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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 ☒
The following terms as defined are used in this document:
Defined Term
Definition
/d
Per day.
2014 Plan
ENLC’s 2014 Long-Term Incentive Plan.
ASC
The
FASB Accounting Standards Codification.
ASC 350
ASC 350, Intangibles—Goodwill and Other.
ASC 842
ASC 842, Leases.
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.
Delaware Basin
A large sedimentary basin in West Texas and New Mexico.
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 and the Tiger Plant located
in the Delaware Basin in Texas.
Devon
Devon Energy Corporation.
ENLC
EnLink Midstream, LLC.
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.
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 became a wholly-owned subsidiary of the Operating Partnership.
FASB
Financial Accounting Standards Board.
GAAP
Generally
accepted accounting principles in the United States of America.
Gal
Gallons.
GCF
Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.
General Partner
EnLink Midstream GP, LLC, the general partner of 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.
GP Plan
The General Partner’s Long-Term Incentive Plan.
Gross Operating Margin
Revenue less cost of sales. Gross Operating Margin is 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 additional information.
ISDAs
International
Swaps and Derivatives Association Agreements.
Unit-based awards granted under the GP Plan prior to the Merger. As of the closing of the Merger, Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio from the Merger Agreement as the conversion rate.
No additional awards will be granted under the GP Plan.
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, 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.
OPEC+
Organization of the Petroleum Exporting Countries and its broader partners.
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.
ENLK’s Series B Cumulative Convertible Preferred Units.
Series C Preferred Units
ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
STACK
Sooner Trend Anadarko Basin Canadian and
Kingfisher Counties in Oklahoma.
Term Loan
An $850.0 million term loan entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guarantees.
Thunderbird Plant
A gas processing plant in Central Oklahoma.
Tiger Plant
A
gas processing plant that is under construction in the Delaware Basin and is owned by the Delaware Basin JV.
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.
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
ENLC is a 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.” ENLC owns all of the common units of ENLK, a Delaware limited partnership formed in 2002. EnLink Midstream GP, LLC, a Delaware limited liability company and our wholly-owned subsidiary, is ENLK’s general partner. The General Partner manages ENLK’s operations and activities.
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
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
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.
i
(2)
Significant Accounting Policies
a.iBasis of Presentation
The accompanying consolidated financial statements have been 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, 2019. 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 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.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
The 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 months ended March 31, 2020, we had contractual commitments of $i41.8
million under our MVC contracts and recorded $i11.8 million of revenue due to volume shortfalls.
MVC and Firm Transportation Commitments (in millions) (1)
2020
(remaining)
$
i199.5
2021
i116.7
2022
i103.3
2023
i94.8
2024
i81.3
Thereafter
i158.2
Total
$
i753.8
____________________________
(1)Amounts
do not represent expected shortfall under these commitments.
c.iProperty and Equipment
Impairment Review. In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their
carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.
For the three months ended March 31, 2020, we recognized a $i168.0
million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows. Additionally, we recorded a $i0.4 million impairment related to certain cancelled projects.
d.Redeemable Non-Controlling Interest
Non-controlling interests that contain an option for the
non-controlling interest holder to require us to purchase such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within our control. Redeemable non-controlling interests are not considered to be a component of members’ equity and are reported as temporary equity in the mezzanine section on the consolidated balance sheets. The amount recorded as a redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder’s share of net income or loss and distributions). When the redemption feature is exercised the redemption value of the non-controlling interest is reclassified to a liability on the consolidated balance sheets.
During
the first quarter of 2020, a non-controlling interest holder in one of our non-wholly owned subsidiaries exercised its option to require us to purchase its remaining interest. We have recorded an estimated liability of $i4.0 million related to the redemption of the non-controlling interest on the consolidated balance sheet as of March 31, 2020, but we have not yet agreed to a redemption value with the non-controlling
interest holder.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
e.iAdopted
Accounting Standards
Effective January 1, 2020, we adopted ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350): Internal-Use Software. 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. For the three months ended March 31, 2020, we did not capitalize any cloud computing costs. However, 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 statements of operations, rather than “Depreciation and amortization.”
Effective January 1, 2020, we adopted ASU 2016-13, Financial Instruments—Credit Losses (Topic 326). The updates in ASU 2016-13 provide financial statement users with more
information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Following the adoption of ASU 2016-13, we record an allowance for doubtful accounts based on our expectation of future losses. Because our receivables are typically paid within 30 days, and because we closely monitor the credit-worthiness of all our counterparties, adopting ASU 2016-13 did not have a material effect on our financial statements. However, in the event we foresee further or sustained deterioration in the current market environment, or other factors indicating an increased likelihood of defaults by our customers, we may recognize additional losses.
i
(3)
Goodwill and Intangible Assets
Goodwill
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 cash flow multiples, and estimated future cash flows, including volume and price forecasts, capital expenditures, 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.
i
The
following table represents our change in carrying value of goodwill by segment (in millions):
Goodwill
Impairment Analysis for the three months ended March 31, 2020
During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a quantitative goodwill impairment analysis on the remaining goodwill in the Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of $i184.6
million was recognized as an impairment loss on the consolidated statement of operations for the three months ended March 31, 2020.
