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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., 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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Name of Exchange on which Registered
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Symbol
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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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☐
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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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Item
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Description
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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 Plan
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EnLink Midstream, LLC’s 2014 Long-Term Incentive Plan.
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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 842
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ASC 842,
Leases,
a new accounting standard effective January 1, 2019 related to the accounting for lease agreements.
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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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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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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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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 of ENLK held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC.
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ENLK
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EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
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ENLK Credit Facility
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A $1.5 billion unsecured revolving credit facility entered into by ENLK that would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
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EOGP
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EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. As of January 31, 2019, EOGP is wholly-owned by the Operating Partnership.
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FASB
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Financial Accounting Standards Board.
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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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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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GP Plan
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EnLink Midstream GP, LLC’s Long-Term Incentive Plan.
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Gross Operating Margin
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A non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for the definition and other information.
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ISDAs
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International Swaps and Derivatives Association Agreements.
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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, our general partner, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger.
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MMbbls
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One million barrels.
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MMbtu
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Million British thermal units.
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MMcf
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Million cubic feet.
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MVC
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Minimum volume commitment.
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NGL
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Natural gas liquid.
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NGP
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NGP Natural Resources XI, LP.
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NOLA Merger Sub
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NOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.
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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 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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Series B Preferred Units
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ENLK’s Series B Cumulative Convertible Preferred Units.
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Series C Preferred Units
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ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
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STACK
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Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
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Term Loan
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An $850.0 million term loan entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guarantees.
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Thunderbird Plant
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A gas processing plant in central Oklahoma.
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White Star
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White Star Petroleum Holdings, LLC.
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June 30, 2019
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December 31, 2018
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(Unaudited)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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58.5
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$
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99.5
|
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Accounts receivable:
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||||
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively
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78.4
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126.3
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Accrued revenue and other
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483.9
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705.9
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Related party
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12.4
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2.1
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Fair value of derivative assets
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9.5
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28.6
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Natural gas and NGLs inventory, prepaid expenses, and other
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71.7
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72.8
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Total current assets
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714.4
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1,035.2
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Property and equipment, net of accumulated depreciation of $3,198.1 and $2,967.4, respectively
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7,023.5
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6,846.7
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Intangible assets, net of accumulated amortization of $484.1 and $422.2, respectively
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1,311.7
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1,373.6
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Goodwill
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190.3
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190.3
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Investment in unconsolidated affiliates
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80.0
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80.1
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Fair value of derivative assets
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7.1
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4.1
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Other assets, net
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97.1
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41.3
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Total assets
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$
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9,424.1
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$
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9,571.3
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LIABILITIES AND PARTNERS’ EQUITY
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Current liabilities:
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||||
Accounts payable and drafts payable
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$
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80.8
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$
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105.5
|
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Accounts payable to related party
|
2.0
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4.3
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Accrued gas, NGLs, condensate, and crude oil purchases
|
377.1
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|
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500.4
|
|
||
Fair value of derivative liabilities
|
5.8
|
|
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21.8
|
|
||
Current maturities of long-term debt
|
—
|
|
|
399.8
|
|
||
Other current liabilities
|
234.5
|
|
|
246.7
|
|
||
Total current liabilities
|
700.2
|
|
|
1,278.5
|
|
||
Long-term debt, including $1,438.5 million from affiliates
|
4,501.0
|
|
|
3,919.8
|
|
||
Asset retirement obligations
|
15.2
|
|
|
14.8
|
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Other long-term liabilities
|
93.0
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20.0
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Deferred tax liability
|
41.2
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|
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42.4
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Fair value of derivative liabilities
|
10.6
|
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2.4
|
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||
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|
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|
||||
Redeemable non-controlling interest
|
5.8
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9.3
|
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Partners’ equity:
|
|
|
|
||||
Common unitholders (144,358,720 and 353,117,434 units issued and outstanding, respectively)
|
2,220.3
|
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|
2,460.8
|
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Series B preferred unitholders (59,302,666 and 58,728,994 units issued and outstanding, respectively)
|
893.2
|
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889.3
|
|
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Series C preferred unitholders (400,000 units outstanding)
|
395.1
|
|
|
395.1
|
|
||
General partner interest (1,594,974 equivalent units outstanding)
|
218.2
|
|
|
231.2
|
|
||
Accumulated other comprehensive loss
|
(15.6
|
)
|
|
(2.1
|
)
|
||
Non-controlling interest
|
345.9
|
|
|
309.8
|
|
||
Total partners’ equity
|
4,057.1
|
|
|
4,284.1
|
|
||
Total liabilities and partners’ equity
|
$
|
9,424.1
|
|
|
$
|
9,571.3
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
|
(Unaudited)
|
||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
||||||||
Product sales
|
$
|
1,450.4
|
|
|
$
|
1,435.1
|
|
|
$
|
2,981.3
|
|
|
$
|
2,934.3
|
|
Product sales—related parties
|
—
|
|
|
27.2
|
|
|
—
|
|
|
30.8
|
|
||||
Midstream services
|
252.7
|
|
|
142.4
|
|
|
499.2
|
|
|
234.6
|
|
||||
Midstream services—related parties
|
—
|
|
|
175.2
|
|
|
—
|
|
|
341.4
|
|
||||
Gain (loss) on derivative activity
|
6.9
|
|
|
(15.2
|
)
|
|
8.7
|
|
|
(14.7
|
)
|
||||
Total revenues
|
1,710.0
|
|
|
1,764.7
|
|
|
3,489.2
|
|
|
3,526.4
|
|
||||
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of sales (1)
|
1,300.1
|
|
|
1,325.6
|
|
|
2,663.5
|
|
|
2,707.1
|
|
||||
Operating expenses
|
117.9
|
|
|
113.4
|
|
|
232.4
|
|
|
222.6
|
|
||||
General and administrative
|
31.9
|
|
|
29.1
|
|
|
70.5
|
|
|
55.3
|
|
||||
Loss on disposition of assets
|
0.1
|
|
|
1.2
|
|
|
0.1
|
|
|
1.3
|
|
||||
Depreciation and amortization
|
153.7
|
|
|
145.3
|
|
|
305.8
|
|
|
283.4
|
|
||||
Loss on secured term loan receivable
|
52.9
|
|
|
—
|
|
|
52.9
|
|
|
—
|
|
||||
Total operating costs and expenses
|
1,656.6
|
|
|
1,614.6
|
|
|
3,325.2
|
|
|
3,269.7
|
|
||||
Operating income
|
53.4
|
|
|
150.1
|
|
|
164.0
|
|
|
256.7
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense, net of interest income
|
(54.3
|
)
|
|
(43.7
|
)
|
|
(103.6
|
)
|
|
(87.4
|
)
|
||||
Income from unconsolidated affiliates
|
4.7
|
|
|
4.4
|
|
|
10.0
|
|
|
7.4
|
|
||||
Other income
|
0.3
|
|
|
—
|
|
|
0.3
|
|
|
0.2
|
|
||||
Total other expense
|
(49.3
|
)
|
|
(39.3
|
)
|
|
(93.3
|
)
|
|
(79.8
|
)
|
||||
Income before non-controlling interest and income taxes
|
4.1
|
|
|
110.8
|
|
|
70.7
|
|
|
176.9
|
|
||||
Income tax benefit (provision)
|
0.7
|
|
|
2.1
|
|
|
(0.2
|
)
|
|
1.1
|
|
||||
Net income
|
4.8
|
|
|
112.9
|
|
|
70.5
|
|
|
178.0
|
|
||||
Net income attributable to non-controlling interest
|
0.7
|
|
|
1.4
|
|
|
3.6
|
|
|
2.2
|
|
||||
Net income attributable to ENLK
|
$
|
4.1
|
|
|
$
|
111.5
|
|
|
$
|
66.9
|
|
|
$
|
175.8
|
|
(1)
|
Includes related party cost of sales of
$5.8 million
and
$46.7 million
for the
three months ended
June 30, 2019
and
2018
, respectively, and
$13.9 million
and
$80.8 million
for the
six
months ended
June 30, 2019
and
2018
, respectively.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
|
(Unaudited)
|
||||||||||||||
Net income
|
$
|
4.8
|
|
|
$
|
112.9
|
|
|
$
|
70.5
|
|
|
$
|
178.0
|
|
Loss on designated cash flow hedge (1)
|
(13.5
|
)
|
|
—
|
|
|
(13.5
|
)
|
|
—
|
|
||||
Comprehensive income (loss)
|
(8.7
|
)
|
|
112.9
|
|
|
57.0
|
|
|
178.0
|
|
||||
Comprehensive income attributable to non-controlling interest
|
0.7
|
|
|
1.4
|
|
|
3.6
|
|
|
2.2
|
|
||||
Comprehensive income (loss) attributable to ENLK
|
$
|
(9.4
|
)
|
|
$
|
111.5
|
|
|
$
|
53.4
|
|
|
$
|
175.8
|
|
(1)
|
Includes an immaterial amount of amortization to interest expense for the three and six months ended
June 30, 2019
and
2018
, respectively.
