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OFFON

ENLINK MIDSTREAM, LLC

(ENLC)
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ENLINK MIDSTREAM, LLC Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

11/03/2021 | 03:08pm EST
Please read the following discussion of our financial condition and results of
operations in conjunction with the financial statements and notes thereto
included elsewhere in this report. In addition, please refer to the Definitions
page set forth in this report prior to Part I-Financial Information.

In this report, the terms "Company" or "Registrant," as well as the terms
"ENLC," "our," "we," "us," or like terms, are sometimes used as abbreviated
references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together
with its consolidated subsidiaries, including ENLK and its consolidated
subsidiaries. References in this report to "EnLink Midstream Partners, LP," the
"Partnership," "ENLK," or like terms refer to EnLink Midstream Partners, LP
itself or EnLink Midstream Partners, LP together with its consolidated
subsidiaries, including the Operating Partnership.

Overview


ENLC is a Delaware limited liability company formed in October 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, and North 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 West Texas and Eastern New Mexico;


•Louisiana Segment. The Louisiana segment includes our natural gas and NGL
pipelines, natural gas processing plants, natural gas and NGL storage
facilities, and fractionation facilities located in Louisiana and our crude oil
operations in ORV;

•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;

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas; and


•Corporate Segment. The Corporate segment includes our unconsolidated affiliate
investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in
South Texas, and our general corporate 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
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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 88% of our adjusted
gross margin was derived from fee-based contractual arrangements with minimal
direct commodity price exposure for the nine months ended September 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                             Nine Months Ended
                                                            September 30,                                 September 30,
                                                     2021                   2020                   2021                   2020
Devon                                                     6.9  %               14.2  %                  7.1  %               14.7  %
Dow Hydrocarbons and Resources LLC                       14.0  %               15.2  %                 14.5  %               13.2  %
Marathon Petroleum Corporation                           12.2  %                7.6  %                 13.1  %               12.7  %



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. Although commodity markets have recovered from the reduction in global
demand and low market prices experienced in 2020 due to the COVID-19 pandemic,
oil and natural gas prices continue to remain volatile. Natural gas prices, in
particular, have risen quickly during 2021, at the date of this report, and the
market price is at a level higher than it has traded in many years.

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 relatively low levels compared to historical
levels and producers remain cautious, even as crude oil and natural gas prices
have steadily increased during 2021.

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
the Permian Basin, because of the availability of higher investment returns.
Currently, a large percentage of all drilling rigs operating in the United
States are operating in the Permian Basin. As a result of this concentration of
drilling activity in the Permian, other basins, including those in which we
operate in Oklahoma and North 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.

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Our Louisiana 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 the Gulf Coast region has remained strong from the
second half of 2020 and through the first three quarters of 2021, supported by
regional industrial activity and export markets. Our activities and, in turn,
our financial performance in the Louisiana 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 February 17, 2021.

Winter Storm Uri and Other Weather Events


From time to time our operations may be affected by extreme weather events, such
as Winter Storm Uri in February 2021. During the third quarter of 2021, we
experienced a temporary loss of some processing volumes in our Louisiana
operations due to the effects of Hurricane Ida, which forced a temporary
shut-down of some of our operations and those of our downstream customers. All
of our operations and those of our customers are now operating normally.

In February 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 in Louisiana 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


On March 11, 2020, the World 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 in March 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
significant COVID-19 related operational disruptions.

There remains considerable uncertainty regarding how long the COVID-19 pandemic
(including variants of the virus) 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
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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 fully resume. 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 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 on February 17, 2021.

Regulatory Developments


On January 20, 2021, the Biden 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 reentering the
United States into the Paris Agreement, effective February 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 the Biden
Administration's climate policies. In addition, on January 27, 2021, President
Biden issued an executive order, which has since been challenged, 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 on April 22, 2021, at
a global summit on climate change, President Biden committed the United States
to target emissions reductions of 50-52% of 2005 levels by 2030. Lastly, on June
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 have Congress pass legislation that could adversely affect the
production of oil and natural gas, 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 the Delaware 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 the Biden 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 February 17, 2021.

Other Recent Developments


Bridgeport CO2 Project. We have entered into an agreement with Continental
Carbonic Products, Inc., a wholly owned subsidiary of Matheson Tri-Gas, Inc.,
and member of the Nippon Sanso Holdings Corporation group of companies, to
capture and sell CO2 emitted from our Bridgeport processing plant in North
Texas. The CO2 will be sold on a firm basis for 15 years and will be converted
into food-grade products. This project is expected to be in service in early
2024. The project makes meaningful progress toward our goal of a 30% reduction
in total CO2-equivalent emissions intensity by 2030, while being modestly
profitable.

Common Unit Repurchase Program. In November 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 in April 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.
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For the three months ended September 30, 2021, ENLC repurchased 2,076,545
outstanding ENLC common units for an aggregate cost, including commissions, of
$12.5 million, or an average of $6.02 per common unit. For the nine months ended
September 30, 2021, ENLC repurchased 2,394,296 outstanding ENLC common units for
an aggregate cost, including commissions, of $14.5 million, or an average of
$6.05 per common unit.

