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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Enlink Midstream Partners, LP Common Units Representing Limited Partnership Interests | NYSE:ENLK | NYSE | Ordinary Share |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 12.05 | 0.00 | 01:00:00 |
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.,
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Suite 1300
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Dallas
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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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Trading Symbol
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Name of Exchange on which Registered
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None.
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None.
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None.
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Large accelerated filer
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☐
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Accelerated filer
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☐
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Non-accelerated filer
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x
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Smaller reporting company
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☐
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Emerging growth company
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☐
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☐
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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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2014 EDA
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Equity Distribution Agreement entered into by ENLK in November 2014 with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC to sell up to $350.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program.
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2014 Plan
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ENLC’s 2014 Long-Term Incentive Plan.
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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 “ENLK Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK’s 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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CO2
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Carbon dioxide.
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Commission
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U.S. Securities and Exchange Commission.
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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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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. Since January 31, 2019, EOGP has been a wholly-owned subsidiary of 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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GP Plan
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EnLink Midstream GP, LLC’s Long-Term Incentive Plan.
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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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MMbbls
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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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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 Unit
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ENLK’s Series B Cumulative Convertible Preferred Unit.
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Series C Preferred Unit
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ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit.
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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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Tiger Plant
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A gas processing plant in the Delaware Basin.
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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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White Star
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White Star Petroleum, LLC.
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•
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Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into 1.15 ENLC common units, which resulted in ENLC owning all of the remaining outstanding ENLK common units.
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•
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Our general partner’s incentive distribution rights in ENLK were eliminated.
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•
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Certain terms of the Series B Preferred Units were modified pursuant to an amended partnership agreement of ENLK. See “Item 8. Financial Statements and Supplementary Data—Note 8” for additional information regarding the modified terms of the Series B Preferred Units.
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•
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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. ENLC also agreed to issue an additional ENLC Class C Common Unit to the applicable holder of each Series B Preferred Unit for each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions. 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.
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•
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The Series C Preferred Units and all of our then-existing senior notes continue to be issued and outstanding following the Merger.
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•
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Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan was converted into 1.15 awards with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time.
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•
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Each unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan was modified such that the performance metric for any then outstanding performance award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger.
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•
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ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “Item 8. Financial Statements and Supplementary Data—Note 6” for additional information regarding the Term Loan.
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•
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We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, ENLC entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Item 8. Financial Statements and Supplementary Data—Note 6” for additional information regarding the Consolidated Credit Facility.
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(1)
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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.
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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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Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas;
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•
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North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas;
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•
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Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations 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 and our crude oil operations in ORV; 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, our derivative activity, and our general corporate assets and expenses.
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•
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Enhance the Profitability of Existing Business. We are focused on enhancing the profitability of current operations and our strong, integrated base of assets by:
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•
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Filling available capacity of our assets and optimizing assets to support increasing demand.
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•
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Growing market share in areas across our footprint.
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•
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Reducing costs across our assets.
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•
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Capitalizing on opportunities to expand and capture business opportunities with customers.
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•
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Position to Capture Long-term Opportunities. 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 drilling activity in our areas of operation or growth in supply needs. We continually evaluate economically attractive organic expansion opportunities in our areas of operation that allow us to leverage our existing infrastructure, operating expertise, and customer relationships by constructing and expanding systems to meet new or increased demand for our services.
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•
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Optimize Strong Financial Position. We are focused on strengthening our financial position by achieving long-term capital structure priorities, increasing cash flows, and maintaining balance sheet strength. 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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Drive Organizational Efficiency. We are committed to optimizing costs and efficiencies company-wide, while maintaining a high level of customer service and safety.
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Year Ended
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December 31, 2019
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Gathering and Transmission Pipelines
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Approximate Length (Miles)
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Compression (HP)
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Estimated Capacity (1)
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Average Throughput (2)
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Gas Pipelines
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Permian assets:
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MEGA System gathering facilities
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765
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132,500
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447
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407,000
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Lobo gathering system (3)
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180
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46,900
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160
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316,400
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Permian gas assets (3)
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945
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179,400
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607
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723,400
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North Texas assets:
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Bridgeport rich and lean gathering systems
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2,800
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|
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206,700
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900
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762,700
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Johnson County gathering system
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390
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|
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49,000
|
|
|
400
|
|
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111,700
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Silver Creek gathering system
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910
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|
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53,800
|
|
|
260
|
|
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285,800
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Acacia transmission system
|
|
130
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|
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16,000
|
|
|
920
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491,700
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North Texas gas assets
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4,230
|
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325,500
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2,480
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1,651,900
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Oklahoma assets:
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Central Oklahoma gathering system
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1,825
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258,700
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1,137
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1,270,200
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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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|
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32,000
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Oklahoma gas assets
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1,965
|
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272,700
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1,202
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1,302,200
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Louisiana assets:
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Louisiana gas gathering and transmission system
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3,010
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|
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97,400
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3,975
|
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2,050,000
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Total Gas Pipelines
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10,150
|
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875,000
|
|
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8,264
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5,727,500
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NGL, Crude Oil, and Condensate Pipelines
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Permian assets:
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Victoria Express Pipeline
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60
|
|
|
—
|
|
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90,000
|
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16,400
|
Permian Basin gathering (4)
|
|
455
|
|
|
—
|
|
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238,500
|
|
|
115,600
|
Permian Crude Oil and Condensate assets
|
|
515
|
|
|
—
|
|
|
328,500
|
|
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132,000
|
|
|
|
|
|
|
|
|
|
|||
Oklahoma assets:
|
|
|
|
|
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|
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|
|||
Central Oklahoma crude oil gathering systems
|
|
175
|
|
|
—
|
|
|
160,000
|
|
|
47,300
|
|
|
|
|
|
|
|
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|
|||
Louisiana assets:
|
|
|
|
|
|
|
|
|
|||
Cajun-Sibon NGL pipeline system
|
|
760
|
|
|
—
|
|
|
185,000
|
|
|
164,200
|
Ascension NGL pipeline (5)
|
|
35
|
|
|
—
|
|
|
50,000
|
|
|
21,300
|
Ohio River Valley (6)
|
|
210
|
|
|
—
|
|
|
25,650
|
|
|
18,900
|
Louisiana NGL, Crude Oil, and Condensate assets
|
|
1,005
|
|
|
—
|
|
|
260,650
|
|
|
204,400
|
|
|
|
|
|
|
|
|
|
|||
Total NGL, Crude Oil, and Condensate Pipelines
|
|
1,695
|
|
|
—
|
|
|
749,150
|
|
|
383,700
|
(1)
|
Estimated capacity for gas pipelines is MMcf/d. Estimated capacity for liquids and crude and condensate pipelines is Bbls/d.
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(2)
|
Average throughput for gas pipelines is MMBtu/d. Average throughput for NGL, crude, and condensate pipelines is Bbls/d.
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(3)
|
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.
|
(4)
|
Estimated capacity is comprised of 188,500 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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(5)
|
Includes gross mileage, capacity, and throughput for the Ascension JV, which is owned 50% by us.
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(6)
|
Estimated capacity is comprised of trucking capacity only.
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Year Ended
|
||
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|
|
|
December 31, 2019
|
||
Processing Facilities
|
|
Processing Capacity (MMcf/d)
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|
Average Throughput (MMBtu/d)
|
||
Permian assets:
|
|
|
|
|
||
MEGA system processing facilities
|
|
458
|
|
|
467,400
|
|
Lobo processing facilities
|
|
375
|
|
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304,000
|
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Permian assets
|
|
833
|
|
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771,400
|
|
|
|
|
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|
||
North Texas assets:
|
|
|
|
|
||
Bridgeport processing facility
|
|
800
|
|
|
580,000
|
|
Silver Creek processing system (1)
|
|
480
|
|
|
170,500
|
|
North Texas assets
|
|
1,280
|
|
|
750,500
|
|
|
|
|
|
|
||
Oklahoma assets:
|
|
|
|
|
||
Central Oklahoma processing facilities
|
|
1,245
|
|
|
1,181,900
|
|
Northridge processing facility
|
|
200
|
|
|
94,800
|
|
Oklahoma assets
|
|
1,445
|
|
|
1,276,700
|
|
|
|
|
|
|
||
Louisiana assets:
|
|
|
|
|
||
Louisiana gas processing facilities (2)
|
|
1,778
|
|
|
400,200
|
|
Total Processing Facilities
|
|
5,336
|
|
|
3,198,800
|
|
(1)
|
The Azle and Goforth processing plants are not operational. These plants represent 50 MMcf/d and 30 MMcf/d, respectively, of the total processing capacity of the Silver Creek processing system.
|
(2)
|
The Blue Water, Eunice, and Sabine processing plants are not operational. These plants represent 193 MMcf/d, 350 MMcf/d, and 300 MMcf/d, respectively, of the total processing capacity of the Louisiana gas processing assets.
|
|
|
|
|
Year Ended
|
||
|
|
|
|
December 31, 2019
|
||
Fractionation Facilities
|
|
Estimated NGL Fractionation Capacity (Bbls/d)
|
|
Average Throughput (Bbls/d)
|
||
Permian assets:
|
|
|
|
|
||
Mesquite terminal (1)
|
|
15,000
|
|
|
—
|
|
|
|
|
|
|
||
North Texas assets:
|
|
|
|
|
||
Bridgeport processing facility (2)
|
|
15,000
|
|
|
—
|
|
|
|
|
|
|
||
Louisiana assets:
|
|
|
|
|
||
Plaquemine fractionation facility (3)
|
|
125,000
|
|
|
79,200
|
|
Plaquemine processing plant
|
|
5,000
|
|
|
3,300
|
|
Eunice fractionation facility
|
|
70,000
|
|
|
58,700
|
|
Riverside fractionation facility (3)
|
|
—
|
|
|
33,600
|
|
Louisiana assets
|
|
200,000
|
|
|
174,800
|
|
|
|
|
|
|
||
Corporate assets:
|
|
|
|
|
||
Gulf Coast Fractionators (4)
|
|
56,000
|
|
|
47,600
|
|
Total Fractionation Facilities
|
|
286,000
|
|
|
222,400
|
|
(1)
|
The Mesquite terminal fractionator is not operational.
|
(2)
|
Our Bridgeport processing plant in North Texas provides 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)
|
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 125 MBbls/d.
|
(4)
|
Volumes shown reflect our 38.75% ownership in Gulf Coast Fractionators.
|
|
|
|
|
Year Ended
|
|
|
|
|
|
December 31, 2019
|
|
Storage Assets
|
|
Storage Type
|
|
Estimated Storage Capacity (1)
|
|
Permian assets:
|
|
|
|
|
|
Avenger storage
|
|
Crude
|
|
0.1
|
|
VEX storage
|
|
Crude
|
|
0.2
|
|
|
|
|
|
|
|
Oklahoma assets:
|
|
|
|
|
|
Central Oklahoma storage
|
|
Crude
|
|
0.2
|
|
|
|
|
|
|
|
Louisiana assets:
|
|
|
|
|
|
Belle Rose gas storage facility
|
|
Gas
|
|
11.9
|
|
Sorrento gas storage facility
|
|
Gas
|
|
7.3
|
|
Napoleonville NGL storage facility
|
|
NGL
|
|
6.0
|
|
ORV storage
|
|
Crude
|
|
0.7
|
|
(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.
|
•
|
Gas Gathering Systems. Our gas gathering systems are connected to our Permian Basin processing assets and consist of the following:
|
•
|
MEGA system gathering facilities. This gathering system in the Midland 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.
|
•
|
Crude Oil Gathering Systems. Our crude oil gathering systems consist of crude oil and condensate pipelines and above ground storage, including:
|
•
|
Avenger. 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 full-service operations during the second 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.
|
•
|
VEX. 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 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 unloading dock and above-ground storage capacity. The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria.
|
•
|
ECP System. The ECP System includes trucking and crude gathering pipelines in the Midland Basin.
|
•
|
Gas Processing Facilities. Our Permian Basin gas processing facilities include six gas processing plants and 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 facility with a capacity of 58 MMcf/d, the Midmar processing facilities with a capacity of 160 MMcf/d, and the Riptide processing facility with a capacity of 165 MMcf/d.
|
•
|
Lobo processing facilities. Our Lobo natural gas processing facilities are located in Loving County, Texas and include Lobo I, Lobo II, and Lobo III, which account for 35 MMcf/d, 140 MMcf/d, and 200 MMcf/d of processing capacity, respectively. The Lobo processing facilities and the connected gathering system are owned by the Delaware Basin JV.
|
•
|
Fractionation Facility. The Mesquite fractionator has an approximate capacity of 15,000 Bbls/d and is located at our Midland gas processing plant complex. We idled the Mesquite fractionator and only operate the condensate stabilizer in the Mesquite terminal, which has a capacity of 5,000 Bbls/d.
|
•
|
Gas Gathering Systems. Our gas gathering systems are connected to our processing assets and consist of 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, 2019. As described above, we have extended our fixed-fee gathering agreement with Devon, which was effective after the GIP Transaction, and currently have approximately nine 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 four 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.
|
•
|
Gas 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 four years remaining on a fixed-fee transportation agreement that covers transmission services and includes annual rate escalators.
|
•
|
Gas Processing Facilities. Our gas processing facilities in North Texas include four gas processing plants and consist of 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, 2019. We have extended our fixed-fee processing agreement with Devon, which was effective after the GIP Transaction, and currently have approximately nine 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, 400 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.
|
•
|
Fractionation Facility. Our Bridgeport processing plant in North Texas also has fractionation capabilities that provide operational flexibility for the related processing plants but is not the primary fractionation facility for the NGLs produced by the processing plants. Under our current contracts, we do not earn fractionation fees for operating this facility, so throughput volumes through this facility are not captured on a routine basis and are not significant to our gross operating margin.
|
•
|
Gas Gathering Systems. Our Oklahoma gas gathering systems consist of 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 2020, the MVC dictates that approximately 230 MMcf/d of natural gas will be delivered through the Chisholm gathering system.
|
•
|
Northridge gathering system. Our Northridge gathering system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma.
|
•
|
Gas Processing Facilities. Our gas processing facilities consist of the following:
|
•
|
Central Oklahoma processing facilities. The Central Oklahoma processing facilities include the Thunderbird Plant, the Chisholm plants, the Battle Ridge plant, and the Cana processing facilities (collectively, the “Central Oklahoma processing system”), which account for 200 MMcf/d, 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 nine 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 a contractual arrangement with Devon on the Chisholm plants that includes an MVC that will remain in effect until December 2020. For 2020, the MVC dictates that approximately 230 MMcf/d of natural gas will be delivered to the Chisholm plant processing facility.
|
•
|
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.
|
•
|
Crude Oil Gathering Systems. Our Oklahoma crude and condensate assets have crude oil and condensate pipelines and above ground storage in Central Oklahoma. These assets consist of the following:
|
•
|
Central Oklahoma Crude Oil Gathering Systems. Our Central Oklahoma crude oil gathering systems include Black Coyote and Redbud. Black Coyote operates in the core of the STACK play in Central Oklahoma and was built primarily to service acreage dedicated from Devon, which is the anchor customer on the system. Redbud also operates in the core of the STACK play and is supported by a contract with Marathon Oil Company.
|
•
|
Transmission and Gathering 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, and two storage facilities. These assets consist of the following:
|
•
|
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.
|
•
|
Belle Rose Gas Storage Facility. The Belle Rose 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.
|
•
|
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.
|
•
|
Idled Processing Plants:
|
•
|
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. We have shut down the Blue Water gas processing plant and we do not expect to operate it in the near future unless 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 350 MMcf/d of natural gas. We have shut down the Eunice processing plant. The plant is not expected to operate in the near future unless 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. We have shut down the Sabine Pass processing plant and do not anticipate reopening the plant based on current market conditions.
|
•
|
NGL and Crude Oil Pipeline Systems. Our NGL and crude oil pipeline systems consist of NGL pipelines, crude oil and condensate pipelines, underground NGL storage, and our ORV crude logistics assets.
|
•
|
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.
|
•
|
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
|
•
|
Napoleonville Storage Facility. The Napoleonville NGL storage facility is connected to the Riverside facility and is comprised of two existing caverns. The caverns currently provide butane storage.
|
•
|
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 125,000 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 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.
|
•
|
GCF. 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 customers for a fee.