Goodwill Impairment Analysis for the three months ended March 31, 2019
During the first quarter of 2019, we recognized a $i186.5 million goodwill impairment
in our Louisiana reporting unit.
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.
The
weighted average amortization period is i15.0 years. Amortization expense was $ii30.9/
million for each of the three months ended March 31, 2020 and 2019, respectively.
i
The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):
2020
(remaining)
$
i92.8
2021
i123.7
2022
i123.7
2023
i123.6
2024
i123.4
Thereafter
i631.8
Total
$
i1,219.0
/
i
(4)
Related Party Transactions
Transactions with Cedar Cove JV. For the three months ended March 31, 2020 and 2019, we recorded cost of sales of $i2.9 million and $i8.1
million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at its Central Oklahoma processing facilities. Additionally, we had accounts payable balances related to transactions with the Cedar Cove JV of $i0.5 million and $i1.1
million at March 31, 2020 and December 31, 2019, 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
i
Lease balances are recorded on the consolidated balance sheets as follows (in millions):
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
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
$
i4,989.5
$
(i5.9)
i4,983.6
$
i4,800.0
$
(i5.9)
i4,794.1
Debt
issuance cost (3)
(i28.8)
(i29.8)
Long-term
debt, net of unamortized issuance cost
$
i4,954.8
$
i4,764.3
____________________________
(1)Bears
interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was i2.4% and i3.3% at March 31,
2020 and December 31, 2019, respectively.
(2)Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was i2.2% and i3.2%
at March 31, 2020 and December 31, 2019, respectively.
The Consolidated Credit Facility permits ENLC to borrow up to $i1.75 billion on a revolving credit basis and includes a $i500.0
million letter of credit subfacility. The Consolidated Credit Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($i550.0 million as of March 31, 2020), and i105%
of the outstanding letters of credit under the Consolidated Credit Facility ($i18.8 million as of March 31, 2020). 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 (LIBOR) 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
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
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 March 31, 2020, we were in compliance with and expect to be in compliance with the financial 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. 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 and the outstanding balance becomes due, 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 March 31, 2020. 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 LIBOR 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 March 31, 2020, we were in compliance with and expect to be in compliance with the financial covenants of the Term Loan for at least the next twelve months.
Senior Unsecured Notes Repurchases
For the three months ended March 31, 2020, ENLK made aggregate payments of $i5.2
million to repurchase $i10.5 million of the 2024, 2025, and 2026 Notes in open market transactions, which resulted in a $i5.3 million gain on
extinguishment of debt.
i
(7) Income Taxes
i
The
components of our income tax benefit (expense) are as follows (in millions):
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
The following schedule reconciles total income tax benefit (expense) and the amount calculated by applying the statutory U.S. federal tax rate to loss before income taxes (in millions):
Expected income tax benefit based on federal statutory rate
$
i67.3
$
i36.7
State
income tax benefit, net of federal benefit
i8.0
i4.4
Non-deductible
expense related to goodwill impairment
(i43.4)
(i43.8)
Other
i1.8
i0.9
Income
tax benefit (expense)
$
i33.7
$
(i1.8)
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 deferred tax assets, net of deferred tax liabilities, are included in “Other assets, net” in the consolidated balance sheets. As of March 31, 2020, we had $i70.1 million of deferred tax assets, net of $i354.8
million of deferred tax liabilities. As of December 31, 2019, we had $i32.2 million of deferred tax assets, net of $i354.0 million of deferred
tax liabilities.
i
(8) Certain Provisions of the ENLK Partnership Agreement
a.ENLK Series B Preferred Units
i
A
summary of the distribution activity relating to the Series B Preferred Units during the three months ended March 31, 2020 and 2019 is provided below:
Declaration period
Distribution paid as additional Series B Preferred Units
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
i
(9)
Members’ Equity
a.Earnings Per Unit and Dilution Computations
As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. 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 March 31, 2020 and 2019, distributed earnings represent a declared distribution of $i0.09375 per unit payable on May 13, 2020 and a distribution of $ii0.279/ per
unit paid on May 14, 2019, respectively.
i
The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):
Notes
to Consolidated Financial Statements (Continued)
(Unaudited)
b.Distributions
i
A summary of our distribution activity relating to the ENLC common units for the three months ended March 31, 2020 and 2019,
respectively, is provided below:
As of March 31, 2020, our unconsolidated investments consisted of a i38.75% ownership in GCF and a i30%
ownership in the Cedar Cove JV. iThe following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
The
following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2020 and December 31, 2019 (in millions):
We account for unit-based compensation in accordance with ASC 718, which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to directors, officers, and
Cost
of unit-based compensation charged to operating expense
$
i2.2
$
i0.3
Cost
of unit-based compensation charged to general and administrative expense
i6.6
i10.8
Total
unit-based compensation expense
$
i8.8
$
i11.1
Non-controlling
interest in unit-based compensation
$
i—
$
i0.5
Amount
of related income tax benefit recognized in net loss
$
i2.1
$
i2.5
b.ENLC
Restricted Incentive Units
i
ENLC restricted incentive units were 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 three months ended March 31, 2020 is provided below:
Aggregate
intrinsic value, end of period (in millions)
$
i7.2
____________________________
(1)Restricted
incentive units typically vest at the end of three years. In February 2020, ENLC granted i1,144,842 restricted incentive units with a fair value of $i5.2
million to officers and certain employees as bonus payments for 2019, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
/
(2)Vested units included i732,473 units withheld for payroll
taxes paid on behalf of employees.
