ENLINK MIDSTREAM, LLC 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 toEnLink Midstream, LLC itself orEnLink 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 toEnLink Midstream Partners, LP itself orEnLink Midstream Partners, LP together with its consolidated subsidiaries, including theOperating Partnership .
Overview
ENLC is aDelaware limited liability company formed inOctober 2013 . ENLC's material 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, 23 natural gas processing plants with approximately 5.5 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. Starting in the first quarter of 2021, we began evaluating the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian,Louisiana ,Oklahoma , andNorth Texas segments. Commodity swaps activity was previously reported in the Corporate segment. We have recast segment information for all presented periods prior to the first quarter of 2021 to conform to current period presentation. Identification of the majority of our operating segments is based principally upon geographic regions served:
•Permian Segment. The Permian segment includes our natural gas gathering,
processing, and transmission activities and our crude oil operations in the
Midland and Delaware Basins in
•Louisiana Segment. TheLouisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located inLouisiana and our crude oil operations in ORV; •Oklahoma Segment. TheOklahoma 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;
•North Texas Segment. The
•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV inOklahoma , our ownership interest in GCF inSouth Texas , and our general corporate assets and expenses. We manage our consolidated operations by focusing on adjusted gross 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 30 -------------------------------------------------------------------------------- Table of Contents 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. Adjusted gross margin is a non-GAAP financial measure and is explained in greater detail under "Non-GAAP Financial Measures" below. Approximately 87% of our adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the six months endedJune 30, 2021 .
Our revenues and adjusted gross 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.
The following customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results of operations because the revenues and adjusted gross margin received from transactions with these customers is material to us.
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Devon 7.6 % 17.7 % 7.3 % 15.0 %
Dow Hydrocarbons and Resources LLC 15.2 % 13.5 % 14.9 % 12.3 %
Marathon Petroleum Corporation 12.8 % 10.3 % 13.8 % 14.8 %
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 adjusted gross 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 adjusted gross margins from our gathering and processing services
primarily through different contractual arrangements: processing margin
("margin") contracts, POL contracts, POP contracts, fixed-fee based contracts,
or a
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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
adjusted gross margins are higher during periods of high NGL prices relative to
natural gas prices. Adjusted gross margin results under POL contracts are
impacted only by the value of the liquids produced with margins higher during
periods of higher liquids prices. Adjusted gross 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 adjusted gross 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
Current Market Environment
The midstream energy business environment and our business are affected by the level of production of natural gas and oil in the areas in which we operate and the various factors that affect this production, including commodity prices, capital markets trends, competition, and regulatory changes. We believe these factors will continue to affect production and therefore the demand for midstream services and our business in the future. To the extent these factors vary from our underlying assumptions, our business and actual results could vary materially from market expectations and from the assumptions discussed in this section. Production levels by our exploration and production customers are driven in large part by the level of oil and natural gas prices. New drilling activity is necessary to maintain or increase production levels as oil and natural gas wells experience production declines over time. New drilling activity generally moves in the same direction as crude oil and natural gas prices as those prices drive investment returns and cash flow available for reinvestment by exploration and production companies. Accordingly, our operations are affected by the level of crude, natural gas, and NGL prices, the relationship among these prices, and related activity levels from our customers. There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. During 2020, the COVID-19 pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, led to a reduction in global demand for energy, volatility in the market prices for crude oil, condensate, natural gas, and NGLs, and a significant reduction in the market price of crude oil during the first half of 2020. Although commodity markets have in large part recovered, oil and natural gas commodity prices remain somewhat weak relative to historical levels and continue to remain volatile. Capital markets and the demands of public investors also affect producer behavior, production levels, and our business. Over the last several years, public investors have exerted pressure on oil and natural gas producers to increase capital discipline and focus on higher investment returns even if it means lower growth. In addition, the ability of companies in the oil and gas industry to access the capital markets on favorable terms has been somewhat negatively impacted. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, has led to more modest capital investment by producers, curtailed drilling and production activity, and, accordingly, slower growth for us and other midstream companies during the past few years. This trend was amplified in 2020 as a result of the COVID-19 pandemic demand destruction. Although volumes have now generally recovered to pre-pandemic levels, global capital investments by oil and natural gas producers remain at low levels compared to historical levels and producers remain cautious. Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In the last few years, many producers have increasingly focused their activities in thePermian Basin , because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating inthe United States are operating in thePermian Basin . As a result of this concentration of drilling activity in the Permian, other basins, including those in which we operate inOklahoma andNorth Texas , have experienced reduced incremental new investment and declines in volumes produced. In contrast, we continue to experience an increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity. 32 -------------------------------------------------------------------------------- Table of Contents OurLouisiana segment, while subject to commodity prices and capital markets developments, is less dependent on gathering and processing activities and more affected by industrial demand for the natural gas and NGLs that we supply. Industrial demand along theGulf Coast region has remained strong from the second half of 2020 and through the first half of 2021, supported by regional industrial activity and export markets. Our activities and, in turn, our financial performance in theLouisiana segment are highly dependent on the availability of natural gas and NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to supply our customers, and maintaining such supply is a key business focus.
