Delaware | 46-4108528 |
(State of organization) | (I.R.S. Employer Identification No.) |
1722 Routh St., Suite 1300 | |
Dallas, Texas | 75201 |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer | ý | Accelerated filer | ¨ | |
Non-accelerated filer | ¨ | Smaller reporting company | ¨ | |
(Do not check if a smaller reporting company) | Emerging growth company | ¨ |
Item | Description | Page | ||
Defined Term | Definition | |
/d | Per day. | |
2017 EDA | 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. | |
AMZ | Alerian MLP Index for Master Limited Partnerships. | |
ASC | The FASB Accounting Standards Codification. | |
ASC 606 | ASC 606, Revenue from Contracts with Customers. | |
ASU | The FASB Accounting Standards Update. | |
Ascension JV | 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. | |
Bbls | Barrels. | |
Bcf | Billion cubic feet. | |
Cedar Cove JV | 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. | |
CFTC | U.S. Commodity Futures Trading Commission. | |
CNOW | Central Northern Oklahoma Woodford Shale. | |
Devon | Devon Energy Corporation. | |
Delaware Basin JV | 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. | |
ENLC | EnLink Midstream, LLC. | |
ENLC Credit Facility | A $250.0 million revolving credit facility entered into by ENLC that matures on March 7, 2019, which includes a $125.0 million letter of credit subfacility. | |
ENLK | EnLink Midstream Partners, LP or EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.” | |
ENLK Credit Facility | A $1.5 billion unsecured revolving credit facility entered into by ENLK that matures on March 6, 2020, which includes a $500.0 million letter of credit subfacility. | |
EOGP | 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. | |
FASB | Financial Accounting Standards Board. | |
FERC | Federal Energy Regulatory Commission. | |
GAAP | Generally accepted accounting principles in the United States of America. | |
Gal | Gallons. | |
GCF | Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF. | |
General Partner | EnLink Midstream GP, LLC, the general partner of ENLK, which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK. | |
GIP | 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. | |
Greater Chickadee | Crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin. | |
Gross Operating Margin | 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. | |
HEP | Howard Energy Partners. ENLK sold its 31% ownership interest in HEP in March 2017. | |
ISDAs | International Swaps and Derivatives Association Agreements. |
Mcf | Thousand cubic feet. | |
MMbtu | Million British thermal units. | |
MMcf | Million cubic feet. | |
MVC | Minimum volume commitment. | |
NGL | Natural gas liquid. | |
NGP | NGP Natural Resources XI, LP, an affiliate of ENLK’s joint venture partner in the Delaware Basin JV. | |
Operating Partnership | EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK. | |
ORV | ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales. | |
OTC | Over-the-counter. | |
Permian Basin | A large sedimentary basin that includes the Midland and Delaware Basins in West Texas. | |
POL contracts | Percentage-of-liquids contracts. | |
POP contracts | Percentage-of-proceeds contracts. | |
Series B Preferred Units | ENLK’s Series B Cumulative Convertible Preferred Units. | |
Series C Preferred Units | ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units. | |
STACK | Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma. | |
VEX | ENLK’s Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas. |
June 30, 2018 | December 31, 2017 | ||||||
(Unaudited) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 36.8 | $ | 31.2 | |||
Accounts receivable: | |||||||
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively | 73.2 | 50.1 | |||||
Accrued revenue and other | 579.4 | 576.6 | |||||
Related party | 122.7 | 102.8 | |||||
Fair value of derivative assets | 4.0 | 6.8 | |||||
Natural gas and NGLs inventory, prepaid expenses, and other | 99.1 | 41.2 | |||||
Total current assets | 915.2 | 808.7 | |||||
Property and equipment, net of accumulated depreciation of $2,745.8 and $2,533.0, respectively | 6,763.2 | 6,587.0 | |||||
Intangible assets, net of accumulated amortization of $360.4 and $298.7, respectively | 1,435.4 | 1,497.1 | |||||
Goodwill | 1,542.2 | 1,542.2 | |||||
Investment in unconsolidated affiliates | 85.5 | 89.4 | |||||
Other assets, net | 42.1 | 13.4 | |||||
Total assets | $ | 10,783.6 | $ | 10,537.8 | |||
LIABILITIES AND MEMBERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and drafts payable | $ | 115.2 | $ | 66.9 | |||
Accounts payable to related party | 30.5 | 16.3 | |||||
Accrued gas, NGLs, condensate, and crude oil purchases | 509.2 | 476.1 | |||||
Fair value of derivative liabilities | 10.7 | 8.4 | |||||
Installment payable, net of discount of $0.5 at December 31, 2017 | — | 249.5 | |||||
Current maturities of long-term debt | 483.7 | — | |||||
Other current liabilities | 206.4 | 222.9 | |||||
Total current liabilities | 1,355.7 | 1,040.1 | |||||
Long-term debt | 3,590.2 | 3,542.1 | |||||
Asset retirement obligations | 14.5 | 14.2 | |||||
Other long-term liabilities | 21.2 | 33.9 | |||||
Deferred tax liability | 358.0 | 346.2 | |||||
Fair value of derivative liabilities | 8.9 | — | |||||
Redeemable non-controlling interest | 4.6 | 4.6 | |||||
Members’ equity: | |||||||
Members’ equity (181,051,875 and 180,600,728 units issued and outstanding, respectively) | 1,871.9 | 1,924.2 | |||||
Accumulated other comprehensive loss | (2.0 | ) | (2.0 | ) | |||
Non-controlling interest | 3,560.6 | 3,634.5 | |||||
Total members’ equity | 5,430.5 | 5,556.7 | |||||
Total liabilities and members’ equity | $ | 10,783.6 | $ | 10,537.8 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(Unaudited) | |||||||||||||||
Revenues: | |||||||||||||||
Product sales | $ | 1,435.1 | $ | 927.2 | $ | 2,934.3 | $ | 1,917.2 | |||||||
Product sales—related parties | 27.2 | 29.3 | 30.8 | 72.0 | |||||||||||
Midstream services | 142.4 | 131.9 | 234.6 | 259.3 | |||||||||||
Midstream services—related parties | 175.2 | 173.6 | 341.4 | 332.6 | |||||||||||
Gain (loss) on derivative activity | (15.2 | ) | 1.6 | (14.7 | ) | 4.4 | |||||||||
Total revenues | 1,764.7 | 1,263.6 | 3,526.4 | 2,585.5 | |||||||||||
Operating costs and expenses: | |||||||||||||||
Cost of sales (1) | 1,325.6 | 932.4 | 2,707.1 | 1,934.7 | |||||||||||
Operating expenses | 113.4 | 102.6 | 222.6 | 206.7 | |||||||||||
General and administrative | 30.4 | 31.1 | 57.9 | 67.2 | |||||||||||
(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 | ) | |||||||||
Total operating costs and expenses | 1,615.9 | 1,194.7 | 3,272.3 | 2,460.1 | |||||||||||
Operating income | 148.8 | 68.9 | 254.1 | 125.4 | |||||||||||
Other income (expense): | |||||||||||||||
Interest expense, net of interest income | (44.6 | ) | (47.7 | ) | (89.1 | ) | (92.6 | ) | |||||||
Gain on extinguishment of debt | — | 9.0 | — | 9.0 | |||||||||||
Income (loss) from unconsolidated affiliates | 4.4 | (0.1 | ) | 7.4 | 0.6 | ||||||||||
Other income (expense) | (0.1 | ) | 0.2 | 0.2 | 0.2 | ||||||||||
Total other expense | (40.3 | ) | (38.6 | ) | (81.5 | ) | (82.8 | ) | |||||||
Income before non-controlling interest and income taxes | 108.5 | 30.3 | 172.6 | 42.6 | |||||||||||
Income tax provision | (6.3 | ) | (3.2 | ) | (13.3 | ) | (6.2 | ) | |||||||
Net income | 102.2 | 27.1 | 159.3 | 36.4 | |||||||||||
Net income attributable to non-controlling interest | 74.2 | 21.2 | 118.9 | 32.4 | |||||||||||
Net income attributable to ENLC | $ | 28.0 | $ | 5.9 | $ | 40.4 | $ | 4.0 | |||||||
Net income attributable to ENLC per unit: | |||||||||||||||
Basic common unit | $ | 0.15 | $ | 0.03 | $ | 0.22 | $ | 0.02 | |||||||
Diluted common unit | $ | 0.15 | $ | 0.03 | $ | 0.22 | $ | 0.02 |
(1) | 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. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(Unaudited) | |||||||||||||||
Net income | $ | 102.2 | $ | 27.1 | $ | 159.3 | $ | 36.4 | |||||||
Loss on designated cash flow hedge, net of tax benefit of $0.2 million for the three and six months ended June 30, 2017 | — | (2.0 | ) | — | (2.0 | ) | |||||||||
Comprehensive income | 102.2 | 25.1 | 159.3 | 34.4 | |||||||||||
Comprehensive income attributable to non-controlling interest | 74.2 | 19.6 | 118.9 | 30.8 | |||||||||||
Comprehensive income attributable to EnLink Midstream, LLC | $ | 28.0 | $ | 5.5 | $ | 40.4 | $ | 3.6 |
Common Units | Accumulated Other Comprehensive Loss | Non-Controlling Interest | Total | Redeemable Non-Controlling Interest (Temporary Equity) | ||||||||||||||||||
$ | Units | $ | $ | $ | $ | |||||||||||||||||
(Unaudited) | ||||||||||||||||||||||
Balance, December 31, 2017 | $ | 1,924.2 | 180.6 | $ | (2.0 | ) | $ | 3,634.5 | $ | 5,556.7 | $ | 4.6 | ||||||||||
Issuance of common units by ENLK | — | — | — | 0.9 | 0.9 | — | ||||||||||||||||
Conversion of restricted units for common units, net of units withheld for taxes | (3.5 | ) | 0.5 | — | — | (3.5 | ) | — | ||||||||||||||
Non-controlling interest’s impact of conversion of restricted units | — | — | — | (3.4 | ) | (3.4 | ) | — | ||||||||||||||
Unit-based compensation | 8.4 | — | — | 8.4 | 16.8 | — | ||||||||||||||||
Change in equity due to issuance of units by ENLK | (1.9 | ) | — | — | 2.5 | 0.6 | — | |||||||||||||||
Contributions from non-controlling interests | — | — | — | 54.3 | 54.3 | — | ||||||||||||||||
Distributions | (95.7 | ) | — | — | (255.5 | ) | (351.2 | ) | — | |||||||||||||
Net income | 40.4 | — | — | 118.9 | 159.3 | — | ||||||||||||||||
Balance, June 30, 2018 | $ | 1,871.9 | 181.1 | $ | (2.0 | ) | $ | 3,560.6 | $ | 5,430.5 | $ | 4.6 |
Six Months Ended June 30, | |||||||
2018 | 2017 | ||||||
(Unaudited) | |||||||
Cash flows from operating activities: | |||||||
Net income | $ | 159.3 | $ | 36.4 | |||