Organic Growth

Phantom Processing Plant. In September 2021, we established a plan to relocate
the Thunderbird processing plant from Central Oklahoma to the Midland Basin.
This processing plant relocation is expected to increase the processing capacity
of our Permian Basin processing facilities by approximately 200 MMcf/d. We
expect to complete the relocation in the second half of 2022.

Amarillo Rattler Acquisition. On April 30, 2021, we completed the acquisition of
Amarillo Rattler, LLC, the owner of a gathering and processing system located in
the Midland 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 on April 30, 2022,
and contingent consideration capped at $15 million and payable between 2024 and
2026 based on Diamondback Energy's drilling activity above historical levels.

War Horse Processing Plant. In December 2020, we began moving equipment and
facilities previously associated with the Battle Ridge processing plant in
Central Oklahoma to the Permian Basin. The War Horse processing plant began
operations in the third quarter of 2021. We are currently expanding the capacity
of the War Horse processing plant to approximately 95 MMcf/d, which we expect to
complete in the fourth quarter 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.

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The following table reconciles total revenues and gross margin to adjusted gross
margin (in millions):
                                                          Three Months Ended                     Nine Months Ended
                                                            September 30,                          September 30,
                                                        2021               2020               2021               2020
Total revenues                                     $   1,787.6          $ 

928.5 $ 4,442.7 $ 2,829.5 Cost of sales, exclusive of operating expenses and depreciation and amortization (1)

                     (1,400.8)           (549.5)          (3,390.6)          (1,702.5)
Operating expenses                                      (106.9)            (94.3)            (260.0)            (283.1)
Depreciation and amortization                           (153.0)           (160.3)            (455.9)            (481.3)
Gross margin                                             126.9             124.4              336.2              362.6
Operating expenses                                       106.9              94.3              260.0              283.1
Depreciation and amortization                            153.0             160.3              455.9              481.3
Adjusted gross margin                              $     386.8          $  379.0          $ 1,052.1          $ 1,127.0

____________________________

(1)Excludes all operating expenses as well as depreciation and amortization
related to our operating segments of $150.8 million and $158.6 million for the
three months ended September 30, 2021 and 2020, respectively, and $449.9 million
and $475.5 million for the nine months ended September 30, 2021 and 2020,
respectively.

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; costs associated with the relocation
of processing facilities; 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.
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The following table reconciles net income (loss) to adjusted EBITDA (in
millions):
                                                              Three Months Ended                     Nine Months Ended
                                                                September 30,                          September 30,
                                                            2021                2020               2021              2020
Net income (loss)                                     $     32.3             $   39.2          $    54.3          $ (191.4)
Interest expense, net of interest income                    60.1                 55.5              180.1             166.3
Depreciation and amortization                              153.0                160.3              455.9             481.3
Impairments                                                    -                    -                  -             354.5
(Income) loss from unconsolidated affiliates                 2.3                  0.2                9.9              (0.8)
Distributions from unconsolidated affiliates                 0.1                    -                3.8               2.0
(Gain) loss on disposition of assets                        (0.4)                (1.8)              (0.7)              2.8
Gain on extinguishment of debt                                 -                    -                  -             (32.0)
Unit-based compensation                                      6.4                  8.4               19.3              24.6
Income tax expense (benefit)                                 4.4                  6.0               12.4             (16.0)
Unrealized loss on commodity swaps                           1.2                  2.2               32.9               8.0

Costs associated with the relocation of processing facilities (1)

                                               8.8                    -               26.6                 -
Other (2)                                                   (0.2)                (0.3)              (0.2)             (0.8)
Adjusted EBITDA before non-controlling interest            268.0                269.7              794.3             798.5
Non-controlling interest share of adjusted EBITDA
from joint ventures (3)                                    (11.6)                (8.1)             (31.0)            (21.8)
Adjusted EBITDA, net to ENLC                          $    256.4            

$ 261.6 $ 763.3 $ 776.7

____________________________

(1)Represents cost incurred related to the relocation of equipment and
facilities from the Battle Ridge processing plant, in the Oklahoma segment, to
the Permian segment that we completed in the third quarter of 2021 and is 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 the Delaware Basin JV,
Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension
JV, and other minor non-controlling interests.

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Free Cash Flow After Distributions

We define free cash flow after distributions as adjusted EBITDA, net to ENLC,
plus (less) (growth and 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); (costs associated with the relocation of processing
facilities); 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.