|
|
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
|
|
$
|
|
$
|
|
$
|
|
$
|
||||||||||||||||||||
|
(Unaudited)
|
||||||||||||||||||||||||||||||||||||||||||
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
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13.5
|
|
|
—
|
|
||||||||
Distributions
|
(139.4
|
)
|
|
—
|
|
|
(16.5
|
)
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
(15.6
|
)
|
|
—
|
|
|
—
|
|
|
(6.3
|
)
|
|
(177.8
|
)
|
|
—
|
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15.7
|
|
|
15.7
|
|
|
—
|
|
||||||||
Fair value adjustment related to redeemable non-controlling interest
|
2.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.1
|
|
|
(2.1
|
)
|
||||||||
Issuance of common units to ENLC for acquisition of EOGP
|
—
|
|
|
55.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Conversion of ENLK common units into ENLC units
|
—
|
|
|
(265.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Net income (loss)
|
47.5
|
|
|
—
|
|
|
18.6
|
|
|
—
|
|
|
6.0
|
|
|
—
|
|
|
(9.3
|
)
|
|
—
|
|
|
—
|
|
|
2.9
|
|
|
65.7
|
|
|
—
|
|
||||||||
Balance, March 31, 2019
|
2,369.9
|
|
|
144.4
|
|
|
891.4
|
|
|
59.2
|
|
|
401.1
|
|
|
0.4
|
|
|
218.4
|
|
|
1.6
|
|
|
(2.1
|
)
|
|
322.1
|
|
|
4,200.8
|
|
|
7.2
|
|
||||||||
Unit-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6.4
|
|
|
—
|
|
||||||||
Distributions
|
(137.2
|
)
|
|
—
|
|
|
(16.7
|
)
|
|
0.1
|
|
|
(12.0
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6.4
|
)
|
|
(172.3
|
)
|
|
—
|
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29.5
|
|
|
29.5
|
|
|
—
|
|
||||||||
Loss on designated cash flow hedge
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13.5
|
)
|
|
—
|
|
|
(13.5
|
)
|
|
—
|
|
||||||||
Fair value adjustment related to redeemable non-controlling interest
|
1.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.4
|
|
|
(1.4
|
)
|
||||||||
Net income (loss)
|
(13.8
|
)
|
|
—
|
|
|
18.5
|
|
|
—
|
|
|
6.0
|
|
|
—
|
|
|
(6.6
|
)
|
|
—
|
|
|
—
|
|
|
0.7
|
|
|
4.8
|
|
|
—
|
|
||||||||
Balance, June 30, 2019
|
$
|
2,220.3
|
|
|
144.4
|
|
|
$
|
893.2
|
|
|
59.3
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
218.2
|
|
|
1.6
|
|
|
$
|
(15.6
|
)
|
|
$
|
345.9
|
|
|
$
|
4,057.1
|
|
|
$
|
5.8
|
|
|
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
|
|
$
|
|
$
|
|
$
|
|
$
|
||||||||||||||||||||
|
(Unaudited)
|
||||||||||||||||||||||||||||||||||||||||||
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
|
0.9
|
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.9
|
|
|
—
|
|
||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(2.7
|
)
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.7
|
)
|
|
—
|
|
||||||||
Unit-based compensation
|
4.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8.8
|
|
|
—
|
|
||||||||
Distributions
|
(137.6
|
)
|
|
—
|
|
|
(16.0
|
)
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
(15.4
|
)
|
|
—
|
|
|
—
|
|
|
(10.0
|
)
|
|
(179.0
|
)
|
|
—
|
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33.3
|
|
|
33.3
|
|
|
—
|
|
||||||||
Adjustment for acquisition of EOGP (Note 1)
|
2.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2.8
|
)
|
|
—
|
|
|
—
|
|
||||||||
Net income
|
21.6
|
|
|
—
|
|
|
21.9
|
|
|
—
|
|
|
6.0
|
|
|
—
|
|
|
14.8
|
|
|
—
|
|
|
—
|
|
|
0.8
|
|
|
65.1
|
|
|
—
|
|
||||||||
Balance, March 31, 2018
|
2,998.0
|
|
|
350.2
|
|
|
870.0
|
|
|
57.5
|
|
|
401.1
|
|
|
0.4
|
|
|
210.4
|
|
|
1.6
|
|
|
(2.1
|
)
|
|
254.5
|
|
|
4,731.9
|
|
|
4.6
|
|
||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(0.7
|
)
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.7
|
)
|
|
—
|
|
||||||||
Unit-based compensation
|
4.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8.0
|
|
|
—
|
|
||||||||
Distributions
|
(137.4
|
)
|
|
—
|
|
|
(16.2
|
)
|
|
0.4
|
|
|
(12.0
|
)
|
|
—
|
|
|
(15.5
|
)
|
|
—
|
|
|
—
|
|
|
(13.4
|
)
|
|
(194.5
|
)
|
|
—
|
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48.3
|
|
|
48.3
|
|
|
—
|
|
||||||||
Adjustment for acquisition of EOGP (Note 1)
|
6.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6.6
|
)
|
|
—
|
|
|
—
|
|
||||||||
Net income
|
58.9
|
|
|
—
|
|
|
22.8
|
|
|
—
|
|
|
6.0
|
|
|
—
|
|
|
23.8
|
|
|
—
|
|
|
—
|
|
|
1.4
|
|
|
112.9
|
|
|
—
|
|
||||||||
Balance, June 30, 2018
|
$
|
2,929.4
|
|
|
350.3
|
|
|
$
|
876.6
|
|
|
57.9
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
222.7
|
|
|
1.6
|
|
|
$
|
(2.1
|
)
|
|
$
|
284.2
|
|
|
$
|
4,705.9
|
|
|
$
|
4.6
|
|
|
Six Months Ended June 30,
|
||||||
|
2019
|
|
2018
|
||||
|
(Unaudited)
|
||||||
Cash flows from operating activities:
|
|
|
|
||||
Net income
|
$
|
70.5
|
|
|
$
|
178.0
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation and amortization
|
305.8
|
|
|
283.4
|
|
||
Loss on secured term loan receivable
|
52.9
|
|
|
—
|
|
||
Non-cash unit-based compensation
|
18.9
|
|
|
14.6
|
|
||
(Gain) loss on derivatives recognized in net income
|
(8.7
|
)
|
|
14.7
|
|
||
Cash settlements on derivatives
|
4.9
|
|
|
(0.4
|
)
|
||
Amortization of debt issue costs, net discount (premium) of notes
|
2.9
|
|
|
2.4
|
|
||
Distribution of earnings from unconsolidated affiliates
|
9.7
|
|
|
9.5
|
|
||
Income from unconsolidated affiliates
|
(10.0
|
)
|
|
(7.4
|
)
|
||
Non-cash revenue from contract restructuring
|
—
|
|
|
(45.5
|
)
|
||
Other operating activities
|
(4.2
|
)
|
|
(0.9
|
)
|
||
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
|
|
|
|
|
|
||
Accounts receivable, accrued revenue, and other
|
259.7
|
|
|
(46.6
|
)
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
(7.8
|
)
|
|
(40.2
|
)
|
||
Accounts payable, accrued product purchases, and other accrued liabilities
|
(179.0
|
)
|
|
69.1
|
|
||
Net cash provided by operating activities
|
515.6
|
|
|
430.7
|
|
||
Cash flows from investing activities:
|
|
|
|
||||
Additions to property and equipment
|
(428.4
|
)
|
|
(404.4
|
)
|
||
Other investing activities
|
1.5
|
|
|
2.6
|
|
||
Net cash used in investing activities
|
(426.9
|
)
|
|
(401.8
|
)
|
||
Cash flows from financing activities:
|
|
|
|
||||
Proceeds from borrowings
|
3,058.5
|
|
|
1,346.0
|
|
||
Payments on borrowings
|
(2,870.0
|
)
|
|
(826.0
|
)
|
||
Payment of installment payable for EOGP acquisition
|
—
|
|
|
(250.0
|
)
|
||
Debt financing costs
|
(9.7
|
)
|
|
—
|
|
||
Proceeds from issuance of common units
|
—
|
|
|
0.9
|
|
||
Distributions to non-controlling interests
|
(12.7
|
)
|
|
(23.4
|
)
|
||
Contributions by non-controlling interests, including contributions from affiliates of $27.3 for the six months ended June 30, 2018
|
45.2
|
|
|
81.6
|
|
||
Distributions to Series B Preferred Units
|
(33.2
|
)
|
|
(32.2
|
)
|
||
Distributions to Series C Preferred Units
|
(12.0
|
)
|
|
(12.0
|
)
|
||
Distributions to common unitholders and to general partner
|
(292.2
|
)
|
|
(305.9
|
)
|
||
Other financing activities
|
(3.6
|
)
|
|
(2.2
|
)
|
||
Net cash used in financing activities
|
(129.7
|
)
|
|
(23.2
|
)
|
||
Net increase (decrease) in cash and cash equivalents
|
(41.0
|
)
|
|
5.7
|
|
||
Cash and cash equivalents, beginning of period
|
99.5
|
|
|
30.8
|
|
||
Cash and cash equivalents, end of period
|
$
|
58.5
|
|
|
$
|
36.5
|
|
|
|
|
|
||||
Supplemental disclosures of cash flow information:
|
|
|
|
||||
Cash paid for interest
|
$
|
103.4
|
|
|
$
|
87.6
|
|
Cash paid for income taxes
|
$
|
1.2
|
|
|
$
|
0.4
|
|
Non-cash investing activities:
|
|
|
|
||||
Non-cash accrual of property and equipment
|
$
|
(5.8
|
)
|
|
$
|
(5.0
|
)
|
Discounted secured term loan receivable from contract restructuring
|
$
|
—
|
|
|
$
|
47.7
|
|
(a)
|
Organization of Business
|
•
|
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.
|
•
|
The Series B Preferred Units continue to be issued and outstanding, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership agreement of ENLK. See
“
Note 7—Partners' Capital
”
for additional information regarding the modified terms of the Series B Preferred Units.
|
•
|
ENLC issued to Enfield, the current holder of the Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled.
|
•
|
The Series C Preferred Units and all of ENLK’s 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 and the 2014 Plan has been converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time.
|
•
|
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 has been modified such that the performance metric for such 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.
|
(b)
|
Nature of Business
|
•
|
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.
|
(a)
|
Basis of Presentation
|
(b)
|
Revenue Recognition
|
MVC and Firm Transportation Commitments (1)
|
|
||
2019 (remaining)
|
$
|
122.0
|
|
2020
|
243.9
|
|
|
2021
|
92.9
|
|
|
2022
|
82.5
|
|
|
2023
|
79.9
|
|
|
Thereafter
|
228.1
|
|
|
Total
|
$
|
849.3
|
|
(1)
|
Amounts do not represent expected shortfall under these commitments.