For additional discussion regarding these factors, see "Item 1A-Risk
Factors-Business and Industry Risks" in our Annual Report on Form 10-K filed
with the Commission on
Winter Storm Uri
InFebruary 2021 , the areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days ("Winter Storm Uri"). Winter Storm Uri adversely affected the Company's facilities and activities across the Company's footprint, as it did for producers and other midstream companies located in these areas. The severe cold temperatures caused production freeze-offs and also led some producers to proactively shut-in their wells to preserve well integrity. As a result, the Company's gathering and processing volumes were significantly reduced during this period, with peak volume declines ranging between 44% and 92%, depending on the region. The Company responded to the challenges presented by the storm by taking active steps to ensure the resiliency of the Company's assets and the protection of the health and well-being of its employees. The Company's operations and its gathering and processing volumes returned to normal levels by the end of the first quarter of 2021. The lack of gathered and processed volumes during Winter Storm Uri presented a number of commercial challenges, including the management of losses on derivative contracts and firm commodity sales contracts and making outlays to meet one-time operating expenses for storm recovery. To balance these challenges, the Company was able to use its integrated asset base to make limited incremental gas available to support local markets and to use its storage volumes inLouisiana to help offset lower natural gas and NGL supplies. Additionally, because of idled operations and elevated power prices, the Company was able to earn approximately$49 million in utility credits for unused electricity which had been purchased on a firm basis. These utility credits can be used to offset future power payments. However, because of the magnitude and unprecedented nature of the storm, we cannot predict the full impact that Winter Storm Uri may have on our future results of operations. The ultimate impacts will depend on future developments, including, among other factors, the outcome of pending billing disputes with customers and regulatory actions by state legislatures and other entities responsible for the regulation and pricing of electricity and the electrical grid.
COVID-19 Update
OnMarch 11, 2020 , theWorld Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. Beginning inMarch 2020 , we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers' operations, and we continue to follow these plans. We also continue to promote heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and operations and we continue to evaluate and adjust our preventative measures, response plans, and business practices with the evolving impacts of COVID-19. We have continued to maintain these COVID protocols since the inception of the pandemic and to date we have not experienced any COVID-19 related operational disruptions. There is considerable uncertainty regarding how long the COVID-19 pandemic will persist and affect economic conditions and the extent and duration of changes in consumer behavior. We cannot predict the full impact that the COVID-19 pandemic or the volatility in oil and natural gas markets related to COVID-19 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 duration and persistence of the pandemic, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the impact of the emergence of any new variants of the virus against which vaccines are less effective, the effect of the pandemic on economic, social, and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of 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, and the timing and extent to which normal economic, social, and operating conditions resume. A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our 33
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Table of Contents services by our customers, whether due to decreases in consumer demand or reduction in the prices for crude 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).
For additional discussion regarding risks associated with the COVID-19 pandemic, see "Item 1A-Risk Factors-The ongoing coronavirus (COVID-19) pandemic has adversely affected and could continue to adversely affect our business, financial condition, and results of operations" in our Annual Report on Form 10-K filed with the Commission onFebruary 17, 2021 .
Regulatory Developments
OnJanuary 20, 2021 , theBiden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers. On his first day in office,President Biden signed an instrument reenteringthe United States into the Paris Agreement, effectiveFebruary 19, 2021 , and issued an executive order on "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis" seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind prior agency actions that are identified as conflicting with theBiden Administration's climate policies. In addition, onJanuary 27, 2021 ,President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of an ongoing comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, and onApril 22, 2021 , at a global summit on climate change,President Biden committedthe United States to target emissions reductions of 50-52% of 2005 levels by 2030. Lastly, onJune 30, 2021 ,President Biden signed into law a reinstatement of regulations put in place during the Obama administration regarding methane emissions. The Company had previously complied with these regulations during the Obama administration and does not expect the reinstatement to have a material effect on the Company or its operations.The Biden Administration could also seek, in the future, to put into place additional executive orders, policy and regulatory reviews, or seek to haveCongress pass legislation that could adversely affect the production of oil and gas assets and our operations and those of our customers. Only a small percentage of our operations are derived from customers operating on public land, mainly in theDelaware Basin , and these activities are expected to represent only approximately 4% of our total segment profit, net to EnLink, during 2021. In addition, we have a robust program to monitor and prevent methane emissions in our operations and we maintain a comprehensive environmental program that is embedded in our operations. However, our activities that take place on public lands require that we and our producer customers obtain leases, permits, and other approvals from the federal government. While the status of recent and future rules and rulemaking initiatives under theBiden Administration remain uncertain, the regulations that might result from such initiatives, could lead to increased costs for us or our customers, difficulties in obtaining leases, permits, and other approvals for us and our customers, reduced utilization of our gathering, processing and pipeline systems or reduced rates under renegotiated transportation or storage agreements in affected regions. These impacts could, in turn, adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders.