                                       40

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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                     Nine Months Ended
                                                                 September 30,                         September 30,
                                                             2021                2020              2021               2020
Net cash provided by operating activities              $    197.0             $ 244.2          $    599.2          $ 561.0
Interest expense (1)                                         55.1                54.5               166.6            163.1
Utility credits, net of usage (2)                            (5.6)                  -                38.2                -
Payments to terminate interest rate swaps (3)                 0.5                   -                 1.8                -
Accruals for settled commodity swap transactions             (2.1)                0.9                (4.6)             0.7

Distributions from unconsolidated affiliate investment in excess of earnings

                                         0.1                (0.4)                3.8              0.4

Costs associated with the relocation of processing facilities (4)

                                                8.8                   -                26.6                -
Other (5)                                                    (0.2)                0.4                 2.4              1.1
Changes in operating assets and liabilities which
(provided) used cash:
Accounts receivable, accrued revenues, inventories,
and other                                                   167.6                46.5               276.8            (72.6)

Accounts payable, accrued product purchases, and other accrued liabilities

                                        (153.2)              (76.4)             (316.5)           144.8
Adjusted EBITDA before non-controlling interest             268.0               269.7               794.3            798.5

Non-controlling interest share of adjusted EBITDA from joint ventures (6)

                                          (11.6)               (8.1)              (31.0)           (21.8)
Adjusted EBITDA, net to ENLC                                256.4               261.6               763.3            776.7
Growth capital expenditures, net to ENLC (7)                (33.2)              (32.6)              (89.1)          (165.9)
Maintenance capital expenditures, net to ENLC (7)            (6.9)               (5.0)              (19.1)           (20.9)
Interest expense, net of interest income                    (60.1)              (55.5)             (180.1)          (166.3)
Distributions declared on common units                      (46.6)              (46.4)             (140.0)          (139.3)

ENLK preferred unit accrued cash distributions (8) (23.0)

     (22.9)              (69.0)           (68.5)

Costs associated with the relocation of processing facilities (4)

                                               (8.8)                  -               (26.6)               -
Non-cash interest expense                                     2.7                   -                 7.3                -
Payments to terminate interest rate swaps (3)                (0.5)                  -                (1.8)               -
Other (9)                                                     0.5                 2.9                 1.3              3.1
Free cash flow after distributions                     $     80.5           

$ 102.1 $ 246.2 $ 218.9

____________________________

(1)Net of amortization of debt issuance costs, net discount of senior unsecured
notes, and designated cash flow hedge, 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. These
utility credits are recorded as "Other current assets" or "Other assets, net" on
our consolidated balance sheets depending on the timing of their expected usage,
and amortized as we incur utility expenses.
(3)Represents cash paid for the early terminations of our interest rate swaps
due to the partial repayments of the Term Loan in May and September 2021. See
"Item 1. Financial Statements-Note 11" for information on the partial
terminations of our interest rate swaps.
(4)Represents cost incurred related to the relocation of equipment and
facilities from the Battle Ridge processing plant, in the Oklahoma segment, to
the Permian segment that we completed in the third quarter of 2021 and is not
part of our ongoing operations.
(5)Includes current income tax expense; 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 the Delaware 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.

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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 September 30,
2021
Gross margin                         $  33.7          $     29.1          $   34.8          $       31.5          $     (2.2)         $ 126.9

Depreciation and amortization           35.4                34.6              52.3                  28.5                 2.2            153.0
Segment profit                          69.1                63.7              87.1                  60.0                   -            279.9
Operating expenses                      37.3                30.5              19.8                  19.3                   -            106.9
Adjusted gross margin                $ 106.4          $     94.2          $  106.9          $       79.3          $        -          $ 386.8

Three Months Ended September 30,
2020
Gross margin                         $  15.0          $     28.8          $ 

52.8 $ 29.5 $ (1.7) $ 124.4


Depreciation and amortization           31.9                36.9              53.0                  36.8                 1.7            160.3
Segment profit                          46.9                65.7             105.8                  66.3                   -            284.7
Operating expenses                      22.9                31.1              20.1                  20.2                   -             94.3
Adjusted gross margin                $  69.8          $     96.8          $  125.9          $       86.5          $        -          $ 379.0



                                      Permian           Louisiana          Oklahoma           North Texas           Corporate            Totals
Nine Months Ended September 30, 2021
Gross margin                         $  52.4          $    106.4          $   74.6          $      108.8          $     (6.0)         $   336.2

Depreciation and amortization          103.5               106.8             153.6                  86.0                 6.0              455.9
Segment profit                         155.9               213.2             228.2                 194.8                   -              792.1
Operating expenses                      52.9                91.4              57.3                  58.4                   -              260.0
Adjusted gross margin                $ 208.8          $    304.6          $  285.5          $      253.2          $        -          $ 1,052.1

Nine Months Ended September 30, 2020
Gross margin                         $  31.8          $     95.5          $  142.7          $       98.4          $     (5.8)         $   362.6

Depreciation and amortization           92.1               109.3             163.7                 110.4                 5.8              481.3
Segment profit                         123.9               204.8             306.4                 208.8                   -              843.9
Operating expenses                      71.1                90.4              62.4                  59.2                   -              283.1
Adjusted gross margin                $ 195.0          $    295.2          $  368.8          $      268.0          $        -          $ 1,127.0