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
||||||
Six Months Ended June 30, 2019
|
|
|
|
|
|
||||||
Customer relationships, beginning of period
|
$
|
1,795.8
|
|
|
$
|
(422.2
|
)
|
|
$
|
1,373.6
|
|
Amortization expense
|
—
|
|
|
(61.9
|
)
|
|
(61.9
|
)
|
|||
Customer relationships, end of period
|
$
|
1,795.8
|
|
|
$
|
(484.1
|
)
|
|
$
|
1,311.7
|
|
2019 (remaining)
|
$
|
61.8
|
|
2020
|
123.7
|
|
|
2021
|
123.7
|
|
|
2022
|
123.7
|
|
|
2023
|
123.6
|
|
|
Thereafter
|
755.2
|
|
|
Total
|
$
|
1,311.7
|
|
•
|
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
$62.5 million
of our lease liability and
$41.5 million
of our right-of-use asset as of
June 30, 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
$28.2 million
of our lease liability and
$30.1 million
of our right-of-use asset as of
June 30, 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
$0.7 million
of our lease liability and
$0.7 million
of our right-of-use asset as of
June 30, 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
$15.0 million
of our lease liability and
$13.1 million
of our right-of-use asset as of
June 30, 2019
.
|
|
June 30, 2019
|
||
Finance leases:
|
|
||
Property and equipment
|
$
|
5.2
|
|
Accumulated depreciation
|
(3.0
|
)
|
|
Property and equipment, net of accumulated depreciation
|
$
|
2.2
|
|
Other current liabilities
|
$
|
0.4
|
|
|
|
||
Operating leases:
|
|
||
Other assets, net
|
$
|
83.2
|
|
Other current liabilities
|
$
|
21.7
|
|
Other long-term liabilities
|
$
|
84.3
|
|
|
|
||
Other lease information
|
|
||
Weighted-average remaining lease term - Finance leases
|
0.3 years
|
|
|
Weighted-average remaining lease term - Operating leases
|
10.7 years
|
|
|
Weighted-average discount rate - Finance leases
|
9.3
|
%
|
|
Weighted-average discount rate - Operating leases
|
5.2
|
%
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||
|
2019
|
|
2019
|
||||
Finance lease expense:
|
|
|
|
||||
Amortization of right-of-use asset
|
$
|
2.3
|
|
|
$
|
3.0
|
|
Operating lease expense:
|
|
|
|
||||
Long-term operating lease expense
|
8.3
|
|
|
14.6
|
|
||
Short-term lease expense
|
8.9
|
|
|
15.8
|
|
||
Variable lease expense
|
1.4
|
|
|
3.0
|
|
||
Total lease expense
|
$
|
20.9
|
|
|
$
|
36.4
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||
|
2019
|
|
2019
|
||||
Supplemental cash flow information:
|
|
|
|
||||
Cash payments for finance leases included in cash flows from financing activities
|
$
|
0.4
|
|
|
$
|
0.8
|
|
Cash payments for operating leases included in cash flows from operating activities
|
$
|
8.2
|
|
|
$
|
15.4
|
|
Right-of-use assets obtained in exchange for operating lease liabilities
|
$
|
14.6
|
|
|
$
|
95.2
|
|
|
|
Total
|
|
2019 (remaining)
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||||
Undiscounted finance lease liability
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Finance lease liability
|
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Undiscounted operating lease liability
|
|
146.5
|
|
|
13.5
|
|
|
22.4
|
|
|
16.1
|
|
|
9.4
|
|
|
8.9
|
|
|
76.2
|
|
|||||||
Reduction due to present value
|
|
(40.5
|
)
|
|
(2.6
|
)
|
|
(4.5
|
)
|
|
(3.8
|
)
|
|
(3.4
|
)
|
|
(3.1
|
)
|
|
(23.1
|
)
|
|||||||
Operating lease liability
|
|
106.0
|
|
|
10.9
|
|
|
17.9
|
|
|
12.3
|
|
|
6.0
|
|
|
5.8
|
|
|
53.1
|
|
|||||||
Total lease liability
|
|
$
|
106.4
|
|
|
$
|
11.3
|
|
|
$
|
17.9
|
|
|
$
|
12.3
|
|
|
$
|
6.0
|
|
|
$
|
5.8
|
|
|
$
|
53.1
|
|
|
June 30, 2019
|
|
December 31, 2018
|
||||||||||||||||||||
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
||||||||||||
Intercompany debt (1)
|
$
|
1,438.5
|
|
|
$
|
—
|
|
|
$
|
1,438.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Term Loan due 2021 (2)
|
—
|
|
|
—
|
|
|
—
|
|
|
850.0
|
|
|
—
|
|
|
850.0
|
|
||||||
2.70% Senior unsecured notes due 2019 (3)
|
—
|
|
|
—
|
|
|
—
|
|
|
400.0
|
|
|
—
|
|
|
400.0
|
|
||||||
4.40% Senior unsecured notes due 2024
|
550.0
|
|
|
1.6
|
|
|
551.6
|
|
|
550.0
|
|
|
1.8
|
|
|
551.8
|
|
||||||
4.15% Senior unsecured notes due 2025
|
750.0
|
|
|
(0.8
|
)
|
|
749.2
|
|
|
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
|
|
|
(6.1
|
)
|
|
443.9
|
|
|
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
|
$
|
4,538.5
|
|
|
$
|
(6.1
|
)
|
|
4,532.4
|
|
|
$
|
4,350.0
|
|
|
$
|
(6.1
|
)
|
|
4,343.9
|
|
||
Debt issuance cost (4)
|
|
|
|
|
(31.4
|
)
|
|
|
|
|
|
(24.3
|
)
|
||||||||||
Less: Current maturities of long-term debt (3)
|
|
|
|
|
—
|
|
|
|
|
|
|
(399.8
|
)
|
||||||||||
Long-term debt, net of unamortized issuance cost
|
|
|
|
|
$
|
4,501.0
|
|
|
|
|
|
|
$
|
3,919.8
|
|
(1)
|
Intercompany debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through an intercompany arrangement with ENLC. Interest charged to ENLK for borrowings made through the intercompany arrangement will be the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes.
|
(2)
|
In December 2018, ENLK entered into an
$850.0 million
, three-year unsecured Term Loan. Borrowings under the Term Loan bear interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was
3.9%
at
December 31, 2018
. In connection with the closing of the Merger, the Term Loan was assumed by ENLC, and we became a guarantor of the Term Loan.
|
(3)
|
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
.
|
(4)
|
Net of amortization of
$11.9 million
and
$15.3 million
at
June 30, 2019
and
December 31, 2018
, respectively.
|
(a)
|
Series B Preferred Units
|
Declaration period
|
|
Distribution paid as additional Series B Preferred Units
|
|
Cash Distribution (in millions)
|
|
Date paid/payable
|
|||
2019
|
|
|
|
|
|
|
|||
Fourth Quarter of 2018
|
|
425,785
|
|
|
$
|
16.5
|
|
|
February 13, 2019
|
First Quarter of 2019
|
|
147,887
|
|
|
$
|
16.7
|
|
|
May 14, 2019
|
Second Quarter of 2019
|
|
148,257
|
|
|
$
|
17.1
|
|
|
August 13, 2019
|
|
|
|
|
|
|
|
|||
2018
|
|
|
|
|
|
|
|||
Fourth Quarter of 2017
|
|
413,658
|
|
|
$
|
16.0
|
|
|
February 13, 2018
|
First Quarter of 2018
|
|
416,657
|
|
|
$
|
16.2
|
|
|
May 14, 2018
|
Second Quarter of 2018
|
|
419,678
|
|
|
$
|
16.3
|
|
|
August 13, 2018
|
(b)
|
Series C Preferred Units
|
(c)
|
Common Unit Distributions
|
Declaration period
|
|
Distribution/unit
|
|
Date paid/payable
|
||
2019
|
|
|
|
|
||
Fourth Quarter of 2018
|
|
$
|
0.39
|
|
|
February 13, 2019
|
|
|
|
|
|
||
2018
|
|
|
|
|
||
Fourth Quarter of 2017
|
|
$
|
0.39
|
|
|
February 13, 2018
|
First Quarter of 2018
|
|
$
|
0.39
|
|
|
May 14, 2018
|
Second Quarter of 2018
|
|
$
|
0.39
|
|
|
August 13, 2018
|
(d)
|
Allocation of ENLK Income
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Income allocation for incentive distributions
|
$
|
—
|
|
|
$
|
14.8
|
|
|
$
|
—
|
|
|
$
|
29.6
|
|
Unit-based compensation attributable to ENLC’s restricted and performance units
|
(6.4
|
)
|
|
(4.0
|
)
|
|
(18.5
|
)
|
|
(8.4
|
)
|
||||
General partner share of net income (loss)
|
(0.2
|
)
|
|
0.4
|
|
|
0.2
|
|
|
0.6
|
|
||||
General partner interest in EOGP acquisition
|
—
|
|
|
12.6
|
|
|
2.4
|
|
|
16.8
|
|
||||
General partner interest in net income (loss)
|
$
|
(6.6
|
)
|
|
$
|
23.8
|
|
|
$
|
(15.9
|
)
|
|
$
|
38.6
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
GCF
|
|
|
|
|
|
|
|
||||||||
Distributions
|
$
|
7.4
|
|
|
$
|
5.4
|
|
|
$
|
9.6
|
|
|
$
|
11.1
|
|
Equity in income
|
$
|
5.2
|
|
|
$
|
4.8
|
|
|
$
|
10.9
|
|
|
$
|
9.4
|
|
|
|
|
|
|
|
|
|
||||||||
Cedar Cove JV
|
|
|
|
|
|
|
|
||||||||
Contributions
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
Distributions
|
$
|
0.2
|
|
|
$
|
—
|
|
|
$
|
0.5
|
|
|
$
|
0.3
|
|
Equity in loss
|
$
|
(0.5
|
)
|
|
$
|
(0.4
|
)
|
|
$
|
(0.9
|
)
|
|
$
|
(2.0
|
)
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
||||||||
Contributions
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
Distributions
|
$
|
7.6
|
|
|
$
|
5.4
|
|
|
$
|
10.1
|
|
|
$
|
11.4
|
|
Equity in income
|
$
|
4.7
|
|
|
$
|
4.4
|
|
|
$
|
10.0
|
|
|
$
|
7.4
|
|
|
June 30, 2019
|
|
December 31, 2018
|
||||
GCF
|
$
|
43.2
|
|
|
$
|
41.9
|
|
Cedar Cove JV
|
36.8
|
|
|
38.2
|
|
||
Total investment in unconsolidated affiliates
|
$
|
80.0
|
|
|
$
|
80.1
|
|
(a)
|
Long-Term Incentive Plans
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Cost of unit-based compensation charged to operating expense
|
$
|
2.1
|
|
|
$
|
2.3
|
|
|
$
|
2.4
|
|
|
$
|
4.3
|
|
Cost of unit-based compensation charged to general and administrative expense
|
5.9
|
|
|
7.2
|
|
|
16.5
|
|
|
10.3
|
|
||||
Total unit-based compensation expense
|
$
|
8.0
|
|
|
$
|
9.5
|
|
|
$
|
18.9
|
|
|
$
|
14.6
|
|
(b)
|
EnLink Midstream Partners, LP Restricted Incentive Units
|
|
|
Six Months Ended
June 30, 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.
