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As Of Filer Filing For·On·As Docs:Size 8/07/19 EnLink Midstream Partners, LP 10-Q 6/30/19 80:14M |
Document/Exhibit Description Pages Size 1: 10-Q Quarterly Report HTML 2.08M 2: EX-31.1 Certification -- §302 - SOA'02 HTML 29K 3: EX-31.2 Certification -- §302 - SOA'02 HTML 29K 4: EX-32.1 Certification -- §906 - SOA'02 HTML 25K 11: R1 Cover Page HTML 69K 12: R2 Consolidated Balance Sheets HTML 131K 13: R3 Consolidated Balance Sheets (Parenthetical) HTML 51K 14: R4 Consolidated Statements of Operations HTML 100K 15: R5 Consolidated Statements of Operations HTML 23K (Parenthetical) 16: R6 Consolidated Statements of Comprehensive Income HTML 41K (Loss) 17: R7 Consolidated Statements of Changes in Partners' HTML 112K Equity 18: R8 Consolidated Statements of Cash Flows HTML 130K 19: R9 Consolidated Statements of Cash Flows HTML 23K (Parenthetical) 20: R10 General HTML 47K 21: R11 Significant Accounting Policies HTML 46K 22: R12 Intangible Assets HTML 44K 23: R13 Related Party Transactions HTML 36K 24: R14 Leases HTML 196K 25: R15 Long-Term Debt HTML 106K 26: R16 Partners' Capital HTML 91K 27: R17 Investment in Unconsolidated Affiliates HTML 72K 28: R18 Employee Incentive Plans HTML 181K 29: R19 Derivatives HTML 88K 30: R20 Fair Value Measurements HTML 55K 31: R21 Segment Information HTML 528K 32: R22 Other Information HTML 52K 33: R23 Significant Accounting Policies (Policies) HTML 50K 34: R24 (Tables) HTML 31K 35: R25 Intangible Assets (Tables) HTML 43K 36: R26 Leases (Tables) HTML 146K 37: R27 Long-Term Debt (Tables) HTML 88K 38: R28 Partners' Capital (Tables) HTML 82K 39: R29 Investment in Unconsolidated Affiliates (Tables) HTML 70K 40: R30 Employee Incentive Plans (Tables) HTML 169K 41: R31 Derivatives (Tables) HTML 80K 42: R32 Fair Value Measurements (Tables) HTML 48K 43: R33 Segment Information (Tables) HTML 528K 44: R34 Other Information (Tables) HTML 51K 45: R35 General (Details) HTML 32K 46: R36 Significant Accounting Policies - Summary of HTML 45K Expected Future Performance Obligations (Details) 47: R37 Significant Accounting Policies - Narrative HTML 52K (Details) 48: R38 Intangible Assets - Narrative (Details) HTML 33K 49: R39 Intangible Assets - Changes in Carrying Value HTML 38K (Details) 50: R40 Intangible Assets - Amortization Expense (Details) HTML 37K 51: R41 Related Party Transactions - Narrative (Details) HTML 79K 52: R42 Leases - Narrative (Details) HTML 40K 53: R43 Leases - Lease Balances Recorded on the HTML 48K Consolidated Balance Sheet (Details) 54: R44 Leases - Components of Total Lease Expense HTML 35K (Details) 55: R45 Leases - Other Information (Details) HTML 29K 56: R46 Leases - Maturity of Lease Liability (Details) HTML 108K 57: R47 Long-Term Debt - Summary (Details) HTML 87K 58: R48 Long-Term Debt - Narrative (Details) HTML 103K 59: R49 Partners' Capital - Narrative and Distribution HTML 76K Activity (Details) 60: R50 Partners' Capital - Net Income Allocated to the HTML 33K General Partner (Details) 61: R51 Investment in Unconsolidated Affiliates (Details) HTML 46K 62: R52 Employee Incentive Plans - Amounts Recognized in HTML 30K Consolidated Financial Statements (Details) 63: R53 Employee Incentive Plans - Restricted and HTML 142K Performance Awards (Details) 64: R54 Employee Incentive Plans - Summary of Tranche HTML 44K Vesting Levels (Details) 65: R55 Derivatives - Interest Rate Swaps (Details) HTML 51K 66: R56 Derivatives - Components of Gain (Loss) (Details) HTML 31K 67: R57 Derivatives - Assets and Liabilities (Details) HTML 38K 68: R58 Derivatives - Commodities (Details) HTML 44K 69: R59 Fair Value Measurements - Measured on a Recurring HTML 32K Basis (Details) 70: R60 Fair Value Measurements - Financial Instruments HTML 49K (Details) 71: R61 Segment Information - Narrative (Details) HTML 23K 72: R62 Segment Information - Financial Information and HTML 300K Assets (Details) 73: R63 Segment Information - Reconciliation (Details) HTML 36K 74: R64 Segment Information - Assets (Details) HTML 36K 75: R65 Other Information (Details) HTML 63K 76: R9999 Uncategorized Items - enlkq2201910-q.htm HTML 47K 79: XML IDEA XML File -- Filing Summary XML 140K 10: XML XBRL Instance -- enlkq2201910-q_htm XML 5.19M 77: EXCEL IDEA Workbook of Financial Reports XLSX 104K 6: EX-101.CAL XBRL Calculations -- enlc-20190630_cal XML 309K 7: EX-101.DEF XBRL Definitions -- enlc-20190630_def XML 872K 8: EX-101.LAB XBRL Labels -- enlc-20190630_lab XML 1.95M 9: EX-101.PRE XBRL Presentations -- enlc-20190630_pre XML 1.14M 5: EX-101.SCH XBRL Schema -- enlc-20190630 XSD 202K 78: JSON XBRL Instance as JSON Data -- MetaLinks 391± 565K 80: ZIP XBRL Zipped Folder -- 0001179060-19-000019-xbrl Zip 359K
Document |
i Delaware | i 16-1616605 | |
(State
of organization) | (I.R.S. Employer Identification No.) | |
i 1722 Routh St., Suite 1300 | ||
i Dallas, | i Texas | i 75201 |
(Address
of principal executive offices) | (Zip Code) |
Title of Each Class | Name of Exchange on which Registered | Symbol | ||
None. | None. | None. |
i Large
accelerated filer | ☒ | Accelerated filer | ☐ | |
Non-accelerated filer | ☐ | Smaller reporting company | i ☐ | |
Emerging
growth company | i ☐ |
Item | Description | Page | ||
Defined Term | Definition | |
/d | Per day. | |
2014 Plan | EnLink
Midstream, LLC’s 2014 Long-Term Incentive Plan. | |
AMZ | Alerian MLP Index for Master Limited Partnerships. | |
ASC | The FASB Accounting Standards Codification. | |
ASC 842 | ASC 842, Leases, a new accounting standard effective January 1, 2019 related to the accounting for lease agreements. | |
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. | |
ASU | The FASB Accounting Standards Update. | |
Avenger | Avenger
crude oil gathering system, a crude oil gathering system in the northern Delaware Basin. | |
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. | |
Consolidated Credit Facility | A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024,
which includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK. | |
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. | |
Devon | Devon Energy Corporation. | |
Enfield | Enfield
Holdings, L.P. | |
ENLC | EnLink Midstream, LLC. | |
ENLC Class C common Units | A class of non-economic ENLC common units issued to Enfield immediately prior to the Merger equal to the number of Series B Preferred Units of ENLK held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. | |
ENLK | EnLink
Midstream Partners, LP or, when applicable, 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 would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger. | |
EOGP | EnLink
Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. As of January 31, 2019, EOGP is wholly-owned by the Operating Partnership. | |
FASB | Financial Accounting Standards Board. | |
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. | |
GIP | Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates. | |
GIP Transaction | 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. | |
GP Plan | EnLink Midstream GP, LLC’s Long-Term Incentive Plan. | |
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. | |
ISDAs | International
Swaps and Derivatives Association Agreements. | |
Merger | On January 25, 2019, NOLA Merger Sub merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC. |
Merger
Agreement | The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, our general partner, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger. | |
MMbbls | One million barrels. | |
MMbtu | Million British thermal units. | |
MMcf | Million
cubic feet. | |
MVC | Minimum volume commitment. | |
NGL | Natural gas liquid. | |
NGP | NGP Natural Resources XI, LP. | |
NOLA Merger Sub | NOLA Merger Sub, LLC, previously a wholly-owned subsidiary
of ENLC prior to the Merger. | |
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 and New Mexico. | |
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. | |
Term
Loan | An $850.0 million term loan entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guarantees. | |
Thunderbird Plant | A gas processing plant in central Oklahoma. | |
White Star | White
Star Petroleum Holdings, LLC. |
(Unaudited) | |||||||
ASSETS | |||||||
Current
assets: | |||||||
Cash and cash equivalents | $ | i 58.5 | $ | i 99.5 | |||
Accounts
receivable: | |||||||
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively | i 78.4 | i 126.3 | |||||
Accrued
revenue and other | i 483.9 | i 705.9 | |||||
Related
party | i 12.4 | i 2.1 | |||||
Fair
value of derivative assets | i 9.5 | i 28.6 | |||||
Natural
gas and NGLs inventory, prepaid expenses, and other | i 71.7 | i 72.8 | |||||
Total
current assets | i 714.4 | i 1,035.2 | |||||
Property
and equipment, net of accumulated depreciation of $3,198.1 and $2,967.4, respectively | i 7,023.5 | i 6,846.7 | |||||
Intangible
assets, net of accumulated amortization of $484.1 and $422.2, respectively | i 1,311.7 | i 1,373.6 | |||||
Goodwill | i 190.3 | i 190.3 | |||||
Investment
in unconsolidated affiliates | i 80.0 | i 80.1 | |||||
Fair
value of derivative assets | i 7.1 | i 4.1 | |||||
Other
assets, net | i 97.1 | i 41.3 | |||||
Total
assets | $ | i 9,424.1 | $ | i 9,571.3 | |||
LIABILITIES
AND PARTNERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and drafts payable | $ | i 80.8 | $ | i 105.5 | |||
Accounts
payable to related party | i 2.0 | i 4.3 | |||||
Accrued
gas, NGLs, condensate, and crude oil purchases | i 377.1 | i 500.4 | |||||
Fair
value of derivative liabilities | i 5.8 | i 21.8 | |||||