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                                                              Three Months Ended                                   Nine Months Ended
                                                                September 30,                                        September 30,
                                                       2021                        2020                     2021                        2020
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d)               1,111,800                     923,400                1,021,800                     875,200
Processing (MMbtu/d)                                 1,062,800                     929,900                  966,500                     895,800
Crude Oil Handling (Bbls/d)                            157,500                      99,100                  129,400                     115,000
Louisiana Segment
Gathering and Transportation (MMbtu/d)               2,013,900                   1,961,100                2,101,000                   1,959,600

Crude Oil Handling (Bbls/d)                             17,600                      15,700                   16,000                      16,300
NGL Fractionation (Gals/d)                           7,050,500                   7,462,600                7,295,100                   7,665,700
Brine Disposal (Bbls/d)                                  3,300                       1,100                    2,500                       1,400
Oklahoma Segment
Gathering and Transportation (MMbtu/d)                 996,900                   1,113,900                  983,700                   1,142,800
Processing (MMbtu/d)                                 1,004,400                   1,125,600                  999,900                   1,120,800
Crude Oil Handling (Bbls/d)                             20,000                      25,600                   20,400                      30,800
North Texas Segment
Gathering and Transportation (MMbtu/d)               1,377,600                   1,450,900                1,370,700                   1,505,100
Processing (MMbtu/d)                                   627,900                     669,000                  626,700                     679,800


Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020

Gross Margin. Gross margin was $126.9 million for the three months ended September 30, 2021 compared to $124.4 million for the three months ended September 30, 2020, an increase of $2.5 million. The primary contributors to the increase were as follows (in millions):

•Permian Segment. Gross margin was $33.7 million for the three months ended September 30, 2021 compared to $15.0 million for the three months ended September 30, 2020, an increase of $18.7 million primarily due to the following:

•Adjusted gross margin in the Permian segment increased $36.6 million, which was primarily driven by:


•A $34.2 million increase to adjusted gross margin associated with our Permian
gas assets. Adjusted gross margin, excluding derivative activity, increased
$32.8 million, which was primarily due to higher volumes from existing
customers. Derivative activity associated with our Permian gas assets increased
margin by $1.4 million, which included $11.9 million from increased unrealized
gains and was partially offset by $10.5 million from increased realized losses.
•A $2.4 million increase to adjusted gross margin associated with our Permian
crude assets. Adjusted gross margin, excluding derivative activity, increased
$2.8 million, which was primarily due to higher volumes from existing customers.
Derivative activity associated with our Permian crude assets decreased margin by
$0.4 million, which included $2.6 million from increased unrealized losses and
was partially offset by $2.2 million from increased realized gains.

•Operating expenses in the Permian segment increased $14.4 million primarily due
to increases in construction fees and services related to the relocation of the
War Horse processing plant, and higher materials and supplies expense and
compressor rentals due to higher volumes.

•Depreciation and amortization in the Permian segment increased $3.5 million
primarily due to new assets placed into service, including the Tiger processing
plant in August 2020 and gathering and processing assets associated with the
acquisition of Amarillo Rattler, LLC in April 2021.

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•Louisiana Segment. Gross margin was $29.1 million for the three months ended
September 30, 2021 compared to $28.8 million for the three months ended
September 30, 2020, an increase of $0.3 million primarily due to the following:

•Adjusted gross margin in the Louisiana segment decreased $2.6 million, resulting from:


•A $3.7 million decrease to adjusted gross margin associated with our Louisiana
gas assets. Adjusted gross margin, excluding derivative activity, increased $6.8
million, 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 the Jefferson Island storage facility in
December 2020. Derivative activity associated with our Louisiana gas assets
decreased margin by $10.5 million, which included $7.1 million from increased
unrealized losses and $3.4 million from increased realized losses.
•A $0.1 million decrease to adjusted gross margin associated with our ORV crude
assets. Adjusted gross margin, excluding derivative activity, increased $0.2
million, which was primarily due to higher volumes. Derivative activity
associated with our ORV crude assets decreased margin by $0.3 million due to
$0.3 million from increased realized losses.
•A $1.2 million increase to adjusted gross margin associated with our Louisiana
NGL transmission and fractionation assets. Adjusted gross margin, excluding
derivative activity, increased $10.8 million, which was primarily due to
favorable market prices on NGL sales. Derivative activity associated with our
Louisiana NGL transmission and fractionation assets decreased margin by $9.6
million, which included $10.6 million from increased realized losses and was
partially offset by $1.0 million from decreased unrealized losses.

•Operating expenses in the Louisiana segment decreased $0.6 million primarily due to decreased construction fees and services and ad valorem taxes. These increases were partially offset by higher utility costs.


•Depreciation and amortization in the Louisiana segment decreased $2.3 million
primarily due to changes in estimated useful lives of certain non-core assets
that were fully depreciated in the second quarter of 2021.

