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

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

Overview



ENLC is a Delaware limited liability company formed in October 2013. ENLC's
assets consist of all of the outstanding common units of ENLK and all of the
membership interests of the General Partner. All of our midstream energy assets
are owned and operated by ENLK and its subsidiaries. We primarily focus on
providing midstream energy services, including:

•gathering, compressing, treating, processing, transporting, storing, and
selling natural gas;
•fractionating, transporting, storing, and selling NGLs; and
•gathering, transporting, stabilizing, storing, trans-loading, and selling crude
oil and condensate, in addition to brine disposal services.

Our midstream energy asset network includes approximately 12,000 miles of
pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of
processing capacity, seven fractionators with approximately 290,000 Bbls/d of
fractionation capacity, barge and rail terminals, product storage facilities,
purchasing and marketing capabilities, brine disposal wells, a crude oil
trucking fleet, and equity investments in certain joint ventures. We manage and
report our activities primarily according to the nature of activity and
geography. We have five reportable segments:

•Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico and our crude operations in South Texas;

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



•Oklahoma Segment. The Oklahoma segment includes our natural gas gathering,
processing, and transmission activities, and our crude oil operations in the
Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW
shale areas;

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

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate
investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in
South Texas, our derivative activity, and our general corporate assets and
expenses.

We manage our operations by focusing on gross operating margin because our
business is generally to gather, process, transport, or market natural gas,
NGLs, crude oil, and condensate using our assets for a fee. We earn our fees
through various fee-based contractual arrangements, which include stated
fee-only contract arrangements or arrangements with fee-based components where
we purchase and resell commodities in connection with providing the related
service and earn a net margin as our fee. We earn our net margin under our
purchase and resell contract arrangements primarily as a result of stated
service-related fees that are deducted from the price of the commodity purchase.
While our transactions vary in form, the essential element of most of our
transactions is the use of our assets to transport a product or provide a
processed product to an end-user or marketer at the tailgate of the plant,
pipeline, or barge, truck, or rail terminal. We define gross operating margin as
operating revenue minus cost of sales. Gross operating margin is a non-GAAP
financial measure and is explained in greater detail under "Non-GAAP Financial
Measures" below. Approximately 94% of our gross operating margin was derived
from fee-based contractual arrangements with minimal direct commodity price
exposure for the six months ended June 30, 2020. We reflect revenue as "Product
sales" and "Midstream services" on the consolidated statements of operations.
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The following customers individually represented greater than 10% of our
consolidated revenues. These 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 gross operating margin
received from transactions with these customers is material to us. No other
customers represented greater than 10% of our consolidated revenues.

                                                           Three Months Ended                                    Six Months Ended
                                                                June 30,                                             June 30,
                                                        2020                2019                2020                2019
Devon                                                     17.7  %                 (1)             15.0  %                 (1)
Dow Hydrocarbons and Resources LLC                        13.5  %             10.1  %             12.3  %             10.4  %
Marathon Petroleum Corporation                            10.3  %             15.2  %             14.8  %             14.7  %


____________________________

(1)Consolidated revenues for Devon did not exceed 10% of our consolidated revenues for the three and six months ended June 30, 2019.

Our revenues and gross operating margins are generated from eight primary sources:



•gathering and transporting natural gas, NGLs, and crude oil on the pipeline
systems we own;
•processing natural gas at our processing plants;
•fractionating and marketing recovered NGLs;
•providing compression services;
•providing crude oil and condensate transportation and terminal services;
•providing condensate stabilization services;
•providing brine disposal services; and
•providing natural gas, crude oil, and NGL storage.

We gather, transport, or store gas owned by others under fee-only contract
arrangements based either on the volume of gas gathered, transported, or stored
or, for firm transportation arrangements, a stated monthly fee for a specified
monthly quantity with an additional fee based on actual volumes. We also buy
natural gas from producers or shippers at a market index less a fee-based
deduction subtracted from the purchase price of the natural gas. We then gather
or transport the natural gas and sell the natural gas at a market index, thereby
earning a margin through the fee-based deduction. We attempt to execute
substantially all purchases and sales concurrently, or we enter into a future
delivery obligation, thereby establishing the basis for the fee we will receive
for each natural gas transaction. We are also party to certain long-term gas
sales commitments that we satisfy through supplies purchased under long-term gas
purchase agreements. When we enter into those arrangements, our sales
obligations generally match our purchase obligations. However, over time, the
supplies that we have under contract may decline due to reduced drilling or
other causes, and we may be required to satisfy the sales obligations by buying
additional gas at prices that may exceed the prices received under the sales
commitments. In our purchase/sale transactions, the resale price is generally
based on the same index at which the gas was purchased.

