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(Exact name of registrant as specified in its charter)
iDelaware
i46-4108528
(State
of organization)
(I.R.S. Employer Identification No.)
i1722 Routh St., Suite 1300
iDallas,
iTexas
i75201
(Address
of principal executive offices)
(Zip Code)
(i214) i953-9500
(Registrant’s telephone number, including area code)
SECURITIES REGISTERED
PURSUANT TO SECTION 12(b) OF THE SECURITIES EXCHANGE ACT OF 1934:
Title of Each Class
Trading Symbol
Name of Exchange on which Registered
iCommon
Units Representing Limited
iENLC
iThe New York Stock Exchange
Liability Company Interests
Indicate
by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☒ No ☐
Indicate by check mark whether the
registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☒ No ☐
Indicate by check mark whether the registrant
is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act. (Check one):
iLarge
accelerated filer
☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
i☐
Emerging
growth company
i☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes i☐ No ☒
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.
Commission
U.S.
Securities and Exchange Commission.
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.
DTA
Deferred tax asset.
DTL
Deferred tax liability.
Enfield
Enfield Holdings, L.P.
ENLC
EnLink Midstream, LLC or, when applicable, EnLink Midstream, LLC together with its consolidated subsidiaries.
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.
ENLC Credit Facility
A $250.0 million secured revolving credit facility entered into by ENLC that would have matured on March 7, 2019, which included a $125.0 million letter of credit subfacility. The ENLC Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
ENLC EDA
Equity
Distribution Agreement entered into by ENLC in February 2019 with RBC Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., BMO Capital Markets Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Jefferies LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc., SunTrust Robinson Humphrey, Inc., and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $400.0 million in aggregate gross sales of ENLC common units from time to time through an “at the market” equity offering program.
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.
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 in ENLK. Prior to the effective time of the Merger, the General Partner also owned all of the incentive distribution rights in ENLK.
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.
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, the General Partner, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger.
MMbbls
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.
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.
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.
a.Organization of Business
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.”
Transfer of EOGP Interest
On
January 31, 2019, ENLC transferred its i16.1% limited partner interest in EOGP to the Operating Partnership in exchange for i55,827,221
ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP.
Simplification of the Corporate Structure
On October 21, 2018, ENLK, ENLC, the General Partner, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. As a result of the Merger:
•Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries)
was converted into i1.15 ENLC common units, which resulted in the issuance of i304,822,035
ENLC common units.
•The 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 8—Certain Provisions of the Partnership Agreement” 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 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.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
•Each
unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan 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, we 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.
•We were required to allocate the goodwill in our Corporate reporting unit previously associated with the incentive distribution rights in ENLK granted to the General Partner which were created at the formation of ENLC in 2014, to the Permian, North Texas, Oklahoma, and Louisiana reporting units. See “Note 3—Goodwill and Intangible Assets” for more information on this transaction.
•We reduced our DTL by $i399.0
million related to ENLC’s step-up in basis of ENLK’s underlying assets with the offsetting credit in members’ equity. See “Note 7—Income Taxes” for more information on the DTA.
b.Nature of Business
We primarily focus on providing midstream energy services, including:
•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.
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.
Notes to Consolidated
Financial Statements (Continued)
(Unaudited)
i
(2) Significant Accounting Policies
a.iBasis
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. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018. Certain reclassifications
were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income (loss). All significant intercompany balances and transactions have been eliminated in consolidation.
b.iRevenue Recognition
Minimum Volume Commitments and Firm Transportation
Contracts
Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers 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 revenue.
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 revenue.
iThe
following table summarizes the contractually committed fees that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below are determined using 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. These fees 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. For
example, for the three and nine months ended September 30, 2019, we had contractual commitments of $i38.9 million and $i113.6
million under our MVC contracts, respectively, and recorded $i6.5 million and $i14.2
million of revenue due to volume shortfalls, respectively./
MVC and Firm Transportation Commitments (1)
2019 (remaining)
$
i58.9
2020
i259.8
2021
i108.1
2022
i94.7
2023
i85.7
Thereafter
i237.0
Total
$
i844.2
____________________________
(1)Amounts
do not represent expected shortfall under these commitments.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
c.Secured Term Loan Receivable
In
late May 2019, White Star, the counterparty to our $i58.0 million second lien secured term loan receivable, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Under the original term loan agreement executed in May 2018, White Star was scheduled to make an installment payment of $i19.5
million in April 2019. In November 2018 and again in February 2019, we amended the installment payment terms with the result that the single 2019 installment payment was split into two payments of $i9.75 million in May 2019 and $i10.75
million in October 2019. White Star defaulted on its May 2019 installment payment prior to filing for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While the outcome of the bankruptcy proceeding is not yet finalized, 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. As a result, we have recorded a $i52.9 million loss in our consolidated statement of operations for the nine months ended September
30, 2019, which represents a full write-down of the second lien secured term loan.
d.iAccounting Standards to be Adopted in Future Periods
On August 29, 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service
Contract (“ASU 2018-15”), which amends ASC 350-40, Internal-Use Software (“ASC 350-40”) to address a customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should
be capitalized in a cloud computing arrangement that is considered a service contract. We do not believe ASU 2018-15 will have a material impact on our financial statements, except to the extent future costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will be included in “Operating expenses” or “General and administrative” in the consolidated statement of operations, rather than “Depreciation and amortization.” We will adopt ASU 2018-15 prospectively effective January 1, 2020.
e.Adopted Accounting Standards
Effective January
1, 2019, we adopted ASC 842, Leases, using the modified retrospective approach whereby we recognized leases on our consolidated balance sheet by recording a right-of-use asset and lease liability. We applied certain practical expedients that were allowed in the adoption of ASC 842, including not reassessing existing contracts for lease arrangements, not reassessing existing lease classification, not recording a right-of-use asset or lease liability for leases of twelve months or less, and not separating lease and non-lease components of a lease arrangement. In connection with the adoption of ASC 842 in January 2019, we recorded a lease liability of $i97.6
million, a right-of-use asset of $i75.3 million, and a reduction of $i22.6 million in other liabilities previously recorded related to lease incentives. For additional
information about our adoption of ASC 842, refer to “Note 5—Leases.”
i
(3) Goodwill and Intangible Assets
Goodwill
In March 2014, at the time of our transactions with Devon that led us to become publicly held, we recorded goodwill in our corporate reporting
unit at ENLC that was associated with the General Partner’s incentive distribution rights in ENLK. Prior to the completion of the Merger in January 2019, ENLC’s aggregate fair value of its reporting units was in excess of the consolidated book value of its assets, including all goodwill, which did not result in a goodwill impairment on a consolidated basis. Upon the completion of the Merger, in accordance with ASC 350, Intangibles-Goodwill and Other (“ASC 350”), the portion of goodwill in our corporate reporting unit that was previously associated with the General Partner’s incentive distribution rights in ENLK was required to be reallocated to the four remaining reporting units based on the relative fair value of each of the reporting units. Due to the application of ASC 350, we were required to allocate goodwill to reporting units at which goodwill had previously been impaired due to book value being in excess of fair value. We recognized a $i186.5
million goodwill impairment related to our Louisiana segment during the first quarter of 2019. During the third quarter of 2019, we performed an interim impairment test due to a significant decline in our unit price from the first quarter and downward revisions in our estimated future cash flows due to delays in development plans announced by certain of our major customers. For the three months ended September 30, 2019, we determined that ino impairments of goodwill were required as of September
30, 2019.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
i
The
table below provides a summary of our change in carrying amount of goodwill by segment (in millions) for the nine months ended September 30, 2019. For the three months ended September 30, 2019 and 2018 and nine months ended September 30, 2018, there were no changes to the carrying amounts of goodwill.
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 i5 to i20
years.
i
The following table represents our change in carrying value of intangible assets (in millions):
The
weighted average amortization period is i15.0 years. Amortization expense was $ii30.9/
million for each of the three months ended September 30, 2019 and 2018, and $i92.8 million and $i92.6
million for the nine months ended September 30, 2019 and 2018, respectively.
i
The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):
2019
(remaining)
$
i30.9
2020
i123.7
2021
i123.7
2022
i123.7
2023
i123.6
Thereafter
i755.2
Total
$
i1,280.8
/
i
(4)
Related Party Transactions
a.Transactions with ENLK
Simplification of the Corporate Structure. On October 21, 2018, ENLK, ENLC, the General Partner, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. See “Note 1—General” for more information on this transaction.
Transfer of EOGP Interest. On January 31, 2019, ENLC transferred
its i16.1% limited partner interest in EOGP to the Operating Partnership in exchange for i55,827,221
ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
b.Transactions
with Devon
On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP for aggregate consideration of $i3.125 billion. 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. Prior to July 18, 2018, revenues from transactions with Devon are included in “Product sales—related parties” or “Midstream services—related parties” in the consolidated statement of operations. Revenues from transactions with Devon after July 18, 2018 are included in “Product sales” or “Midstream services” in the consolidated statement of operations.