•Oklahoma Segment. Gross margin was $34.8 million for the three months ended September 30, 2021 compared to $52.8 million for the three months ended September 30, 2020, a decrease of $18.0 million primarily due to the following:

•Adjusted gross margin in the Oklahoma segment decreased $19.0 million, resulting from:


•A $18.3 million decrease to adjusted gross margin associated with our Oklahoma
gas assets. Adjusted gross margin, excluding derivative activity, decreased
$11.2 million, which was primarily due to a $13.7 million decrease in adjusted
gross margin resulting from the expiration of the MVC provision of a gathering
and processing contract at the end of 2020. Derivative activity associated with
our Oklahoma gas assets decreased margin by $7.1 million, which included $5.1
million from increased realized losses and $2.0 million from increased
unrealized losses.
•A $0.7 million decrease to adjusted gross margin associated with our Oklahoma
crude assets, which was primarily due to lower volumes from our existing
customers.

•Operating expenses in the Oklahoma segment decreased $0.3 million primarily due to reductions in compressor rentals.


•Depreciation and amortization in the Oklahoma segment decreased $0.7 million
primarily due to the relocation of the Battle Ridge processing plant to the War
Horse processing plant.

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•North Texas Segment. Gross margin was $31.5 million for the three months ended
September 30, 2021 compared to $29.5 million for the three months ended
September 30, 2020, an increase of $2.0 million primarily due to the following:

•Adjusted gross margin in the North Texas segment decreased $7.2 million.
Adjusted gross margin, excluding derivative activity, decreased $5.2 million,
which was primarily due to decreased revenues due to lower volumes from our
existing customers. Derivative activity associated with our North Texas segment
decreased margin by $2.0 million, which included $1.8 million from increased
realized losses and $0.2 million from increased unrealized losses.

•Operating expenses in the North Texas segment decreased $0.9 million primarily due to reductions in construction fees and services, ad valorem taxes, and compressor rentals.

•Depreciation and amortization in the North Texas segment decreased $8.3 million primarily due to a change in the estimated useful lives of certain non-core assets that were fully depreciated at the end of 2020.


•Corporate Segment. Gross margin was negative $2.2 million for the three months
ended September 30, 2021 compared to negative $1.7 million for the three months
ended September 30, 2020. Corporate gross margin consists of depreciation and
amortization of corporate assets.

General and Administrative Expenses. General and administrative expenses were
$28.2 million for the three months ended September 30, 2021 compared to $25.7
million for the three months ended September 30, 2020, an increase of $2.5
million. The increase was primarily due to labor and benefits costs, which
increased $4.1 million, and was partially offset by unit-based compensation
costs, which decreased $1.5 million.

Interest Expense. Interest expense was $60.1 million for the three months ended
September 30, 2021 compared to $55.5 million for the three months ended
September 30, 2020, an increase of $4.6 million. Interest expense consisted of
the following (in millions):
                                                                           Three Months Ended
                                                                              September 30,
                                                                         2021                  2020
ENLK and ENLC Senior Notes                                        $     50.3               $    43.3
Term Loan                                                                1.0                     3.6
Consolidated Credit Facility                                             1.3                     3.4
AR Facility                                                              1.0                       -
Capitalized interest                                                       -                    (0.6)

Amortization of debt issuance costs and net discount of senior unsecured notes

                                                          1.4                     0.9
Interest rate swap - realized                                            5.0                     4.6
Other                                                                    0.1                     0.3
Total                                                             $     60.1               $    55.5



Income (Loss) from Unconsolidated Affiliate Investments. Loss from
unconsolidated affiliate investments was $2.3 million for the three months ended
September 30, 2021 compared to loss of $0.2 million for the three months ended
September 30, 2020, an increased loss of $2.1 million. The increased loss was
primarily attributable to a reduction of income of $2.1 million from our GCF
investment, as a result of the GCF assets being temporarily idled beginning in
January 2021.

Income Tax Benefit (Expense). Income tax expense was $4.4 million for the three
months ended September 30, 2021 compared to an income tax expense of $6.0
million for the three months ended September 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 $30.4 million for the three months
ended September 30, 2021 compared to net income of $26.6 million for the three
months ended September 30, 2020, an increase of $3.8 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.

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Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30,
2020

Gross Margin. Gross margin was $336.2 million for the nine months ended September 30, 2021 compared to $362.6 million for the nine months ended September 30, 2020, a decrease of $26.4 million. The primary contributors to the decrease were as follows (in millions):

•Permian Segment. Gross margin was $52.4 million for the nine months ended September 30, 2021 compared to $31.8 million for the nine months ended September 30, 2020, an increase of $20.6 million primarily due to the following:

•Adjusted gross margin in the Permian segment increased $13.8 million, which was primarily driven by:


•A $12.6 million increase to adjusted gross margin associated with our Permian
gas assets. Adjusted gross margin, excluding derivative activity, increased
$90.1 million, which was primarily due to higher volumes and due to significant
favorable commodity prices on sales in our Permian gas assets from Winter Storm
Uri. Derivative activity associated with our Permian gas assets decreased margin
by $77.5 million, which included $75.1 million from increased realized losses
and $2.4 million from increased unrealized losses.
•A $1.2 million increase to adjusted gross margin associated with our Permian
crude assets. Adjusted gross margin, excluding derivative activity, decreased
$1.8 million, which was primarily due to weather disruptions from Winter Storm
Uri and storage fees earned in April of 2020 due to the negative futures price
of crude. Derivative activity associated with our Permian crude assets increased
margin by $3.0 million, which included $5.9 million from increased realized
gains and was partially offset by $2.9 million from decreased unrealized gains.