|
•
|
Cedar Cove JV. We own a 30% interest in the Cedar Cove JV, which operates gathering and compression assets in Blaine County, Oklahoma that tie into our existing Oklahoma assets. Kinder Morgan, Inc. owns a 70% interest in, and is the operator of, the Cedar Cove JV. All gas gathered by the Cedar Cove JV is processed by our Central Oklahoma processing facilities.
|
|
Year Ended December 31,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Devon
|
10.5
|
%
|
|
10.4
|
%
|
|
14.4
|
%
|
Dow Hydrocarbons and Resources LLC
|
10.0
|
%
|
|
11.1
|
%
|
|
11.2
|
%
|
Marathon Petroleum Corporation
|
13.8
|
%
|
|
11.5
|
%
|
|
(1)
|
|
(1)
|
Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the year ended December 31, 2017.
|
•
|
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;
|
•
|
public health crises that reduce economic activity and affect the demand for travel, including the coronavirus outbreak;
|
•
|
the availability of local, intrastate, and interstate transportation systems;
|
•
|
the availability of downstream NGL fractionation facilities;
|
•
|
the availability and marketing of competitive fuels;
|
•
|
the development and adoption of alternative energy technologies, such as electric vehicles;
|
•
|
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 funds available for operations and future business opportunities will be reduced by that portion of our cash flows required to make interest payments on our debt;
|
•
|
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 from governmental regulation, changes in feedstocks, products, and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.
|
•
|
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.
|
•
|
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.
|
•
|
properly conduct 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.
|
|
EnLink Midstream Partners, LP
|
||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
(In millions, except per unit data)
|
||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Product sales
|
$
|
5,030.1
|
|
|
$
|
6,512.3
|
|
|
$
|
4,358.4
|
|
|
$
|
3,008.9
|
|
|
$
|
3,253.7
|
|
Product sales—related parties
|
—
|
|
|
41.0
|
|
|
144.9
|
|
|
134.3
|
|
|
119.4
|
|
|||||
Midstream services
|
1,008.4
|
|
|
763.3
|
|
|
552.3
|
|
|
467.2
|
|
|
451.0
|
|
|||||
Midstream services—related parties
|
—
|
|
|
377.2
|
|
|
688.2
|
|
|
653.1
|
|
|
618.6
|
|
|||||
Gain (loss) on derivative activity
|
14.4
|
|
|
5.2
|
|
|
(4.2
|
)
|
|
(11.1
|
)
|
|
9.4
|
|
|||||
Total revenues
|
6,052.9
|
|
|
7,699.0
|
|
|
5,739.6
|
|
|
4,252.4
|
|
|
4,452.1
|
|
|||||
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of sales (1)
|
4,392.5
|
|
|
6,008.0
|
|
|
4,361.5
|
|
|
3,015.5
|
|
|
3,245.3
|
|
|||||
Operating expenses
|
467.1
|
|
|
453.4
|
|
|
418.7
|
|
|
398.5
|
|
|
419.9
|
|
|||||
General and administrative
|
139.2
|
|
|
130.2
|
|
|
123.5
|
|
|
119.3
|
|
|
132.4
|
|
|||||
(Gain) loss on disposition of assets
|
(1.9
|
)
|
|
0.4
|
|
|
—
|
|
|
13.2
|
|
|
1.2
|
|
|||||
Depreciation and amortization
|
617.0
|
|
|
577.3
|
|
|
545.3
|
|
|
503.9
|
|
|
387.3
|
|
|||||
Impairments
|
198.2
|
|
|
365.8
|
|
|
17.1
|
|
|
566.3
|
|
|
1,563.4
|
|
|||||
Loss on secured term loan receivable
|
52.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Gain on litigation settlement
|
—
|
|
|
—
|
|
|
(26.0
|
)
|
|
—
|
|
|
—
|
|
|||||
Total operating costs and expenses
|
5,865.0
|
|
|
7,535.1
|
|
|
5,440.1
|
|
|
4,616.7
|
|
|
5,749.5
|
|
|||||
Operating income (loss)
|
187.9
|
|
|
163.9
|
|
|
299.5
|
|
|
(364.3
|
)
|
|
(1,297.4
|
)
|
|||||
Other income (expense):
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net of interest income
|
(215.7
|
)
|
|
(178.3
|
)
|
|
(187.9
|
)
|
|
(188.1
|
)
|
|
(102.5
|
)
|
|||||
Gain on extinguishment of debt
|
—
|
|
|
—
|
|
|
9.0
|
|
|
—
|
|
|
—
|
|
|||||
Income (loss) from unconsolidated affiliates
|
(16.8
|
)
|
|
13.3
|
|
|
9.6
|
|
|
(19.9
|
)
|
|
20.4
|
|
|||||
Other income
|
0.9
|
|
|
0.6
|
|
|
0.6
|
|
|
0.3
|
|
|
0.8
|
|
|||||
Total other expense
|
(231.6
|
)
|
|
(164.4
|
)
|
|
(168.7
|
)
|
|
(207.7
|
)
|
|
(81.3
|
)
|
|||||
Income (loss) before non-controlling interest and income taxes
|
(43.7
|
)
|
|
(0.5
|
)
|
|
130.8
|
|
|
(572.0
|
)
|
|
(1,378.7
|
)
|
|||||
Income tax benefit (expense)
|
(2.5
|
)
|
|
2.1
|
|
|
24.0
|
|
|
(1.3
|
)
|
|
0.5
|
|
|||||
Net income (loss)
|
(46.2
|
)
|
|
1.6
|
|
|
154.8
|
|
|
(573.3
|
)
|
|
(1,378.2
|
)
|
|||||
Net income (loss) attributable to non-controlling interests
|
8.1
|
|
|
2.1
|
|
|
1.1
|
|
|
(2.6
|
)
|
|
(0.4
|
)
|
|||||
Net income (loss) attributable to ENLK
|
$
|
(54.3
|
)
|
|
$
|
(0.5
|
)
|
|
$
|
153.7
|
|
|
$
|
(570.7
|
)
|
|
$
|
(1,377.8
|
)
|
Distributions declared per limited partner unit
|
$
|
—
|
|
|
$
|
1.560
|
|
|
$
|
1.560
|
|
|
$
|
1.560
|
|
|
$
|
1.545
|
|
(1)
|
Includes related party cost of sales of $21.7 million, $114.1 million, $211.0 million, $150.1 million, and $141.3 million for the years ended December 31, 2019, 2018, 2017, 2016, and 2015, respectively.
|
|
EnLink Midstream Partners, LP
|
||||||||||||||||||
|
December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
|
(In millions)
|
||||||||||||||||||
Balance Sheet Data (end of period):
|
|
|
|
|
|
|
|
|
|
||||||||||
Property and equipment, net
|
$
|
7,081.3
|
|
|
$
|
6,846.7
|
|
|
$
|
6,587.0
|
|
|
$
|
6,256.7
|
|
|
$
|
5,666.8
|
|
Total assets
|
9,134.6
|
|
|
9,571.3
|
|
|
9,414.0
|
|
|
9,153.4
|
|
|
8,092.8
|
|
|||||
Long-term debt (including current maturities)
|
4,764.3
|
|
|
4,319.6
|
|
|
3,467.8
|
|
|
3,268.0
|
|
|
3,066.8
|
|
|||||
Partners' equity including non-controlling interest
|
3,564.9
|
|
|
4,284.1
|
|
|
4,805.5
|
|
|
4,640.4
|
|
|
4,434.5
|
|
•
|
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.
|
•
|
Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas;
|
•
|
North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas;
|
•
|
Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations 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 and our crude oil operations in ORV; 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, our derivative activity, and our general corporate assets 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.
|
•
|
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. See “Item 8. Financial Statements and Supplementary Data—Note 1” for more information regarding the GIP Transaction.
|
•
|
During the second quarter of 2018, we completed construction of an expansion to our Lobo II cryogenic gas processing plant, which brought total operational processing capacity at our Lobo facilities to 175 MMcf/d. We further expanded our natural gas processing capacity at our Lobo facilities through the construction of the Lobo III cryogenic gas processing plant, which was completed during the fourth quarter of 2018 and provided an additional 100 MMcf/d of operational capacity.
|
•
|
In late March 2018, we completed construction of Black Coyote. 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.
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Operating income
|
$
|
187.9
|
|
|
$
|
163.9
|
|
|
$
|
299.5
|
|
|
|
|
|
|
|
||||||
Add:
|
|
|
|
|
|
||||||
Operating expenses
|
467.1
|
|
|
453.4
|
|
|
418.7
|
|
|||
General and administrative
|
139.2
|
|
|
130.2
|
|
|
123.5
|
|
|||
(Gain) loss on disposition of assets
|
(1.9
|
)
|
|
0.4
|
|
|
—
|
|
|||
Depreciation and amortization
|
617.0
|
|
|
577.3
|
|
|
545.3
|
|
|||
Impairments
|
198.2
|
|
|
365.8
|
|
|
17.1
|
|
|||
Loss on secured term loan receivable
|
52.9
|
|
|
—
|
|
|
—
|
|
|||
Gain on litigation settlement
|
—
|
|
|
—
|
|
|
(26.0
|
)
|
|||
Gross operating margin
|
$
|
1,660.4
|
|
|
$
|
1,691.0
|
|
|
$
|
1,378.1
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Permian Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
2,542.3
|
|
|
$
|
3,030.3
|
|
|
$
|
1,797.2
|
|
Cost of sales
|
(2,283.9
|
)
|
|
(2,808.3
|
)
|
|
(1,628.5
|
)
|
|||
Total gross operating margin
|
$
|
258.4
|
|
|
$
|
222.0
|
|
|
$
|
168.7
|
|
North Texas Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
601.1
|
|
|
$
|
684.1
|
|
|
$
|
745.0
|
|
Cost of sales
|
(208.8
|
)
|
|
(199.2
|
)
|
|
(264.5
|
)
|
|||
Total gross operating margin
|
$
|
392.3
|
|
|
$
|
484.9
|
|
|
$
|
480.5
|
|
Oklahoma Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
1,181.1
|
|
|
$
|
1,299.8
|
|
|
$
|
874.8
|
|
Cost of sales
|
(627.0
|
)
|
|
(743.6
|
)
|
|
(523.0
|
)
|
|||
Total gross operating margin
|
$
|
554.1
|
|
|
$
|
556.2
|
|
|
$
|
351.8
|
|
Louisiana Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
2,622.8
|
|
|
$
|
3,788.4
|
|
|
$
|
3,182.2
|
|
Cost of sales
|
(2,181.6
|
)
|
|
(3,365.7
|
)
|
|
(2,800.9
|
)
|
|||
Total gross operating margin
|
$
|
441.2
|
|
|
$
|
422.7
|
|
|
$
|
381.3
|
|
Corporate Segment
|
|
|
|
|
|
||||||
Revenues
|
$
|
(894.4
|
)
|
|
$
|
(1,103.6
|
)
|
|
$
|
(859.6
|
)
|
Cost of sales
|
908.8
|
|
|
1,108.8
|
|
|
855.4
|
|
|||
Total gross operating margin
|
$
|
14.4
|
|
|
$
|
5.2
|
|
|
$
|
(4.2
|
)
|
Total
|
|
|
|
|
|
||||||
Revenues
|
$
|
6,052.9
|
|
|
$
|
7,699.0
|
|
|
$
|
5,739.6
|
|
Cost of sales
|
(4,392.5
|
)
|
|
(6,008.0
|
)
|
|
(4,361.5
|
)
|
|||
Total gross operating margin
|
$
|
1,660.4
|
|
|
$
|
1,691.0
|
|
|
$
|
1,378.1
|
|
|
|
|
|
|
|
||||||
Midstream Volumes:
|
|
|
|
|
|
||||||
Permian Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
723,400
|
|
|
521,900
|
|
|
361,200
|
|
|||
Processing (MMBtu/d)
|
771,400
|
|
|
531,700
|
|
|
385,000
|
|
|||
Crude Oil Handling (Bbls/d)
|
132,000
|
|
|
124,300
|
|
|
91,800
|
|
|||
North Texas Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
1,651,900
|
|
|
1,733,900
|
|
|
1,901,700
|
|
|||
Processing (MMBtu/d)
|
750,500
|
|
|
747,400
|
|
|
799,400
|
|
|||
Oklahoma Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
1,302,200
|
|
|
1,204,700
|
|
|
829,300
|
|
|||
Processing (MMBtu/d)
|
1,276,700
|
|
|
1,195,300
|
|
|
810,300
|
|
|||
Crude Oil Handling (Bbls/d)
|
47,300
|
|
|
15,700
|
|
|
—
|
|
|||
Louisiana Segment
|
|
|
|
|
|
||||||
Gathering and Transportation (MMBtu/d)
|
2,050,000
|
|
|
2,196,200
|
|
|
1,995,800
|
|
|||
Processing (MMBtu/d)
|
400,200
|
|
|
431,200
|
|
|
453,300
|
|
|||
Crude Oil Handling (Bbls/d)
|
18,900
|
|
|
15,400
|
|
|
16,400
|
|
|||
NGL Fractionation (Gals/d)
|
7,341,700
|
|
|
6,584,400
|
|
|
5,772,800
|
|
|||
Brine Disposal (Bbls/d)
|
2,700
|
|
|
3,200
|
|
|
4,200
|
|
•
|
Permian Segment. Gross operating margin in the Permian segment increased $36.4 million, which was primarily due to a $43.4 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $26.7 million from our Delaware Basin assets, and $16.7 million from our Midland Basin assets. This increase was partially offset by a $7.0 million decrease in gross operating margin from our Permian crude assets, which was due to a $5.4 million decrease in gross operating margin from our South Texas assets due to an MVC expiration in July 2019 and a $4.5 million decrease in gross operating margin associated with our physical crude marketing arrangements partially offset by a $2.9 million increase in gross operating margin from our Midland and Delaware Basins crude assets. We manage our exposure to crude price fluctuations in our physical crude marketing arrangements through various derivative arrangements, which primarily relate to our Permian segment. The timing of our realization of the gains or losses from these crude derivative arrangements may not occur in the same period as the corresponding physical crude marketing transaction, and all associated gains and losses from the derivative arrangements are reflected in our Corporate segment.
|
•
|
North Texas Segment. Gross operating margin in the North Texas segment decreased $92.6 million, which was primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets and normal volume declines due to limited new drilling in the region. Shortfall revenue from the Devon-related MVCs was $84.3 million for the year ended December 31, 2018.
|
•
|
Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $2.1 million. Gross operating margin from our Oklahoma assets increased $43.4 million, which was primarily due to higher volumes from continued development by our customers, with $20.4 million contributed by our Oklahoma gas assets and $23.0 million contributed by our Oklahoma crude assets. These increases in gross operating margin for the year ended December 31, 2019 derived from our Oklahoma assets were offset by the recognition of $45.5 million in revenue from a contract restructuring with White Star during the year ended December 31, 2018.
|
•
|
Louisiana Segment. Gross operating margin in the Louisiana segment increased $18.5 million. Gross operating margin from our NGL assets increased by $40.4 million primarily due to higher volumes with the completion of the Cajun-Sibon pipeline expansion in April 2019. Our ORV crude assets contributed an increase of $1.1 million primarily due to higher volumes. These increases were partially offset by a decrease of $23.0 million from our Louisiana gas business, primarily due to a $14.6 million decrease from a less favorable processing environment for our Louisiana gas plants and an $8.4 million decrease in our Louisiana gas transportation business due to the expiration of certain firm transportation contracts and decreased volumes during the same period.