We typically buy mixed NGLs from our suppliers to our gas processing plants at a
fixed discount to market indices for the component NGLs with a deduction for our
fractionation fee. We subsequently sell the fractionated NGL products based on
the same index-based prices. To a lesser extent, we transport and fractionate or
store NGLs owned by others for a fee based on the volume of NGLs transported and
fractionated or stored. The operating results of our NGL fractionation business
are largely dependent upon the volume of mixed NGLs fractionated and the level
of fractionation fees charged. With our fractionation business, we also have the
opportunity for product upgrades for each of the discrete NGL products. We
realize higher gross operating margins from product upgrades during periods with
higher NGL prices.

We gather or transport crude oil and condensate owned by others by rail, truck,
pipeline, and barge facilities under fee-only contract arrangements based on
volumes gathered or transported. We also buy crude oil and condensate on our own
gathering systems, third-party systems, and trucked from producers at a market
index less a stated transportation deduction. We then transport and resell the
crude oil and condensate through a process of basis and fixed price trades. We
execute substantially all purchases and sales concurrently, thereby establishing
the net margin we will receive for each crude oil and condensate transaction.

We realize gross operating margins from our gathering and processing services
primarily through different contractual arrangements: processing margin
("margin") contracts, POL contracts, POP contracts, fixed-fee component
contracts, or a combination of these contractual arrangements. "See Item 3.
Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk"
for a detailed description of these contractual arrangements. Under any of these
gathering and
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processing arrangements, we may earn a fee for the services performed, or we may
buy and resell the gas and/or NGLs as part of the processing arrangement and
realize a net margin as our fee. Under margin contract arrangements, our gross
operating margins are higher during periods of high NGL prices relative to
natural gas prices. Gross operating margin results under POL contracts are
impacted only by the value of the liquids produced with margins higher during
periods of higher liquids prices. Gross operating margin results under POP
contracts are impacted only by the value of the natural gas and liquids produced
with margins higher during periods of higher natural gas and liquids prices.
Under fixed-fee based contracts, our gross operating margins are driven by
throughput volume.

Operating expenses are costs directly associated with the operations of a
particular asset. Among the most significant of these costs are those associated
with direct labor and supervision, property insurance, property taxes, repair
and maintenance expenses, contract services, and utilities. These costs are
normally fairly stable across broad volume ranges and therefore do not normally
increase or decrease significantly in the short term with increases or decreases
in the volume of gas, liquids, crude oil, and condensate moved through or by our
assets.

Recent Developments Affecting Industry Conditions and Our Business



On March 11, 2020, the World Health Organization declared the ongoing
coronavirus (COVID-19) outbreak a pandemic and recommended containment and
mitigation measures worldwide. The pandemic has now reached every region of the
globe and has resulted in widespread adverse impacts on the global economy, on
the energy industry as a whole and on midstream companies, and on our customers,
suppliers, and other parties with whom we have business relations. The pandemic
and related travel and operational restrictions, as well as business closures
and curtailed consumer activity, have resulted in a reduction in global demand
for condensate, natural gas, and NGLs and especially crude oil. While reductions
in global demand for natural gas and NGLs were never as severe as for crude oil
and the demand for crude oil has recovered from the steepest drops in April and
May, global demand for energy is still reduced as of the date of this report
from levels before the pandemic in mid-February. The decline in demand, coupled
with the failure of OPEC+ to quickly agree on oil production cuts, resulted in a
decline in the market price for these commodities, most severely for crude oil.
Although OPEC+ agreed to production cuts in April, extended these cuts through
July, and are expected to continue the production cuts beyond July, although at
a more moderate level, and although United States oil producers have also
curtailed their drilling programs, these cuts have not been enough to fully
offset demand loss attributable to the COVID-19 pandemic and market prices
remain lower than prior to the pandemic.

As a result of the supply/demand imbalance, reduced commodity prices, and an
uncertain timeline for recovery, oil and natural gas producers, including many
of our customers, have curtailed their current drilling and production activity,
including in some cases by shutting-in production, as well as reducing their
plans for future drilling and production activity. As a result of these
decreases in producer activity, we have experienced reduced volumes gathered,
processed, fractionated, and transported on our assets in some of the regions
that supply our systems.

