664
|
|
|
—
|
|
|
391,188
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,012
|
|
(3)
|
196,741
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44,929
|
|
(3)
|
699,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Alaina K. Brooks
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,850
|
|
(2)
|
194,292
|
|
|
|
3/13/2018
|
|
12,850
|
|
|
12,850
|
|
|
25,700
|
|
|
—
|
|
|
327,804
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,465
|
|
(3)
|
350,005
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,465
|
|
(3)
|
350,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
McMillan Hummel (5)
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,772
|
|
(2)
|
344,313
|
|
|
|
3/13/2018
|
|
22,772
|
|
|
22,772
|
|
|
45,544
|
|
|
—
|
|
|
438,133
|
|
(1)
|
These grants include accrued DERs that provide for distributions on performance awards, unless otherwise forfeited, if distributions are made on common units during the restriction period. When the performance awards vest on January 1, 2021, recipients receive DERs, if any, with respect to the number of performance awards vested.
|
(2)
|
These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2021.
|
(3)
|
These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 50% on August 1, 2020 and 50% on August 1, 2021.
|
(4)
|
The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—
Note 10—Employee Incentive Plans
” for the assumptions made in our valuation of such awards.
|
(5)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
|
|
|
|
Estimated Future Payouts Under Equity Incentive Plan Awards
|
|
|
|
|
|||||||||
Name
|
|
Grant Date
|
|
Threshold (#) (1)
|
|
Target (#)
(1) |
|
Maximum (#)(1)
|
|
All Other Unit Awards: Number of Units
|
|
Grant Date Fair Value of Unit Awards ($)(4)
|
|||||
Michael J. Garberding
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
49,716
|
|
(2)
|
775,570
|
|
|
|
3/13/2018
|
|
49,716
|
|
|
49,716
|
|
|
99,432
|
|
|
—
|
|
|
1,386,579
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
109,718
|
|
(3)
|
1,750,002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Benjamin D. Lamb
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,886
|
|
(2)
|
310,222
|
|
|
|
3/13/2018
|
|
19,886
|
|
|
19,886
|
|
|
39,772
|
|
|
—
|
|
|
430,134
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31,348
|
|
(3)
|
500,001
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54,859
|
|
(3)
|
875,001
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Barry E. Davis
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42,614
|
|
(2)
|
664,778
|
|
|
|
3/13/2018
|
|
42,614
|
|
|
42,614
|
|
|
85,228
|
|
|
—
|
|
|
1,188,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Eric D. Batchelder
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,756
|
|
(2)
|
276,994
|
|
|
|
3/13/2018
|
|
17,756
|
|
|
17,756
|
|
|
35,512
|
|
|
—
|
|
|
384,062
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,364
|
|
(3)
|
177,278
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,887
|
|
(3)
|
699,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Alaina K. Brooks
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,222
|
|
(2)
|
175,063
|
|
|
|
3/13/2018
|
|
11,222
|
|
|
11,222
|
|
|
22,444
|
|
|
—
|
|
|
312,982
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,944
|
|
(3)
|
350,007
|
|
|
|
8/1/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,944
|
|
(3)
|
350,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
McMillan Hummel (5)
|
|
3/13/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,886
|
|
(2)
|
310,222
|
|
|
|
3/13/2018
|
|
19,886
|
|
|
19,886
|
|
|
39,772
|
|
|
—
|
|
|
430,134
|
|
(1)
|
These grants include accrued DERs that provide for distributions on performance awards, unless otherwise forfeited, if distributions are made on common units during the restriction period. When the performance awards vest on January 1, 2021, recipients receive DERs, if any, with respect to the number of performance awards vested.
|
(2)
|
These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on January 1, 2021.
|
(3)
|
These grants include DERs that provide for distribution on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 50% on August 1, 2020 and 50% on August 1, 2021.
|
(4)
|
The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—
Note 10—Employee Incentive Plans
” for the assumptions made in our valuation of such awards.