|
•
|
Corporate Segment. Gross operating margin in the Corporate segment increased $9.2 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):
|
|
|
Year Ended December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
Realized swaps:
|
|
|
|
|
||||
Crude swaps
|
|
$
|
11.7
|
|
|
$
|
(0.3
|
)
|
NGL swaps
|
|
6.5
|
|
|
(3.2
|
)
|
||
Gas swaps
|
|
(3.7
|
)
|
|
(1.4
|
)
|
||
Realized gain (loss) on derivatives
|
|
14.5
|
|
|
(4.9
|
)
|
||
|
|
|
|
|
||||
Unrealized swaps:
|
|
|
|
|
||||
Crude swaps
|
|
(0.3
|
)
|
|
7.0
|
|
||
NGL swaps
|
|
(3.5
|
)
|
|
8.3
|
|
||
Gas swaps
|
|
3.7
|
|
|
(5.2
|
)
|
||
Change in fair value of derivatives
|
|
(0.1
|
)
|
|
10.1
|
|
||
|
|
|
|
|
||||
Gain on derivative activity
|
|
$
|
14.4
|
|
|
$
|
5.2
|
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Total
|
||||||||
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
|
$
|
9.4
|
|
|
$
|
—
|
|
|
$
|
10.3
|
|
|
$
|
19.7
|
|
Total
|
|
$
|
9.4
|
|
|
$
|
—
|
|
|
$
|
10.3
|
|
|
$
|
19.7
|
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
||||||||
Midstream services (1)
|
|
$
|
5.2
|
|
|
$
|
41.0
|
|
|
$
|
53.4
|
|
|
$
|
99.6
|
|
Midstream services—related parties
|
|
6.3
|
|
|
43.3
|
|
|
1.2
|
|
|
50.8
|
|
||||
Total
|
|
$
|
11.5
|
|
|
$
|
84.3
|
|
|
$
|
54.6
|
|
|
$
|
150.4
|
|
(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 “Item 8. Financial Statements and Supplementary Data—Note 2.”
|
|
Year Ended December 31,
|
|
Change
|
|||||||||||
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Permian Segment
|
$
|
112.9
|
|
|
$
|
96.1
|
|
|
$
|
16.8
|
|
|
17.5
|
%
|
North Texas Segment
|
102.9
|
|
|
112.7
|
|
|
(9.8
|
)
|
|
(8.7
|
)%
|
|||
Oklahoma Segment
|
104.0
|
|
|
90.3
|
|
|
13.7
|
|
|
15.2
|
%
|
|||
Louisiana Segment
|
147.3
|
|
|
154.3
|
|
|
(7.0
|
)
|
|
(4.5
|
)%
|
|||
Total
|
$
|
467.1
|
|
|
$
|
453.4
|
|
|
$
|
13.7
|
|
|
3.0
|
%
|
•
|
Permian Segment. Operating expenses in the Permian segment increased $16.8 million primarily due to expanded operations and higher utilities expense, bulk purchases of materials and supplies, construction fees and services, and compressor rentals.
|
•
|
North Texas Segment. Operating expenses in the North Texas segment decreased $9.8 million primarily due to decreased compressor rentals, compressor overhauls, and labor and benefits costs.
|
•
|
Oklahoma Segment. Operating expenses in the Oklahoma segment increased $13.7 million primarily due to expanded operations with increases in utilities, equipment rentals, compression operations and maintenance, and labor and benefits costs.
|
•
|
Louisiana Segment. Operating expenses in the Louisiana segment decreased $7.0 million primarily due to reduced materials and supplies expenses, labor and benefits costs, and compression rentals partially offset by increased equipment rental and utility costs.
|
•
|
Fees and services expense increased $4.6 million, which was primarily due to increased software consulting and legal fees.
|
•
|
Other office expense increased $2.9 million, which was primarily due to a reduction of expense allocation to ENLC as a result of the Merger, which closed during the first quarter of 2019.
|
•
|
Unit-based compensation expense increased $2.5 million, which was primarily due to increased bonus expense and accelerated vesting of units related to an executive departure in the third quarter of 2019. This increase was partially offset by accelerated vesting of units related to the GIP Transaction during 2018.
|
•
|
Labor and benefits costs decreased $0.7 million. Labor and benefit costs for the year ended December 31, 2019 included severance costs of $7.0 million, driven by an executive departure and a reduction in workforce, compared to $3.0 million in severance costs for the year ended December 31, 2018. The $4.0 million increase in severance costs between years was offset by a decrease in bonus expense of $5.5 million.
|
•
|
Transaction costs decreased $1.0 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019, compared to the costs of transactions related to the GIP Transaction, which closed during 2018.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
Senior notes
|
$
|
151.8
|
|
|
$
|
160.0
|
|
Related Party Debt
|
66.0
|
|
|
—
|
|
||
Term Loan
|
—
|
|
|
1.9
|
|
||
ENLK Credit Facility
|
0.3
|
|
|
22.3
|
|
||
Capitalized interest
|
(5.8
|
)
|
|
(7.0
|
)
|
||
Amortization of debt issuance costs and net discount
|
4.9
|
|
|
4.0
|
|
||
Other
|
(1.5
|
)
|
|
(2.9
|
)
|
||
Total interest expense, net of interest income
|
$
|
215.7
|
|
|
$
|
178.3
|
|
•
|
Permian Segment. Gross operating margin in the Permian segment increased $53.3 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 $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 and $2.3 million due to higher volumes on VEX.
|
•
|
North Texas Segment. Gross operating margin in the North Texas segment increased $4.4 million, which was primarily due to an increase in processing, gathering, and transmission volumes associated with new development in the Barnett
|
•
|
Oklahoma Segment. Gross operating margin in the Oklahoma segment increased $204.4 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 and Supplementary Data—Note 2”). 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. 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.
|
•
|
Louisiana Segment. Gross operating margin in the Louisiana segment increased $41.4 million, which was primarily due to a $29.0 million 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. In addition, there was a $14.9 million increase from ORV due to higher condensate stabilization volumes and improved margins from contract renegotiations.
|
•
|
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.
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Total
|
||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
||||||||
Midstream services (1)
|
$
|
5.2
|
|
|
$
|
41.0
|
|
|
$
|
53.4
|
|
|
$
|
99.6
|
|
Midstream services—related parties
|
6.3
|
|
|
43.3
|
|
|
1.2
|
|
|
50.8
|
|
||||
Total
|
$
|
11.5
|
|
|
$
|
84.3
|
|
|
$
|
54.6
|
|
|
$
|
150.4
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
$
|
—
|
|
|
$
|
0.8
|
|
|
$
|
16.1
|
|
|
$
|
16.9
|
|
Midstream services—related parties
|
8.9
|
|
|
59.2
|
|
|
13.8
|
|
|
81.9
|
|
||||
Total
|
$
|
8.9
|
|
|
$
|
60.0
|
|
|
$
|
29.9
|
|
|
$
|
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 “Item 8. Financial Statements and Supplementary Data—Note 2.”
|
|
Year Ended December 31,
|
|
Change
|
|||||||||||
|
2018
|
|
2017
|
|
$
|
|
%
|
|||||||
Permian Segment
|
$
|
96.1
|
|
|
$
|
85.1
|
|
|
$
|
11.0
|
|
|
12.9
|
%
|
North Texas Segment
|
112.7
|
|
|
121.8
|
|
|
(9.1
|
)
|
|
(7.5
|
)%
|
|||
Oklahoma Segment
|
90.3
|
|
|
64.6
|
|
|
25.7
|
|
|
39.8
|
%
|
|||
Louisiana Segment
|
154.3
|
|
|
147.2
|
|
|
7.1
|
|
|
4.8
|
%
|
|||
Total
|
$
|
453.4
|
|
|
$
|
418.7
|
|
|
$
|
34.7
|
|
|
8.3
|
%
|
•
|
Permian Segment. Operating expenses in the Permian segment increased $11.0 million primarily due to expanded operations and higher utilities expense.
|
•
|
North Texas Segment. Operating expenses in the North Texas segment decreased $9.1 million primarily due to decreases in materials and supplies, equipment rentals, and operational fees and services.
|
•
|
Oklahoma Segment. Operating expenses in the Oklahoma segment increased $25.7 million primarily 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.
|
•
|
Louisiana Segment. Operating expenses in the Louisiana segment increased $7.1 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.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
Operating cash flows before working capital
|
$
|
899.8
|
|
|
$
|
928.2
|
|
Changes in working capital
|
84.7
|
|
|
(71.4
|
)
|
•
|
General and administrative expenses excluding unit-based compensation increased $6.5 million, primarily due to higher transaction costs related to the Merger in January 2019. For more information, see “Results of Operations.”
|
•
|
Operating expenses excluding unit-based compensation increased $17.7 million primarily due to expanded operations. For more information, see “Results of Operations.”
|
•
|
Interest expense, excluding amortization of debt issue costs and net discounts, increased $36.5 million.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
Growth capital expenditures
|
$
|
(709.0
|
)
|
|
$
|
(800.3
|
)
|
Maintenance capital expenditures
|
(45.9
|
)
|
|
(42.8
|
)
|
||
Proceeds from sale of property
|
14.3
|
|
|
1.9
|
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
Net borrowings on related party debt
|
$
|
850.0
|
|
|
$
|
—
|
|
Unsecured senior notes repayments
|
(400.0
|
)
|
|
—
|
|
||
Proceeds from the Term Loan
|
—
|
|
|
850.0
|
|
||
Proceeds from issuance of common units
|
—
|
|
|
46.1
|
|
||
Payment of installment payable for EOGP acquisition
|
—
|
|
|
(250.0
|
)
|
||
Contributions by non-controlling partners (1)
|
97.5
|
|
|
156.4
|
|
||
Distributions to non-controlling interests (2)
|
(24.1
|
)
|
|
(54.5
|
)
|
||
Distributions to common units (3)
|
(667.0
|
)
|
|
(551.6
|
)
|
||
Distribution to general partner interest (including incentive distribution rights) (4)
|
(15.6
|
)
|
|
(61.9
|
)
|
||
Distributions to Series B Preferred unitholders (5)
|
(67.4
|
)
|
|
(65.0
|
)
|
||
Distributions to Series C Preferred unitholders (5)
|
(24.0
|
)
|
|
(24.0
|
)
|
(1)
|
Represents contributions from NGP to the Delaware Basin JV of $97.5 million and $90.5 million for the years ended December 31, 2019 and 2018, respectively. Represents contributions from ENLC to EOGP of $66.2 million for the year ended December 31, 2018.
|
(2)
|
Represents distributions to NGP for its ownership in the Delaware Basin JV and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV for the years December 31, 2019 and 2018. Includes distributions to ENLC for its ownership in EOGP for the year ended December 31, 2018.
|
(3)
|
Subsequent to the closing of the Merger, we no longer have publicly held common units. ENLC owns all of our outstanding common units and we make quarterly distributions to ENLC related to its ownership of our common units.
|
(4)
|
At the closing of the Merger, our general partner’s incentive distribution rights were eliminated.
|
(5)
|
See “Item 8. Financial Statements and Supplementary Data—Note 8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units.
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
Thereafter
|
||||||||||||||
Long-term debt obligations
|
$
|
3,100.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
550.0
|
|
|
$
|
2,550.0
|
|
Related party debt
|
1,700.0
|
|
|
—
|
|
|
850.0
|
|
|
—
|
|
|
—
|
|
|
350.0
|
|
|
500.0
|
|
|||||||
Interest payable on fixed long-term debt obligations
|
2,514.1
|
|
|
176.0
|
|
|
176.0
|
|
|
176.0
|
|
|
176.0
|
|
|
163.9
|
|
|
1,646.2
|
|
|||||||
Operating lease obligations
|
141.2
|
|
|
25.0
|
|
|
18.7
|
|
|
11.7
|
|
|
9.7
|
|
|
9.1
|
|
|
67.0
|
|
|||||||
Purchase obligations
|
21.2
|
|
|
21.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Pipeline and trucking capacity and deficiency agreements (1)
|
191.9
|
|
|
39.4
|
|
|
37.7
|
|
|
31.8
|
|
|
28.1
|
|
|
19.0
|
|
|
35.9
|
|
|||||||
Inactive easement commitment (2)
|
10.0
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Total contractual obligations
|
$
|
7,678.4
|
|
|
$
|
261.6
|
|
|
$
|
1,082.4
|
|
|
$
|
229.5
|
|
|
$
|
213.8
|
|
|
$
|
1,092.0
|
|
|
$
|
4,799.1
|
|
(1)
|
Consists of pipeline capacity payments for firm transportation and deficiency agreements.
|
(2)
|
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, 2019, less than 1% of our gross operating margin was generated from 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)
|
|
Net Fair Value
Asset/(Liability) (In millions) |
||
January 2020 - September 2020
|
|
Ethane
|
|
380 (MBbls)
|
|
$0.1692/gal
|
|
Index
|
|
$
|
(0.5
|
)
|
January 2020 - September 2020
|
|
Propane
|
|
954 (MBbls)
|
|
Index
|
|
$0.4399/gal
|
|
1.9
|
|
|
January 2020 - September 2020
|
|
Normal butane
|
|
339 (MBbls)
|
|
Index
|
|
$0.6136/gal
|
|
(0.3
|
)
|
|
January 2020 - September 2020
|
|
Natural gasoline
|
|
130 (MBbls)
|
|
Index
|
|
$1.2148/gal
|
|
0.1
|
|
|
January 2020 - January 2021
|
|
Natural gas
|
|
23,123 (MMBtu/d)
|
|
Index
|
|
$2.0241/MMBtu
|
|
0.6
|
|
|
January 2020 - July 2020
|
|
Crude and condensate
|
|
130 (MBbls)
|
|
Index
|
|
$55.60/Bbl
|
|
0.4
|
|
|
January 2020 - December 2022
|
|
Crude and condensate
|
|
10,933 (MBbls)
|
|
$2.015/Bbl
|
|
Index (2)
|
|
6.2
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8.4
|
|
(1)
|
Weighted average.
|
(2)
|
Represents the WTI Houston and WTI Midland differential.
|
|
/s/ KPMG LLP
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
77.4
|
|
|
$
|
99.5
|
|
Accounts receivable:
|
|
|
|
||||
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively
|
36.2
|
|
|
126.3
|
|
||
Accrued revenue and other
|
460.1
|
|
|
705.9
|
|
||
Related party
|
18.1
|
|
|
2.1
|
|
||
Fair value of derivative assets
|
12.9
|
|
|
28.6
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
56.9
|
|
|
72.8
|
|
||
Total current assets
|
661.6
|
|
|
1,035.2
|
|
||
Property and equipment, net of accumulated depreciation of $3,418.6 and $2,967.4, respectively
|
7,081.3
|
|
|
6,846.7
|
|
||
Intangible assets, net of accumulated amortization of $545.9 and $422.2, respectively
|
1,249.9
|
|
|
1,373.6
|
|
||
Goodwill
|
—
|
|
|
190.3
|
|
||
Investment in unconsolidated affiliates
|
43.1
|
|
|
80.1
|
|
||
Fair value of derivative assets
|
4.3
|
|
|
4.1
|
|
||
Other assets, net
|
94.4
|
|
|
41.3
|
|
||
Total assets
|
$
|
9,134.6
|
|
|
$
|
9,571.3
|
|
LIABILITIES AND PARTNERS’ EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable and drafts payable
|
$
|
70.6
|
|
|
$
|
105.5
|
|
Accounts payable to related party
|
1.1
|
|
|
4.3
|
|
||
Accrued gas, NGLs, condensate, and crude oil purchases
|
354.8
|
|
|
500.4
|
|
||
Fair value of derivative liabilities
|
14.4
|
|
|
21.8
|
|
||
Current maturities of long-term debt
|
—
|
|
|
399.8
|
|
||
Other current liabilities
|
201.7
|
|
|
246.7
|
|
||
Total current liabilities
|
642.6
|
|
|
1,278.5
|
|
||
Long-term debt, including $1,700.0 from affiliates
|
4,764.3
|
|
|
3,919.8
|
|
||
Asset retirement obligations
|
15.5
|
|
|
14.8
|
|
||
Other long-term liabilities
|
90.8
|
|
|
20.0
|
|
||
Deferred tax liability
|
44.5
|
|
|
42.4
|
|
||
Fair value of derivative liabilities
|
6.8
|
|
|
2.4
|
|
||
|
|
|
|
||||
Redeemable non-controlling interest
|
5.2
|
|
|
9.3
|
|
||
|
|
|
|
||||
Partners’ equity:
|
|
|
|
||||
Common unitholders (144,358,720 and 353,117,434 units issued and outstanding, respectively)
|
1,681.2
|
|
|
2,460.8
|
|
||
Series B preferred unitholders (59,599,550 and 58,728,994 units issued and outstanding, respectively)
|
895.1
|
|
|
889.3
|
|
||
Series C preferred unitholders (400,000 units outstanding)
|
395.1
|
|
|
395.1
|
|
||
General partner interest (1,594,974 equivalent units outstanding)
|
216.6
|
|
|
231.2
|
|
||
Accumulated other comprehensive loss
|
(14.5
|
)
|
|
(2.1
|
)
|
||
Non-controlling interest
|
391.4
|
|
|
309.8
|
|
||
Total partners’ equity
|
3,564.9
|
|
|
4,284.1
|
|
||
Commitments and contingencies (Note 13)
|
|
|
|
|
|
||
Total liabilities and partners’ equity
|
$
|
9,134.6
|
|
|
$
|
9,571.3
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Product sales
|
$
|
5,030.1
|
|
|
$
|
6,512.3
|
|
|
$
|
4,358.4
|
|
Product sales—related parties
|
—
|
|
|
41.0
|
|
|
144.9
|
|
|||
Midstream services
|
1,008.4
|
|
|
763.3
|
|
|
552.3
|
|
|||
Midstream services—related parties
|
—
|
|
|
377.2
|
|
|
688.2
|
|
|||
Gain (loss) on derivative activity
|
14.4
|
|
|
5.2
|
|
|
(4.2
|
)
|
|||
Total revenues
|
6,052.9
|
|
|
7,699.0
|
|
|
5,739.6
|
|
|||
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of sales (1)
|
4,392.5
|
|
|
6,008.0
|
|
|
4,361.5
|
|
|||
Operating expenses
|
467.1
|
|
|
453.4
|
|
|
418.7
|
|
|||
General and administrative
|
139.2
|
|
|
130.2
|
|
|
123.5
|
|
|||
(Gain) loss on disposition of assets
|
(1.9
|
)
|
|
0.4
|
|
|
—
|
|
|||
Depreciation and amortization
|
617.0
|
|
|
577.3
|
|
|
545.3
|
|
|||
Impairments
|
198.2
|
|
|
365.8
|
|
|
17.1
|
|
|||
Loss on secured term loan receivable
|
52.9
|
|
|
—
|
|
|
—
|
|
|||
Gain on litigation settlement
|
—
|
|
|
—
|
|
|
(26.0
|
)
|
|||
Total operating costs and expenses
|
5,865.0
|
|
|
7,535.1
|
|
|
5,440.1
|
|
|||
Operating income
|
187.9
|
|
|
163.9
|
|
|
299.5
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense, net of interest income (2)
|
(215.7
|
)
|
|
(178.3
|
)
|
|
(187.9
|
)
|
|||
Gain on extinguishment of debt
|
—
|
|
|
—
|
|
|
9.0
|
|
|||
Income (loss) from unconsolidated affiliates
|
(16.8
|
)
|
|
13.3
|
|
|
9.6
|
|
|||
Other income
|
0.9
|
|
|
0.6
|
|
|
0.6
|
|
|||
Total other expense
|
(231.6
|
)
|
|
(164.4
|
)
|
|
(168.7
|
)
|
|||
Income (loss) before non-controlling interest and income taxes
|
(43.7
|
)
|
|
(0.5
|
)
|
|
130.8
|
|
|||
Income tax benefit (expense)
|
(2.5
|
)
|
|
2.1
|
|
|
24.0
|
|
|||
Net income (loss)
|
(46.2
|
)
|
|
1.6
|
|
|
154.8
|
|
|||
Net income attributable to non-controlling interest
|
8.1
|
|
|
2.1
|
|
|
1.1
|
|
|||
Net income (loss) attributable to ENLK
|
$
|
(54.3
|
)
|
|
$
|
(0.5
|
)
|
|
$
|
153.7
|
|
(1)
|
Includes related party cost of sales of $21.7 million, $114.1 million, and $211.0 million for the years ended December 31, 2019, 2018, and 2017, respectively.