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 | 14.7 | 28.7 | |||||
(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 | 2.5 | 14.3 | |||||
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 | 13.2 | 5.8 | |||||
Changes in assets and liabilities, net of assets acquired and liabilities assumed: | |||||||
Accounts receivable, accrued revenue, and other | (46.7 | ) | 56.2 | ||||
Natural gas and NGLs inventory, prepaid expenses, and other | (40.1 | ) | (34.0 | ) | |||
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities | 72.1 | (36.1 | ) | ||||
Net cash provided by operating activities | 429.3 | 329.1 | |||||
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 | 1,361.8 | 1,800.2 | |||||
Payments on borrowings | (832.0 | ) | (1,384.9 | ) | |||
Payment of installment payable for EOGP acquisition | (250.0 | ) | (250.0 | ) | |||
Debt financing costs | — | (5.7 | ) | ||||
Conversion of restricted units, net of units withheld for taxes | (3.5 | ) | (4.8 | ) | |||
Conversion of ENLK's restricted units, net of units withheld for taxes | (3.4 | ) | (5.1 | ) | |||
Proceeds from issuance of ENLK common units | 0.9 | 72.2 | |||||
Distribution to members | (95.7 | ) | (92.9 | ) | |||
Distributions to non-controlling partners | (255.5 | ) | (202.9 | ) | |||
Contributions by non-controlling interests | 54.3 | 28.5 | |||||
Other financing activities | 1.2 | (0.4 | ) | ||||
Net cash used in financing activities | (21.9 | ) | (45.8 | ) | |||
Net increase (decrease) in cash and cash equivalents | 5.6 | (0.3 | ) | ||||
Cash and cash equivalents, beginning of period | 31.2 | 11.7 | |||||
Cash and cash equivalents, end of period | $ | 36.8 | $ | 11.4 | |||
Supplemental disclosures of cash flow information: | |||||||
Cash paid for interest | $ | 89.1 | $ | 79.1 | |||
Cash paid for income taxes | $ | 0.4 | $ | 3.6 | |||
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 |
• | 88,528,451 common units representing an aggregate 21.6% limited partner interest in ENLK; |
• | 100% ownership interest in the General Partner of ENLK, which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK; and |
• | 16.1% limited partner interest in EOGP |
(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 |
(c) | Accounting Standards to be Adopted in Future Periods |
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 | ||||||||||||||||||
ENLK credit facility due 2020 (1) | $ | 520.0 | $ | — | $ | 520.0 | $ | — | $ | — | $ | — | |||||||||||
ENLC credit facility due 2019 (2) | 84.4 | — | 84.4 | 74.6 | — | 74.6 | |||||||||||||||||
ENLK’s 2.70% Senior unsecured notes due 2019 | 400.0 | (0.1 | ) | 399.9 | 400.0 | (0.1 | ) | 399.9 | |||||||||||||||
ENLK’s 4.40% Senior unsecured notes due 2024 | 550.0 | 2.0 | 552.0 | 550.0 | 2.2 | 552.2 | |||||||||||||||||
ENLK’s 4.15% Senior unsecured notes due 2025 | 750.0 | (0.9 | ) | 749.1 | 750.0 | (1.0 | ) | 749.0 | |||||||||||||||
ENLK’s 4.85% Senior unsecured notes due 2026 | 500.0 | (0.6 | ) | 499.4 | 500.0 | (0.6 | ) | 499.4 | |||||||||||||||
ENLK’s 5.60% Senior unsecured notes due 2044 | 350.0 | (0.2 | ) | 349.8 | 350.0 | (0.2 | ) | 349.8 | |||||||||||||||
ENLK’s 5.05% Senior unsecured notes due 2045 | 450.0 | (6.3 | ) | 443.7 | 450.0 | (6.5 | ) | 443.5 | |||||||||||||||
ENLK's 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 | $ | 4,104.4 | $ | (6.2 | ) | $ | 4,098.2 | $ | 3,574.6 | $ | (6.3 | ) | $ | 3,568.3 | |||||||||
Debt issuance cost (3) | (24.3 | ) | (26.2 | ) | |||||||||||||||||||
Less: Current maturities of long-term debt (4) | (483.7 | ) | — | ||||||||||||||||||||
Long-term debt, net of unamortized issuance cost | $ | 3,590.2 | $ | 3,542.1 |
(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) | Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.9% and 3.2% at June 30, 2018 and December 31, 2017, respectively. |
(3) | Net of amortization of $14.8 million and $12.9 million at June 30, 2018 and December 31, 2017, respectively. |
(4) | The outstanding balance, net of debt issuance costs, of the ENLC Credit Facility and ENLK’s 2.70% senior unsecured notes as of June 30, 2018 are classified as “Current maturities of long-term debt” on the consolidated balance sheet as the ENLC Credit Facility matures on March 7, 2019, and ENLK’s 2.70% senior unsecured notes mature on April 1, 2019. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Current income tax provision (benefit) | $ | (0.3 | ) | $ | (1.0 | ) | $ | 0.9 | $ | (0.2 | ) | ||||
Deferred income tax provision | 6.6 | 4.2 | $ | 12.4 | $ | 6.4 | |||||||||
Total income tax provision | $ | 6.3 | $ | 3.2 | $ | 13.3 | $ | 6.2 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Expected income tax provision based on federal statutory rate (1) | $ | 7.2 | $ | 3.1 | $ | 11.3 | $ | 3.5 | |||||||
State income taxes expense, net of federal tax benefit | 0.8 | 0.3 | 1.3 | 0.3 | |||||||||||
Income tax expense (benefit) from ENLK | (2.0 | ) | (0.3 | ) | (1.0 | ) | 0.2 | ||||||||
Unit-based compensation | (0.1 | ) | — | 1.5 | 2.3 | ||||||||||
Other | 0.4 | 0.1 | 0.2 | (0.1 | ) | ||||||||||
Total income tax provision | $ | 6.3 | $ | 3.2 | $ | 13.3 | $ | 6.2 |
(1) | The statutory federal tax rate for corporations was 21% at June 30, 2018 and 35% at June 30, 2017. |
(a) | Issuance of ENLK 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) | ENLK Series C Preferred Units |
(d) | ENLK 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) | Allocation of ENLK Income |
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 | ||||||||||||
ENLC interest in net income | $ | 28.0 | $ | 5.9 | $ | 40.4 | $ | 4.0 | |||||||
Distributed earnings allocated to: | |||||||||||||||
Common units (1) (2) | $ | 48.3 | $ | 46.1 | $ | 95.9 | $ | 92.0 | |||||||
Unvested restricted units (1) (2) | 0.8 | 0.6 | 1.3 | 1.2 | |||||||||||
Total distributed earnings | $ | 49.1 | $ | 46.7 | $ | 97.2 | $ | 93.2 | |||||||
Undistributed loss allocated to: | |||||||||||||||
Common units | $ | (20.8 | ) | $ | (40.3 | ) | $ | (56.1 | ) | $ | (88.1 | ) | |||
Unvested restricted units | (0.3 | ) | (0.5 | ) | (0.7 | ) | (1.1 | ) | |||||||
Total undistributed loss | $ | (21.1 | ) | $ | (40.8 | ) | $ | (56.8 | ) | $ | (89.2 | ) | |||
Net income allocated to: | |||||||||||||||
Common units | $ | 27.5 | $ | 5.8 | $ | 39.8 | $ | 3.9 | |||||||
Unvested restricted units | 0.5 | 0.1 | 0.6 | 0.1 | |||||||||||
Total net income | $ | 28.0 | $ | 5.9 | $ | 40.4 | $ | 4.0 | |||||||
Basic and diluted net income per unit: | |||||||||||||||
Basic | $ | 0.15 | $ | 0.03 | $ | 0.22 | $ | 0.02 | |||||||
Diluted | $ | 0.15 | $ | 0.03 | $ | 0.22 | $ | 0.02 |
(1) | For the three months ended June 30, 2018 and 2017, distributed earnings represent a declared distribution of $0.267 per unit payable on August 14, 2018 and a distribution of $0.255 per unit paid on August 14, 2017, respectively. |
(2) | For the six months ended June 30, 2018, distributed earnings included a distribution of $0.263 per unit paid on May 15, 2018 and a declared distribution of $0.267 per unit payable on August 14, 2018. For the six months ended June 30, 2017, distributed earnings included distributions of $0.255 per unit paid on May 15, 2017 and $0.255 per unit paid on August 14, 2017. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Basic weighted average units outstanding: | |||||||||||
Weighted average common units outstanding | 181.0 | 180.6 | 181.0 | 180.4 | |||||||
Diluted weighted average units outstanding: | |||||||||||
Weighted average basic common units outstanding | 181.0 | 180.6 | 181.0 | 180.4 | |||||||
Dilutive effect of non-vested restricted units | 1.2 | 1.1 | 1.0 | 1.2 | |||||||
Total weighted average diluted common units outstanding | 182.2 | 181.7 | 182.0 | 181.6 |
Declaration period | Distribution/unit | Date paid/payable | ||||
2018 | ||||||
Fourth Quarter of 2017 | $ | 0.259 | February 14, 2018 | |||
First Quarter of 2018 | $ | 0.263 | May 15, 2018 | |||
Second Quarter 2018 | $ | 0.267 | August 14, 2018 | |||
2017 | ||||||
Fourth Quarter of 2016 | $ | 0.255 | February 14, 2017 | |||
First Quarter of 2017 | $ | 0.255 | May 15, 2017 | |||
Second Quarter 2017 | $ | 0.255 | August 14, 2017 |
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 | 7.3 | 6.7 | 10.4 | 21.1 | |||||||||||
Total unit-based compensation expense | $ | 9.6 | $ | 9.3 | $ | 14.7 | $ | 28.7 | |||||||
Non-controlling interest in unit-based compensation | $ | 3.6 | $ | 3.5 | $ | 5.5 | $ | 10.8 | |||||||
Amount of related income tax benefit recognized in net income (1) | $ | 1.2 | $ | 2.1 | $ | 1.9 | $ | 6.7 |
(1) | For the three and six months ended June 30, 2018, the amount of related income tax benefit recognized in net income excluded $0.1 million of income tax benefit and $1.5 million of income tax expense, respectively, related to tax deficiencies recorded upon vesting of restricted units. For the six months ended June 30, 2017, the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related to tax deficiencies recorded upon vesting of restricted units. There was no income tax expense or benefit related to tax deficiencies recorded upon vesting of restricted units for the three months ended June 30, 2017. |
(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, ENLK 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. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
EnLink Midstream, LLC Restricted Incentive Units: | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Aggregate intrinsic value of units vested | $ | 0.4 | $ | 0.3 | $ | 9.3 | $ | 14.6 | ||||||||
Fair value of units vested | $ | 0.4 | $ | 0.4 | $ | 13.5 | $ | 20.8 |
(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) | $ | 4,073.9 | $ | 3,795.2 | $ | 3,542.1 | $ | 3,650.2 | |||||||
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 $24.3 million and $26.2 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 | $ | — | $ | 1,119.9 | $ | 1,542.2 | |||||||||||