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Aggregate intrinsic value of units vested
|
|
$
|
—
|
|
|
$
|
0.4
|
|
|
$
|
8.0
|
|
|
$
|
9.1
|
|
Fair value of units vested
|
|
$
|
—
|
|
|
$
|
0.5
|
|
|
$
|
7.2
|
|
|
$
|
13.3
|
|
(c)
|
EnLink Midstream Partners, LP Performance Units
|
|
|
Six Months Ended
June 30, 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.
|
|
|
Six Months Ended June 30,
|
||||||
EnLink Midstream Partners, LP Performance Units:
|
|
2019
|
|
2018
|
||||
Aggregate intrinsic value of units vested
|
|
$
|
2.1
|
|
|
$
|
2.0
|
|
Fair value of units vested
|
|
$
|
1.7
|
|
|
$
|
4.1
|
|
(d)
|
EnLink Midstream, LLC Restricted Incentive Units
|
|
|
Six Months Ended
June 30, 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)
|
|
1,835,494
|
|
|
11.44
|
|
||
Vested (1)(2)
|
|
(1,255,211
|
)
|
|
10.47
|
|
||
Forfeited
|
|
(272,185
|
)
|
|
10.86
|
|
||
Converted from ENLK (3)
|
|
2,103,266
|
|
|
14.01
|
|
||
Non-vested, end of period
|
|
4,837,231
|
|
|
$
|
14.44
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
48.8
|
|
|
|
|
(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
420,778
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.
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
EnLink Midstream, LLC Restricted Incentive Units:
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Aggregate intrinsic value of units vested
|
|
$
|
0.5
|
|
|
$
|
0.4
|
|
|
$
|
12.9
|
|
|
$
|
9.3
|
|
Fair value of units vested
|
|
$
|
0.5
|
|
|
$
|
0.4
|
|
|
$
|
13.1
|
|
|
$
|
13.5
|
|
(e)
|
EnLink Midstream, LLC’s Performance Units
|
|
|
Six Months Ended
June 30, 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
|
|
931,469
|
|
|
13.02
|
|
||
Vested (1)
|
|
(161,286
|
)
|
|
11.71
|
|
||
Forfeited
|
|
(92,422
|
)
|
|
20.41
|
|
||
Converted from ENLK (2)
|
|
333,798
|
|
|
25.84
|
|
||
Non-vested, end of period
|
|
1,429,708
|
|
|
$
|
17.48
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
14.4
|
|
|
|
|
(1)
|
Vested units included
62,219
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.
|
|
|
Six Months Ended June 30,
|
||||||
EnLink Midstream, LLC Performance Units:
|
|
2019
|
|
2018
|
||||
Aggregate intrinsic value of units vested
|
|
$
|
1.8
|
|
|
$
|
1.9
|
|
Fair value of units vested
|
|
$
|
1.9
|
|
|
$
|
4.2
|
|
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:
|
|
June 2019
|
|
March 2019
|
||||
Beginning TSR price
|
|
$
|
9.84
|
|
|
$
|
10.92
|
|
Risk-free interest rate
|
|
1.72
|
%
|
|
2.42
|
%
|
||
Volatility factor
|
|
33.50
|
%
|
|
33.86
|
%
|
||
Distribution yield
|
|
11.5
|
%
|
|
9.7
|
%
|
|
June 30, 2019
|
||
Fair value of derivative liabilities—current
|
$
|
(3.3
|
)
|
Fair value of derivative liabilities—long-term
|
(10.2
|
)
|
|
Net fair value of derivatives
|
$
|
(13.5
|
)
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Change in fair value of derivatives
|
$
|
7.2
|
|
|
$
|
(10.5
|
)
|
|
$
|
5.2
|
|
|
$
|
(14.0
|
)
|
Realized gain (loss) on derivatives
|
(0.3
|
)
|
|
(4.7
|
)
|
|
3.5
|
|
|
(0.7
|
)
|
||||
Gain (loss) on derivative activity
|
$
|
6.9
|
|
|
$
|
(15.2
|
)
|
|
$
|
8.7
|
|
|
$
|
(14.7
|
)
|
|
June 30, 2019
|
|
December 31, 2018
|
||||
Fair value of derivative assets—current
|
$
|
9.5
|
|
|
$
|
28.6
|
|
Fair value of derivative assets—long-term
|
7.1
|
|
|
4.1
|
|
||
Fair value of derivative liabilities—current
|
(2.5
|
)
|
|
(21.8
|
)
|
||
Fair value of derivative liabilities—long-term
|
(0.4
|
)
|
|
(2.4
|
)
|
||
Net fair value of derivatives
|
$
|
13.7
|
|
|
$
|
8.5
|
|
|
|
|
|
June 30, 2019
|
|||||||
Commodity
|
|
Instruments
|
|
Unit
|
|
Volume
|
|
Fair Value
|
|||
NGL (short contracts)
|
|
Swaps
|
|
Gallons
|
|
(24.2
|
)
|
|
$
|
3.0
|
|
NGL (long contracts)
|
|
Swaps
|
|
Gallons
|
|
15.0
|
|
|
(0.6
|
)
|
|
Natural gas (short contracts)
|
|
Swaps
|
|
MMBtu
|
|
(2.4
|
)
|
|
0.4
|
|
|
Natural gas (long contracts)
|
|
Swaps
|
|
MMBtu
|
|
6.3
|
|
|
(0.4
|
)
|
|
Crude and condensate (short contracts)
|
|
Swaps
|
|
MMbbls
|
|
(12.3
|
)
|
|
5.6
|
|
|
Crude and condensate (long contracts)
|
|
Swaps
|
|
MMbbls
|
|
0.8
|
|
|
5.7
|
|
|
Total fair value of derivatives
|
|
|
|
|
|
|
|
|
$
|
13.7
|
|
|
|
Level 2
|
||||||
|
|
June 30, 2019
|
|
December 31, 2018
|
||||
Interest rate swaps (1)
|
|
$
|
(13.5
|
)
|
|
$
|
—
|
|
Commodity swaps (2)
|
|
$
|
13.7
|
|
|
$
|
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.
