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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, 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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Large accelerated filer
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ý
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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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(Do not check if a smaller reporting company)
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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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Page
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Defined Term
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Definition
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/d
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Per day.
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2017 EDA
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Equity Distribution Agreement entered into by ENLK in August 2017 with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc., and Wells Fargo Securities, LLC to sell up to $600.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program.
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AMZ
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Alerian MLP Index for Master Limited Partnerships.
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ASC
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The FASB Accounting Standards Codification.
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ASC 606
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ASC 606,
Revenue from Contracts with Customers.
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ASU
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The FASB Accounting Standards Update.
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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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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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Devon
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Devon Energy Corporation.
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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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ENLC
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EnLink Midstream, LLC.
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ENLK
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EnLink Midstream Partners, LP or EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
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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. EOGP is a partnership in which ENLK and ENLC hold an approximate 84% and 16% interest, respectively.
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FASB
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Financial Accounting Standards Board.
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FERC
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Federal Energy Regulatory Commission.
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GAAP
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Generally accepted accounting principles in the United States of America.
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Gal
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Gallons.
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GCF
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Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
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GIP
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Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, or its affiliates, including GIP III Stetson I, L.P. and GIP III Stetson II, L.P.
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Greater Chickadee
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Crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin.
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Gross Operating Margin
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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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HEP
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Howard Energy Partners. ENLK sold its 31% ownership interest in HEP in March 2017.
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ISDAs
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International Swaps and Derivatives Association Agreements.
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Mcf
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Thousand cubic feet.
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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, an affiliate of ENLK’s joint venture partner in the Delaware Basin JV.
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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.
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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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Series B Cumulative Convertible Preferred Units.
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Series C Preferred Units
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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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VEX
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ENLK’s Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas.
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June 30, 2018
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December 31, 2017
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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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36.5
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$
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30.8
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Accounts receivable:
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Trade, net of allowance for bad debt of $0.3 and $0.3, respectively
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73.2
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50.1
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Accrued revenue and other
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579.4
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576.6
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Related party
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122.7
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102.7
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Fair value of derivative assets
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4.0
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6.8
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Natural gas and NGLs inventory, prepaid expenses, and other
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97.6
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39.7
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Total current assets
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913.4
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806.7
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Property and equipment, net of accumulated depreciation of $2,745.8 and $2,533.0, respectively
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6,763.2
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6,587.0
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Intangible assets, net of accumulated amortization of $360.4 and $298.7, respectively
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1,435.4
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1,497.1
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Goodwill
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422.3
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422.3
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Investment in unconsolidated affiliates
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85.5
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89.4
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Other assets, net
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40.3
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11.5
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Total assets
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$
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9,660.1
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$
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9,414.0
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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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115.2
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$
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66.9
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Accounts payable to related party
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30.5
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18.4
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Accrued gas, NGLs, condensate, and crude oil purchases
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509.2
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476.1
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Fair value of derivative liabilities
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10.7
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8.4
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Installment payable, net of discount of $0.5 at December 31, 2017
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—
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249.5
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Current maturities of long-term debt
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399.4
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—
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Other current liabilities
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205.3
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222.4
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Total current liabilities
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1,270.3
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1,041.7
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Long-term debt
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3,590.2
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3,467.8
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Asset retirement obligations
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14.5
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14.2
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Other long-term liabilities
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21.2
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33.9
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Deferred tax liability
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44.5
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46.3
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Fair value of derivative liabilities
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8.9
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—
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Redeemable non-controlling interest
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4.6
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4.6
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Partners’ equity:
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Common unitholders (350,257,779 and 349,702,372 units issued and outstanding, respectively)
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2,603.0
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2,791.6
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Series B preferred unitholders (57,886,596 and 57,056,281 units issued and outstanding, respectively)
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876.6
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864.1
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Series C preferred unitholders (400,000 units outstanding)
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395.1
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395.1
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General partner interest (1,594,974 equivalent units outstanding)
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206.6
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207.3
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Accumulated other comprehensive loss
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(2.1
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)
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(2.1
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)
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Non-controlling interest
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626.7
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549.5
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Total partners’ equity
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4,705.9
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4,805.5
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Total liabilities and partners’ equity
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$
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9,660.1
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$
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9,414.0
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Three Months Ended
June 30, |
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Six Months Ended
June 30, |
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2018
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2017
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2018
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2017
|
||||||||
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(Unaudited)
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||||||||||||||
Revenues:
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||||||||
Product sales
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$
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1,435.1
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$
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927.2
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$
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2,934.3
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$
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1,917.2
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Product sales—related parties
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27.2
|
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29.3
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30.8
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72.0
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||||
Midstream services
|
142.4
|
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131.9
|
|
|
234.6
|
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259.3
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|
||||
Midstream services—related parties
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175.2
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173.6
|
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341.4
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332.6
|
|
||||
Gain (loss) on derivative activity
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(15.2
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)
|
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1.6
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(14.7
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)
|
|
4.4
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|
||||
Total revenues
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1,764.7
|
|
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1,263.6
|
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3,526.4
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2,585.5
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|
||||
Operating costs and expenses:
|
|
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|
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|
||||||||
Cost of sales (1)
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1,325.6
|
|
|
932.4
|
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2,707.1
|
|
|
1,934.7
|
|
||||
Operating expenses
|
113.4
|
|
|
102.6
|
|
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222.6
|
|
|
206.7
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|
||||
General and administrative
|
29.1
|
|
|
29.6
|
|
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55.3
|
|
|
64.6
|
|
||||
(Gain) loss on disposition of assets
|
1.2
|
|
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(5.4
|
)
|
|
1.3
|
|
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(0.3
|
)
|
||||
Depreciation and amortization
|
145.3
|
|
|
142.5
|
|
|
283.4
|
|
|
270.8
|
|
||||
Impairments
|
—
|
|
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—
|
|
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—
|
|
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7.0
|
|
||||
Gain on litigation settlement
|
—
|
|
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(8.5
|
)
|
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—
|
|
|
(26.0
|
)
|
||||
Total operating costs and expenses
|
1,614.6
|
|
|
1,193.2
|
|
|
3,269.7
|
|
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2,457.5
|
|
||||
Operating income
|
150.1
|
|
|
70.4
|
|
|
256.7
|
|
|
128.0
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense, net of interest income
|
(43.7
|
)
|
|
(47.1
|
)
|
|
(87.4
|
)
|
|
(91.6
|
)
|
||||
Gain on extinguishment of debt
|
—
|
|
|
9.0
|
|
|
—
|
|
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9.0
|
|
||||
Income (loss) from unconsolidated affiliates
|
4.4
|
|
|
(0.1
|
)
|
|
7.4
|
|
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0.6
|
|
||||
Other income
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—
|
|
|
0.2
|
|
|
0.2
|
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0.2
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|
||||
Total other expense
|
(39.3
|
)
|
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(38.0
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)
|
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(79.8
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)
|
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(81.8
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)
|
||||
Income before non-controlling interest and income taxes
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110.8
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32.4
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|
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176.9
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46.2
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|
||||
Income tax benefit (provision)
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2.1
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|
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0.3
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1.1
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(0.2
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)
|
||||
Net income
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112.9
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|
|
32.7
|
|
|
178.0
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46.0
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|
||||
Net income (loss) attributable to non-controlling interest
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14.0
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3.1
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19.0
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(1.7
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)
|
||||
Net income attributable to ENLK
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$
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98.9
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$
|
29.6
|
|
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$
|
159.0
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$
|
47.7
|
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General partner interest in net income
|
$
|
11.2
|
|
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$
|
10.8
|
|
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$
|
21.8
|
|
|
$
|
16.7
|
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Limited partners’ interest in net income (loss) attributable to ENLK
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$
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58.9
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|
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$
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(0.5
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)
|
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$
|
80.5
|
|
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$
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(9.8
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)
|
Series B preferred interest in net income attributable to ENLK
|
$
|
22.8
|
|
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$
|
19.3
|
|
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$
|
44.7
|
|
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$
|
40.8
|
|
Series C preferred interest in net income attributable to ENLK
|
$
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6.0
|
|
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$
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—
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$
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12.0
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|
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$
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—
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|
Net income (loss) attributable to ENLK per limited partners’ unit:
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||||||||
Basic common unit
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$
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0.17
|
|
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$
|
—
|
|
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$
|
0.23
|
|
|
$
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(0.03
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)
|
Diluted common unit
|
$
|
0.17
|
|
|
$
|
—
|
|
|
$
|
0.23
|
|
|
$
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(0.03
|
)
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(1)
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Includes related party cost of sales of
$46.7 million
and
$50.9 million
for the
three months ended
June 30, 2018
and
2017
, respectively
, and
$80.8 million
and
$79.6 million
for the
six months ended
June 30, 2018
and
2017
, respectively
.