For the three and nine months ended September 30, 2018, related party revenues from
Devon accounted for i2.0% and i7.3%, respectively, of our revenues.
c.Transactions with Cedar Cove JV
For
the three and nine months ended September 30, 2019, we recorded cost of sales of $i4.1 million and $i18.0
million, respectively, and for the three and nine months ended September 30, 2018, we recorded cost of sales of $i11.3 million and $i33.8
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 ino accounts receivable balances related to transactions with the Cedar Cove JV at September 30, 2019 and $i0.7
million at December 31, 2018. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $i3.6 million and $i4.3
million at September 30, 2019 and December 31, 2018, respectively.
Management believes the foregoing transactions with related parties were 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.
ii
(5)
Leases
Effective with the adoption of ASC 842 in January 2019, we evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain
to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. The majority of our leases are for the following types of assets:
•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 $i61.3
million of our lease liability and $i40.6 million of our right-of-use asset as of September 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 $i26.4
million of our lease liability and $i26.3 million of our right-of-use asset as of September 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
$i0.7 million of our lease liability and $i0.7 million of our right-of-use asset as of September 30, 2019.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
•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 $i15.1
million of our lease liability and $i13.0 million of our right-of-use asset as of September 30, 2019.
i
Lease
balances are recorded on the consolidated balance sheets as follows (in millions):
Certain
of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions.
i
Lease expense is recognized on the consolidated statements of operations as “Operating expenses”
and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions):
Debt
classified as long-term, including current maturities of long-term debt
$
i4,725.0
$
(i5.9)
i4,719.1
$
i4,461.4
$
(i6.1)
i4,455.3
Debt
issuance cost (5)
(i30.8)
(i24.5)
Less:
Current maturities of long-term debt (4)
i—
(i399.8)
Long-term
debt, net of unamortized issuance cost
$
i4,688.3
$
i4,031.0
____________________________
(1)Bore interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was i4.4% at December 31, 2018. In connection with the closing of the Merger, the ENLC Credit Facility was canceled, and all outstanding borrowings were refinanced through borrowings on the Consolidated Credit Facility. Since the borrowings under the ENLC Credit Facility were refinanced with long-term debt, they are
classified as “Long-term debt” on the consolidated balance sheet as of December 31, 2018.
(2)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate wasi3.7%atSeptember 30, 2019.
(3)Bears
interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was i3.5% and i3.9% at September 30,
2019 and December 31, 2018, respectively.
(4)ENLK’s i2.70% 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.
On April 9, 2019, ENLC issued $i500.0 million in aggregate principal amount of ENLC’s i5.375% senior
unsecured notes due June 1, 2029 (the “2029 Notes”) at a price to the public of i100% of their face value. Interest payments on the 2029 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2019. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $i496.5
million were used to repay outstanding borrowings under the Consolidated Credit Facility, including borrowings incurred on April 1, 2019 to repay at maturity all of the $i400.0 million outstanding aggregate principal amount of ENLK’s i2.70%
senior unsecured notes due 2019, and for general limited liability company purposes.
Consolidated Credit Facility
On December 11, 2018, ENLC entered into the Consolidated Credit Facility, which permits ENLC to borrow up to $i1.75 billion on a revolving credit basis and includes a $i500.0
million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($i275.0 million as of September 30, 2019), and i105%
of the
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
outstanding letters of credit under the Consolidated Credit Facility ($i4.0
million as of September 30, 2019). The obligations under the Consolidated Credit Facility are unsecured.
The Consolidated Credit Facility includes provisions for additional financial institutions to become lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of $i2.25 billion for all commitments under the Consolidated Credit Facility.
The
Consolidated Credit Facility will mature on January 25, 2024, unless ENLC requests, and the requisite lenders agree, to extend it pursuant to its terms. The Consolidated 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. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Consolidated Credit Facility, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than i2.5
to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Consolidated Credit Facility) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than i5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $i50.0
million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to i5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.
Borrowings under the Consolidated Credit Facility bear interest at ENLC’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from i1.125%
to i2.00%) or the Base Rate (the highest of the Federal Funds Rate plus i0.50%, the 30-day Eurodollar Rate plus i1.0%
or the administrative agent’s prime rate) plus an applicable margin (ranging from i0.125% to i1.00%). The applicable margins vary depending on ENLC’s
debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately.
At September 30, 2019, we were in compliance with and expect to be in compliance with the covenants of the Consolidated Credit Facility for at least the next twelve months.
Term Loan
On December 11, 2018, ENLK entered into the Term Loan 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. On December 11, 2018, ENLK borrowed $i850.0 million under the Term Loan and used the net proceeds to repay obligations outstanding under the ENLK Credit Facility. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan, the outstanding balance immediately becomes due, and ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. The outstanding balance
of the Term Loan was $i850.0 million as of September 30, 2019. The obligations under the Term Loan are unsecured.
The Term Loan will mature on December 10, 2021. The Term Loan 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. The financial
covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Term Loan, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than i2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Term Loan) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than i5.0
to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $i50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to i5.5
to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.
Borrowings under the Term Loan bear interest at ENLC’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from i1.0% to i1.75%)
or the Base Rate (the highest of the Federal Funds Rate plus i0.5%, the 30-day Eurodollar Rate plus i1.0% or the administrative agent’s prime rate)
plus an applicable margin (ranging from i0.0% to i0.75%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain
covenants included in the Term Loan, amounts outstanding under the Term Loan may become due and payable immediately.
At September 30, 2019, we were in compliance with and expect to be in compliance with the covenants of the Term Loan for at least the next twelve months.
The
following schedule reconciles total income tax expense and the amount calculated by applying the statutory U.S. federal tax rate to income (loss) before income taxes (in millions):
Expected income tax benefit (expense) based on federal statutory rate
$
(i3.8)
$
(i2.4)
$
i37.4
$
(i13.7)
State
income tax benefit (expense), net of federal benefit
(i0.7)
(i1.0)
i3.6
(i2.7)
Non-deductible
expense related to asset impairment
i—
i—
(i43.8)
i—
Other
(i1.8)
(i0.6)
i0.1
(i0.9)
Income
tax expense
$
(i6.3)
$
(i4.0)
$
(i2.7)
$
(i17.3)
/
Deferred
Tax Assets and Liabilities
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The DTAs, net of DTLs, are included in “Other assets, net” in the consolidated balance sheets. As of September 30, 2019, we had $i39.2 million of DTAs, net of $i111.9
million of DTLs. As of December 31, 2018, we had $i362.4 million of DTLs, net of $i79.6 million of DTAs.
/
As
a result of the Merger, we acquired all issued and outstanding ENLK common units that were not already held by us or our subsidiaries in exchange for the issuance of ENLC common units. See “Note 1—General” for more information regarding this transaction. This was a taxable exchange to our unitholders, and we received a step-up in tax basis of the underlying assets acquired. In accordance with ASC 810, Consolidation, the step-up in our basis reduced our DTL by $i399.0
million at the time of the Merger, and the resulting DTA will be realized over the tax-basis depreciable life of the underlying assets.
i
(8) Certain Provisions of the Partnership Agreement
a.ENLK Series B Preferred Units
Prior to the closing
of the Merger, Series B Preferred Unit distributions were payable quarterly in cash at an amount equal to $i0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) i0.0025
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 ENLK common units over the Cash Distribution Component, divided by (ii) the issue price of $i15.00 (the “Issue Price”).
Following the closing of the Merger, and beginning with the quarter ended March 31, 2019, the holder of the Series B Preferred Units is entitled
to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units as described below. The quarterly in-kind distribution (the “Series B PIK Distribution”) equals the greater of (A) i0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the exchange ratio
of i1.15 ENLC common units for each Series B Preferred Unit, subject to certain adjustments (the “Series B Exchange Ratio”), over (2) the Cash Distribution Component, divided by (y) the Issue Price. The quarterly cash distribution consists of the Cash
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
Distribution Component plus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the Series B PIK Distribution and (ii) the Series B Preferred Units that would have been distributed in the Series B PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments).
i
A
summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2019 and 2018 is provided below:
Declaration period
Distribution paid as additional Series B Preferred Units
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 initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is i6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $i1,000
liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of i4.11%. ENLK distributed $ii12.0/
million to holders of Series C Preferred Units for each of the nine months ended September 30, 2019 and 2018.