|
(5)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
|
|
|
|
Stock Awards
|
||||||||||
Name
|
|
Vesting Year (1)
|
|
Number of Units That Have Not Vested
(#) |
|
Market Value of Shares or Units That Have Not Vested
($)(2) |
|
Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3)
|
|
Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
|
||||
Michael J. Garberding
|
|
2021
|
|
113,091
|
|
|
1,245,132
|
|
|
56,929
|
|
|
626,788
|
|
|
|
2020
|
|
101,572
|
|
|
1,118,308
|
|
|
45,411
|
|
|
499,975
|
|
|
|
2019
|
|
82,712
|
|
|
910,659
|
|
|
33,784
|
|
|
371,962
|
|
Benjamin D. Lamb (4)
|
|
2021
|
|
66,899
|
|
|
736,558
|
|
|
—
|
|
|
—
|
|
|
|
2020
|
|
74,400
|
|
|
819,144
|
|
|
—
|
|
|
—
|
|
|
|
2019
|
|
53,588
|
|
|
590,004
|
|
|
—
|
|
|
—
|
|
Barry E. Davis
|
|
2021
|
|
48,796
|
|
|
537,244
|
|
|
48,796
|
|
|
537,244
|
|
|
|
2020
|
|
51,241
|
|
|
564,163
|
|
|
51,241
|
|
|
564,163
|
|
|
|
2019
|
|
128,145
|
|
|
1,410,876
|
|
|
58,248
|
|
|
641,310
|
|
Eric D. Batchelder (4)
|
|
2021
|
|
55,809
|
|
|
614,457
|
|
|
—
|
|
|
—
|
|
|
|
2020
|
|
22,464
|
|
|
247,329
|
|
|
—
|
|
|
—
|
|
Alaina K. Brooks
|
|
2021
|
|
35,316
|
|
|
388,829
|
|
|
12,850
|
|
|
141,479
|
|
|
|
2020
|
|
31,903
|
|
|
351,252
|
|
|
9,439
|
|
|
103,923
|
|
|
|
2019
|
|
13,429
|
|
|
147,853
|
|
|
13,429
|
|
|
147,853
|
|
McMillan Hummel (4)(5)
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Restricted incentive units vesting in 2019 vest on January 1, 2019. Restricted incentive units vesting in 2020 and 2021 vest on January 1
st
and August 1
st
of the relevant year, as applicable.
|
(2)
|
The closing price for the ENLK common units was $11.01 as of December 31, 2018.
|
(3)
|
Reflects the target number of performance units granted to the named executive officers multiplied by a performance percentage of 100%. Vesting of these awards on January 1, 2019 is contingent upon the EnLink TSR performance. For performance periods ending after January 1, 2019, vesting of these awards in the relevant year is contingent upon (i) the EnLink TSR performance measured against a peer group of companies in respect of periods preceding the effective time of the Merger and (ii) the TSR performance of ENLC measured against a peer group of companies in respect of periods after the effective time of the Merger.
|
(4)
|
In connection with the GIP Transaction, outstanding performance units held by certain executives who elected not to waive their rights to have such awards vest due to the closing of the GIP Transaction vested at 100%.
|
(5)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
Pursuant to his departure, Mr. Hummel’s outstanding restricted incentive units vested and his outstanding performance units vested at 100% in 2018.
|
|
|
|
|
Unit Awards
|
||||||||||
Name
|
|
Vesting Year (1)
|
|
Number of Units That Have Not Vested
(#) |
|
Market Value of Shares or Units That Have Not Vested
($)(2) |
|
Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3)
|
|
Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)(2)
|
||||
Michael J. Garberding
|
|
2021
|
|
104,575
|
|
|
992,417
|
|
|
49,716
|
|
|
471,805
|
|
|
|
2020
|
|
100,910
|
|
|
957,636
|
|
|
46,051
|
|
|
437,024
|
|
|
|
2019
|
|
71,457
|
|
|
678,127
|
|
|
29,187
|
|
|
276,985
|
|
Benjamin D. Lamb (4)
|
|
2021
|
|
62,990
|
|
|
597,775
|
|
|
—
|
|
|
—
|
|
|
|
2020
|
|
73,803
|
|
|
700,390
|
|
|
—
|
|
|
—
|
|
|
|
2019
|
|
46,296
|
|
|
439,349
|
|
|
—
|
|
|
—
|
|
Barry E. Davis
|
|
2021
|
|
42,614
|
|
|
404,407
|
|
|
42,614
|
|
|
404,407
|
|
|
|
2020
|
|
47,739
|
|
|
453,043
|
|
|
47,739
|
|
|
453,043
|
|
|
|
2019
|
|
110,709
|
|
|
1,050,628
|
|
|
50,322
|
|
|
477,556
|
|
Eric D. Batchelder (4)
|
|
2021
|
|
51,064
|
|
|
484,597
|
|
|
—
|
|
|
—
|
|
|
|
2020
|
|
21,943
|
|
|
208,239
|
|
|
—
|
|
|
—
|
|
Alaina K. Brooks
|
|
2021
|
|
33,166
|
|
|
314,745
|
|
|
11,222
|
|
|
106,497
|
|
|
|
2020
|
|
30,738
|
|
|
291,704
|
|
|
8,794
|
|
|
83,455
|
|
|
|
2019
|
|
14,286
|
|
|
135,574
|
|
|
14,286
|
|
|
135,574
|
|
McMillan Hummel (4)(5)
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Restricted incentive units vesting in 2019 vest on January 1, 2019. Restricted incentive units vesting in 2020 and 2021 vest on January 1
st
and August 1
st
of the relevant year, as applicable.