|
(2)
|
Includes related party interest expense of $66.0 million for the year ended December 31, 2019.
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Net income (loss)
|
$
|
(46.2
|
)
|
|
$
|
1.6
|
|
|
$
|
154.8
|
|
Loss on designated cash flow hedge
|
(12.4
|
)
|
|
—
|
|
|
(2.1
|
)
|
|||
Comprehensive income (loss)
|
(58.6
|
)
|
|
1.6
|
|
|
152.7
|
|
|||
Comprehensive income attributable to non-controlling interest
|
8.1
|
|
|
2.1
|
|
|
1.1
|
|
|||
Comprehensive income (loss) attributable to ENLK
|
$
|
(66.7
|
)
|
|
$
|
(0.5
|
)
|
|
$
|
151.6
|
|
|
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
|
|
$
|
|
$
|
|
$
|
|
$
|
||||||||||||||||||||
Balance, December 31, 2016
|
$
|
3,461.8
|
|
|
342.9
|
|
|
$
|
794.0
|
|
|
53.2
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
203.6
|
|
|
1.6
|
|
|
$
|
—
|
|
|
$
|
181.0
|
|
|
$
|
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
|
)
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
126.4
|
|
|
126.4
|
|
|
—
|
|
||||||||
Loss on designated cash flow hedge
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.1
|
)
|
|
—
|
|
|
(2.1
|
)
|
|
—
|
|
||||||||
Adjustment for acquisition of EOGP (Note 1)
|
48.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(48.4
|
)
|
|
—
|
|
|
—
|
|
||||||||
Net income
|
17.9
|
|
|
—
|
|
|
86.0
|
|
|
—
|
|
|
6.7
|
|
|
—
|
|
|
43.1
|
|
|
—
|
|
|
—
|
|
|
1.1
|
|
|
154.8
|
|
|
—
|
|
||||||||
Balance, December 31, 2017
|
3,108.6
|
|
|
349.7
|
|
|
864.1
|
|
|
57.1
|
|
|
395.1
|
|
|
0.4
|
|
|
206.6
|
|
|
1.6
|
|
|
(2.1
|
)
|
|
233.2
|
|
|
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
|
)
|
|
—
|
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156.4
|
|
|
156.4
|
|
|
—
|
|
||||||||
Fair value adjustment related to redeemable non-controlling interest
|
(4.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.1
|
)
|
|
4.1
|
|
||||||||
Adjustment for acquisition of EOGP (Note 1)
|
26.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(26.8
|
)
|
|
—
|
|
|
—
|
|
||||||||
Net income (loss)
|
(180.8
|
)
|
|
—
|
|
|
90.2
|
|
|
—
|
|
|
24.0
|
|
|
—
|
|
|
66.1
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|
1.0
|
|
|
0.6
|
|
||||||||
Balance, December 31, 2018
|
$
|
2,460.8
|
|
|
353.1
|
|
|
$
|
889.3
|
|
|
58.7
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
231.2
|
|
|
1.6
|
|
|
$
|
(2.1
|
)
|
|
$
|
309.8
|
|
|
$
|
4,284.1
|
|
|
$
|
9.3
|
|
|
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
|
|
$
|
|
$
|
|
$
|
|
$
|
||||||||||||||||||||
Balance, December 31, 2018
|
$
|
2,460.8
|
|
|
353.1
|
|
|
$
|
889.3
|
|
|
58.7
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
231.2
|
|
|
1.6
|
|
|
$
|
(2.1
|
)
|
|
$
|
309.8
|
|
|
$
|
4,284.1
|
|
|
$
|
9.3
|
|
Adoption of ASC 842
|
0.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
||||||||
Balance, January 1, 2019
|
2,461.1
|
|
|
353.1
|
|
|
889.3
|
|
|
58.7
|
|
|
395.1
|
|
|
0.4
|
|
|
231.2
|
|
|
1.6
|
|
|
(2.1
|
)
|
|
309.8
|
|
|
4,284.4
|
|
|
9.3
|
|
||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(2.8
|
)
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.8
|
)
|
|
—
|
|
||||||||
Unit-based compensation
|
1.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38.4
|
|
|
—
|
|
||||||||
Distributions
|
(667.0
|
)
|
|
—
|
|
|
(67.4
|
)
|
|
0.9
|
|
|
(24.0
|
)
|
|
—
|
|
|
(15.6
|
)
|
|
—
|
|
|
—
|
|
|
(23.8
|
)
|
|
(797.8
|
)
|
|
(0.3
|
)
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
97.5
|
|
|
97.5
|
|
|
—
|
|
||||||||
Loss on designated cash flow hedge
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12.4
|
)
|
|
—
|
|
|
(12.4
|
)
|
|
—
|
|
||||||||
Fair value adjustment related to redeemable non-controlling interest
|
4.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.0
|
|
|
(4.0
|
)
|
||||||||
Net income (loss)
|
(115.5
|
)
|
|
—
|
|
|
73.2
|
|
|
—
|
|
|
24.0
|
|
|
—
|
|
|
(36.0
|
)
|
|
—
|
|
|
—
|
|
|
7.9
|
|
|
(46.4
|
)
|
|
0.2
|
|
||||||||
Issuance of common units to ENLC for acquisition of EOGP
|
—
|
|
|
55.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Conversion of ENLK common units into ENLC units
|
—
|
|
|
(265.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Balance, December 31, 2019
|
$
|
1,681.2
|
|
|
144.4
|
|
|
$
|
895.1
|
|
|
59.6
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
216.6
|
|
|
1.6
|
|
|
$
|
(14.5
|
)
|
|
$
|
391.4
|
|
|
$
|
3,564.9
|
|
|
$
|
5.2
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(46.2
|
)
|
|
$
|
1.6
|
|
|
$
|
154.8
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Impairments
|
198.2
|
|
|
365.8
|
|
|
17.1
|
|
|||
Depreciation and amortization
|
617.0
|
|
|
577.3
|
|
|
545.3
|
|
|||
Loss on secured term loan receivable
|
52.9
|
|
|
—
|
|
|
—
|
|
|||
Non-cash revenue from contract restructuring
|
—
|
|
|
(45.5
|
)
|
|
—
|
|
|||
Non-cash unit-based compensation
|
39.2
|
|
|
40.8
|
|
|
47.8
|
|
|||
Deferred tax expense (benefit)
|
2.1
|
|
|
(3.9
|
)
|
|
(26.6
|
)
|
|||
(Gain) loss on derivative activity recognized in net income (loss)
|
(14.4
|
)
|
|
(5.2
|
)
|
|
4.2
|
|
|||
Cash settlements on derivatives
|
16.9
|
|
|
(7.0
|
)
|
|
(11.2
|
)
|
|||
Gain on extinguishment of debt
|
—
|
|
|
—
|
|
|
(9.0
|
)
|
|||
Amortization of debt issue costs, net (premium) discount of notes and installment payable
|
4.9
|
|
|
4.0
|
|
|
29.1
|
|
|||
Distribution of earnings from unconsolidated affiliates
|
16.5
|
|
|
15.8
|
|
|
13.3
|
|
|||
(Income) loss from unconsolidated affiliates
|
16.8
|
|
|
(13.3
|
)
|
|
(9.6
|
)
|
|||
Other operating activities
|
(4.1
|
)
|
|
(2.2
|
)
|
|
0.6
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable, accrued revenue, and other
|
320.3
|
|
|
(114.6
|
)
|
|
(189.5
|
)
|
|||
Natural gas and NGLs inventory, prepaid expenses, and other
|
12.7
|
|
|
(12.2
|
)
|
|
(23.7
|
)
|
|||
Accounts payable, accrued product purchases, and other accrued liabilities
|
(248.3
|
)
|
|
55.4
|
|
|
163.9
|
|
|||
Net cash provided by operating activities
|
984.5
|
|
|
856.8
|
|
|
706.5
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Additions to property and equipment
|
(754.9
|
)
|
|
(843.1
|
)
|
|
(790.8
|
)
|
|||
Proceeds from sale of unconsolidated affiliate investment
|
—
|
|
|
—
|
|
|
189.7
|
|
|||
Proceeds from sale of property
|
14.3
|
|
|
1.9
|
|
|
2.3
|
|
|||
Investment in unconsolidated affiliates
|
—
|
|
|
(0.1
|
)
|
|
(12.6
|
)
|
|||
Distribution from unconsolidated affiliates in excess of earnings
|
3.7
|
|
|
6.9
|
|
|
0.2
|
|
|||
Other investing activities
|
(4.6
|
)
|
|
8.1
|
|
|
0.4
|
|
|||
Net cash used in investing activities
|
(741.5
|
)
|
|
(826.3
|
)
|
|
(610.8
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds from borrowings
|
4,160.0
|
|
|
3,904.0
|
|
|
2,315.9
|
|
|||
Payments on borrowings
|
(3,710.0
|
)
|
|
(3,054.0
|
)
|
|
(2,104.3
|
)
|
|||
Payment of installment payable for EOGP acquisition
|
—
|
|
|
(250.0
|
)
|
|
(250.0
|
)
|
|||
Debt financing costs
|
(10.0
|
)
|
|
(1.7
|
)
|
|
(5.5
|
)
|
|||
Proceeds from issuance of common units
|
—
|
|
|
46.1
|
|
|
106.9
|
|
|||
Proceeds from issuance of Series C Preferred Units
|
—
|
|
|
—
|
|
|
394.0
|
|
|||
Distribution to common unitholders and to general partner
|
(682.6
|
)
|
|
(613.5
|
)
|
|
(604.8
|
)
|
|||
Distributions to Series B Preferred Unitholders
|
(67.4
|
)
|
|
(65.0
|
)
|
|
(15.9
|
)
|
|||
Distributions to Series C Preferred Unitholders
|
(24.0
|
)
|
|
(24.0
|
)
|
|
(5.6
|
)
|
|||
Distributions to non-controlling interests
|
(24.1
|
)
|
|
(54.5
|
)
|
|
(27.5
|
)
|
|||
Contributions by non-controlling interests, including contributions from ENLC of $66.2 million and $69.1 million for the years ended December 31, 2018 and 2017, respectively
|
97.5
|
|
|
156.4
|
|
|
126.4
|
|
|||
Other financing activities
|
(4.5
|
)
|
|
(5.6
|
)
|
|
(6.1
|
)
|
|||
Net cash provided by (used in) financing activities
|
(265.1
|
)
|
|
38.2
|
|
|
(76.5
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
(22.1
|
)
|
|
68.7
|
|
|
19.2
|
|
|||
Cash and cash equivalents, beginning of period
|
99.5
|
|
|
30.8
|
|
|
11.6
|
|
|||
Cash and cash equivalents, end of period
|
$
|
77.4
|
|
|
$
|
99.5
|
|
|
$
|
30.8
|
|
•
|
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 our general partner.
|
•
|
Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into 1.15 ENLC common units, which resulted in ENLC owning all of the remaining outstanding ENLK common units.
|
•
|
Our general partner’s incentive distribution rights in ENLK were eliminated.
|
•
|
Certain terms of the Series B Preferred Units were 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. ENLC also agreed to issue an additional ENLC Class C Common Unit to the applicable holder of each Series B Preferred Unit for each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions. 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 our then-existing senior notes continue to be issued and outstanding following the Merger.
|
•
|
Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan was converted into 1.15 awards with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time.
|
•
|
Each unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan was modified such that the performance metric for any then outstanding performance award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger.
|
•
|
ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “Note 6—Long-Term Debt” for additional information regarding the Term Loan.
|
•
|
We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, ENLC entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility.
|
•
|
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—Product 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.
|
•
|
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.
|
MVC and Firm Transportation Commitments (in millions) (1)
|
|
||
2020
|
$
|
262.7
|
|
2021
|
111.0
|
|
|
2022
|
97.6
|
|
|
2023
|
92.7
|
|
|
2024
|
81.3
|
|
|
Thereafter
|
158.2
|
|
|
Total
|
$
|
803.5
|
|
(1)
|
Amounts do not represent expected shortfall under these commitments.
|
|
Year Ended December 31,
|
||||||
|
2019
|
|
2018
|
||||
Transmission assets
|
$
|
1,376.5
|
|
|
$
|
1,329.4
|
|
Gathering systems
|
4,856.5
|
|
|
4,410.5
|
|
||
Gas processing plants
|
3,862.2
|
|
|
3,590.5
|
|
||
Other property and equipment
|
188.0
|
|
|
171.7
|
|
||
Construction in process
|
216.7
|
|
|
312.0
|
|
||
Property and equipment
|
10,499.9
|
|
|
9,814.1
|
|
||
Accumulated depreciation
|
(3,418.6
|
)
|
|
(2,967.4
|
)
|
||
Property and equipment, net of accumulated depreciation
|
$
|
7,081.3
|
|
|
$
|
6,846.7
|
|
|
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,
|
|||||||
|
2019
|
|
2018
|
|
2017
|
|||
Devon
|
10.5
|
%
|
|
10.4
|
%
|
|
14.4
|
%
|
Dow Hydrocarbons and Resources LLC
|
10.0
|
%
|
|
11.1
|
%
|
|
11.2
|
%
|
Marathon Petroleum Corporation
|
13.8
|
%
|
|
11.5
|
%
|
|
(1)
|
|
(1)
|
Consolidated revenues for Marathon Petroleum Corporation did not exceed 10% of our consolidated revenues for the year ended December 31, 2017.