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 | $ | — | $ | 1,119.9 | $ | 1,542.2 | |||||||||||
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 | $ | — | $ | 1,119.9 | $ | 1,542.2 | |||||||||||
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 | $ | — | $ | 1,119.9 | $ | 1,542.2 | |||||||||||
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 | 1,254.4 | 1,268.3 | |||||
Total identifiable assets | $ | 10,783.6 | $ | 10,537.8 |
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 | (30.4 | ) | (31.1 | ) | (57.9 | ) | (67.2 | ) | |||||||
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 | $ | 148.8 | $ | 68.9 | $ | 254.1 | $ | 125.4 |
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 of $1.6 | 17.9 | — | ||||||
Prepaid expenses and other | 20.4 | 11.1 | ||||||
Natural gas and NGLs inventory, prepaid expenses, and other | $ | 99.1 | $ | 41.2 |
Other Current Liabilities: | June 30, 2018 | December 31, 2017 | ||||||
Accrued interest | $ | 36.6 | $ | 35.6 | ||||
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 | 66.2 | 65.1 | ||||||
Other current liabilities | $ | 206.4 | $ | 222.9 |
• | 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. |
• | 88,528,451 common units representing an aggregate 21.6% limited partner interest in ENLK; |
• | 100.0% ownership interest in the General Partner of ENLK, which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK; and |
• | 16.1% limited partner interest in EOGP |
• | 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, goodwill, 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. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Distribution declared by ENLK associated with (1): | ||||||||||||||||
General partner interest | $ | 0.6 | $ | 0.7 | $ | 1.2 | $ | 1.3 | ||||||||
Incentive distribution rights | 14.8 | 14.6 | 29.6 | 29.3 | ||||||||||||
ENLK common units owned | 34.6 | 34.6 | 69.1 | 69.1 | ||||||||||||
Total share of ENLK distributions declared | 50.0 | 49.9 | 99.9 | 99.7 | ||||||||||||
Adjusted EBITDA of EOGP (2) | 10.3 | 5.1 | 19.2 | 7.7 | ||||||||||||
Total cash available | 60.3 | 55.0 | 119.1 | 107.4 | ||||||||||||
Uses of cash: | ||||||||||||||||
General and administrative expenses | (1.3 | ) | (1.6 | ) | (2.5 | ) | (2.6 | ) | ||||||||
Current income taxes (3) | (0.1 | ) | (0.2 | ) | (0.2 | ) | (0.2 | ) | ||||||||
Interest expense | (0.9 | ) | (0.6 | ) | (1.7 | ) | (1.0 | ) | ||||||||
Maintenance capital expenditures (4) | (0.1 | ) | — | (0.2 | ) | — | ||||||||||
Total cash used | (2.4 | ) | (2.4 | ) | (4.6 | ) | (3.8 | ) | ||||||||
ENLC cash available for distribution | $ | 57.9 | $ | 52.6 | $ | 114.5 | $ | 103.6 |
(1) | Represents distributions declared by ENLK and to be paid to ENLC on August 13, 2018 and distributions paid by ENLK to ENLC on May 14, 2018, August 11, 2017, and May 12, 2017. |
(2) | Represents ENLC’s interest in EOGP adjusted EBITDA, which is disbursed to ENLC by EOGP on a monthly basis. EOGP adjusted EBITDA is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from ENLK. |
(3) | Represents ENLC’s stand-alone current tax expense. |
(4) | Represents ENLC’s interest in EOGP’s maintenance capital expenditures which is netted against the monthly disbursement of EOGP’s adjusted EBITDA per (2) above. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Net income of ENLC | $ | 102.2 | $ | 27.1 | $ | 159.3 | $ | 36.4 | ||||||||
Less: Net income attributable to ENLK | 98.9 | 29.6 | 159.0 | 47.7 | ||||||||||||
Net income (loss) of ENLC excluding ENLK | 3.3 | (2.5 | ) | 0.3 | (11.3 | ) | ||||||||||
ENLC's share of distributions from ENLK (1) | 50.0 | 49.9 | 99.9 | 99.7 | ||||||||||||
ENLC's interest in EOGP's non-cash expenses (2) | (2.3 | ) | 4.2 | 2.4 | 8.2 | |||||||||||
ENLC deferred income tax expense (3) | 8.4 | 3.3 | 14.2 | 5.8 | ||||||||||||
Non-controlling interest share of ENLK's net (income) loss (4) | (1.4 | ) | (2.2 | ) | (2.1 | ) | 1.2 | |||||||||
Other items (5) | (0.1 | ) | (0.1 | ) | (0.2 | ) | — | |||||||||
ENLC cash available for distribution | $ | 57.9 | $ | 52.6 | $ | 114.5 | $ | 103.6 |
(1) | Represents distributions declared by ENLK and to be paid to ENLC on August 13, 2018 and distributions paid by ENLK to ENLC on May 14, 2018, August 11, 2017, and May 12, 2017. |
(2) | Includes depreciation and amortization, unit-based compensation expense allocated to EOGP, gains and losses on sale of property, and non-cash revenue recognized upon receipt of secured term loan receivable related to contract restructuring (as discussed in “Item 1. Financial Statements—Note 2”). |
(3) | Represents ENLC’s stand-alone deferred taxes. |
(4) | Represents NGP’s 49.9% share of the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of the Ascension JV, and other minor non-controlling interests. |
(5) | Represents ENLC’s interest in EOGP’s maintenance capital expenditures (which is netted against the monthly disbursement of EOGP’s adjusted EBITDA) and other non-cash items not included in cash available for distribution. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Operating income | $ | 148.8 | $ | 68.9 | 254.1 | $ | 125.4 | |||||||||
Add (deduct): | ||||||||||||||||
Operating expenses | 113.4 | 102.6 | 222.6 | 206.7 | ||||||||||||
General and administrative expenses | 30.4 | 31.1 | 57.9 | 67.2 | ||||||||||||
(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 | |||||||
ENLK senior notes | $ | 40.0 | $ | 38.9 | ||||
ENLK Credit Facility | 4.9 | 2.5 | ||||||
ENLC Credit Facility | 0.9 | 0.5 | ||||||
Capitalized interest | (1.6 | ) | (1.4 | ) | ||||
Amortization of debt issue costs and net discounts | 0.9 | 7.1 | ||||||
Other | (0.5 | ) | 0.1 | |||||
Total | $ | 44.6 | $ | 47.7 |
• | 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 months ended June 30, 2018, the shortfall revenue from Devon-related MVCs was $38.9 million compared to $26.2 million for the six months ended June 30, 2017. |
• | 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 | ||||||
ENLK senior notes | $ | 80.0 | $ | 75.0 | |||
ENLK Credit Facility | 8.3 | 5.9 | |||||
ENLC Credit Facility | 1.6 | 0.9 | |||||
Capitalized interest | (2.9 | ) | (4.0 | ) | |||
Amortization of debt issue cost and net discounts (premium) | 2.5 | 14.4 | |||||
Other | (0.4 | ) | 0.4 | ||||
Total | $ | 89.1 | $ | 92.6 |
Six Months Ended June 30, | |||||||
2018 | 2017 | ||||||
Operating cash flows before working capital | $ | 444.0 | $ | 343.0 | |||
Changes in working capital | (14.7 | ) | (13.9 | ) |
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 the ENLK Credit Facility | $ | 520.0 | $ | 46.0 | |||
Net borrowings on the ENLC Credit Facility | 9.8 | 37.7 | |||||
ENLK unsecured senior notes borrowings, net of notes extinguished | — | 331.6 | |||||
Proceeds from issuance of ENLK common units | 0.9 | 72.2 | |||||
Contributions by non-controlling interests | 54.3 | 28.5 | |||||
Payment of installment payable for EOGP acquisition | (250.0 | ) | (250.0 | ) |
Six Months Ended June 30, | |||||||
2018 | 2017 | ||||||
Distributions to members | $ | 95.7 | $ | 92.9 | |||
Distributions to non-controlling interests | 255.5 | 202.9 |
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) | (44 - 59) | |
Growth capital expenditures, attributable to ENLC | $ | 384 - 484 |
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 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 | |||||||||||||
ENLK Credit Facility | 520.0 | — | — | 520.0 | — | — | — | ||||||||||||||||||||
ENLC Credit Facility | 84.4 | — | 84.4 | — | — | — | — | ||||||||||||||||||||
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 | $ | 6,944.1 | $ | 157.3 | $ | 694.1 | $ | 701.9 | $ | 180.6 | $ | 190.2 | $ | 5,020.0 |
(1) | On April 1, 2019, $400.0 million in aggregate principal amount of ENLK’s 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 |
• | neither our operating agreement nor any other agreement requires GIP to pursue a business strategy that favors us, to enter into any commercial agreements with us or ENLK, or to sell any assets to us or ENLK. GIP’s officers have a fiduciary duty to make decisions in the best interests of the owners of GIP, which may be contrary to our interests; |
• | the Managing Member determines the amount and timing of asset purchases and sales, borrowings, issuance of additional membership interests, and the creation, reduction, or increase of reserves, each of which can affect the amount of cash that is available to be distributed to unitholders; |
• | the Managing Member determines which costs incurred by its affiliates are reimbursable by us; |
• | the Managing Member is allowed to take into account the interests of parties other than us in exercising certain rights under our operating agreement, which limits its duties to our unitholders; |
• | our operating agreement limits the liability of, and eliminates and replaces the fiduciary duties that would otherwise be owed by, the Managing Member and also restricts the remedies available to our unitholders for actions that, without the provisions of the operating agreement, might constitute breaches of fiduciary duty; |
• | any future contracts between us, on the one hand, and the Managing Member and its affiliates, on the other, will not be the result of arm’s-length negotiations, and disputes may arise under any such future contracts; |
• | except in limited circumstances, the Managing Member has the power and authority to conduct our business without unitholder approval; |
• | the Managing Member may exercise its right to call and purchase all of ENLC’s outstanding common units not owned by it and its affiliates if it and its affiliates own more than 90% of ENLC’s outstanding common units; |