|
(2)
|
The closing price for the ENLC common units was $9.49 as of December 31, 2018
.
|
(3)
|
Reflects the target number of performance units granted to the named executive officers multiplied by a performance percentage of 100%. Vesting of these awards on January 1, 2019 is contingent upon the EnLink TSR performance. For performance periods ending after January 1, 2019, vesting of these awards in the relevant year is contingent upon (i) the EnLink TSR performance measured against a peer group of companies in respect of periods preceding the effective time of the Merger and (ii) the TSR performance of ENLC measured against a peer group of companies in respect of periods after the effective time of the Merger.
|
(4)
|
In connection with the GIP Transaction, outstanding performance units held by certain executives who elected not to waive their rights to have such awards vest due to the closing of the GIP Transaction vested at 100%.
|
(5)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
Pursuant to his departure, Mr. Hummel’s outstanding restricted incentive units vested and his outstanding performance units vested at 100% in 2018.
|
Name
|
|
Date Vested
|
|
Number of Units Acquired on Vesting
|
|
Value Per Unit Realized on Vesting ($)
|
|
Total ($)
|
|
Michael J. Garberding
|
|
1/1/18
|
|
17,532
|
|
15.37
|
|
|
269,467
|
|
|
1/22/18
|
|
17,532
|
|
17.45
|
|
|
305,933
|
|
|
3/5/18
|
|
12,669
|
|
14.80
|
|
|
187,501
|
|
|
|
|
|
|
|
|
|
|
Benjamin D. Lamb
|
|
1/1/18
|
|
11,695
|
|
15.37
|
|
|
179,752
|
|
|
1/22/18
|
|
11,695
|
|
17.45
|
|
|
204,078
|
|
|
3/5/18
|
|
8,742
|
|
14.80
|
|
|
129,382
|
|
|
4/1/18
|
|
4,858
|
|
13.66
|
|
|
66,360
|
|
|
7/18/18
|
|
69,354
|
(1)
|
14.93
|
|
|
1,035,455
|
|
|
|
|
|
|
|
|
|
|
Barry E. Davis
|
|
1/1/18
|
|
30,680
|
|
15.37
|
|
|
471,552
|
|
|
1/22/18
|
|
30,680
|
|
17.45
|
|
|
535,366
|
|
|
3/5/18
|
|
24,324
|
|
14.80
|
|
|
359,995
|
|
|
|
|
|
|
|
|
|
|
Eric D. Batchelder
|
|
7/18/18
|
|
20,332
|
(1)
|
14.93
|
|
|
303,557
|
|
|
|
|
|
|
|
|
|
|
Alaina K. Brooks
|
|
1/1/18
|
|
4,678
|
|
15.37
|
|
|
71,901
|
|
|
1/22/18
|
|
4,678
|
|
17.45
|
|
|
81,631
|
|
|
3/5/18
|
|
5,533
|
|
14.80
|
|
|
81,888
|
|
|
|
|
|
|
|
|
|
|
McMillan Hummel (2)
|
|
1/1/18
|
|
14,025
|
|
15.37
|
|
|
215,564
|
|
|
1/22/18
|
|
14,025
|
|
17.45
|
|
|
244,736
|
|
|
3/5/18
|
|
10,515
|
|
14.80
|
|
|
155,622
|
|
|
7/18/18
|
|
65,931
|
(1)
|
14.93
|
|
|
984,350
|
|
|
8/2/18
|
|
96,220
|
|
16.72
|
|
|
1,608,798
|
(1)
|
In connection with the GIP Transaction, outstanding performance units held by certain executives who elected not to waive their rights to have such awards vest due to the closing of the GIP Transaction vested at 100%.
|
(2)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
Pursuant to his departure, Mr. Hummel’s outstanding restricted incentive units vested and his outstanding performance units vested at 100% in 2018.