For more information, see our risk factors under "Environmental, Legal
Compliance, and Regulatory Risk" in Section 1A "Risk Factors" in our Annual
Report on Form 10-K filed with the Commission on
Other Recent Developments
Common Unit Repurchase Program. InNovember 2020 , the board of directors of the Managing Member authorized a common unit repurchase program for the repurchase of up to$100.0 million of outstanding ENLC common units and reauthorized such program inApril 2021 . The repurchases will be made, in accordance with applicable securities laws, from time to time in open market or private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time. For the three and six months endedJune 30, 2021 , ENLC repurchased 317,751 outstanding ENLC common units for an aggregate cost, including commissions, of$2.0 million , or an average of$6.22 per common unit. Amarillo Rattler Acquisition. OnApril 30, 2021 , we completed the acquisition ofAmarillo Rattler, LLC , the owner of a gathering and processing system located in theMidland Basin . In connection with the purchase, we entered into an amended and restated gas gathering and processing agreement with Diamondback Energy, strengthening our dedicated acreage position with Diamondback Energy. We acquired the system with an upfront payment of$50.0 million , which was paid with cash-on-hand, with an additional$10 million to be paid onApril 30, 2022 , and contingent consideration capped at$15 million based on Diamondback Energy's drilling activity above historical levels. 34 -------------------------------------------------------------------------------- Table of Contents War Horse Processing Plant. InDecember 2020 , we began moving equipment and facilities previously associated with theBattle Ridge processing plant inCentral Oklahoma to thePermian Basin . This processing plant relocation is expected to increase the processing capacity of ourPermian Basin processing facilities by approximately 95 MMcf/d. We expect to complete the relocation in the second half of 2021. Non-GAAP Financial Measures To assist management in assessing our business, we use the following non-GAAP financial measures: adjusted gross margin, adjusted earnings before interest, taxes, and depreciation and amortization ("adjusted EBITDA") and free cash flow after distributions. Adjusted Gross Margin We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization related to our operating segments. We present adjusted gross margin by segment in "Results of Operations." We disclose adjusted gross margin in addition to gross margin as defined by GAAP because it is the primary performance measure used by our management to evaluate consolidated operations. We believe adjusted gross 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 the 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 exclude all operating expenses and depreciation and amortization related to our operating segments from adjusted gross 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 adjusted gross margin is gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin as determined in accordance with GAAP. Adjusted gross margin has important limitations because it excludes all operating expenses and depreciation and amortization related to our operating segments that affect gross margin. Our adjusted gross 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 reconciles total revenues and gross margin to adjusted gross margin (in millions): Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 Total revenues$ 1,406.7 $
744.9
(1,055.1) (397.7) (1,989.8) (1,153.0)
Operating expenses (96.8) (88.1) (153.1) (188.8)
Depreciation and amortization (151.9) (158.2) (302.9) (321.0)
Gross margin 102.9 100.9 209.3 238.2
Operating expenses 96.8 88.1 153.1 188.8
Depreciation and amortization 151.9 158.2 302.9 321.0
Adjusted gross margin $ 351.6 $ 347.2 $ 665.3 $ 748.0 ____________________________
(1)Excludes all operating expenses as well as depreciation and amortization related to our operating segments of$150.1 million and$156.1 million for the three months endedJune 30, 2021 and 2020, respectively, and$299.1 million and$316.9 million for the six months endedJune 30, 2021 and 2020, respectively. 35 -------------------------------------------------------------------------------- Table of Contents Adjusted EBITDA We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; (income) loss from unconsolidated affiliate investments; distributions from unconsolidated affiliate investments; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; relocation costs associated with the War Horse processing facility; accretion expense associated with asset retirement obligations; transaction costs; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is one of the metrics 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 have 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. 36
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The following table reconciles net income (loss) to adjusted EBITDA (in
millions):
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net income (loss) $ 9.4 $ 29.8 $ 22.0 $ (230.6)
Interest expense, net of interest income 60.0 55.2 120.0 110.8
Depreciation and amortization 151.9 158.2 302.9 321.0
Impairments - 1.5 - 354.5
(Income) loss from unconsolidated affiliates 1.3 0.7 7.6 (1.0)
Distributions from unconsolidated affiliates 0.1 0.2 3.7 2.0
(Gain) loss on disposition of assets (0.3) 5.2 (0.3) 4.6
Gain on extinguishment of debt - (26.7) - (32.0)
Unit-based compensation 6.4 7.4 12.9 16.2
Income tax expense (benefit) 6.6 11.7 8.0 (22.0)
Unrealized loss on commodity swaps 23.8 18.8 31.7 5.8
Relocation costs associated with the War Horse
processing facility (1) 10.2 - 17.8 -
Other (2) 0.4 (0.4) - (0.5)
Adjusted EBITDA before non-controlling interest 269.8 261.6 526.3 528.8
Non-controlling interest share of adjusted EBITDA
from joint ventures (3) (12.3) (6.5) (19.4) (13.7)
Adjusted EBITDA, net to ENLC $ 257.5 ____________________________