• | the Managing Member controls the enforcement of obligations owed to us by the Managing Member and its affiliates, including commercial agreements; and |
• | the Managing Member decides whether to retain separate counsel, accountants, or others to perform services for us. |
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 | 3,942 | $ | 14.49 | — | — | ||||||||
May 1, 2018 to May 31, 2018 | 68 | 15.40 | — | — | |||||||||
June 1, 2018 to June 30, 2018 | 3,001 | 17.01 | — | — | |||||||||
Total | 7,011 | $ | 15.58 | — | — |
Number | Description | |
3.1 | — | |
3.2 | — | |
3.3 | — | |
3.4 | — | |
3.5 | — | |
3.6 | — | |
3.7 | — | |
3.8 | — | |
3.9 | — | |
3.10 | — | |
3.11 | — | |
3.12 | — | |
3.13 | — | |
3.14 | — | |
3.15 | — | |
10.1 | — | |
10.2 | — | |
10.3 | — | |
31.1 * | — | |
31.2 * | — | |
32.1 * | — | |
101 * | — | The following financial information from EnLink Midstream, LLC'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 Members’ 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, LLC | ||
By: | EnLink Midstream Manager, LLC, | |
its managing member | ||
By: | /s/ ERIC D. BATCHELDER | |
Eric D. Batchelder | ||
Executive Vice President and Chief Financial Officer | ||
August 1, 2018 |
1. | I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: August 1, 2018 | /s/ MICHAEL J. GARBERDING |
Michael J. Garberding | |
President and Chief Executive Officer | |
(principal executive officer) |
1. | I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
Date: August 1, 2018 | /s/ ERIC D. BATCHELDER |
Eric D. Batchelder | |
Chief Financial Officer | |
(principal financial and accounting officer) |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
Date: August 1, 2018 | /s/ MICHAEL J. GARBERDING |
Michael J. Garberding | |
Chief Executive Officer | |
Date: August 1, 2018 | /s/ ERIC D. BATCHELDER |
Eric D. Batchelder | |
Chief Financial Officer |
Document and Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2018 |
Jul. 26, 2018 |
|
Entity Information [Abstract] | ||
Document Type | 10-Q | |
Document Fiscal Period Focus | Q2 | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2018 | |
Amendment Flag | false | |
Entity Registrant Name | Enlink Midstream, LLC | |
Entity Central Index Key | 0001592000 | |
Entity Current Reporting Status | Yes | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 181,132,896 |
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
ASSETS | ||
Allowance for bad debt | $ 0.3 | $ 0.3 |
Property and equipment, accumulated depreciation | 2,745.8 | 2,533.0 |
Intangible assets, accumulated amortization | 360.4 | 298.7 |
Liabilities: | ||
Current installment payable discount | $ 0.0 | $ 0.5 |
Members’ equity: | ||
Common units issued (in shares) | 181,051,875 | 180,600,728 |
Common units outstanding (in shares) | 181,051,875 | 180,600,728 |
Consolidated Statements of Operations - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||
---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|||
Revenues: | ||||||
Product sales | $ 1,435.1 | $ 927.2 | $ 2,934.3 | $ 1,917.2 | ||
Product sales—related parties | 27.2 | 29.3 | 30.8 | 72.0 | ||
Midstream services | 142.4 | 131.9 | 234.6 | 259.3 | ||
Midstream services—related parties | 175.2 | 173.6 | 341.4 | 332.6 | ||
Gain (loss) on derivative activity | (15.2) | 1.6 | (14.7) | 4.4 | ||
Total revenues | 1,764.7 | 1,263.6 | 3,526.4 | 2,585.5 | ||
Operating costs and expenses: | ||||||
Cost of sales | [1] | 1,325.6 | 932.4 | 2,707.1 | 1,934.7 | |
Operating expenses | 113.4 | 102.6 | 222.6 | 206.7 | ||
General and administrative | 30.4 | 31.1 | 57.9 | 67.2 | ||
(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 | 0.0 | 0.0 | 0.0 | 7.0 | ||
Gain on litigation settlement | 0.0 | (8.5) | 0.0 | (26.0) | ||
Total operating costs and expenses | 1,615.9 | 1,194.7 | 3,272.3 | 2,460.1 | ||
Operating income | 148.8 | 68.9 | 254.1 | 125.4 | ||
Other income (expense): | ||||||
Interest expense, net of interest income | (44.6) | (47.7) | (89.1) | (92.6) | ||
Gain on extinguishment of debt | 0.0 | 9.0 | 0.0 | 9.0 | ||
Income (loss) from unconsolidated affiliates | 4.4 | (0.1) | 7.4 | 0.6 | ||
Other income (expense) | (0.1) | 0.2 | 0.2 | 0.2 | ||
Total other expense | (40.3) | (38.6) | (81.5) | (82.8) | ||
Income before non-controlling interest and income taxes | 108.5 | 30.3 | 172.6 | 42.6 | ||
Income tax provision | (6.3) | (3.2) | (13.3) | (6.2) | ||
Net income | 102.2 | 27.1 | 159.3 | 36.4 | ||
Net income attributable to non-controlling interest | 74.2 | 21.2 | 118.9 | 32.4 | ||
Net income attributable to ENLC | $ 28.0 | $ 5.9 | $ 40.4 | $ 4.0 | ||
Net income attributable to ENLC per unit: | ||||||
Basic common unit (in dollars per share) | $ 0.15 | $ 0.03 | $ 0.22 | $ 0.02 | ||
Diluted common unit (in dollars per share) | $ 0.15 | $ 0.03 | $ 0.22 | $ 0.02 | ||
|
Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Income Statement [Abstract] | ||||
Related party cost of sales | $ 46.7 | $ 50.9 | $ 80.8 | $ 79.6 |
Consolidated Statements of Comprehensive Income Statement - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 102.2 | $ 27.1 | $ 159.3 | $ 36.4 |
Loss on designated cash flow hedge, net of tax benefit of $0.2 million for the three and six months ended June 30, 2017 | 0.0 | (2.0) | 0.0 | (2.0) |
Comprehensive income | 102.2 | 25.1 | 159.3 | 34.4 |
Comprehensive income attributable to non-controlling interest | 74.2 | 19.6 | 118.9 | 30.8 |
Comprehensive income attributable to EnLink Midstream, LLC | $ 28.0 | $ 5.5 | $ 40.4 | $ 3.6 |
Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Statement of Comprehensive Income [Abstract] | ||||
Loss on designated cash flow hedge, tax benefit | $ 0.0 | $ 0.2 | $ 0.0 | $ 0.2 |
General |
6 Months Ended | ||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||
General | (1) General In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership and EOGP. Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information.
EnLink Midstream, LLC is a publicly traded Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.” Our assets consist of equity interests in ENLK and EOGP. ENLK is a publicly traded limited partnership formed on July 12, 2002 and is engaged in the gathering, transmission, processing, and marketing of natural gas, NGLs, condensate, and crude oil, as well as providing crude oil, condensate, and brine services to producers. EOGP is a partnership held by us and ENLK and is engaged in the gathering and processing of natural gas. As of June 30, 2018, our direct and indirect interests in ENLK and EOGP consisted of the following:
Prior to July 18, 2018, subsidiaries of Devon collectively owned a 100% equity interest in ENLC’s managing member, common units of ENLC representing approximately 63.8% of the outstanding limited liability company interests in ENLC, and approximately 23.1% of the outstanding limited partner interests in ENLK. On July 18, 2018, the Devon subsidiaries sold all of these interests to GIP. See Note 15—Subsequent Event for more information regarding this transaction.
We primarily focus on providing midstream energy services, including:
Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines. Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers. Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities to various markets. Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. |
Significant Accounting Policies |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies | (2) Significant Accounting Policies
The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.
We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:
Adoption of ASC 606 Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaces previous revenue recognition requirements in GAAP and requires entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 also requires significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Evaluation of Our Contractual Performance Obligations In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include:
The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream service revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, 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 when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For the three and six months ended June 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $163 million and $301 million, respectively, or 9% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):
This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows. Changes in Accounting Methodology for Certain Contracts For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the 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 our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606. For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories:
For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, 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. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606. For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606. We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, crude, and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, 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 when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606. Satisfaction of Performance Obligations and Recognition of Revenue While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606. We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). Minimum Volume Commitments and Firm Transportation Contracts Certain gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenues. For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenues. The following table summarizes the expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. In addition, amounts in the table below do not represent the shortfall amounts we expect to collect under our MVC contracts as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods.