|
Name
|
|
Date Vested
|
|
Number of Units Acquired on Vesting
|
|
Value Per Unit Realized on Vesting ($)
|
|
Total ($)
|
|
Michael J. Garberding
|
|
1/1/18
|
|
15,823
|
|
17.60
|
|
|
278,485
|
|
|
1/22/18
|
|
15,823
|
|
18.75
|
|
|
296,681
|
|
|
3/5/18
|
|
12,255
|
|
15.30
|
|
|
187,502
|
|
|
|
|
|
|
|
|
|
|
Benjamin D. Lamb
|
|
1/1/18
|
|
10,074
|
|
17.60
|
|
|
177,302
|
|
|
1/22/18
|
|
10,074
|
|
18.75
|
|
|
188,888
|
|
|
3/5/18
|
|
8,456
|
|
15.30
|
|
|
129,377
|
|
|
4/1/18
|
|
3,556
|
|
14.65
|
|
|
52,095
|
|
|
7/18/18
|
|
64,676
|
(1)
|
15.30
|
|
|
989,543
|
|
|
|
|
|
|
|
|
|
|
Barry E. Davis
|
|
1/1/18
|
|
27,690
|
|
17.60
|
|
|
487,344
|
|
|
1/22/18
|
|
27,690
|
|
18.75
|
|
|
519,188
|
|
|
3/5/18
|
|
23,529
|
|
15.30
|
|
|
359,994
|
|
|
|
|
|
|
|
|
|
|
Eric D. Batchelder
|
|
7/18/18
|
|
17,756
|
(1)
|
15.30
|
|
|
271,667
|
|
|
|
|
|
|
|
|
|
|
Alaina K. Brooks
|
|
1/1/18
|
|
4,030
|
|
17.60
|
|
|
70,928
|
|
|
1/22/18
|
|
4,030
|
|
18.75
|
|
|
75,563
|
|
|
3/5/18
|
|
5,352
|
|
15.30
|
|
|
81,886
|
|
|
|
|
|
|
|
|
|
|
McMillan Hummel (2)
|
|
1/1/18
|
|
12,658
|
|
17.60
|
|
|
222,781
|
|
|
1/22/18
|
|
12,658
|
|
18.75
|
|
|
237,338
|
|
|
3/5/18
|
|
10,172
|
|
15.30
|
|
|
155,632
|
|
|
7/18/18
|
|
58,360
|
(1)
|
15.30
|
|
|
892,908
|
|
|
8/2/18
|
|
84,527
|
|
17.35
|
|
|
1,466,543
|
(1)
|
In connection with the GIP Transaction, outstanding performance units held by certain executives who elected not to waive their rights to have such awards vest due to the closing of the GIP Transaction vested at 100%.
|
(2)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
Pursuant to his departure, Mr. Hummel’s outstanding restricted incentive units vested and his outstanding performance units vested at 100% in 2018.
|
Named Executive Officer
|
|
Payment Under Severance Agreements Upon Termination Other Than For Cause or With Good Reason
($)(1)
|
|
Health Care Benefits Under Change in Control and Severance Agreements Upon Termination Other Than For Cause or With Good Reason
($)(2)
|
|
Payment and Health Care Benefits Under Change in Control and Severance Agreements Upon Termination For Cause or Without Good Reason
($)(3)
|
|
Payment Under Change in Control Agreements Upon Termination and Change of Control
($)(4)
|
|
Acceleration of Vesting Under Long-Term Incentive Plans Upon Change of Control
($)(5)
|
|||||
Michael J. Garberding
|
|
3,659,247
|
|
|
30,853
|
|
|
—
|
|
|
4,959,247
|
|
|
8,586,817
|
|
Benjamin D. Lamb
|
|
2,615,733
|
|
|
33,140
|
|
|
—
|
|
|
2,615,733
|
|
|
3,883,220
|
|
Barry E. Davis
|
|
2,881,867
|
|
|
33,678
|
|
|
—
|
|
|
3,905,617
|
|
|
7,498,086
|
|
Eric D. Batchelder
|
|
2,263,771
|
|
|
20,901
|
|
|
—
|
|
|
2,263,771
|
|
|
1,554,622
|
|
Alaina K. Brooks
|
|
2,133,087
|
|
|
30,853
|
|
|
—
|
|
|
2,133,087
|
|
|
2,348,739
|
|
McMillan Hummel (6)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
Each named executive officer is entitled to a lump sum amount equal to two times the Severance Benefit, the Outplacement Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he or she is terminated without cause (as defined in the Severance Agreement) or if he or she terminates employment for good reason (as defined in the Severance Agreement), subject to compliance with certain non-competition and non-solicitation covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
|
(2)
|
Each named executive officer is entitled to health care benefits equal to a lump sum payment of the estimated monthly cost of the benefits under COBRA for 18 months if he or she is terminated without cause (as defined in the applicable Severance Agreement or Change of Control Agreement (the “Applicable Agreement”) or if he or she terminates employment for good reason (as defined in the Applicable Agreement)).
|
(3)
|
Each named executive officer is entitled to his or her then current base salary up to the date of termination plus such other fringe benefits (other than any bonus, severance pay benefit, participation in the company’s 401(k) employee benefit plan, or medical insurance benefit) normally provided to employees of the company as earned up to the date of termination if he or she is terminated for cause (as defined in the Applicable Agreement) or he or she terminates employment without good reason (as defined in the Applicable Agreement). The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
|
(4)
|
Each named executive officer is entitled to a lump sum payment equal to two times the Severance Benefit (three times in the case of the Chief Executive Officer and Executive Chairman), the Outplacement Benefit, and when applicable, the bonus amounts comprising the General Benefits will be paid if he or she is terminated without cause (as defined in the Change of Control Agreement) or if he or she terminates employment for good reason (as defined in the Change of Control Agreement) within 120 days prior to or two years following a change in control (as defined in the Severance Agreement), subject to compliance with certain non-competition, non-solicitation, and other covenants described elsewhere in this Annual Report on Form 10-K. The figures shown do not include amounts of base salary previously paid or fringe benefits previously received.