•Operating expenses in the Permian segment decreased $18.2 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
and benefits expense as a result of reductions in workforce in April 2020. These
decreases were partially offset by increases in construction fees and services
related to the relocation of the War Horse processing plant, increases in
materials and supplies expense and compressor rentals due to higher volumes, and
increases in sales and use taxes as a result of tax refunds in the first half of
2020.

•Depreciation and amortization in the Permian segment increased $11.4 million
primarily due to new assets placed into service, including the Tiger processing
plant in August 2020 and acquisition of the Amarillo Rattler, LLC gathering and
processing system in April 2021.

•Louisiana Segment. Gross margin was $106.4 million for the nine months ended September 30, 2021 compared to $95.5 million for the nine months ended September 30, 2020, an increase of $10.9 million primarily due to the following:

•Adjusted gross margin in the Louisiana segment increased $9.4 million, resulting from:


•A $12.1 million increase to adjusted gross margin associated with our Louisiana
NGL transmission and fractionation assets. Adjusted gross margin, excluding
derivative activity, increased $40.0 million, which was primarily due to
favorable market prices on NGL sales. Derivative activity associated with our
Louisiana NGL transmission and fractionation assets decreased margin by $27.9
million, which included $29.6 million from increased realized losses and was
partially offset by $1.7 million from decreased unrealized losses.
•A $2.5 million decrease to adjusted gross margin associated with our ORV crude
assets. Adjusted gross margin, excluding derivative activity, decreased $4.5
million, which was primarily due to lower volumes. Derivative activity
associated with our ORV crude assets increased margin by $2.0 million, which
included $1.1 million from increased unrealized gains and $0.9 million from
decreased realized losses.
•A $0.2 million decrease to adjusted gross margin associated with our Louisiana
gas assets. Adjusted gross margin, excluding derivative activity, increased
$18.6 million, 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 the Jefferson Island storage facility
in December 2020. Derivative activity associated with our Louisiana gas assets
decreased margin by $18.8
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million, which included $13.6 million from increased unrealized losses and $5.2
million from increased realized losses.

•Operating expenses in the Louisiana segment increased $1.0 million primarily
due to increased materials and supplies expense and utilities. This increase was
partially offset by lower labor and benefits expense as a result of reductions
in workforce in April 2020 and ad valorem taxes.

•Depreciation and amortization in the Louisiana segment decreased $2.5 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 $74.6 million for the nine months ended September 30, 2021 compared to $142.7 million for the nine months ended September 30, 2020, a decrease of $68.1 million primarily due to the following:

•Adjusted gross margin in the Oklahoma segment decreased $83.3 million, resulting from:


•A $82.2 million decrease to adjusted gross margin associated with our Oklahoma
gas assets. Adjusted gross margin, excluding derivative activity, decreased
$57.7 million, which was primarily due to lower volumes from our existing
customers, including weather disruptions from Winter Storm Uri, and a $38.6
million decrease in adjusted gross margin resulting from the expiration of the
MVC provision of a gathering and processing contract at the end of 2020.
Derivative activity associated with our Oklahoma gas assets decreased margin by
$24.5 million, which included $15.0 million from increased realized losses and
$9.5 million from increased unrealized losses.
•A $1.1 million decrease to adjusted gross margin associated with our Oklahoma
crude assets. Adjusted gross margin, excluding derivative activity, decreased
$4.6 million, which was primarily due to lower volumes from our existing
customers and partially as a result of weather disruptions from Winter Storm
Uri. Derivative activity associated with our Oklahoma crude assets increased
margin by $3.5 million, which included $2.5 million from increased unrealized
gains and $1.0 million from increased realized gains.

•Operating expenses in the Oklahoma segment decreased $5.1 million primarily due
to reductions in compressor rentals and lower labor and benefits expense as a
result of reductions in workforce in April 2020. These decreases were partially
offset by higher costs in 2021 to decommission equipment from the Battle Ridge
processing plant to be moved to the War Horse processing plant.

•Depreciation and amortization in the Oklahoma segment decreased $10.1 million
primarily due to the relocation of the Battle Ridge processing plant to the War
Horse processing plant.

•North Texas Segment. Gross margin was $108.8 million for the nine months ended September 30, 2021 compared to $98.4 million for the nine months ended September 30, 2020, an increase of $10.4 million primarily due to the following:


•Adjusted gross margin in the North Texas segment decreased $14.8 million.
Adjusted gross margin, excluding derivative activity, decreased $8.1 million,
which was primarily due to lower volumes from our existing customers. Derivative
activity associated with our North Texas segment decreased margin by $6.7
million, which included $4.9 million from increased realized losses and $1.8
million from increased unrealized losses.