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Balance, beginning of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
Impairment
|
—
|
|
|
—
|
|
|
(190.3
|
)
|
|
—
|
|
|
—
|
|
|
(190.3
|
)
|
||||||
Balance, end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Balance, beginning of period
|
$
|
29.3
|
|
|
$
|
202.7
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Impairment
|
(29.3
|
)
|
|
(202.7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(232.0
|
)
|
||||||
Balance, end of period
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
||||||
Year Ended December 31, 2019
|
|
|
|
|
|
||||||
Customer relationships, beginning of period
|
$
|
1,795.8
|
|
|
$
|
(422.2
|
)
|
|
$
|
1,373.6
|
|
Amortization expense
|
—
|
|
|
(123.7
|
)
|
|
(123.7
|
)
|
|||
Customer relationships, end of period
|
$
|
1,795.8
|
|
|
$
|
(545.9
|
)
|
|
$
|
1,249.9
|
|
|
|
|
|
|
|
||||||
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
|
|
2020
|
$
|
123.7
|
|
2021
|
123.7
|
|
|
2022
|
123.7
|
|
|
2023
|
123.6
|
|
|
2024
|
123.4
|
|
|
Thereafter
|
631.8
|
|
|
Total
|
$
|
1,249.9
|
|
•
|
Office space. Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $60.0 million of our lease liability and $39.8 million of our right-of-use asset as of December 31, 2019. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred.
|
•
|
Compression and other field equipment. We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $27.1 million of our lease liability and $27.1 million of our right-of-use asset as of December 31, 2019. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred.
|
•
|
Office equipment. We rent office equipment for a monthly fee. These leases are typically for several years and represent $0.6 million of our lease liability and $0.6 million of our right-of-use asset as of December 31, 2019.
|
•
|
Land and land easements. We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $15.3 million of our lease liability and $12.9 million of our right-of-use asset as of December 31, 2019.
|
|
December 31, 2019
|
||
Operating leases:
|
|
||
Other assets, net
|
$
|
80.4
|
|
Other current liabilities
|
$
|
21.1
|
|
Other long-term liabilities
|
$
|
81.9
|
|
|
|
||
Other lease information
|
|
||
Weighted-average remaining lease term—Operating leases
|
10.6 years
|
|
|
Weighted-average discount rate—Operating leases
|
5.1
|
%
|
|
Year Ended December 31, 2019
|
||
Finance lease expense:
|
|
||
Amortization of right-of-use asset
|
$
|
5.2
|
|
Interest on lease liability
|
0.1
|
|
|
Operating lease expense:
|
|
||
Long-term operating lease expense
|
28.7
|
|
|
Short-term lease expense
|
32.0
|
|
|
Variable lease expense
|
7.7
|
|
|
Total lease expense
|
$
|
68.4
|
|
|
Year Ended December 31, 2019
|
||
Supplemental cash flow information:
|
|
||
Cash payments for finance leases included in cash flows from financing activities
|
$
|
1.2
|
|
Cash payments for operating leases included in cash flows from operating activities
|
$
|
29.8
|
|
Right-of-use assets obtained in exchange for operating lease liabilities
|
$
|
104.1
|
|
|
Total
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
Thereafter
|
||||||||||||||
Undiscounted operating lease liability
|
$
|
141.2
|
|
|
$
|
25.0
|
|
|
$
|
18.7
|
|
|
$
|
11.7
|
|
|
$
|
9.7
|
|
|
$
|
9.1
|
|
|
$
|
67.0
|
|
Reduction due to present value
|
(38.2
|
)
|
|
(4.7
|
)
|
|
(3.9
|
)
|
|
(3.4
|
)
|
|
(3.1
|
)
|
|
(2.7
|
)
|
|
(20.4
|
)
|
|||||||
Operating lease liability
|
$
|
103.0
|
|
|
$
|
20.3
|
|
|
$
|
14.8
|
|
|
$
|
8.3
|
|
|
$
|
6.6
|
|
|
$
|
6.4
|
|
|
$
|
46.6
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||||||||||
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
||||||||||||
Related party debt
|
$
|
1,700.0
|
|
|
$
|
—
|
|
|
$
|
1,700.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Term Loan due 2021 (1)
|
—
|
|
|
—
|
|
|
—
|
|
|
850.0
|
|
|
—
|
|
|
850.0
|
|
||||||
2.70% Senior unsecured notes due 2019 (2)
|
—
|
|
|
—
|
|
|
—
|
|
|
400.0
|
|
|
—
|
|
|
400.0
|
|
||||||
4.40% Senior unsecured notes due 2024
|
550.0
|
|
|
1.5
|
|
|
551.5
|
|
|
550.0
|
|
|
1.8
|
|
|
551.8
|
|
||||||
4.15% Senior unsecured notes due 2025
|
750.0
|
|
|
(0.7
|
)
|
|
749.3
|
|
|
750.0
|
|
|
(0.9
|
)
|
|
749.1
|
|
||||||
4.85% Senior unsecured notes due 2026
|
500.0
|
|
|
(0.5
|
)
|
|
499.5
|
|
|
500.0
|
|
|
(0.5
|
)
|
|
499.5
|
|
||||||
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
|
|
|
(5.9
|
)
|
|
444.1
|
|
|
450.0
|
|
|
(6.2
|
)
|
|
443.8
|
|
||||||
5.45% Senior unsecured notes due 2047
|
500.0
|
|
|
(0.1
|
)
|
|
499.9
|
|
|
500.0
|
|
|
(0.1
|
)
|
|
499.9
|
|
||||||
Debt classified as long-term, including current maturities of long-term debt
|
$
|
4,800.0
|
|
|
$
|
(5.9
|
)
|
|
4,794.1
|
|
|
$
|
4,350.0
|
|
|
$
|
(6.1
|
)
|
|
4,343.9
|
|
||
Debt issuance cost (3)
|
|
|
|
|
(29.8
|
)
|
|
|
|
|
|
(24.3
|
)
|
||||||||||
Less: Current maturities of long-term debt (2)
|
|
|
|
|
—
|
|
|
|
|
|
|
(399.8
|
)
|
||||||||||
Long-term debt, net of unamortized issuance cost
|
|
|
|
|
$
|
4,764.3
|
|
|
|
|
|
|
$
|
3,919.8
|
|
(1)
|
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. In connection with the closing of the Merger, the Term Loan was assumed by ENLC, and we became a guarantor of the Term Loan.
|
(2)
|
The 2.70% senior unsecured notes matured 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.
|
(3)
|
Net of accumulated amortization of $10.9 million and $15.3 million at December 31, 2019 and 2018, respectively.
|
2020
|
$
|
—
|
|
2021
|
850.0
|
|
|
2022
|
—
|
|
|
2023
|
—
|
|
|
2024
|
900.0
|
|
|
Thereafter
|
3,050.0
|
|
|
Subtotal
|
4,800.0
|
|
|
Less: net discount
|
(5.9
|
)
|
|
Less: debt issuance cost
|
(29.8
|
)
|
|
Long-term debt, net of unamortized issuance cost
|
$
|
4,764.3
|
|
Issuance
|
|
Maturity Date of Notes
|
|
Early Redemption Date
|
|
Basis Point Premium
|
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
|
2029 Notes
|
|
June 1, 2029
|
|
Prior to March 1, 2029
|
|
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 ENLC and ENLK.
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Current income tax expense
|
$
|
(0.4
|
)
|
|
$
|
(1.8
|
)
|
|
$
|
(2.6
|
)
|
Deferred tax benefit (expense)
|
(2.1
|
)
|
|
3.9
|
|
|
26.6
|
|
|||
Total income tax benefit (expense)
|
$
|
(2.5
|
)
|
|
$
|
2.1
|
|
|
$
|
24.0
|
|
Declaration period
|
|
Distribution
paid as additional Series B Preferred Units |
|
Cash distribution
(in millions) |
|
Date paid/payable
|
|||
2019
|
|
|
|
|
|
|
|||
First Quarter of 2019
|
|
147,887
|
|
|
$
|
16.7
|
|
|
May 14, 2019
|
Second Quarter of 2019
|
|
148,257
|
|
|
$
|
17.1
|
|
|
August 13, 2019
|
Third Quarter of 2019
|
|
148,627
|
|
|
$
|
17.1
|
|
|
November 13, 2019
|
Fourth Quarter of 2019
|
|
148,999
|
|
|
$
|
16.8
|
|
|
February 13, 2020
|
|
|
|
|
|
|
|
|||
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
|
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
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Income allocation for incentive distributions
|
$
|
—
|
|
|
$
|
59.5
|
|
|
$
|
58.9
|
|
Unit-based compensation attributable to ENLC’s restricted and performance units
|
(37.0
|
)
|
|
(20.3
|
)
|
|
(21.0
|
)
|
|||
General partner share of net income (loss)
|
(1.4
|
)
|
|
(0.6
|
)
|
|
0.4
|
|
|||
General partner interest in EOGP acquisition
|
2.4
|
|
|
27.5
|
|
|
4.8
|
|
|||
General partner interest in net income (loss)
|
$
|
(36.0
|
)
|
|
$
|
66.1
|
|
|
$
|
43.1
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
GCF
|
|
|
|
|
|
||||||
Distributions
|
$
|
19.2
|
|
|
$
|
22.3
|
|
|
$
|
12.7
|
|
Equity in income
|
$
|
16.5
|
|
|
$
|
15.8
|
|
|
$
|
12.6
|
|
|
|
|
|
|
|
||||||
HEP
|
|
|
|
|
|
||||||
Equity in loss (1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3.4
|
)
|
|
|
|
|
|
|
||||||
Cedar Cove JV
|
|
|
|
|
|
||||||
Contributions
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
12.6
|
|
Distributions
|
$
|
1.0
|
|
|
$
|
0.4
|
|
|
$
|
0.8
|
|
Equity in income (loss) (2)
|
$
|
(33.3
|
)
|
|
$
|
(2.5
|
)
|
|
$
|
0.4
|
|
|
|
|
|
|
|
||||||
Total
|
|
|
|
|
|
||||||
Contributions
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
12.6
|
|
Distributions
|
$
|
20.2
|
|
|
$
|
22.7
|
|
|
$
|
13.5
|
|
Equity in income (loss) (1)(2)
|
$
|
(16.8
|
)
|
|
$
|
13.3
|
|
|
$
|
9.6
|
|
(1)
|
Includes a loss of $3.4 million for the year ended December 31, 2017 related to the sale of our HEP interests. In March 2017, we sold an approximate 31.0% ownership interest in HEP for aggregate net proceeds of $189.7 million.
|
(2)
|
Includes a loss of $31.4 million for the year ended December 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV, as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV.
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
GCF
|
$
|
39.2
|
|
|
$
|
41.9
|
|
Cedar Cove JV
|
3.9
|
|
|
38.2
|
|
||
Total investment in unconsolidated affiliates
|
$
|
43.1
|
|
|
$
|
80.1
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Cost of unit-based compensation charged to general and administrative expense
|
$
|
32.5
|
|
|
$
|
30.0
|
|
|
$
|
37.1
|
|
Cost of unit-based compensation charged to operating expense
|
6.7
|
|
|
10.8
|
|
|
10.7
|
|
|||
Total unit-based compensation expense
|
$
|
39.2
|
|
|
$
|
40.8
|
|
|
$
|
47.8
|
|
|
|
Year Ended December 31, 2019
|
|||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
Number of Units
|
|
Weighted Average
Grant-Date Fair Value
|
|||
Non-vested, beginning of period
|
|
2,556,270
|
|
|
$
|
14.43
|
|
Vested (1)
|
|
(722,853
|
)
|
|
10.02
|
|
|
Forfeited
|
|
(4,490
|
)
|
|
11.93
|
|
|
Converted to ENLC (2)
|
|
(1,828,927
|
)
|
|
16.11
|
|
|
Non-vested, end of period
|
|
—
|
|
|
$
|
—
|
|
(1)
|
Vested units included 249,201 units withheld for payroll taxes paid on behalf of employees.
|
(2)
|
As a result of the Merger, the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.
|
|
|
Year Ended December 31,
|
||||||||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
2019
|
|
2018
|
|
2017
|
||||||
Aggregate intrinsic value of units vested
|
|
$
|
8.0
|
|
|
$
|
13.1
|
|
|
$
|
16.6
|
|
Fair value of units vested
|
|
$
|
7.2
|
|
|
$
|
16.4
|
|
|
$
|
22.6
|
|
EnLink Midstream Partners, LP Performance Units:
|
|
March 2018
|
|
March 2017
|
||||
Grant-date fair value
|
|
$
|
19.24
|
|
|
$
|
25.73
|
|
Beginning TSR price
|
|
$
|
15.44
|
|
|
$
|
17.55
|
|
Risk-free interest rate
|
|
2.38
|
%
|
|
1.62
|
%
|
||
Volatility factor
|
|
43.85
|
%
|
|
43.94
|
%
|
||
Distribution yield
|
|
10.5
|
%
|
|
8.7
|
%
|
|
|
Year Ended December 31, 2019
|
|||||
EnLink Midstream Partners, LP Performance Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
|||
Non-vested, beginning of period
|
|
451,669
|
|
|
$
|
17.74
|
|
Vested (1)
|
|
(161,410
|
)
|
|
10.54
|
|
|
Converted to ENLC (2)
|
|
(290,259
|
)
|
|
28.31
|
|
|
Non-vested, end of period
|
|
—
|
|
|
$
|
—
|
|
(1)
|
Vested units included 62,403 units withheld for payroll taxes paid on behalf of employees.
|
(2)
|
As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC unit-based performance awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.
|
|
|
Year Ended December 31,
|
||||||
EnLink Midstream Partners, LP Performance Units:
|
|
2019
|
|
2018
|
||||
Aggregate intrinsic value of units vested
|
|
$
|
2.1
|
|
|
$
|
5.0
|
|
Fair value of units vested
|
|
$
|
1.7
|
|
|
$
|
7.7
|
|
|
|
Year Ended December 31, 2019
|
||||||
EnLink Midstream, LLC Restricted Incentive Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
2,425,867
|
|
|
$
|
14.62
|
|
|
Granted (1)
|
|
2,027,653
|
|
|
11.09
|
|
||
Vested (1)(2)
|
|
(1,886,905
|
)
|
|
12.06
|
|
||
Forfeited
|
|
(606,276
|
)
|
|
13.85
|
|
||
Converted from ENLK (3)
|
|
2,103,266
|
|
|
14.01
|
|
||
Non-vested, end of period
|
|
4,063,605
|
|
|
$
|
13.85
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
24.9
|
|
|
|
|
(1)
|
Restricted incentive units typically vest at the end of three years. In March 2019, ENLC granted 420,842 restricted incentive units with a fair value of $4.8 million to officers and certain employees as bonus payments for 2018, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
|
(2)
|
Vested units included 626,133 units withheld for payroll taxes paid on behalf of employees.
|
(3)
|
Represents Legacy ENLK Awards that were converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.