|
(5)
|
Each named executive officer is entitled to accelerated vesting of certain outstanding equity awards in the event of a change of control (as defined under the long-term incentive plans). These amounts correspond to the values set forth in the table in the section above entitled Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year
2018
.
|
(6)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
Pursuant to his departure, Mr. Hummel received a cash payment of
$1,701,404
related to his Severance Benefit,
$362,474
related to his 2018 bonus,
and accelerated vesting of outstanding equity awards valued at
$3,075,342
as of the vesting date.
|
Name
|
|
Fees Earned or Paid in Cash ($)
|
|
Unit Awards ($)(1)
|
|
All Other Compensation ($)(2)
|
|
Total
($)
|
Leldon E. Echols (3)
|
|
48,250
|
|
55,629
|
|
5,383
|
|
109,262
|
Scott A. Griffiths (3)
|
|
217,667
|
|
111,257
|
|
10,766
|
|
339,690
|
Kyle D. Vann (3)
|
|
245,472
|
|
111,257
|
|
10,766
|
|
367,495
|
Mary P. Ricciardello (4)
|
|
35,951
|
|
55,629
|
|
2,465
|
|
94,045
|
(1)
|
Messrs. Echols, Griffiths, and Vann, and Ms. Ricciardello were granted awards of restricted incentive units of ENLK on March 7,
2018
with a fair market value of
$14.87
per unit and that will vest on March 7,
2019
in the following amounts, respectively:
3,741
,
7,482
,
7,482
, and
3,741
. Mr. Echols and Ms. Ricciardello were granted awards of restricted incentive units of ENLC on March 7,
2018
with a fair market value of
$15.30
per unit and that will vest on March 7,
2019
in the following amounts, respectively:
3,267
and
3,267
. The amounts shown represent the grant date fair value of awards computed in accordance with ASC 718. See “Item 8. Financial Statements and Supplementary Data—
Note 10—Employee Incentive Plans
” for the assumptions made in our valuation of such awards. At
December 31, 2018
, Messrs. Echols, Griffiths, and Mr. Vann and Ms. Ricciardello held aggregate outstanding restricted incentive unit awards of ENLK, in the following amounts, respectively:
3,741
,
7,482
,
7,482
, and
3,741
. At
December 31, 2018
, Mr. Echols and Ms. Ricciardello held aggregate outstanding restricted incentive units of ENLC in the following amounts, respectively:
3,267
and
3,267
.
|
(2)
|
Other Compensation is comprised of DERs with respect to restricted incentive units.
|
(3)
|
In connection with the closing of the Merger, each of Messrs. Echols, Griffiths, and Vann departed from their positions as directors.
|
(4)
|
In July 2018, Ms. Ricciardello departed from her position as a director. Pursuant to her departure, Ms. Ricciardello’s outstanding restricted incentive units vested in 2018.
|
•
|
each person who is known to ENLK to beneficially own more than 5% of any class of voting units then outstanding;
|
•
|
all the directors of EnLink Midstream GP, LLC;
|
•
|
each named executive officer of EnLink Midstream GP, LLC; and
|
•
|
all the directors and executive officers of EnLink Midstream GP, LLC as a group.
|
Name of Beneficial Owner (1)
|
|
Common Units Beneficially Owned (2)
|
|
Percentage of Common Units Beneficially Owned
|
||
Global Infrastructure Investors III, LLC (3) (4)
|
|
144,535,672
|
|
|
100.00
|
%
|
Barry E. Davis
|
|
—
|
|
|
—
|
%
|
Michael J. Garberding
|
|
—
|
|
|
—
|
%
|
Eric D. Batchelder
|
|
—
|
|
|
—
|
%
|
Benjamin D. Lamb
|
|
—
|
|
|
—
|
%
|
Alaina K. Brooks
|
|
—
|
|
|
—
|
%
|
McMillan Hummel (5)
|
|
—
|
|
|
—
|
%
|
All directors and executive officers as a group (5 persons)
|
|
—
|
|
|
—
|
%
|
(1)
|
The address of each person listed above is 1722 Routh Street, Suite 1300, Dallas, Texas 75201, except for Global Infrastructure Investors III, LLC, whose address is 1345 Avenue of the Americas, 30th Floor, New York, New York 10105.
|
(2)
|
Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days.