Current
maturities of long-term debt | i — | i 399.8 | |||||
Other
current liabilities | i 234.5 | i 246.7 | |||||
Total
current liabilities | i 700.2 | i 1,278.5 | |||||
Long-term
debt, including $1,438.5 million from affiliates | i 4,501.0 | i 3,919.8 | |||||
Asset
retirement obligations | i 15.2 | i 14.8 | |||||
Other
long-term liabilities | i 93.0 | i 20.0 | |||||
Deferred
tax liability | i 41.2 | i 42.4 | |||||
Fair
value of derivative liabilities | i 10.6 | i 2.4 | |||||
Redeemable
non-controlling interest | i 5.8 | i 9.3 | |||||
Partners’
equity: | |||||||
Common unitholders (144,358,720 and 353,117,434 units issued and outstanding, respectively) | i 2,220.3 | i 2,460.8 | |||||
Series
B preferred unitholders (59,302,666 and 58,728,994 units issued and outstanding, respectively) | i 893.2 | i 889.3 | |||||
Series
C preferred unitholders (400,000 units outstanding) | i 395.1 | i 395.1 | |||||
General
partner interest (1,594,974 equivalent units outstanding) | i 218.2 | i 231.2 | |||||
Accumulated
other comprehensive loss | ( i 15.6 | ) | ( i 2.1 | ) | |||
Non-controlling
interest | i 345.9 | i 309.8 | |||||
Total
partners’ equity | i 4,057.1 | i 4,284.1 | |||||
Total
liabilities and partners’ equity | $ | i 9,424.1 | $ | i 9,571.3 |
Three
Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(Unaudited) | |||||||||||||||
Revenues: | |||||||||||||||
Product
sales | $ | i 1,450.4 | $ | i 1,435.1 | $ | i 2,981.3 | $ | i 2,934.3 | |||||||
Product
sales—related parties | i — | i 27.2 | i — | i 30.8 | |||||||||||
Midstream
services | i 252.7 | i 142.4 | i 499.2 | i 234.6 | |||||||||||
Midstream
services—related parties | i — | i 175.2 | i — | i 341.4 | |||||||||||
Gain
(loss) on derivative activity | i 6.9 | ( i 15.2 | ) | i 8.7 | ( i 14.7 | ) | |||||||||
Total
revenues | i 1,710.0 | i 1,764.7 | i 3,489.2 | i 3,526.4 | |||||||||||
Operating
costs and expenses: | |||||||||||||||
Cost of sales (1) | i 1,300.1 | i 1,325.6 | i 2,663.5 | i 2,707.1 | |||||||||||
Operating
expenses | i 117.9 | i 113.4 | i 232.4 | i 222.6 | |||||||||||
General
and administrative | i 31.9 | i 29.1 | i 70.5 | i 55.3 | |||||||||||
Loss
on disposition of assets | i 0.1 | i 1.2 | i 0.1 | i 1.3 | |||||||||||
Depreciation
and amortization | i 153.7 | i 145.3 | i 305.8 | i 283.4 | |||||||||||
Loss
on secured term loan receivable | i 52.9 | i — | i 52.9 | i — | |||||||||||
Total
operating costs and expenses | i 1,656.6 | i 1,614.6 | i 3,325.2 | i 3,269.7 | |||||||||||
Operating
income | i 53.4 | i 150.1 | i 164.0 | i 256.7 | |||||||||||
Other
income (expense): | |||||||||||||||
Interest expense, net of interest income | ( i 54.3 | ) | ( i 43.7 | ) | ( i 103.6 | ) | ( i 87.4 | ) | |||||||
Income
from unconsolidated affiliates | i 4.7 | i 4.4 | i 10.0 | i 7.4 | |||||||||||
Other
income | i 0.3 | i — | i 0.3 | i 0.2 | |||||||||||
Total
other expense | ( i 49.3 | ) | ( i 39.3 | ) | ( i 93.3 | ) | ( i 79.8 | ) | |||||||
Income
before non-controlling interest and income taxes | i 4.1 | i 110.8 | i 70.7 | i 176.9 | |||||||||||
Income
tax benefit (provision) | i 0.7 | i 2.1 | ( i 0.2 | ) | i 1.1 | ||||||||||
Net
income | i 4.8 | i 112.9 | i 70.5 | i 178.0 | |||||||||||
Net
income attributable to non-controlling interest | i 0.7 | i 1.4 | i 3.6 | i 2.2 | |||||||||||
Net
income attributable to ENLK | $ | i 4.1 | $ | i 111.5 | $ | i 66.9 | $ | i 175.8 |
(1) | Includes
related party cost of sales of $ i 5.8 million and $ i 46.7
million for the three months ended June 30, 2019 and 2018, respectively, and $ i 13.9 million and $ i 80.8
million for the six months ended June 30, 2019 and 2018, respectively. |
Three
Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(Unaudited) | |||||||||||||||
Net
income | $ | i 4.8 | $ | i 112.9 | $ | i 70.5 | $ | i 178.0 | |||||||
Loss
on designated cash flow hedge (1) | ( i 13.5 | ) | i — | ( i 13.5 | ) | i — | |||||||||
Comprehensive
income (loss) | ( i 8.7 | ) | i 112.9 | i 57.0 | i 178.0 | ||||||||||
Comprehensive
income attributable to non-controlling interest | i 0.7 | i 1.4 | i 3.6 | i 2.2 | |||||||||||
Comprehensive
income (loss) attributable to ENLK | $ | ( i 9.4 | ) | $ | i 111.5 | $ | i 53.4 | $ | i 175.8 |
(1) | Includes
an immaterial amount of amortization to interest expense for the three and six months ended June 30, 2019 and 2018, respectively. |
Common
Units | Series B Preferred Units | Series C Preferred Units | General Partner Interest | Accumulated Other Comprehensive Loss | Non-Controlling Interest | Total | Redeemable
Non-controlling interest (Temporary Equity) | ||||||||||||||||||||||||||||||||||||
$ | Units | $ | Units | $ | Units | $ | Units | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||||||||||||||||||||||||
Balance,
December 31, 2018 | $ | i 2,460.8 | i 353.1 | $ | i 889.3 | i 58.7 | $ | i 395.1 | i 0.4 | $ | i 231.2 | i 1.6 | $ | ( i 2.1 | ) | $ | i 309.8 | $ | i 4,284.1 | $ | i 9.3 | ||||||||||||||||||||||
Adoption
of ASC 842 | i 0.3 | — | — | — | — | — | — | — | — | — | i 0.3 | — | |||||||||||||||||||||||||||||||
Balance,
January 1, 2019 | i 2,461.1 | i 353.1 | i 889.3 | i 58.7 | i 395.1 | i 0.4 | i 231.2 | i 1.6 | ( i 2.1 | ) | i 309.8 | i 4,284.4 | i 9.3 | ||||||||||||||||||||||||||||||
Conversion
of restricted units for common units, net of units withheld for taxes | ( i 2.8 | ) | i 0.5 | — | — | — | — | — | — | — | — | ( i 2.8 | ) | — | |||||||||||||||||||||||||||||
Unit-based
compensation | i 1.4 | — | — | — | — | — | i 12.1 | — | — | — | i 13.5 | — | |||||||||||||||||||||||||||||||
Distributions | ( i 139.4 | ) | — | ( i 16.5 | ) | i 0.5 | — | — | ( i 15.6 | ) | — | — | ( i 6.3 | ) | ( i 177.8 | ) | — | ||||||||||||||||||||||||||
Contributions
from non-controlling interests | — | — | — | — | — | — | — | — | — | i 15.7 | i 15.7 | — | |||||||||||||||||||||||||||||||
Fair
value adjustment related to redeemable non-controlling interest | i 2.1 | — | — | — | — | — | — | — | — | — | i 2.1 | ( i 2.1 | ) | ||||||||||||||||||||||||||||||
Issuance
of common units to ENLC for acquisition of EOGP | — | i 55.8 | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||
Conversion
of ENLK common units into ENLC units | — | ( i 265.0 | ) | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Net
income (loss) | i 47.5 | — | i 18.6 | — | i 6.0 | — | ( i 9.3 | ) | — | — | i 2.9 | i 65.7 | — | ||||||||||||||||||||||||||||||
Balance,
March 31, 2019 | i 2,369.9 | i 144.4 | i 891.4 | i 59.2 | i 401.1 | i 0.4 | i 218.4 | i 1.6 | ( i 2.1 | ) | i 322.1 | i 4,200.8 | i 7.2 | ||||||||||||||||||||||||||||||
Unit-based
compensation | i — | — | — | — | — | — | i 6.4 | — | — | — | i 6.4 | — | |||||||||||||||||||||||||||||||
Distributions | ( i 137.2 | ) | — | ( i 16.7 | ) | i 0.1 | ( i 12.0 | ) | — | i — | — | — | ( i 6.4 | ) | ( i 172.3 | ) | — | ||||||||||||||||||||||||||
Contributions
from non-controlling interests | — | — | — | — | — | — | — | — | — | i 29.5 | i 29.5 | — | |||||||||||||||||||||||||||||||
Loss
on designated cash flow hedge | — | — | — | — | — | — | — | — | ( i 13.5 | ) | — | ( i 13.5 | ) | — | |||||||||||||||||||||||||||||
Fair
value adjustment related to redeemable non-controlling interest | i 1.4 | — | — | — | — | — | — | — | — | — | i 1.4 | ( i 1.4 | ) | ||||||||||||||||||||||||||||||
Net
income (loss) | ( i 13.8 | ) | — | i 18.5 | — | i 6.0 | — | ( i 6.6 | ) | — | — | i 0.7 | i 4.8 | — | |||||||||||||||||||||||||||||
Balance,
June 30, 2019 | $ | i 2,220.3 | i 144.4 | $ | i 893.2 | i 59.3 | $ | i 395.1 | i 0.4 | $ | i 218.2 | i 1.6 | $ | ( i 15.6 | ) | $ | i 345.9 | $ | i 4,057.1 | $ | i 5.8 |
Common
Units | Series B Preferred Units | Series C Preferred Units | General Partner Interest | Accumulated Other Comprehensive Loss | Non-Controlling Interest | Total | Redeemable
Non-Controlling Interest (Temporary Equity) | ||||||||||||||||||||||||||||||||||||
$ | Units | $ | Units | $ | Units | $ | Units | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||||||||||||||||||||||||
Balance,
December 31, 2017 | $ | i 3,108.6 | i 349.7 | $ | i 864.1 | i 57.1 | $ | i 395.1 | i 0.4 | $ | i 206.6 | i 1.6 | $ | ( i 2.1 | ) | $ | i 233.2 | $ | i 4,805.5 | $ | i 4.6 | ||||||||||||||||||||||
Issuance
of common units | i 0.9 | i 0.1 | — | — | — | — | — | — | — | — | i 0.9 | — | |||||||||||||||||||||||||||||||
Conversion
of restricted units for common units, net of units withheld for taxes | ( i 2.7 | ) | i 0.4 | — | — | — | — | — | — | — | — | ( i 2.7 | ) | — | |||||||||||||||||||||||||||||
Unit-based
compensation | i 4.4 | — | — | — | — | — | i 4.4 | — | — | — | i 8.8 | — | |||||||||||||||||||||||||||||||
Distributions | ( i 137.6 | ) | — | ( i 16.0 | ) | i 0.4 | i — | — | ( i 15.4 | ) | — | — | ( i 10.0 | ) | ( i 179.0 | ) | — | ||||||||||||||||||||||||||
Contributions
from non-controlling interests | — | — | — | — | — | — | — | — | — | i 33.3 | i 33.3 | — | |||||||||||||||||||||||||||||||
Adjustment
for acquisition of EOGP (Note 1) | i 2.8 | — | — | — | — | — | — | — | — | ( i 2.8 | ) | — | — | ||||||||||||||||||||||||||||||
Net
income | i 21.6 | — | i 21.9 | — | i 6.0 | — | i 14.8 | — | — | i 0.8 | i 65.1 | — | |||||||||||||||||||||||||||||||
Balance,
March 31, 2018 | i 2,998.0 | i 350.2 | i 870.0 | i 57.5 | i 401.1 | i 0.4 | i 210.4 | i 1.6 | ( i 2.1 | ) | i 254.5 | i 4,731.9 | i 4.6 | ||||||||||||||||||||||||||||||
Conversion
of restricted units for common units, net of units withheld for taxes | ( i 0.7 | ) | i 0.1 | — | — | — | — | — | — | — | — | ( i 0.7 | ) | — | |||||||||||||||||||||||||||||
Unit-based