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 months ended March 31, 2020 and 2019 is provided below (in millions):
Three
Months Ended March 31,
ENLC Restricted Incentive Units:
2020
2019
Aggregate intrinsic value of units vested
$
i10.1
$
i12.4
Fair
value of units vested
$
i18.9
$
i12.6
/
As
of March 31, 2020, there was $i37.3 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. This cost is expected to be recognized over a weighted-average period of i1.9
years.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
c.ENLC 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 such 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.
i
The following table presents a summary of the performance units:
Aggregate
intrinsic value, end of period (in millions)
$
i2.6
____________________________
(1)Vested
units included i60,920 units withheld for payroll taxes paid on behalf of employees.
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 months ended March 31, 2020 and 2019 is provided below (in
millions).
Three Months Ended March 31,
ENLC Performance Units:
2020
2019
Aggregate
intrinsic value of units vested
$
i0.9
$
i1.8
Fair
value of units vested
$
i5.0
$
i1.9
/
As
of March 31, 2020, there was $i16.8 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 i1.8
years.
i
The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:
ENLC Performance Units:
January
2020
March 2020
Grant-Date Fair Value
$
i7.69
$
i1.13
Beginning
TSR price
$
i6.13
$
i1.25
Risk-free
interest rate
i1.62
%
i0.42
%
Volatility
factor
i37.00
%
i51.00
%
/
d.ENLK
Restricted Incentive Units
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 months ended March 31, 2019 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.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
e.ENLK Performance Units
A summary of the performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 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.
i
Three
Months Ended March 31,
ENLK Performance Units:
2019
Aggregate intrinsic value of units vested
$
i2.1
Fair
value of units vested
$
i1.7
/
i
(12)
Derivatives
Interest Rate Swaps
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 i2.28%
in exchange for LIBOR-based variable interest through December 2021. There was no ineffectiveness related to this hedge.
For the three months ended March 31, 2020, we recorded $i13.1 million, net of a tax benefit of $i4.0
million, into accumulated other comprehensive loss related to changes in fair value of our interest rate swaps.
For the three months ended March 31, 2020, we realized a loss of $i1.3 million related to the monthly settlements of our interest rate swaps, which we recorded into interest expense, net of interest income from accumulated
other comprehensive loss. We expect to recognize an additional $i16.3 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 related to commodity swaps that we held for price risk management purposes and the related physical offsets at March 31, 2020 (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 commodity swap contracts, the maximum loss on our gross receivable position of $i83.2
million as of March 31, 2020 would be reduced to $i21.4 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.
i
(13)
Fair Value Measurements
i
Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
(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.
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
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 is reduced by debt issuance costs of $i28.8 million and $i29.8 million as of March 31, 2020 and December 31,
2019, respectively. The respective fair values do not factor in debt issuance costs.
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.
The fair values of all senior unsecured notes as of March 31, 2020 and December 31, 2019 were based on Level 2 inputs from third-party market quotations.
i
(14)
Segment Information
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)
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 loss as reported on the consolidated statements of operations (in millions):
Current Market Environment. On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the energy industry as a whole and midstream companies, and on our employees, customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a significant reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for crude oil has dropped by nearly one-third since mid-February. The decline
in demand has been met with a decline in the market price for these commodities, particularly for crude oil, and especially following the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire. On April 12, 2020, members of OPEC+ agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for oil and significantly higher costs for available storage. In the case of the oil markets, both the decline in demand and storage concerns have caused the price of oil to reach
historic lows.
As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity, and an uncertain timeline for recovery, oil and natural gas producers, including our customers, have sharply curtailed their current drilling and production
Notes to Consolidated Financial Statements (Continued)
(Unaudited)
activity
as well as their plans for future drilling and production activity. As a result of these decreases in activity, our business and financial results, and those of others in our industry, have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets as a result of reduced production from the regions that supply our systems. We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, or cash flows (including our ability to make distributions to our unitholders) at this time, due to numerous uncertainties. The ultimate impacts will depend on future
developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak and the governmental measures designed to contain the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, the availability of oil storage capacity, and the timing and extent to which normal economic and operating conditions resume.
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.