|
(3)
|
ENLC is the record holder of
144,535,672
common units of ENLK. Global Infrastructure Investors III, LLC ("Global Investors") is the sole general partner of Global Infrastructure GP III, L.P. (“Global GP”), which is the general partner of each of GIP III Stetson Aggregator I, L.P. (“Aggregator I”) and GIP III Stetson Aggregator II, L.P. (“Aggregator II”), which are the managing members of GIP III Stetson GP, LLC (“Stetson GP”), which is the general partner of GIP III Stetson I, L.P. (“Stetson I”), which is the sole member of EnLink Midstream Manager, LLC, which is the managing member of ENLC. As a result, Global Investors, Global GP, Aggregator I, Aggregator II, Stetson GP, Stetson I, and EnLink Midstream Manager, LLC may be deemed to share beneficial ownership of the Common Units held by ENLC.
|
(4)
|
As the indirect owner of
40.4%
of the outstanding membership interest in EnLink Midstream, LLC, and 100% of the outstanding membership interest in EnLink Midstream, LLC’s managing member, GIP may be deemed to beneficially own all common units.
|
(5)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
•
|
all the directors of EnLink Midstream GP, LLC;
|
•
|
each named executive officer of EnLink Midstream GP, LLC; and
|
•
|
all the directors and executive officers of EnLink Midstream GP, LLC as a group.
|
Name of Beneficial Owner (1)
|
|
Common Units Beneficially Owned (2)
|
|
Percentage of Common Units Beneficially Owned (3)
|
|
ENLC Class C Common Units Beneficially Owned (2)
|
|
Percentage of ENLC Class C Common Units Beneficially Owned
|
|
Total Units Beneficially Owned (2)
|
|
Percentage of Total Units Beneficially Owned (4)
|
||||
Barry E. Davis (5)
|
|
2,679,249
|
|
|
*
|
|
—
|
|
|
—
|
|
|
2,679,249
|
|
|
*
|
Michael J. Garberding (6)
|
|
544,116
|
|
|
*
|
|
—
|
|
|
—
|
|
|
544,116
|
|
|
*
|
Eric D. Batchelder
|
|
24,950
|
|
|
*
|
|
—
|
|
|
—
|
|
|
24,950
|
|
|
*
|
Benjamin D. Lamb
|
|
242,288
|
|
|
*
|
|
—
|
|
|
—
|
|
|
242,288
|
|
|
*
|
Alaina K. Brooks (7)
|
|
48,626
|
|
|
*
|
|
—
|
|
|
—
|
|
|
48,626
|
|
|
*
|
McMillan (Mac) Hummel (8)
|
|
318,635
|
|
|
*
|
|
—
|
|
|
—
|
|
|
318,635
|
|
|
*
|
All directors and executive officers as group (5 persons)
|
|
3,539,229
|
|
|
*
|
|
—
|
|
|
—
|
|
|
3,539,229
|
|
|
*
|
(1)
|
The address of each person listed above is 1722 Routh Street, Suite 1300, Dallas, Texas 75201.
|
(2)
|
Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days.
|
(3)
|
The percentages reflected in the column below are based on a total of
486,879,590
common units (including
244,664
restricted incentive units that are deemed beneficially owned).
|
(4)
|
The percentages reflected in the column below are based on a total of 554,907,586 common units, which includes the units described in (3) above, and 68,027,996 common units, which reflects the as-exchanged amount of the 59,154,779 ENLC Class C Common Units held by Enfield, which owns the same number of Series B Preferred Units. The Series B Preferred Units are exchangeable into ENLC common units on a 1-for-1.15 basis, subject to certain adjustments. For this reason, the percentages in this column reflect the exchange of the Series B Preferred Units into ENLC common units. Upon any exchange of Series B Preferred Units into ENLC common units, an equal number of ENLC Class C Common Units will be cancelled.
|
(5)
|
Includes 2,555,842 ENLC common units owned of record by Mr. Davis and 123,407 restricted incentive units that are deemed beneficially owned. Of these common units of the Company owned, 964,724 are held by MK Holdings, LP, a family limited partnership, which Mr. Davis controls, and Mr. Davis disclaims beneficial ownership of these securities except to the extent of his pecuniary interest therein.
|
(6)
|
Includes 472,540 common units owned of record by Mr. Garberding and 71,576 restricted incentive units that are deemed beneficially owned.
|
(7)
|
Includes 17,351 common units owned of record by Ms. Brooks and 31,275 restricted incentive units that are deemed beneficially owned.
|
(8)
|
In August 2018, Mr. Hummel departed from his position as Executive Vice President / Business Unit President.