c.ENLK Common Unit Distributions
i
A summary of ENLK’s distribution activity relating to the common units for periods prior to the Merger is provided
below:
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
d.Allocation of ENLK Income
Prior to the closing of the Merger and for the three and nine months ended September 30, 2018, net income was allocated to the General Partner in an amount equal to its incentive distribution rights. Prior to the closing of the Merger, ENLK was required to pay the General Partner incentive distributions in the amount of i13.0%
of ENLK distributions in excess of $i0.25 per unit, i23.0% of ENLK distributions in excess of $i0.3125
per unit, and i48.0% of ENLK distributions in excess of $i0.375 per unit. The General Partner was not entitled to incentive distributions with respect to (i) distributions
on the Series B Preferred Units until such units converted into common units or (ii) the Series C Preferred Units. At the closing of the Merger, the General Partner’s incentive distribution rights in ENLK were eliminated.
i
For the three and nine months ended September 30, 2018, the General Partner’s share of net income consisted 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):
Unit-based
compensation attributable to ENLC’s restricted and performance units
(i11.1)
(i7.3)
(i29.6)
(i15.7)
General
Partner share of net income
i0.4
i—
i0.6
i0.6
General
Partner interest in EOGP acquisition
i—
i5.6
i2.4
i22.4
General
Partner interest in net income (loss)
$
(i10.7)
$
i13.3
$
(i26.6)
$
i51.9
/
i
(9)
Members' Equity
a.Issuance of ENLC Common Units related to the Merger
In connection with the consummation of the Merger, we issued i304,822,035 ENLC common units in exchange for all of the outstanding ENLK common units not previously owned by us.
b.ENLC
Equity Distribution Agreement
On February 22, 2019, ENLC entered into the ENLC EDA with the Sales Agents to sell up to $i400.0 million in aggregate gross sales of ENLC common units from time to time through an “at the market” equity offering program. Under the ENLC EDA, ENLC 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. ENLC has no obligation to sell any ENLC common units under the ENLC EDA and may at any time suspend solicitation and offers under the ENLC EDA. As of November 8, 2019, ENLC has not sold any common units under the ENLC EDA.
Notes to Consolidated
Financial Statements (Continued)
(Unaudited)
c.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. iThe
following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):
(1)For
the three months ended September 30, 2019 and 2018, distributed earnings represent a declared distribution of $iii0.283// per
unit payable on November 13, 2019 and a distribution of $ii0.271/ per
unit paid on November 14, 2018, respectively.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
d.Distributions
i
A
summary of our distribution activity relating to the ENLC common units for the nine months ended September 30, 2019 and 2018, respectively, is provided below:
The
following table shows the balances related to our investment in unconsolidated affiliates as of September 30, 2019 and December 31, 2018 (in millions):
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
i
(11) Employee Incentive Plans
a.Long-Term
Incentive Plans
Prior to the Merger, ENLC and ENLK each had similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the 2014 Plan, and ENLK granted unit-based awards under the GP Plan. As of the closing of the Merger, (i) ENLC assumed all obligations in respect of the GP Plan and the outstanding awards granted thereunder (the “Legacy ENLK Awards”) and (ii) 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. In addition, as of the closing of the Merger, the performance metric of each Legacy ENLK Award and each then outstanding award under the 2014 Plan with performance-based vesting conditions was modified as discussed in (c) and (e) below. Following the consummation of the Merger, no additional awards will be granted under 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.
iAmounts
recognized on the consolidated financial statements with respect to these plans are as follows (in millions):
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
b.EnLink Midstream Partners, LP Restricted Incentive Units
i
ENLK
restricted incentive units were 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 nine months ended September 30, 2019 is provided below:
(1)Vested
units included i249,201 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 i1.15
exchange ratio (as defined in the Merger Agreement) as the conversion rate.
/
i
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 nine months ended September 30, 2019 and 2018 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional restricted incentive units will vest as ENLK units under the GP Plan (such restricted incentive units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.
Prior to the Merger, the General Partner granted performance awards under the GP Plan. The performance award agreements provided that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder was 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 contemplated that the Peer Companies for an individual performance award (the “Subject Award”) were the companies comprising the AMZ, excluding ENLK and ENLC, on the grant date for the Subject Award. The performance units would vest based on the percentile ranking of the average of ENLK’s and ENLC’s TSR achievement (“EnLink TSR”) for
the applicable performance period relative to the TSR achievement of the Peer Companies. As of the closing of the Merger, these performance-based Legacy ENLK Awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger. 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 performance units ranges from izero
to i200% of the performance units granted depending on the extent to which the related performance goals are achieved over the relevant performance period.
The fair value of each performance unit was 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 and 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 ithree years.
(1)Vested
units included i62,403 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 i1.15
exchange ratio (as defined in the Merger Agreement) as the conversion rate.
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 three and nine months ended September 30, 2019 and 2018 is provided below (in millions). Since the Legacy ENLK Awards converted into ENLC unit-based awards as a result of the Merger, no additional performance units will vest as ENLK units under the GP Plan (such performance units, as converted, are eligible to vest as ENLC units) and no additional expense will be recognized after January 25, 2019 under the GP Plan.
Three
Months Ended September 30,
Nine Months Ended September 30,
EnLink Midstream Partners, LP Performance Units:
2019
2018
2019
2018
Aggregate intrinsic value of units vested
$
i—
$
i3.0
$
i2.1
$
i5.0
Fair
value of units vested
$
i—
$
i3.6
$
i1.7
$
i7.7
/
d.EnLink
Midstream, LLC Restricted Incentive Units
i
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 nine months ended September 30, 2019 is provided below:
Aggregate
intrinsic value, end of period (in millions)
$
i36.4
____________________________
(1)Restricted
incentive units typically vest at the end of three years. In March 2019, ENLC granted i420,842 restricted incentive units with a fair value of $i4.8
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 i563,606 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 i1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.
Notes
to Consolidated Financial Statements (Continued)
(Unaudited)
i
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 nine months ended September 30, 2019 and 2018
is provided below (in millions):
Three Months Ended September 30,
Nine Months Ended September 30,
EnLink
Midstream, LLC Restricted Incentive Units:
2019
2018
2019
2018
Aggregate intrinsic value of units vested
$
i3.1
$
i3.3
$
i16.0
$
i12.6
Fair
value of units vested
$
i5.8
$
i2.6
$
i18.9
$
i16.1
/
As
of September 30, 2019, there was $i29.1 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 i1.8
years.
For restricted incentive unit awards granted after March 8, 2019 to certain officers and employees (the “grantee”), such awards (the “Subject Grants”) generally provide that, subject to the satisfaction of the conditions set forth in the agreement, the Subject Grants will vest on the third anniversary of the vesting commencement date (the “Regular Vesting Date”). The Subject Grants will be forfeited if the grantee’s employment or service with ENLC and its affiliates terminates prior to the Regular Vesting Date except that the Subject Grants will vest in full or on a pro-rated basis for certain terminations of employment or service prior to the Regular Vesting Date. For instance, the Subject Grants will vest on a pro-rated basis for any terminations of the grantee’s employment: (i) due to retirement, (ii) by
ENLC or its affiliates without cause, or (iii) by the grantee for good reason (each, a “Covered Termination” and more particularly defined in the Subject Grants agreement) except that the Subject Grants will vest in full if the applicable Covered Termination is a “normal retirement” (as defined in the Subject Grants agreement) or the applicable Covered Termination occurs after a change of control (if any). The Subject Grants will vest in full if death or a qualifying disability occurs prior to the Regular Vesting Date.
e.EnLink Midstream, LLC’s Performance Units
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 performance goals 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 izero to i200%
of the units granted depending on the extent to which the related performance goals are achieved over the relevant performance period.
Performance awards granted prior to March 8, 2019 provided that the vesting of performance units granted was dependent on the achievement of certain TSR performance goals relative to the TSR achievement of the Peer Companies over the applicable performance period. Prior to the Merger, vesting of the performance units was based on the percentile ranking of the EnLink TSR for the applicable performance period relative to the TSR achievement of the Peer Companies. As of the effective time of the Merger, these performance-based awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies
in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger.
Aggregate
intrinsic value, end of period (in millions)
$
i8.5
____________________________
(1)Vested
units included i146,218 units withheld for payroll taxes paid on behalf of employees.
(2)As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC performance-based awards using the i1.15
exchange ratio (as defined in the Merger Agreement) as the conversion rate.
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 three and nine months ended September 30, 2019 and 2018 is provided below (in millions).
Three
Months Ended September 30,
Nine Months Ended September 30,
EnLink Midstream, LLC Performance Units:
2019
2018
2019
2018
Aggregate intrinsic value of units vested
$
i1.6
$
i2.8
$
i3.4
$
i4.7
Fair
value of units vested
$
i6.0
$
i3.5
$
i7.9
$
i7.7
/
As
of September 30, 2019, there was $i10.1 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 i1.9
years.
In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to, among other things: (i) provide that the awards granted thereunder did not vest due to the closing of the GIP Transaction, and (ii) increase the minimum vesting of units from izero to i100%
as described in our Current Report on Form 8-K filed with the Commission on July 23, 2018. The modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $i2.1 million compensation cost over the life of these ENLC performance units.