|
|
June 30, 2019
|
|
December 31, 2018
|
||||||||||||
|
Carrying
Value
|
|
Fair
Value
|
|
Carrying
Value |
|
Fair
Value |
||||||||
Long-term debt (1)
|
$
|
4,501.0
|
|
|
$
|
4,368.9
|
|
|
$
|
4,319.6
|
|
|
$
|
3,953.6
|
|
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 long-term debt is reduced by debt issuance costs of
$31.4 million
and
$24.3 million
at
June 30, 2019
and
December 31, 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. We do not believe that it is probable that White Star will be 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
|
||||||||||||
Three Months Ended June 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
(1.0
|
)
|
|
$
|
31.9
|
|
|
$
|
60.3
|
|
|
$
|
102.6
|
|
|
$
|
—
|
|
|
$
|
193.8
|
|
NGL sales
|
0.8
|
|
|
8.7
|
|
|
4.3
|
|
|
498.8
|
|
|
—
|
|
|
512.6
|
|
||||||
Crude oil and condensate sales
|
632.0
|
|
|
—
|
|
|
28.6
|
|
|
83.5
|
|
|
—
|
|
|
744.1
|
|
||||||
Other
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
||||||
Product sales
|
631.8
|
|
|
40.6
|
|
|
93.1
|
|
|
684.9
|
|
|
—
|
|
|
1,450.4
|
|
||||||
Natural gas sales—related parties
|
0.4
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
(0.7
|
)
|
|
—
|
|
||||||
NGL sales—related parties
|
76.4
|
|
|
22.2
|
|
|
104.6
|
|
|
5.3
|
|
|
(208.5
|
)
|
|
—
|
|
||||||
Crude oil and condensate sales—related parties
|
6.9
|
|
|
1.7
|
|
|
—
|
|
|
—
|
|
|
(8.6
|
)
|
|
—
|
|
||||||
Product sales—related parties
|
83.7
|
|
|
24.2
|
|
|
104.6
|
|
|
5.3
|
|
|
(217.8
|
)
|
|
—
|
|
||||||
Gathering and transportation
|
11.3
|
|
|
49.0
|
|
|
59.2
|
|
|
16.7
|
|
|
—
|
|
|
136.2
|
|
||||||
Processing
|
7.3
|
|
|
35.7
|
|
|
35.7
|
|
|
0.8
|
|
|
—
|
|
|
79.5
|
|
||||||
NGL services
|
—
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
|
—
|
|
|
10.0
|
|
||||||
Crude services
|
5.3
|
|
|
—
|
|
|
5.2
|
|
|
12.9
|
|
|
—
|
|
|
23.4
|
|
||||||
Other services
|
2.9
|
|
|
0.3
|
|
|
0.2
|
|
|
0.2
|
|
|
—
|
|
|
3.6
|
|
||||||
Midstream services
|
26.8
|
|
|
85.0
|
|
|
100.3
|
|
|
40.6
|
|
|
—
|
|
|
252.7
|
|
||||||
NGL services—related parties
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
0.3
|
|
|
—
|
|
||||||
Crude services—related parties
|
—
|
|
|
—
|
|
|
1.2
|
|
|
—
|
|
|
(1.2
|
)
|
|
—
|
|
||||||
Midstream services—related parties
|
—
|
|
|
—
|
|
|
1.2
|
|
|
(0.3
|
)
|
|
(0.9
|
)
|
|
—
|
|
||||||
Revenue from contracts with customers
|
742.3
|
|
|
149.8
|
|
|
299.2
|
|
|
730.5
|
|
|
(218.7
|
)
|
|
1,703.1
|
|
||||||
Cost of sales
|
(680.5
|
)
|
|
(51.0
|
)
|
|
(159.4
|
)
|
|
(627.9
|
)
|
|
218.7
|
|
|
(1,300.1
|
)
|
||||||
Operating expenses
|
(28.4
|
)
|
|
(25.8
|
)
|
|
(26.1
|
)
|
|
(37.6
|
)
|
|
—
|
|
|
(117.9
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6.9
|
|
|
6.9
|
|
||||||
Segment profit
|
$
|
33.4
|
|
|
$
|
73.0
|
|
|
$
|
113.7
|
|
|
$
|
65.0
|
|
|
$
|
6.9
|
|
|
$
|
292.0
|
|
Depreciation and amortization
|
$
|
(30.1
|
)
|
|
$
|
(36.9
|
)
|
|
$
|
(47.6
|
)
|
|
$
|
(36.9
|
)
|
|
$
|
(2.2
|
)
|
|
$
|
(153.7
|
)
|
Goodwill
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
Capital expenditures
|
$
|
52.4
|
|
|
$
|
27.0
|
|
|
$
|
70.3
|
|
|
$
|
19.5
|
|
|
$
|
2.4
|
|
|
$
|
171.6
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Three Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
33.5
|
|
|
$
|
23.3
|
|
|
$
|
37.9
|
|
|
$
|
122.7
|
|
|
$
|
—
|
|
|
$
|
217.4
|
|
NGL sales
|
0.3
|
|
|
—
|
|
|
3.6
|
|
|
627.9
|
|
|
—
|
|
|
631.8
|
|
||||||
Crude oil and condensate sales
|
511.5
|
|
|
—
|
|
|
23.3
|
|
|
51.1
|
|
|
—
|
|
|
585.9
|
|
||||||
Product sales
|
545.3
|
|
|
23.3
|
|
|
64.8
|
|
|
801.7
|
|
|
—
|
|
|
1,435.1
|
|
||||||
Natural gas sales—related parties
|
—
|
|
|
—
|
|
|
1.9
|
|
|
—
|
|
|
—
|
|
|
1.9
|
|
||||||
NGL sales—related parties
|
122.9
|
|
|
11.5
|
|
|
140.4
|
|
|
28.9
|
|
|
(278.7
|
)
|
|
25.0
|
|
||||||
Crude oil and condensate sales—related parties
|
0.4
|
|
|
0.4
|
|
|
0.3
|
|
|
0.1
|
|
|
(0.9
|
)
|
|
0.3
|
|
||||||
Product sales—related parties
|
123.3
|
|
|
11.9
|
|
|
142.6
|
|
|
29.0
|
|
|
(279.6
|
)
|
|
27.2
|
|
||||||
Gathering and transportation
|
7.6
|
|
|
6.8
|
|
|
25.6
|
|
|
16.7
|
|
|
—
|
|
|
56.7
|
|
||||||
Processing
|
7.3
|
|
|
2.2
|
|
|
47.4
|
|
|
1.1
|
|
|
—
|
|
|
58.0
|
|
||||||
NGL services
|
—
|
|
|
—
|
|
|
—
|
|
|
10.3
|
|
|
—
|
|
|
10.3
|
|
||||||
Crude services
|
0.1
|
|
|
—
|
|
|
—
|
|
|
14.9
|
|
|
—
|
|
|
15.0
|
|
||||||
Other services
|
2.0
|
|
|
—
|
|
|
(0.1
|
)
|
|
0.5
|
|
|
—
|
|
|
2.4
|
|
||||||
Midstream services
|
17.0
|
|
|
9.0
|
|
|
72.9
|
|
|
43.5
|
|
|
—
|
|
|
142.4
|
|
||||||
Gathering and transportation—related parties
|
—
|
|
|
61.4
|
|
|
38.7
|
|
|
—
|
|
|
—
|
|
|
100.1
|
|
||||||
Processing—related parties
|
—
|
|
|
46.8
|
|
|
23.1
|
|
|
—
|
|
|
—
|
|
|
69.9
|
|
||||||
Crude services—related parties
|
4.3
|
|
|
—
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
|
5.0
|
|
||||||
Other services—related parties
|
—
|
|
|
0.4
|
|
|
(0.2
|
)
|
|
—
|
|
|
—
|
|
|
0.2
|
|
||||||
Midstream services—related parties
|
4.3
|
|
|
108.6
|
|
|
62.3
|
|
|
—
|
|
|
—
|
|
|
175.2
|
|
||||||
Revenue from contracts with customers
|
689.9
|
|
|
152.8
|
|
|
342.6
|
|
|
874.2
|
|
|
(279.6
|
)
|
|
1,779.9
|
|
||||||
Cost of sales
|
(633.9
|
)
|
|
(32.0
|
)
|
|
(170.1
|
)
|
|
(769.2
|
)
|
|
279.6
|
|
|
(1,325.6
|
)
|
||||||
Operating expenses
|
(24.7
|
)
|
|
(28.4
|
)
|
|
(20.8
|
)
|
|
(39.5
|
)
|
|
—
|
|
|
(113.4
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15.2
|
)
|
|
(15.2
|
)
|
||||||
Segment profit
|
$
|
31.3
|
|
|
$
|
92.4
|
|
|
$
|
151.7
|
|
|
$
|
65.5
|
|
|
$
|
(15.2
|
)
|
|
$
|
325.7
|
|
Depreciation and amortization
|
$
|
(27.3
|
)
|
|
$
|
(31.6
|
)
|
|
$
|
(46.4
|
)
|
|
$
|
(37.4
|
)
|
|
$
|
(2.6
|
)
|
|
$
|
(145.3
|
)
|
Goodwill
|
$
|
29.3
|
|
|
$
|
202.7
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
52.8
|
|
|
$
|
5.5
|
|
|
$
|
140.0
|
|
|
$
|
18.8
|
|
|
$
|
1.1
|
|
|
$
|
218.2
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Six Months Ended June 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
35.1
|
|
|
$
|
82.5
|
|
|
$
|
121.9
|
|
|
$
|
224.8
|
|
|
$
|
—
|
|
|
$
|
464.3
|
|
NGL sales
|
0.6
|
|
|
18.0
|
|
|
13.2
|
|
|
1,071.9
|
|
|
—
|
|
|
1,103.7
|
|
||||||
Crude oil and condensate sales
|
1,212.8
|
|
|
—
|
|
|
58.2
|
|
|
142.3
|
|
|
—
|
|
|
1,413.3
|
|
||||||
Product sales
|
1,248.5
|
|
|
100.5
|
|
|
193.3
|
|
|
1,439.0
|
|
|
—
|
|
|
2,981.3
|
|
||||||
Natural gas sales—related parties
|
0.4
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
(0.7
|
)
|
|
—
|
|
||||||
NGL sales—related parties
|
173.6
|
|
|
50.7
|
|
|
230.7
|
|
|
8.5
|
|
|
(463.5
|
)
|
|
—
|
|
||||||
Crude oil and condensate sales—related parties
|
10.9
|
|
|
2.7
|
|