|
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)
|
|
3,064,822
|
(2)
|
$
|
4.65
|
|
(3)
|
3,418,034
|
|
Equity Compensation Plans Not Approved by Security Holders
|
|
N/A
|
|
N/A
|
|
|
N/A
|
|
(1)
|
The GP Plan was approved by our unitholders, effective April 6, 2016, for the benefit of our officers, employees and directors. See “Item 11. Executive Compensation—Compensation Discussion and Analysis.” The plan, as amended, provides for the issuance of a total of
14,070,000
common units under the plan.
|
(2)
|
The number of securities includes
2,556,270
restricted incentive units that have been granted under the GP Plan that have not vested. In addition, the number of securities includes
451,669
performance unit awards granted under the plan, assuming the target distribution at the time of vesting. Actual issuance of these performance unit awards may range from 0% to 200% of the target distribution depending on performance actually attained.
|
(3)
|
The exercise prices for outstanding options under the plan as of
December 31, 2018
range from
$3.11
to
$6.00
per unit.
|
(a)
|
Financial Statements and Schedules
|
1.
|
See “Item 8. Financial Statements and Supplementary Data.”
|
2.
|
Exhibits
|
Number
|
|
|
Description
|
2.1
|
**
|
—
|
|
2.2
|
**
|
—
|
|
2.3
|
**
|
—
|
|
3.1
|
|
—
|
|
3.2
|
|
—
|
|
3.3
|
|
—
|
|
3.4
|
|
—
|
|
3.5
|
|
—
|
|
3.6
|
|
—
|
|
3.7
|
|
—
|
|
3.8
|
|
—
|
|
4.1
|
|
—
|
|
4.2
|
|
—
|
|
4.3
|
|
—
|
4.4
|
|
—
|
|
4.5
|
|
—
|
|
4.6
|
|
—
|
|
4.7
|
|
—
|
|
10.1
|
|
—
|
|
10.2
|
|
—
|
|
10.3
|
†
|
—
|
|
10.4
|
†
|
—
|
|
10.5
|
†*
|
—
|
|
10.6
|
†
|
—
|
|
10.7
|
|
—
|
|
10.8
|
|
—
|
|
10.9
|
|
—
|
|
10.10
|
|
—
|
|
10.11
|
|
—
|
10.12
|
|
—
|
|
10.13
|
†
|
—
|
|
10.14
|
†
|
—
|
|
10.15
|
†
|
—
|
|
10.16
|
†
|
—
|
|
10.17
|
†
|
—
|
|
10.18
|
†
|
—
|
|
10.19
|
†
|
—
|
|
10.20
|
†
|
—
|
|
10.21
|
†
|
—
|
|
10.22
|
|
—
|
|
21.1
|
*
|
—
|
|
31.1
|
*
|
—
|
|
31.2
|
*
|
—
|
|
32.1
|
*
|
—
|
|
101
|
*
|
—
|
The following financial information from EnLink Midstream Partners, LP’s Annual Report on Form 10-K for the year ended December 31, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2018, 2017, and 2016, (ii) Consolidated Balance Sheets as of December 31, 2018 and 2017, (iii) Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017, and 2016, (iv) Consolidated Statements of Changes in Partners’ Equity for the years ended December 31, 2018, 2017, and 2016 and (v) the Notes to Consolidated Financial Statements.
|
|
|
|
|
EnLink Midstream Partners, LP
|
|
|
By:
|
EnLink Midstream GP, LLC, its general partner
|
February 20, 2019
|
By:
|
/s/ MICHAEL J. GARBERDING
|
|
|
Michael J. Garberding,
|
|
|
President and Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ MICHAEL J. GARBERDING
|
|
President, Chief Executive Officer, and Director
(Principal Executive Officer)
|
|
February 20, 2019
|
Michael J. Garberding
|
|
|
||
|
|
|
|
|
/s/ BARRY E. DAVIS
|
|
Executive Chairman and Director
|
|
February 20, 2019
|
Barry E. Davis
|
|
|
||
|
|
|
|
|
/s/ ALAINA K. BROOKS
|
|
Executive Vice President, Chief Legal and Administrative Officer, Secretary, and Director
|
|
February 20, 2019
|
Alaina K. Brooks
|
|
|
||
|
|
|
|
|
/s/ ERIC D. BATCHELDER
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer) |
|
February 20, 2019
|
Eric D. Batchelder
|
|
|
TSR
|
=
|
((Closing Average Value - Opening Average Value) + Reinvested Dividends) / Opening Average Value
*
|
Performance Level
|
EnLink’s Achieved TSR Percentile
Position Relative to AMZ Peers*
|
Associated Individual Payout Level
(expressed as a percentage
of the Subject Award)
|
Below Threshold
|
Less than 25%
|
0%
|
Threshold
|
Equal to 25%
|
50%
|
Target
|
Equal to 50%
|
100%
|
Maximum
|
Greater than or Equal to 75%
|
200%
|
(a)
|
Definitions
. For purposes of the determinations set forth below:
|
Name of Subsidiary
|
State of Organization
|
Acacia Natural Gas, L.L.C.