In
connection with the Merger, Legacy ENLK Awards with “performance-based” vesting and payment conditions were modified to reflect the Performance Metric Adjustment (as defined in the Merger Agreement) as described in our Current Report on Form 8-K filed with the Commission on January 29, 2019. The modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $i0.7
million in compensation costs over the life of the Legacy ENLK Awards.
2019 Performance Unit Awards
For performance awards granted after March 8, 2019 to the grantee, the vesting of performance units is dependent on (a) the grantee’s continued employment or service with ENLC or its affiliates for all relevant periods and (b) the TSR performance of ENLC (the “ENLC TSR”) and a performance goal based on cash flow (“Cash Flow”). At the time of grant, the Board of Directors of the managing member of ENLC (the “Board”) will determine the relative weighting of the two performance goals by including in the award agreement the number of units that will be eligible for vesting depending on the achievement of the TSR performance goals (the
“Total TSR Units”) versus the achievement of the Cash Flow performance goals (the “Total CF Units”). These performance awards have four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date of the performance awards and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”).
Notes
to Consolidated Financial Statements (Continued)
(Unaudited)
One-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to each of the four performance periods described above. Following the end date of a given performance period, the Governance and Compensation Committee (the “Committee”) of the Board will measure and determine the ENLC TSR relative to the TSR performance of a designated group of peer companies (the “Designated Peer Companies”) to determine the Tranche TSR Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end date of the Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance
period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period.
i
The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement
of the Designated Peer Companies:
Performance Level
Achieved ENLC TSR Position Relative to Designated Peer Companies
Vesting percentage of the Tranche TSR Units
Below Threshold
Less
than 25%
i0%
Threshold
Equal to 25%
i50%
Target
Equal
to 50%
i100%
Maximum
Greater than or Equal to 75%
i200%
Approximately
one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current
taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units outstanding during the relevant performance period. The following table sets out the levels at which the Tranche CF Units will be eligible to vest (using linear interpolation) based on the Cash Flow performance of ENLC for the performance period ending December 31, 2019:
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
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’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC (or for outstanding
performance units granted prior to the Merger, ENLC and ENLK) among the Designated Peer Companies or 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 ithree years.
i
The
following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
EnLink Midstream, LLC Performance Units:
June 2019
March 2019
Grant-Date Fair Value
$
i9.92
$
i13.10
Beginning
TSR price
$
i9.84
$
i10.92
Risk-free
interest rate
i1.72
%
i2.42
%
Volatility
factor
i33.50
%
i33.86
%
Distribution
yield
i11.5
%
i9.7
%
/
i
(12)
Derivatives
Interest Rate Swaps
We periodically enter into interest rate swaps during the debt issuance process to hedge 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 or to hedge variability in cash flows on our variable-rate debt. We designate interest rate swaps as cash flow hedges in accordance with ASC 815.
In April 2019, we entered into an $i850.0
million interest rate swap to manage the interest rate risk associated with our floating-rate, LIBOR-based borrowings. Under this arrangement, we pay a fixed interest rate of i2.27825% in exchange for LIBOR-based variable interest through December 2021. Assets or liabilities related to this interest rate swap contract are included in the fair value of derivative assets and liabilities on the consolidated balance sheets, and the change in fair value of this contract
is recorded net as gain or loss on designated cash flow hedges on the consolidated statements of comprehensive income. Monthly, upon settlement, we reclassify the gain or loss associated with the interest rate swap into interest expense from accumulated other comprehensive income (loss). There is no ineffectiveness related to this hedge.
In May 2017, we entered into an interest rate swap in connection with the issuance of ENLK’s 2047 Notes. Upon settlement of the interest rate swap in May 2017, we recorded the associated $i2.2
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 nine months ended September 30, 2019, we recorded $i1.3
million, net of a tax benefit of $i0.5 million, and $i11.2
million, net of a tax benefit of $i4.1 million, respectively, into accumulated other comprehensive loss related to changes in fair value of our interest rate swaps.
For the three and nine months ended September 30, 2019, we realized a gain of $i0.1
million and $i0.4 million, respectively, related to the monthly settlement of our interest rate swaps and an immaterial amount of amortization, which we recorded into interest expense, net of interest income from accumulated other comprehensive loss. For the three and nine months ended September 30, 2018, we recorded an immaterial amount into interest expense, net of interest income from accumulated other comprehensive loss. We expect
to recognize $i5.3 million of interest expense out of accumulated other comprehensive loss over the next twelve months.
i
The
fair value of our interest rate swaps included in our consolidated balance sheets were as follows (in millions):
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 September 30, 2019 (in millions). The remaining term of the contracts extend no later than December 2022.
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 $i17.5
million as of September 30, 2019 would be reduced to $i13.2 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.
(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.
Fair Value of Financial Instruments
i
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):
(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 $i30.8 million and $i24.5
million at September 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 $i58.0 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.”
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.
As of September 30, 2019, we had total borrowings under senior unsecured notes of $i3.6
billion maturing between 2024 and 2047 with fixed interest rates ranging from i4.15% to i5.60%. As of December 31,
2018, we had total borrowings under senior unsecured notes of $i3.5 billion maturing between 2019 and 2047 with fixed interest rates ranging from i2.70% to i5.60%.
/
The
fair values of all senior unsecured notes as of September 30, 2019 and December 31, 2018 were based on Level 2 inputs from third-party market quotations. The fair values of the secured term loan receivable were calculated using Level 2 inputs from third-party banks.
Notes to Consolidated
Financial Statements (Continued)
(Unaudited)
i
(14) Segment Information
Effective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources. As of December 31, 2018, our reportable operating segments consisted
of the following: (i) natural gas gathering, processing, transmission, and fractionation operations located in north Texas and the Permian Basin primarily in west Texas, (ii) natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana, (iii) natural gas gathering and processing operations located throughout Oklahoma, and (iv) crude rail, truck, pipeline, and barge facilities in west Texas, south Texas, Louisiana, Oklahoma, and ORV. Effective January 1, 2019, we are reporting financial performance in five segments: Permian, North Texas, Oklahoma, Louisiana, and Corporate. Crude and condensate operations are combined regionally with natural gas and NGL operations in the Oklahoma and Permian segments, and ORV operations are included in the Louisiana segment. We have recast the segment information for the three and nine months ended September 30,
2018 to conform to the current period presentation.
Identification of the majority of our operating segments is based principally upon geographic regions served:
•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.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
i
We
evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (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):
Secured
term loan receivable from contract restructuring, net of discount of $1.1 at December 31, 2018 (1)
i—
i19.4
Prepaid
expenses and other
i18.7
i13.5
Natural
gas and NGLs inventory, prepaid expenses, and other
$
i68.5
$
i74.2
____________________________
(1)In
late May 2019, White Star, the counterparty to our $i58.0 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.”
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Please read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. In addition, please refer to the Definitions page set forth in this report prior to Part I—Financial Information.
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.
Overview
ENLC is a Delaware limited liability company formed in October 2013. ENLC’s assets consist of equity interests in ENLK and, effective January 25, 2019, ENLC owns all of the outstanding
common units of ENLK as a result of the closing of the Merger described in “Item 1. Financial Statements—Note 1.” All of our midstream energy assets are owned and operated by ENLK and its subsidiaries. We primarily focus on providing midstream energy services, including:
•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.
Our
midstream energy asset network includes approximately 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately 280,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography. We have five reportable segments:
•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.
We manage our operations by focusing on gross operating margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We 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 commodity purchase. 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. We define gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 90% of our gross operating margin was derived from fee-based
contractual arrangements with minimal direct commodity price exposure for the nine months ended September 30, 2019. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.
Devon is one of our primary customers. For the three and nine months ended September 30, 2019, approximately 31.8% and 30.2% of our gross operating margin, respectively, was attributable to commercial contracts with Devon. For the three and nine months ended September 30, 2018, approximately 38.5% and 38.3% of our gross operating margin, respectively, was
attributable to commercial contracts with Devon.
Our revenues and gross operating margins are generated from eight primary sources:
•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.
We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of
the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments.
In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.
We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher gross operating margins from product
upgrades during periods with higher NGL prices.
We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction.
We realize gross operating margins
from our gathering and processing services primarily through different contractual arrangements: processing margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee component contracts, or a combination of these contractual arrangements. “See Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a detailed description of these contractual arrangements. Under any of these gathering and processing arrangements, we may earn a fee for the services performed, or we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize
a net margin as our fee. Under margin contract arrangements, our gross operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our gross operating margins are driven by throughput
volume.
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate
moved through or by our assets.
Recent Developments
Lobo Natural Gas Gathering and Processing Facilities. In early April 2019, we completed construction of a 100 MMcf/d expansion to our Lobo III cryogenic gas processing plant, bringing the total operational processing capacity at our Lobo facilities to 375 MMcf/d.