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. We
have implemented preventative measures and developed a response plan to minimize
unnecessary risk of exposure and prevent infection, while supporting our
customers' operations. We have a crisis management team for health, safety and
environmental matters and personnel issues, and we have established a
cross-functional COVID-19 response team to address various impacts of the
situation, as they have been developing. We also have modified certain business
practices (including discontinuing all non-essential business travel,
implementing a temporary work-from-home policy for employees who can execute
their work remotely, and encouraging employees to adhere to local and regional
social distancing recommendations) to support efforts to reduce the spread of
COVID-19 and to conform to government restrictions and best practices encouraged
by the Centers for Disease Control and Prevention, the World Health
Organization, and other governmental and regulatory authorities. We also have
promoted heightened awareness and vigilance, hygiene, and implementation of more
stringent cleaning protocols across our facilities and operations. We continue
to evaluate and adjust these preventative measures, response plans and business
practices with the evolving impacts of COVID-19.

There is considerable uncertainty regarding how long COVID-19 will persist and
affect economic conditions and the extent and duration of changes in consumer
behavior, such as the reluctance to travel, as well as governmental and other
measures implemented to try to slow the spread of the virus, such as large-scale
travel bans and restrictions, border closures, quarantines, shelter-in-place
orders, and business and government shutdowns. As a result, there is significant
uncertainty regarding how long the market dislocations will continue and how
significantly and how long they will continue to affect us. We expect to see
continued volatility in crude oil, condensate, natural gas, and NGL prices for
the foreseeable future, which may, over the long term, adversely impact our
business. A sustained significant decline in oil and natural gas exploration and
production activities and related reduced demand for our services by our
customers, whether due to decreases in consumer demand or reduction in the
prices for oil, condensate natural gas and NGLs or otherwise, would have a
material adverse effect on our business, liquidity, financial condition, results
of operations, and cash flows (including our ability to make distributions to
our unitholders).

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As of the date of this report, our efforts to respond to the challenges
presented by the conditions described above and minimize the impacts to our
business have yielded results. Our systems, pipelines, and facilities have
remained operational. We have also moved quickly and decisively, and we continue
to adapt and respond promptly, to implement strategies to reduce costs, increase
operational efficiencies, and lower our capital spending. As we previously
announced, we intend to reduce our capital expenditures in 2020, including both
growth and maintenance capital expenditures, to between $190 million and $250
million, a 65% reduction from 2019 total capital spending. We have also reduced
costs across our platform and we intend to reduce our general and administrative
and operational expenses by $120 million for the full-year 2020 versus the
twelve months ended December 31, 2019. Also, as of June 30, 2020, we had
approximately $52 million of cash on our balance sheet and have drawn only
approximately $400 million on the $1.75 billion Consolidated Credit Facility. We
have not requested any funding under any federal or other governmental programs
to support our operations, and we do not expect to utilize any such funding. We
are continuing to address concerns to protect the health and safety of our
employees and those of our customers and other business counterparties, and this
includes changes to comply with health-related guidelines as they are modified
and supplemented.

We cannot predict the full impact that COVID-19 or the significant disruption
and volatility currently being experienced in the oil and natural gas markets
will have on our business, liquidity, financial condition, results of
operations, and cash flows (including our ability to make distributions to
unitholders) at this time due to numerous uncertainties. The ultimate impacts
will depend on future developments, including, among others, the ultimate
duration and persistence of the outbreak, the effect of the outbreak on
economic, social and other aspects of everyday life, the consequences of
governmental and other measures designed to prevent the spread of the virus, the
development and timing of effective treatments and vaccines, actions taken by
members of OPEC+ and other foreign, oil-exporting countries, actions taken by
governmental authorities, customers, suppliers, and other third parties,
workforce availability, and the timing and extent to which normal economic,
social and operating conditions resume.

For additional discussion regarding risks associated with the COVID-19 pandemic,
see Part II, Item 1A "Risk Factors" in our Quarterly Report on Form 10-Q for the
quarter ended March 31, 2020.

Other Recent Developments

Riptide Processing Plant. In March 2020, we completed construction of a 55 MMcf/d expansion to our Riptide processing plant in the Midland Basin, bringing the total operational processing capacity at the plant to 220 MMcf/d.