|
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Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
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2017
|
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2018
|
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2017
|
||||||||
|
(Unaudited)
|
||||||||||||||
Net income
|
$
|
112.9
|
|
|
$
|
32.7
|
|
|
$
|
178.0
|
|
|
$
|
46.0
|
|
Loss on designated cash flow hedge
|
—
|
|
|
(2.2
|
)
|
|
—
|
|
|
(2.2
|
)
|
||||
Comprehensive income
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112.9
|
|
|
30.5
|
|
|
178.0
|
|
|
43.8
|
|
||||
Comprehensive income (loss) attributable to non-controlling interest
|
14.0
|
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|
3.1
|
|
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19.0
|
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(1.7
|
)
|
||||
Comprehensive income attributable to EnLink Midstream Partners, LP
|
$
|
98.9
|
|
|
$
|
27.4
|
|
|
$
|
159.0
|
|
|
$
|
45.5
|
|
|
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
|
$
|
2,791.6
|
|
|
349.7
|
|
|
$
|
864.1
|
|
|
57.1
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
207.3
|
|
|
1.6
|
|
|
$
|
(2.1
|
)
|
|
$
|
549.5
|
|
|
$
|
4,805.5
|
|
|
$
|
4.6
|
|
Issuance of common units
|
0.9
|
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.9
|
|
|
—
|
|
||||||||
Conversion of restricted units for common units, net of units withheld for taxes
|
(3.4
|
)
|
|
0.5
|
|
|
—
|
|
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—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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(3.4
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|
|
—
|
|
||||||||
Unit-based compensation
|
8.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16.8
|
|
|
—
|
|
||||||||
Distributions
|
(275.0
|
)
|
|
—
|
|
|
(32.2
|
)
|
|
0.8
|
|
|
(12.0
|
)
|
|
—
|
|
|
(30.9
|
)
|
|
—
|
|
|
—
|
|
|
(23.4
|
)
|
|
(373.5
|
)
|
|
—
|
|
||||||||
Contributions from non-controlling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
81.6
|
|
|
81.6
|
|
|
—
|
|
||||||||
Net income
|
80.5
|
|
|
—
|
|
|
44.7
|
|
|
—
|
|
|
12.0
|
|
|
—
|
|
|
21.8
|
|
|
—
|
|
|
—
|
|
|
19.0
|
|
|
178.0
|
|
|
—
|
|
||||||||
Balance, June 30, 2018
|
$
|
2,603.0
|
|
|
350.3
|
|
|
$
|
876.6
|
|
|
57.9
|
|
|
$
|
395.1
|
|
|
0.4
|
|
|
$
|
206.6
|
|
|
1.6
|
|
|
$
|
(2.1
|
)
|
|
$
|
626.7
|
|
|
$
|
4,705.9
|
|
|
$
|
4.6
|
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
|
(Unaudited)
|
||||||
Cash flows from operating activities:
|
|
|
|
||||
Net income
|
$
|
178.0
|
|
|
$
|
46.0
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Impairments
|
—
|
|
|
7.0
|
|
||
Depreciation and amortization
|
283.4
|
|
|
270.8
|
|
||
Non-cash unit-based compensation
|
14.6
|
|
|
28.6
|
|
||
(Gain) loss on derivatives recognized in net income
|
14.7
|
|
|
(4.4
|
)
|
||
Gain on extinguishment of debt
|
—
|
|
|
(9.0
|
)
|
||
Cash settlements on derivatives
|
(0.4
|
)
|
|
(6.0
|
)
|
||
Amortization of debt issue costs, net discount (premium) of notes and installment payable
|
2.4
|
|
|
14.2
|
|
||
Distribution of earnings from unconsolidated affiliates
|
9.5
|
|
|
—
|
|
||
Income from unconsolidated affiliates
|
(7.4
|
)
|
|
(0.6
|
)
|
||
Non-cash revenue from contract restructuring
|
(45.5
|
)
|
|
—
|
|
||
Other operating activities
|
(0.9
|
)
|
|
—
|
|
||
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
|
|
|
|
|
|
||
Accounts receivable, accrued revenue, and other
|
(46.6
|
)
|
|
56.1
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
(40.2
|
)
|
|
(34.1
|
)
|
||
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities
|
69.1
|
|
|
(36.4
|
)
|
||
Net cash provided by operating activities
|
430.7
|
|
|
332.2
|
|
||
Cash flows from investing activities:
|
|
|
|
||||
Additions to property and equipment
|
(404.4
|
)
|
|
(471.7
|
)
|
||
Proceeds from sale of unconsolidated affiliate investment
|
—
|
|
|
189.7
|
|
||
Investment in unconsolidated affiliates
|
(0.1
|
)
|
|
(10.3
|
)
|
||
Distribution from unconsolidated affiliates in excess of earnings
|
1.9
|
|
|
7.4
|
|
||
Other investing activities
|
0.8
|
|
|
1.3
|
|
||
Net cash used in investing activities
|
(401.8
|
)
|
|
(283.6
|
)
|
||
Cash flows from financing activities:
|
|
|
|
||||
Proceeds from borrowings
|
1,346.0
|
|
|
1,750.9
|
|
||
Payments on borrowings
|
(826.0
|
)
|
|
(1,373.3
|
)
|
||
Payment of installment payable for EOGP acquisition
|
(250.0
|
)
|
|
(250.0
|
)
|
||
Debt financing costs
|
—
|
|
|
(5.7
|
)
|
||
Proceeds from issuance of common units
|
0.9
|
|
|
72.2
|
|
||
Distributions to non-controlling interests
|
(23.4
|
)
|
|
(8.3
|
)
|
||
Contributions by non-controlling interests, including contributions from affiliates of $27.3 and $43.0, respectively
|
81.6
|
|
|
71.5
|
|
||
Distributions to Series B Preferred Units
|
(32.2
|
)
|
|
—
|
|
||
Distributions to Series C Preferred Units
|
(12.0
|
)
|
|
—
|
|
||
Distributions to common unitholders and to general partner
|
(305.9
|
)
|
|
(300.8
|
)
|
||
Other financing activities
|
(2.2
|
)
|
|
(5.5
|
)
|
||
Net cash used in financing activities
|
(23.2
|
)
|
|
(49.0
|
)
|
||
Net increase (decrease) in cash and cash
equivalents
|
5.7
|
|
|
(0.4
|
)
|
||
Cash and cash equivalents, beginning of period
|
30.8
|
|
|
11.6
|
|
||
Cash and cash equivalents, end of period
|
$
|
36.5
|
|
|
$
|
11.2
|
|
|
|
|
|
||||
Supplemental disclosures of cash flow information:
|
|
|
|
||||
Cash paid for interest
|
$
|
87.6
|
|
|
$
|
78.2
|
|
Cash paid for income taxes
|
$
|
0.4
|
|
|
$
|
3.2
|
|
Non-cash investing activities:
|
|
|
|
||||
Non-cash accrual of property and equipment
|
$
|
(5.0
|
)
|
|
$
|
(5.2
|
)
|
Discounted secured term loan receivable from contract restructuring
|
$
|
47.7
|
|
|
$
|
—
|
|
(a)
|
Organization of Business
|
(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
|
•
|
Product sales
—Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above.
|
•
|
Midstream services
—Midstream services represent all other revenue generated as a result of performing our midstream services as outlined above.
|
•
|
promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and
|
•
|
promises to sell a specified volume of commodities to our customers.
|
|
|
Increase (Decrease) in Revenue Due to
ASC 606 Adoption |
||||||
|
|
Three Months Ended June 30, 2018
|
|
Six Months Ended June 30, 2018
|
||||
Product sales
|
|
$
|
(46
|
)
|
|
$
|
(78
|
)
|
Product sales—related parties
|
|
(24
|
)
|
|
(46
|
)
|
||
Midstream services
|
|
(76
|
)
|
|
(153
|
)
|
||
Midstream services—related parties
|
|
(17
|
)
|
|
(24
|
)
|
||
Total
|
|
$
|
(163
|
)
|
|
$
|
(301
|
)
|
•
|
For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.
|
•
|
For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream service revenues over time as we satisfy our performance obligations.
|
2018 (remaining)
|
$
|
388.4
|
|
2019
|
235.8
|
|
|
2020
|
224.8
|
|
|
2021
|
82.2
|
|
|
2022
|
71.9
|
|
|
Thereafter
|
231.2
|
|
|
Total
|
$
|
1,234.3
|
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
||||||
Six Months Ended June 30, 2018
|
|
|
|
|
|
||||||
Customer relationships, beginning of period
|
$
|
1,795.8
|
|
|
$
|
(298.7
|
)
|
|
$
|
1,497.1
|
|
Amortization expense
|
—
|
|
|
(61.7
|
)
|
|
(61.7
|
)
|
|||
Customer relationships, end of period
|
$
|
1,795.8
|
|
|
$
|
(360.4
|
)
|
|
$
|
1,435.4
|
|
2018 (remaining)
|
$
|
61.8
|
|
2019
|
123.4
|
|
|
2020
|
123.4
|
|
|
2021
|
123.4
|
|
|
2022
|
123.4
|
|
|
Thereafter
|
880.0
|
|
|
Total
|
$
|
1,435.4
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Long-Term Debt
|
||||||||||||
Credit facility due 2020 (1)
|
$
|
520.0
|
|
|
$
|
—
|
|
|
$
|
520.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2.70% Senior unsecured notes due 2019 (2)
|
400.0
|
|
|
(0.1
|
)
|
|
399.9
|
|
|
400.0
|
|
|
(0.1
|
)
|
|
399.9
|
|
||||||
4.40% Senior unsecured notes due 2024
|
550.0
|
|
|
2.0
|
|
|
552.0
|
|
|
550.0
|
|
|
2.2
|
|
|
552.2
|
|
||||||
4.15% Senior unsecured notes due 2025
|
750.0
|
|
|
(0.9
|
)
|
|
749.1
|
|
|
750.0
|
|
|
(1.0
|
)
|
|
749.0
|
|
||||||
4.85% Senior unsecured notes due 2026
|
500.0
|
|
|
(0.6
|
)
|
|
499.4
|
|
|
500.0
|
|
|
(0.6
|
)
|
|
499.4
|
|
||||||
5.60% Senior unsecured notes due 2044
|
350.0
|
|
|
(0.2
|
)
|
|
349.8
|
|
|
350.0
|
|
|
(0.2
|
)
|
|
349.8
|
|
||||||
5.05% Senior unsecured notes due 2045
|
450.0
|
|
|
(6.3
|
)
|
|
443.7
|
|
|
450.0
|
|
|
(6.5
|
)
|
|
443.5
|
|
||||||
5.45% Senior unsecured notes due 2047
|
500.0
|
|
|
(0.1
|
)
|
|
499.9
|
|
|
500.0
|
|
|
(0.1
|
)
|
|
499.9
|
|
||||||
Debt classified as long-term, including current maturities of long-term debt
|
$
|
4,020.0
|
|
|
$
|
(6.2
|
)
|
|
4,013.8
|
|
|
$
|
3,500.0
|
|
|
$
|
(6.3
|
)
|
|
3,493.7
|
|
||
Debt issuance cost (3)
|
|
|
|
|
(24.2
|
)
|
|
|
|
|
|
(25.9
|
)
|
||||||||||
Less: Current maturities of long-term debt (2)
|
|
|
|
|
(399.4
|
)
|
|
|
|
|
|
—
|
|
||||||||||
Long-term debt, net of unamortized issuance cost
|
|
|
|
|
$
|
3,590.2
|
|
|
|
|
|
|
$
|
3,467.8
|
|
(1)
|
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was
3.6%
at
June 30, 2018
.
|
(2)
|
The
2.70%
senior unsecured notes mature on April 1, 2019. Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of
June 30, 2018
.
|
(3)
|
Net of amortization of
$13.7 million
and
$12.0 million
at
June 30, 2018
and
December 31, 2017
, respectively.