•Operating expenses in the North Texas segment decreased $0.8 million primarily
due to reductions in compressor rentals, reductions to labor and benefits
expense as a result of reductions in workforce in April 2020, reductions to
utility costs, and reductions in ad valorem taxes. These decreases were
partially offset by increases in materials and supplies expense and operation
and maintenance costs, and increases in sales and use taxes as a result of tax
refunds in the first half of 2020.

•Depreciation and amortization in the North Texas segment decreased $24.4 million primarily due to a change in the estimated useful lives of certain non-core assets that were fully depreciated at the end of 2020.

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•Corporate Segment. Gross margin was negative $6.0 million for the nine months
ended September 30, 2021 compared to negative $5.8 million for the nine months
ended September 30, 2020. Corporate gross margin consists of depreciation and
amortization of corporate assets.

Impairments. For the nine months ended September 30, 2021, we did not recognize
an impairment expense. For the nine months ended September 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):
                                           Nine Months Ended
                                             September 30,
                                                  2020
Goodwill impairment                       $            184.6
Property and equipment impairment                      168.0
Cancelled projects                                       1.9
Total                                     $            354.5



General and Administrative Expenses. General and administrative expenses were
$80.3 million for the nine months ended September 30, 2021 compared to $79.6
million for the nine months ended September 30, 2020, an increase of $0.7
million. The increase was primarily due to labor and benefits costs, which
increased $2.3 million; transaction and transition costs, which increased $1.0
million primarily due to the Amarillo Rattler, LLC acquisition in April 2021;
franchise taxes, which increased $0.6 million primarily due to franchise tax
refunds in the first half of 2020; and $0.7 million from consulting fees and
services. These increases were partially offset by a $4.0 million decrease to
unit-based compensation costs.

Interest Expense. Interest expense was $180.1 million for the nine months ended September 30, 2021 compared to $166.3 million for the nine months ended September 30, 2020, an increase of $13.8 million, or 8.3%. Interest expense consisted of the following (in millions):

                                                                         Nine Months Ended
                                                                           September 30,
                                                                      2021                2020
ENLK and ENLC Senior Notes                                        $    150.9          $   130.6
Term Loan                                                                3.7               14.2
Consolidated Credit Facility                                             4.0               11.6
AR Facility                                                              3.0                  -
Capitalized interest                                                    (0.3)              (3.1)

Amortization of debt issuance costs and net discount of senior unsecured notes

                                                          3.9                3.1
Interest rate swap - realized                                           14.6                9.6
Other                                                                    0.3                0.3
Total                                                             $    180.1          $   166.3



Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt
of $32.0 million for the nine months ended September 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 $9.9 million for the nine months ended
September 30, 2021 compared to income of $0.8 million for the nine months ended
September 30, 2020, a decrease of income of $10.7 million. The decrease was
attributable to a reduction of income of $10.6 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 $12.4 million for the nine months
ended September 30, 2021 compared to an income tax benefit of $16.0 million for
the nine months ended September 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 $86.7 million for the nine months
ended September 30, 2021 compared to net income of $78.7 million for the nine
months ended September 30, 2020, an increase of $8.0 million. ENLC's
non-controlling interest is comprised of Series B Preferred Units,
                                       48

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Table of Contents 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 ended December 31,
2020 filed with the Commission on February 17, 2021.

Liquidity and Capital Resources


Cash Flows from Operating Activities. Net cash provided by operating activities
was $599.2 million for the nine months ended September 30, 2021 compared to
$561.0 million for the nine months ended September 30, 2020. Operating cash
flows and changes in working capital for comparative periods were as follows (in
millions):
                                                    Nine Months Ended
                                                      September 30,
                                                    2021          2020

Operating cash flows before working capital $ 559.5 $ 633.2 Changes in working capital

                            39.7        (72.2)



Operating cash flows before changes in working capital decreased $73.7 million
for the nine months ended September 30, 2021 compared to the nine months ended
September 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 $61.1 million.
For more information regarding the changes in gross margin for the nine months
ended September 30, 2021 compared to the nine months ended September 30, 2020,
see "Results of Operations."

•General and administrative expenses excluding unit-based compensation increased $4.7 million. For more information, see "Results of Operations."

•Interest expense, excluding amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, increased $3.5 million.


The changes in working capital for the nine months ended September 30, 2021
compared to the nine months ended September 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
$155.4 million for the nine months ended September 30, 2021 compared to $250.7
million for the nine months ended September 30, 2020. Investing cash flows are
primarily related to capital expenditures. Capital expenditures decreased from
$254.4 million for the nine months ended September 30, 2020 to $104.7 million
for the nine months ended September 30, 2021. The decrease in capital
expenditures was primarily due to the completion of major projects in 2020. The
decrease in investing cash flows was partially offset by $56.7 million related
to cash paid for the acquisition of assets, net of cash acquired, for the nine
months ended September 30, 2021.