|
|
|
Year Ended December 31,
|
||||||||||
EnLink Midstream, LLC Restricted Incentive Units:
|
|
2019
|
|
2018
|
|
2017
|
||||||
Aggregate intrinsic value of units vested
|
|
$
|
17.3
|
|
|
$
|
12.8
|
|
|
$
|
15.3
|
|
Fair value of units vested
|
|
$
|
22.8
|
|
|
$
|
16.5
|
|
|
$
|
22.2
|
|
Performance Level
|
|
Achieved ENLC TSR
Position Relative to Designated Peer Companies |
|
Vesting percentage
of the Tranche TSR Units |
Below Threshold
|
|
Less than 25%
|
|
0%
|
Threshold
|
|
Equal to 25%
|
|
50%
|
Target
|
|
Equal to 50%
|
|
100%
|
Maximum
|
|
Greater than or Equal to 75%
|
|
200%
|
Performance Level
|
|
ENLC’s Achieved Cash Flow
|
|
Vesting percentage
of the Tranche CF Units |
Below Threshold
|
|
Less than $1.43
|
|
0%
|
Threshold
|
|
Equal to $1.43
|
|
50%
|
Target
|
|
Equal to $1.55
|
|
100%
|
Maximum
|
|
Greater than or Equal to $1.72
|
|
200%
|
EnLink Midstream, LLC Performance Units:
|
|
October 2019
|
|
June 2019
|
|
March 2019
|
|
March 2018
|
|
March 2017
|
||||||||||
Grant-date fair value
|
|
$
|
7.29
|
|
|
$
|
9.92
|
|
|
$
|
13.10
|
|
|
$
|
21.63
|
|
|
$
|
28.77
|
|
Beginning TSR price
|
|
$
|
7.42
|
|
|
$
|
9.84
|
|
|
$
|
10.92
|
|
|
$
|
16.55
|
|
|
$
|
18.29
|
|
Risk-free interest rate
|
|
1.44
|
%
|
|
1.72
|
%
|
|
2.42
|
%
|
|
2.38
|
%
|
|
1.62
|
%
|
|||||
Volatility factor
|
|
35.00
|
%
|
|
33.50
|
%
|
|
33.86
|
%
|
|
51.36
|
%
|
|
52.07
|
%
|
|||||
Distribution yield
|
|
10.1
|
%
|
|
11.5
|
%
|
|
9.7
|
%
|
|
6.7
|
%
|
|
5.4
|
%
|
|
|
Year Ended December 31, 2019
|
||||||
EnLink Midstream, LLC Performance Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
418,149
|
|
|
$
|
19.15
|
|
|
Granted
|
|
1,202,105
|
|
|
11.73
|
|
||
Vested (1)
|
|
(374,745
|
)
|
|
21.08
|
|
||
Forfeited
|
|
(261,451
|
)
|
|
15.68
|
|
||
Converted from ENLK (2)
|
|
333,798
|
|
|
25.84
|
|
||
Non-vested, end of period
|
|
1,317,856
|
|
|
$
|
14.22
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
8.1
|
|
|
|
(1)
|
Vested units included 146,218 units withheld for payroll taxes paid on behalf of employees.
|
(2)
|
As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC performance-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.
|
|
|
Year Ended December 31,
|
||||||
EnLink Midstream, LLC Performance Units:
|
|
2019
|
|
2018
|
||||
Aggregate intrinsic value of units vested
|
|
$
|
3.4
|
|
|
$
|
4.7
|
|
Fair value of units vested
|
|
$
|
7.9
|
|
|
$
|
7.7
|
|
|
December 31, 2019
|
||
Fair value of derivative liabilities—current
|
$
|
(5.6
|
)
|
Fair value of derivative liabilities—long-term
|
(6.8
|
)
|
|
Net fair value of derivatives
|
$
|
(12.4
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Change in fair value of derivatives
|
$
|
(0.1
|
)
|
|
$
|
10.1
|
|
|
$
|
4.7
|
|
Realized gain (loss) on derivatives
|
14.5
|
|
|
(4.9
|
)
|
|
(8.9
|
)
|
|||
Gain (loss) on derivative activity
|
$
|
14.4
|
|
|
$
|
5.2
|
|
|
$
|
(4.2
|
)
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
Fair value of derivative assets—current
|
$
|
12.9
|
|
|
$
|
28.6
|
|
Fair value of derivative assets—long-term
|
4.3
|
|
|
4.1
|
|
||
Fair value of derivative liabilities—current
|
(8.8
|
)
|
|
(21.8
|
)
|
||
Fair value of derivative liabilities—long-term
|
—
|
|
|
(2.4
|
)
|
||
Net fair value of derivatives
|
$
|
8.4
|
|
|
$
|
8.5
|
|
|
|
|
|
December 31, 2019
|
|||||||
Commodity
|
|
Instruments
|
|
Unit
|
|
Volume
|
|
|
Net Fair Value
|
||
NGL (short contracts)
|
|
Swaps
|
|
Gallons
|
|
(64.0
|
)
|
|
$
|
1.7
|
|
NGL (long contracts)
|
|
Swaps
|
|
Gallons
|
|
11.7
|
|
|
(0.5
|
)
|
|
Natural gas (short contracts)
|
|
Swaps
|
|
MMBtu
|
|
(4.7
|
)
|
|
1.0
|
|
|
Natural gas (long contracts)
|
|
Swaps
|
|
MMBtu
|
|
3.7
|
|
|
(0.4
|
)
|
|
Crude and condensate (short contracts)
|
|
Swaps
|
|
MMbbls
|
|
(12.8
|
)
|
|
(1.0
|
)
|
|
Crude and condensate (long contracts)
|
|
Swaps
|
|
MMbbls
|
|
2.0
|
|
|
7.6
|
|
|
Total fair value of derivatives
|
|
|
|
|
|
|
|
$
|
8.4
|
|
|
Level 2
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
Interest rate swaps (1)
|
$
|
(12.4
|
)
|
|
$
|
—
|
|
Commodity swaps (2)
|
$
|
8.4
|
|
|
$
|
8.5
|
|
(1)
|
The fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates.
|
(2)
|
The fair values of commodity swaps 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, 2019
|
|
December 31, 2018
|
||||||||||||
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
||||||||
Long-term debt (1)
|
$
|
4,764.3
|
|
|
$
|
4,444.2
|
|
|
$
|
4,319.6
|
|
|
$
|
3,953.6
|
|
Obligations under financing lease
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.5
|
|
|
$
|
2.2
|
|
Secured term loan receivable (2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
51.1
|
|
|
$
|
51.1
|
|
(1)
|
The carrying value of long-term debt as of December 31, 2018 includes current maturities. The carrying value of the long-term debt is reduced by debt issuance costs of $29.8 million and $24.3 million at December 31, 2019 and 2018, respectively. The respective fair values do not factor in debt issuance costs.
|
(2)
|
In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code and was not able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”
|
•
|
Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas;
|
•
|
North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas;
|
•
|
Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations 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 and our crude oil operations in ORV; 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, our derivative activity, and our general corporate assets and expenses.
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
94.3
|
|
|
$
|
129.3
|
|
|
$
|
236.4
|
|
|
$
|
416.6
|
|
|
$
|
—
|
|
|
$
|
876.6
|
|
NGL sales
|
0.9
|
|
|
30.9
|
|
|
19.6
|
|
|
1,725.6
|
|
|
—
|
|
|
1,777.0
|
|
||||||
Crude oil and condensate sales
|
1,975.0
|
|
|
—
|
|
|
109.6
|
|
|
291.9
|
|
|
—
|
|
|
2,376.5
|
|
||||||
Product sales
|
2,070.2
|
|
|
160.2
|
|
|
365.6
|
|
|
2,434.1
|
|
|
—
|
|
|
5,030.1
|
|
||||||
Natural gas sales—related parties
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.4
|
)
|
|
—
|
|
||||||
NGL sales—related parties
|
347.7
|
|
|
94.8
|
|
|
421.1
|
|
|
25.7
|
|
|
(889.3
|
)
|
|
—
|
|
||||||
Crude oil and condensate sales—related parties
|
13.5
|
|
|
5.5
|
|
|
—
|
|
|
1.7
|
|
|
(20.7
|
)
|
|
—
|
|
||||||
Product sales—related parties
|
361.6
|
|
|
100.3
|
|
|
421.1
|
|
|
27.4
|
|
|
(910.4
|
)
|
|
—
|
|
||||||
Gathering and transportation
|
48.8
|
|
|
196.4
|
|
|
234.5
|
|
|
58.3
|
|
|
—
|
|
|
538.0
|
|
||||||
Processing
|
30.5
|
|
|
143.0
|
|
|
138.2
|
|
|
3.2
|
|
|
—
|
|
|
314.9
|
|
||||||
NGL services
|
—
|
|
|
0.1
|
|
|
—
|
|
|
50.6
|
|
|
—
|
|
|
50.7
|
|
||||||
Crude services
|
19.2
|
|
|
—
|
|
|
19.8
|
|
|
51.9
|
|
|
—
|
|
|
90.9
|
|
||||||
Other services
|
12.0
|
|
|
1.1
|
|
|
0.1
|
|
|
0.7
|
|
|
—
|
|
|
13.9
|
|
||||||
Midstream services
|
110.5
|
|
|
340.6
|
|
|
392.6
|
|
|
164.7
|
|
|
—
|
|
|
1,008.4
|
|
||||||
NGL services—related parties
|
—
|
|
|
—
|
|
|
—
|
|
|
(3.4
|
)
|
|
3.4
|
|
|
—
|
|
||||||
Crude services—related parties
|
—
|
|
|
—
|
|
|
1.8
|
|
|
—
|
|
|
(1.8
|
)
|
|
—
|
|
||||||
Midstream services—related parties
|
—
|
|
|
—
|
|
|
1.8
|
|
|
(3.4
|
)
|
|
1.6
|
|
|
—
|
|
||||||
Revenue from contracts with customers
|
2,542.3
|
|
|
601.1
|
|
|
1,181.1
|
|
|
2,622.8
|
|
|
(908.8
|
)
|
|
6,038.5
|
|
||||||
Cost of sales
|
(2,283.9
|
)
|
|
(208.8
|
)
|
|
(627.0
|
)
|
|
(2,181.6
|
)
|
|
908.8
|
|
|
(4,392.5
|
)
|
||||||
Operating expenses
|
(112.9
|
)
|
|
(102.9
|
)
|
|
(104.0
|
)
|
|
(147.3
|
)
|
|
—
|
|
|
(467.1
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14.4
|
|
|
14.4
|
|
||||||
Segment profit
|
$
|
145.5
|
|
|
$
|
289.4
|
|
|
$
|
450.1
|
|
|
$
|
293.9
|
|
|
$
|
14.4
|
|
|
$
|
1,193.3
|
|
Depreciation and amortization
|
$
|
(119.8
|
)
|
|
$
|
(139.8
|
)
|
|
$
|
(194.9
|
)
|
|
$
|
(154.1
|
)
|
|
$
|
(8.4
|
)
|
|
$
|
(617.0
|
)
|
Impairments
|
$
|
(3.5
|
)
|
|
$
|
(2.1
|
)
|
|
$
|
(190.5
|
)
|
|
$
|
(2.1
|
)
|
|
$
|
—
|
|
|
$
|
(198.2
|
)
|
Capital expenditures
|
$
|
364.5
|
|
|
$
|
39.0
|
|
|
$
|
238.1
|
|
|
$
|
99.9
|
|
|
$
|
6.9
|
|
|
$
|
748.4
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
152.3
|
|
|
$
|
140.6
|
|
|
$
|
189.7
|
|
|
$
|
531.1
|
|
|
$
|
—
|
|
|
$
|
1,013.7
|
|
NGL sales
|
0.5
|
|
|
29.0
|
|
|
25.2
|
|
|
2,786.3
|
|
|
—
|
|
|
2,841.0
|
|
||||||
Crude oil and condensate sales
|
2,344.1
|
|
|
0.5
|
|
|
85.9
|
|
|
227.1
|
|
|
—
|
|
|
2,657.6
|
|
||||||
Product sales
|
2,496.9
|
|
|
170.1
|
|
|
300.8
|
|
|
3,544.5
|
|
|
—
|
|
|
6,512.3
|
|
||||||
Natural gas sales—related parties
|
(0.3
|
)
|
|
—
|
|
|
2.5
|
|
|
0.3
|
|
|
—
|
|
|
2.5
|
|
||||||
NGL sales—related parties
|
454.1
|
|
|
49.4
|
|
|
590.8
|
|
|
47.4
|
|
|
(1,104.3
|
)
|
|
37.4
|
|
||||||
Crude oil and condensate sales—related parties
|
—
|
|
|
1.8
|
|
|
0.3
|
|
|
0.2
|
|
|
(1.2
|
)
|
|
1.1
|
|
||||||
Product sales—related parties
|
453.8
|
|
|
51.2
|
|
|
593.6
|
|
|
47.9
|
|
|
(1,105.5
|
)
|
|
41.0
|
|
||||||
Gathering and transportation
|
28.0
|
|
|
146.3
|
|
|
143.2
|
|
|
68.8
|
|
|
—
|
|
|
386.3
|
|
||||||
Processing
|
23.8
|
|
|
83.9
|
|
|
128.7
|
|
|
3.3
|
|
|
—
|
|
|
239.7
|
|
||||||
NGL services
|
—
|
|
|
—
|
|
|
—
|
|
|
59.6
|
|
|
—
|
|
|
59.6
|
|
||||||
Crude services
|
4.2
|
|
|
—
|
|
|
2.8
|
|
|
60.1
|
|
|
—
|
|
|
67.1
|
|
||||||
Other services
|
8.7
|
|
|
0.9
|
|
|
0.1
|
|
|
0.9
|
|
|
—
|
|
|
10.6
|
|
||||||
Midstream services
|
64.7
|
|
|
231.1
|
|
|
274.8
|
|
|
192.7
|
|
|
—
|
|
|
763.3
|
|
||||||
Gathering and transportation—related parties
|
—
|
|
|
122.7
|
|
|
80.6
|
|
|
—
|
|
|
—
|
|
|
203.3
|
|
||||||
Processing—related parties
|
—
|
|
|
108.5
|
|
|
48.5
|
|
|
—
|
|
|
—
|
|
|
157.0
|
|
||||||
NGL services—related parties
|
—
|
|
|
—
|
|
|
—
|
|
|
3.3
|
|
|
(3.3
|
)
|
|
—
|
|
||||||
Crude services—related parties
|
14.9
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
—
|
|
|
16.4
|
|
||||||
Other services—related parties
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
||||||
Midstream services—related parties
|
14.9
|
|
|
231.7
|
|
|
130.6
|
|
|
3.3
|
|
|
(3.3
|
)
|
|
377.2
|
|
||||||
Revenue from contracts with customers
|
3,030.3
|
|
|
684.1
|
|
|
1,299.8
|
|
|
3,788.4
|
|
|
(1,108.8
|
)
|
|
7,693.8
|
|
||||||
Cost of sales
|
(2,808.3
|
)
|
|
(199.2
|
)
|
|
(743.6
|
)
|
|
(3,365.7
|
)
|
|
1,108.8
|
|
|
(6,008.0
|
)
|
||||||
Operating expenses
|
(96.1
|
)
|
|
(112.7
|
)
|
|
(90.3
|
)
|
|
(154.3
|
)
|
|
—
|
|
|
(453.4
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.2
|
|
|
5.2
|
|
||||||
Segment profit
|
$
|
125.9
|
|
|
$
|
372.2
|
|
|
$
|
465.9
|
|
|
$
|
268.4
|
|
|
$
|
5.2
|
|
|
$
|
1,237.6
|
|
Depreciation and amortization
|
$
|
(111.0
|
)
|
|
$
|
(127.9
|
)
|
|
$
|
(178.8
|
)
|
|
$
|
(150.9
|
)
|
|
$
|
(8.7
|
)
|
|
$
|
(577.3
|
)
|
Impairments
|
$
|
(138.5
|
)
|
|
$
|
(202.7
|
)
|
|
$
|
—
|
|
|
$
|
(24.6
|
)
|
|
$
|
—
|
|
|
$
|
(365.8
|
)
|
Goodwill
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
Capital expenditures
|
$
|
271.7
|
|
|
$
|
24.7
|
|
|
$
|
493.8
|
|
|
$
|
54.4
|
|
|
$
|
5.3
|
|
|
$
|
849.9
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Product sales
|
$
|
1,344.0
|
|
|
$
|
162.5
|
|
|
$
|
128.8
|
|
|
$
|
2,723.1
|
|
|
$
|
—
|
|
|
$
|
4,358.4
|
|
Product sales—related parties
|
357.0
|
|
|
120.5
|
|
|
349.4
|
|
|
39.8
|
|
|
(721.8
|
)
|
|
144.9
|
|
||||||
Midstream services
|
77.5
|
|
|
51.6
|
|
|
155.0
|
|
|
268.2
|
|
|
—
|
|
|
552.3
|
|
||||||
Midstream services—related parties
|
18.7
|
|
|
410.4
|
|
|
241.6
|
|
|
151.1
|
|
|
(133.6
|
)
|
|
688.2
|
|
||||||
Cost of sales
|
(1,628.5
|
)
|
|
(264.5
|
)
|
|
(523.0
|
)
|
|
(2,800.9
|
)
|
|
855.4
|
|
|
(4,361.5
|
)
|
||||||
Operating expenses
|
(85.1
|
)
|
|
(121.8
|
)
|
|
(64.6
|
)
|
|
(147.2
|
)
|
|
—
|
|
|
(418.7
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4.2
|
)
|
|
(4.2
|
)
|
||||||
Segment profit (loss)
|
$
|
83.6
|
|
|
$
|
358.7
|
|
|
$
|
287.2
|
|
|
$
|
234.1
|
|
|
$
|
(4.2
|
)
|
|
$
|
959.4
|
|
Depreciation and amortization
|
$
|
(109.9
|
)
|
|
$
|
(127.0
|
)
|
|
$
|
(156.3
|
)
|
|
$
|
(141.7
|
)
|
|
$
|
(10.4
|
)
|
|
$
|
(545.3
|
)
|
Impairments
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(17.1
|
)
|
|
$
|
—
|
|
|
$
|
(17.1
|
)
|
Goodwill
|
$
|
29.3
|
|
|
$
|
202.7
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
186.1
|
|
|
$
|
18.2
|
|
|
$
|
450.1
|
|
|
$
|
87.3
|
|
|
$
|
26.4
|
|
|
$
|
768.1
|
|
|
Year Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Segment profit
|
$
|
1,193.3
|
|
|
$
|
1,237.6
|
|
|
$
|
959.4
|
|
General and administrative expenses
|
(139.2
|
)
|
|
(130.2
|
)
|
|
(123.5
|
)
|
|||
Gain (loss) on disposition of assets
|
1.9
|
|
|
(0.4
|
)
|
|
—
|
|
|||
Depreciation and amortization
|
(617.0
|
)
|
|
(577.3
|
)
|
|
(545.3
|
)
|
|||
Impairments
|
(198.2
|
)
|
|
(365.8
|
)
|
|
(17.1
|
)
|
|||
Loss on secured term loan receivable
|
(52.9
|
)
|
|
—
|
|
|
—
|
|
|||
Gain on litigation settlement
|
—
|
|
|
—
|
|
|
26.0
|
|
|||
Operating income
|
$
|
187.9
|
|
|
$
|
163.9
|
|
|
$
|
299.5
|
|
Segment Identifiable Assets:
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
Permian
|
|
$
|
2,281.1
|
|
|
$
|
2,096.8
|
|
North Texas
|
|
1,135.8
|
|
|
1,308.2
|
|
||
Oklahoma
|
|
3,035.0
|
|
|
3,209.5
|
|
||
Louisiana
|
|
2,562.0
|
|
|
2,734.5
|
|
||
Corporate
|
|
120.7
|
|
|
222.3
|
|
||
Total identifiable assets
|
|
$
|
9,134.6
|
|
|
$
|
9,571.3
|
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
|
Total
|
||||||||||
2019
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
1,779.2
|
|
|
$
|
1,710.0
|
|
|
$
|
1,408.0
|
|
|
$
|
1,155.7
|
|
|
$
|
6,052.9
|
|
Impairments
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
198.2
|
|
|
$
|
198.2
|
|
Operating income (loss)
|
$
|
110.6
|
|
|
$
|
53.4
|
|
|
$
|
96.7
|
|
|
$
|
(72.8
|
)
|
|
$
|
187.9
|
|
Net income (loss) attributable to ENLK
|
$
|
62.8
|
|
|
$
|
4.1
|
|
|
$
|
42.4
|
|
|
$
|
(163.6
|
)
|
|
$
|
(54.3
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
$
|
64.3
|
|
|
$
|
111.5
|
|
|
$
|
48.8
|
|
|
$
|
(225.1
|
)
|
|
$
|
(0.5
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
$
|
16.7
|
|
|
$
|
30.4
|
|
|
$
|
27.8
|
|
|
$
|
78.8
|
|
|
$
|
153.7
|
|
|
|
Year Ended December 31,
|
||||||||||
Supplemental disclosures of cash flow information:
|
|
2019
|
|
2018
|
|
2017
|
||||||
Cash paid for interest (1)
|
|
$
|
218.5
|
|
|
$
|
182.6
|
|
|
$
|
163.8
|
|
Cash paid for income taxes
|
|
$
|
3.9
|
|
|
$
|
1.5
|
|
|
$
|
4.8
|
|
|
|
|
|
|
|
|
||||||
Non-cash investing activities:
|
|
|
|
|
|
|
||||||
Non-cash accrual of property and equipment
|
|
$
|
(6.5
|
)
|
|
$
|
6.8
|
|
|
$
|
(22.7
|
)
|
Discounted secured term loan receivable from contract restructuring
|
|
$
|
—
|
|
|
$
|
47.7
|
|
|
$
|
—
|
|
(1)
|
Includes cash paid to ENLC for interest of $62.6 million for the year ended December 31, 2019.