|
(a)
|
Issuance of Common Units
|
Declaration period
|
|
Distribution paid as additional Series B Preferred Units
|
|
Cash Distribution (in millions)
|
|
Date paid/payable
|
|||
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
|
|
|
|
|
|
|
|
|||
2017
|
|
|
|
|
|
|
|||
Fourth Quarter of 2016
|
|
1,130,131
|
|
|
$
|
—
|
|
|
February 13, 2017
|
First Quarter of 2017
|
|
1,154,147
|
|
|
$
|
—
|
|
|
May 12, 2017
|
Second Quarter of 2017
|
|
1,178,672
|
|
|
$
|
—
|
|
|
August 11, 2017
|
(c)
|
Series C Preferred Units
|
(d)
|
Common Unit Distributions
|
Declaration period
|
|
Distribution/unit
|
|
Date paid/payable
|
||
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
|
|
|
|
|
|
||
2017
|
|
|
|
|
||
Fourth Quarter of 2016
|
|
$
|
0.39
|
|
|
February 13, 2017
|
First Quarter of 2017
|
|
$
|
0.39
|
|
|
May 12, 2017
|
Second Quarter of 2017
|
|
$
|
0.39
|
|
|
August 11, 2017
|
(e)
|
Earnings Per Unit and Dilution Computations
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Limited partners’ interest in net income (loss)
|
$
|
58.9
|
|
|
$
|
(0.5
|
)
|
|
$
|
80.5
|
|
|
$
|
(9.8
|
)
|
Distributed earnings allocated to:
|
|
|
|
|
|
|
|
||||||||
Common units (1) (2)
|
$
|
136.6
|
|
|
$
|
135.3
|
|
|
$
|
273.1
|
|
|
$
|
269.3
|
|
Unvested restricted units (1) (2)
|
1.1
|
|
|
1.0
|
|
|
1.9
|
|
|
1.9
|
|
||||
Total distributed earnings
|
$
|
137.7
|
|
|
$
|
136.3
|
|
|
$
|
275.0
|
|
|
$
|
271.2
|
|
Undistributed loss allocated to:
|
|
|
|
|
|
|
|
||||||||
Common units
|
$
|
(78.1
|
)
|
|
$
|
(135.8
|
)
|
|
$
|
(193.1
|
)
|
|
$
|
(279.0
|
)
|
Unvested restricted units
|
(0.7
|
)
|
|
(1.0
|
)
|
|
(1.4
|
)
|
|
(2.0
|
)
|
||||
Total undistributed loss
|
$
|
(78.8
|
)
|
|
$
|
(136.8
|
)
|
|
$
|
(194.5
|
)
|
|
$
|
(281.0
|
)
|
Net income (loss) allocated to:
|
|
|
|
|
|
|
|
||||||||
Common units
|
$
|
58.5
|
|
|
$
|
(0.5
|
)
|
|
$
|
80.0
|
|
|
$
|
(9.7
|
)
|
Unvested restricted units
|
0.4
|
|
|
—
|
|
|
0.5
|
|
|
(0.1
|
)
|
||||
Total limited partners’ interest in net income (loss)
|
$
|
58.9
|
|
|
$
|
(0.5
|
)
|
|
$
|
80.5
|
|
|
$
|
(9.8
|
)
|
Basic and diluted net income (loss) per unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.17
|
|
|
$
|
—
|
|
|
$
|
0.23
|
|
|
$
|
(0.03
|
)
|
Diluted
|
$
|
0.17
|
|
|
$
|
—
|
|
|
$
|
0.23
|
|
|
$
|
(0.03
|
)
|
(1)
|
For the three months ended
June 30, 2018
and
2017
, distributed earnings represent a declared distribution of
$0.39
per unit payable on
August 13, 2018
and a distribution of
$0.39
per unit paid on
August 11, 2017
, respectively.
|
(2)
|
For the
six
months ended
June 30, 2018
, distributed earnings included a distribution of
$0.39
per unit paid on
May 14, 2018
and a declared distribution of
$0.39
per unit payable on
August 13, 2018
. For the
six
months ended
June 30, 2017
, distributed earnings included distributions of
$0.39
per unit paid on
May 12, 2017
and
$0.39
per unit paid on
August 11, 2017
.
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Basic weighted average units outstanding:
|
|
|
|
|
|
|
|
|
||||
Weighted average limited partner basic common units outstanding
|
|
350.2
|
|
|
346.9
|
|
|
350.2
|
|
|
345.2
|
|
|
|
|
|
|
|
|
|
|
||||
Diluted weighted average units outstanding:
|
|
|
|
|
|
|
|
|
||||
Weighted average limited partner basic common units outstanding
|
|
350.2
|
|
|
346.9
|
|
|
350.2
|
|
|
345.2
|
|
Dilutive effect of non-vested restricted units (1)
|
|
1.4
|
|
|
—
|
|
|
1.3
|
|
|
—
|
|
Total weighted average limited partner diluted common units outstanding
|
|
351.6
|
|
|
346.9
|
|
|
351.5
|
|
|
345.2
|
|
(1)
|
All common unit equivalents were antidilutive for the
three and six
months ended
June 30, 2017
because the limited partners were allocated a net loss. The Series B Preferred Units were also antidilutive for the
three and six
months ended
June 30, 2018
.
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Income allocation for incentive distributions
|
|
$
|
14.8
|
|
|
$
|
14.6
|
|
|
$
|
29.6
|
|
|
$
|
29.3
|
|
Unit-based compensation attributable to ENLC’s restricted units
|
|
(4.0
|
)
|
|
(3.9
|
)
|
|
(8.4
|
)
|
|
(12.7
|
)
|
||||
General partner share of net income
|
|
0.4
|
|
|
0.1
|
|
|
0.6
|
|
|
0.1
|
|
||||
General partner interest in net income
|
|
$
|
11.2
|
|
|
$
|
10.8
|
|
|
$
|
21.8
|
|
|
$
|
16.7
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
GCF
|
|
|
|
|
|
|
|
||||||||
Distributions
|
$
|
5.4
|
|
|
$
|
4.4
|
|
|
$
|
11.1
|
|
|
$
|
7.1
|
|
Equity in income
|
$
|
4.8
|
|
|
$
|
—
|
|
|
$
|
9.4
|
|
|
$
|
4.0
|
|
|
|
|
|
|
|
|
|
||||||||
HEP
|
|
|
|
|
|
|
|
||||||||
Equity in loss (1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3.4
|
)
|
|
|
|
|
|
|
|
|
||||||||
Cedar Cove JV
|
|
|
|
|
|
|
|
||||||||
Contributions
|
$
|
0.1
|
|
|
$
|
4.3
|
|
|
$
|
0.1
|
|
|
$
|
10.3
|
|
Distributions
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
0.3
|
|
|
$
|
0.3
|
|
Equity in loss
|
$
|
(0.4
|
)
|
|
$
|
(0.1
|
)
|
|
$
|
(2.0
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
||||||||
Contributions
|
$
|
0.1
|
|
|
$
|
4.3
|
|
|
$
|
0.1
|
|
|
$
|
10.3
|
|
Distributions
|
$
|
5.4
|
|
|
$
|
4.5
|
|
|
$
|
11.4
|
|
|
$
|
7.4
|
|
Equity in income (loss) (1)
|
$
|
4.4
|
|
|
$
|
(0.1
|
)
|
|
$
|
7.4
|
|
|
$
|
0.6
|
|
(1)
|
We sold our ownership interest in HEP during the first quarter of 2017
, resulting in a loss of
$3.4 million
for the
six
months ended
June 30, 2017
.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
GCF
|
$
|
46.7
|
|
|
$
|
48.4
|
|
Cedar Cove JV
|
38.8
|
|
|
41.0
|
|
||
Total investment in unconsolidated affiliates
|
$
|
85.5
|
|
|
$
|
89.4
|
|
(a)
|
Long-Term Incentive Plans
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Cost of unit-based compensation charged to operating expense
|
|
$
|
2.3
|
|
|
$
|
2.6
|
|
|
$
|
4.3
|
|
|
$
|
7.6
|
|
Cost of unit-based compensation charged to general and administrative expense
|
|
7.2
|
|
|
6.7
|
|
|
10.3
|
|
|
21.0
|
|
||||
Total unit-based compensation expense
|
|
$
|
9.5
|
|
|
$
|
9.3
|
|
|
$
|
14.6
|
|
|
$
|
28.6
|
|
(b)
|
EnLink Midstream Partners, LP Restricted Incentive Units
|
|
|
Six Months Ended
June 30, 2018 |
||||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
1,980,224
|
|
|
$
|
15.81
|
|
|
Granted (1)
|
|
1,166,464
|
|
|
15.15
|
|
||
Vested (1)(2)
|
|
(601,581
|
)
|
|
22.04
|
|
||
Forfeited
|
|
(148,572
|
)
|
|
12.29
|
|
||
Non-vested, end of period
|
|
2,396,535
|
|
|
$
|
14.14
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
37.2
|
|
|
|
|
(1)
|
Restricted incentive units
typically vest at the end of three years. In March 2018,
we
granted
200,753
restricted incentive units with a fair value of
$3.0 million
to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
|
(2)
|
Vested units included
189,584
units withheld for payroll taxes paid on behalf of employees.
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
EnLink Midstream Partners, LP Restricted Incentive Units:
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Aggregate intrinsic value of units vested
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
9.1
|
|
|
$
|
15.7
|
|
Fair value of units vested
|
|
$
|
0.5
|
|
|
$
|
0.5
|
|
|
$
|
13.3
|
|
|
$
|
21.0
|
|
(c)
|
EnLink Midstream Partners, LP Performance Units
|
EnLink Midstream Partners, LP Performance Units:
|
|
March 2018
|
||
Beginning TSR price
|
|
$
|
15.44
|
|
Risk-free interest rate
|
|
2.38
|
%
|
|
Volatility factor
|
|
43.85
|
%
|
|
Distribution yield
|
|
10.5
|
%
|
|
|
Six Months Ended
June 30, 2018 |
||||||
EnLink Midstream Partners, LP Performance Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
585,285
|
|
|
$
|
20.52
|
|
|
Granted
|
|
256,345
|
|
|
19.24
|
|
||
Vested (1)
|
|
(115,328
|
)
|
|
35.39
|
|
||
Forfeited
|
|
(76,351
|
)
|
|
16.62
|
|
||
Non-vested, end of period
|
|
649,951
|
|
|
$
|
17.83
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
10.1
|
|
|
|
|
(1)
|
Vested units included
34,069
units withheld for payroll taxes paid on behalf of employees.
|
EnLink Midstream Partners, LP Performance Units:
|
|
Six Months Ended June 30, 2018
|
||
Aggregate intrinsic value of units vested
|
|
$
|
2.0
|
|
Fair value of units vested
|
|
$
|
4.1
|
|
(d)
|
EnLink Midstream, LLC Restricted Incentive Units
|
|
|
Six Months Ended
June 30, 2018 |
||||||
EnLink Midstream, LLC Restricted Incentive Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
1,889,310
|
|
|
$
|
16.33
|
|
|
Granted (1)
|
|
1,059,062
|
|
|
15.67
|
|
||
Vested (1)(2)
|
|
(556,262
|
)
|
|
24.24
|
|
||
Forfeited
|
|
(138,187
|
)
|
|
12.24
|
|
||
Non-vested, end of period
|
|
2,253,923
|
|
|
$
|
14.32
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
37.1
|
|
|
|
|
(1)
|
Restricted incentive units
typically vest at the end of three years. In March 2018,
ENLC
granted
194,185
restricted incentive units with a fair value of
$3.0 million
to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
|
(2)
|
Vested units included
178,824
units withheld for payroll taxes paid on behalf of employees.