Overview
ENLC is a Delaware limited liability company formed in October 2013. ENLC’s assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. 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 290,000 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 89% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the three months ended March 31, 2020. 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 months ended March 31, 2020 and 2019, approximately 33.4% and 30.0% 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 Affecting Industry Conditions and Our Business
On March 11, 2020, the World Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, the energy industry as a whole and midstream companies,
and on our employees, customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a significant reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for oil has dropped by nearly one-third since mid-February. The decline in demand has been met with a decline in the market price for these commodities, particularly for crude oil, and especially following the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire on April 1, 2020, and the ensuing expiration thereof. On April 12, 2020, members of OPEC+
agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for oil and significantly higher costs for available storage. In the case of the oil markets, both the decline in demand and storage concerns have caused the price of oil to reach historic lows.
As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity, and an uncertain timeline for recovery, oil and natural gas producers, including our customers, have sharply curtailed their current drilling and production activity as well as their plans for future drilling and production activity. This reduction in
production has been most acute for crude oil production, but because condensate production and a significant portion of gas and NGL production depends on, or is a byproduct of, the production of crude oil, the curtailment of crude oil drilling and production affects the production of these other commodities. As a result of these decreases in producer activity, our business and financial results, and those of others in our industry, have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets as a result of reduced production from the regions that supply our systems. Our first priority in our response to this crisis has been the health and safety of our employees and those of our customers and other business counterparties.
We have implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a cross-functional COVID-19 response team to address various impacts of the situation, as they have been developing. We also have modified certain business practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employees who can execute their work remotely, and encouraging employees to adhere to local and regional social distancing recommendations) to support efforts to reduce the spread of COVID-19 and to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization, and other governmental and regulatory authorities. We
also have promoted heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and operations.
There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how significantly and how long they will continue to affect us. We expect to see continued volatility in crude oil, condensate, natural gas, and NGL prices for the foreseeable future, which may, over the long term, adversely impact our business. A sustained significant decline
in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for oil, condensate natural gas and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders).
As of the date of this report, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded results. Our systems, pipelines, and facilities have remained operational. We have also moved quickly and decisively to implement strategies to reduce costs, increase operational efficiencies, and lower our capital spending. As we previously announced, we intend to reduce our capital expenditures
in 2020, including both growth and maintenance capital expenditures, to between $190 million and $250 million, a 65% reduction from 2019 total capital spending. We have also reduced costs across our platform and we intend to reduce our general and administrative and operational expenses by $100 million for the full-year 2020 versus the twelve months ended December 31, 2019. In addition, we maintain
our previously announced plan to fully self-fund all capital expenditures during 2020 with internally generated cash flows, and have no plans to access the capital markets during 2020. Also, as of March
31, 2020, we had approximately $258 million of cash on our balance sheet and have drawn only approximately $550 million on our $1.75 billion ENLC Credit Facility. We have not requested any funding under any federal or other governmental programs to support our operations, and we do not expect to utilize any such funding. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented.
We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to unitholders)
at this time due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, and the governmental measures designed to contain the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, the availability of oil storage capacity, and the timing and extent to which normal economic and operating conditions resume.
We have revised our forecasts and as a result have recorded impairments of goodwill and property and equipment during the three months ended March
31, 2020. We will continue to monitor the market environment and will evaluate whether additional triggering events would indicate possible impairments of property and equipment and intangible assets.
For additional discussion regarding risks associated with the COVID-19 pandemic, see Part II, Item 1A “Risk Factors” in this report.
Other Recent Developments
Riptide Processing Plant. In March 2020, we completed construction of a 55 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 220 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
To assist management in assessing our business, we use 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”), excess free cash flow, and gross operating margin.
Adjusted
EBITDA
We define adjusted EBITDA as net loss plus interest expense, net of interest income; income tax expense (benefit); depreciation and amortization; impairments; distributions from unconsolidated affiliates; unit-based compensation; transaction costs; unrealized (gain) loss on commodity swaps; and accretion expense associated with asset retirement obligations; less gain on disposition of assets; gain on extinguishment of debt; income from unconsolidated affiliates; payments under onerous performance obligation; non-cash rent; and non-controlling interest share of adjusted EBITDA from joint ventures. 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, net of interest income; income tax expense (benefit); and depreciation and amortization. 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 loss (in millions):
Payments under onerous performance obligation offset to other current and long-term liabilities
—
(4.5)
Transaction
costs (1)
—
13.5
Other (2)
(0.7)
0.3
Adjusted EBITDA before non-controlling interest
267.2
274.8
Non-controlling
interest share of adjusted EBITDA from joint ventures (3)
(7.2)
(6.6)
Adjusted EBITDA, net to ENLC
$
260.0
$
268.2
____________________________
(1)Represents
transaction costs attributable to costs incurred related to the Merger in January 2019.
(2)Includes accretion expense associated with asset retirement obligations, gain on disposition of assets, and non-cash rent, which relates to lease incentives pro-rated over the lease term.
(3)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.
Distributable Cash Flow and Excess Free Cash Flow
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 Series B Preferred Units and 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. Excess free cash flow is defined as distributable cash flow less distributions declared on common units and growth capital expenditures, excluding growth capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated joint ventures.
Distributable cash flow and excess free cash flow are used as supplemental liquidity measures 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, make cash distributions, and make capital expenditures.
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.
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.