|
—
|
|
|
—
|
|
|
(13.6
|
)
|
|
—
|
|
||||||
Product sales—related parties
|
184.9
|
|
|
53.7
|
|
|
230.7
|
|
|
8.5
|
|
|
(477.8
|
)
|
|
—
|
|
||||||
Gathering and transportation
|
21.6
|
|
|
112.6
|
|
|
114.5
|
|
|
33.9
|
|
|
—
|
|
|
282.6
|
|
||||||
Processing
|
15.0
|
|
|
56.8
|
|
|
69.8
|
|
|
1.7
|
|
|
—
|
|
|
143.3
|
|
||||||
NGL services
|
—
|
|
|
—
|
|
|
—
|
|
|
21.7
|
|
|
—
|
|
|
21.7
|
|
||||||
Crude services
|
10.5
|
|
|
—
|
|
|
9.2
|
|
|
26.7
|
|
|
—
|
|
|
46.4
|
|
||||||
Other services
|
4.4
|
|
|
0.5
|
|
|
(0.1
|
)
|
|
0.4
|
|
|
—
|
|
|
5.2
|
|
||||||
Midstream services
|
51.5
|
|
|
169.9
|
|
|
193.4
|
|
|
84.4
|
|
|
—
|
|
|
499.2
|
|
||||||
NGL services—related parties
|
—
|
|
|
—
|
|
|
—
|
|
|
(3.3
|
)
|
|
3.3
|
|
|
—
|
|
||||||
Crude services—related parties
|
—
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
(1.5
|
)
|
|
—
|
|
||||||
Midstream services—related parties
|
—
|
|
|
—
|
|
|
1.5
|
|
|
(3.3
|
)
|
|
1.8
|
|
|
—
|
|
||||||
Revenue from contracts with customers
|
1,484.9
|
|
|
324.1
|
|
|
618.9
|
|
|
1,528.6
|
|
|
(476.0
|
)
|
|
3,480.5
|
|
||||||
Cost of sales
|
(1,356.7
|
)
|
|
(124.7
|
)
|
|
(343.6
|
)
|
|
(1,314.5
|
)
|
|
476.0
|
|
|
(2,663.5
|
)
|
||||||
Operating expenses
|
(56.2
|
)
|
|
(51.5
|
)
|
|
(51.5
|
)
|
|
(73.2
|
)
|
|
—
|
|
|
(232.4
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8.7
|
|
|
8.7
|
|
||||||
Segment profit
|
$
|
72.0
|
|
|
$
|
147.9
|
|
|
$
|
223.8
|
|
|
$
|
140.9
|
|
|
$
|
8.7
|
|
|
$
|
593.3
|
|
Depreciation and amortization
|
$
|
(58.0
|
)
|
|
$
|
(71.2
|
)
|
|
$
|
(93.7
|
)
|
|
$
|
(78.7
|
)
|
|
$
|
(4.2
|
)
|
|
$
|
(305.8
|
)
|
Goodwill
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
Capital expenditures
|
$
|
148.3
|
|
|
$
|
31.3
|
|
|
$
|
178.5
|
|
|
$
|
60.5
|
|
|
$
|
4.0
|
|
|
$
|
422.6
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Louisiana
|
|
Corporate
|
|
Totals
|
||||||||||||
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
71.2
|
|
|
$
|
68.6
|
|
|
$
|
86.0
|
|
|
$
|
247.7
|
|
|
$
|
—
|
|
|
$
|
473.5
|
|
NGL sales
|
0.8
|
|
|
—
|
|
|
5.5
|
|
|
1,236.3
|
|
|
—
|
|
|
1,242.6
|
|
||||||
Crude oil and condensate sales
|
1,088.7
|
|
|
—
|
|
|
45.2
|
|
|
84.3
|
|
|
—
|
|
|
1,218.2
|
|
||||||
Product sales
|
1,160.7
|
|
|
68.6
|
|
|
136.7
|
|
|
1,568.3
|
|
|
—
|
|
|
2,934.3
|
|
||||||
Natural gas sales—related parties
|
—
|
|
|
—
|
|
|
2.4
|
|
|
—
|
|
|
—
|
|
|
2.4
|
|
||||||
NGL sales—related parties
|
206.8
|
|
|
20.5
|
|
|
240.5
|
|
|
34.5
|
|
|
(474.9
|
)
|
|
27.4
|
|
||||||
Crude oil and condensate sales—related parties
|
1.9
|
|
|
0.8
|
|
|
0.7
|
|
|
0.2
|
|
|
(2.6
|
)
|
|
1.0
|
|
||||||
Product sales—related parties
|
208.7
|
|
|
21.3
|
|
|
243.6
|
|
|
34.7
|
|
|
(477.5
|
)
|
|
30.8
|
|
||||||
Gathering and transportation
|
13.8
|
|
|
14.6
|
|
|
41.2
|
|
|
34.3
|
|
|
—
|
|
|
103.9
|
|
||||||
Processing
|
11.1
|
|
|
2.2
|
|
|
56.4
|
|
|
1.7
|
|
|
—
|
|
|
71.4
|
|
||||||
NGL services
|
—
|
|
|
—
|
|
|
—
|
|
|
26.9
|
|
|
—
|
|
|
26.9
|
|
||||||
Crude services
|
0.1
|
|
|
—
|
|
|
0.1
|
|
|
27.7
|
|
|
—
|
|
|
27.9
|
|
||||||
Other services
|
3.7
|
|
|
0.3
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
4.5
|
|
||||||
Midstream services
|
28.7
|
|
|
17.1
|
|
|
97.7
|
|
|
91.1
|
|
|
—
|
|
|
234.6
|
|
||||||
Gathering and transportation—related parties
|
—
|
|
|
114.0
|
|
|
73.4
|
|
|
—
|
|
|
—
|
|
|
187.4
|
|
||||||
Processing—related parties
|
—
|
|
|
98.4
|
|
|
45.2
|
|
|
—
|
|
|
—
|
|
|
143.6
|
|
||||||
Crude services—related parties
|
8.6
|
|
|
—
|
|
|
1.4
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
||||||
Other services—related parties
|
—
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
||||||
Midstream services—related parties
|
8.6
|
|
|
212.8
|
|
|
120.0
|
|
|
—
|
|
|
—
|
|
|
341.4
|
|
||||||
Revenue from contracts with customers
|
1,406.7
|
|
|
319.8
|
|
|
598.0
|
|
|
1,694.1
|
|
|
(477.5
|
)
|
|
3,541.1
|
|
||||||
Cost of sales
|
(1,308.0
|
)
|
|
(81.9
|
)
|
|
(309.4
|
)
|
|
(1,485.3
|
)
|
|
477.5
|
|
|
(2,707.1
|
)
|
||||||
Operating expenses
|
(48.5
|
)
|
|
(56.8
|
)
|
|
(41.5
|
)
|
|
(75.8
|
)
|
|
—
|
|
|
(222.6
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(14.7
|
)
|
|
(14.7
|
)
|
||||||
Segment profit
|
$
|
50.2
|
|
|
$
|
181.1
|
|
|
$
|
247.1
|
|
|
$
|
133.0
|
|
|
$
|
(14.7
|
)
|
|
$
|
596.7
|
|
Depreciation and amortization
|
$
|
(54.1
|
)
|
|
$
|
(62.9
|
)
|
|
$
|
(88.5
|
)
|
|
$
|
(73.3
|
)
|
|
$
|
(4.6
|
)
|
|
$
|
(283.4
|
)
|
Goodwill
|
$
|
29.3
|
|
|
$
|
202.7
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
116.4
|
|
|
$
|
8.0
|
|
|
$
|
243.9
|
|
|
$
|
28.8
|
|
|
$
|
2.3
|
|
|
$
|
399.4
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Segment profit
|
$
|
292.0
|
|
|
$
|
325.7
|
|
|
$
|
593.3
|
|
|
$
|
596.7
|
|
General and administrative expenses
|
(31.9
|
)
|
|
(29.1
|
)
|
|
(70.5
|
)
|
|
(55.3
|
)
|
||||
Loss on disposition of assets
|
(0.1
|
)
|
|
(1.2
|
)
|
|
(0.1
|
)
|
|
(1.3
|
)
|
||||
Depreciation and amortization
|
(153.7
|
)
|
|
(145.3
|
)
|
|
(305.8
|
)
|
|
(283.4
|
)
|
||||
Loss on secured term loan receivable
|
(52.9
|
)
|
|
—
|
|
|
(52.9
|
)
|
|
—
|
|
||||
Operating income
|
$
|
53.4
|
|
|
$
|
150.1
|
|
|
$
|
164.0
|
|
|
$
|
256.7
|
|
Segment Identifiable Assets:
|
|
June 30, 2019
|
|
December 31, 2018
|
||||
Permian
|
|
$
|
2,201.5
|
|
|
$
|
2,096.8
|
|
North Texas
|
|
1,221.0
|
|
|
1,308.2
|
|
||
Oklahoma
|
|
3,258.6
|
|
|
3,209.5
|
|
||
Louisiana
|
|
2,575.1
|
|
|
2,734.5
|
|
||
Corporate
|
|
167.9
|
|
|
222.3
|
|
||
Total identifiable assets
|
|
$
|
9,424.1
|
|
|
$
|
9,571.3
|
|
Natural gas and NGLs inventory, prepaid expenses, and other:
|
|
June 30, 2019
|
|
December 31, 2018
|
||||
Natural gas and NGLs inventory
|
|
$
|
51.5
|
|
|
$
|
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
|
|
20.2
|
|
|
12.1
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
|
$
|
71.7
|
|
|
$
|
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. We do not believe that it is probable that White Star will be 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:
|
|
June 30, 2019
|
|
December 31, 2018
|
||||
Accrued interest
|
|
$
|
32.6
|
|
|
$
|
37.3
|
|
Accrued wages and benefits, including taxes
|
|
18.6
|
|
|
37.2
|
|
||
Accrued ad valorem taxes
|
|
25.8
|
|
|
28.1
|
|
||
Capital expenditure accruals
|
|
44.9
|
|
|
50.6
|
|
||
Onerous performance obligations
|
|
—
|
|
|
9.0
|
|
||
Short-term lease liability
|
|
22.1
|
|
|
1.5
|
|
||
Suspense producer payments
|
|
15.4
|
|
|
34.6
|
|
||
Deferred revenue
|
|
48.6
|
|
|
6.6
|
|
||
Other
|
|
26.5
|
|
|
41.8
|
|
||
Other current liabilities
|
|
$
|
234.5
|
|
|
$
|
246.7
|
|
•
|
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.