|
(e)
|
EnLink Midstream, LLC’s Performance Units
|
EnLink Midstream, LLC Performance Units:
|
|
March 2018
|
||
Beginning TSR price
|
|
$
|
16.55
|
|
Risk-free interest rate
|
|
2.38
|
%
|
|
Volatility factor
|
|
51.36
|
%
|
|
Distribution yield
|
|
6.7
|
%
|
|
|
Six Months Ended
June 30, 2018 |
||||||
EnLink Midstream, LLC Performance Units:
|
|
Number of Units
|
|
Weighted Average Grant-Date Fair Value
|
||||
Non-vested, beginning of period
|
|
548,839
|
|
|
$
|
22.14
|
|
|
Granted
|
|
223,865
|
|
|
21.63
|
|
||
Vested (1)
|
|
(102,555
|
)
|
|
40.48
|
|
||
Forfeited
|
|
(70,918
|
)
|
|
17.75
|
|
||
Non-vested, end of period
|
|
599,231
|
|
|
$
|
19.33
|
|
|
Aggregate intrinsic value, end of period (in millions)
|
|
$
|
9.9
|
|
|
|
|
(1)
|
Vested units included
28,846
units withheld for payroll taxes paid on behalf of employees.
|
EnLink Midstream, LLC Performance Units:
|
|
Six Months Ended June 30, 2018
|
||
Aggregate intrinsic value of units vested
|
|
$
|
1.9
|
|
Fair value of units vested
|
|
$
|
4.2
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Change in fair value of derivatives
|
$
|
(10.5
|
)
|
|
$
|
1.8
|
|
|
$
|
(14.0
|
)
|
|
$
|
7.1
|
|
Realized loss on derivatives
|
(4.7
|
)
|
|
(0.2
|
)
|
|
(0.7
|
)
|
|
(2.7
|
)
|
||||
Gain (loss) on derivative activity
|
$
|
(15.2
|
)
|
|
$
|
1.6
|
|
|
$
|
(14.7
|
)
|
|
$
|
4.4
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Fair value of derivative assets—current
|
$
|
4.0
|
|
|
$
|
6.8
|
|
Fair value of derivative liabilities—current
|
(10.7
|
)
|
|
(8.4
|
)
|
||
Fair value of derivative liabilities—long-term
|
(8.9
|
)
|
|
—
|
|
||
Net fair value of derivatives
|
$
|
(15.6
|
)
|
|
$
|
(1.6
|
)
|
|
|
|
|
June 30, 2018
|
|||||||
Commodity
|
|
Instruments
|
|
Unit
|
|
Volume
|
|
Fair Value
|
|||
NGL (short contracts)
|
|
Swaps
|
|
Gallons
|
|
(46.9
|
)
|
|
$
|
(7.3
|
)
|
NGL (long contracts)
|
|
Swaps
|
|
Gallons
|
|
17.9
|
|
|
0.5
|
|
|
Natural Gas (short contracts)
|
|
Swaps
|
|
MMBtu
|
|
(9.7
|
)
|
|
1.4
|
|
|
Natural Gas (long contracts)
|
|
Swaps
|
|
MMBtu
|
|
7.5
|
|
|
(2.4
|
)
|
|
Crude and condensate (short contracts)
|
|
Swaps
|
|
MMbbls
|
|
(8.8
|
)
|
|
(12.1
|
)
|
|
Crude and condensate (long contracts)
|
|
Swaps
|
|
MMbbls
|
|
1.1
|
|
|
4.3
|
|
|
Total fair value of derivatives
|
|
|
|
|
|
|
|
|
$
|
(15.6
|
)
|
|
|
Level 2
|
||||||
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Commodity Swaps (1)
|
|
$
|
(15.6
|
)
|
|
$
|
(1.6
|
)
|
(1)
|
The fair values of derivative contracts included in assets or liabilities for risk management activities represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying
Value
|
|
Fair
Value
|
|
Carrying
Value |
|
Fair
Value |
||||||||
Long-term debt, including current maturities of long-term debt (1)
|
$
|
3,989.6
|
|
|
$
|
3,710.8
|
|
|
$
|
3,467.8
|
|
|
$
|
3,575.6
|
|
Installment Payables
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
249.5
|
|
|
$
|
249.6
|
|
Obligations under capital lease
|
$
|
3.3
|
|
|
$
|
2.8
|
|
|
$
|
4.1
|
|
|
$
|
3.4
|
|
Secured term loan receivable
|
$
|
48.5
|
|
|
$
|
48.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of
$24.2 million
and
$25.9 million
at
June 30, 2018
and
December 31, 2017
,
respectively. The respective fair values do not factor in debt issuance costs.
|
|
Texas
|
|
Louisiana
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Corporate
|
|
Totals
|
||||||||||||
Three Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
56.8
|
|
|
$
|
122.7
|
|
|
$
|
37.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
217.4
|
|
NGL sales
|
—
|
|
|
627.9
|
|
|
3.6
|
|
|
0.3
|
|
|
—
|
|
|
631.8
|
|
||||||
Crude oil and condensate sales
|
—
|
|
|
0.1
|
|
|
—
|
|
|
585.8
|
|
|
—
|
|
|
585.9
|
|
||||||
Product sales
|
56.8
|
|
|
750.7
|
|
|
41.5
|
|
|
586.1
|
|
|
—
|
|
|
1,435.1
|
|
||||||
Natural gas sales—related parties
|
—
|
|
|
—
|
|
|
1.9
|
|
|
—
|
|
|
—
|
|
|
1.9
|
|
||||||
NGL sales—related parties
|
134.3
|
|
|
28.9
|
|
|
140.4
|
|
|
—
|
|
|
(278.6
|
)
|
|
25.0
|
|
||||||
Crude oil and condensate sales—related parties
|
15.1
|
|
|
0.1
|
|
|
23.6
|
|
|
1.7
|
|
|
(40.2
|
)
|
|
0.3
|
|
||||||
Product sales—related parties
|
149.4
|
|
|
29.0
|
|
|
165.9
|
|
|
1.7
|
|
|
(318.8
|
)
|
|
27.2
|
|
||||||
Gathering and transportation
|
13.5
|
|
|
16.7
|
|
|
25.6
|
|
|
0.9
|
|
|
—
|
|
|
56.7
|
|
||||||
Processing
|
9.5
|
|
|
1.1
|
|
|
47.4
|
|
|
—
|
|
|
—
|
|
|
58.0
|
|
||||||
NGL services
|
—
|
|
|
10.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.3
|
|
||||||
Crude services
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
15.1
|
|
|
—
|
|
|
15.0
|
|
||||||
Other services
|
2.2
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.4
|
|
||||||
Midstream services
|
25.2
|
|
|
28.3
|
|
|
72.9
|
|
|
16.0
|
|
|
—
|
|
|
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
|
—
|
|
|
—
|
|
|
0.7
|
|
|
4.3
|
|
|
—
|
|
|
5.0
|
|
||||||
Other services—related parties
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
||||||
Midstream services—related parties
|
108.4
|
|
|
—
|
|
|
62.5
|
|
|
4.3
|
|
|
—
|
|
|
175.2
|
|
||||||
Revenue from contracts with customers
|
339.8
|
|
|
808.0
|
|
|
342.8
|
|
|
608.1
|
|
|
(318.8
|
)
|
|
1,779.9
|
|
||||||
Cost of sales
|
(178.7
|
)
|
|
(723.0
|
)
|
|
(170.3
|
)
|
|
(572.4
|
)
|
|
318.8
|
|
|
(1,325.6
|
)
|
||||||
Operating expenses
|
(45.8
|
)
|
|
(28.0
|
)
|
|
(20.8
|
)
|
|
(18.8
|
)
|
|
—
|
|
|
(113.4
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15.2
|
)
|
|
(15.2
|
)
|
||||||
Segment profit (loss)
|
$
|
115.3
|
|
|
$
|
57.0
|
|
|
$
|
151.7
|
|
|
$
|
16.9
|
|
|
$
|
(15.2
|
)
|
|
$
|
325.7
|
|
Depreciation and amortization
|
$
|
(53.4
|
)
|
|
$
|
(30.5
|
)
|
|
$
|
(46.4
|
)
|
|
$
|
(12.7
|
)
|
|
$
|
(2.3
|
)
|
|
$
|
(145.3
|
)
|
Goodwill
|
$
|
232.0
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
44.7
|
|
|
$
|
16.6
|
|
|
$
|
121.0
|
|
|
$
|
34.9
|
|
|
$
|
1.0
|
|
|
$
|
218.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Three Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Product sales
|
$
|
74.6
|
|
|
$
|
548.7
|
|
|
$
|
27.7
|
|
|
$
|
276.2
|
|
|
$
|
—
|
|
|
$
|
927.2
|
|
Product sales—related parties
|
115.5
|
|
|
5.4
|
|
|
62.4
|
|
|
—
|
|
|
(154.0
|
)
|
|
29.3
|
|
||||||
Midstream services
|
28.2
|
|
|
56.3
|
|
|
33.0
|
|
|
14.4
|
|
|
—
|
|
|
131.9
|
|
||||||
Midstream services—related parties
|
107.2
|
|
|
35.3
|
|
|
59.4
|
|
|
5.3
|
|
|
(33.6
|
)
|
|
173.6
|
|
||||||
Cost of sales
|
(177.0
|
)
|
|
(575.7
|
)
|
|
(99.0
|
)
|
|
(268.3
|
)
|
|
187.6
|
|
|
(932.4
|
)
|
||||||
Operating expenses
|
(42.9
|
)
|
|
(24.6
|
)
|
|
(14.7
|
)
|
|
(20.4
|
)
|
|
—
|
|
|
(102.6
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.6
|
|
|
1.6
|
|
||||||
Segment profit
|
$
|
105.6
|
|
|
$
|
45.4
|
|
|
$
|
68.8
|
|
|
$
|
7.2
|
|
|
$
|
1.6
|
|
|
$
|
228.6
|
|
Depreciation and amortization
|
$
|
(59.6
|
)
|
|
$
|
(29.4
|
)
|
|
$
|
(38.6
|
)
|
|
$
|
(12.6
|
)
|
|
$
|
(2.3
|
)
|
|
$
|
(142.5
|
)
|
Goodwill
|
$
|
232.0
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
39.7
|
|
|
$
|
15.6
|
|
|
$
|
135.0
|
|
|
$
|
13.7
|
|
|
$
|
14.5
|
|
|
$
|
218.5
|
|
|
Texas
|
|
Louisiana
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Corporate
|
|
Totals
|
||||||||||||
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Natural gas sales
|
$
|
139.8
|
|
|
$
|
247.7
|
|
|
$
|
86.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
473.5
|
|
NGL sales
|
—
|
|
|
1,236.3
|
|
|
5.5
|
|
|
0.8
|
|
|
—
|
|
|
1,242.6
|
|
||||||
Crude oil and condensate sales
|
—
|
|
|
0.1
|
|
|
—
|
|
|
1,218.1
|
|
|
—
|
|
|
1,218.2
|
|
||||||
Product sales
|
139.8
|
|
|
1,484.1
|
|
|
91.5
|
|
|
1,218.9
|
|
|
—
|
|
|
2,934.3
|
|
||||||
Natural gas sales—related parties
|
—
|
|
|
—
|
|
|
2.4
|
|
|
—
|
|
|
—
|
|
|
2.4
|
|
||||||
NGL sales—related parties
|
227.3
|
|
|
34.5
|
|
|
240.5
|
|
|
—
|
|
|
(474.9
|
)
|
|
27.4