compensation | i 4.0 | — | — | — | — | — | i 4.0 | — | — | — | i 8.0 | — | |||||||||||||||||||||||||||||||
Distributions | ( i 137.4 | ) | — | ( i 16.2 | ) | i 0.4 | ( i 12.0 | ) | — | ( i 15.5 | ) | — | — | ( i 13.4 | ) | ( i 194.5 | ) | — | |||||||||||||||||||||||||
Contributions
from non-controlling interests | — | — | — | — | — | — | — | — | — | i 48.3 | i 48.3 | — | |||||||||||||||||||||||||||||||
Adjustment
for acquisition of EOGP (Note 1) | i 6.6 | — | — | — | — | — | — | — | — | ( i 6.6 | ) | — | — | ||||||||||||||||||||||||||||||
Net
income | i 58.9 | — | i 22.8 | — | i 6.0 | — | i 23.8 | — | — | i 1.4 | i 112.9 | — | |||||||||||||||||||||||||||||||
Balance,
June 30, 2018 | $ | i 2,929.4 | i 350.3 | $ | i 876.6 | i 57.9 | $ | i 395.1 | i 0.4 | $ | i 222.7 | i 1.6 | $ | ( i 2.1 | ) | $ | i 284.2 | $ | i 4,705.9 | $ | i 4.6 |
Six
Months Ended June 30, | |||||||
2019 | 2018 | ||||||
(Unaudited) | |||||||
Cash flows from operating activities: | |||||||
Net income | $ | i 70.5 | $ | i 178.0 | |||
Adjustments
to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | i 305.8 | i 283.4 | |||||
Loss
on secured term loan receivable | i 52.9 | i — | |||||
Non-cash
unit-based compensation | i 18.9 | i 14.6 | |||||
(Gain)
loss on derivatives recognized in net income | ( i 8.7 | ) | i 14.7 | ||||
Cash
settlements on derivatives | i 4.9 | ( i 0.4 | ) | ||||
Amortization
of debt issue costs, net discount (premium) of notes | i 2.9 | i 2.4 | |||||
Distribution
of earnings from unconsolidated affiliates | i 9.7 | i 9.5 | |||||
Income
from unconsolidated affiliates | ( i 10.0 | ) | ( i 7.4 | ) | |||
Non-cash
revenue from contract restructuring | i — | ( i 45.5 | ) | ||||
Other
operating activities | ( i 4.2 | ) | ( i 0.9 | ) | |||
Changes
in assets and liabilities, net of assets acquired and liabilities assumed: | |||||||
Accounts receivable, accrued revenue, and other | i 259.7 | ( i 46.6 | ) | ||||
Natural
gas and NGLs inventory, prepaid expenses, and other | ( i 7.8 | ) | ( i 40.2 | ) | |||
Accounts
payable, accrued product purchases, and other accrued liabilities | ( i 179.0 | ) | i 69.1 | ||||
Net
cash provided by operating activities | i 515.6 | i 430.7 | |||||
Cash
flows from investing activities: | |||||||
Additions to property and equipment | ( i 428.4 | ) | ( i 404.4 | ) | |||
Other
investing activities | i 1.5 | i 2.6 | |||||
Net
cash used in investing activities | ( i 426.9 | ) | ( i 401.8 | ) | |||
Cash
flows from financing activities: | |||||||
Proceeds from borrowings | i 3,058.5 | i 1,346.0 | |||||
Payments
on borrowings | ( i 2,870.0 | ) | ( i 826.0 | ) | |||
Payment
of installment payable for EOGP acquisition | i — | ( i 250.0 | ) | ||||
Debt
financing costs | ( i 9.7 | ) | i — | ||||
Proceeds
from issuance of common units | i — | i 0.9 | |||||
Distributions
to non-controlling interests | ( i 12.7 | ) | ( i 23.4 | ) | |||
Contributions
by non-controlling interests, including contributions from affiliates of $27.3 for the six months ended June 30, 2018 | i 45.2 | i 81.6 | |||||
Distributions
to Series B Preferred Units | ( i 33.2 | ) | ( i 32.2 | ) | |||
Distributions
to Series C Preferred Units | ( i 12.0 | ) | ( i 12.0 | ) | |||
Distributions
to common unitholders and to general partner | ( i 292.2 | ) | ( i 305.9 | ) | |||
Other
financing activities | ( i 3.6 | ) | ( i 2.2 | ) | |||
Net
cash used in financing activities | ( i 129.7 | ) | ( i 23.2 | ) | |||
Net
increase (decrease) in cash and cash equivalents | ( i 41.0 | ) | i 5.7 | ||||
Cash
and cash equivalents, beginning of period | i 99.5 | i 30.8 | |||||
Cash
and cash equivalents, end of period | $ | i 58.5 | $ | i 36.5 | |||
Supplemental
disclosures of cash flow information: | |||||||
Cash paid for interest | $ | i 103.4 | $ | i 87.6 | |||
Cash
paid for income taxes | $ | i 1.2 | $ | i 0.4 | |||
Non-cash
investing activities: | |||||||
Non-cash accrual of property and equipment | $ | ( i 5.8 | ) | $ | ( i 5.0 | ) | |
Discounted
secured term loan receivable from contract restructuring | $ | i — | $ | i 47.7 |
(a) | Organization
of Business |
• | Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into i 1.15
ENLC common units, which resulted in ENLC owning all of the remaining outstanding ENLK common units. |
• | Our general partner’s incentive distribution rights in ENLK were eliminated. |
• | The Series B Preferred Units continue to be issued and outstanding, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership
agreement of ENLK. See “Note 7—Partners' Capital” for additional information regarding the modified terms of the Series B Preferred Units. |
• | ENLC issued to Enfield, the current holder of the Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an
additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled. |
• | The Series C Preferred Units and all of ENLK’s then-existing senior notes continue to be issued and outstanding following the Merger. |
• | Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan has been converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time. |
• | Each
unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan has been modified such that the performance metric for such award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger. |
• | ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “Note 6—Long-Term Debt” for additional
information regarding the Term Loan. |
• | We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, ENLC entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility. |
(b) | Nature
of Business |
• | gathering, compressing, treating, processing, transporting, storing, and selling natural gas; |
• | fractionating, transporting, storing, and selling NGLs; and |
• | gathering,
transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. |
(a) | i Basis
of Presentation |
(b) | i Revenue
Recognition |
MVC and Firm Transportation Commitments
(1) | |||
2019 (remaining) | $ | i 122.0 | |
2020 | i 243.9 | ||
2021 | i 92.9 | ||
2022 | i 82.5 | ||
2023 | i 79.9 | ||
Thereafter | i 228.1 | ||
Total | $ | i 849.3 |
(1) | Amounts
do not represent expected shortfall under these commitments. |
Gross
Carrying Amount | Accumulated Amortization | Net Carrying Amount | |||||||||
Six Months Ended June 30, 2019 | |||||||||||
Customer relationships, beginning of period | $ | i 1,795.8 | $ | ( i 422.2 | ) | $ | i 1,373.6 | ||||
Amortization
expense | — | ( i 61.9 | ) | ( i 61.9 | ) | ||||||
Customer
relationships, end of period | $ | i 1,795.8 | $ | ( i 484.1 | ) | $ | i 1,311.7 |
2019 (remaining) | $ | i 61.8 | |
2020 | i 123.7 | ||
2021 | i 123.7 | ||
2022 | i 123.7 | ||
2023 | i 123.6 | ||
Thereafter | i 755.2 | ||
Total | $ | i 1,311.7 |
• | Office space- Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $ i 62.5
million of our lease liability and $ i 41.5 million of our right-of-use asset as of June 30, 2019. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share
of the building expenses each month and expensed as incurred. |
• | Compression and other field equipment- We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically
renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $ i 28.2 million of our lease liability and $ i 30.1
million of our right-of-use asset as of June 30, 2019. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred. |
• | Office equipment- We rent office equipment for a monthly fee. These leases are typically for several years and represent $ i 0.7
million of our lease liability and $ i 0.7 million of our right-of-use asset as of June 30, 2019. |
• | Land
and land easements- We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $ i 15.0 million of our lease liability and $ i 13.1
million of our right-of-use asset as of June 30, 2019. |
Finance leases: | |||
Property and equipment | $ | i 5.2 | |
Accumulated depreciation | ( i 3.0 | ) | |
Property
and equipment, net of accumulated depreciation | $ | i 2.2 | |
Other current liabilities | $ | i 0.4 | |
Operating
leases: | |||
Other assets, net | $ | i 83.2 | |
Other current liabilities | $ | i 21.7 | |
Other
long-term liabilities | $ | i 84.3 | |
Other lease information | |||
Weighted-average
remaining lease term - Finance leases | i 0.3 years | ||
Weighted-average remaining lease term - Operating leases | i 10.7
years | ||
Weighted-average discount rate - Finance leases | i 9.3 | % | |
Weighted-average discount rate - Operating leases | i 5.2 | % |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||
2019 | 2019 | ||||||
Finance
lease expense: | |||||||
Amortization of right-of-use asset | $ | i 2.3 | $ | i 3.0 | |||
Operating
lease expense: | |||||||
Long-term operating lease expense | i 8.3 | i 14.6 | |||||
Short-term
lease expense | i 8.9 | i 15.8 | |||||
Variable
lease expense | i 1.4 | i 3.0 | |||||
Total
lease expense | $ | i 20.9 | $ | i 36.4 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||
2019 | 2019 | ||||||
Supplemental
cash flow information: | |||||||
Cash payments for finance leases included in cash flows from financing activities | $ | i 0.4 | $ | i 0.8 | |||
Cash
payments for operating leases included in cash flows from operating activities | $ | i 8.2 | $ | i 15.4 | |||
Right-of-use
assets obtained in exchange for operating lease liabilities | $ | i 14.6 | $ | i 95.2 |
Total | 2019
(remaining) | 2020 | 2021 | 2022 | 2023 | Thereafter | ||||||||||||||||||||||
Undiscounted finance lease liability | $ | i 0.4 | $ | i 0.4 | $ | i — | $ | i — | $ | i — | $ | i — | $ | i — | ||||||||||||||
Finance
lease liability | i 0.4 | i 0.4 | i — | i — | i — | i — | i — | |||||||||||||||||||||