(1)Represents cost incurred related to the relocation of equipment and facilities from theBattle Ridge processing plant, in theOklahoma segment, to the Permian segment that we expect to complete in 2021 and are not part of our ongoing operations. (2)Includes accretion expense associated with asset retirement obligations; transaction costs, 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 theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests. 37 -------------------------------------------------------------------------------- Table of Contents Free Cash Flow After Distributions We define free cash flow after distributions as adjusted EBITDA, net to ENLC, plus (less) (growth capital expenditures, excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities); (maintenance capital expenditures, excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities); (interest expense, net of interest income); (distributions declared on common units); (accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid); (relocation costs associated with the War Horse processing facility); non-cash interest (income)/expense; (payments to terminate interest rate swaps); (current income taxes); and proceeds from the sale of equipment and land. Free cash flow after distributions is the principal cash flow metric used by the Company in its public reporting. Free cash flow after distributions is one of the metrics used in our short-term incentive program for compensating employees. It is also used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, pay back our indebtedness, make cash distributions, and make capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income. Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations. The GAAP measure most directly comparable to free cash flow after distributions is net cash provided by operating activities. Free cash flow after distributions should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Free cash flow after distributions has important limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Free cash flow after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate this non-GAAP metric 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 free cash flow after distributions, to evaluate our overall liquidity. 38
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Table of Contents The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):
Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Net cash provided by operating activities $ 176.4 $ 134.8 $ 402.2 $ 316.8
Interest expense (1) 55.6 54.0 111.5 108.7
Utility credits (2) 3.4 - 43.8 -
Payments to terminate interest rate swaps (3) 1.3 - 1.3 -
Accruals for settled commodity swap transactions (2.6) (5.2) (2.5) (0.2)
Distributions from unconsolidated affiliate investment in excess of earnings
0.1 0.6 3.7 0.8
Relocation costs associated with the War Horse
processing facility (4) 10.2 - 17.8 -
Other (5) 1.4 (0.1) 2.6 0.6
Changes in operating assets and liabilities which
(provided) used cash:
Accounts receivable, accrued revenues, inventories,
and other 91.7 50.2 109.2 (119.1)
Accounts payable, accrued product purchases, and other accrued liabilities
(67.7) 27.3 (163.3) 221.2
Adjusted EBITDA before non-controlling interest 269.8 261.6 526.3 528.8
Non-controlling interest share of adjusted EBITDA from joint ventures (6)
(12.3) (6.5) (19.4) (13.7)
Adjusted EBITDA, net to ENLC 257.5 255.1 506.9 515.1
Growth capital expenditures, net to ENLC (7) (40.0) (50.7) (55.9) (133.3)
Maintenance capital expenditures, net to ENLC (7) (7.5) (7.7) (12.2) (15.9)
Interest expense, net of interest income (60.0) (55.2) (120.0) (110.8)
Distributions declared on common units (46.7) (46.4) (93.4) (92.9)
ENLK preferred unit accrued cash distributions (8) (23.0)
(22.8) (46.0) (45.6)
Relocation costs associated with the War Horse
processing facility (4) (10.2) - (17.8) -
Non-cash interest expense 2.4 - 4.6 -
Payments to terminate interest rate swaps (3) (1.3) - (1.3) -
Other (9) 0.3 - 0.8 0.2
Free cash flow after distributions $ 71.5 ____________________________
(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)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. (3)Represents cash paid for the early termination of$100.0 million of our interest rate swaps due to the partial repayment of the Term Loan inMay 2021 . See "Item 1. Financial Statements-Note 11" for information on the partial termination of our interest rate swaps. (4)Represents cost incurred related to the relocation of equipment and facilities from theBattle Ridge processing plant, in theOklahoma segment, to the Permian segment that we expect to complete in 2021 and are not part of our ongoing operations. (5)Includes current income tax expense; amortization of designated cash flow hedge; transaction costs; and non-cash rent, which relates to lease incentives pro-rated over the lease term. (6)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests. (7)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities. (8)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See "Item 1. Financial Statements- Note 7" for information on the cash distributions earned by holders of the Series B Preferred Units and Series C Preferred Units. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders. (9)Includes current income tax expense and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business. 39 -------------------------------------------------------------------------------- Table of Contents Results of Operations
The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the tables below (in millions, except volumes):
Permian Louisiana Oklahoma North Texas Corporate Totals
Three Months Ended June 30, 2021
Gross margin $ 9.4 $ 31.2 $ 35.0 $ 29.1 $ (1.8) $ 102.9
Depreciation and amortization 34.6 36.1 50.6 28.8 1.8 151.9
Segment profit 44.0 67.3 85.6 57.9 - 254.8
Operating expenses 27.4 31.7 17.8 19.9 - 96.8
Adjusted gross margin $ 71.4 $ 99.0 $ 103.4 $ 77.8 $ - $ 351.6
Three Months Ended June 30, 2020
Gross margin $ 3.4 $ 29.2 $
38.5
Depreciation and amortization 31.0 34.6 54.1 36.4 2.1 158.2 Segment profit 34.4 63.8 92.6 68.3 - 259.1 Operating expenses 22.7 27.5 19.4 18.5 - 88.1 Adjusted gross margin$ 57.1 $ 91.3 $ 112.0 $ 86.8 $ -$ 347.2 Permian Louisiana Oklahoma North Texas Corporate Totals Six Months EndedJune 30, 2021 Gross margin$ 18.7 $ 77.3 $
39.8
Depreciation and amortization 68.1 72.2 101.3 57.5 3.8 302.9 Segment profit 86.8 149.5 141.1 134.8 - 512.2 Operating expenses 15.6 60.9 37.5 39.1 - 153.1 Adjusted gross margin$ 102.4 $ 210.4 $
178.6
Six Months EndedJune 30, 2020 Gross margin$ 16.8 $ 66.7 $
89.9
Depreciation and amortization 60.2 72.4 110.7 73.6 4.1 321.0 Segment profit 77.0 139.1 200.6 142.5 - 559.2 Operating expenses 48.2 59.3 42.3 39.0 - 188.8 Adjusted gross margin$ 125.2 $ 198.4 $ 242.9 $ 181.5 $ -$ 748.0 40
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Three Months Ended Six Months Ended
June 30, June 30,
2021 2020 2021 2020
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d) 1,025,900 871,500 976,000 851,300
Processing (MMbtu/d) 958,400 896,100 917,500 878,900
Crude Oil Handling (Bbls/d) 121,900 112,300 115,100 122,900
Louisiana Segment
Gathering and Transportation (MMbtu/d) 2,139,300 1,873,600 2,145,300 1,958,400
Crude Oil Handling (Bbls/d) 15,200 15,700 15,100 16,600
NGL Fractionation (Gals/d) 7,729,300 7,344,800 7,419,500 7,764,500
Brine Disposal (Bbls/d) 2,900 1,400 2,200 1,600
Oklahoma Segment
Gathering and Transportation (MMbtu/d) 1,016,200 1,092,600 977,000 1,156,800
Processing (MMbtu/d) 1,040,000 1,082,100 997,900 1,118,300
Crude Oil Handling (Bbls/d) 23,800 30,000 20,700 33,300
North Texas Segment
Gathering and Transportation (MMbtu/d) 1,377,400 1,485,900 1,367,200 1,531,800
Processing (MMbtu/d) 627,600 670,600 626,100 685,200
Three Months Ended