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Cash Flows from Financing Activities. Net cash used in financing activities was
$447.3 million for the nine months ended September 30, 2021 compared to $308.8
million for the nine months ended September 30, 2020. Our primary financing
activities consisted of the following (in millions):
                                                                                     Nine Months Ended
                                                                                       September 30,
                                                                               2021                      2020
Net repayments on the Term Loan (1)                                    $      (200.0)              $            -
Net repayments on the AR Facility (1)                                           (5.0)                           -
Net repayments 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)                                   2.4                         52.2
Distribution to members                                                       (140.4)                      (186.2)
Distributions to Series B Preferred unitholders (3)                            (50.9)                       (50.4)
Distributions to Series C Preferred unitholders (3)                            (12.0)                       (12.0)
Distributions to joint venture partners (4)                                    (25.3)                       (21.8)
Common unit repurchases (5)                                                    (14.5)                           -


____________________________
(1)See "Item 1. Financial Statements-Note 5" for more information regarding the
Term Loan, the Consolidated Credit Facility, the AR Facility, and the senior
unsecured notes.
(2)Represents contributions from NGP to the Delaware 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 the Delaware 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 total capital expenditures and operating
expenses, related to the relocation of equipment and facilities, to be
approximately $225 million for 2021. We have incurred approximately $136 million
of capital expenditures and operating expenses, related to the relocation of
equipment and facilities, for the nine months ended September 30, 2021. Our
primary capital projects for the remainder of 2021 include the expansion of the
War Horse processing plant, the start of the relocation of the Phantom
processing plant, continued development of our existing systems through well
connects, and other low-cost development projects. We expect to fund our
remaining 2021 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.

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.

In August 2021, we received a $4.4 million grant from the Texas Commission on
Environmental Quality ("TCEQ") as a result of the TCEQ Emissions Reduction
Incentive Grant Program. This grant will allow us to seek reimbursements for
costs associated with upgrading compressor units that will result in reduced
nitrogen oxide levels.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2021.

                                       50

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Table of Contents Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2021 is as follows (in millions):

                                                                                        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)                            150.0                   150.0                -                -                -                -                   -
Consolidated Credit Facility (2)             -                       -                -                -                -                -                   -
AR Facility (3)                          245.0                       -                -                -            245.0                -                   -
Acquisition installment payable (4)       10.0                                     10.0                -                -                -              

-

Acquisition contingent consideration
(5)                                        6.9                       -                -                -              2.3              2.4              

2.2

Interest payable on fixed long-term
debt obligations                       2,409.6                    74.6            201.2            201.2            189.7            163.3             1,579.6
Operating lease obligations              113.2                     5.2             17.0             11.6             10.1              9.8                59.5
Purchase obligations                       4.4                     4.4                -                -                -                -                   -
Pipeline and trucking capacity and
deficiency agreements (6)                176.0                    12.4             46.6             38.7             29.2             24.8              

24.3

Inactive easement commitment (7)          10.0                       -             10.0                -                -                -                   -
Total contractual obligations        $ 7,157.4          $        246.6          $ 284.8          $ 251.5          $ 998.1          $ 921.1          $  4,455.3


____________________________
(1)The Term Loan matures on December 10, 2021.
(2)The Consolidated Credit Facility will mature on January 25, 2024. As of
September 30, 2021, there were no amounts outstanding under the Consolidated
Credit Facility.
(3)The AR Facility will terminate on September 24, 2024, unless extended or
earlier terminated in accordance with its terms.
(4)Amount related to the consideration of the Amarillo Rattler, LLC acquisition
due on April 30, 2022.
(5)The estimated fair value of the Amarillo 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. See "Item
1. Financial Statements-Note 12" for additional information.
(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 Consolidated Credit Facility,
and the AR Facility are not reflected in the above table because such amounts
depend on the outstanding balances and interest rates of the Term Loan, the
Consolidated Credit Facility, and the AR 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 Consolidated Credit Facility, the AR Facility, or other debt sources.

Indebtedness


In October 2020, we entered into the AR Facility, which was originally a
three-year committed accounts receivable securitization facility in the amount
of up to $250.0 million. On September 24, 2021, the SPV entered into the Second
Amendment to the Receivables Financing Agreement, which amended the AR Facility
to, among other things, increase the facility limit and lender commitments to
$350.0 million and extend the scheduled termination date to September 24, 2024.
As of September 30, 2021, the AR Facility had a borrowing base of $350.0 million
and there was $245.0 million in outstanding borrowings under the AR Facility.

In addition, as of September 30, 2021, we have $4.0 billion in aggregate
principal amount of outstanding unsecured senior notes maturing from 2024 to
2047 and $150.0 million in outstanding principal on the Term Loan. There were no
outstanding borrowings under the Consolidated Credit Facility and $41.1 million
outstanding letters of credit as of September 30, 2021.
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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 of September 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 February 17, 2021 for information on recently issued and adopted accounting pronouncements.

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, Winter Storm Uri, and other
weather related events 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
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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 ended December 31, 2020 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.

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