The GAAP measure most directly comparable to distributable cash flow
and excess free cash flow is net cash provided by operating activities. Distributable cash flow and excess free cash flow should not be considered alternatives 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 and excess free cash flow have important limitations because they exclude some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Distributable cash flow and excess free cash flow may not be comparable to similarly titled measures of other companies because other companies may not calculate these non-GAAP metrics 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 and excess free cash flow, to evaluate
our overall liquidity.
The following table reconciles excess free cash flow, distributable cash flow, and adjusted EBITDA to net cash provided by operating activities (in millions):
Changes in operating
assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other
(169.3)
(97.4)
Accounts payable,
accrued product purchases, and other accrued liabilities (4)
193.9
45.7
Adjusted EBITDA before non-controlling interest
267.2
274.8
Non-controlling
interest share of adjusted EBITDA from joint ventures (5)
(7.2)
(6.6)
Adjusted EBITDA, net to ENLC
260.0
268.2
Interest
expense, net of interest income
(i55.6)
(49.6)
Maintenance capital expenditures, net to ENLC (6)
(8.2)
(8.5)
ENLK
preferred unit accrued cash distributions (7)
(22.8)
(22.7)
Other (8)
(0.3)
(2.5)
Distributable
cash flow
173.1
184.9
Common distributions declared
(46.5)
(137.3)
Growth
capital expenditures, net to ENLC (6)
(82.6)
(219.6)
Excess free cash flow
$
44.0
$
(172.0)
____________________________
(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 attributable to costs incurred related to the Merger in January 2019.
(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 during the three months
ended March 31, 2019.
(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 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 Series B Preferred Units and Series C Preferred Units of $16.8 million and $6.0 million, respectively, for the three months ended March 31,
2020, and cash distributions earned by the Series B Preferred Units and Series C Preferred Units of $16.7 million and $6.0 million, respectively, for the three months ended March 31, 2019. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.
(8)Includes non-cash interest income and current income tax expense.
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 loss 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 $400.8 million for the three months ended March 31, 2020 compared to $415.8 million for the three months ended March 31, 2019, a decrease of $15.0 million, or 3.6%, due to the following:
•Permian Segment. Gross operating margin in the Permian segment decreased $8.6 million, resulting from (i) a $7.6 million decrease in gross operating margin
from our Permian crude assets with a $3.8 million decrease due to declines in crude oil prices and $3.8 million of that decrease due to the expiration of an MVC related to our South Texas assets in July 2019, and (ii) a $1.0 million decrease in gross operating margin from our Permian gas assets due to a $2.3 million decrease in gross operating margin related to our Midland Basin assets offset by a $1.3 million increase in gross operating margin related to our Delaware Basin assets.
•North Texas Segment. Gross operating margin in the North Texas segment decreased $6.9 million, which was primarily due to volume declines resulting from limited new drilling in the region.
•Oklahoma Segment. Gross operating margin
in the Oklahoma segment decreased $9.2 million. Gross operating margin contributed by our Oklahoma gas assets decreased $10.1 million, which was partially due to lower volumes from our existing customers, and was partially offset by a $0.9 million increase in gross operating margin contributed by our Oklahoma crude assets.
•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $7.7 million, resulting from (i) a $4.0 million decrease in gross operating margin from our Louisiana gas plants due to lower processing margins and volumes attributable to a less favorable processing environment, and (ii) a $3.7 million decrease in gross operating margin from our Louisiana gas transmission assets due to the expiration of certain firm transportation contracts
and decreased volumes. While gross operating margin related to our ORV crude assets decreased $1.8 million, primarily due to lower volumes, this decrease was partially offset by an increase of $1.8 million in gross operating margin from our NGL transmission and fractionation assets, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion in April 2019.
•Corporate Segment. Gross operating margin in the Corporate segment increased $17.4 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
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 $100.7 million for the three months ended March 31, 2020 compared to $114.5 million for the three months ended March 31, 2019, a decrease of $13.8 million, or 12.1%. The primary contributors to the total decrease by segment were as follows (in millions):
Three
Months Ended March 31,
Change
2020
2019
$
%
Permian Segment
$
25.5
$
27.8
$
(2.3)
(8.3)
%
North
Texas Segment
20.5
25.7
(5.2)
(20.2)
%
Oklahoma Segment
22.9
25.4
(2.5)
(9.8)
%
Louisiana
Segment
31.8
35.6
(3.8)
(10.7)
%
Total
$
100.7
$
114.5
$
(13.8)
(12.1)
%
•Permian
Segment. Operating expenses in the Permian segment decreased $2.3 million primarily due to reductions in materials and supplies expenses.
•North Texas Segment. Operating expenses in the North Texas segment decreased $5.2 million primarily due to reductions in materials and supplies expenses, construction fees and services, and vehicle rentals.
•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $2.5 million primarily due to reductions in compressor operations and maintenance, materials and supplies expenses, construction fees and services, and vehicle rentals.
•Louisiana
Segment. Operating expenses in the Louisiana segment decreased $3.8 million primarily due to reductions in labor and benefits costs, materials and supplies expenses, construction fees and services, and vehicle rentals.