Cajun-Sibon Pipeline. In April 2019, we completed the expansion of our Cajun-Sibon NGL pipeline capacity, which connects the Mont Belvieu NGL hub to our fractionation facilities in Louisiana. This is the third phase of our Cajun-Sibon system referred to as Cajun Sibon III, which increases throughput capacity from 130,000
bbls/d to 185,000 bbls/d.
Avenger Crude Oil Gathering System. Avenger is a crude oil gathering system in the northern Delaware Basin and is supported by a long-term contract with Devon on dedicated acreage in their Todd and Potato Basin development areas in Eddy and Lea counties in New Mexico. We commenced initial operations on Avenger during the third quarter of 2018 and began full-service operations during the second quarter of 2019.
Central Oklahoma Plants. In June 2019, we commenced operations on our Thunderbird Plant, which expands our central Oklahoma gas processing capacity by an additional 200 MMcf/d, bringing our total processing capacity at our central Oklahoma facilities to 1.2 Bcf/d.
Riptide
Processing Plant. In September 2019, we completed construction of a 65 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 165 MMcf/d.
Delaware Basin Processing Plant. In August 2019, we commenced construction of our Tiger Plant, which will expand our Delaware Basin processing capacity by an additional 200 MMcf/d. We expect the plant to be operational in the second half of 2020. This processing plant is owned by the Delaware Basin JV.
Non-GAAP Financial Measures
We include the following non-GAAP financial measures: Adjusted
earnings before interest, taxes, and depreciation and amortization (“adjusted EBITDA”), distributable cash flow available to common unitholders (“distributable cash flow”), and gross operating margin.
Adjusted EBITDA
We define adjusted EBITDA as net income (loss) plus net interest expense, income tax expense (benefit), depreciation and amortization expense, impairments, unit-based compensation, (gain) loss on non-cash derivatives, (gain) loss on disposition of assets, loss on secured term loan receivable, successful transaction costs, accretion expense associated with asset retirement obligations, and distributions from unconsolidated affiliate investments, less payments under onerous performance obligations, non-controlling interest, income
(loss) from unconsolidated affiliate investments, non-cash rent, and non-cash revenue from contract restructuring. Adjusted EBITDA is a primary metric used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:
•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;
•the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness,
and make cash distributions to our unitholders;
•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and
•the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
The GAAP measures most directly comparable to adjusted EBITDA are net
income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly-titled measures of other companies because other companies may not calculate adjusted EBITDA in the same manner.
Adjusted EBITDA does not include interest expense, income taxes, or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude
these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.
The following table reconciles adjusted EBITDA to net income (in millions):
Reconciliation of net income (loss) to adjusted EBITDA
Payments
under onerous performance obligation offset to other current and long-term liabilities
—
(4.5)
(9.0)
(13.5)
Transaction costs (2)
—
2.8
13.9
2.8
Other
(3)
(1.2)
(0.3)
(0.8)
0.5
Adjusted EBITDA before non-controlling interest
267.5
282.4
806.7
807.8
Non-controlling
interest share of adjusted EBITDA from joint ventures (4)
(6.3)
(6.1)
(18.1)
(13.8)
Adjusted EBITDA, net to ENLC
$
261.2
$
276.3
$
788.6
$
794.0
____________________________
(1)In
May 2018, we restructured our natural gas gathering and processing contract with White Star, and, as a result, recognized non-cash revenue representing the discounted present value of a secured term loan receivable granted to us by White Star. We have recorded a $52.9 million loss in our consolidated statement of operations for the nine months ended September 30, 2019 related to the write-off of the secured term loan receivable. For additional information regarding this transaction, refer to “Item 1. Financial Statements—Note 2.”
(2)Represents transaction costs attributable to costs incurred related to the Merger in January 2019 and costs incurred by ENLC related to the GIP Transaction in July 2018.
(3)Includes
accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(4)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.
We
define distributable cash flow as adjusted EBITDA, net to ENLC, less interest expense, interest rate swaps, current income taxes and other non-distributable cash flows, accrued cash distributions on ENLK Series B Preferred Units and ENLK Series C Preferred Units paid or expected to be paid, and maintenance capital expenditures, excluding maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities. Distributable cash flow is used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions.
Maintenance capital expenditures include capital expenditures
made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations.
The GAAP measure most directly comparable to distributable cash flow is net cash provided by operating activities. Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Distributable cash flow has important
limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Distributable cash flow may not be comparable to similarly-titled measures of other companies because other companies may not calculate distributable cash flow in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as distributable cash flow, to evaluate our overall liquidity.
Changes
in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other
(78.0)
(341.3)
Accounts payable, accrued product purchases, and other accrued liabilities (4)
34.6
196.9
Adjusted
EBITDA before non-controlling interest
267.5
806.7
Non-controlling interest share of adjusted EBITDA from joint ventures (5)
(6.3)
(18.1)
Adjusted EBITDA, net to ENLC
261.2
788.6
Interest
expense, net of interest income
(i56.6)
(160.5)
Current
taxes and other
(0.6)
(4.1)
Maintenance capital expenditures, net to ENLC (6)
(12.7)
(34.4)
ENLK preferred unit accrued cash distributions (7)
(23.1)
(68.9)
Distributable
cash flow
$
168.2
$
520.7
____________________________
(1)Net of amortization of debt issuance costs and discount and premium, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA.
(2)Represents transaction costs incurred related
to the Merger.
(3)Includes accruals for settled commodity swap transactions, distributions received from equity method investments to the extent those distributions exceed earnings from the investment, and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(4)Net of payments under onerous performance obligation offset to other current and long-term liabilities.
(5)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, Marathon Petroleum Corporation’s50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.
(6)Excludes
maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.
(7)Represents the cash distributions earned by the ENLK Series B Preferred Units and ENLK Series C Preferred Units of $17.1 million and $6.0 million, respectively, for the three months ended September 30, 2019, and cash distributions earned by the Series B Preferred Units and Series C Preferred Units of $50.9 million and $18.0 million, respectively, for the nine months ended September 30, 2019. Cash distributions to be paid to holders of the ENLK Series B Preferred Units and ENLK Series C Preferred Units are not available to common unitholders.
Distributable cash flow is not presented
for the three and nine months ended September 30, 2018, because distributable cash flow was not used as a supplemental liquidity measure by ENLC during 2018. ENLC began using distributable cash flow as a supplemental liquidity measure in 2019 as a result of the simplification of our corporate structure in the Merger.
We define gross operating margin as revenues less cost of sales. We present gross operating
margin by segment in “Results of Operations.” We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are
largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to gross operating margin is operating income (loss). Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) as determined in accordance with GAAP. Gross operating margin has important limitations because it excludes all operating costs that affect operating income (loss) except cost of sales. Our gross operating margin may not be comparable to similarly-titled measures of other companies because other entities may not calculate these amounts in the same manner.
The following table provides a reconciliation of operating income to gross operating margin (in millions):
The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin, which we define as revenue less cost of sales as reflected in the table below (in millions, except volumes):
Gross Operating Margin. Gross operating margin was $408.5 million for the three months ended September 30, 2019 compared to $417.7 million for the three months ended September 30, 2018, a decrease of $9.2 million, or 2.2%, due to the following:
•Permian Segment. Gross operating margin in the Permian segment increased $4.3 million, which was primarily due to a $9.5 million increase
in gross operating margin due to higher volumes from our Permian gas assets related to continued development by our customers, as a result of $5.2 million from our Delaware Basin assets and $4.3 million from our Midland Basin assets. These increases were partially offset by a $5.5 million decrease from our Permian crude assets, which was attributable to a $2.1 million decrease in gross operating margin due to lower crude oil handling volumes and the expiration of an MVC related to a transportation services agreement with Devon during the third quarter of 2019 and a $3.4 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 $27.3 million primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets and volume declines due to limited new drilling. Shortfall revenue from the Devon-related MVCs was $22.1 million for the three months ended September 30, 2018.
•Oklahoma Segment. Gross operating margin in the Oklahoma segment increased $4.3 million, which was primarily due to higher
volumes from our Oklahoma crude assets. Gross operating margin from our Oklahoma gas assets decreased by $3.0 million between periods as increases in gross operating margin from higher volumes were offset by the negative impact of NGL and gas price declines under our Oklahoma processing contracts with fixed recovery provisions.
•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $3.4 million. Gross operating margin from our NGL transmission and fractionation assets increased by $9.0 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 $12.4 million decrease from our Louisiana gas business. Gross operating margin
from our Louisiana gas transmission assets decreased $6.0 million due to the expiration of certain firm transportation contracts and decreased volumes. Gross operating margin from our Louisiana gas plants decreased $6.4 million due to lower processing margins and volumes attributable to a less favorable processing environment during the three months ended September 30, 2019.