Gross Margin. Gross margin was$102.9 million for the three months endedJune 30, 2021 compared to$100.9 million for the three months endedJune 30, 2020 , an increase of$2.0 million . The primary contributors to the increase were as follows (in millions): •Permian Segment. Gross margin was$9.4 million for the three months endedJune 30, 2021 compared to$3.4 million for the three months endedJune 30, 2020 , an increase of$6.0 million primarily due to the following:
•Adjusted gross margin in the Permian segment increased
•A
These increases were partially offset by a$3.1 million decrease in realized derivative gains and a$2.7 million decrease in adjusted gross margin associated with our Permian crude assets from higher storage fees earned in April of 2020 resulting from negative crude futures, which was partially offset by higher volumes from existing customers. •Operating expenses in the Permian segment increased$4.7 million primarily due to increased construction costs associated with our War Horse processing facility and higher compression expenses due to higher volumes. These increases were partially offset by lower utility costs as a result of$8.1 million of utility credits that we received in the second quarter because our electricity usage was below our contractual base load amounts during Winter Storm Uri, which entitled us to credits based on market rates for our unused electricity. These credits can be used to offset future utility payments. •Depreciation and amortization in the Permian segment increased$3.6 million primarily due to new assets placed into service, including the Tiger processing plant inAugust 2020 and gathering and processing assets associated with the acquisition ofAmarillo Rattler, LLC inApril 2021 . 41 -------------------------------------------------------------------------------- Table of Contents •Louisiana Segment. Gross margin was$31.2 million for the three months endedJune 30, 2021 compared to$29.2 million for the three months endedJune 30, 2020 , an increase of$2.0 million primarily due to the following:
•Adjusted gross margin in the
•A$10.4 million increase in adjusted gross margin associated with ourLouisiana gas assets, which was primarily due to increased gathering and transportation fees as a result of higher volumes transported in addition to increased storage and hub fees following the acquisition of theJefferson Island storage facility inDecember 2020 . •A$7.5 million increase in adjusted gross margin associated with ourLouisiana NGL transmission and fractionation assets, which was primarily due to favorable market prices on NGL sales and higher volumes. These increases were partially offset by a$4.6 million and$5.3 million increase in realized and unrealized derivative losses, respectively, due to an increase in commodity prices relative to our hedged prices, and a$0.3 million decrease in adjusted gross margin associated with our ORV crude assets, which was primarily due to lower volumes.
•Operating expenses in the
•Depreciation and amortization in the
•Oklahoma Segment. Gross margin was
•Adjusted gross margin in the
•A$4.8 million decrease in adjusted gross margin associated with ourOklahoma gas assets primarily due to a$15.1 million decrease resulting from the expiration of the MVC provision of a gathering and processing contract at the end of 2020. This decrease was partially offset by an increase in processing prices, despite lower processing volumes. •A$2.3 million decrease in adjusted gross margin associated with ourOklahoma crude assets primarily due to lower volumes from our existing customers. •A$2.1 million increase in realized derivative losses.
These decreases were partially offset by a
•Operating expenses in the
•Depreciation and amortization in theOklahoma segment decreased$3.5 million primarily due to the relocation of theBattle Ridge processing plant to the War Horse processing facility.
•North Texas Segment. Gross margin was
•Adjusted gross margin in theNorth Texas segment decreased$9.0 million , which was primarily due to$7.6 million of decreased revenues due to lower volumes from our existing customers and$1.0 million and$0.4 million of increased realized and unrealized derivative losses, respectively. •Operating expenses in theNorth Texas segment increased$1.4 million primarily due to increased sales and use taxes and operation and maintenance costs. These increases were partially offset by lower materials and supplies expense and compressor rentals related to the assets in this segment.
•Depreciation and amortization in the
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•Corporate Segment. Gross margin was negative $1.8 million for the three months
ended June 30, 2021 compared to negative $2.1 million for the three months ended
June 30, 2020 . Corporate gross margin consists of depreciation and amortization
of corporate assets.
General and Administrative Expenses. General and administrative expenses were
$26.1 million for the three months ended June 30, 2021 compared to $23.5 million
for the three months ended June 30, 2020 , an increase of $2.6 million . The
increase was primarily due to transaction and transition costs, which increased
$1.2 million primarily due to the Amarillo Rattler, LLC acquisition in April
2021 , and labor and benefits costs, which increased $1.3 million .
Interest Expense. Interest expense was $60.0 million for the three months ended
June 30, 2021 compared to $55.2 million for the three months ended June 30,
2020 , an increase of $4.8 million . Interest expense consisted of the following
(in millions):
Three Months Ended
June 30,
2021 2020
ENLK and ENLC Senior Notes $ 50.3 $ 43.3
Term Loan 1.3 4.2
AR Facility 0.8 -
Consolidated Credit Facility 1.4 4.1
Capitalized interest (0.1) (1.3)Amortization of debt issue costs and net discounts (premiums) 1.3
1.2
Interest rate swap - realized 4.8 3.7
Other 0.2 -
Total $ 60.0 $ 55.2
Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt
of $26.7 million for the three months ended June 30, 2020 due to repurchases of
the 2024, 2025, 2026, and 2029 Notes in open market transactions.
Income (Loss) from Unconsolidated Affiliate Investments. Loss from
unconsolidated affiliate investments was $1.3 million for the three months ended
June 30, 2021 compared to loss of $0.7 million for the three months ended
June 30, 2020 , a decrease of $0.6 million . The decrease was primarily
attributable to a reduction of income of $1.0 million from our GCF investment,
as a result of the GCF assets being temporarily idled beginning in January 2021 ,
and was partially offset by a reduction of loss of $0.4 million from our Cedar
Cove JV.
Income Tax Benefit (Expense). Income tax expense was $6.6 million for the three
months ended June 30, 2021 compared to an income tax expense of $11.7 million
for the three months ended June 30, 2020 . The decrease in income tax expense was
primarily attributable to the decrease in income between periods. See "Item 1.