|
|
||||||
Crude oil and condensate sales—related parties
|
26.0
|
|
|
0.2
|
|
|
45.9
|
|
|
1.8
|
|
|
(72.9
|
)
|
|
1.0
|
|
||||||
Product sales—related parties
|
253.3
|
|
|
34.7
|
|
|
288.8
|
|
|
1.8
|
|
|
(547.8
|
)
|
|
30.8
|
|
||||||
Gathering and transportation
|
26.7
|
|
|
34.3
|
|
|
41.2
|
|
|
1.7
|
|
|
—
|
|
|
103.9
|
|
||||||
Processing
|
13.3
|
|
|
1.7
|
|
|
56.4
|
|
|
—
|
|
|
—
|
|
|
71.4
|
|
||||||
NGL services
|
—
|
|
|
26.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26.9
|
|
||||||
Crude services
|
—
|
|
|
—
|
|
|
—
|
|
|
27.9
|
|
|
—
|
|
|
27.9
|
|
||||||
Other services
|
4.0
|
|
|
0.4
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
4.5
|
|
||||||
Midstream services
|
44.0
|
|
|
63.3
|
|
|
97.6
|
|
|
29.7
|
|
|
—
|
|
|
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
|
—
|
|
|
—
|
|
|
1.4
|
|
|
8.6
|
|
|
—
|
|
|
10.0
|
|
||||||
Other services—related parties
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
||||||
Midstream services—related parties
|
212.8
|
|
|
—
|
|
|
120.0
|
|
|
8.6
|
|
|
—
|
|
|
341.4
|
|
||||||
Revenue from contracts with customers
|
649.9
|
|
|
1,582.1
|
|
|
597.9
|
|
|
1,259.0
|
|
|
(547.8
|
)
|
|
3,541.1
|
|
||||||
Cost of sales
|
(340.2
|
)
|
|
(1,409.7
|
)
|
|
(309.3
|
)
|
|
(1,195.7
|
)
|
|
547.8
|
|
|
(2,707.1
|
)
|
||||||
Operating expenses
|
(90.0
|
)
|
|
(53.6
|
)
|
|
(41.5
|
)
|
|
(37.5
|
)
|
|
—
|
|
|
(222.6
|
)
|
||||||
Loss on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(14.7
|
)
|
|
(14.7
|
)
|
||||||
Segment profit (loss)
|
$
|
219.7
|
|
|
$
|
118.8
|
|
|
$
|
247.1
|
|
|
$
|
25.8
|
|
|
$
|
(14.7
|
)
|
|
$
|
596.7
|
|
Depreciation and amortization
|
$
|
(105.9
|
)
|
|
$
|
(59.7
|
)
|
|
$
|
(88.5
|
)
|
|
$
|
(25.1
|
)
|
|
$
|
(4.2
|
)
|
|
$
|
(283.4
|
)
|
Goodwill
|
$
|
232.0
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
110.0
|
|
|
$
|
23.4
|
|
|
$
|
219.5
|
|
|
$
|
44.2
|
|
|
$
|
2.3
|
|
|
$
|
399.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Product sales
|
$
|
159.7
|
|
|
$
|
1,093.2
|
|
|
$
|
42.2
|
|
|
$
|
622.1
|
|
|
$
|
—
|
|
|
$
|
1,917.2
|
|
Product sales—related parties
|
222.0
|
|
|
15.6
|
|
|
126.8
|
|
|
0.8
|
|
|
(293.2
|
)
|
|
72.0
|
|
||||||
Midstream services
|
56.0
|
|
|
109.4
|
|
|
60.9
|
|
|
33.0
|
|
|
—
|
|
|
259.3
|
|
||||||
Midstream services—related parties
|
212.3
|
|
|
64.3
|
|
|
108.8
|
|
|
8.6
|
|
|
(61.4
|
)
|
|
332.6
|
|
||||||
Cost of sales
|
(356.2
|
)
|
|
(1,140.4
|
)
|
|
(187.7
|
)
|
|
(605.0
|
)
|
|
354.6
|
|
|
(1,934.7
|
)
|
||||||
Operating expenses
|
(86.8
|
)
|
|
(50.0
|
)
|
|
(28.8
|
)
|
|
(41.1
|
)
|
|
—
|
|
|
(206.7
|
)
|
||||||
Gain on derivative activity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.4
|
|
|
4.4
|
|
||||||
Segment profit
|
$
|
207.0
|
|
|
$
|
92.1
|
|
|
$
|
122.2
|
|
|
$
|
18.4
|
|
|
$
|
4.4
|
|
|
$
|
444.1
|
|
Depreciation and amortization
|
$
|
(109.4
|
)
|
|
$
|
(57.5
|
)
|
|
$
|
(75.1
|
)
|
|
$
|
(24.1
|
)
|
|
$
|
(4.7
|
)
|
|
$
|
(270.8
|
)
|
Impairments
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(7.0
|
)
|
|
$
|
—
|
|
|
$
|
(7.0
|
)
|
Goodwill
|
$
|
232.0
|
|
|
$
|
—
|
|
|
$
|
190.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
422.3
|
|
Capital expenditures
|
$
|
68.0
|
|
|
$
|
48.3
|
|
|
$
|
275.7
|
|
|
$
|
51.1
|
|
|
$
|
23.5
|
|
|
$
|
466.6
|
|
Segment Identifiable Assets:
|
June 30, 2018
|
|
December 31, 2017
|
||||
Texas
|
$
|
3,139.3
|
|
|
$
|
3,094.8
|
|
Louisiana
|
2,391.1
|
|
|
2,408.5
|
|
||
Oklahoma
|
2,993.8
|
|
|
2,836.7
|
|
||
Crude and Condensate
|
1,005.0
|
|
|
929.5
|
|
||
Corporate
|
130.9
|
|
|
144.5
|
|
||
Total identifiable assets
|
$
|
9,660.1
|
|
|
$
|
9,414.0
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Segment profit
|
$
|
325.7
|
|
|
$
|
228.6
|
|
|
$
|
596.7
|
|
|
$
|
444.1
|
|
General and administrative expenses
|
(29.1
|
)
|
|
(29.6
|
)
|
|
(55.3
|
)
|
|
(64.6
|
)
|
||||
Gain (loss) on disposition of assets
|
(1.2
|
)
|
|
5.4
|
|
|
(1.3
|
)
|
|
0.3
|
|
||||
Depreciation and amortization
|
(145.3
|
)
|
|
(142.5
|
)
|
|
(283.4
|
)
|
|
(270.8
|
)
|
||||
Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
(7.0
|
)
|
||||
Gain on litigation settlement
|
—
|
|
|
8.5
|
|
|
—
|
|
|
26.0
|
|
||||
Operating income
|
$
|
150.1
|
|
|
$
|
70.4
|
|
|
$
|
256.7
|
|
|
$
|
128.0
|
|
Other Current Assets:
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Natural gas and NGLs inventory
|
|
$
|
60.8
|
|
|
$
|
30.1
|
|
Secured term loan receivable from contract restructuring, net of discount o
f $1.6
|
|
17.9
|
|
|
—
|
|
||
Prepaid expenses and other
|
|
18.9
|
|
|
9.6
|
|
||
Natural gas and NGLs inventory, prepaid expenses, and other
|
|
$
|
97.6
|
|
|
$
|
39.7
|
|
Other Current Liabilities:
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Accrued interest
|
|
$
|
36.3
|
|
|
$
|
35.4
|
|
Accrued wages and benefits, including taxes
|
|
18.0
|
|
|
30.4
|
|
||
Accrued ad valorem taxes
|
|
25.9
|
|
|
27.8
|
|
||
Capital expenditure accruals
|
|
41.8
|
|
|
48.8
|
|
||
Onerous performance obligations
|
|
17.9
|
|
|
15.2
|
|
||
Other
|
|
65.4
|
|
|
64.8
|
|
||
Other current liabilities
|
|
$
|
205.3
|
|
|
$
|
222.4
|
|
•
|
GIP, through GIP Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the managing member of ENLC, which amount to
100%
of the outstanding limited liability company interests in the managing member of ENLC and approximately
23.1%
of the outstanding limited partner interests in ENLK. Through this ownership, GIP acquired control of the managing member of ENLC and ENLC, and, as a result of ENLC’s indirect ownership of ENLK’s general partner, GIP has the ability to control ENLK; and
|
•
|
GIP, through GIP Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which amount to approximately
63.8%
of the outstanding limited liability company interests in ENLC.
|
•
|
gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
|
•
|
fractionating, transporting, storing, and selling NGLs; and
|
•
|
gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services.
|
•
|
Texas Segment
. The Texas segment includes our natural gas gathering, processing, and transmission operations in North Texas and the Permian Basin primarily in West Texas;
|
•
|
Oklahoma Segment
. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities in the Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK, and CNOW areas;
|
•
|
Louisiana Segment
. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana;
|
•
|
Crude and Condensate Segment
. The Crude and Condensate segment includes our ORV crude oil, condensate, condensate stabilization, natural gas compression, and brine disposal activities in the Utica and Marcellus Shales, our crude oil operations in the Permian Basin and Central Oklahoma, and our crude oil activities associated with VEX located in the Eagle Ford Shale; and
|
•
|
Corporate Segment
. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in South Texas, and our general corporate property
and expenses.
|
•
|
gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own;
|
•
|
processing natural gas at our processing plants;
|
•
|
fractionating and marketing recovered NGLs;
|
•
|
providing compression services;
|
•
|
providing crude oil and condensate transportation and terminal services;
|
•
|
providing condensate stabilization services;
|
•
|
providing brine disposal services; and
|
•
|
providing natural gas, crude oil, and NGL storage.
|
•
|
natural gas gathered, transported, purchased, and sold through our pipeline systems;
|
•
|
natural gas processed at our processing facilities;
|
•
|
NGLs handled at our fractionation facilities or transported through our pipeline systems;
|
•
|
crude oil and condensate handled at our crude terminals;
|
•
|
crude oil and condensate gathered, transported, purchased, and sold;
|
•
|
condensate stabilized;
|
•
|
brine disposed; and
|
•
|
natural gas, crude oil, and NGLs stored.