Delaware Basin Processing Plant. In August 2019, we commenced construction of
our Tiger Plant, which will expand our Delaware Basin processing capacity by an
additional 200 MMcf/d. We expect the plant to be operational in the third
quarter of 2020. This processing plant is owned by the Delaware Basin JV.

Non-GAAP Financial Measures



To assist management in assessing our business, we use the following non-GAAP
financial measures: Adjusted earnings before interest, taxes, and depreciation
and amortization ("adjusted EBITDA"), distributable cash flow available to
common unitholders ("distributable cash flow"), excess free cash flow, and gross
operating margin.

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net
of interest income; depreciation and amortization; impairments; loss on secured
term loan receivable, (income) loss from unconsolidated affiliates;
distributions from unconsolidated affiliates; (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; (payments
under onerous performance obligation); transaction costs; accretion expense
associated with asset retirement obligations; (non-cash rent); and
(non-controlling interest share of adjusted EBITDA from joint ventures).
Adjusted EBITDA is a primary metric used in our short-term incentive program for
compensating employees. In addition, adjusted EBITDA is used as a supplemental
liquidity and performance measure by our management and by external users of our
financial statements, such as investors, commercial banks, research analysts,
and others, to assess:

•the financial performance of our assets without regard to financing methods,
capital structure, or historical cost basis;
•the ability of our assets to generate cash sufficient to pay interest costs,
support our indebtedness, and make cash distributions to our unitholders;
•our operating performance and return on capital as compared to those of other
companies in the midstream energy sector, without regard to financing methods or
capital structure; and
•the viability of acquisitions and capital expenditure projects and the overall
rates of return on alternative investment opportunities.

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The GAAP measures most directly comparable to adjusted EBITDA are net income
(loss) and net cash provided by operating activities. Adjusted EBITDA should not
be considered an alternative to, or more meaningful than, net income (loss),
operating income (loss), net cash provided by operating activities, or any other
measure of financial performance presented in accordance with GAAP. Adjusted
EBITDA may not be comparable to similarly titled measures of other companies
because other companies may not calculate adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, net of interest income;
income tax expense (benefit); and depreciation and amortization. Because we have
borrowed money to finance our operations, interest expense is a necessary
element of our costs and our ability to generate cash available for
distribution. Because we use capital assets, depreciation and amortization are
also necessary elements of our costs. Therefore, any measures that exclude these
elements have material limitations. To compensate for these limitations, we
believe that it is important to consider net income (loss) and net cash provided
by operating activities as determined under GAAP, as well as adjusted EBITDA, to
evaluate our overall performance.

The following table reconciles adjusted EBITDA to net income (loss) (in
millions):
                                                              Three Months Ended                                Six Months Ended
                                                                   June 30,                                         June 30,
                                                             2020              2019             2020               2019
Net income (loss)                                        $    29.8          $   9.1          $ (230.6)         $  (125.7)
Interest expense, net of interest income                      55.2             54.3             110.8              103.9
Depreciation and amortization                                158.2            153.7             321.0              305.8
Impairments                                                    1.5                -             354.5              186.5
Loss on secured term loan receivable (1)                         -             52.9                 -               52.9
(Income) loss from unconsolidated affiliates                   0.7             (4.7)             (1.0)             (10.0)
Distributions from unconsolidated affiliates                   0.2              7.6               2.0               10.1
Loss on disposition of assets                                  5.2              0.1               4.6                0.1
Gain on extinguishment of debt                               (26.7)               -             (32.0)                 -
Unit-based compensation                                        7.4              8.0              16.2               19.1
Income tax expense (benefit)                                  11.7             (5.4)            (22.0)              (3.6)
Unrealized (gain) loss on commodity swaps                     18.8             (7.2)              5.8               (5.2)

Payments under onerous performance obligation offset to other current and long-term liabilities

                          -             (4.5)                -               (9.0)
Transaction costs (2)                                            -              0.4                 -               13.9
Other (3)                                                     (0.4)             0.1              (0.5)               0.4
Adjusted EBITDA before non-controlling interest              261.6            264.4             528.8              539.2
Non-controlling interest share of adjusted EBITDA from
joint ventures (4)                                            (6.5)            (5.2)            (13.7)             (11.8)
Adjusted EBITDA, net to ENLC                             $   255.1          $ 259.2          $  515.1          $   527.4