In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected $135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a $19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us $58.0 million in principal payments in various installments ending in May 2023, with interest accruing on the loan balance at 8.0% per annum beginning in 2020; and (iii) the counterparty granted to us a 1.0% term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized $45.5 million of midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer. Contributions in Aid of Construction The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for the three and six months ended June 30, 2018. Disaggregation of Revenue and Presentation of Prior Periods Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. See Note 13—Segment Information for the revenue disaggregation information included in the segment information table for the three and six months ended June 30, 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the three and six months ended June 30, 2018 are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”), which establishes ASC Topic 842, Leases (“ASC 842”). Under ASC 842, lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASC 842 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. Entities are required to adopt ASC 842 using a modified retrospective transition. We will adopt ASC 842 effective January 1, 2019. We are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. This assessment includes the evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASC 842 will have on our consolidated financial statements, the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In addition, there are industry-specific concerns with the implementation of ASC 842 that will require further evaluation before we are able to fully assess the impact of ASC 842 on our consolidated financial statements. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 amends ASC 842 and provides an optional practical expedient to not evaluate under ASC 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in ASC 840, Leases. Under ASU 2018-01, an entity that elects this practical expedient should evaluate new or modified land easements under ASC 842 beginning at the date that the entity adopts ASC 842. We plan to utilize the practical expedient provided in ASU 2018-01 in conjunction with our adoption of ASC 842. (d) Property & Equipment Impairment Review. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. For the six months ended June 30, 2017, we recognized impairments of property and equipment of $7.0 million, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well. We did not recognize impairments for any other period presented in the consolidated statements of operations. |
Intangible Assets |
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Intangible Assets | (3) Intangible Assets Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from 10 to 20 years. The following table represents our change in carrying value of intangible assets (in millions):
The weighted average amortization period is 15.0 years. Amortization expense was $30.9 million and $35.5 million for the three months ended June 30, 2018 and 2017, respectively, and $61.7 million and $65.0 million for the six months ended June 30, 2018 and 2017, respectively. The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):
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Related Party Transactions |
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Related Party Transactions [Abstract] | |
Related Party Transactions | (4) Related Party Transactions We engage in various transactions with Devon and other related parties. For the three and six months ended June 30, 2018, Devon accounted for 11.5% and 10.6% of our revenues, respectively, and for the three and six months ended June 30, 2017, Devon accounted for 15.8% and 15.3% of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $122.1 million at June 30, 2018 and $102.7 million at December 31, 2017. Additionally, we had an accounts payable balance related to transactions with Devon of $27.0 million at June 30, 2018 and $16.3 million at December 31, 2017. On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. Accordingly, Devon is no longer an affiliate of ENLK or ENLC. The sale did not affect our commercial arrangements with Devon, except that Devon agreed to extend through 2029 certain existing, fixed-fee gathering and processing contracts related to the Bridgeport plant in North Texas and the Cana plant in Oklahoma. See Note 15—Subsequent Event for additional information regarding Devon’s sale to GIP. For the three and six months ended June 30, 2018, we recorded cost of sales of $9.5 million and $22.5 million, respectively, and for the three and six months ended June 30, 2017, we recorded cost of sales of $4.3 million and $5.5 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities. We had an accounts receivable balance related to transactions with Cedar Cove of $0.6 million at June 30, 2018. Additionally, we had an accounts payable balance related to transactions with Cedar Cove of $3.5 million at June 30, 2018. The accounts receivable and payable balances related to transactions with Cedar Cover were immaterial at December 31, 2017. Management believes these transactions are executed on terms that are fair and reasonable to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements. |
Long-Term Debt |
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Long-Term Debt | (5) Long-Term Debt As of June 30, 2018 and December 31, 2017, long-term debt consisted of the following (in millions):
ENLC Credit Facility The ENLC Credit Facility is a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility. Our obligations under the ENLC Credit Facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 ENLK common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us, and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility. The ENLC Credit Facility contains certain financial, operational, and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization, and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the ENLC Credit Facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization, and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 unless an investment grade event (as defined in the ENLC Credit Facility) occurs. Borrowings under the ENLC Credit Facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.75% to 2.50%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.75% to 1.50%). The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the ENLC Credit Facility, amounts outstanding under the ENLC Credit Facility, if any, may become due and payable immediately and the liens securing the ENLC Credit Facility could be foreclosed upon. On June 20, 2018, we amended the change of control provisions of the ENLC Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLC Credit Facility). At June 30, 2018, ENLC was in compliance and expects to be in compliance with the covenants in the ENLC Credit Facility through its maturity date. As of June 30, 2018, there were no outstanding letters of credit and $84.4 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $165.6 million available for future borrowing. ENLK Credit Facility The ENLK Credit Facility is a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 and includes a $500.0 million letter of credit subfacility. Under the ENLK Credit Facility, ENLK is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the ENLK Credit Facility by an additional amount not to exceed $500.0 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the ENLK Credit Facility by one year on each occasion. The ENLK Credit Facility contains certain financial, operational, and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in the ENLK Credit Facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If ENLK consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLK can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters. Borrowings under the ENLK Credit Facility bear interest at ENLK’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.0% to 0.75%). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately. On June 20, 2018, ENLK amended the change of control provisions of the ENLK Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLK Credit Facility). At June 30, 2018, ENLK was in compliance and expects to be in compliance with the covenants in the ENLK Credit Facility for at least the next twelve months. As of June 30, 2018, there were $9.3 million in outstanding letters of credit and $520.0 million outstanding borrowings under the ENLK Credit Facility, leaving approximately $970.7 million available for future borrowing. All other material terms and conditions of the ENLC Credit Facility, the ENLK Credit Facility, and outstanding senior unsecured notes are described in Part II, “Item 8. Financial Statements and Supplementary Data—Note 6” in our Annual Report on Form 10-K for the year ended December 31, 2017. |
Income Taxes |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | (6) Income Taxes Income taxes included on the consolidated financial statements were as follows for the periods presented (in millions):
The following schedule reconciles total income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):
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Certain Provisions of the Partnership Agreement |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partners' Capital [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Certain Provisions of the Partnership Agreement | (7) Certain Provisions of the Partnership Agreement