Undiscounted
operating lease liability | i 146.5 | i 13.5 | i 22.4 | i 16.1 | i 9.4 | i 8.9 | i 76.2 | |||||||||||||||||||||
Reduction
due to present value | ( i 40.5 | ) | ( i 2.6 | ) | ( i 4.5 | ) | ( i 3.8 | ) | ( i 3.4 | ) | ( i 3.1 | ) | ( i 23.1 | ) | ||||||||||||||
Operating
lease liability | i 106.0 | i 10.9 | i 17.9 | i 12.3 | i 6.0 | i 5.8 | i 53.1 | |||||||||||||||||||||
Total
lease liability | $ | i 106.4 | $ | i 11.3 | $ | i 17.9 | $ | i 12.3 | $ | i 6.0 | $ | i 5.8 | $ | i 53.1 |
Outstanding Principal | Premium (Discount) | Long-Term Debt | Outstanding Principal | Premium
(Discount) | Long-Term Debt | ||||||||||||||||||
Intercompany debt (1) | $ | i 1,438.5 | $ | i — | $ | i 1,438.5 | $ | i — | $ | i — | $ | i — | |||||||||||
Term
Loan due 2021 (2) | i — | i — | i — | i 850.0 | i — | i 850.0 | |||||||||||||||||
2.70%
Senior unsecured notes due 2019 (3) | i — | i — | i — | i 400.0 | i — | i 400.0 | |||||||||||||||||
4.40%
Senior unsecured notes due 2024 | i 550.0 | i 1.6 | i 551.6 | i 550.0 | i 1.8 | i 551.8 | |||||||||||||||||
4.15%
Senior unsecured notes due 2025 | i 750.0 | ( i 0.8 | ) | i 749.2 | i 750.0 | ( i 0.9 | ) | i 749.1 | |||||||||||||||
4.85%
Senior unsecured notes due 2026 | i 500.0 | ( i 0.5 | ) | i 499.5 | i 500.0 | ( i 0.5 | ) | i 499.5 | |||||||||||||||
5.60%
Senior unsecured notes due 2044 | i 350.0 | ( i 0.2 | ) | i 349.8 | i 350.0 | ( i 0.2 | ) | i 349.8 | |||||||||||||||
5.05%
Senior unsecured notes due 2045 | i 450.0 | ( i 6.1 | ) | i 443.9 | i 450.0 | ( i 6.2 | ) | i 443.8 | |||||||||||||||
5.45%
Senior unsecured notes due 2047 | i 500.0 | ( i 0.1 | ) | i 499.9 | i 500.0 | ( i 0.1 | ) | i 499.9 | |||||||||||||||
Debt
classified as long-term, including current maturities of long-term debt | $ | i 4,538.5 | $ | ( i 6.1 | ) | i 4,532.4 | $ | i 4,350.0 | $ | ( i 6.1 | ) | i 4,343.9 | |||||||||||
Debt
issuance cost (4) | ( i 31.4 | ) | ( i 24.3 | ) | |||||||||||||||||||
Less:
Current maturities of long-term debt (3) | i — | ( i 399.8 | ) | ||||||||||||||||||||
Long-term
debt, net of unamortized issuance cost | $ | i 4,501.0 | $ | i 3,919.8 |
(1) | Intercompany
debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through an intercompany arrangement with ENLC. Interest charged to ENLK for borrowings made through the intercompany arrangement will be the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes. |
(2) | In December 2018, ENLK entered into an $ i 850.0
million, three-year unsecured Term Loan. Borrowings under the Term Loan bear interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was i 3.9% at December 31, 2018. In connection with the closing of the Merger, the Term Loan was assumed
by ENLC, and we became a guarantor of the Term Loan. |
(3) | The i 2.70% senior unsecured notes matured on April 1, 2019. Therefore,
the outstanding principal balance, net of discount and debt issuance costs, is classified as “Current maturities of long-term debt” on the consolidated balance sheet as of December 31, 2018. |
(4) | Net of amortization of $ i 11.9
million and $ i 15.3 million at June 30, 2019 and December 31, 2018, respectively. |
(a) | Series
B Preferred Units |
Declaration period | Distribution paid as additional Series B Preferred Units | Cash Distribution (in millions) | Date paid/payable | ||||||
2019 | |||||||||
Fourth
Quarter of 2018 | i 425,785 | $ | i 16.5 | ||||||
First Quarter of 2019 | i 147,887 | $ | i 16.7 | ||||||
Second Quarter of 2019 | i 148,257 | $ | i 17.1 | ||||||
2018 | |||||||||
Fourth
Quarter of 2017 | i 413,658 | $ | i 16.0 | ||||||
First Quarter of 2018 | i 416,657 | $ | i 16.2 | ||||||
Second Quarter of 2018 | i 419,678 | $ | i 16.3 |
(b) | Series C Preferred Units |
(c) | Common Unit Distributions |
Declaration period | Distribution/unit | Date paid/payable | ||||
2019 | ||||||
Fourth
Quarter of 2018 | $ | i 0.39 | ||||
2018 | ||||||
Fourth Quarter of 2017 | $ | i 0.39 | ||||
First Quarter of 2018 | $ | i 0.39 | ||||
Second Quarter of 2018 | $ | i 0.39 |
(d) | Allocation of ENLK Income |
Three
Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Income allocation for incentive distributions | $ | i — | $ | i 14.8 | $ | i — | $ | i 29.6 | |||||||
Unit-based
compensation attributable to ENLC’s restricted and performance units | ( i 6.4 | ) | ( i 4.0 | ) | ( i 18.5 | ) | ( i 8.4 | ) | |||||||
General
partner share of net income (loss) | ( i 0.2 | ) | i 0.4 | i 0.2 | i 0.6 | ||||||||||
General
partner interest in EOGP acquisition | i — | i 12.6 | i 2.4 | i 16.8 | |||||||||||
General
partner interest in net income (loss) | $ | ( i 6.6 | ) | $ | i 23.8 | $ | ( i 15.9 | ) | $ | i 38.6 |
Three
Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
GCF | |||||||||||||||
Distributions | $ | i 7.4 | $ | i 5.4 | $ | i 9.6 | $ | i 11.1 | |||||||
Equity
in income | $ | i 5.2 | $ | i 4.8 | $ | i 10.9 | $ | i 9.4 | |||||||
Cedar
Cove JV | |||||||||||||||
Contributions | $ | i — | $ | i 0.1 | $ | i — | $ | i 0.1 | |||||||
Distributions | $ | i 0.2 | $ | i — | $ | i 0.5 | $ | i 0.3 | |||||||
Equity
in loss | $ | ( i 0.5 | ) | $ | ( i 0.4 | ) | $ | ( i 0.9 | ) | $ | ( i 2.0 | ) | |||
Total | |||||||||||||||
Contributions | $ | i — | $ | i 0.1 | $ | i — | $ | i 0.1 | |||||||
Distributions | $ | i 7.6 | $ | i 5.4 | $ | i 10.1 | $ | i 11.4 | |||||||
Equity
in income | $ | i 4.7 | $ | i 4.4 | $ | i 10.0 | $ | i 7.4 |
GCF | $ | i 43.2 | $ | i 41.9 | |||
Cedar
Cove JV | i 36.8 | i 38.2 | |||||
Total
investment in unconsolidated affiliates | $ | i 80.0 | $ | i 80.1 |
(a) | Long-Term Incentive Plans |
Three
Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Cost of unit-based compensation charged to operating expense | $ | i 2.1 | $ | i 2.3 | $ | i 2.4 | $ | i 4.3 | |||||||
Cost
of unit-based compensation charged to general and administrative expense | i 5.9 | i 7.2 | i 16.5 | i 10.3 | |||||||||||
Total
unit-based compensation expense | $ | i 8.0 | $ | i 9.5 | $ | i 18.9 | $ | i 14.6 |
(b) | EnLink
Midstream Partners, LP Restricted Incentive Units |
Six
Months Ended June 30, 2019 | |||||||
EnLink Midstream Partners, LP Restricted Incentive Units: | Number of Units | Weighted Average Grant-Date Fair Value | |||||
Non-vested, beginning of period | i 2,556,270 | $ | i 14.43 | ||||
Vested
(1) | ( i 722,853 | ) | i 10.02 | ||||
Forfeited | ( i 4,490 | ) | i 11.93 | ||||
Converted
to ENLC (2) | ( i 1,828,927 | ) | i 16.11 | ||||
Non-vested,
end of period | i — | $ | i — |
(1) | Vested
units included i 249,201 units withheld for payroll taxes paid on behalf of employees. |
(2) | As a result of the Merger, the Legacy ENLK Awards converted into ENLC unit-based
awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
EnLink Midstream Partners, LP Restricted Incentive Units: | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Aggregate
intrinsic value of units vested | $ | i — | $ | i 0.4 | $ | i 8.0 | $ | i 9.1 | ||||||||
Fair
value of units vested | $ | i — | $ | i 0.5 | $ | i 7.2 | $ | i 13.3 |
(c) | EnLink Midstream Partners, LP Performance Units |
Six
Months Ended June 30, 2019 | |||||||
EnLink Midstream Partners, LP Performance Units: | Number of Units | Weighted Average Grant-Date Fair Value | |||||
Non-vested, beginning of period | i 451,669 | $ | i 17.74 | ||||
Vested
(1) | ( i 161,410 | ) | i 10.54 | ||||
Converted
to ENLC (2) | ( i 290,259 | ) | i 28.31 | ||||
Non-vested,
end of period | i — | $ | i — |
(1) | Vested
units included i 62,403 units withheld for payroll taxes paid on behalf of employees. |
(2) | As a result of the Merger, the
performance-based Legacy ENLK Awards converted into ENLC unit-based performance awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. |
Six Months Ended June 30, | ||||||||
EnLink Midstream Partners, LP Performance Units: | 2019 | 2018 | ||||||
Aggregate
intrinsic value of units vested | $ | i 2.1 | $ | i 2.0 | ||||
Fair
value of units vested | $ | i 1.7 | $ | i 4.1 |
(d) | EnLink Midstream, LLC Restricted Incentive Units |
Six Months Ended June 30, 2019 | ||||||||
EnLink Midstream, LLC Restricted Incentive Units: | Number of Units | Weighted Average Grant-Date Fair Value | ||||||
Non-vested, beginning of period | i 2,425,867 | $ | i 14.62 | |||||
Granted
(1) | i 1,835,494 | i 11.44 | ||||||
Vested
(1)(2) | ( i 1,255,211 | ) | i 10.47 | |||||
Forfeited | ( i 272,185 | ) | i 10.86 | |||||
Converted
from ENLK (3) | i 2,103,266 | i 14.01 | ||||||
Non-vested,
end of period | i 4,837,231 | $ | i 14.44 | |||||
Aggregate
intrinsic value, end of period (in millions) | $ | i 48.8 |
(1) | Restricted
incentive units typically vest at the end of three years. In March 2019, ENLC granted i 420,842 restricted incentive units with a fair value of $ i 4.8
million to officers and certain employees as bonus payments for 2018, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items. |
(2) | Vested units included i 420,778
units withheld for payroll taxes paid on behalf of employees. |
(3) | Represents Legacy ENLK Awards that were converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. |
Three
Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
EnLink Midstream, LLC Restricted Incentive Units: | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Aggregate intrinsic value of units
vested | $ | i 0.5 | $ | i 0.4 | $ | i 12.9 | $ | i 9.3 | ||||||||
Fair
value of units vested | $ | i 0.5 | $ | i 0.4 | $ | i 13.1 | $ | i 13.5 |
(e) | EnLink Midstream, LLC’s Performance Units |
Six Months Ended June 30, 2019 | ||||||||
EnLink Midstream, LLC Performance Units: | Number of Units | Weighted Average Grant-Date Fair Value | ||||||