____________________________
(1)In May 2018, we restructured our natural gas gathering and processing
contract with White Star, and, as a result, recognized the discounted present
value of a secured term loan receivable granted to us by White Star. We recorded
a $52.9 million loss in our consolidated statement of operations for the three
and six months ended June 30, 2019 related to the write-off of the secured term
loan receivable.
(2)Represents transaction costs attributable to costs incurred related to the
Merger in January 2019.
(3)Includes accretion expense associated with asset retirement obligations and
non-cash rent, which relates to lease incentives pro-rated over the lease term.
(4)Non-controlling interest share of adjusted EBITDA from joint ventures
includes NGP's 49.9% share of adjusted EBITDA from the Delaware Basin JV,
Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension
JV, and other minor non-controlling interests.

Distributable Cash Flow and Excess Free Cash Flow



We define distributable cash flow as adjusted EBITDA, net to ENLC, less interest
expense, net of interest income; maintenance capital expenditures, excluding
maintenance capital expenditures that were contributed by other entities and
relate to the non-controlling interest share of our consolidated entities;
accrued cash distributions on Series B Preferred Units and Series C Preferred
Units paid or expected to be paid; non-cash interest income; and current income
taxes. Excess free cash flow
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is defined as distributable cash flow less distributions declared on common
units and growth capital expenditures, excluding growth capital expenditures
that were contributed by other entities and relate to the non-controlling
interest share of our consolidated joint ventures.

Distributable cash flow and excess free cash flow are used as supplemental
liquidity measures by our management and by external users of our financial
statements, such as investors, commercial banks, research analysts, and others,
to assess the ability of our assets to generate cash sufficient to pay interest
costs, support our indebtedness, make cash distributions, and make capital
expenditures.

Maintenance capital expenditures include capital expenditures made to replace
partially or fully depreciated assets in order to maintain the existing
operating capacity of the assets and to extend their useful lives. Examples of
maintenance capital expenditures are expenditures to refurbish and replace
pipelines, gathering assets, well connections, compression assets, and
processing assets up to their original operating capacity, to maintain pipeline
and equipment reliability, integrity, and safety, and to address environmental
laws and regulations.

Growth capital expenditures generally include capital expenditures made for
acquisitions or capital improvements that we expect will increase our asset
base, operating income, or operating capacity over the long-term. Examples of
growth capital expenditures include the acquisition of assets and the
construction or development of additional pipeline, storage, well connections,
gathering, or processing assets, in each case, to the extent such capital
expenditures are expected to expand our asset base, operating capacity, or our
operating income.

The GAAP measure most directly comparable to distributable cash flow and excess
free cash flow is net cash provided by operating activities. Distributable cash
flow and excess free cash flow should not be considered alternatives to, or more
meaningful than, net income (loss), operating income (loss), net cash provided
by operating activities, or any other measure of liquidity presented in
accordance with GAAP. Distributable cash flow and excess free cash flow have
important limitations because they exclude some items that affect net income
(loss), operating income (loss), and net cash provided by operating activities.
Distributable cash flow and excess free cash flow may not be comparable to
similarly titled measures of other companies because other companies may not
calculate these non-GAAP metrics in the same manner. To compensate for these
limitations, we believe that it is important to consider net cash provided by
operating activities determined under GAAP, as well as distributable cash flow
and excess free cash flow, to evaluate our overall liquidity.

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The following table reconciles excess free cash flow, distributable cash flow,
and adjusted EBITDA to net cash provided by operating activities (in millions):
                                                           Three Months Ended                               Six Months Ended
                                                                June 30,                                        June 30,
                                                         2020              2019              2020              2019
Net cash provided by operating activities             $  134.8          $  257.5          $ 316.8          $   521.5
Interest expense (1)                                      54.0              53.9            108.7              103.4
Current income tax expense                                 0.4               0.3              0.7                1.3
Transaction costs (2)                                        -               0.4                -               13.9
Other (3)                                                 (5.1)              1.6              0.5                0.1
Changes in operating assets and liabilities which
(provided) used cash:
Accounts receivable, accrued revenues, inventories,
and other                                                 50.2            (165.9)          (119.1)            (263.3)
Accounts payable, accrued product purchases, and
other accrued liabilities (4)                             27.3             116.6            221.2              162.3
Adjusted EBITDA before non-controlling interest          261.6             264.4            528.8              539.2
Non-controlling interest share of adjusted EBITDA
from joint ventures (5)                                   (6.5)             (5.2)           (13.7)             (11.8)
Adjusted EBITDA, net to ENLC                             255.1             259.2            515.1              527.4
Interest expense, net of interest income                 (55.2)            (54.3)          (110.8)            (103.9)
Maintenance capital expenditures, net to ENLC (6)         (7.7)            (13.2)           (15.9)             (21.7)
ENLK preferred unit accrued cash distributions (7)       (22.8)            (23.1)           (45.6)             (45.8)
Other (8)                                                 (0.3)             (1.0)            (0.6)              (3.5)
Distributable cash flow                                  169.1             167.6            342.2              352.5
Common distributions declared                            (46.4)           (139.3)           (92.9)            (276.6)
Growth capital expenditures, net to ENLC (6)             (50.7)           (141.9)          (133.3)            (361.5)
Excess free cash flow                                 $   72.0          $ (113.6)         $ 116.0          $  (285.6)