|
•
|
the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;
|
•
|
the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders and our general partner;
|
•
|
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and
|
•
|
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net income
|
|
$
|
112.9
|
|
|
$
|
32.7
|
|
|
$
|
178.0
|
|
|
$
|
46.0
|
|
Interest expense, net of interest income
|
|
43.7
|
|
|
47.1
|
|
|
87.4
|
|
|
91.6
|
|
||||
Depreciation and amortization
|
|
145.3
|
|
|
142.5
|
|
|
283.4
|
|
|
270.8
|
|
||||
Impairments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7.0
|
|
||||
(Income) loss from unconsolidated affiliates (1)
|
|
(4.4
|
)
|
|
0.1
|
|
|
(7.4
|
)
|
|
(0.6
|
)
|
||||
Distributions from unconsolidated affiliates
|
|
5.4
|
|
|
4.5
|
|
|
11.4
|
|
|
7.4
|
|
||||
(Gain) loss on disposition of assets
|
|
1.2
|
|
|
(5.4
|
)
|
|
1.3
|
|
|
(0.3
|
)
|
||||
Gain on extinguishment of debt
|
|
—
|
|
|
(9.0
|
)
|
|
—
|
|
|
(9.0
|
)
|
||||
Unit-based compensation
|
|
9.5
|
|
|
9.3
|
|
|
14.6
|
|
|
28.6
|
|
||||
Income tax provision (benefit)
|
|
(2.1
|
)
|
|
(0.3
|
)
|
|
(1.1
|
)
|
|
0.2
|
|
||||
(Gain) loss on non-cash derivatives
|
|
10.5
|
|
|
(1.8
|
)
|
|
14.0
|
|
|
(7.1
|
)
|
||||
Payments under onerous performance obligation offset to other current and long-term liabilities
|
|
(4.5
|
)
|
|
(4.5
|
)
|
|
(9.0
|
)
|
|
(9.0
|
)
|
||||
Non-cash revenue from contract restructuring (2)
|
|
(45.5
|
)
|
|
—
|
|
|
(45.5
|
)
|
|
—
|
|
||||
Other (3)
|
|
(0.4
|
)
|
|
1.9
|
|
|
0.7
|
|
|
2.7
|
|
||||
Adjusted EBITDA before non-controlling interest
|
|
$
|
271.6
|
|
|
$
|
217.1
|
|
|
$
|
527.8
|
|
|
$
|
428.3
|
|
Non-controlling interest share of adjusted EBITDA (4)
|
|
(14.4
|
)
|
|
(7.4
|
)
|
|
(26.9
|
)
|
|
(11.0
|
)
|
||||
Adjusted EBITDA, net to ENLK
|
|
$
|
257.2
|
|
|
$
|
209.7
|
|
|
$
|
500.9
|
|
|
$
|
417.3
|
|
(1)
|
Includes a loss of $3.4 million for the six months ended June 30, 2017 from the sale of HEP in March 2017.
|
(2)
|
In May 2018, we restructured a natural gas gathering and processing contract, and, as a result, recognized non-cash revenue representing the discounted present value of a secured term loan receivable.
For more information, see “Item 1. Financial Statements—
Note 2
.”
|
(3)
|
Includes accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term.
|
(4)
|
Non-controlling interest share of adjusted EBITDA includes ENLC’s
16.1%
share of adjusted EBITDA from EOGP, NGP’s
49.9%
share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net cash provided by operating activities
|
$
|
238.0
|
|
|
$
|
158.0
|
|
|
$
|
430.7
|
|
|
$
|
332.2
|
|
Interest expense (1)
|
43.6
|
|
|
40.1
|
|
|
85.8
|
|
|
77.4
|
|
||||
Current income tax
|
(0.3
|
)
|
|
(0.6
|
)
|
|
0.7
|
|
|
0.2
|
|
||||
Distributions from unconsolidated affiliate investment in excess of earnings
|
0.5
|
|
|
4.5
|
|
|
1.9
|
|
|
7.4
|
|
||||
Other (2)
|
(1.8
|
)
|
|
4.8
|
|
|
—
|
|
|
5.7
|
|
||||
Changes in operating assets and liabilities which (provided) used cash:
|
|
|
|
|
|
|
|
||||||||
Accounts receivable, accrued revenues, inventories and other
|
31.2
|
|
|
(2.6
|
)
|
|
86.8
|
|
|
(22.0
|
)
|
||||
Accounts payable, accrued gas and crude oil purchases and other (3)
|
(39.6
|
)
|
|
12.9
|
|
|
(78.1
|
)
|
|
27.4
|
|
||||
Adjusted EBITDA before non-controlling interest
|
$
|
271.6
|
|
|
$
|
217.1
|
|
|
$
|
527.8
|
|
|
$
|
428.3
|
|
Non-controlling interest share of adjusted EBITDA (4)
|
(14.4
|
)
|
|
(7.4
|
)
|
|
(26.9
|
)
|
|
(11.0
|
)
|
||||
Adjusted EBITDA, net to ENLK
|
$
|
257.2
|
|
|
$
|
209.7
|
|
|
$
|
500.9
|
|
|
$
|
417.3
|
|
Interest expense, net of interest income
|
(43.7
|
)
|
|
(47.1
|
)
|
|
(87.4
|
)
|
|
(91.6
|
)
|
||||
Amortization of EOGP. installment payable discount included in interest expense (5)
|
—
|
|
|
6.5
|
|
|
0.5
|
|
|
13.5
|
|
||||
Litigation settlement adjustment (6)
|
—
|
|
|
(5.8
|
)
|
|
—
|
|
|
(18.1
|
)
|
||||
Current taxes and other
|
(0.3
|
)
|
|
0.4
|
|
|
(1.2
|
)
|
|
(0.2
|
)
|
||||
Maintenance capital expenditures, net to ENLK (7)
|
(12.1
|
)
|
|
(9.4
|
)
|
|
(18.3
|
)
|
|
(13.6
|
)
|
||||
Preferred unit accrued cash distributions (8)
|
(22.3
|
)
|
|
—
|
|
|
(44.5
|
)
|
|
—
|
|
||||
Distributable cash flow
|
$
|
178.8
|
|
|
$
|
154.3
|
|
|
$
|
350.0
|
|
|
$
|
307.3
|
|
(1)
|
Excludes non-cash interest income and amortization of debt issuance costs and discount and premium.
|
(2)
|
Includes non-cash rent, which relates to lease incentives pro-rated over the lease term, and accruals for settled commodity swap transactions.
|
(3)
|
Net of payments under onerous performance obligation offset to other current and long-term liabilities.
|
(4)
|
Non-controlling interest share of adjusted EBITDA includes ENLC’s
16.1%
share of adjusted EBITDA from EOGP, NGP’s
49.9%
share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.
|
(5)
|
Amortization of the EOGP installment payable discount is considered non-cash interest under
our
credit facility since the payment under the payable is consideration for the acquisition of the EOGP assets.
|
(6)
|
Represents recoveries from a lawsuit settled in 2017 for amounts not previously deducted from distributable cash flow.
|
(7)
|
Excludes maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.
|
(8)
|
Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units of
$16.3 million
and
$6.0 million
, respectively, for the
three
months ended
June 30, 2018
, and cash distributions earned by the Series B Preferred Units and Series C Preferred Units of
$32.5 million
and
$12.0 million
, respectively, for the
six
months ended
June 30, 2018
. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Operating income
|
|
$
|
150.1
|
|
|
$
|
70.4
|
|
|
$
|
256.7
|
|
|
$
|
128.0
|
|
|
|
|
|
|
|
|
|
|
||||||||
Add (deduct):
|
|
|
|
|
|
|
|
|
||||||||
Operating expenses
|
|
113.4
|
|
|
102.6
|
|
|
222.6
|
|
|
206.7
|
|
||||
General and administrative expenses
|
|
29.1
|
|
|
29.6
|
|
|
55.3
|
|
|
64.6
|
|
||||
(Gain) loss on disposition of assets
|
|
1.2
|
|
|
(5.4
|
)
|
|
1.3
|
|
|
(0.3
|
)
|
||||
Depreciation and amortization
|
|
145.3
|
|
|
142.5
|
|
|
283.4
|
|
|
270.8
|
|
||||
Impairments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7.0
|
|
||||
Gain on litigation settlement
|
|
—
|
|
|
(8.5
|
)
|
|
—
|
|
|
(26.0
|
)
|
||||
Gross operating margin
|
|
$
|
439.1
|
|
|
$
|
331.2
|
|
|
$
|
819.3
|
|
|
$
|
650.8
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Texas Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
339.8
|
|
|
$
|
325.5
|
|
|
$
|
649.9
|
|
|
$
|
650.0
|
|
Cost of sales
|
(178.7
|
)
|
|
(177.0
|
)
|
|
(340.2
|
)
|
|
(356.2
|
)
|
||||
Total gross operating margin
|
$
|
161.1
|
|
|
$
|
148.5
|
|
|
$
|
309.7
|
|
|
$
|
293.8
|
|
Louisiana Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
808.0
|
|
|
$
|
645.7
|
|
|
$
|
1,582.1
|
|
|
$
|
1,282.5
|
|
Cost of sales
|
(723.0
|
)
|
|
(575.7
|
)
|
|
(1,409.7
|
)
|
|
(1,140.4
|
)
|
||||
Total gross operating margin
|
$
|
85.0
|
|
|
$
|
70.0
|
|
|
$
|
172.4
|
|
|
$
|
142.1
|
|
Oklahoma Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
342.8
|
|
|
$
|
182.5
|
|
|
$
|
597.9
|
|
|
$
|
338.7
|
|
Cost of sales
|
(170.3
|
)
|
|
(99.0
|
)
|
|
(309.3
|
)
|
|
(187.7
|
)
|
||||
Total gross operating margin
|
$
|
172.5
|
|
|
$
|
83.5
|
|
|
$
|
288.6
|
|
|
$
|
151.0
|
|
Crude and Condensate Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
608.1
|
|
|
$
|
295.9
|
|
|
$
|
1,259.0
|
|
|
$
|
664.5
|
|
Cost of sales
|
(572.4
|
)
|
|
(268.3
|
)
|
|
(1,195.7
|
)
|
|
(605.0
|
)
|
||||
Total gross operating margin
|
$
|
35.7
|
|
|
$
|
27.6
|
|
|
$
|
63.3
|
|
|
$
|
59.5
|
|
Corporate Segment
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
(334.0
|
)
|
|
$
|
(186.0
|
)
|
|
$
|
(562.5
|
)
|
|
$
|
(350.2
|
)
|
Cost of sales
|
318.8
|
|
|
187.6
|
|
|
547.8
|
|
|
354.6
|
|
||||
Total gross operating margin
|
$
|
(15.2
|
)
|
|
$
|
1.6
|
|
|
$
|
(14.7
|
)
|
|
$
|
4.4
|
|
Total
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
1,764.7
|
|
|
$
|
1,263.6
|
|
|
$
|
3,526.4
|
|
|
$
|
2,585.5
|
|
Cost of sales
|
(1,325.6
|
)
|
|
(932.4
|
)
|
|
(2,707.1
|
)
|
|
(1,934.7
|
)
|
||||
Total gross operating margin
|
$
|
439.1
|
|
|
$
|
331.2
|
|
|
$
|
819.3
|
|
|
$
|
650.8
|
|
|
|
|
|
|
|
|
|
||||||||
Midstream Volumes:
|
|
|
|
|
|
|
|
||||||||
Texas Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
2,258,300
|
|
|
2,272,100
|
|
|
2,224,700
|
|
|
2,273,100
|
|
||||
Processing (MMBtu/d)
|
1,283,100
|
|
|
1,179,700
|
|
|
1,238,800
|
|
|
1,170,900
|
|
||||
Louisiana Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
2,094,100
|
|
|
1,939,500
|
|
|
2,158,200
|
|
|
1,935,400
|
|
||||
Processing (MMBtu/d)
|
395,600
|
|
|
446,500
|
|
|
418,600
|
|
|
457,100
|
|
||||
NGL Fractionation (Gals/d)
|
6,480,100
|
|
|
5,819,600
|
|
|
6,342,400
|
|
|
5,534,100
|
|
||||
Oklahoma Segment
|
|
|
|
|
|
|
|
||||||||
Gathering and Transportation (MMBtu/d)
|
1,235,500
|
|
|
765,500
|
|
|
1,142,200
|
|
|
735,600
|
|
||||
Processing (MMBtu/d)
|
1,200,700
|
|
|
733,100
|
|
|
1,135,400
|
|
|
693,200
|
|
||||
Crude and Condensate Segment
|
|
|
|
|
|
|
|
||||||||
Crude Oil Handling (Bbls/d)
|
148,600
|
|
|
107,600
|
|
|
138,200
|
|
|
109,000
|
|
||||
Brine Disposal (Bbls/d)
|
3,500
|
|
|
4,800
|
|
|
3,100
|
|
|
4,600
|
|
•
|
Texas Segment.