Non-vested, beginning of period | i 418,149 | $ | i 19.15 | |||||
Granted | i 931,469 | i 13.02 | ||||||
Vested
(1) | ( i 161,286 | ) | i 11.71 | |||||
Forfeited | ( i 92,422 | ) | i 20.41 | |||||
Converted
from ENLK (2) | i 333,798 | i 25.84 | ||||||
Non-vested,
end of period | i 1,429,708 | $ | i 17.48 | |||||
Aggregate
intrinsic value, end of period (in millions) | $ | i 14.4 |
(1) | Vested
units included i 62,219 units withheld for payroll taxes paid on behalf of employees. |
(2) | As a result of the Merger, the performance-based Legacy
ENLK Awards converted into ENLC performance-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. |
Six Months Ended June 30, | ||||||||
EnLink Midstream, LLC Performance Units: | 2019 | 2018 | ||||||
Aggregate
intrinsic value of units vested | $ | i 1.8 | $ | i 1.9 | ||||
Fair
value of units vested | $ | i 1.9 | $ | i 4.2 |
Performance Level | Achieved ENLC TSR Position Relative to Designated Peer Companies | Vesting percentage of the Tranche TSR Units | ||
Below
Threshold | Less than 25% | i 0% | ||
Threshold | Equal
to 25% | i 50% | ||
Target | Equal to 50% | i 100% | ||
Maximum | Greater
than or Equal to 75% | i 200% |
Performance Level | ENLC’s Achieved Cash Flow | Vesting percentage of the Tranche CF Units | ||
Below Threshold | Less than $1.43 | i 0% | ||
Threshold | Equal
to $1.43 | i 50% | ||
Target | Equal to $1.55 | i 100% | ||
Maximum | Greater
than or Equal to $1.72 | i 200% |
EnLink Midstream, LLC Performance Units: | June
2019 | March 2019 | ||||||
Beginning TSR price | $ | i 9.84 | $ | i 10.92 | ||||
Risk-free
interest rate | i 1.72 | % | i 2.42 | % | ||||
Volatility
factor | i 33.50 | % | i 33.86 | % | ||||
Distribution
yield | i 11.5 | % | i 9.7 | % |
Fair value of derivative liabilities—current | $ | ( i 3.3 | ) |
Fair
value of derivative liabilities—long-term | ( i 10.2 | ) | |
Net fair value of derivatives | $ | ( i 13.5 | ) |
Three Months Ended June 30, | Six Months Ended June
30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Change in fair value of derivatives | $ | i 7.2 | $ | ( i 10.5 | ) | $ | i 5.2 | $ | ( i 14.0 | ) | |||||
Realized
gain (loss) on derivatives | ( i 0.3 | ) | ( i 4.7 | ) | i 3.5 | ( i 0.7 | ) | ||||||||
Gain
(loss) on derivative activity | $ | i 6.9 | $ | ( i 15.2 | ) | $ | i 8.7 | $ | ( i 14.7 | ) |
Fair value of derivative assets—current | $ | i 9.5 | $ | i 28.6 | |||
Fair
value of derivative assets—long-term | i 7.1 | i 4.1 | |||||
Fair
value of derivative liabilities—current | ( i 2.5 | ) | ( i 21.8 | ) | |||
Fair
value of derivative liabilities—long-term | ( i 0.4 | ) | ( i 2.4 | ) | |||
Net
fair value of derivatives | $ | i 13.7 | $ | i 8.5 |
Commodity | Instruments | Unit | Volume | Fair Value | |||||||
NGL (short contracts) | Swaps | Gallons | ( i 24.2 | ) | $ | i 3.0 | |||||
NGL
(long contracts) | Swaps | Gallons | i 15.0 | ( i 0.6 | ) | ||||||
Natural
gas (short contracts) | Swaps | MMBtu | ( i 2.4 | ) | i 0.4 | ||||||
Natural
gas (long contracts) | Swaps | MMBtu | i 6.3 | ( i 0.4 | ) | ||||||
Crude
and condensate (short contracts) | Swaps | MMbbls | ( i 12.3 | ) | i 5.6 | ||||||
Crude
and condensate (long contracts) | Swaps | MMbbls | i 0.8 | i 5.7 | |||||||
Total
fair value of derivatives | $ | i 13.7 |
Level 2 | ||||||||
Interest rate swaps (1) | $ | ( i 13.5 | ) | $ | i — | |||
Commodity
swaps (2) | $ | i 13.7 | $ | i 8.5 |
(1) | The
fair values of the interest rate swaps are estimated based on the difference between expected cash flows calculated at the contracted interest rates and the expected cash flows using observable benchmarks for the variable interest rates. |
(2) | The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820. |
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
Long-term
debt (1) | $ | i 4,501.0 | $ | i 4,368.9 | $ | i 4,319.6 | $ | i 3,953.6 | |||||||
Secured
term loan receivable (2) | $ | i — | $ | i — | $ | i 51.1 | $ | i 51.1 |
(1) | The
carrying value of long-term debt as of December 31, 2018 includes current maturities. The carrying value of long-term debt is reduced by debt issuance costs of $ i 31.4 million and $ i 24.3
million at June 30, 2019 and December 31, 2018, respectively. The respective fair values do not factor in debt issuance costs. |
(2) | In late May 2019, White Star, the counterparty to our $ i 58.0
million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional information regarding this transaction, refer to “Note 2—Significant Accounting Policies.” |
• | Permian
Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in west Texas and eastern New Mexico and our crude operations in south Texas; |
• | North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in north Texas; |
• | Oklahoma
Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas; |
• | Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana and our crude oil operations in ORV; and |
• | Corporate
Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in south Texas, our derivative activity, and our general corporate assets and expenses. |
Permian | North
Texas | Oklahoma | Louisiana | Corporate | Totals | ||||||||||||||||||
Three Months Ended June 30, 2019 | |||||||||||||||||||||||
Natural
gas sales | $ | ( i 1.0 | ) | $ | i 31.9 | $ | i 60.3 | $ | i 102.6 | $ | i — | $ | i 193.8 | ||||||||||
NGL
sales | i 0.8 | i 8.7 | i 4.3 | i 498.8 | i — | i 512.6 | |||||||||||||||||
Crude
oil and condensate sales | i 632.0 | i — | i 28.6 | i 83.5 | i — | i 744.1 | |||||||||||||||||
Other
| i — | i — | ( i 0.1 | ) | i — | i — | ( i 0.1 | ) | |||||||||||||||
Product
sales | i 631.8 | i 40.6 | i 93.1 | i 684.9 | i — | i 1,450.4 | |||||||||||||||||
Natural
gas sales—related parties | i 0.4 | i 0.3 | i — | i — | ( i 0.7 | ) | i — | ||||||||||||||||
NGL
sales—related parties | i 76.4 | i 22.2 | i 104.6 | i 5.3 | ( i 208.5 | ) | i — | ||||||||||||||||
Crude
oil and condensate sales—related parties | i 6.9 | i 1.7 | i — | i — | ( i 8.6 | ) | i — | ||||||||||||||||
Product
sales—related parties | i 83.7 | i 24.2 | i 104.6 | i 5.3 | ( i 217.8 | ) | i — | ||||||||||||||||
Gathering
and transportation | i 11.3 | i 49.0 | i 59.2 | i 16.7 | i — | i 136.2 | |||||||||||||||||
Processing | i 7.3 | i 35.7 | i 35.7 | i 0.8 | i — | i 79.5 | |||||||||||||||||
NGL
services | i — | i — | i — | i 10.0 | i — | i 10.0 | |||||||||||||||||
Crude
services | i 5.3 | i — | i 5.2 | i 12.9 | i — | i 23.4 | |||||||||||||||||
Other
services | i 2.9 | i 0.3 | i 0.2 | i 0.2 | i — | i 3.6 | |||||||||||||||||
Midstream
services | i 26.8 | i 85.0 | i 100.3 | i 40.6 | i — | i 252.7 | |||||||||||||||||
NGL
services—related parties | i — | i — | i — | ( i 0.3 | ) | i 0.3 | i — | ||||||||||||||||
Crude
services—related parties | i — | i — | i 1.2 | i — | ( i 1.2 | ) | i — | ||||||||||||||||
Midstream
services—related parties | i — | i — | i 1.2 | ( i 0.3 | ) | ( i 0.9 | ) | i — | |||||||||||||||
Revenue
from contracts with customers | i 742.3 | i 149.8 | i 299.2 | i 730.5 | ( i 218.7 | ) | i 1,703.1 | ||||||||||||||||
Cost
of sales | ( i 680.5 | ) | ( i 51.0 | ) | ( i 159.4 | ) | ( i 627.9 | ) | i 218.7 | ( i 1,300.1 | ) | ||||||||||||
Operating
expenses | ( i 28.4 | ) | ( i 25.8 | ) | ( i 26.1 | ) | ( i 37.6 | ) | i — | ( i 117.9 | ) | ||||||||||||
Gain
on derivative activity | i — | i — | i — | i — | i 6.9 | i 6.9 | |||||||||||||||||
Segment
profit | $ | i 33.4 | $ | i 73.0 | $ | i 113.7 | $ | i 65.0 | $ | i 6.9 | $ | i 292.0 | |||||||||||
Depreciation
and amortization | $ | ( i 30.1 | ) | $ | ( i 36.9 | ) | $ | ( i 47.6 | ) | $ | ( i 36.9 | ) | $ | ( i 2.2 | ) | $ | ( i 153.7 | ) | |||||
Goodwill | $ | i — | $ | i — | $ | i 190.3 | $ | i — | $ | i — | $ | i 190.3 | |||||||||||
Capital
expenditures | $ | i 52.4 | $ | i 27.0 | $ | i 70.3 | $ | i 19.5 | $ | i 2.4 | $ | i 171.6 |
Permian | North
Texas | Oklahoma | Louisiana | Corporate | Totals | ||||||||||||||||||
Three Months Ended June 30, 2018 | |||||||||||||||||||||||
Natural
gas sales | $ | i 33.5 | $ | i 23.3 | $ | i 37.9 | $ | i 122.7 | $ | i — | $ | i 217.4 | |||||||||||
NGL
sales | i 0.3 | i — | i 3.6 | i 627.9 | i — | i 631.8 | |||||||||||||||||
Crude
oil and condensate sales | i 511.5 | i — | i 23.3 | i 51.1 | i — | i 585.9 | |||||||||||||||||
Product
sales | i 545.3 | i 23.3 | i 64.8 | i 801.7 | i — | i 1,435.1 | |||||||||||||||||
Natural
gas sales—related parties | i — | i — | i 1.9 | i — | i — | i 1.9 | |||||||||||||||||
NGL
sales—related parties | i 122.9 | i 11.5 | i 140.4 | i 28.9 | ( i 278.7 | ) | i 25.0 | ||||||||||||||||
Crude
oil and condensate sales—related parties | i 0.4 | i 0.4 | i 0.3 | i 0.1 | ( i 0.9 | ) | i 0.3 | ||||||||||||||||
Product
sales—related parties | i 123.3 | i 11.9 | i 142.6 | i 29.0 | ( i 279.6 | ) | i 27.2 | ||||||||||||||||
Gathering
and transportation | i 7.6 | i 6.8 | i 25.6 | i 16.7 | i — | i 56.7 | |||||||||||||||||
Processing | i 7.3 | i 2.2 | i 47.4 | i 1.1 | i — | i 58.0 | |||||||||||||||||
NGL
services | i — | i — | i — | i 10.3 | i — | i 10.3 | |||||||||||||||||
Crude
services | i 0.1 | i — | i — | i 14.9 | i — | i 15.0 | |||||||||||||||||
Other
services | i 2.0 | i — | ( i 0.1 | ) | i 0.5 | i — | i 2.4 | ||||||||||||||||
Midstream
services | i 17.0 | i 9.0 | i 72.9 | i 43.5 | i — | i 142.4 | |||||||||||||||||
Gathering
and transportation—related parties | i — | i 61.4 | i 38.7 | i — | i — | i 100.1 | |||||||||||||||||
Processing—related
parties | i — | i 46.8 | i 23.1 | i — | i — | i 69.9 | |||||||||||||||||
Crude
services—related parties | i 4.3 | i — | i 0.7 | i — | i — | i 5.0 | |||||||||||||||||