____________________________


(1)Net of amortization of debt issuance costs and discount and premium, which
are included in interest expense but not included in net cash provided by
operating activities, and non-cash interest income, which is netted against
interest expense but not included in adjusted EBITDA.
(2)Represents transaction costs attributable to costs incurred related to the
Merger in January 2019.
(3)Includes accruals for settled commodity swap transactions, distributions
received from equity method investments to the extent those distributions exceed
earnings from the investment, and non-cash rent, which relates to lease
incentives pro-rated over the lease term.
(4)Net of payments under onerous performance obligation offset to other current
and long-term liabilities during the three and six months ended June 30, 2019.
(5)Non-controlling interest share of adjusted EBITDA from joint ventures
includes NGP's 49.9% share of adjusted EBITDA from the Delaware Basin JV,
Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension
JV, and other minor non-controlling interests.
(6)Excludes capital expenditures that were contributed by other entities and
relate to the non-controlling interest share of our consolidated entities.
(7)Represents the cash distributions earned by the Series B Preferred Units and
Series C Preferred Units. 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.
(8)Includes non-cash interest income and current income tax expense.
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Gross Operating Margin

We define gross operating margin as revenues less cost of sales. We present
gross operating margin by segment in "Results of Operations." We disclose gross
operating margin in addition to total revenue because it is the primary
performance measure used by our management. We believe gross operating margin is
an important measure because, in general, our business is to gather, process,
transport, or market natural gas, NGLs, condensate, and crude oil for a fee or
to purchase and resell natural gas, NGLs, condensate, and crude oil for a
margin. Operating expense is a separate measure used by our management to
evaluate operating performance of field operations. Direct labor and
supervision, property insurance, property taxes, repair and maintenance,
utilities, and contract services comprise the most significant portion of our
operating expenses. We do not deduct operating expenses from total revenue in
calculating gross operating margin because these expenses are largely
independent of the volumes we transport or process and fluctuate depending on
the activities performed during a specific period. The GAAP measure most
directly comparable to gross operating margin is operating income (loss). Gross
operating margin should not be considered an alternative to, or more meaningful
than, operating income (loss) as determined in accordance with GAAP. Gross
operating margin has important limitations because it excludes all operating
costs that affect operating income (loss) except cost of sales. Our gross
operating margin may not be comparable to similarly titled measures of other
companies because other entities may not calculate these amounts in the same
manner.

The following table provides a reconciliation of operating income (loss) to gross operating margin (in millions):


                                           Three Months Ended                           Six Months Ended
                                                June 30,                                    June 30,
                                           2020           2019          2020               2019
Operating income (loss)                $    70.7       $  53.1       $ (174.8)      $        (35.6)

Add:
Operating expenses                          88.1         117.9          188.8                232.4
General and administrative expenses         23.5          32.2           53.9                 83.6
Loss on disposition of assets                5.2           0.1            4.6                  0.1
Depreciation and amortization              158.2         153.7          321.0                305.8
Impairments                                  1.5             -          354.5                186.5
Loss on secured term loan receivable           -          52.9              -                 52.9
Gross operating margin                 $   347.2       $ 409.9       $  748.0       $        825.7