|
Delaware
|
Appalachian Oil Purchasers, LLC
|
Delaware
|
Ascension Pipeline Company, LLC
|
Delaware
|
Bridgeline Holdings, L.P.
|
Delaware
|
Cedar Cove Midstream LLC
|
Delaware
|
Chandeleur Pipe Line, LLC
|
Delaware
|
Coronado Midstream LLC
|
Texas
|
Delaware G&P, LLC
|
Delaware
|
Delaware Processing LLC
|
Delaware
|
EnLink Appalachian Compression, LLC
|
Delaware
|
EnLink Calcasieu, LLC
|
Delaware
|
EnLink Crude Marketing, LLC
|
Delaware
|
EnLink Crude Oil, Inc.
|
Texas
|
EnLink Crude Pipeline, LLC
|
Delaware
|
EnLink Crude Purchasing LLC
|
Texas
|
EnLink Delaware Crude Pipeline, LLC
|
Texas
|
EnLink Energy GP, LLC
|
Delaware
|
EnLink Gas Marketing, LP
|
Texas
|
EnLink GOM, LLC
|
Delaware
|
EnLink LIG Liquids, LLC
|
Louisiana
|
EnLink LIG, LLC
|
Louisiana
|
EnLink Louisiana Gathering, LLC
|
Louisiana
|
EnLink Matli Holdings, LLC
|
Delaware
|
EnLink Midstream Finance Corporation
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Delaware
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EnLink Midstream Holdings GP, LLC
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Delaware
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EnLink Midstream Holdings, LP
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Delaware
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EnLink Midstream Operating GP, LLC
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Delaware
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EnLink Midstream Operating, LP
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Delaware
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EnLink Midstream Services, LLC
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Texas
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EnLink NGL Marketing, LP
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Texas
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EnLink NGL Pipeline, LP
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Texas
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EnLink Nominee Corp.
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Delaware
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EnLink North Texas Gathering, LP
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Texas
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EnLink Ohio Compression, LLC
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Delaware
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EnLink Oklahoma Crude Gathering, LLC
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Delaware
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EnLink Oklahoma Gas Processing, LP
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Delaware
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EnLink Oklahoma Pipeline, LLC
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Delaware
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EnLink ORV Holdings, Inc.
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Delaware
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EnLink Pelican, LLC
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Delaware
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EnLink Permian, LLC
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Texas
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EnLink Permian II, LLC
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Texas
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EnLink Processing Services, LLC
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Delaware
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EnLink Texas NGL Pipeline, LLC
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Texas
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EnLink Texas Processing, LP
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Texas
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EnLink Tuscaloosa, LLC
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Louisiana
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Gulf Coast Fractionators
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Texas
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Kentucky Oil Gathering, LLC
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Delaware
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Ohio Oil Gathering II, LLC
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Delaware
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Ohio Oil Gathering III, LLC
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Delaware
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Ohio River Valley Pipeline, LLC
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Delaware
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OOGC Disposal Company I, LLC
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Delaware
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Sabine Hub Services LLC
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Delaware
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Sabine Pass Plant Facility Joint Venture
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Texas
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Sabine Pipe Line LLC
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Delaware
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SWG Pipeline, L.L.C.
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Texas
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TOMPC LLC
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Delaware
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TOM-STACK, LLC
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Delaware
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Victoria Express Pipeline, L.L.C.
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Texas
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West Virginia Oil Gathering, LLC
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Delaware
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1.
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I have reviewed this annual report on Form 10-K of EnLink Midstream Partners, LP;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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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;
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(b)
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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;
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(c)
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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
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(d)
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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
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5.
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The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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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
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(b)
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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.
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Date: February 20, 2019
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/s/ MICHAEL J. GARBERDING
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MICHAEL J. GARBERDING
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President and Chief Executive Officer
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(principal executive officer)
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1.
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I have reviewed this annual report on Form 10-K of EnLink Midstream Partners, LP;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(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;
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(b)
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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;
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(c)
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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
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(d)
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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
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5.
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The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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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
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(b)
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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.
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Date: February 20, 2019
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/s/ ERIC D. BATCHELDER
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ERIC D. BATCHELDER
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Executive Vice President and Chief Financial Officer
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(principal financial and accounting officer)
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.
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Date: February 20, 2019
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/s/ MICHAEL J. GARBERDING
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Michael J. Garberding
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President and Chief Executive Officer
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Date: February 20, 2019
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/s/ ERIC D. BATCHELDER
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Eric D. Batchelder
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Executive Vice President and Chief Financial Officer
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