In August 2017, ENLK entered into the 2017 EDA with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK common units from time to time through an “at the market” equity offering program. ENLK may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. ENLK has no obligation to sell any of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA. For the six months ended June 30, 2018, ENLK sold an aggregate of approximately 0.1 million common units under the 2017 EDA, generating proceeds of approximately $0.9 million (net of less than $0.1 million of commissions paid to the Sales Agents). ENLK used the net proceeds for general partnership purposes. As of June 30, 2018, approximately $564.5 million in aggregate gross proceeds remains available to be issued under the 2017 EDA. (b) ENLK Series B Preferred Units Beginning with the quarter ended September 30, 2017, Series B Preferred Unit distributions are payable quarterly in cash at an amount equal to $0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the issue price of $15.00. A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2018 and 2017 is provided below:
Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. The distribution rate for the Series C Preferred Units is 6.0% per annum, and ENLK distributed $12.0 million to holders of Series C Preferred Units during the six months ended June 30, 2018.
Unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing ENLK’s senior unsecured notes, ENLK must make distributions of 100% of available cash, as defined in its partnership agreement, within 45 days following the end of each quarter. Distributions of available cash are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner is not entitled to incentive distributions with respect to (i) distributions on the Series B Preferred Units until such units convert into common units or (ii) the Series C Preferred Units. The General Partner owns the general partner interest in ENLK and all incentive distribution rights in ENLK. The General Partner is entitled to receive incentive distributions if the amount ENLK distributes with respect to any quarter exceeds levels specified in its partnership agreement. Under the quarterly incentive distribution provisions, the General Partner is entitled to 13.0% of amounts ENLK distributes in excess of $0.25 per unit, 23.0% of the amounts ENLK distributes in excess of $0.3125 per unit, and 48.0% of amounts ENLK distributes in excess of $0.375 per unit. A summary of ENLK’s distribution activity relating to the common units during the six months ended June 30, 2018 and 2017 is provided below:
Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(d) ENLK Common Unit Distributions” above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows (in millions):
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Members' Equity |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Members' Equity | (8) Members' Equity (a) Earnings Per Unit and Dilution Computations As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):
The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):
All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented. (b) Distributions A summary of our distribution activity relating to the ENLC common units for the six months ended June 30, 2018 and 2017, respectively, is provided below:
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Investment in Unconsolidated Affiliates |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investment in Unconsolidated Affiliates | (9) Investment in Unconsolidated Affiliates As of June 30, 2018, our unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership in GCF and an approximate 30% ownership in the Cedar Cove JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2018 and December 31, 2017 (in millions):
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Employee Incentive Plans |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Incentive Plans | (10) Employee Incentive Plans
ENLC and ENLK each have similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”), and ENLK grants unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”). We account for unit-based compensation in accordance with ASC 718, Stock Compensation (“ASC 718”), which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to ENLC’s officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in ENLK and EOGP. Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions):
ENLK restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of ENLK common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2018 is provided below:
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2018 and 2017 is provided below (in millions):
As of June 30, 2018, there was $20.2 million of unrecognized compensation cost related to non-vested ENLK restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.9 years.
The General Partner grants performance awards under the GP Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the AMZ, excluding ENLC and ENLK, on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLC’s and ENLK’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units ranges from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLK’s common units and the designated Peer Companies securities; (iii) an estimated ranking of ENLK among the designated Peer Companies; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair value of performance units granted and the related assumptions by performance unit grant date:
The following table presents a summary of the performance units:
A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2018 is provided below (in millions). No performance units vested for the three months ended June 30, 2018 or for the three and six months ended June 30, 2017.
As of June 30, 2018, there was $7.4 million of unrecognized compensation cost that related to non-vested ENLK performance units. That cost is expected to be recognized over a weighted-average period of 2.0 years.
ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of ENLC common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2018 is provided below:
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2018 and 2017 is provided below (in millions):
As of June 30, 2018, there was $19.2 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 1.9 years.
ENLC grants performance awards under the 2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain TSR performance goals relative to the TSR achievement of the Peer Companies over the applicable performance period. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units ranges from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designated Peer Companies securities; (iii) an estimated ranking of ENLC among the designated Peer Companies, and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
The following table presents a summary of the performance units:
A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2018 is provided below (in millions). No performance units vested for the three months ended June 30, 2018 or for the three and six months ended June 30, 2017.
As of June 30, 2018, there was $7.5 million of unrecognized compensation cost that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.0 years. |
Derivatives |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives | (11) Derivatives Interest Rate Swaps We periodically enter into interest rate swaps in connection with new debt issuances. During the debt issuance process, we are exposed to variability in future long-term debt interest payments that may result from changes in the benchmark interest rate (commonly the U.S. Treasury yield) prior to the debt being issued. In order to hedge this variability, we enter into interest rate swaps to effectively lock in the benchmark interest rate at the inception of the swap. Prior to 2017, we did not designate interest rate swaps as hedges and, therefore, included the associated settlement gains and losses as interest expense, net of interest income on the consolidated statements of operations. In May 2017, we entered into an interest rate swap in connection with the issuance of ENLK’s 5.45% senior unsecured notes due 2047 (the “2047 Notes”). In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes. There was no ineffectiveness related to the hedge. For the three and six months ended June 30, 2018, we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss). We expect to recognize $0.1 million of interest expense out of accumulated other comprehensive income (loss) over the next twelve months. We have no open interest rate swap position as of June 30, 2018. Commodity Swaps We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas, and NGLs. We do not designate commodity swaps as cash flow or fair value hedges for hedge accounting treatment under ASC 815. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our risk management policy does not allow us to take speculative positions with our derivative contracts. We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs, and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate, and crude oil, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage. Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities, and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity on the consolidated statements of operations. We estimate the fair value of all of our derivative contracts based upon actively-quoted prices of the underlying commodities. The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):
The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
As of June 30, 2018 and December 31, 2017, there were no derivative assets classified as long-term on the consolidated balance sheets. Set forth below are the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at June 30, 2018 (in millions). The remaining term of the contracts extend no later than October 2019.