•Corporate Segment. Gross operating margin in the Corporate segment increased $12.9
million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):
Certain gathering and processing agreements provide for quarterly or annual MVCs, including MVCs from Devon. Under these agreements, our customers agree to ship and/or process a minimum volume of commodity on our systems over an agreed time period. If a customer 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 commodity volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer 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.
Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):
On
January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the North Texas and Oklahoma segments expired. These MVCs generated $22.1 million in shortfall revenue for the three months ended September 30, 2018. Additionally, an MVC related to a transportation services agreement with Devon for operations in the Permian segment expired on July 31, 2019. This MVC generated $1.7 million and $2.7 million in shortfall revenue for the three months ended September 30, 2019 and 2018, respectively. Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December
2020.
Operating Expenses. Operating expenses were $119.2 million for the three months ended September 30, 2019 compared to $114.7 million for the three months ended September 30, 2018, an increase of $4.5 million, or 3.9%. The primary contributors to the total increase by segment were as follows (in millions):
Three
Months Ended September 30,
Change
2019
2018
$
%
Permian Segment
$
28.9
$
22.4
$
6.5
29.0
%
North
Texas Segment
26.2
27.9
(1.7)
(6.1)
%
Oklahoma Segment
25.7
23.0
2.7
11.7
%
Louisiana
Segment
38.4
41.4
(3.0)
(7.2)
%
Total
$
119.2
$
114.7
$
4.5
3.9
%
•Permian
Segment. Operating expenses in the Permian segment increased $6.5 million primarily due to expanded operations with increases in utilities, materials and supplies expenses, construction fees and services, and ad valorem taxes.
•North Texas Segment. Operating expenses in the North Texas segment decreased $1.7 million primarily due to reduced compression and treater rental costs.
•Oklahoma Segment. Operating expenses in the Oklahoma segment increased $2.7 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 $3.0 million primarily due to reduced compression rental expense and lower ad valorem taxes.
General and Administrative Expenses. General and administrative expenses were $38.5 million for the three months ended September 30, 2019 compared to $41.9 million for the three months ended September 30, 2018, a decrease of $3.4 million, or 8.1%. The primary contributors to the decrease were as follows:
•Transaction costs decreased $3.0 million compared to the higher level of transaction costs incurred in the third quarter of
2018 related to the GIP Transaction.
•Unit-based compensation expense decreased $1.9 million compared to the higher level of unit-based compensation expense in the third quarter of 2018 due to accelerated vesting related to the GIP Transaction and an organizational realignment. This decrease was partially offset by accelerated vesting related to an executive departure in the third quarter of 2019.
•Partially offsetting these decreases is a $1.6 million increase in fees and services expense, which was primarily due to increased software consulting and legal fees in the third quarter of 2019.
Depreciation and Amortization.
Depreciation and amortization was $157.3 million for the three months ended September 30, 2019 compared to $146.7 million for the three months ended September 30, 2018, an increase of $10.6 million, or 7.2%. This increase was primarily due to additional depreciation of $6.8 million attributable to new assets placed in service in key growth areas, primarily related to the completion of the Thunderbird Plant, the expansion of the Lobo III cryogenic gas processing plant, further expansion of Avenger, and additional well connections in Oklahoma.
Impairments. For the three months ended September 30, 2018, we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets
because the carrying values were no longer recoverable.
Interest Expense. Interest expense was $56.6 million for the three months ended September 30, 2019 compared to $45.2 million for the three months ended September 30, 2018, an increase of $11.4 million, or 25.2%. Interest expense consisted of the following (in millions):
Amortization
of debt issue costs and net discounts (premiums)
1.1
0.9
Other
—
(1.3)
Total
$
56.6
$
45.2
Income
Tax Expense. Income tax expense was $6.3 million for the three months ended September 30, 2019 compared to an income tax expense of $4.0 million for the three months ended September 30, 2018, an increase in income tax expense of $2.3 million. The increase in income tax expense was primarily attributable to higher income between periods. See “Item 1. Financial Statements—Note 7” for additional information.
Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $25.7 million for the three months ended September 30, 2019 compared to net income of $37.3 million for the three months ended September 30,
2018, a decrease of $11.6 million. This decrease was primarily due to the conversion of ENLK common units as a result of the Merger. Subsequent to the Merger, ENLC’s non-controlling interest is comprised of ENLK’s Series B Preferred Units, ENLK’s Series C Preferred Units, 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.
Gross Operating Margin. Gross operating margin was
$1,234.2 million for the nine months ended September 30, 2019 compared to $1,237.0 million for the nine months ended September 30, 2018, a decrease of $2.8 million, or 0.2%, due to the following:
•Permian Segment. Gross operating margin in the Permian segment increased $33.8 million, which was primarily due to a $34.8 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued development by our customers, including $20.0 million from our Delaware Basin assets, and $14.8 million from our Midland Basin assets. This increase was slightly offset by a $1.3 million decrease in gross operating margin from our Permian crude assets, which was due to a $3.9 million increase in gross operating margin
from our Midland and Delaware Basins crude assets, offset by a $5.2 million decrease in gross operating margin from our south Texas assets due to an MVC expiration in July 2019 and decreased crude activity during 2019.
•North Texas Segment. Gross operating margin in the North Texas segment decreased $65.8 million, which was primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets and normal volume declines due to limited new drilling. Shortfall revenue from the Devon-related MVCs was $61.1 million for the nine months ended September 30, 2018.
•Oklahoma Segment. Gross
operating margin in the Oklahoma segment decreased $9.0 million. Gross operating margin from our Oklahoma assets increased $36.1 million, which was primarily due to higher volumes from continued development by our customers, with $18.6 million contributed by our Oklahoma gas assets and $17.5 million contributed by our Oklahoma crude assets. This increase in gross operating margin was offset by the recognition of $45.5 million in gross operating margin from a contract restructuring with White Star during the nine months ended September 30, 2018.
•Louisiana
Segment. Gross operating margin in the Louisiana segment increased $1.9 million. Gross operating margin from our NGL assets increased by $17.4 million primarily due to higher volumes with the completion of the Cajun-Sibon pipeline expansion in April 2019. Our ORV crude assets contributed an increase of $4.3 million primarily due to higher volumes. These increases were partially offset by a decrease of $19.2 million from our Louisiana gas business, primarily due to a $11.2 million decrease from our Louisiana gas plants due to a less favorable processing environment during the nine months ended September 30, 2019 and an $8.0 million decrease from our Louisiana gas transportation assets due to the expiration of certain firm transportation contracts and decreased volumes during the same period.
•Corporate
Segment. Gross operating margin in the Corporate segment increased $36.3 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):
(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 nine months ended September 30, 2018.
On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the North Texas and Oklahoma segments expired. These MVCs generated $62.3 million in shortfall revenue for the nine months ended September 30, 2018. Additionally, an MVC related to a transportation services agreement with Devon for operations in the Permian segment expired on July
31, 2019. This MVC generated $9.4 million and $8.4 million in shortfall revenue for the nine months ended September 30, 2019 and 2018, respectively. Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020.
Operating Expenses. Operating expenses were $351.6 million for the nine months ended September 30,
2019 compared to $337.3 million for the nine months ended September 30, 2018, an increase of $14.3 million, or 4.2%. The primary contributors to the increase by segment were as follows (in millions):
Nine Months Ended September 30,
Change
2019
2018
$
%
Permian
Segment
$
85.1
$
70.9
$
14.2
20.0
%
North Texas Segment
77.7
84.7
(7.0)
(8.3)
%
Oklahoma
Segment
77.2
64.5
12.7
19.7
%
Louisiana Segment
111.6
117.2
(5.6)
(4.8)
%
Total
$
351.6
$
337.3
$
14.3
4.2
%
•Permian
Segment. Operating expenses in the Permian segment increased $14.2 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 $7.0 million primarily due to decreased compressor rentals, compressor overhauls, and labor and benefits costs.
•Oklahoma Segment. Operating expenses in the Oklahoma segment increased $12.7 million primarily due to expanded operations with increases in utilities, equipment rentals, compression operations and maintenance, and labor and benefits costs.
•Louisiana
Segment. Operating expenses in the Louisiana segment decreased $5.6 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.
General and Administrative Expenses. General and administrative expenses were $122.1 million for the nine months ended September 30, 2019 compared to $99.8 million for the nine months ended September 30, 2018, an increase of $22.3 million, or 22.3%. The primary contributors to the increase were as follows:
•Transaction costs increased
$11.1 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019.
•Unit-based compensation expense increased $4.4 million, which was primarily due to increased bonus expense and accelerated vesting related to an executive departure in the third quarter of 2019. This increase was partially offset by accelerated vesting related to the GIP Transaction and an organizational realignment in the third quarter of 2018.
•Fees and services expense increased $3.3 million, which was primarily due to increased software consulting and legal fees.
•Salaries and wages expense increased $1.2 million,
which was primarily due to severance expense for an executive departure in the third quarter of 2019.