Operating expenses for the three months ended March 31, 2020 included $3.3 million of severance costs related to a reduction in workforce.
General and Administrative Expenses. General and administrative expenses were $30.4 million for the three months ended March 31, 2020 compared to $51.4 million for the three months ended March 31,
2019, a decrease of $21.0 million, or 40.9%. The primary contributors to the decrease were as follows:
•Transaction costs decreased $13.5 million, which was primarily due to higher transaction costs related to the Merger that were incurred during the first quarter of 2019.
•Unit-based compensation expense decreased $4.2 million, which was primarily due to larger awards and lower forfeitures during the first quarter of 2019 as compared to the first quarter of 2020.
•Benefits
and payroll taxes decreased $1.2 million, which was primarily due to a reduction in costs related to employee benefits.
General and administrative expenses for the three months ended March 31, 2020 included $2.6 million of severance costs related to a reduction in workforce.
Depreciation and Amortization. Depreciation and amortization was $162.8 million for the three months ended March 31, 2020 compared to $152.1 million for the three months ended March 31, 2019, an increase of $10.7 million, or 7.0%. This increase was primarily
due to accelerated depreciation in the North Texas and Oklahoma segments on certain non-core assets based on changes in their estimated useful lives and new assets placed into service in key growth areas, including 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. These increases were partially offset by retirements of certain non-core assets in the Louisiana segment during the first quarter of 2019.
Impairments. For the three months ended March 31, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash
flows. Additionally, we recorded a $0.4 million impairment related to certain cancelled projects. See “Item 1. Financial Statements—Note 2” for additional information on our property and equipment impairments.
During the three months ended March 31, 2020, we recognized a goodwill impairment of $184.6 million related to our Permian segment. During the three months ended March 31, 2019, we recognized a goodwill impairment of $186.5 million related to our Louisiana segment. See “Item 1. Financial Statements—Note 3” for additional information on our goodwill impairments.
Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $5.3 million for
the three months ended March 31, 2020 due to repurchases of the 2024, 2025, and 2026 Notes in open market transactions. See “Item 1. Financial Statements—Note 6” for additional information.
Interest Expense. Interest expense was $55.6 million for the three months ended March 31, 2020 compared to $49.6 million for the three months ended March 31, 2019, an increase of $6.0 million, or 12.1%. Interest expense consisted of the following (in millions):
Amortization of debt issue costs and net discounts
(premiums)
1.0
1.8
Other
1.3
(1.2)
Total
$
55.6
$
49.6
Income
Tax Expense. Income tax benefit was $33.7 million for the three months ended March 31, 2020 compared to an income tax expense of $1.8 million for the three months ended March 31, 2019, a decrease in income tax expense of $35.5 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 $26.4 million for the three months ended March 31, 2020 compared to net income of $41.5 million for the three months ended March 31,
2019, a decrease of $15.1 million. This decrease was primarily due to the conversion of ENLK common units into ENLC common units as a result of the Merger in the first quarter of 2019. 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.
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, 2019, except as described below.
Property and Equipment
Impairment Review. In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent
management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs.
During March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. For the three months ended March 31, 2020, we recognized a $168.0 million impairment on property and equipment related to a portion of our Louisiana reporting segment because the carrying amounts were not recoverable based on our expected
future cash flows. Additionally, we recorded a $0.4 million impairment related to certain cancelled projects.
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.
During
March 2020, we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a quantitative goodwill impairment analysis on the remaining goodwill in the Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of $184.6 million was recognized as an impairment loss on the consolidated statement of operations for the three months ended March 31, 2020.
Liquidity
and Capital Resources
Cash Flows from Operating Activities. Net cash provided by operating activities was $182.0 million for the three months ended March 31, 2020 compared to $264.0 million for the three months ended March 31, 2019. 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 $10.2 million for the three months ended March 31, 2020 compared to the three months ended
March 31, 2019. The primary contributors to the decrease in operating cash flows were as follows:
These changes to operating cash flows were offset by the following:
•General
and administrative expenses excluding unit-based compensation decreased $17.0 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 decreased $15.7 million primarily due to a reduction in operations. For more information, see “Results of Operations.”
The changes in working capital for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 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 $115.5 million for the three months ended March 31, 2020, compared to $241.0 million for the three months ended March 31, 2019. Investing cash flows are primarily related to capital expenditures. Capital expenditures decreased from $241.5 million for the three months ended March 31, 2019 to $112.0 million for the three months ended March 31, 2020. The decrease was primarily due to reduced capital
spending plans for 2020.
Cash Flows from Financing Activities. Net cash provided by financing activities was $114.2 million for the three months ended March 31, 2020 and net cash used in financing activities was $122.7 million for the three months ended March 31, 2019. Our primary financing activities consisted of the following (in millions):
Distributions to ENLK common units held by public unitholders (2)
—
(104.8)
Distributions
to Series B Preferred Unitholders (3)
(16.8)
(16.5)
Distributions to joint venture partners (4)
(7.9)
(6.3)
____________________________
(1)Represents
contributions from NGP to the Delaware Basin JV.