Other
services—related parties | i — | i 0.4 | ( i 0.2 | ) | i — | i — | i 0.2 | ||||||||||||||||
Midstream
services—related parties | i 4.3 | i 108.6 | i 62.3 | i — | i — | i 175.2 | |||||||||||||||||
Revenue
from contracts with customers | i 689.9 | i 152.8 | i 342.6 | i 874.2 | ( i 279.6 | ) | i 1,779.9 | ||||||||||||||||
Cost
of sales | ( i 633.9 | ) | ( i 32.0 | ) | ( i 170.1 | ) | ( i 769.2 | ) | i 279.6 | ( i 1,325.6 | ) | ||||||||||||
Operating
expenses | ( i 24.7 | ) | ( i 28.4 | ) | ( i 20.8 | ) | ( i 39.5 | ) | i — | ( i 113.4 | ) | ||||||||||||
Loss
on derivative activity | i — | i — | i — | i — | ( i 15.2 | ) | ( i 15.2 | ) | |||||||||||||||
Segment
profit | $ | i 31.3 | $ | i 92.4 | $ | i 151.7 | $ | i 65.5 | $ | ( i 15.2 | ) | $ | i 325.7 | ||||||||||
Depreciation
and amortization | $ | ( i 27.3 | ) | $ | ( i 31.6 | ) | $ | ( i 46.4 | ) | $ | ( i 37.4 | ) | $ | ( i 2.6 | ) | $ | ( i 145.3 | ) | |||||
Goodwill | $ | i 29.3 | $ | i 202.7 | $ | i 190.3 | $ | i — | $ | i — | $ | i 422.3 | |||||||||||
Capital
expenditures | $ | i 52.8 | $ | i 5.5 | $ | i 140.0 | $ | i 18.8 | $ | i 1.1 | $ | i 218.2 |
Permian | North
Texas | Oklahoma | Louisiana | Corporate | Totals | ||||||||||||||||||
Six Months Ended June 30, 2019 | |||||||||||||||||||||||
Natural
gas sales | $ | i 35.1 | $ | i 82.5 | $ | i 121.9 | $ | i 224.8 | $ | i — | $ | i 464.3 | |||||||||||
NGL
sales | i 0.6 | i 18.0 | i 13.2 | i 1,071.9 | i — | i 1,103.7 | |||||||||||||||||
Crude
oil and condensate sales | i 1,212.8 | i — | i 58.2 | i 142.3 | i — | i 1,413.3 | |||||||||||||||||
Product
sales | i 1,248.5 | i 100.5 | i 193.3 | i 1,439.0 | i — | i 2,981.3 | |||||||||||||||||
Natural
gas sales—related parties | i 0.4 | i 0.3 | i — | i — | ( i 0.7 | ) | i — | ||||||||||||||||
NGL
sales—related parties | i 173.6 | i 50.7 | i 230.7 | i 8.5 | ( i 463.5 | ) | i — | ||||||||||||||||
Crude
oil and condensate sales—related parties | i 10.9 | i 2.7 | i — | i — | ( i 13.6 | ) | i — | ||||||||||||||||
Product
sales—related parties | i 184.9 | i 53.7 | i 230.7 | i 8.5 | ( i 477.8 | ) | i — | ||||||||||||||||
Gathering
and transportation | i 21.6 | i 112.6 | i 114.5 | i 33.9 | i — | i 282.6 | |||||||||||||||||
Processing | i 15.0 | i 56.8 | i 69.8 | i 1.7 | i — | i 143.3 | |||||||||||||||||
NGL
services | i — | i — | i — | i 21.7 | i — | i 21.7 | |||||||||||||||||
Crude
services | i 10.5 | i — | i 9.2 | i 26.7 | i — | i 46.4 | |||||||||||||||||
Other
services | i 4.4 | i 0.5 | ( i 0.1 | ) | i 0.4 | i — | i 5.2 | ||||||||||||||||
Midstream
services | i 51.5 | i 169.9 | i 193.4 | i 84.4 | i — | i 499.2 | |||||||||||||||||
NGL
services—related parties | i — | i — | i — | ( i 3.3 | ) | i 3.3 | i — | ||||||||||||||||
Crude
services—related parties | i — | i — | i 1.5 | i — | ( i 1.5 | ) | i — | ||||||||||||||||
Midstream
services—related parties | i — | i — | i 1.5 | ( i 3.3 | ) | i 1.8 | i — | ||||||||||||||||
Revenue
from contracts with customers | i 1,484.9 | i 324.1 | i 618.9 | i 1,528.6 | ( i 476.0 | ) | i 3,480.5 | ||||||||||||||||
Cost
of sales | ( i 1,356.7 | ) | ( i 124.7 | ) | ( i 343.6 | ) | ( i 1,314.5 | ) | i 476.0 | ( i 2,663.5 | ) | ||||||||||||
Operating
expenses | ( i 56.2 | ) | ( i 51.5 | ) | ( i 51.5 | ) | ( i 73.2 | ) | i — | ( i 232.4 | ) | ||||||||||||
Gain
on derivative activity | i — | i — | i — | i — | i 8.7 | i 8.7 | |||||||||||||||||
Segment
profit | $ | i 72.0 | $ | i 147.9 | $ | i 223.8 | $ | i 140.9 | $ | i 8.7 | $ | i 593.3 | |||||||||||
Depreciation
and amortization | $ | ( i 58.0 | ) | $ | ( i 71.2 | ) | $ | ( i 93.7 | ) | $ | ( i 78.7 | ) | $ | ( i 4.2 | ) | $ | ( i 305.8 | ) | |||||
Goodwill | $ | i — | $ | i — | $ | i 190.3 | $ | i — | $ | i — | $ | i 190.3 | |||||||||||
Capital
expenditures | $ | i 148.3 | $ | i 31.3 | $ | i 178.5 | $ | i 60.5 | $ | i 4.0 | $ | i 422.6 |
Permian | North
Texas | Oklahoma | Louisiana | Corporate | Totals | ||||||||||||||||||
Six Months Ended June 30, 2018 | |||||||||||||||||||||||
Natural
gas sales | $ | i 71.2 | $ | i 68.6 | $ | i 86.0 | $ | i 247.7 | $ | i — | $ | i 473.5 | |||||||||||
NGL
sales | i 0.8 | i — | i 5.5 | i 1,236.3 | i — | i 1,242.6 | |||||||||||||||||
Crude
oil and condensate sales | i 1,088.7 | i — | i 45.2 | i 84.3 | i — | i 1,218.2 | |||||||||||||||||
Product
sales | i 1,160.7 | i 68.6 | i 136.7 | i 1,568.3 | i — | i 2,934.3 | |||||||||||||||||
Natural
gas sales—related parties | i — | i — | i 2.4 | i — | i — | i 2.4 | |||||||||||||||||
NGL
sales—related parties | i 206.8 | i 20.5 | i 240.5 | i 34.5 | ( i 474.9 | ) | i 27.4 | ||||||||||||||||
Crude
oil and condensate sales—related parties | i 1.9 | i 0.8 | i 0.7 | i 0.2 | ( i 2.6 | ) | i 1.0 | ||||||||||||||||
Product
sales—related parties | i 208.7 | i 21.3 | i 243.6 | i 34.7 | ( i 477.5 | ) | i 30.8 | ||||||||||||||||
Gathering
and transportation | i 13.8 | i 14.6 | i 41.2 | i 34.3 | i — | i 103.9 | |||||||||||||||||
Processing | i 11.1 | i 2.2 | i 56.4 | i 1.7 | i — | i 71.4 | |||||||||||||||||
NGL
services | i — | i — | i — | i 26.9 | i — | i 26.9 | |||||||||||||||||
Crude
services | i 0.1 | i — | i 0.1 | i 27.7 | i — | i 27.9 | |||||||||||||||||
Other
services | i 3.7 | i 0.3 | i — | i 0.5 | i — | i 4.5 | |||||||||||||||||
Midstream
services | i 28.7 | i 17.1 | i 97.7 | i 91.1 | i — | i 234.6 | |||||||||||||||||
Gathering
and transportation—related parties | i — | i 114.0 | i 73.4 | i — | i — | i 187.4 | |||||||||||||||||
Processing—related
parties | i — | i 98.4 | i 45.2 | i — | i — | i 143.6 | |||||||||||||||||
Crude
services—related parties | i 8.6 | i — | i 1.4 | i — | i — | i 10.0 | |||||||||||||||||
Other
services—related parties | i — | i 0.4 | i — | i — | i — | i 0.4 | |||||||||||||||||
Midstream
services—related parties | i 8.6 | i 212.8 | i 120.0 | i — | i — | i 341.4 | |||||||||||||||||
Revenue
from contracts with customers | i 1,406.7 | i 319.8 | i 598.0 | i 1,694.1 | ( i 477.5 | ) | i 3,541.1 | ||||||||||||||||
Cost
of sales | ( i 1,308.0 | ) | ( i 81.9 | ) | ( i 309.4 | ) | ( i 1,485.3 | ) | i 477.5 | ( i 2,707.1 | ) | ||||||||||||
Operating
expenses | ( i 48.5 | ) | ( i 56.8 | ) | ( i 41.5 | ) | ( i 75.8 | ) | i — | ( i 222.6 | ) | ||||||||||||
Loss
on derivative activity | i — | i — | i — | i — | ( i 14.7 | ) | ( i 14.7 | ) | |||||||||||||||
Segment
profit | $ | i 50.2 | $ | i 181.1 | $ | i 247.1 | $ | i 133.0 | $ | ( i 14.7 | ) | $ | i 596.7 | ||||||||||
Depreciation
and amortization | $ | ( i 54.1 | ) | $ | ( i 62.9 | ) | $ | ( i 88.5 | ) | $ | ( i 73.3 | ) | $ | ( i 4.6 | ) | $ | ( i 283.4 | ) | |||||
Goodwill | $ | i 29.3 | $ | i 202.7 | $ | i 190.3 | $ | i — | $ | i — | $ | i 422.3 | |||||||||||
Capital
expenditures | $ | i 116.4 | $ | i 8.0 | $ | i 243.9 | $ | i 28.8 | $ | i 2.3 | $ | i 399.4 |
Three Months Ended June 30, | Six
Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Segment profit | $ | i 292.0 | $ | i 325.7 | $ | i 593.3 | $ | i 596.7 | |||||||
General
and administrative expenses | ( i 31.9 | ) | ( i 29.1 | ) | ( i 70.5 | ) | ( i 55.3 | ) | |||||||
Loss
on disposition of assets | ( i 0.1 | ) | ( i 1.2 | ) | ( i 0.1 | ) | ( i 1.3 | ) | |||||||
Depreciation
and amortization | ( i 153.7 | ) | ( i 145.3 | ) | ( i 305.8 | ) | ( i 283.4 | ) | |||||||
Loss
on secured term loan receivable | ( i 52.9 | ) | i — | ( i 52.9 | ) | i — | |||||||||
Operating
income | $ | i 53.4 | $ | i 150.1 | $ | i 164.0 | $ | i 256.7 |
Segment Identifiable Assets: | ||||||||
Permian | $ | i 2,201.5 | $ | i 2,096.8 | ||||
North
Texas | i 1,221.0 | i 1,308.2 | ||||||
Oklahoma | i 3,258.6 | i 3,209.5 | ||||||
Louisiana | i 2,575.1 | i 2,734.5 | ||||||
Corporate | i 167.9 | i 222.3 | ||||||
Total
identifiable assets | $ | i 9,424.1 | $ | i 9,571.3 |
Natural gas and NGLs inventory, prepaid expenses, and other: | ||||||||
Natural
gas and NGLs inventory | $ | i 51.5 | $ | i 41.3 | ||||
Secured
term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1) | i — | i 19.4 | ||||||
Prepaid
expenses and other | i 20.2 | i 12.1 | ||||||
Natural
gas and NGLs inventory, prepaid expenses, and other | $ | i 71.7 | $ | i 72.8 |
(1) | In
late May 2019, White Star, the counterparty to our $ i 58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. We do not believe that it is probable that White Star will be able to repay the outstanding amounts owed to us under the second lien secured term loan. For additional
information regarding this transaction, refer to “Note 2—Significant Accounting Policies.” |
Other current liabilities: | ||||||||
Accrued interest | $ | i 32.6 | $ | i 37.3 | ||||
Accrued
wages and benefits, including taxes | i 18.6 | i 37.2 | ||||||
Accrued
ad valorem taxes | i 25.8 | i 28.1 | ||||||
Capital
expenditure accruals | i 44.9 | i 50.6 | ||||||
Onerous
performance obligations | i — | i 9.0 | ||||||
Short-term
lease liability | i 22.1 | i 1.5 | ||||||
Suspense
producer payments | i 15.4 | i 34.6 | ||||||
Deferred
revenue | i 48.6 | i 6.6 | ||||||
Other | i 26.5 | i 41.8 | ||||||
Other
current liabilities | $ | i 234.5 | $ | i 246.7 |
• | gathering, compressing, treating, processing, transporting, storing, and selling natural gas;
|
• | fractionating, transporting, storing, and selling NGLs; and |
• | gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. |
• | Permian Segment. The Permian segment includes our natural
gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in west Texas and eastern New Mexico and our crude operations in south Texas; |
• | North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in north Texas; |
• | Oklahoma Segment.