Depreciation and Amortization. Depreciation and amortization was $463.1 million for the nine months ended September 30, 2019 compared to $430.1 million for the nine months ended September 30, 2018, an increase of $33.0 million, or 7.7%. This increase was primarily due to increased depreciation of $19.0 million attributable to new assets placed in service in key growth areas, primarily related to the completion of the Thunderbird Plant, the expansion of the Lobo III cryogenic gas processing plant, the Cajun-Sibon NGL pipeline, Avenger, the Black Coyote crude oil gathering system, and well connections in
Oklahoma. Additionally, depreciation increased by $16.2 million primarily due to retirements and reductions in our estimated useful lives of certain assets primarily located in the Texas and Louisiana segments. These increases were partially offset by a $7.8 million decrease due to a reduction in depreciation resulting from an impairment of the carrying value of certain non-core crude pipeline assets during 2018.
Impairments. During the first quarter of 2019, as a result of the Merger, we recognized a $186.5 million goodwill impairment related to our Louisiana segment. For the nine months ended September 30, 2018, we recognized impairments of
property and equipment of $24.6 million related to certain non-core pipeline assets because the carrying values were no longer recoverable.
Loss on secured term loan receivable. We have recorded a $52.9 million loss in our consolidated statement of operations for the nine months ended September 30, 2019 related to the write-off of the secured term loan receivable. For additional information regarding this transaction, refer to “Item 1. Financial Statements—Note 2.”
Interest Expense. Interest expense was $160.5 million for the nine months ended September 30, 2019 compared to $134.3 million for
the nine months ended September 30, 2018, an increase of $26.2 million, or 19.5%. Interest expense consisted of the following (in millions):
Amortization of debt issue costs and net discounts (premiums)
3.9
3.4
Other
(2.2)
(1.7)
Total
$
160.5
$
134.3
Income
(Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $14.0 million for the nine months ended September 30, 2019 compared to $11.7 million for the nine months ended September 30, 2018, an increase of $2.3 million. The increase was primarily attributable to additional income of $1.3 million from our GCF investment as a result of higher fractionation revenues and lower operating expenses and additional income of $1.0 million from our Cedar Cove JV.
Income Tax Expense. Income tax expense was $2.7 million for the nine months ended September 30, 2019 compared to an income tax expense of $17.3 million for the nine months ended September 30,
2018, a decrease in income tax expense of $14.6 million. The decrease in income tax expense was primarily attributable to lower income between periods. See “Item 1. Financial Statements—Note 7” for additional information.
Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $92.4 million for the nine months ended September 30, 2019 compared to net income of $156.2 million for the nine months ended September 30, 2018, a decrease of $63.8 million. This decrease was primarily due to the conversion of ENLK common units as a result of the Merger. Subsequent to the Merger, ENLC’s non-controlling interest is comprised of ENLK’s Series B Preferred Units, ENLK’s Series C Preferred Units, 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.
Critical Accounting Policies
Information regarding our critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018, except for our critical accounting policy on leases, which changed as a result of the adoption of ASC 842 on January 1, 2019. See “Item 1. Financial Statements—Note 5” for information on our leases accounting policy.
Goodwill Impairment
We
perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill
impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. The estimated fair value of our reporting units may be impacted in the future by a prolonged decline in our unit price or a prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our reporting units.
In March 2014, at the time of our transactions with Devon that led us to become publicly held, we recorded goodwill in our corporate reporting unit at ENLC that was associated with the General Partner’s incentive distribution rights in ENLK. Prior to the completion of the Merger in January 2019, ENLC’s aggregate fair value of its reporting units was in excess of the consolidated book value of its assets, including
all goodwill, which did not result in a goodwill impairment on a consolidated basis. Upon the completion of the Merger, in accordance with ASC 350, Intangibles-Goodwill and Other (“ASC 350”), the portion of goodwill in our corporate reporting unit that was previously associated with the General Partner’s incentive distribution rights in ENLK was required to be reallocated to the four remaining reporting units based on the relative fair value of each of the reporting units, with $184.6 million allocated to our Permian segment, $125.7 million allocated to our North Texas segment, $623.1 million allocated to our Oklahoma segment, and $186.5 million allocated to our Louisiana segment. We recognized a $186.5 million goodwill impairment related to our Louisiana segment during the first quarter of 2019. During the third quarter of 2019, we performed an interim impairment test due to a significant decline in our unit price from the first quarter and downward revisions
in our estimated future cash flows due to delays in development plans announced by certain of our major customers. For the three months ended September 30, 2019, we determined that 0 impairments of goodwill were required as of September 30, 2019. As a result of our latest goodwill impairment test performed as of September 30, 2019, the goodwill on our North Texas and Oklahoma segment assets is at risk for future impairment because the fair values of these reporting units do not substantially exceed their carrying values.
Liquidity and Capital Resources
Cash
Flows from Operating Activities. Net cash provided by operating activities was $i777.5 million for the nine months ended September 30, 2019 compared to $i539.0
million for the nine months ended September 30, 2018. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):
Operating cash flows before changes in working capital decreased $39.7 million for the nine months ended September 30, 2019 compared to the nine months ended September 30,
2018. The primary contributors to the decrease in operating cash flows were as follows:
•General and administrative expenses excluding unit-based compensation increased $17.8 million primarily due to higher transaction costs related to the Merger in January 2019. For more information, see “Results of Operations.”
•Operating expenses excluding unit-based compensation increased $19.3 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 $25.7 million.
These
decreases to operating cash flows were partially offset by a $23.2 million increase in gross operating margin, excluding unrealized gains and losses on derivative activity and excluding non-cash revenue recognized from the restructuring of a contract. The changes in working capital for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.
Cash Flows from Investing Activities. Net cash used in investing activities was $i583.0 million for the nine months ended September 30, 2019, compared to $i633.0
million for the nine months ended September 30, 2018. Our primary investing cash flows were as follows (in millions):
Growth
capital expenditures decreased $48.8 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The decrease was primarily due to lower overall growth capital expenditures due to the completion of Avenger and the Lobo III gas processing plant in the Delaware Basin in 2018, compared to the capital expenditures in 2019 related to the Lobo III cryogenic gas processing plant expansion, the Thunderbird Plant, the expansion of the Cajun-Sibon NGL pipeline, and the expansion of the Riptide processing plant.
Proceeds from the sale of assets increased $12.2 million for the nine months ended September 30, 2019, primarily due to the sale of certain non-core assets during 2019.
Cash
Flows from Financing Activities. Net cash used in financing activities was $i192.7 million for the nine months ended September 30, 2019 and net cash provided by financing activities was $i127.6
million for the nine months ended September 30, 2018. Our primary financing activities consisted of the following (in millions):
Net borrowings (repayments) on the ENLC Credit Facility
(111.4)
26.8
Net borrowings on the Consolidated Credit Facility
275.0
—
Net
repayments on the ENLK 2019 unsecured senior notes
(400.0)
—
Net borrowings on the ENLC 2029 unsecured senior notes
500.0
—
Proceeds from issuance of ENLK common units
—
46.1
Contributions
by non-controlling interests (1)
78.6
73.4
Payment of installment payable for EOGP acquisition
—
(250.0)
Distribution to members
(328.0)
(145.0)
Distributions
to non-controlling interests
(185.1)
(379.3)
____________________________
(1)Represents contributions from NGP to the Delaware Basin JV.
On April 9, 2019, we issued $i500.0
million in aggregate principal amount of ENLC’s 2029 Notes at a price to the public of i100% of their face value. Interest payments on the 2029 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2019. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $i496.5
million were used to repay outstanding borrowings under the Consolidated Credit Facility, including borrowings incurred on April 1, 2019 to repay at maturity all of the $i400.0 million outstanding aggregate principal amount of ENLK’s i2.70%
senior unsecured notes due 2019, and for general limited liability company purposes.
For the nine months ended September 30, 2018, ENLK sold an aggregate of 2.6 million common units under an equity distribution agreement, generating proceeds of $46.1 million.
Distributions to ENLK common units held by public unitholders (1)
$
(104.8)
$
(309.4)
Distributions to Series B and C Preferred Units (2)
(62.3)
(60.5)
Distributions
to joint venture partners (3)
(18.0)
(9.4)
____________________________
(1)Subsequent to the closing of the Merger, ENLK no longer has publicly held common units.
(2)See “Item 1. Financial Statements—Note 8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units.
(3)Represents distributions to NGP for its ownership in the Delaware Basin JV and distributions to Marathon Petroleum Corporation
for its ownership in the Ascension JV.
Capital Requirements. We consider a number of factors in determining whether our capital expenditures are growth capital expenditures or maintenance capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income.
Maintenance
capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, or to maintain pipeline and equipment reliability, integrity, and safety and to address environmental laws and regulations.