On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with financial institutions when entering into financial derivatives on commodities. We have entered into Master ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing swap contracts, the maximum loss on our gross receivable position of $8.3 million as of June 30, 2018 would be reduced to an immaterial amount due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. |
Fair Value Measurements |
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Fair Value Measurements | (12) Fair Value Measurements ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Our derivative contracts primarily consist of commodity swap contracts, which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly-quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate, and credit risk and are classified as Level 2 in hierarchy. Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions):
Fair Value of Financial Instruments The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. ENLK had $520.0 million of outstanding borrowings under the ENLK Credit Facility as of June 30, 2018 and no outstanding borrowings under the ENLK Credit Facility as of December 31, 2017. ENLC had $84.4 million and $74.6 million in outstanding borrowings under the ENLC Credit Facility as of June 30, 2018 and December 31, 2017, respectively. As borrowings under the ENLK Credit Facility and ENLC Credit Facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the ENLK Credit Facility and the ENLC Credit Facility. As of June 30, 2018 and December 31, 2017, ENLK had total borrowings under senior unsecured notes of $3.5 billion maturing between 2019 and 2047 with fixed interest rates ranging from 2.7% to 5.6%. The fair values of all senior unsecured notes and installment payables as of June 30, 2018 and December 31, 2017 were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases and the secured term loan receivable were calculated using Level 2 inputs from third-party banks. |
Segment Information |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Information | (13) Segment Information Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. Our reportable segments consist of the following: natural gas gathering, processing, transmission, and fractionation operations located in North Texas and the Permian Basin primarily in West Texas (“Texas”), natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”), and crude rail, truck, pipeline, and barge facilities in West Texas, South Texas, Louisiana, Oklahoma, and the Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the Corporate segment. Our sales are derived from external domestic customers. We evaluate the performance of our operating segments based on segment profits. Corporate assets consist primarily of cash, property, and equipment, including software, for general corporate support, debt financing costs, and unconsolidated affiliate investments in GCF and the Cedar Cove JV. Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the three and six months ended June 30, 2018 are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606. Summarized financial information for our reportable segments is shown in the following tables (in millions):
The table below represents information about segment assets as of June 30, 2018 and December 31, 2017 (in millions):
The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions):
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Other Information |
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Other Liabilities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Information | (14) Other Information The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):
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Subsequent Event |
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Subsequent Events [Abstract] | |||||||||
Subsequent Event | (15) Subsequent Event On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. In connection with the closing of the transaction, GIP paid aggregate consideration of $3.125 billion in cash to Devon. As a result of the transaction:
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Presentation | Basis of Presentation The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. |
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Revenue Recognition | Revenue Recognition We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:
Adoption of ASC 606 Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaces previous revenue recognition requirements in GAAP and requires entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 also requires significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. Evaluation of Our Contractual Performance Obligations In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include:
The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream service revenues over time as we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, 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 when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For the three and six months ended June 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $163 million and $301 million, respectively, or 9% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):
This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows. Changes in Accounting Methodology for Certain Contracts For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the 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 our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606. For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories:
For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, 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. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606. For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenues over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606. We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, crude, and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, 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 when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606. Satisfaction of Performance Obligations and Recognition of Revenue While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606. We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues). Minimum Volume Commitments and Firm Transportation Contracts Certain gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenues. For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenues. The following table summarizes the expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. In addition, amounts in the table below do not represent the shortfall amounts we expect to collect under our MVC contracts as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods.
In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected $135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a $19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us $58.0 million in principal payments in various installments ending in May 2023, with interest accruing on the loan balance at 8.0% per annum beginning in 2020; and (iii) the counterparty granted to us a 1.0% term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized $45.5 million of midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer. Contributions in Aid of Construction The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for the three and six months ended June 30, 2018. Disaggregation of Revenue and Presentation of Prior Periods Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. See Note 13—Segment Information for the revenue disaggregation information included in the segment information table for the three and six months ended June 30, 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for the three and six months ended June 30, 2018 are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606. |
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Accounting Standards to be Adopted in Future Periods | Accounting Standards to be Adopted in Future Periods In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”), which establishes ASC Topic 842, Leases (“ASC 842”). Under ASC 842, lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASC 842 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. Entities are required to adopt ASC 842 using a modified retrospective transition. We will adopt ASC 842 effective January 1, 2019. We are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. This assessment includes the evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASC 842 will have on our consolidated financial statements, the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In addition, there are industry-specific concerns with the implementation of ASC 842 that will require further evaluation before we are able to fully assess the impact of ASC 842 on our consolidated financial statements. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 amends ASC 842 and provides an optional practical expedient to not evaluate under ASC 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in ASC 840, Leases. Under ASU 2018-01, an entity that elects this practical expedient should evaluate new or modified land easements under ASC 842 beginning at the date that the entity adopts ASC 842. We plan to utilize the practical expedient provided in ASU 2018-01 in conjunction with our adoption of ASC 842. |
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Property and Equipment | Property & Equipment Impairment Review. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. |
Significant Accounting Polices (Tables) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of New Accounting Pronouncements and Changes in Accounting Principles | Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For the three and six months ended June 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately $163 million and $301 million, respectively, or 9% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):
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Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | The following table summarizes the expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. In addition, amounts in the table below do not represent the shortfall amounts we expect to collect under our MVC contracts as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods.
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Intangible Assets (Tables) |
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Summary of Changes in Carrying Value | The following table represents our change in carrying value of intangible assets (in millions):
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Schedule of Amortization Expense | The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):
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Long-Term Debt (Tables) |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Debt | As of June 30, 2018 and December 31, 2017, long-term debt consisted of the following (in millions):
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Income Taxes (Tables) |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | Income taxes included on the consolidated financial statements were as follows for the periods presented (in millions):
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Reconciliation of Total Income Tax Expense to Income before Income Taxes | The following schedule reconciles total income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):
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Certain Provisions of the Partnership Agreement (Tables) |
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Partners' Capital [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Distribution Activity | A summary of the distribution activity relating to the Series B Preferred Units during the six months ended June 30, 2018 and 2017 is provided below:
A summary of ENLK’s distribution activity relating to the common units during the six months ended June 30, 2018 and 2017 is provided below:
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Incentive Distributions | Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(d) ENLK Common Unit Distributions” above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows (in millions):
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Members' Equity (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Computation of Basic and Diluted Earnings per Limited Partner Unit | The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):
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Schedule of Unit Amounts Used to Computer Earnings per Unit | The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):
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Summary of Distribution Activity | A summary of our distribution activity relating to the ENLC common units for the six months ended June 30, 2018 and 2017, respectively, is provided below:
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Investment in Unconsolidated Affiliates (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Activity Related to Investment in Unconsolidated Affiliates | The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
The following table shows the balances related to our investment in unconsolidated affiliates as of June 30, 2018 and December 31, 2017 (in millions):
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Employee Incentive Plans (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Amounts Recognized in Consolidated Financial Statements | Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions):
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Summary of Restricted Incentive Unit Activity | A summary of the restricted incentive unit activity for the six months ended June 30, 2018 is provided below:
A summary of the restricted incentive unit activity for the six months ended June 30, 2018 is provided below:
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Summary of Restricted Units' Aggregate Intrinsic Value | A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2018 and 2017 is provided below (in millions):
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and six months ended June 30, 2018 and 2017 is provided below (in millions):
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Summary of Grant-Date Fair Values | The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
The following table presents a summary of the grant-date fair value of performance units granted and the related assumptions by performance unit grant date:
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Summary of Performance Units | The following table presents a summary of the performance units:
A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2018 is provided below (in millions). No performance units vested for the three months ended June 30, 2018 or for the three and six months ended June 30, 2017.
The following table presents a summary of the performance units:
A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the six months ended June 30, 2018 is provided below (in millions). No performance units vested for the three months ended June 30, 2018 or for the three and six months ended June 30, 2017.
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Derivatives (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Gain (Loss) on Derivative Activity | The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):
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Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps | The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
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Notional Amount and Fair Value of Derivative Instruments | Set forth below are the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at June 30, 2018 (in millions). The remaining term of the contracts extend no later than October 2019.