Financial Statements-Note 6" for additional information.
Net Income (Loss) Attributable to Non-Controlling Interest. Net income
attributable to non-controlling interest was $31.0 million for the three months
ended June 30, 2021 compared to net income of $25.7 million for the three months
ended June 30, 2020 , an increase of $5.3 million . ENLC's non-controlling
interest is comprised of Series B Preferred Units, Series C Preferred Units,
NGP's 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation's
50% share of the Ascension JV.
43
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Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020 Gross Margin. Gross margin was
•Permian Segment. Gross margin was
•Adjusted gross margin in the Permian segment decreased
•An increase in realized and unrealized derivative losses of$60.9 million and$14.6 million , respectively, due to significant commodity price impacts resulting from Winter Storm Uri and subsequent increases in commodity prices relative to our hedged prices. •A$6.7 million decrease to adjusted gross margin associated with ourMidland Basin crude assets primarily due to volume declines related to weather disruptions from Winter Storm Uri and due to storage fees earned in April of 2020 due to the negative futures price of crude. These decreases were partially offset by a$54.2 million and$3.1 million increase in adjusted gross margin due to higher volumes and due to significant favorable physical commodity prices on sales in ourMidland Basin andDelaware gas assets, respectively, resulting from Winter Storm Uri and a$2.1 million increase in adjusted gross margin due to volume growth in ourDelaware Basin crude assets from system expansion. •Operating expenses in the Permian segment decreased$32.6 million primarily due to lower utility costs as a result of approximately$48.1 million of utility credits that we received because our electricity usage was below our contractual base load amounts during Winter Storm Uri, which entitled us to credits based on market rates for our unused electricity. These credits can be used to offset future utility payments. Operating expenses also decreased due to lower labor expense as a result of reductions in workforce inApril 2020 . These decreases were partially offset by increases in construction fees and services related to the construction of our War Horse processing facility and higher materials and supplies expense, compressor rentals, and sales and use taxes due to higher volumes. •Depreciation and amortization in the Permian segment increased$7.9 million primarily due to new assets placed into service, including the Tiger processing plant inAugust 2020 and acquisition of theAmarillo Rattler, LLC gathering and processing system inApril 2021 . •Louisiana Segment. Gross margin was$77.3 million for the six months endedJune 30, 2021 compared to$66.7 million for the six months endedJune 30, 2020 , an increase of$10.6 million primarily due to the following:
•Adjusted gross margin in the
•A$29.2 million increase in adjusted gross margin associated with ourLouisiana NGL transmission and fractionation assets, which was primarily due to favorable market prices on NGL sales. •An$11.8 million increase in adjusted gross margin associated with ourLouisiana gas assets, which was primarily due to increased gathering and transportation fees as a result of higher volumes transported and increased storage and hub fees following our acquisition of theJefferson Island storage facility inDecember 2020 .
These increases were partially offset by a
•Operating expenses in the
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•Depreciation and amortization in the Louisiana segment decreased $0.2 million
primarily due to the impairment of assets in the first quarter of 2020,
partially offset by changes in estimated useful lives of certain non-core
assets.
•Oklahoma Segment. Gross margin was $39.8 million for the six months ended
June 30, 2021 compared to $89.9 million for the six months ended June 30, 2020 ,
a decrease of $50.1 million primarily due to the following:
•Adjusted gross margin in the
•A$46.5 million decrease in adjusted gross margin associated with ourOklahoma gas assets primarily due to lower volumes from our existing customers, including weather disruptions from Winter Storm Uri, and a$24.9 million decrease due to the expiration of the MVC provision of a gathering and processing contract at the end of 2020. •An increase in realized and unrealized derivative losses of$8.9 million and$5.0 million , respectively, due to increased commodity prices relative to our hedged prices. •A$3.9 million decrease in adjusted gross margin associated with ourOklahoma crude assets primarily due to lower volumes from our existing customers and partially as a result of weather disruptions from Winter Storm Uri. •Operating expenses in theOklahoma segment decreased$4.8 million primarily due to reductions in compressor rentals and lower labor and benefits expense as a result of reductions in workforce inApril 2020 . These decreases were partially offset by higher costs in 2021 to decommission equipment from theBattle Ridge processing plant to be moved to the War Horse processing facility. •Depreciation and amortization in theOklahoma segment decreased$9.4 million primarily due to the relocation of theBattle Ridge processing plant to the War Horse processing facility. •North Texas Segment. Gross margin was$77.3 million for the six months endedJune 30, 2021 compared to$68.9 million for the six months endedJune 30, 2020 , an increase of$8.4 million primarily due to the following: •Adjusted gross margin in theNorth Texas segment decreased$7.6 million , which was primarily due to$2.9 million of decreased revenues from volume declines and$3.1 million and$1.6 million of increased realized and unrealized derivative losses, respectively. •Operating expenses in theNorth Texas segment increased$0.1 million primarily due to increased sales and use taxes and operation and maintenance costs. These increases were partially offset by reductions in compressor rentals, reductions to labor and benefits expense as a result of reductions in workforce inApril 2020 , and reductions to utility costs.