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Operating income
|
|
$
|
53.4
|
|
|
$
|
150.1
|
|
|
$
|
164.0
|
|
|
$
|
256.7
|
|
|
|
|
|
|
|
|
|
|
||||||||
Add:
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses
|
|
117.9
|
|
|
113.4
|
|
|
232.4
|
|
|
222.6
|
|
||||
General and administrative expenses
|
|
31.9
|
|
|
29.1
|
|
|
70.5
|
|
|
55.3
|
|
||||
Loss on disposition of assets
|
|
0.1
|
|
|
1.2
|
|
|
0.1
|
|
|
1.3
|
|
||||
Depreciation and amortization
|
|
153.7
|
|
|
145.3
|
|
|
305.8
|
|
|
283.4
|
|
||||
Loss on secured term loan receivable
|
|
52.9
|
|
|
—
|
|
|
52.9
|
|
|
—
|
|
||||
Gross operating margin
|
|
$
|
409.9
|
|
|
$
|
439.1
|
|
|
$
|
825.7
|
|
|
$
|
819.3
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Permian Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
742.3
|
|
|
$
|
689.9
|
|
|
$
|
1,484.9
|
|
|
$
|
1,406.7
|
|
Cost of sales
|
(680.5
|
)
|
|
(633.9
|
)
|
|
(1,356.7
|
)
|
|
(1,308.0
|
)
|
||||
Total gross operating margin
|
$
|
61.8
|
|
|
$
|
56.0
|
|
|
$
|
128.2
|
|
|
$
|
98.7
|
|
North Texas Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
149.8
|
|
|
$
|
152.8
|
|
|
$
|
324.1
|
|
|
$
|
319.8
|
|
Cost of sales
|
(51.0
|
)
|
|
(32.0
|
)
|
|
(124.7
|
)
|
|
(81.9
|
)
|
||||
Total gross operating margin
|
$
|
98.8
|
|
|
$
|
120.8
|
|
|
$
|
199.4
|
|
|
$
|
237.9
|
|
Oklahoma Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
299.2
|
|
|
$
|
342.6
|
|
|
$
|
618.9
|
|
|
$
|
598.0
|
|
Cost of sales
|
(159.4
|
)
|
|
(170.1
|
)
|
|
(343.6
|
)
|
|
(309.4
|
)
|
||||
Total gross operating margin
|
$
|
139.8
|
|
|
$
|
172.5
|
|
|
$
|
275.3
|
|
|
$
|
288.6
|
|
Louisiana Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
730.5
|
|
|
$
|
874.2
|
|
|
$
|
1,528.6
|
|
|
$
|
1,694.1
|
|
Cost of sales
|
(627.9
|
)
|
|
(769.2
|
)
|
|
(1,314.5
|
)
|
|
(1,485.3
|
)
|
||||
Total gross operating margin
|
$
|
102.6
|
|
|
$
|
105.0
|
|
|
$
|
214.1
|
|
|
$
|
208.8
|
|
Corporate Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
(211.8
|
)
|
|
$
|
(294.8
|
)
|
|
$
|
(467.3
|
)
|
|
$
|
(492.2
|
)
|
Cost of sales
|
218.7
|
|
|
279.6
|
|
|
476.0
|
|
|
477.5
|
|
||||
Total gross operating margin
|
$
|
6.9
|
|
|
$
|
(15.2
|
)
|
|
$
|
8.7
|
|
|
$
|
(14.7
|
)
|
Total
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
1,710.0
|
|
|
$
|
1,764.7
|
|
|
$
|
3,489.2
|
|
|
$
|
3,526.4
|
|
Cost of sales
|
(1,300.1
|
)
|
|
(1,325.6
|
)
|
|
(2,663.5
|
)
|
|
(2,707.1
|
)
|
||||
Total gross operating margin
|
$
|
409.9
|
|
|
$
|
439.1
|
|
|
$
|
825.7
|
|
|
$
|
819.3
|
|
|
|
|
|
|
|
|
|
||||||||
Midstream Volumes:
|
|
|
|
|
|
|
|
||||||||
Permian Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
676,000
|
|
|
511,300
|
|
|
666,800
|
|
|
467,900
|
|
||||
Processing (MMBtu/d)
|
724,100
|
|
|
529,100
|
|
|
718,100
|
|
|
485,800
|
|
||||
Crude Oil Handling (Bbls/d)
|
145,100
|
|
|
119,700
|
|
|
146,200
|
|
|
113,800
|
|
||||
North Texas Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
1,646,900
|
|
|
1,747,000
|
|
|
1,664,900
|
|
|
1,756,800
|
|
||||
Processing (MMBtu/d)
|
770,100
|
|
|
754,000
|
|
|
750,100
|
|
|
753,100
|
|
||||
Oklahoma Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
1,314,900
|
|
|
1,235,500
|
|
|
1,279,800
|
|
|
1,142,200
|
|
||||
Processing (MMBtu/d)
|
1,298,800
|
|
|
1,200,700
|
|
|
1,265,400
|
|
|
1,135,400
|
|
||||
Crude Oil Handling (Bbls/d)
|
53,800
|
|
|
13,000
|
|
|
41,600
|
|
|
10,600
|
|
||||
Louisiana Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
1,925,900
|
|
|
2,094,100
|
|
|
1,997,800
|
|
|
2,158,100
|
|
||||
Processing (MMBtu/d)
|
337,100
|
|
|
395,600
|
|
|
402,200
|
|
|
418,600
|
|
||||
Crude Oil Handling (Bbls/d)
|
20,000
|
|
|
15,700
|
|
|
17,500
|
|
|
13,600
|
|
||||
NGL Fractionation (Gals/d)
|
7,477,400
|
|
|
6,480,100
|
|
|
7,227,000
|
|
|
6,412,200
|
|
||||
Brine Disposal (Bbls/d)
|
3,400
|
|
|
3,500
|
|
|
3,400
|
|
|
3,200
|
|
•
|
Permian Segment.
Gross operating margin in the Permian segment
increased
$5.8 million
, which was primarily due to an $8.7 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $6.1 million from our Delaware Basin assets and $2.6 million from our Midland Basin assets. These increases were partially offset by a $2.9 million decrease from our Permian Basin crude assets, which was primarily driven by higher gathering and transportation volumes contributing $2.9 million of incremental gross operating margin that was offset by a $5.6 million decrease in gross operating margin associated with our physical crude marketing arrangements. We manage our exposure to crude price fluctuations in our physical crude marketing arrangements through various derivative arrangements. 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
$22.0 million
primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets. Shortfall revenue from the Devon-related MVCs was $20.8 million for the three months ended June 30, 2018.
|
•
|
Oklahoma Segment.
Gross operating margin in the Oklahoma segment
decreased
$32.7 million
, which was primarily due to the recognition of $45.5 million in gross operating margin from a contract restructuring with White Star during the three months ended June 30, 2018, which was partially offset by $12.8 million due to higher volumes from continued development by our customers, including $6.6 million contributed by our Oklahoma gas assets and $6.2 million contributed by our Oklahoma crude assets.
|
•
|
Louisiana Segment.
Gross operating margin in the Louisiana segment
decreased
$2.4 million
. Gross operating margin from our NGL transmission and fractionation assets increased by $7.8 million, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019. The increase was offset by a $10.5 million decrease from our Louisiana gas business. Gross operating margin from our Louisiana gas transmission assets decreased $6.4 million due to the expiration of certain firm transportation contracts, decreased volumes, and negative market adjustment on gas inventory due to price declines. Gross operating margin from our Louisiana gas plants decreased $4.1 million due to lower processing margins and volumes attributable to a less favorable processing environment during the three months ended June 30, 2019.
|
•
|
Corporate Segment.
Gross operating margin in the Corporate segment
increased
$22.1 million
, which was primarily due to the changes in fair value of our commodity swaps between the periods.
For the three months ended
June 30, 2019
,
realized losses
of
$0.3 million
were offset by
unrealized gains
of
$7.2 million
. For the three months ended
June 30, 2018
, there were
realized losses
of
$4.7 million
in addition to
unrealized losses
of
$10.5 million
.
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Total
|
||||||||
Three Months Ended
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2019
|
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
|
$
|
3.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.9
|
|
Total
|
|
$
|
3.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.9
|
|
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2018
|
|
|
|
|
|
|
|
|
||||||||
Midstream services (1)
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
47.7
|
|
|
$
|
47.8
|
|
Midstream services—related parties
|
|
2.3
|
|
|
20.8
|
|
|
—
|
|
|
23.1
|
|
||||
Total
|
|
$
|
2.3
|
|
|
$
|
20.9
|
|
|
$
|
47.7
|
|
|
$
|
70.9
|
|
(1)
|
We restructured a natural gas gathering and processing contract with White Star that contained MVCs. As a result, we recognized
$45.5 million
of midstream services revenue in the Oklahoma segment for the
three
months ended
June 30, 2018
.
|
|
|
Change
|
||||||||||||
|
2019
|
|
2018
|
|
$
|
|
%
|
|||||||
Permian Segment
|
$
|
28.4
|
|
|
$
|
24.7
|
|
|
$
|
3.7
|
|
|
15.0
|
%
|
North Texas Segment
|
25.8
|
|
|
28.4
|
|
|
(2.6
|
)
|
|
(9.2
|
)%
|
|||
Oklahoma Segment
|
26.1
|
|
|
20.8
|
|
|
5.3
|
|
|
25.5
|
%
|
|||
Louisiana Segment
|
37.6
|
|
|
39.5
|
|
|
(1.9
|
)
|
|
(4.8
|
)%
|
|||
Total
|
$
|
117.9
|
|
|
$
|
113.4
|
|
|
$
|
4.5
|
|
|
4.0
|
%
|
•
|
Permian Segment.
Operating expenses in the Permian segment
increased
$3.7 million
primarily due to expanded operations with increases in utilities, materials and supplies expenses, and construction fees and services.
|
•
|
North Texas Segment.
Operating expenses in the North Texas segment
decreased
$2.6 million
primarily due to decreased rents, compressor overhauls, labor and benefits costs, and materials and supplies expenses.
|
•
|
Oklahoma Segment.
Operating expenses in the Oklahoma segment
increased
$5.3 million
primarily due to expanded operations with increases in compressor rentals and compression operations and maintenance.
|
•
|
Louisiana Segment.
Operating expenses in the Louisiana segment
decreased
$1.9 million
primarily due to reduced materials and supplies expenses, labor and benefits costs, and compression rental offset partially by increased utility costs.
|
|
Three Months Ended
June 30, |
||||||
|
2019
|
|
2018
|
||||
Senior Notes
|
$
|
37.3
|
|
|
$
|
40.0
|
|
ENLK Credit Facility
|
—
|
|
|
4.9
|
|
||
Intercompany debt
|
18.3
|
|
|
—
|
|
||
Capitalized interest
|
(1.8
|
)
|
|
(1.5
|
)
|
||
Amortization of debt issue costs and net discounts (premiums)
|
1.0
|
|
|
0.9
|
|
||
Other
|
(0.5
|
)
|
|
(0.6
|
)
|
||
Total
|
$
|
54.3
|
|
|
$
|
43.7
|
|
•
|
Permian Segment.
Gross operating margin in the Permian segment
increased
$29.5 million
, which was primarily due to a $25.4 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $15.0 million from our Delaware Basin assets, and $10.4 million from our Midland Basin assets. The remaining increase of $4.3 million was from our Permian Basin crude assets due to a $9.1 million increase in gross operating margin from higher gathering and transportation volumes, which was partially offset by a $4.8 million decrease in gross operating margin associated with our physical crude marketing arrangements.
|
•
|
North Texas Segment.
Gross operating margin in the North Texas segment
decreased
$38.5 million
, which was primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets. Shortfall revenue from the Devon-related MVCs was $38.9 million for the six months ended June 30, 2018.
|
•
|
Oklahoma Segment.