|
Other current assets:
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
Natural gas and NGLs inventory
|
|
$
|
43.4
|
|
|
$
|
41.3
|
|
Secured term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1)
|
|
—
|
|
|
19.4
|
|
||
Prepaid expenses and other
|
|
13.5
|
|
|
12.1
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
|
$
|
56.9
|
|
|
$
|
72.8
|
|
(1)
|
In late May 2019, White Star, the counterparty to our $58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code and was not able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.”
|
Other current liabilities:
|
|
December 31, 2019
|
|
December 31, 2018
|
||||
Accrued interest
|
|
$
|
32.6
|
|
|
$
|
37.3
|
|
Accrued wages and benefits, including taxes
|
|
25.5
|
|
|
37.2
|
|
||
Accrued ad valorem taxes
|
|
28.5
|
|
|
28.1
|
|
||
Capital expenditure accruals
|
|
42.4
|
|
|
50.6
|
|
||
Onerous performance obligations
|
|
—
|
|
|
9.0
|
|
||
Short-term lease liability
|
|
21.1
|
|
|
1.5
|
|
||
Suspense producer payments
|
|
13.8
|
|
|
34.6
|
|
||
Operating expense accruals
|
|
10.8
|
|
|
10.2
|
|
||
Other
|
|
27.0
|
|
|
38.2
|
|
||
Other current liabilities
|
|
$
|
201.7
|
|
|
$
|
246.7
|
|
Name
|
|
Age
|
|
Position with EnLink Midstream GP, LLC
|
Barry E. Davis
|
|
58
|
|
Chairman and Chief Executive Officer
|
Eric D. Batchelder
|
|
48
|
|
Executive Vice President, Chief Financial Officer, and Director
|
Benjamin D. Lamb
|
|
40
|
|
Executive Vice President and Chief Operating Officer
|
Alaina K. Brooks
|
|
45
|
|
Executive Vice President, Chief Legal and Administrative Officer, Secretary, and Director
|
•
|
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 plan 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 2020 |
|
Percent Increase (Decrease)
|
|||||
Barry E. Davis (1)
|
$
|
735,000
|
|
|
$
|
748,000
|
|
|
1.8
|
%
|
Benjamin D. Lamb
|
$
|
491,625
|
|
|
$
|
501,000
|
|
|
1.9
|
%
|
Eric D. Batchelder
|
$
|
450,225
|
|
|
$
|
458,000
|
|
|
1.7
|
%
|
Alaina K. Brooks
|
$
|
439,875
|
|
|
$
|
450,000
|
|
|
2.3
|
%
|
Michael J. Garberding (2)
|
$
|
675,000
|
|
|
$
|
—
|
|
|
(100.0
|
)%
|
(1)
|
In August 2019, Mr. Davis, formerly our Executive Chairman, was named Chairman and Chief Executive Officer.
|
(2)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company.
|
Component
|
|
Description
|
|
Weighting
|
Financial
|
|
Adjusted EBITDA and distributable cash flow (“DCF”) per unit to maximize financial performance
|
|
50% Adjusted EBITDA
10% DCF per unit |
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)
|
|
2019 Bonus (as a % of Base Salary)
|
|
2019 Bonus Amount ($)
|
|||
Barry E. Davis (1)
|
|
125
|
%
|
|
87
|
%
|
|
636,568
|
|
Benjamin D. Lamb
|
|
100
|
%
|
|
106
|
%
|
|
521,207
|
|
Eric D. Batchelder
|
|
90
|
%
|
|
95
|
%
|
|
429,585
|
|
Alaina K. Brooks
|
|
90
|
%
|
|
101
|
%
|
|
444,709
|
|
Michael J. Garberding (2)
|
|
100
|
%
|
|
83
|
%
|
|
560,463
|
|
(1)
|
In August 2019, Mr. Davis, formerly our Executive Chairman, was named Chairman and Chief Executive Officer. In association with this transition, the target bonus percentage for Mr. Davis increased from 90% to 125%.
|
(2)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company.
|
Name and Principal Position
|
|
Year
|
|
Salary
($) |
|
Bonus
($)(1) |
|
Restricted Incentive Unit and Performance Unit Awards
($)(2) |
|
All Other Compensation
($) |
|
Total
($) |
||
Barry E. Davis (3)
|
|
2019
|
|
556,000
|
|
636,568
|
|
|
4,553,287
|
(6)
|
744,456
|
(7)
|
6,490,311
|
|
Chairman and Chief Executive Officer
|
|
2018
|
|
529,000
|
|
784,367
|
|
|
3,835,864
|
|
784,034
|
|
5,933,265
|
|
|
|
2017
|
|
695,000
|
|
960,000
|
|
|
4,533,371
|
|
565,075
|
|
6,753,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Benjamin D. Lamb
|
|
2019
|
|
491,200
|
|
521,207
|
|
|
1,264,284
|
|
362,424
|
(8)
|
2,639,115
|
|
Executive Vice President and Chief Operating Officer
|
|
2018
|
|
447,500
|
|
665,733
|
|
|
4,272,801
|
|
703,111
|
|
6,089,145
|
|
|
2017
|
|
345,000
|
|
345,000
|
|
|
1,431,552
|
|
274,563
|
|
2,396,115
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Eric D. Batchelder
|
|
2019
|
|
449,900
|
|
429,585
|
|
|
948,218
|
|
205,157
|
(9)
|
2,032,860
|
|
Executive Vice President and Chief Financial Officer
|
|
2018
|
|
399,200
|
|
560,771
|
|
|
3,133,675
|
|
304,836
|
|
4,398,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Alaina K. Brooks (4)
|
|
2019
|
|
439,500
|
|
444,709
|
|
|
902,261
|
|
302,253
|
(10)
|
2,088,723
|
|
Executive Vice President, Chief Legal and Administrative Officer, and Secretary
|
|
2018
|
|
393,300
|
|
468,087
|
|
|
2,410,163
|
|
204,661
|
|
3,476,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Michael J. Garberding (5)
|
|
2019
|
|
528,200
|
|
560,463
|
|
|
2,844,635
|
|
5,486,256
|
(11)
|
9,419,554
|
|
President and Chief Executive Officer
|
|
2018
|
|
646,600
|
|
1,009,247
|
|
|
7,975,169
|
|
727,195
|
|
10,358,211
|
|
|
2017
|
|
500,000
|
|
500,000
|
|
|
2,147,374
|
|
396,190
|
|
3,543,564
|
|
(1)
|
Bonuses include all annual bonus payments. For 2019, the named executive officers received bonuses in the form of 35% cash and 65% equity awards that immediately vest. 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. 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. Equity awards for 2019, 2018, and 2017 represent the grant date fair value of awards computed in accordance with ASC 718.
|
(2)
|
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” for the assumptions made in our valuation of such awards.
|
(3)
|
In August 2019, Mr. Davis, formerly our Executive Chairman, was named Chairman and Chief Executive Officer.
|
(4)
|
Ms. Brooks became a named executive officer in fiscal year 2018, and, therefore, summary compensation information is presented only for fiscal years 2018 and 2019.
|
(5)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company.
|
(6)
|
In connection with assuming his role as Chairman and Chief Executive Office in August 2019, Mr. Davis received a one-time transition grant of restricted incentive units and performance unit awards of $1,000,000 and $1,972,936, respectively.
|
(7)
|
Amount of all other compensation for Mr. Davis includes a matching 401(k) contribution of $16,800, DERs with respect to restricted incentive units of ENLK in the amount of $325,786, and DERs with respect to restricted incentive units of ENLC in the amount of $401,870.
|
(8)
|
Amount of all other compensation for Mr. Lamb includes a matching 401(k) contribution of $16,800, DERs with respect to restricted incentive units of ENLK in the amount of $55,107, and DERs with respect to restricted incentive units of ENLC in the amount of $290,517.
|
(9)
|
Amount of all other compensation for Mr. Batchelder includes a matching 401(k) contribution of $16,800, DERs with respect to restricted incentive units of ENLK in the amount of $30,526, and DERs with respect to restricted incentive units of ENLC in the amount of $157,831.
|
(10)
|
Amount of all other compensation for Ms. Brooks includes a matching 401(k) contribution of $16,800, DERs with respect to restricted incentive units of ENLK in the amount of $97,839, and DERs with respect to restricted incentive units of ENLC in the amount of $187,614.
|
(11)
|
Amount of all other compensation for Mr. Garberding includes a matching 401(k) contribution of $16,800, DERs with respect to restricted incentive units of ENLK in the amount of $250,046, and DERs with respect to restricted incentive units of ENLC in the amount of $935,623. Mr. Garberding received $4,283,788 in connection with his departure.
|
|
|
|
|
Estimated Future Payouts Under Equity Incentive Plan Awards
|
|
|
|
|
|||||||||
Name
|
|
Grant Date
|
|
Threshold (#)
|
|
Target (#)
|
|
Maximum (#)
|
|
All Other Unit Awards: Number of Units
|
|
Grant Date Fair Value of Unit Awards ($)(1)
|
|||||
Barry E. Davis
|
|
3/12/2019
|
|
60,328
|
|
|
120,656
|
|
|
241,312
|
|
|
—
|
|
(2)
|
1,580,351
|
|
|
|
10/9/2019
|
|
—
|
|
|
—
|
|
|
—
|
|
|
135,318
|
|
(3)
|
1,000,000
|
|
|
|
10/9/2019
|
|
135,318
|
|
270,636
|
|
|
541,272
|
|
|
—
|
|
(4)
|
1,972,936
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Benjamin D. Lamb
|
|
3/12/2019
|
|
48,263
|
|
|
96,525
|
|
|
193,050
|
|
|
—
|
|
(2)
|
1,264,284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Eric D. Batchelder
|
|
3/12/2019
|
|
36,197
|
|
|
72,394
|
|
|
144,788
|
|
|
—
|
|
(2)
|
948,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Alaina K. Brooks
|
|
3/12/2019
|
|
28,958
|
|
|
57,915
|
|
|
115,830
|
|
|
—
|
|
(2)
|
758,571
|
|
|
|
6/19/2019
|
|
7,240
|
|
|
14,479
|
|
|
28,958
|
|
|
—
|
|
(2)
|
143,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Michael J. Garberding (5)
|
|
3/12/2019
|
|
108,591
|
|
|
217,181
|
|
|
434,362
|
|
|
—
|
|
(2)
|
2,844,635
|
|
(1)
|
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 Data—Note 10” for the assumptions made in our valuation of such awards.
|
(2)
|
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, 2022, recipients receive DERs, if any, with respect to the number of performance awards vested.
|
(3)
|
In connection with assuming his role as Chairman and Chief Executive Office in August 2019, Mr. Davis received a one-time transition grant of restricted incentive units. These awards include DERs that provide for distributions on restricted incentive units if made on unrestricted common units during the restriction period unless otherwise forfeited and vest 100% on August 1, 2022.
|
(4)
|
In connection with assuming his role as Chairman and Chief Executive Office in August 2019, Mr. Davis received a one-time transition grant of performance unit awards. These awards 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 August 1, 2022, recipients receive DERs, if any, with respect to the number of performance awards vested.
|
(5)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company.