(2)Subsequent to the closing of the Merger, ENLK no longer has publicly held common units.
(3)See “Item 1. Financial Statements—Note 8” for information on distributions to holders of the Series B Preferred Units.
(4)Represents distributions to NGP for its ownership in the Delaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other minor non-controlling interests.
Capital Requirements. We expect our remaining 2020 capital expenditures,
including capital contributions to our unconsolidated affiliate investments, to be approximately $100 million to $160 million, which is net of approximately $10 million to $40 million from our joint venture partners. Our primary capital projects for the remainder of 2020 include the 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 capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. In 2020, 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. We had no off-balance sheet arrangements as of March 31, 2020.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations
as of March 31, 2020 is as follows (in millions):
Payments Due by Period
Total
Remainder
2020
2021
2022
2023
2024
Thereafter
Long-term debt obligations
$
3,589.5
$
—
$
—
$
—
$
—
$
545.0
$
3,044.5
Term
Loan
850.0
—
850.0
—
—
—
—
Consolidated Credit
Facility
550.0
—
—
—
—
550.0
—
Interest payable
on fixed long-term debt obligations
2,499.7
163.6
175.6
175.6
175.6
163.6
1,645.7
Operating
lease obligations
133.9
16.3
17.0
12.2
10.2
9.5
68.7
Purchase
obligations
18.5
18.5
—
—
—
—
—
Pipeline and trucking
capacity and deficiency agreements (1)
196.0
29.5
37.7
31.8
28.1
33.0
35.9
Inactive
easement commitment (2)
10.0
—
—
10.0
—
—
—
Total
contractual obligations
$
7,847.6
$
227.9
$
1,080.3
$
229.6
$
213.9
$
1,301.1
$
4,794.8
____________________________
(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 that is not already disclosed in the table above.
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 2020 are expected to be funded from cash flows generated from our operations.
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. As of March 31, 2020,
there was $550.0 million in outstanding borrowings under the Consolidated Credit Facility and $18.8 million in outstanding letters of credit.
In addition, as of March 31, 2020, we have $3.6 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047 and $850.0 million in outstanding principal on the Term Loan.
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 within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein
involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. 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 forward-looking statements include, but are not limited to, statements about when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial metrics, operating efficiencies and other benefits of cost savings
or operational initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic on us and our financial results and operations, and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operation, or cash flows, include, without limitation,(a) the ongoing coronavirus (COVID-19) outbreak could adversely affect our business, financial condition, and results of operation, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP’s own interests to the detriment of our unitholders, (c) GIP’s ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or businesses, (d) a default under GIP’s credit facility could result in a change in control
of us, could adversely affect the price of our common units, and could result in a default under our credit facility, (e) the dependence on Devon for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect Devon or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) construction risks in our major development projects, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production
by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, and (t) the effects of existing and future laws and governmental regulations,
including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and 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, 2019 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 new rules in January 2020 (withdrawing previously proposed rules from November 2013 and December 2016) 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 potential 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 to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
Commodity
Price Risk
We are subject to risks due to fluctuations in commodity prices. Approximately 89% of our gross operating margin for the three months ended March 31, 2020 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 three months ended March 31, 2020, 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 three months ended March 31, 2020, approximately 4% 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, and crude oil volumes produced for our account. We have tailored our hedges to generally match the product composition and the delivery points to those of our physical equity volumes. The hedges cover specific products based upon our expected equity composition.
The following table sets forth certain information related to derivative instruments outstanding at March 31, 2020 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)
Net Fair Value Asset/(Liability) (In millions)
April 2020 - March 2021
Ethane
2,017 (MBbls)
$0.1365/gal
Index
$
0.2
April
2020 - March 2021
Propane
1,397 (MBbls)
Index
$0.3162/gal
6.0
April 2020 - March 2021
Normal butane
458 (MBbls)
Index
$0.3455/gal
2.2
April
2020 - December 2020
Natural gasoline
30 (MBbls)
Index
$0.4318/gal
0.2
April 2020 - January 2021
Natural gas
95,855 (MMBtu/d)
Index
$1.2207/MMBtu
—
April
2020 - July 2020
Crude and condensate
4,275 (MBbls)
Index
$23.92/Bbl
0.1
April 2020 - December 2022
Crude and condensate
10,970 (MBbls)
$1.928/Bbl
Index
(2)
12.7
$
21.4
____________________________
(1)Weighted average.
(2)Represents the WTI Houston and WTI Midland differential.
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 March 31, 2020, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments had a net fair value asset of $21.4 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 $5.5 million in the net fair value of these contracts as of March 31, 2020.
Interest
Rate Risk
We are exposed to interest rate risk on the Consolidated Credit Facility and the Term Loan. At March 31, 2020, we had $550.0 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 $5.5 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 notes due in 2029 as these are fixed-rate obligations. As of March 31, 2020, the estimated fair value of the senior unsecured notes was approximately $1,621.6 million, based on the market prices of ENLK’s and our publicly traded debt at March 31, 2020. 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 $79.3 million decrease in fair value of the senior unsecured notes at March 31, 2020. See “Item 1. Financial Statements—Note 6” for more information on our outstanding indebtedness.