Gross operating margin in the Texas segment
increased
$12.6 million
, which was due to a $12.6 million increase from our Permian Basin processing assets as a result of higher volumes from continued development by our customers. Our gross operating margin from our North Texas assets was flat quarter over quarter despite declines in volumes across the system, which were offset by an increase in revenue earned from MVCs (as discussed in more detail below). For the three months ended June 30, 2018, the shortfall revenue from Devon-related MVCs was $20.8 million compared to $13.7 million for the three months ended June 30, 2017.
|
•
|
Louisiana Segment.
Gross operating margin in the Louisiana segment
increased
$15.0 million
, which was due to an $8.5 million increase from our NGL transmission and fractionation assets as a result of higher volumes received from our Permian Basin and Oklahoma assets and fees earned from the Ascension JV, which commenced operations in April 2017. In addition, there was a $6.5 million increase from our gas processing and transmission assets as a result of higher gathering and transportation volumes and increased gross operating margin under our processing margin contracts due to higher NGL prices during the three months ended June 30, 2018.
|
•
|
Oklahoma Segment.
Gross operating margin in the Oklahoma segment
increased
$89.0 million
, which includes $45.5 million recognized from a contract restructuring with a customer during the three months ended June 30, 2018 (as discussed in “Item 1. Financial Statements—Note 2”). The remaining $43.5 million increase in gross operating margin was primarily due to higher volumes as a result of continued development by our customers.
|
•
|
Crude and Condensate Segment.
Gross operating margin in the Crude and Condensate segment
increased
$8.1 million
, which was primarily due to a $4.8 million increase from our ORV assets due to higher condensate stabilization volumes and improved margins due to contract renegotiations. In addition, there was a $2.0 million increase from our Midland Basin crude business as a result of increased trucked volumes, higher trucking fees, and higher volumes due to continued expansion of our customer base on the Greater Chickadee gathering system.
|
•
|
Corporate Segment.
Gross operating margin in the Corporate segment
decreased
$16.8 million
, which was due to the changes in fair value of our commodity swaps between the periods.
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
.
For the three months ended
June 30, 2017
, realized losses of
$0.2 million
were offset by unrealized gains of
$1.8 million
.
|
|
|
Texas
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Total
|
||||||||
Three Months Ended
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2018
|
|
|
|
|
|
|
|
|
||||||||
Midstream services (1)
|
|
$
|
0.1
|
|
|
$
|
47.7
|
|
|
$
|
—
|
|
|
$
|
47.8
|
|
Midstream services—related parties
|
|
20.8
|
|
|
—
|
|
|
2.3
|
|
|
23.1
|
|
||||
Total
|
|
$
|
20.9
|
|
|
$
|
47.7
|
|
|
$
|
2.3
|
|
|
$
|
70.9
|
|
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2017
|
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
|
$
|
0.5
|
|
|
$
|
4.7
|
|
|
$
|
—
|
|
|
$
|
5.2
|
|
Midstream services—related parties
|
|
13.7
|
|
|
4.4
|
|
|
2.0
|
|
|
20.1
|
|
||||
Total
|
|
$
|
14.2
|
|
|
$
|
9.1
|
|
|
$
|
2.0
|
|
|
$
|
25.3
|
|
(1)
|
We restructured a natural gas gathering and processing contract that contained MVCs. As a result, we recognized
$45.5 million
of midstream services revenue in the Oklahoma segment for the three months ended
June 30, 2018
. For more information, see “Item 1. Financial Statements—
Note 2
.”
|
|
Three Months Ended
June 30, |
|
Change
|
|||||||||||
|
2018
|
|
2017
|
|
$
|
|
%
|
|||||||
Texas Segment
|
$
|
45.8
|
|
|
$
|
42.9
|
|
|
$
|
2.9
|
|
|
6.8
|
%
|
Louisiana Segment
|
28.0
|
|
|
24.6
|
|
|
3.4
|
|
|
13.8
|
%
|
|||
Oklahoma Segment
|
20.8
|
|
|
14.7
|
|
|
6.1
|
|
|
41.5
|
%
|
|||
Crude and Condensate Segment
|
18.8
|
|
|
20.4
|
|
|
(1.6
|
)
|
|
(7.8
|
)%
|
|||
Total
|
$
|
113.4
|
|
|
$
|
102.6
|
|
|
$
|
10.8
|
|
|
10.5
|
%
|
•
|
Texas Segment.
Operating expenses in the Texas segment
increased
$2.9 million
primarily due to expanded operations in the Permian Basin.
|
•
|
Louisiana Segment.
Operating expenses in the Louisiana segment
increased
$3.4 million
primarily due to increased regulatory, utilities, and materials and supplies expenses as a result of higher volumes across our Louisiana assets.
|
•
|
Oklahoma Segment.
Operating expenses in the Oklahoma segment
increased
$6.1 million
primarily due to an increase in labor and benefits expenses due to increased headcount, as well as an increase in materials and supplies, utilities, and ad valorem tax expenses as a result of increased activity on our Oklahoma assets.
|
•
|
Crude and Condensate Segment.
Operating expenses in the Crude and Condensate segment
decreased
$1.6 million
primarily due to decreases in third-party transportation charges and labor and benefits expenses.
|
|
Three Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Senior notes
|
$
|
40.0
|
|
|
$
|
38.9
|
|
Credit facility
|
4.9
|
|
|
2.5
|
|
||
Capitalized interest
|
(1.5
|
)
|
|
(1.4
|
)
|
||
Amortization of debt issue costs and net discounts
|
0.9
|
|
|
7.0
|
|
||
Other
|
(0.6
|
)
|
|
0.1
|
|
||
Total
|
$
|
43.7
|
|
|
$
|
47.1
|
|
•
|
Texas Segment.
Gross operating margin in the Texas segment
increased
$15.9 million
, which was primarily due to a $19.0 million increase from our Permian Basin processing assets as a result of higher volumes due to continued development by our customers, partially offset by a $3.1 million decrease from our North Texas assets as a result of lower volumes due to well production declines. The decrease in gross operating margin from our North Texas assets was partially offset by an increase in revenue earned from MVCs (as discussed in more detail below). For the six
|
•
|
Louisiana Segment.
Gross operating margin in the Louisiana segment
increased
$30.3 million
, which was primarily due to a $29.0 million increase in our NGL transmission and fractionation gross operating margin due to additional NGL volumes received from our Oklahoma and Permian Basin assets and fees earned from the start-up of our Ascension JV assets in April 2017, as well as a $1.3 million increase from volume increases within our gas gathering and transmission assets.
|
•
|
Oklahoma Segment.
Gross operating margin in the Oklahoma segment
increased
$137.6 million
, which was primarily due to a $92.1 million increase from higher volumes as a result of continued development by our customers. In addition, during the six months ended June 30, 2018, we restructured a contract with a customer, which resulted in the recognition of $45.5 million in revenue for the six months ended June 30, 2018 (as discussed in “Item 1. Financial Statements
—
Note 2
”).
|
•
|
Crude and Condensate Segment.
Gross operating margin in the Crude and Condensate segment
increased
$3.8 million
, which was primarily due to a $1.5 million increase from our ORV assets related to renegotiated contracts and a $2.8 million increase due to higher volumes from continued expansion of our customer base on the Greater Chickadee gathering system.
|
•
|
Corporate Segment.
Gross operating margin in the Corporate segment
decreased
$19.1 million
due to the changes in fair value of our commodity swaps between the periods.
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
.
For the
six
months ended
June 30, 2017
, realized losses of
$2.7 million
were offset by unrealized gains of
$7.1 million
.
|
|
|
Texas
|
|
Oklahoma
|
|
Crude and Condensate
|
|
Total
|
||||||||
Six Months Ended
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2018
|
|
|
|
|
|
|
|
|
||||||||
Midstream services (1)
|
|
$
|
0.1
|
|
|
$
|
52.7
|
|
|
$
|
—
|
|
|
$
|
52.8
|
|
Midstream services—related parties
|
|
38.9
|
|
|
1.2
|
|
|
5.7
|
|
|
45.8
|
|
||||
Total
|
|
$
|
39.0
|
|
|
$
|
53.9
|
|
|
$
|
5.7
|
|
|
$
|
98.6
|
|
|
|
|
|
|
|
|
|
|
||||||||
June 30, 2017
|
|
|
|
|
|
|
|
|
||||||||
Midstream services
|
|
$
|
0.8
|
|
|
$
|
6.2
|
|
|
$
|
—
|
|
|
$
|
7.0
|
|
Midstream services—related parties
|
|
26.2
|
|
|
8.0
|
|
|
2.8
|
|
|
37.0
|
|
||||
Total
|
|
$
|
27.0
|
|
|
$
|
14.2
|
|
|
$
|
2.8
|
|
|
$
|
44.0
|
|
(1)
|
We restructured a natural gas gathering and processing contract that contained MVCs. As a result, we recognized
$45.5 million
of midstream services revenue in the Oklahoma segment for the
six
months ended
June 30, 2018
. For more information, see “Item 1. Financial Statements—
Note 2
.”
|
|
Six Months Ended
June 30, |
|
Change
|
|||||||||||
|
2018
|
|
2017
|
|
$
|
|
%
|
|||||||
Texas Segment
|
$
|
90.0
|
|
|
$
|
86.8
|
|
|
$
|
3.2
|
|
|
3.7
|
%
|
Louisiana Segment
|
53.6
|
|
|
50.0
|
|
|
3.6
|
|
|
7.2
|
%
|
|||
Oklahoma Segment
|
41.5
|
|
|
28.8
|
|
|
12.7
|
|
|
44.1
|
%
|
|||
Crude and Condensate Segment
|
37.5
|
|
|
41.1
|
|
|
(3.6
|
)
|
|
(8.8
|
)%
|
|||
Total
|
$
|
222.6
|
|
|
$
|
206.7
|
|
|
$
|
15.9
|
|
|
7.7
|
%
|
•
|
Texas Segment.