|
|
|
|
|
Unit Awards
|
||||||||||
Name
|
|
Vesting Year (1)
|
|
Number of Units That Have Not Vested
(#) |
|
Market Value of Shares or Units That Have Not Vested
($)(2) |
|
Equity Incentive Plan Awards: Number of Unearned Units or Other Rights that Have Not Vested (#)(3)(4)(5)
|
|
Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)(2)
|
||||
Barry E. Davis
|
|
2022
|
|
135,318
|
|
|
829,499
|
|
|
391,292
|
|
(6)
|
2,398,620
|
|
|
|
2021
|
|
98,730
|
|
|
605,215
|
|
|
98,730
|
|
|
605,215
|
|
|
|
2020
|
|
106,667
|
|
|
653,869
|
|
|
106,667
|
|
|
653,869
|
|
Benjamin D. Lamb
|
|
2022
|
|
—
|
|
|
—
|
|
|
96,525
|
|
|
591,698
|
|
|
|
2021
|
|
139,925
|
|
|
857,740
|
|
|
—
|
|
|
—
|
|
|
|
2020
|
|
159,364
|
|
|
976,901
|
|
|
—
|
|
|
—
|
|
Eric D. Batchelder
|
|
2022
|
|
—
|
|
|
—
|
|
|
72,394
|
|
|
443,775
|
|
|
|
2021
|
|
115,245
|
|
|
706,452
|
|
|
—
|
|
|
—
|
|
|
|
2020
|
|
47,777
|
|
|
292,873
|
|
|
—
|
|
|
—
|
|
Alaina K. Brooks
|
|
2022
|
|
—
|
|
|
—
|
|
|
72,394
|
|
|
443,775
|
|
|
|
2021
|
|
73,780
|
|
|
452,271
|
|
|
26,000
|
|
|
159,380
|
|
|
|
2020
|
|
67,427
|
|
|
413,328
|
|
|
19,649
|
|
|
120,448
|
|
Michael J. Garberding (7)
|
|
2022
|
|
—
|
|
|
—
|
|
|
48,152
|
|
|
295,172
|
|
(1)
|
Restricted incentive units vesting in 2020 and 2021 vest on January 1st and August 1st of the relevant year, as applicable. Restricted incentive units vesting in 2022 vest on January 1st. For Mr. Davis, restricted incentive units vesting in 2022 vest on January 1st and August 1st, as applicable.
|
(2)
|
The closing price for the ENLC common units was $6.13 as of December 31, 2019.
|
(3)
|
Reflects the target number of performance units granted to the named executive officers multiplied by a performance percentage of 100%.
|
(4)
|
Vesting of awards in 2021 and 2022 are contingent upon (i) the EnLink TSR performance measured against a peer group of companies in respect of periods preceding the effective time of the Merger and (ii) the TSR performance of ENLC measured against a peer group of companies in respect of periods after the effective time of the Merger.
|
(5)
|
Vesting of awards in 2022 are contingent upon (i) the EnLink TSR performance measured against a peer group of companies and (ii) EnLink’s achieved distributable cash flow per unit outstanding.
|
(6)
|
Vesting of awards in August 2020 for Mr. Davis are contingent upon the EnLink TSR performance measured against a peer group of companies.
|
(7)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company. Pursuant to his departure, Mr. Garberding’s outstanding restricted incentive units vested and a portion of his outstanding performance units vested at 100% in 2019. The remaining outstanding performance units not vested in 2019 will vest on the original vesting date of January 1, 2022.
|
Name
|
|
Date Vested (1)
|
|
Number of Units Acquired on Vesting
|
|
Value Per Unit Realized on Vesting ($)
|
|
Total ($)
|
||||
Barry E. Davis
|
|
1/1/2019
|
|
128,145
|
|
|
11.01
|
|
|
1,410,876
|
|
|
|
|
2/14/2019
|
|
61,277
|
|
|
12.49
|
|
|
765,293
|
|
|
|
|
|
|
|
|
|
|
|
||||
Benjamin D. Lamb
|
|
1/1/2019
|
|
53,588
|
|
|
11.01
|
|
|
590,004
|
|
|
|
|
|
|
|
|
|
|
|
||||
Eric D. Batchelder
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Alaina K. Brooks
|
|
1/1/2019
|
|
13,429
|
|
|
11.01
|
|
|
147,853
|
|
|
|
|
2/14/2019
|
|
14,127
|
|
|
12.49
|
|
|
176,442
|
|
|
|
|
|
|
|
|
|
|
|
||||
Michael J. Garberding (2)
|
|
1/1/2019
|
|
82,712
|
|
|
11.01
|
|
|
910,659
|
|
|
|
|
2/14/2019
|
|
35,540
|
|
|
12.49
|
|
|
443,870
|
|
(1)
|
Units listed as vesting after the closing of the Merger vested as ENLC units with the amount adjusted to be 1.15 ENLC units for each unit listed.
|
(2)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company. Pursuant to his departure, Mr. Garberding’s outstanding restricted incentive units vested and a portion of his outstanding performance units vested at 100% in 2019. The remaining outstanding performance units not vested in 2019 will vest on the original vesting date of January 1, 2022.
|
Name
|
|
Date Vested
|
|
Number of Units Acquired on Vesting
|
|
Value Per Unit Realized on Vesting ($)
|
|
Total ($)
|
|
Barry E. Davis
|
|
1/1/2019
|
|
110,709
|
|
9.49
|
|
|
1,050,628
|
|
|
2/14/2019
|
|
52,938
|
|
10.86
|
|
|
574,907
|
|
|
3/6/2019
|
|
34,645
|
|
11.32
|
|
|
392,181
|
|
|
|
|
|
|
|
|
|
|
Benjamin D. Lamb
|
|
1/1/2019
|
|
46,296
|
|
9.49
|
|
|
439,349
|
|
|
3/6/2019
|
|
29,405
|
|
11.32
|
|
|
332,865
|
|
|
|
|
|
|
|
|
|
|
Eric D. Batchelder
|
|
3/6/2019
|
|
24,769
|
|
11.32
|
|
|
280,385
|
|
|
|
|
|
|
|
|
|
|
Alaina K. Brooks
|
|
1/1/2019
|
|
14,286
|
|
9.49
|
|
|
135,574
|
|
|
2/14/2019
|
|
15,028
|
|
10.86
|
|
|
163,204
|
|
|
3/6/2019
|
|
20,675
|
|
11.32
|
|
|
234,041
|
|
|
|
|
|
|
|
|
|
|
Michael J. Garberding (1)
|
|
1/1/2019
|
|
71,457
|
|
9.49
|
|
|
678,127
|
|
|
2/14/2019
|
|
30,704
|
|
10.86
|
|
|
333,445
|
|
|
3/6/2019
|
|
44,578
|
|
11.32
|
|
|
504,623
|
|
|
9/2/2019
|
|
534,779
|
|
7.94
|
|
|
4,246,145
|
(1)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company. Pursuant to his departure, Mr. Garberding’s outstanding restricted incentive units vested and a portion of his outstanding performance units vested at 100% in 2019. The remaining outstanding performance units not vested in 2019 will vest on the original vesting date of January 1, 2022.
|
Named Executive Officer
|
|
Payment Under Severance Agreements Upon Termination Other Than For Cause or With Good Reason
($)(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) |
|||||
Barry E. Davis
|
|
3,994,068
|
|
|
34,150
|
|
|
—
|
|
|
5,647,818
|
|
|
5,746,287
|
|
Benjamin D. Lamb
|
|
2,417,707
|
|
|
33,612
|
|
|
—
|
|
|
2,417,707
|
|
|
2,426,340
|
|
Eric D. Batchelder
|
|
2,190,440
|
|
|
24,067
|
|
|
—
|
|
|
2,190,440
|
|
|
1,443,100
|
|
Alaina K. Brooks
|
|
2,166,234
|
|
|
31,288
|
|
|
—
|
|
|
2,166,234
|
|
|
1,589,203
|
|
Michael J. Garberding (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 Chairman and Chief Executive Officer), 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 2019.
|
(6)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company. Pursuant to his departure, Mr. Garberding received a cash payment of $4,283,788 related to his Severance Benefit, $560,463, which is a prorated amount related to his 2019 bonus at the time the bonus is payable at the end of March 2020, and accelerated vesting of outstanding equity awards valued at $4,246,145 as of the vesting date.
|
Name
|
|
Fees Earned or Paid in Cash
($)
|
|
Unit Awards ($)
|
|
All Other Compensation ($)(1)
|
|
Total
($)
|
|
Leldon E. Echols (2)
|
|
15,413
|
|
—
|
|
|
1,459
|
|
16,872
|
Kyle D. Vann (2)
|
|
36,250
|
|
—
|
|
|
2,918
|
|
39,168
|
Scott A. Griffiths (2)
|
|
37,708
|
|
—
|
|
|
2,918
|
|
40,626
|
(1)
|
Other Compensation is comprised of DERs with respect to restricted incentive units.
|
(2)
|
In connection with the closing of the Merger, each of Messrs. Echols, Griffiths, and Vann departed from their positions as directors.
|
•
|
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 our general partner;
|
•
|
each named executive officer of our general partner; and
|
•
|
all the directors and executive officers of our general partner 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)
|
|
144,358,720
|
|
|
100.00
|
%
|
Barry E. Davis
|
|
—
|
|
|
—
|
%
|
Eric D. Batchelder
|
|
—
|
|
|
—
|
%
|
Benjamin D. Lamb
|
|
—
|
|
|
—
|
%
|
Alaina K. Brooks
|
|
—
|
|
|
—
|
%
|
Michael J. Garberding (5)
|
|
—
|
|
|
—
|
%
|
All directors and executive officers as a group (4 persons)
|
|
—
|
|
|
—
|
%
|
(1)
|
Unless otherwise indicated, the beneficial owner has sole voting and dispositive power over all units listed. Unless otherwise indicated, the address of each beneficial owner 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)
|
ENLC is the record holder of 144,358,720 common units of ENLK. The managing member of ENLC may be deemed to share beneficial ownership of these ENLK common units. GIP III Stetson I, L.P. (“Stetson I”) is the sole member of the managing member of ENLC and may be deemed to share beneficial ownership of the ENLK common units beneficially owned by the managing member of ENLC. Based solely on the Amendment No. 2 to the Schedule 13D with the Commission on February 5, 2019 by Global Infrastructure Investors III, LLC (“Global Investors”), 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 Stetson I. As a result, Global Investors, Global GP, Aggregator I, Aggregator II, and Stetson GP may be deemed to share beneficial ownership of the ENLK common units beneficially owned by Stetson I. Adebayo Ogunlesi, Jonathan Bram, William Brilliant, Matthew Harris, Michael McGhee, Rajaram Rao, William Woodburn, Salim Samaha and Robert O’Brien, as the voting members of the Investment Committee of Global Investors, may be deemed to share beneficial ownership of the ENLK common units beneficially owned by Global Investors. Such individuals expressly disclaim any such beneficial ownership. The address of each of Stetson I, Global Investors, Global GP, Aggregator I, Aggregator II, Stetson GP, and Messrs. Ogunlesi, Bram, Brilliant, Harris, McGhee, Rao, Woodburn, Samaha, and O’Brien is c/o Global Infrastructure Management, LLC, 1345 Avenue of the Americas, 30th Floor, New York, New York 10105.
|
(4)
|
As the indirect owner of 40.3% of the outstanding membership interests in ENLC, and 100% of the outstanding membership interests in ENLC’s managing member, GIP may be deemed to beneficially own all common units of ENLK.
|
(5)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company. The units listed reflect Mr. Garberding’s ownership of ENLK common units at the time of his departure.
|
•
|
all the directors of our general partner;
|
•
|
each named executive officer of our general partner; and
|
•
|
all the directors and executive officers of our general partner 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)
|
|
2,922,797
|
|
|
*
|
|
—
|
|
|
—
|
|
|
2,922,797
|
|
|
*
|
Eric D. Batchelder
|
|
40,024
|
|
|
*
|
|
—
|
|
|
—
|
|
|
40,024
|
|
|
*
|
Benjamin D. Lamb
|
|
298,917
|
|
|
*
|
|
—
|
|
|
—
|
|
|
298,917
|
|
|
*
|
Alaina K. Brooks
|
|
71,741
|
|
|
*
|
|
—
|
|
|
—
|
|
|
71,741
|
|
|
*
|
Michael J. Garberding (6)
|
|
867,322
|
|
|
*
|
|
—
|
|
|
—
|
|
|
867,322
|
|
|
*
|
All directors and executive officers as group (4 persons)
|
|
3,333,479
|
|
|
*
|
|
—
|
|
|
—
|
|
|
3,333,479
|
|
|
*
|
(1)
|
The beneficial owner has sole voting and dispositive power over all units listed. The address of each beneficial owner 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 488,445,794 common units.
|
(4)
|
The percentages reflected in the column below are based on a total of 557,156,625 common units, which includes the units described in (3) above, and 68,710,831 common units, which reflects the as-exchanged amount of the 59,748,549 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 canceled.
|
(5)
|
Of these ENLC common units, 1,101,424 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)
|
In August 2019, Mr. Garberding departed from his position as President and Chief Executive Officer. In September 2019, Mr. Garberding left the Company. The units listed reflect Mr. Garberding’s ownership of ENLC common units at the time of his departure.
|
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)
|
|
5,381,461
|
(2)
|
N/A
|
|
14,865,181
|
(3)
|
Equity Compensation Plans Not Approved by Security Holders
|
|
N/A
|
|
N/A
|
|
N/A
|
|
(1)
|
These plans include both the 2014 Plan, which was approved by ENLC’s unitholders in March 2014 for the benefit of ENLC’s officers, employees, and directors, and the GP Plan, which was approved by our unitholders effective April 6, 2016 for the benefit of our officers, employees, and directors. As of the closing of the Merger, ENLC assumed all obligations in respect of the GP Plan. See “Item 11—Executive Compensation—Compensation Discussion and Analysis” for additional information regarding the 2014 Plan and the GP Plan.
|
(2)
|
The number of securities includes 2,574,619 restricted units that have been granted under the 2014 Plan that have not vested and 1,488,986 restricted units that have been granted under the GP Plan that have not vested. In addition, the number of securities includes 1,126,581 performance unit awards that have been granted under the 2014 Plan, assuming the target distribution at the time of vesting, and 191,275 performance unit awards that have been granted under the GP 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. See “Item 11—Executive Compensation—Compensation Discussion and Analysis” for additional information regarding the 2014 Plan and the GP Plan.
|
(3)
|
Effective as of the closing of the Merger, the 2014 Plan, as amended, provided for the issuance of a total of 21,116,046 common units under the 2014 Plan, inclusive of the Rollover Units that remained eligible for future grants under the GP Plan immediately prior to the effective time of the Merger. No additional grants of equity awards will be made under the GP Plan for periods after the Merger. Of the 21,116,046 common units that may be awarded under the 2014 Plan, 14,865,181 common units remained eligible for future grants as of December 31, 2019.
|
(a)
|
Financial Statements and Schedules
|
1.
|
See “Item 8. Financial Statements and Supplementary Data.”
|
2.
|
Exhibits
|
Number
|
|
|
Description
|
2.1
|
**
|
—
|
|
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
|
|
—
|
|
4.8
|
|
—
|
|
4.9
|
|
—
|
|
4.10
|
*
|
—
|
|
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
|
†
|
—
|
|
10.23
|
|
—
|
|
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, 2019, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018, (ii) Consolidated Statements of Operations for the years ended December 31, 2019, 2018, and 2017, (iii) Consolidated Statements of Changes in Members’ Equity for the years ended December 31, 2019, 2018, and 2017, (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018, and 2017, and (v) the notes to Consolidated Financial Statements.
|
104
|
*
|
—
|
Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).
|
*
|
Filed herewith.
|
**
|
In accordance with the instruction on Item 601(b)(2) of Regulation S-K, the exhibits and schedules to Exhibits 2.1, 2.2, and 2.3 are not filed herewith. The agreements identify such exhibits and schedules, including the general nature of their content. We undertake to provide such exhibits and schedules to the Commission upon request.
|
†
|
As required by Item 15(a)(3), this Exhibit is identified as a compensatory benefit plan or arrangement.
|
|
|
|
|
EnLink Midstream Partners, LP
|
|
|
By:
|
EnLink Midstream GP, LLC, its general partner
|
February 26, 2020
|
By:
|
/s/ BARRY E. DAVIS
|
|
|
Barry E. Davis
|
|
|
Chairman and Chief Executive Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ BARRY E. DAVIS
|
|
Chairman, Chief Executive Officer, and Director
(Principal Executive Officer)
|
|
February 26, 2020
|
Barry E. Davis
|
|
|
||
|
|
|
|
|
/s/ ALAINA K. BROOKS
|
|
Executive Vice President, Chief Legal and Administrative Officer, Secretary, and Director
|
|
February 26, 2020
|
Alaina K. Brooks
|
|
|
||
|
|
|
|
|
/s/ ERIC D. BATCHELDER
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer) |
|
February 26, 2020
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Eric D. Batchelder
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|
1 Year EnLink Midstream Partners, LP Chart |
1 Month EnLink Midstream Partners, LP Chart |
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