Gross operating margin in the Oklahoma segment
decreased
$13.3 million
, which was primarily due to recognition of $45.5 million in gross operating margin from a contract restructuring with White Star during the three months ended June 30, 2018, which was partially offset by $32.2 million primarily due to higher volumes from continued development by our customers with $21.9 million contributed by our Oklahoma gas assets and $10.3 million contributed by our Oklahoma crude assets.
|
•
|
Louisiana Segment.
Gross operating margin in the Louisiana segment
increased
$5.3 million
. Gross operating margin from our NGL assets increased by $8.1 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 $3.7 million primarily due to higher volumes. These increases were partially offset by a decrease of $6.7 million from our Louisiana gas business, primarily due to a $4.8 million decrease from our Louisiana gas plants, due to a less favorable processing environment during the six months ended June 30, 2019.
|
•
|
Corporate Segment.
Gross operating margin in the Corporate segment
increased
$23.4 million
, which was primarily due to the changes in fair value of our commodity swaps between the periods. For the
six
months ended
June 30, 2019
, there were
realized gains
of
$3.5 million
in addition to
unrealized gains
of
$5.2 million
. For the
six
months ended
June 30, 2018
, there were
realized losses
of
$0.7 million
in addition to
unrealized losses
of
$14.0 million
.
|
|
|
Permian
|
|
North Texas
|
|
Oklahoma
|
|
Total
|
||||||||
Six Months Ended
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2019
|
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
|
$
|
7.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7.7
|
|
Total
|
|
$
|
7.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7.7
|
|
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2018
|
|
|
|
|
|
|
|
|
||||||||
Midstream Services (1)
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
52.7
|
|
|
$
|
52.8
|
|
Midstream services—related parties
|
|
5.7
|
|
|
38.9
|
|
|
1.2
|
|
|
45.8
|
|
||||
Total
|
|
$
|
5.7
|
|
|
$
|
39.0
|
|
|
$
|
53.9
|
|
|
$
|
98.6
|
|
(1)
|
We restructured a natural gas gathering and processing contract with White Star that contained MVCs. As a result, we recognized
$45.5 million
of midstream services revenue in the Oklahoma segment for the
six
months ended
June 30, 2018
.
|
•
|
Permian Segment.
Operating expenses in the Permian segment
increased
$7.7 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
$5.3 million
primarily due to decreased rents, compressor overhauls, and labor and benefits costs.
|
•
|
Oklahoma Segment.
Operating expenses in the Oklahoma segment
increased
$10.0 million
primarily due to expanded operations with increases in compressor rentals, compression operations and maintenance, and labor and benefits costs.
|
•
|
Louisiana Segment.
Operating expenses in the Louisiana segment
decreased
$2.6 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.
|
•
|
Unit-based compensation expense increased
$6.2 million
primarily due to increased bonus expense and lower forfeiture of units in 2019.
|
•
|
Transaction costs increased
$2.6 million
primarily due to additional costs incurred related to the Merger, which closed during the first quarter of 2019.
|
•
|
Fees and services expense increased
$1.9 million
primarily due to increased software consulting and legal fees.
|
|
Six Months Ended
June 30, |
||||||
|
2019
|
|
2018
|
||||
Senior Notes
|
$
|
77.3
|
|
|
$
|
80.0
|
|
ENLK Credit Facility
|
0.3
|
|
|
8.3
|
|
||
Intercompany debt
|
29.3
|
|
|
—
|
|
||
Capitalized interest
|
(3.8
|
)
|
|
(2.8
|
)
|
||
Amortization of debt issue costs and net discounts (premiums)
|
2.8
|
|
|
2.4
|
|
||
Other
|
(2.3
|
)
|
|
(0.5
|
)
|
||
Total
|
$
|
103.6
|
|
|
$
|
87.4
|
|
|
Six Months Ended June 30,
|
||||||
|
2019
|
|
2018
|
||||
Operating cash flows before working capital
|
$
|
442.7
|
|
|
$
|
448.4
|
|
Changes in working capital
|
72.9
|
|
|
(17.7
|
)
|
•
|
General and administrative expenses excluding unit-based compensation increased
$8.9 million
primarily due to higher transaction costs related to the Merger. For more information, see “Results of Operations.”
|
•
|
Operating expenses excluding unit-based compensation increased
$11.7 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
$18.0 million
.
|
|
Six Months Ended June 30,
|
||||||
|
2019
|
|
2018
|
||||
Growth capital expenditures
|
$
|
(406.7
|
)
|
|
$
|
(385.9
|
)
|
Maintenance capital expenditures
|
(21.7
|
)
|
|
(18.5
|
)
|
|
Six Months Ended June 30,
|
||||||
|
2019
|
|
2018
|
||||
Net borrowings on the ENLK Credit Facility
|
$
|
—
|
|
|
$
|
520.0
|
|
Net borrowings on intercompany debt
|
588.5
|
|
|
—
|
|
||
Net repayments on the 2019 unsecured senior notes
|
(400.0
|
)
|
|
—
|
|
||
Contributions by non-controlling interests
|
45.2
|
|
|
81.6
|
|
||
Payment of installment payable for EOGP acquisition
|
—
|
|
|
(250.0
|
)
|
||
Distributions to common units
|
(276.6
|
)
|
|
(275.0
|
)
|
||
Distributions to general partner interest (including incentive distribution rights)
|
(15.6
|
)
|
|
(30.9
|
)
|
||
Distributions to non-controlling interests
|
(12.7
|
)
|
|
(23.4
|
)
|
||
Distributions to Series B Preferred Units
|
(33.2
|
)
|
|
(32.2
|
)
|
||
Distributions to Series C Preferred Units
|
(12.0
|
)
|
|
(12.0
|
)
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
Remainder 2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||||
Long-term debt obligations
|
$
|
3,100.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,100.0
|
|
Intercompany debt (1)
|
1,438.5
|
|
|
—
|
|
|
—
|
|
|
850.0
|
|
|
—
|
|
|
—
|
|
|
588.5
|
|
|||||||
Interest payable on fixed long-term debt obligations
|
2,604.5
|
|
|
90.3
|
|
|
176.0
|
|
|
176.0
|
|
|
176.0
|
|
|
176.0
|
|
|
1,810.2
|
|
|||||||
Capital lease obligations
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Operating lease obligations
|
146.5
|
|
|
13.5
|
|
|
22.4
|
|
|
16.1
|
|
|
9.4
|
|
|
8.9
|
|
|
76.2
|
|
|||||||
Purchase obligations
|
31.7
|
|
|
31.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Pipeline capacity and deficiency agreements (2)
|
205.0
|
|
|
18.6
|
|
|
36.6
|
|
|
36.5
|
|
|
31.0
|
|
|
28.1
|
|
|
54.2
|
|
|||||||
Inactive easement commitment (3)
|
10.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
|
—
|
|
|
—
|
|
|||||||
Total contractual obligations
|
$
|
7,536.6
|
|
|
$
|
154.5
|
|
|
$
|
235.0
|
|
|
$
|
1,078.6
|
|
|
$
|
226.4
|
|
|
$
|
213.0
|
|
|
$
|
5,629.1
|
|
(1)
|
Intercompany debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through an intercompany arrangement with ENLC. Interest charged to ENLK for borrowings made through the intercompany arrangement will be the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes.
|
(2)
|
Consists of pipeline capacity payments for firm transportation and deficiency agreements.
|
(3)
|
Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.
|
1.
|
Fee-based contracts
: Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of volume processed or (2) arrangements where we purchase and resell commodities in connection with providing the related processing service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities.
|
2.
|
Processing margin contracts:
Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the
six
months ended
June 30, 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)
|
|
Fair Value
Asset/(Liability)
(In millions)
|
||
July 2019 - March 2020
|
|
Ethane
|
|
357 (MBbls)
|
|
$0.2098/gal
|
|
Index
|
|
$
|
(0.6
|
)
|
July 2019 - March 2020
|
|
Propane
|
|
522 (MBbls)
|
|
Index
|
|
$0.5229/gal
|
|
2.6
|
|
|
July 2019 - September 2019
|
|
Normal butane
|
|
16 (MBbls)
|
|
Index
|
|
$0.5591/gal
|
|
0.3
|
|
|
July 2019 - September 2019
|
|
Natural gasoline
|
|
40 (MBbls)
|
|
Index
|
|
$1.1165/gal
|
|
0.1
|
|
|
July 2019 - October 2019
|
|
Natural gas
|
|
24,036 (MMBtu/d)
|
|
Index
|
|
$2.1606/MMBtu
|
|
—
|
|
|
July 2019 - December 2022
|
|
Crude and condensate
|
|
13,129 (MBbls)
|
|
Index
|
|
$57.62/bbl
|
|
11.3
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
13.7
|
|
(1)
|
Weighted average.
|
Number
|
|
Description
|
2.1
|
—
|
|
3.1
|
—
|
|
3.2
|
—
|
|
3.3
|
—
|
|
3.4
|
—
|
|
3.5
|
—
|
|
3.6
|
—
|
|
3.7
|
—
|
|
3.8
|
—
|
|
4.1
|
—
|
|
4.2
|
—
|
|
31.1 *
|
—
|
|
31.2 *
|
—
|
|
32.1 *
|
—
|
|
101 *
|
—
|
The following financial information from EnLink Midstream Partners, LP's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in inline XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018, (ii) Consolidated Statements of Operations for the three and six months ended June 30, 2019 and 2018, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended June 30, 2019 and 2018 and March 31, 2019 and 2018, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018, and (v) the Notes to Consolidated Financial Statements.
|
104 *
|
—
|
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
|
*
|
Filed herewith.
|
|
EnLink Midstream Partners, LP
|
|
|
|
|
|
By:
|
EnLink Midstream GP, LLC,
|
|
|
its general partner
|
|
|
|
|
By:
|
/s/ ERIC D. BATCHELDER
|
|
|
Eric D. Batchelder
|
|
|
Executive Vice President and Chief Financial Officer
|
|
|
|
August 7, 2019
|
|
|
1 Year EnLink Midstream Partners, LP Chart |
1 Month EnLink Midstream Partners, LP Chart |
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