We expect our remaining 2019 growth capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately $120 million to $200 million, net of $31 million to $51 million which we expect to come from our joint venture partners. We expect our remaining 2019 maintenance capital expenditures to be approximately
$10 million to $20 million. Our primary capital projects for the remainder of 2019 include the ongoing construction of the Tiger Plant in the Delaware Basin, and continued development of our existing systems. See “Recent Developments” for further details.
We expect to fund growth capital expenditures from the proceeds of borrowings under the Consolidated Credit Facility, operating cash flows, and proceeds from other debt and equity sources, including capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. We expect to fund our maintenance capital expenditures from operating cash flows. In 2019, it is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon
our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.
Off-Balance Sheet Arrangements. No off-balance sheet arrangements existed as of September 30, 2019.
Total Contractual Cash Obligations. A summary of contractual cash obligations as of September 30,
2019 is as follows (in millions):
Payments Due by Period
Total
Remainder
2019
2020
2021
2022
2023
Thereafter
Long-term debt obligations
$
3,600.0
$
—
$
—
$
—
$
—
$
—
$
3,600.0
Term
Loan
850.0
—
—
850.0
—
—
—
Consolidated Credit
Facility
275.0
—
—
—
—
—
275.0
Interest payable
on fixed long-term debt obligations
2,592.2
78.1
176.0
176.0
176.0
176.0
1,810.1
Operating
lease obligations
142.7
6.7
23.5
17.1
10.2
9.0
76.2
Purchase
obligations
29.6
29.6
—
—
—
—
—
Pipeline capacity
and deficiency agreements (1)
198.1
9.7
37.2
37.1
31.1
28.1
54.9
Inactive
easement commitment (2)
10.0
—
—
—
10.0
—
—
Total
contractual obligations
$
7,697.6
$
124.1
$
236.7
$
1,080.2
$
227.3
$
213.1
$
5,816.2
____________________________
(1)Consists
of pipeline capacity payments for firm transportation and deficiency agreements.
(2)Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.
The above table does not include any physical or financial contract purchase commitments for natural gas and NGLs due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.
The interest payable related to the Consolidated Credit Facility and the Term Loan are not reflected in the above
table because such amounts depend on the outstanding balances and interest rates of the Consolidated Credit Facility and the Term Loan, which vary from time to time.
Our contractual cash obligations for the remainder of 2019 are expected to be funded from cash flows generated from our operations, potential non-core asset sales, and other debt and equity sources.
Indebtedness
In December 2018, we entered into the Consolidated Credit Facility, which permits us to borrow up to $1.75 billion on a revolving credit basis and includes a $500.0 million letter of credit subfacility. At the closing of the Merger, the ENLC Credit Facility was canceled, the Consolidated Credit Facility
became available for borrowings and letters of credit, and ENLK became a guarantor under the Consolidated Credit Facility. As of September 30, 2019, there was $275.0 million in outstanding borrowings under the Consolidated Credit Facility and $4.0 million in outstanding letters of credit.
In December 2018, ENLK entered into the Term Loan and used the net proceeds to repay borrowings under the ENLK Credit Facility. At the closing of the Merger, the Term Loan was assumed by us, and ENLK became a guarantor of the Term Loan.
In addition, as of September 30, 2019, we have $3.6 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047.
See
“Item 1. Financial Statements—Note 6” for more information on our outstanding debt instruments.
Recent Accounting Pronouncements
See “Item 1. Financial Statements—Note 2” for more information on recently issued and adopted accounting pronouncements.
This
Quarterly Report on Form 10-Q contains forward-looking statements that are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,”“may,”“believe,”“will,”“should,”“plan,”“predict,”“anticipate,”“intend,”“estimate,”“expect,”“continue,” and similar expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part II, “Item 1A. Risk Factors” of
this report and in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018 may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary
market risk is the risk related to changes in the prices of natural gas, NGLs, condensate, and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.
Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the CFTC to regulate certain markets for derivative products, including OTC derivatives. The CFTC has issued several relevant regulations, and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the legislation to cause significant portions of derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the regulatory regime affecting
commodity derivatives remains uncertain.
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures, and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two
industry associations and was vacated and remanded by a federal district court. The CFTC proposed and revised new rules in November 2013 and December 2016, respectively, that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC sought comment on the position limits rules as reproposed and revised, but the new rules have not yet been issued in final form, and the impact of any final provisions on us is uncertain at this time.
The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.
The legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions
at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.
We are subject to risks due to fluctuations in commodity prices. Approximately 90% of our gross operating margin for the nine months ended September 30, 2019 was
generated from arrangements with fee-based structures with minimal direct commodity price exposure. Our exposure to these commodity price fluctuations is primarily in the gas processing component of our business. We currently process gas under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below.
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 nine months ended September 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.
For the nine months ended September 30, 2019, approximately 7% of our gross operating margin was generated from POL or POP contracts.
Our
primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using OTC derivative financial instruments with only certain well-capitalized counterparties which have been approved in accordance with our commodity risk management policy.
We have hedged our exposure to fluctuations in prices for natural gas, NGLs, crude oil, and condensate volumes produced for our account. We hedge our exposure based on volumes we consider hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms,
such as contracts with month-to-month processing options. Further, we have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon our expected equity NGL composition.
The following table sets forth certain information related to derivative instruments outstanding at September 30, 2019 mitigating the risks associated with the gas processing
and fractionation components of our business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by Oil Price Information Service. The relevant index price for natural gas is Henry Hub Gas Daily as defined by the pricing dates in the swap contracts.
Period
Underlying
Notional
Volume
We Pay
We Receive (1)
Fair Value Asset/(Liability) (In millions)
October 2019 - March 2020
Ethane
271 (MBbls)
$0.1841/gal
Index
$
(0.5)
October
2019 - July 2020
Propane
725 (MBbls)
Index
$0.4616/gal
2.3
October 2019 - July 2020
Normal butane
89 (MBbls)
Index
$0.5299/gal
—
October
2019 - July 2020
Natural gasoline
70 (MBbls)
Index
$1.0541/gal
0.1
October 2019 - July 2020
Natural gas
17,968 (MMBtu/d)
Index
$2.4223/MMBtu
0.3
October
2019 - December 2022
Crude and condensate
13,546 (MBbls)
Index
$53.07/bbl
11.0
$
13.2
____________________________
(1)Weighted
average.
Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted
quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.
As of September 30, 2019, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments were a net fair value asset of $13.2 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in a change of approximately $4.7 million in the net fair value of these contracts as of September 30,
2019.
Interest Rate Risk
We are exposed to interest rate risk on the Consolidated Credit Facility and the Term Loan. At September 30, 2019, we had $275.0 million and $850.0 million in outstanding borrowings under the Consolidated Credit Facility and the Term Loan, respectively. In April 2019, we entered into $850.0 million of interest rate swaps to reduce the variability of cash outflows associated with interest payments related to our long-term debt with variable interest rates. These swaps have been designated as cash flow hedges. See “Item 1. Financial Statements—Note 12” for more information on our outstanding derivatives. A 1.0% increase or decrease in interest rates would change our annualized
interest expense by approximately $2.8 million and $8.5 million for the Consolidated Credit Facility and the Term Loan, respectively. This change in interest expense would be partially offset by an $8.5 million change related to our open interest rate swap hedge.
We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured note due in 2029 as these are fixed-rate obligations. The estimated fair value of the senior unsecured notes was approximately $3,250.8 million as of September 30, 2019, based on market prices of similar debt at September 30, 2019. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1.0% in
interest rates. Such an increase in interest rates would result in an approximate $237.2 million decrease in fair value of the senior unsecured notes at September 30, 2019. See “Item 1. Financial Statements—Note 6” for more information on our outstanding indebtedness.
a.Evaluation of Disclosure Controls and Procedures
We
carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of EnLink Midstream Manager, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (September 30, 2019), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time period specified in the
applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
b.Changes in Internal Control Over Financial Reporting
Effective January 1, 2019, we adopted ASC 842. The adoption of this accounting standard had no material impact on our operating income, results of operations, financial condition, or cash flows. While the adoption of ASC 842 did not materially affect our internal control over financial reporting, we did implement certain changes to our related lease control activities, including changes to our policies related to leases, training, ongoing lease contract
review requirements, and gathering of information to comply with disclosure requirements. Furthermore, there has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
We
are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations, or cash flows.
Item 1A. Risk Factors
Information about risk factors does not differ materially from that set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018.
Item 2. Unregistered Sales of Equity Securities and Use
of Proceeds
During the three months ended September 30, 2019, we re-acquired ENLC common units from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted incentive units.
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
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, formatted in inline XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, 2019 and December 31, 2018, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, 2019 and 2018, (iii) Consolidated Statements of Changes in Members’
Equity for the three months ended September 30, 2019 and 2018, three months ended June 30, 2019 and 2018, and three months ended March 31, 2019 and 2018, (iv) Consolidated Statements of Cash Flows for the nine months ended September 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).
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.