•Depreciation and amortization in the
•Corporate Segment. Gross margin was negative$3.8 million for the six months endedJune 30, 2021 compared to negative$4.1 million for the six months endedJune 30, 2020 . Corporate gross margin consists of depreciation and amortization of corporate assets. Impairments. For the six months endedJune 30, 2021 , we did not recognize an impairment expense. For the six months endedJune 30, 2020 , we recognized impairment expense related to goodwill and property and equipment, including cancelled projects. Impairment expense is composed of the following amounts (in millions): Six Months Ended June 30, 2020 Goodwill impairment $ 184.6 Property and equipment impairment 168.0 Cancelled projects 1.9 Total $ 354.5 45
-------------------------------------------------------------------------------- Table of Contents General and Administrative Expenses. General and administrative expenses were$52.1 million for the six months endedJune 30, 2021 compared to$53.9 million for the six months endedJune 30, 2020 , a decrease of$1.8 million . The decrease was primarily due to reduced labor and benefits costs and unit-based compensation costs, which decreased$4.3 million as a result of reductions in workforce inApril 2020 . This decrease was partially offset by transaction and transition costs, which increased$1.3 million primarily due to theAmarillo Rattler, LLC acquisition inApril 2021 , and franchise taxes, which increased$0.6 million primarily due to franchise tax refunds in the first half of 2020. Interest Expense. Interest expense was$120.0 million for the six months endedJune 30, 2021 compared to$110.8 million for the six months endedJune 30, 2020 , an increase of$9.2 million , or 8.3%. Interest expense consisted of the following (in millions): Six Months Ended June 30, 2021 2020 ENLK and ENLC Senior Notes$ 100.6 $ 87.3 Term Loan 2.7 10.6 AR Facility 2.0 - Consolidated Credit Facility 2.7 8.2 Capitalized interest (0.3) (2.5)
Amortization of debt issue costs and net discounts (premiums) 2.5
2.2
Interest rate swap - realized 9.6 5.0
Other 0.2 -
Total $ 120.0 $ 110.8
Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt
of $32.0 million for the six months ended June 30, 2020 due to repurchases of
the 2024, 2025, 2026, and 2029 Notes in open market transactions.
Income (Loss) from Unconsolidated Affiliate Investments. Loss from
unconsolidated affiliate investments was $7.6 million for the six months ended
June 30, 2021 compared to income of $1.0 million for the six months ended
June 30, 2020 , a decrease of $8.6 million . The decrease was primarily
attributable to a reduction of income of $8.5 million from our GCF investment,
as a result of the GCF assets being temporarily idled beginning in January 2021 ,
and additional losses of $0.1 million from our Cedar Cove JV.
Income Tax Expense. Income tax expense was $8.0 million for the six months ended
June 30, 2021 compared to an income tax benefit of $22.0 million for the six
months ended June 30, 2020 . The decrease in income tax benefit was primarily
attributable to the decrease in loss between periods. See "Item 1. Financial
Statements-Note 6" for additional information.
Net Income (Loss) Attributable to Non-Controlling Interest. Net income
attributable to non-controlling interest was $56.3 million for the six months
ended June 30, 2021 compared to net income of $52.1 million for the six months
ended June 30, 2020 , an increase of $4.2 million . ENLC's non-controlling
interest is comprised of Series B Preferred Units, Series C Preferred Units,
NGP's 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation's
50% share of the Ascension JV.
Critical Accounting Policies
Information regarding our critical accounting policies is included in "Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations" of our Annual Report on Form 10-K for the year endedDecember 31, 2020 . 46 -------------------------------------------------------------------------------- Table of Contents Liquidity and Capital Resources Cash Flows from Operating Activities. Net cash provided by operating activities was$402.2 million for the six months endedJune 30, 2021 compared to$316.8 million for the six months endedJune 30, 2020 . Operating cash flows and changes in working capital for comparative periods were as follows (in millions): Six Months EndedJune 30, 2021 2020
Operating cash flows before working capital
54.1 (102.1)
Operating cash flows before changes in working capital decreased $70.8 million
for the six months ended June 30, 2021 compared to the six months ended June 30,
2020 . The primary contributors to the decrease in operating cash flows were as
follows:
•Gross margin, excluding depreciation and amortization, non-cash commodity swap
activity, utility credits, and unit-based compensation, decreased $63.4 million .
For more information regarding the changes in gross margin for the six months
ended June 30, 2021 compared to the six months ended June 30, 2020 , see "Results
of Operations."
•Interest expense, excluding amortization of debt issue costs and net discounts
(premium) of notes, increased
The changes in working capital for the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 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$112.2 million for the six months endedJune 30, 2021 compared to$202.0 million for the six months endedJune 30, 2020 . Investing cash flows are primarily related to capital expenditures. Capital expenditures decreased from$203.6 million for the six months endedJune 30, 2020 to$62.5 million for the six months endedJune 30, 2021 . The decrease in capital expenditures was primarily due to the completion of major projects in 2020 and was partially offset by$55.0 million related to cash paid for the acquisition of assets for the six months endedJune 30, 2021 . 47 -------------------------------------------------------------------------------- Table of Contents Cash Flows from Financing Activities. Net cash used in financing activities was$296.8 million for the six months endedJune 30, 2021 compared to$140.2 million for the six months endedJune 30, 2020 . Our primary financing activities consisted of the following (in millions): Six Months Ended June 30, 2021 2020 Net repayments on the Term Loan (1)$ (100.0) $ - Net repayments on the AR Facility (1) (40.0)
-
Net borrowings on the Consolidated Credit Facility (1) -
50.0
Net repurchases on ENLK's senior unsecured notes (1) -
(35.2)
Net repurchases on the 2029 Notes (1) -
(0.8)
Contributions by non-controlling interests (2) 1.9
50.3
Distribution to members (93.8)
(139.8)
Distributions to Series B Preferred unitholders (3) (33.9)
(33.6)
Distributions to Series C Preferred unitholders (3) (12.0)
(12.0)
Distributions to joint venture partners (4) (16.1) (15.0) Common unit repurchases (5) (2.0) - ____________________________ (1)See "Item 1. Financial Statements-Note 5" for more information regarding the Term Loan, the AR Facility, the Consolidated Credit Facility, and the senior unsecured notes. (2)Represents contributions from NGP to theDelaware Basin JV. (3)See "Item 1. Financial Statements-Note 7" for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units. (4)Represents distributions to NGP for its ownership in theDelaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other non-controlling interests. (5)See "Item 1. Financial Statements-Note 8" for more information regarding the ENLC common unit repurchase program. Capital Requirements. We expect our remaining 2021 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately$72 million to$102 million , net to ENLC. Our primary capital projects for the remainder of 2021 include continued development of our existing systems through well connects and other low-cost development projects. Additionally, we expect our remaining 2021 operating expenses related to the relocation of equipment and facilities previously associated with theBattle Ridge processing plant inCentral Oklahoma to thePermian Basin to be approximately$7 million . These expenses are treated as an operating expense under GAAP and, therefore, are not included in our expected remaining 2021 capital expenditures. We expect to fund capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. In 2021, it is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.
Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of
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Total Contractual Cash Obligations. A summary of our total contractual cash
obligations as of
Payments Due by Period
Total Remainder 2021 2022 2023 2024 2025 Thereafter
ENLC's & ENLK's senior unsecured notes$ 4,032.3 $ - $ - $ -$ 521.8 $ 720.8 $ 2,789.7 Term Loan (1) 250.0 250.0 - - - - - AR Facility (2) 210.0 - - 210.0 - - - Consolidated Credit Facility (3) - - - - - -
-
Acquisition installment payable (4) 10.0 10.0 - - - -
-
Acquisition contingent consideration (5) 6.7 - - - 2.2 2.3
2.2
Interest payable on fixed long-term debt obligations 2,436.7 101.7 201.2 201.2 189.7 163.3 1,579.6 Operating lease obligations 118.9 10.7 17.0 11.7 10.2 9.8 59.5 Purchase obligations 4.3 4.3 - - - - - Pipeline and trucking capacity and deficiency agreements (6) 187.8 24.3 46.6 38.6 29.2 24.8
24.3
Inactive easement commitment (7) 10.0 - 10.0 - - - - Total contractual obligations$ 7,266.7 $ 401.0 $ 274.8 $ 461.5 $ 753.1 $ 921.0 $ 4,455.3 ____________________________ (1)The Term Loan matures onDecember 10, 2021 . (2)The AR Facility will terminate onOctober 20, 2023 . (3)The Consolidated Credit Facility will mature onJanuary 25, 2024 . As ofJune 30, 2021 , there were no amounts outstanding under the Consolidated Credit Facility. (4)Amount related to the consideration of theAmarillo Rattler, LLC acquisition due onApril 30, 2022 . (5)The estimated fair value of theAmarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820, Fair Value Measurements. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from these estimated fair values. (6)Consists of pipeline capacity payments for firm transportation and deficiency agreements. (7)Amount 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 Term Loan, the AR Facility, and the Consolidated Credit Facility are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Term Loan, the AR Facility, and the Consolidated Credit Facility, which vary from time to time. Our contractual cash obligations for the remainder of 2021 are expected to be funded from cash flows generated from our operations and the available capacity under the AR Facility, the Consolidated Credit Facility, or other debt sources.
Indebtedness
InOctober 2020 , we entered into the AR Facility, which is a three-year committed accounts receivable securitization facility originally in the amount of up to$250.0 million . OnFebruary 26, 2021 , the SPV entered into the First Amendment to the Receivables Financing Agreement, which amended the AR Facility to, among other things, increase the facility limit and lender commitments by$50.0 million to$300.0 million . As ofJune 30, 2021 , the AR Facility had a borrowing base of$300.0 million and there was$210.0 million in outstanding borrowings under the AR Facility. In addition, as ofJune 30, 2021 , we have$4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047 and$250.0 million in outstanding principal on the Term Loan. There were no outstanding borrowings under the Consolidated Credit Facility and$40.7 million outstanding letters of credit as ofJune 30, 2021 . 49 -------------------------------------------------------------------------------- Table of Contents Guarantees. The amounts outstanding on our senior unsecured notes, the Term Loan, and the Consolidated Credit Facility are guaranteed in full by our subsidiary ENLK, including 105% of any letters of credit outstanding on the Consolidated Credit Facility. ENLK's guarantees of these amounts are full, irrevocable, unconditional, and absolute, and cover all payment obligations arising under the senior unsecured notes, the Term Loan, and the Consolidated Credit Facility. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness of ENLK. ENLC's material assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. Other than these equity interests, all of our material assets and operations are held by our non-guarantor operating subsidiaries. ENLK, directly and indirectly, owns all of these non-guarantor operating subsidiaries, which in some cases are joint ventures that are partially owned by a third party. As a result, the assets, liabilities, and results of operations of ENLK are not materially different than the corresponding amounts presented in our consolidated financial statements. As ofJune 30, 2021 , ENLC records, on a stand-alone basis, transactions that do not occur at ENLK related to taxation of ENLC, the elimination of intercompany borrowings, and impairment of goodwill that only existed at ENLC.
See "Item 1. Financial Statements-Note 5" for more information on our outstanding debt instruments.
Recent Accounting Pronouncements
See "Item 8. Financial Statements and Supplementary Data-Note 2" in our Annual
Report on Form 10-K filed with the Commission on
Disclosure Regarding Forward-Looking Statements
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 or leverage metrics, future cost savings or operational initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic and Winter Storm Uri 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 impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of the emergence of any new variants of the virus) on 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 or prepayment event under our credit facility and certain of our other debt, (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) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (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 and the risk factors set forth in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year endedDecember 31, 2020 may affect our performance and results of operations. Should one 50
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Table of Contents 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.
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