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Fair Value Measurements (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis | Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions):
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Schedule of the Estimated Fair Value of Financial Instruments | Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
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Segment Information (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Financial Information | Summarized financial information for our reportable segments is shown in the following tables (in millions):
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Schedule of Segment Assets | The table below represents information about segment assets as of June 30, 2018 and December 31, 2017 (in millions):
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Reconciliation of Profits to Operating Income (Loss) | The following table reconciles the segment profits reported above to the operating income as reported on the consolidated statements of operations (in millions):
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Other Information (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Liabilities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Other Current Liabilities | The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):
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Intangible Assets - Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Finite-Lived Intangible Assets [Line Items] | ||||
Amortization expense | $ 30.9 | $ 35.5 | $ 61.7 | $ 65.0 |
Minimum | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Estimated useful life of intangible assets | 10 years | |||
Maximum | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Estimated useful life of intangible assets | 20 years | |||
Weighted average | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Estimated useful life of intangible assets | 15 years |
Intangible Assets - Amortization Expense (Details) - EnLink Midstream Partners, LP $ in Millions |
Jun. 30, 2018
USD ($)
|
---|---|
Finite-Lived Intangible Assets [Line Items] | |
2018 (remaining) | $ 61.8 |
2019 | 123.4 |
2020 | 123.4 |
2021 | 123.4 |
2022 | 123.4 |
Thereafter | 880.0 |
Total | $ 1,435.4 |
Related Party Transactions (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | |||||
---|---|---|---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
Dec. 31, 2017 |
|||
Related Party Transaction [Line Items] | |||||||
Accounts payable to related party | $ 30.5 | $ 30.5 | $ 16.3 | ||||
Cost of sales | [1] | 1,325.6 | $ 932.4 | 2,707.1 | $ 1,934.7 | ||
Devon Energy Corporation | |||||||
Related Party Transaction [Line Items] | |||||||
Accounts receivable balance | 122.1 | 122.1 | 102.7 | ||||
Accounts payable to related party | $ 27.0 | $ 27.0 | $ 16.3 | ||||
Devon Energy Corporation | Customer Concentration Risk | Sales Revenue, Net | |||||||
Related Party Transaction [Line Items] | |||||||
Concentration risk | 11.50% | 15.80% | 10.60% | 15.30% | |||
Cedar Cove Joint Venture | |||||||
Related Party Transaction [Line Items] | |||||||
Accounts receivable balance | $ 0.6 | $ 0.6 | |||||
Accounts payable to related party | 3.5 | 3.5 | |||||
Cost of sales | $ 9.5 | $ 4.3 | $ 22.5 | $ 5.5 | |||
|
Income Taxes (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Income Tax Disclosure [Abstract] | ||||
Current income tax provision (benefit) | $ (0.3) | $ (1.0) | $ 0.9 | $ (0.2) |
Deferred income tax provision | 6.6 | 4.2 | 12.4 | 6.4 |
Total income tax provision | 6.3 | 3.2 | 13.3 | 6.2 |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||||
Expected income tax provision based on federal statutory rate | 7.2 | 3.1 | 11.3 | 3.5 |
State income taxes expense, net of federal tax benefit | 0.8 | 0.3 | 1.3 | 0.3 |
Income tax expense (benefit) from ENLK | (2.0) | (0.3) | (1.0) | 0.2 |
Unit-based compensation | (0.1) | 0.0 | 1.5 | 2.3 |
Other | 0.4 | 0.1 | 0.2 | (0.1) |
Total income tax provision | $ 6.3 | $ 3.2 | $ 13.3 | $ 6.2 |
Certain Provisions of the Partnership Agreement - Allocation of Income (Details) - General Partner - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Incentive distribution | ||||
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 |
Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Basic weighted average units outstanding: | ||||
Weighted average common units outstanding (in shares) | 181.0 | 180.6 | 181.0 | 180.4 |
Diluted weighted average units outstanding: | ||||
Weighted average basic common units outstanding (in shares) | 181.0 | 180.6 | 181.0 | 180.4 |
Dilutive effect of non-vested restricted incentive units (in shares) | 1.2 | 1.1 | 1.0 | 1.2 |
Total weighted average diluted common units outstanding (in shares) | 182.2 | 181.7 | 182.0 | 181.6 |
Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Allocation | ||||
Compensation expense | $ 9.6 | $ 9.3 | $ 14.7 | $ 28.7 |
Amount of related income tax benefit recognized in net income | 1.2 | 2.1 | 1.9 | 6.7 |
Tax expense excluded from income tax benefit | (0.1) | 0.0 | 1.5 | 2.3 |
Cost of unit-based compensation charged to operating expense | ||||
Allocation | ||||
Compensation expense | 2.3 | 2.6 | 4.3 | 7.6 |
Cost of unit-based compensation charged to general and administrative expense | ||||
Allocation | ||||
Compensation expense | 7.3 | 6.7 | 10.4 | 21.1 |
Non-controlling interest in unit-based compensation | ||||
Allocation | ||||
Compensation expense | $ 3.6 | $ 3.5 | $ 5.5 | $ 10.8 |
Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
May 31, 2017 |
---|---|---|---|
Derivatives | |||
Accumulated other comprehensive loss | $ 2.0 | $ 2.0 | $ 2.2 |
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months | $ (0.1) | ||
ENLK's 5.45% Senior unsecured notes due 2047 | |||
Derivatives | |||
Stated interest rate | 5.45% | 5.45% |
Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Derivatives | ||||
Gain (loss) on derivative activity | $ (15.2) | $ 1.6 | $ (14.7) | $ 4.4 |
EnLink Midstream Partners, LP | Commodity Swaps | ||||
Derivatives | ||||
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 |
Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($) |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Derivatives | ||
Fair value of derivative assets—current | $ 4,000,000 | $ 6,800,000 |
Fair value of derivative liabilities—current | (10,700,000) | (8,400,000) |
Fair value of derivative liabilities | (8,900,000) | 0 |
EnLink Midstream Partners, LP | ||
Derivatives | ||
Fair value of derivative assets—current | 4,000,000 | 6,800,000 |
Fair value of derivative liabilities—current | (10,700,000) | (8,400,000) |
Fair value of derivative liabilities | (8,900,000) | 0 |
Net fair value of derivatives | (15,600,000) | (1,600,000) |
Fair value of derivative assets — long-term | $ 0 | $ 0 |
Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Level 2 | Commodity Swaps | Recurring | ||
Fair Value | ||
Fair Value | $ (15.6) | $ (1.6) |
Segment Information - Reconciliation (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2018 |
Jun. 30, 2017 |
Jun. 30, 2018 |
Jun. 30, 2017 |
|
Segment Reporting [Abstract] | ||||
Segment profit | $ 325.7 | $ 228.6 | $ 596.7 | $ 444.1 |
General and administrative expenses | (30.4) | (31.1) | (57.9) | (67.2) |
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 | 0.0 | 0.0 | 0.0 | (7.0) |
Gain on litigation settlement | 0.0 | 8.5 | 0.0 | 26.0 |
Operating income | $ 148.8 | $ 68.9 | $ 254.1 | $ 125.4 |
Other Information (Details) - USD ($) |
Jun. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Other Current Assets: | ||
Natural gas and NGLs inventory | $ 60,800,000 | $ 30,100,000 |
Secured term loan receivable from contract restructuring, net of discount of $1.6 | 17,900,000 | 0 |
Secured term loan receivable, discount | 1,600,000 | 0 |
Prepaid expenses and other | 20,400,000 | 11,100,000 |
Natural gas and NGLs inventory, prepaid expenses, and other | 99,100,000 | 41,200,000 |
Other Current Liabilities: | ||
Accrued interest | 36,600,000 | 35,600,000 |
Accrued wages and benefits, including taxes | 18,000,000 | 30,400,000 |
Accrued ad valorem taxes | 25,900,000 | 27,800,000 |
Capital expenditure accruals | 41,800,000 | 48,800,000 |
Onerous performance obligations | 17,900,000 | 15,200,000 |
Other | 66,200,000 | 65,100,000 |
Other current liabilities | $ 206,400,000 | $ 222,900,000 |
Subsequent Event (Details) - USD ($) $ in Millions |
6 Months Ended | |
---|---|---|
Jul. 18, 2018 |
Jun. 30, 2018 |
|
EnLink Midstream Partners, LP | ||
Subsequent Event [Line Items] | ||
Membership interest in the General Partner | 0.40% | |
GIP | Devon Energy Corporation | Subsequent Event | ||
Subsequent Event [Line Items] | ||
Aggregated consideration paid to acquire equity interest | $ 3,125 | |
GIP Stetson | EnLink Midstream Partners GP, LLC | Subsequent Event | ||
Subsequent Event [Line Items] | ||
Membership interest in the General Partner | 100.00% | |
GIP Stetson | EnLink Midstream Partners, LP | Subsequent Event | ||
Subsequent Event [Line Items] | ||
Membership interest in the General Partner | 23.10% | |
GIP Stetson II | ENLC | Subsequent Event | ||
Subsequent Event [Line Items] | ||
Membership interest in the General Partner | 63.80% |
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