Operating expenses in the Texas segment
increased
$3.2 million
as a result of expanded operations and higher utilities expense in the Permian Basin.
|
•
|
Louisiana Segment.
Operating expenses in the Louisiana segment
increased
$3.6 million
primarily due to increased regulatory, utilities, and materials and supplies expenses as a result of the start-up of the Ascension JV in April 2017 and higher volumes across our Louisiana assets.
|
•
|
Oklahoma Segment.
Operating expenses in the Oklahoma segment
increased
$12.7 million
primarily due to
increased labor and benefits charges attributable to higher headcount and increased materials and supplies expense as a result of expanded operations.
|
•
|
Crude and Condensate Segment.
Operating expenses in the Crude and Condensate segment
decreased
$3.6 million
primarily due to decreases in third-party transportation charges and labor and benefits expenses.
|
•
|
Unit-based compensation expense decreased $10.7 million primarily due to a higher portion of the annual bonuses being paid in the form of units that vested immediately in March 2017.
|
•
|
Office lease expense decreased $0.9 million.
|
•
|
Salaries and wages expense increased $3.4 million due to a higher portion of the annual bonus being paid in cash during 2018.
|
|
Six Months Ended
June 30, |
||||||
|
2018
|
|
2017
|
||||
Senior notes
|
$
|
80.0
|
|
|
$
|
75.0
|
|
Credit facility
|
8.3
|
|
|
5.9
|
|
||
Capitalized interest
|
(2.8
|
)
|
|
(4.0
|
)
|
||
Amortization of debt issue costs and net discounts (premium)
|
2.4
|
|
|
14.3
|
|
||
Other
|
(0.5
|
)
|
|
0.4
|
|
||
Total
|
$
|
87.4
|
|
|
$
|
91.6
|
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
Operating cash flows before working capital
|
$
|
448.4
|
|
|
$
|
346.6
|
|
Changes in working capital
|
(17.7
|
)
|
|
(14.4
|
)
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
Growth capital expenditures
|
$
|
(385.9
|
)
|
|
$
|
(458.1
|
)
|
Maintenance capital expenditures
|
(18.5
|
)
|
|
(13.6
|
)
|
||
Proceeds from sale of unconsolidated affiliate investment
|
—
|
|
|
189.7
|
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
Net borrowings on credit facility
|
$
|
520.0
|
|
|
$
|
46.0
|
|
Unsecured senior notes borrowings, net of notes extinguished
|
—
|
|
|
331.6
|
|
||
Proceeds from issuance of common units
|
0.9
|
|
|
72.2
|
|
||
Contributions by non-controlling interests
|
81.6
|
|
|
71.5
|
|
||
Payment of installment payable for EOGP acquisition
|
(250.0
|
)
|
|
(250.0
|
)
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
Common units
|
$
|
275.0
|
|
|
$
|
270.4
|
|
General partner interest (including incentive distribution rights)
|
30.9
|
|
|
30.4
|
|
||
Distributions to non-controlling interests
|
23.4
|
|
|
8.3
|
|
||
Distributions to Series B Preferred Units
|
32.2
|
|
|
—
|
|
||
Distributions to Series C Preferred Units
|
12.0
|
|
|
—
|
|
|
Remainder of
|
|
|
2018
|
|
Growth Capital Expenditures
|
|
|
Texas segment
|
$
|
135 - 165
|
Louisiana segment
|
|
35 - 45
|
Oklahoma segment (1)
|
|
183 - 223
|
Crude and Condensate segment
|
|
72 - 102
|
Corporate segment
|
|
3 - 8
|
Total growth capital expenditures
|
$
|
428 - 543
|
Less: Growth capital expenditures funded by joint venture partners (2)
|
|
(51 - 96)
|
Growth capital expenditures, attributable to ENLK
|
$
|
377 - 447
|
|
|
|
Maintenance Capital Expenditures
|
$
|
32 - 37
|
(1)
|
Includes projected growth capital contributions related to our non-controlling interest share of the Cedar Cove JV.
|
(2)
|
Includes growth capital expenditures that will be contributed by other entities and relate to the non-controlling interest share of our consolidated entities. These contributions include contributions by ENLC to EOGP, contributions by NGP to the Delaware Basin JV, and contributions by Marathon Petroleum Corporation to the Ascension JV.
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
Remainder 2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
||||||||||||||
Long-term debt obligations (1)
|
$
|
3,500.0
|
|
|
$
|
—
|
|
|
$
|
400.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,100.0
|
|
Credit facility
|
520.0
|
|
|
—
|
|
|
—
|
|
|
520.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Interest payable on fixed long-term debt obligations
|
2,493.4
|
|
|
79.9
|
|
|
154.5
|
|
|
149.2
|
|
|
149.2
|
|
|
149.2
|
|
|
1,811.4
|
|
|||||||
Capital lease obligations
|
3.6
|
|
|
0.8
|
|
|
1.5
|
|
|
1.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Operating lease obligations
|
103.8
|
|
|
7.9
|
|
|
11.5
|
|
|
8.6
|
|
|
8.6
|
|
|
8.6
|
|
|
58.6
|
|
|||||||
Purchase obligations
|
44.6
|
|
|
44.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Delivery contract obligation
|
17.9
|
|
|
8.9
|
|
|
9.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Pipeline capacity and deficiency agreements (2)
|
166.4
|
|
|
15.2
|
|
|
33.2
|
|
|
22.8
|
|
|
22.8
|
|
|
22.4
|
|
|
50.0
|
|
|||||||
Inactive easement commitment (3)
|
10.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10.0
|
|
|
—
|
|
|||||||
Total contractual obligations
|
$
|
6,859.7
|
|
|
$
|
157.3
|
|
|
$
|
609.7
|
|
|
$
|
701.9
|
|
|
$
|
180.6
|
|
|
$
|
190.2
|
|
|
$
|
5,020.0
|
|
(1)
|
On April 1, 2019, $400.0 million in aggregate principal amount of
our
2.7% senior unsecured notes will mature.
|
(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
|
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, 2018
, approximately
1.3%
of our contracts, based on gross operating margin, were under processing margin contracts.
|
3.
|
POL contracts:
Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under POL contracts, but they do decline during periods of low liquids prices.
|
4.
|
POP contracts
: Under these contracts, we receive a fee in the form of a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under POP contracts, but they do decline during periods of low natural gas and liquids prices.
|
Period
|
|
Underlying
|
|
Notional Volume
|
|
We Pay
|
|
We Receive (1)
|
|
Fair Value
Asset/(Liability)
(In millions)
|
||
July 2018 - June 2019
|
|
Ethane
|
|
425 (MBbls)
|
|
$0.3051/gal
|
|
Index
|
|
$
|
0.5
|
|
July 2018 - June 2019
|
|
Propane
|
|
767 (MBbls)
|
|
Index
|
|
$0.8676/gal
|
|
(5.1
|
)
|
|
July 2018 - June 2019
|
|
Normal Butane
|
|
244 (MBbls)
|
|
Index
|
|
$0.9623/gal
|
|
(1.3
|
)
|
|
July 2018 - June 2019
|
|
Natural Gasoline
|
|
107 (MBbls)
|
|
Index
|
|
$1.4054/gal
|
|
(0.9
|
)
|
|
July 2018 - October 2019
|
|
Natural Gas
|
|
45,989 (MMBtu/d)
|
|
Index
|
|
$2.183/MMBtu
|
|
(1.0
|
)
|
|
August 2018 - December 2021
|
|
Crude and condensate
|
|
7,650 (MBbls)
|
|
Index
|
|
$59.53/bbl
|
|
(7.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(15.6
|
)
|
(1)
|
Weighted average.
|
(a)
|
Evaluation of Disclosure Controls and Procedures
|
(b)
|
Changes in Internal Control Over Financial Reporting
|
•
|
our partnership agreement limits our general partner’s liability and reduces its fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner;
|
•
|
in resolving conflicts of interest, our general partner is allowed to take into account the interests of parties in addition to unitholders, which has the effect of limiting its fiduciary duties to the unitholders;
|
•
|
our general partner’s affiliates may engage in competition with us;
|
•
|
our general partner decides whether to retain separate counsel, accountants, or others to perform services for us;
|
•
|
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests, and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is available to distribute to unitholders;
|
•
|
our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as an operating expense, which reduces operating surplus, or capital improvement, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner;
|
•
|
our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
|
•
|
our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the Series B Preferred Units, the Series C Preferred Units, or to make incentive distributions; and
|
•
|
our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.
|
Period
|
|
Total Number of Units Purchased (1)
|
|
Average Price Paid Per Unit
|
|
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Number of Units that May Yet Be Purchased under the Plans or Programs
|
|||||
April 1, 2018 to April 30, 2018
|
|
4,449
|
|
|
$
|
13.64
|
|
|
—
|
|
|
—
|
|
May 1, 2018 to May 31, 2018
|
|
69
|
|
|
15.01
|
|
|
—
|
|
|
—
|
|
|
June 1, 2018 to June 30, 2018
|
|
3,107
|
|
|
17.14
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
7,625
|
|
|
$
|
15.08
|
|
|
—
|
|
|
—
|
|
Number
|
|
Description
|
3.1
|
—
|
|
3.2
|
—
|
|
3.3
|
—
|
|
3.4
|
—
|
|
3.5
|
—
|
|
3.6
|
—
|
|
3.7
|
—
|
|
3.8
|
—
|
|
3.9
|
—
|
|
10.1
|
—
|
|
10.2
|
—
|
|
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, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017, (ii) Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017, (iii) Consolidated Statements of Changes in Partners’ Equity for the six months ended June 30, 2018, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017, and (v) the Notes to Consolidated Financial Statements.
|
*
|
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 1, 2018
|
|
|
1 Year EnLink Midstream Partners, LP Chart |
1 Month EnLink Midstream Partners, LP Chart |
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