The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas; |
• | Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana and our crude oil operations in ORV; and |
• | Corporate
Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in south Texas, our derivative activity, and our general corporate assets and expenses. |
• | gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own; |
• | processing natural gas at our processing plants; |
• | fractionating
and marketing recovered NGLs; |
• | providing compression services; |
• | providing crude oil and condensate transportation and terminal services; |
• | providing condensate stabilization services; |
• | providing
brine disposal services; and |
• | providing natural gas, crude oil, and NGL storage. |
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||||||
Operating income | $ | 53.4 | $ | 150.1 | $ | 164.0 | $ | 256.7 | ||||||||
Add: | ||||||||||||||||
Operating
expenses | 117.9 | 113.4 | 232.4 | 222.6 | ||||||||||||
General and administrative expenses | 31.9 | 29.1 | 70.5 | 55.3 | ||||||||||||
Loss
on disposition of assets | 0.1 | 1.2 | 0.1 | 1.3 | ||||||||||||
Depreciation and amortization | 153.7 | 145.3 | 305.8 | 283.4 | ||||||||||||
Loss
on secured term loan receivable | 52.9 | — | 52.9 | — | ||||||||||||
Gross operating margin | $ | 409.9 | $ | 439.1 | $ | 825.7 | $ | 819.3 |
Three
Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
Permian Segment | |||||||||||||||
Revenues | $ | 742.3 | $ | 689.9 | $ | 1,484.9 | $ | 1,406.7 | |||||||
Cost
of sales | (680.5 | ) | (633.9 | ) | (1,356.7 | ) | (1,308.0 | ) | |||||||
Total gross operating margin | $ | 61.8 | $ | 56.0 | $ | 128.2 | $ | 98.7 | |||||||
North
Texas Segment | |||||||||||||||
Revenues | $ | 149.8 | $ | 152.8 | $ | 324.1 | $ | 319.8 | |||||||
Cost
of sales | (51.0 | ) | (32.0 | ) | (124.7 | ) | (81.9 | ) | |||||||
Total gross operating margin | $ | 98.8 | $ | 120.8 | $ | 199.4 | $ | 237.9 | |||||||
Oklahoma
Segment | |||||||||||||||
Revenues | $ | 299.2 | $ | 342.6 | $ | 618.9 | $ | 598.0 | |||||||
Cost
of sales | (159.4 | ) | (170.1 | ) | (343.6 | ) | (309.4 | ) | |||||||
Total gross operating margin | $ | 139.8 | $ | 172.5 | $ | 275.3 | $ | 288.6 | |||||||
Louisiana
Segment | |||||||||||||||
Revenues | $ | 730.5 | $ | 874.2 | $ | 1,528.6 | $ | 1,694.1 | |||||||
Cost
of sales | (627.9 | ) | (769.2 | ) | (1,314.5 | ) | (1,485.3 | ) | |||||||
Total gross operating margin | $ | 102.6 | $ | 105.0 | $ | 214.1 | $ | 208.8 | |||||||
Corporate
Segment | |||||||||||||||
Revenues | $ | (211.8 | ) | $ | (294.8 | ) | $ | (467.3 | ) | $ | (492.2 | ) | |||
Cost
of sales | 218.7 | 279.6 | 476.0 | 477.5 | |||||||||||
Total gross operating margin | $ | 6.9 | $ | (15.2 | ) | $ | 8.7 | $ | (14.7 | ) | |||||
Total | |||||||||||||||
Revenues | $ | 1,710.0 | $ | 1,764.7 | $ | 3,489.2 | $ | 3,526.4 | |||||||
Cost
of sales | (1,300.1 | ) | (1,325.6 | ) | (2,663.5 | ) | (2,707.1 | ) | |||||||
Total gross operating margin | $ | 409.9 | $ | 439.1 | $ | 825.7 | $ | 819.3 | |||||||
Midstream
Volumes: | |||||||||||||||
Permian Segment | |||||||||||||||
Gathering
and Transportation (MMBtu/d) | 676,000 | 511,300 | 666,800 | 467,900 | |||||||||||
Processing (MMBtu/d) | 724,100 | 529,100 | 718,100 | 485,800 | |||||||||||
Crude
Oil Handling (Bbls/d) | 145,100 | 119,700 | 146,200 | 113,800 | |||||||||||
North Texas Segment | |||||||||||||||
Gathering
and Transportation (MMBtu/d) | 1,646,900 | 1,747,000 | 1,664,900 | 1,756,800 | |||||||||||
Processing (MMBtu/d) | 770,100 | 754,000 | 750,100 | 753,100 | |||||||||||
Oklahoma
Segment | |||||||||||||||
Gathering and Transportation (MMBtu/d) | 1,314,900 | 1,235,500 | 1,279,800 | 1,142,200 | |||||||||||
Processing
(MMBtu/d) | 1,298,800 | 1,200,700 | 1,265,400 | 1,135,400 | |||||||||||
Crude Oil Handling (Bbls/d) | 53,800 | 13,000 | 41,600 | 10,600 | |||||||||||
Louisiana
Segment | |||||||||||||||
Gathering and Transportation (MMBtu/d) | 1,925,900 | 2,094,100 | 1,997,800 | 2,158,100 | |||||||||||
Processing
(MMBtu/d) | 337,100 | 395,600 | 402,200 | 418,600 | |||||||||||
Crude Oil Handling (Bbls/d) | 20,000 | 15,700 | 17,500 | 13,600 | |||||||||||
NGL
Fractionation (Gals/d) | 7,477,400 | 6,480,100 | 7,227,000 | 6,412,200 | |||||||||||
Brine Disposal (Bbls/d) | 3,400 | 3,500 | 3,400 | 3,200 |
• | Permian Segment. Gross operating margin in the Permian segment
increased $5.8 million, which was primarily due to an $8.7 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $6.1 million from our Delaware Basin assets and $2.6 million from our Midland Basin assets. These increases were partially offset by a $2.9 million decrease from our Permian Basin crude assets, which was primarily driven by higher gathering and transportation volumes contributing $2.9 million of incremental gross operating margin that was offset by a $5.6 million decrease in gross operating margin associated with our physical crude marketing arrangements. We manage our exposure to crude price fluctuations in our physical crude marketing arrangements through various derivative arrangements. The timing of our realization of the gains or losses from these crude derivative arrangements
may not occur in the same period as the corresponding physical crude marketing transaction and all associated gains and losses from the derivative arrangements are reflected in our Corporate segment. |
• | North Texas Segment. Gross operating margin in the North Texas segment decreased $22.0 million primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets. Shortfall revenue from the Devon-related MVCs was $20.8 million
for the three months ended June 30, 2018. |
• | Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $32.7 million, which was primarily due to the recognition of $45.5 million in gross operating margin from a contract restructuring with White Star during the three months ended June 30, 2018, which was partially offset by $12.8 million due to higher volumes from
continued development by our customers, including $6.6 million contributed by our Oklahoma gas assets and $6.2 million contributed by our Oklahoma crude assets. |
• | Louisiana Segment. Gross operating margin in the Louisiana segment decreased $2.4 million. Gross operating margin from our NGL transmission and fractionation assets increased by $7.8 million, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019. The increase was offset by a $10.5 million decrease from our Louisiana gas business. Gross operating
margin from our Louisiana gas transmission assets decreased $6.4 million due to the expiration of certain firm transportation contracts, decreased volumes, and negative market adjustment on gas inventory due to price declines. Gross operating margin from our Louisiana gas plants decreased $4.1 million due to lower processing margins and volumes attributable to a less favorable processing environment during the three months ended June 30, 2019. |
• | Corporate Segment. Gross operating margin in the Corporate segment
increased $22.1 million, which was primarily due to the changes in fair value of our commodity swaps between the periods. For the three months ended June 30, 2019, realized losses of $0.3 million were offset by unrealized gains of $7.2 million. For the three months ended June 30, 2018,
there were realized losses of $4.7 million in addition to unrealized losses of $10.5 million. |
Permian | North Texas | Oklahoma | Total | |||||||||||||
Three
Months Ended | ||||||||||||||||
Midstream
services | $ | 3.9 | $ | — | $ | — | $ | 3.9 | ||||||||
Total | $ | 3.9 | $ | — | $ | — | $ | 3.9 | ||||||||
Midstream services (1) | $ | — | $ | 0.1 | $ | 47.7 | $ | 47.8 | ||||||||
Midstream
services—related parties | 2.3 | 20.8 | — | 23.1 | ||||||||||||
Total | $ | 2.3 | $ | 20.9 | $ | 47.7 | $ | 70.9 |
(1) | We
restructured a natural gas gathering and processing contract with White Star that contained MVCs. As a result, we recognized $45.5 million of midstream services revenue in the Oklahoma segment for the three months ended June 30, 2018. |
Three
Months Ended June 30, | Change | |||||||||||||
2019 | 2018 | $ | % | |||||||||||
Permian Segment | $ | 28.4 | $ | 24.7 | $ | 3.7 | 15.0 | % | ||||||
North
Texas Segment | 25.8 | 28.4 | (2.6 | ) | (9.2 | )% | ||||||||
Oklahoma Segment | 26.1 | 20.8 | 5.3 | 25.5 | % | |||||||||
Louisiana
Segment | 37.6 | 39.5 | (1.9 | ) | (4.8 | )% | ||||||||
Total | $ | 117.9 | $ | 113.4 | $ | 4.5 | 4.0 | % |
• | Permian
Segment. Operating expenses in the Permian segment increased $3.7 million primarily due to expanded operations with increases in utilities, materials and supplies expenses, and construction fees and services. |
• | North Texas Segment. Operating expenses in the North Texas segment decreased $2.6 million primarily due to decreased rents, compressor overhauls, labor and benefits
costs, and materials and supplies expenses. |
• | Oklahoma Segment. Operating expenses in the Oklahoma segment increased $5.3 million primarily due to expanded operations with increases in compressor rentals and compression operations and maintenance. |
• | Louisiana
Segment. Operating expenses in the Louisiana segment decreased $1.9 million primarily due to reduced materials and supplies expenses, labor and benefits costs, and compression rental offset partially by increased utility costs. |
Three Months Ended June 30, | |||||||
2019 | 2018 | ||||||
Senior
Notes | $ | 37.3 | $ | 40.0 | |||
ENLK Credit Facility | — | 4.9 | |||||
Intercompany
debt | 18.3 | — | |||||
Capitalized interest | (1.8 | ) | (1.5 | ) | |||
Amortization of debt issue costs and net discounts (premiums) | 1.0 | 0.9 | |||||
Other | (0.5 | ) | (0.6 | ) | |||
Total | $ | 54.3 | $ | 43.7 |
• | Permian Segment. Gross operating margin in the Permian segment increased
$29.5 million, which was primarily due to a $25.4 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $15.0 million from our Delaware Basin assets, and $10.4 million from our Midland Basin assets. The remaining increase of $4.3 million was from our Permian Basin crude assets due to a $9.1 million increase in gross operating margin from higher gathering and transportation volumes, which was partially offset by a $4.8 million decrease in gross operating margin associated with our physical crude marketing arrangements. |
• | North Texas Segment. Gross
operating margin in the North Texas segment decreased $38.5 million, which was primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets. Shortfall revenue from the Devon-related MVCs was $38.9 million for the six months ended June 30, 2018. |
• | Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $13.3
million, which was primarily due to recognition of $45.5 million in gross operating margin from a contract restructuring with White Star during the three months ended June 30, 2018, which was partially offset by $32.2 million primarily due to higher volumes from continued development by our customers with $21.9 million contributed by our Oklahoma gas assets and $10.3 million contributed by our Oklahoma crude assets. |