Item 4. Controls and Procedures
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 (March 31, 2020), 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
There has been no change in our internal control over financial reporting that occurred in the three months ended March 31, 2020 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
Except as set forth below, 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,
2019.
The ongoing coronavirus (COVID-19) outbreak could adversely affect our business, financial condition, and results of operations.
The ongoing coronavirus (COVID-19) outbreak, which the World Health Organization declared as a pandemic on March 11, 2020, has reached more than 200 countries and has continued to be a rapidly evolving situation. The pandemic has resulted in widespread adverse impacts on the global economy, the energy industry as a whole and on midstream companies, and on our employees, customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a significant
reduction in global demand for crude oil, condensate, natural gas, and NGLs. For example, global demand for oil has dropped by nearly one-third since mid-February. The decline in demand has been met with a decline in the market price for these commodities, particularly for crude oil, and especially following the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity, as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire. On April 12, 2020, members of OPEC+ agreed to certain production cuts; however, these cuts are not expected to be enough to offset near-term demand loss attributable to the COVID-19 pandemic. In addition, crude oil stockpiles and the decision of end users, such as refineries, not to take a normal level of crude oil shipments has led to a severe and growing shortage of storage capacity for
oil and significantly higher costs for available storage. In the case of the oil markets, both the decline in demand and storage concerns have caused the price of oil to reach historic lows.
As a result of the supply/demand imbalance, reduced commodity prices, limited storage capacity and an uncertain timeline for recovery, oil and gas producers, including our customers, have sharply curtailed their current drilling and production activity as well as their plans for future drilling and production activity. As a result of these decreases in producer activity, our business and financial results have been adversely affected and will likely continue to be adversely affected until the markets for these commodities recover and producers elect to expand their production activities. For example, since mid-March, we have experienced reduced volumes gathered, processed, fractionated, and transported
on our assets as a result of reduced production from the regions that supply our systems. In addition, available storage for crude oil is expected to be increasingly limited and costly for the foreseeable future, which would also have a negative impact on our customers’ ability to store crude oil during this period of reduced demand. If our producer customers are unable to store crude oil at reasonable prices, or the market prices our customers receive for their production stays at low levels for a prolonged period or declines even further, our customers could reduce their production levels or shut-in producing wells until storage is available and/or market prices recover. Consequently, our future business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders) could be materially and adversely affected.
There
is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how long they will continue to affect us.
We have modified certain business and workforce practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employees who can execute their work remotely, and encouraging employees to adhere to local and regional social distancing recommendations) to conform to government restrictions and best practices encouraged by governmental and
regulatory authorities. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. Also, we have a limited number of highly skilled employees for some of our operations. If a large proportion of our employees in those critical positions were to contract COVID-19 at the same time, we would rely upon our business continuity plans in an effort to continue operations at our systems, pipelines, and facilities, but there is no certainty that such measures will be sufficient to mitigate the adverse impact to our operations that could result from shortages of highly skilled employees.
Although we do not have plans to access the capital markets in 2020, to the extent that we need to seek external funding for our operations and COVID-19 adversely affects our ability to access the capital and other financial markets, as a result of credit rating downgrades or otherwise, we may need to consider alternative sources of funding for some of our operations and for working capital, which may increase our cost of, as well as adversely impact our access to, capital. These uncertain economic conditions may also result in the inability of our customers and other counterparties to make payments to us, on a timely basis or at all, which could adversely affect our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders and noteholders). A substantial deterioration in our business and/or a prolonged period of market
dislocation could also affect our compliance with the financial covenants in our Consolidated Credit Facility, particularly the consolidated leverage ratio covenant. The leverage ratio covenant requires that we maintain a leverage ratio of no more than 5.0x at the end of any fiscal quarter. At March 31, 2020, our ratio was 4.6x. If we were unable to continue to meet any of the financial covenants, we would not be able to borrow funds under our Consolidated Credit Facility and we would not be able to use the Consolidated Credit Facility to refinance our $850 million Term Loan in 2021.
We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including
our ability to make distributions to our unitholders) at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus or its affects, the development of effective treatments, the duration of the outbreak, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume and whether the virus causes structural shifts in the global economy and the demand for oil and natural gas as a result of changes in the way people work, travel, and interact.
Item
2. Unregistered Sales of Equity Securities and Use of Proceeds
During the three months ended March 31, 2020, 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 March 31, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of March 31, 2020 and December 31, 2019, (ii) Consolidated Statements of Operations for the three months ended March 31, 2020 and 2019, (iii) Consolidated Statements of Changes in Members’ Equity for the three
months ended March 31, 2020 and 2019 (iv) Consolidated Statements of Cash Flows for the three months ended March 31, 2020 and 2019, and (v) the Notes to Consolidated Financial Statements.
104 *
—
Cover Page Interactive Data File (formatted as Inline iXBRL and included 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.