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Results of Operations

The table below sets forth certain financial and operating data for the periods
indicated. We manage our operations by focusing on gross operating margin, which
we define as revenue less cost of sales as reflected in the table below (in
millions, except volumes):
                                                         Three Months Ended                                       Six Months Ended
                                                              June 30,                                                June 30,
                                                      2020                2019                2020                   2019
Permian Segment
Revenues                                         $     204.6          $    742.3          $    576.3          $       1,484.9
Cost of sales                                         (138.4)             (680.5)             (452.3)                (1,356.7)
Total gross operating margin                     $      66.2          $     61.8          $    124.0          $         128.2
North Texas Segment
Revenues                                         $     106.4          $    149.8          $    227.1          $         324.1
Cost of sales                                          (18.9)              (51.0)              (45.9)                  (124.7)
Total gross operating margin                     $      87.5          $     98.8          $    181.2          $         199.4
Oklahoma Segment
Revenues                                         $     179.8          $    299.2          $    399.8          $         618.9
Cost of sales                                          (61.1)             (159.4)             (154.8)                  (343.6)
Total gross operating margin                     $     118.7          $    139.8          $    245.0          $         275.3
Louisiana Segment
Revenues                                         $     409.7          $    730.5          $    973.2          $       1,528.6
Cost of sales                                         (312.5)             (627.9)             (772.2)                (1,314.5)
Total gross operating margin                     $      97.2          $    102.6          $    201.0          $         214.1
Corporate Segment
Revenues                                         $    (155.6)         $   (211.8)         $   (275.4)         $        (467.3)
Cost of sales                                          133.2               218.7               272.2                    476.0
Total gross operating margin                     $     (22.4)         $      6.9          $     (3.2)         $           8.7
Total
Revenues                                         $     744.9          $  1,710.0          $  1,901.0          $       3,489.2
Cost of sales                                         (397.7)           (1,300.1)           (1,153.0)                (2,663.5)
Total gross operating margin                     $     347.2          $    

409.9 $ 748.0 $ 825.7



Midstream Volumes:
Permian Segment
Gathering and Transportation (MMBtu/d)               871,500             676,000             851,300                  666,800
Processing (MMBtu/d)                                 896,100             724,100             878,900                  718,100
Crude Oil Handling (Bbls/d)                          112,300             145,100             122,900                  146,200
North Texas Segment
Gathering and Transportation (MMBtu/d)             1,485,900           1,646,900           1,531,800                1,664,900
Processing (MMBtu/d)                                 670,600             770,100             685,200                  750,100
Oklahoma Segment
Gathering and Transportation (MMBtu/d)             1,092,600           1,314,900           1,156,800                1,279,800
Processing (MMBtu/d)                               1,082,100           1,298,800           1,118,300                1,265,400
Crude Oil Handling (Bbls/d)                           30,000              53,800              33,300                   41,600
Louisiana Segment
Gathering and Transportation (MMBtu/d)             1,873,600           1,925,900           1,958,400                1,997,800
Processing (MMBtu/d)                                 197,200             337,100             183,400                  402,200
Crude Oil Handling (Bbls/d)                           15,700              20,000              16,600                   17,500
NGL Fractionation (Gals/d)                         7,344,800           7,477,400           7,764,500                7,227,000
Brine Disposal (Bbls/d)                                1,400               3,400               1,600                    3,400


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Table of Contents Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019



Gross Operating Margin. Gross operating margin was $347.2 million for the three
months ended June 30, 2020 compared to $409.9 million for the three months ended
June 30, 2019, a decrease of $62.7 million, or 15.3%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment increased $4.4
million, resulting from (i) a $2.5 million increase in gross operating margin
from our Permian crude assets primarily attributable to volume growth in our
Delaware Basin assets, which was partially offset by the expiration of an MVC
related to our South Texas assets in July 2019, and (ii) a $1.9 million increase
in gross operating margin from our Permian gas assets primarily attributable to
volume growth.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $11.3 million, which was primarily due to volume declines resulting from limited new drilling in the region.

•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased $21.1 million, primarily due to lower volumes from well shut-ins from our customers.