• | Louisiana Segment. Gross operating margin in the Louisiana segment increased
$5.3 million. Gross operating margin from our NGL assets increased by $8.1 million primarily due to higher volumes with the completion of the Cajun-Sibon pipeline expansion in April 2019. Our ORV crude assets contributed an increase of $3.7 million primarily due to higher volumes. These increases were partially offset by a decrease of $6.7 million from our Louisiana gas business, primarily due to a $4.8 million decrease from our Louisiana gas plants, due to a less favorable processing environment during the six months ended June 30, 2019. |
• | Corporate Segment. Gross
operating margin in the Corporate segment increased $23.4 million, which was primarily due to the changes in fair value of our commodity swaps between the periods. For the six months ended June 30, 2019, there were realized gains of $3.5 million in addition to unrealized gains of $5.2 million. For the
six months ended June 30, 2018, there were realized losses of $0.7 million in addition to unrealized losses of $14.0 million. |
Permian | North Texas | Oklahoma | Total | |||||||||||||
Six
Months Ended | ||||||||||||||||
Midstream
services | $ | 7.7 | $ | — | $ | — | $ | 7.7 | ||||||||
Total | $ | 7.7 | $ | — | $ | — | $ | 7.7 | ||||||||
Midstream Services (1) | $ | — | $ | 0.1 | $ | 52.7 | $ | 52.8 | ||||||||
Midstream
services—related parties | 5.7 | 38.9 | 1.2 | 45.8 | ||||||||||||
Total | $ | 5.7 | $ | 39.0 | $ | 53.9 | $ | 98.6 |
(1) | We
restructured a natural gas gathering and processing contract with White Star that contained MVCs. As a result, we recognized $45.5 million of midstream services revenue in the Oklahoma segment for the six months ended June 30, 2018. |
Six
Months Ended June 30, | Change | |||||||||||||
2019 | 2018 | $ | % | |||||||||||
Permian Segment | $ | 56.2 | $ | 48.5 | $ | 7.7 | 15.9 | % | ||||||
North
Texas Segment | 51.5 | 56.8 | (5.3 | ) | (9.3 | )% | ||||||||
Oklahoma Segment | 51.5 | 41.5 | 10.0 | 24.1 | % | |||||||||
Louisiana
Segment | 73.2 | 75.8 | (2.6 | ) | (3.4 | )% | ||||||||
Total | $ | 232.4 | $ | 222.6 | $ | 9.8 | 4.4 | % |
• | Permian
Segment. Operating expenses in the Permian segment increased $7.7 million primarily due to expanded operations and higher utilities expense, bulk purchases of materials and supplies, construction fees and services, and compressor rentals. |
• | North Texas Segment. Operating expenses in the North Texas segment decreased $5.3 million primarily due to decreased rents, compressor overhauls, and labor and benefits
costs. |
• | Oklahoma Segment. Operating expenses in the Oklahoma segment increased $10.0 million primarily due to expanded operations with increases in compressor rentals, compression operations and maintenance, and labor and benefits costs. |
• | Louisiana
Segment. Operating expenses in the Louisiana segment decreased $2.6 million primarily due to reduced materials and supplies expenses, labor and benefits costs, and compression rentals partially offset by increased equipment rental and utility costs. |
• | Unit-based compensation expense increased $6.2 million primarily due to increased bonus expense and lower forfeiture of units in 2019. |
• | Transaction costs increased $2.6 million primarily due to additional costs incurred related to the Merger, which
closed during the first quarter of 2019. |
• | Fees and services expense increased $1.9 million primarily due to increased software consulting and legal fees. |
Six
Months Ended June 30, | |||||||
2019 | 2018 | ||||||
Senior Notes | $ | 77.3 | $ | 80.0 | |||
ENLK
Credit Facility | 0.3 | 8.3 | |||||
Intercompany debt | 29.3 | — | |||||
Capitalized interest | (3.8 | ) | (2.8 | ) | |||
Amortization
of debt issue costs and net discounts (premiums) | 2.8 | 2.4 | |||||
Other | (2.3 | ) | (0.5 | ) | |||
Total | $ | 103.6 | $ | 87.4 |
Six
Months Ended June 30, | |||||||
2019 | 2018 | ||||||
Operating cash flows before working capital | $ | 442.7 | $ | 448.4 | |||
Changes
in working capital | 72.9 | (17.7 | ) |
• | General and administrative expenses excluding unit-based compensation increased $8.9 million primarily due to higher transaction costs related to the Merger. For more information, see “Results of Operations.” |
• | Operating expenses excluding unit-based compensation increased $11.7
million primarily due to expanded operations. For more information, see “Results of Operations.” |
• | Interest expense, excluding amortization of debt issue costs and net discounts, increased $18.0 million. |
Six
Months Ended June 30, | |||||||
2019 | 2018 | ||||||
Growth capital expenditures | $ | (406.7 | ) | $ | (385.9 | ) | |
Maintenance
capital expenditures | (21.7 | ) | (18.5 | ) |
Six
Months Ended June 30, | |||||||
2019 | 2018 | ||||||
Net borrowings on the ENLK Credit Facility | $ | — | $ | 520.0 | |||
Net
borrowings on intercompany debt | 588.5 | — | |||||
Net repayments on the 2019 unsecured senior notes | (400.0 | ) | — | ||||
Contributions by non-controlling interests | 45.2 | 81.6 | |||||
Payment
of installment payable for EOGP acquisition | — | (250.0 | ) | ||||
Distributions to common units | (276.6 | ) | (275.0 | ) | |||
Distributions to general partner interest (including
incentive distribution rights) | (15.6 | ) | (30.9 | ) | |||
Distributions to non-controlling interests | (12.7 | ) | (23.4 | ) | |||
Distributions to Series B Preferred Units | (33.2 | ) | (32.2 | ) | |||
Distributions
to Series C Preferred Units | (12.0 | ) | (12.0 | ) |
Payments Due by Period | |||||||||||||||||||||||||||
Total | Remainder
2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | |||||||||||||||||||||
Long-term debt obligations | $ | 3,100.0 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 3,100.0 | |||||||||||||
Intercompany
debt (1) | 1,438.5 | — | — | 850.0 | — | — | 588.5 | ||||||||||||||||||||
Interest
payable on fixed long-term debt obligations | 2,604.5 | 90.3 | 176.0 | 176.0 | 176.0 | 176.0 | 1,810.2 | ||||||||||||||||||||
Capital
lease obligations | 0.4 | 0.4 | — | — | — | — | — | ||||||||||||||||||||
Operating
lease obligations | 146.5 | 13.5 | 22.4 | 16.1 | 9.4 | 8.9 | 76.2 | ||||||||||||||||||||
Purchase
obligations | 31.7 | 31.7 | — | — | — | — | — | ||||||||||||||||||||
Pipeline
capacity and deficiency agreements (2) | 205.0 | 18.6 | 36.6 | 36.5 | 31.0 | 28.1 | 54.2 | ||||||||||||||||||||
Inactive
easement commitment (3) | 10.0 | — | — | — | 10.0 | — | — | ||||||||||||||||||||
Total
contractual obligations | $ | 7,536.6 | $ | 154.5 | $ | 235.0 | $ | 1,078.6 | $ | 226.4 | $ | 213.0 | $ | 5,629.1 |
(1) | Intercompany
debt includes borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes to fund the operations and growth capital expenditures of ENLK through an intercompany arrangement with ENLC. Interest charged to ENLK for borrowings made through the intercompany arrangement will be the same as interest charged to ENLC on borrowings under the Consolidated Credit Facility, the Term Loan, and ENLC’s 5.375% senior unsecured notes. |
(2) | Consists of pipeline capacity payments for firm transportation and deficiency agreements. |
(3) | Amounts
related to inactive easements paid as utilized by us with balance due in 2022 if not utilized. |
1. | Fee-based
contracts: Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of volume processed or (2) arrangements where we purchase and resell commodities in connection with providing the related processing service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities. |
2. | Processing margin contracts:
Under these contracts, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts
that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the six months ended June 30, 2019, less than 1% of our gross operating margin was generated from processing margin contracts. |
3. | POL contracts: Under
these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under POL contracts, but they do decline during periods of low liquids prices. |
4. | POP contracts: Under
these contracts, we receive a fee in the form of a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under POP contracts, but they do decline during periods of low natural gas and liquids prices. |
Period | Underlying | Notional
Volume | We Pay | We Receive (1) | Fair Value Asset/(Liability) (In millions) | |||||||
July 2019 - March 2020 | Ethane | 357 (MBbls) | $0.2098/gal | Index | $ | (0.6 | ) | |||||
July
2019 - March 2020 | Propane | 522 (MBbls) | Index | $0.5229/gal | 2.6 | |||||||
July 2019 - September 2019 | Normal
butane | 16 (MBbls) | Index | $0.5591/gal | 0.3 | |||||||
July 2019 - September 2019 | Natural gasoline | 40
(MBbls) | Index | $1.1165/gal | 0.1 | |||||||
July 2019 - October 2019 | Natural gas | 24,036 (MMBtu/d) | Index | $2.1606/MMBtu | — | |||||||
July
2019 - December 2022 | Crude and condensate | 13,129 (MBbls) | Index | $57.62/bbl | 11.3 | |||||||
$ | 13.7 |
(1) | Weighted
average. |
Number | Description | |
2.1 | — | |
3.1 | — | |
3.2 | — | |
3.3 | — | |
3.4 | — | |
3.5 | — | |
3.6 | — | |
3.7 | — | |
3.8 | — | |
4.1 | — | |
4.2 | — | |
31.1 * | — | |
31.2 * | — | |
32.1 * | — | |
101 * | — | The following financial information from EnLink Midstream Partners, LP's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in inline XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets
as of June 30, 2019 and December 31, 2018, (ii) Consolidated Statements of Operations for the three and six months ended June 30, 2019 and 2018, (iii) Consolidated Statements of Changes in Members’ Equity for the three months ended June 30, 2019 and 2018 and March 31, 2019 and 2018, (iv) Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018, and (v) the Notes to Consolidated Financial Statements. |
104 * | — | Cover
Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
* |
EnLink Midstream Partners, LP | ||
By: | ||
its general partner | ||
By: | ||
Executive Vice President and Chief Financial Officer | ||
This ‘10-Q’ Filing | Date | Other Filings | ||
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6/1/29 | ||||
1/25/24 | ||||
12/15/22 | ||||
12/10/21 | ||||
3/6/20 | ||||
1/1/20 | ||||
12/31/19 | 10-K | |||
12/1/19 | ||||
8/13/19 | ||||
Filed on: | 8/7/19 | |||
8/1/19 | ||||
7/31/19 | ||||
For Period end: | 6/30/19 | |||
5/14/19 | ||||
4/9/19 | 8-K | |||
4/1/19 | ||||
3/31/19 | 10-Q | |||
3/8/19 | 8-K | |||
2/13/19 | ||||
1/31/19 | 4, 8-K | |||
1/29/19 | 4, 8-K, SC 13D/A | |||
1/25/19 | 4, 8-K | |||
1/1/19 | 4 | |||
12/31/18 | 10-K | |||
12/11/18 | 425, 8-K | |||
10/21/18 | 8-K | |||
8/29/18 | ||||
8/13/18 | 4 | |||
7/23/18 | 8-K | |||
7/18/18 | 3, 4, 8-K, SC 13D/A | |||
6/30/18 | 10-Q | |||
5/14/18 | 4 | |||
3/31/18 | 10-Q | |||
2/13/18 | 4 | |||
12/31/17 | 10-K | |||
10/18/11 | ||||
7/21/10 | ||||
7/12/02 | ||||
List all Filings |