•Louisiana Segment. Gross operating margin in the Louisiana segment decreased $5.4 million, resulting from:



•A $4.7 million decrease from our Louisiana gas assets due to lower processing
margins and volumes attributable to a less favorable processing environment, the
expiration of certain firm transportation contracts, and decreased volumes.
•A $4.3 million decrease from our ORV crude assets primarily due to lower
volumes.
•A $3.6 million increase from our NGL transmission and fractionation assets,
which was primarily due to a settlement payment received as the result of a
contract dispute.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $29.3 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


                                              Three Months Ended
                                                   June 30,
                                              2020           2019
Realized swaps:
Crude swaps                               $     (2.4)      $ (2.5)
NGL swaps                                       (0.4)         3.7
Gas swaps                                       (0.8)        (1.5)
Realized loss on derivatives                    (3.6)        (0.3)

Unrealized swaps:
Crude swaps                                     (3.6)         4.9
NGL swaps                                      (14.4)         1.3
Gas swaps                                       (0.8)         1.0
Change in fair value of derivatives            (18.8)         7.2

Gain (loss) on derivatives                $    (22.4)      $  6.9



Certain gathering and processing agreements provide for quarterly or annual
MVCs. Under these agreements, our customers agree to ship and/or process a
minimum volume of commodity on our systems over an agreed time period. If a
customer under such an agreement fails to meet its MVC for a specified period,
the customer is obligated to pay a contractually determined fee based upon the
shortfall between actual commodity volumes and the MVC for that period. Some of
these agreements also contain make-up right provisions that allow a customer to
utilize gathering or processing fees in excess of the MVC in subsequent periods
to offset shortfall amounts in previous periods. We record revenue under MVC
contracts during periods of shortfall when it is known that the customer cannot,
or will not, make up the deficiency in subsequent periods.

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Revenue recorded for the shortfall between actual production volumes and the MVC
is as follows (in millions):
                          Three Months Ended
                               June 30,
                              2020                     2019
Permian Segment       $           (1.7)              $ 3.9
Oklahoma Segment                  15.1                   -
Total                 $           13.4               $ 3.9

Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020.



Operating Expenses. Operating expenses were $88.1 million for the three months
ended June 30, 2020 compared to $117.9 million for the three months ended
June 30, 2019, a decrease of $29.8 million, or 25.3%. The primary contributors
to the total decrease by segment were as follows (in millions):
                          Three Months Ended
                               June 30,                               Change
                          2020           2019           $             %

Permian Segment $ 22.7 $ 28.4 $ (5.7) (20.1) % North Texas Segment 18.5

           25.8          (7.3)       (28.3) %
Oklahoma Segment          19.4           26.1          (6.7)       (25.7) %
Louisiana Segment         27.5           37.6         (10.1)       (26.9) %
Total                 $   88.1        $ 117.9       $ (29.8)       (25.3) %



•Permian Segment. Operating expenses in the Permian segment decreased $5.7
million primarily due to decreased labor and benefits expense as a result of a
reduction in workforce in April 2020 and reductions in construction fees and
services, and sales and use tax.

•North Texas Segment. Operating expenses in the North Texas segment decreased
$7.3 million primarily due to decreased labor and benefits expense as a result
of a reduction in workforce in April 2020 and reductions in operations and
maintenance, ad valorem tax, sales and use tax, and compressor rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $6.7
million primarily due to decreased labor and benefits expense as a result of a
reduction in workforce in April 2020 and reductions in materials and supplies
expense, operations and maintenance, construction fees and services, and
compressor and treater rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $10.1
million primarily due to decreased labor and benefits expense as a result of a
reduction in workforce in April 2020 and reductions in materials and supplies
expense, utilities, construction fees and services, ad valorem tax, and vehicle
expenses.

General and Administrative Expenses. General and administrative expenses were
$23.5 million for the three months ended June 30, 2020 compared to $32.2 million
for the three months ended June 30, 2019, a decrease of $8.7 million, or 27.0%.
The primary contributors to the decrease were as follows:

•Labor costs and unit-based compensation costs decreased $3.8 million, which was primarily due to a reduction in workforce in April 2020.

•Expenses related to fees and services, travel, rents and leases, and insurance decreased $3.2 million primarily due to general cost saving initiatives and decreased activity as a result of COVID-19.



Depreciation and Amortization. Depreciation and amortization was $158.2 million
for the three months ended June 30, 2020 compared to $153.7 million for the
three months ended June 30, 2019, an increase of $4.5 million, or 2.9%. This
increase was primarily due to new assets placed in service in the Permian,
Oklahoma, and Louisiana segments, as well as accelerated depreciation on certain
non-core assets. These increases were partially offset by the impairment of
Louisiana segment assets in the first quarter of 2020 and the conclusion of a
finance lease in the North Texas segment in 2019.

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Impairments. For the three months ended June 30, 2020, we recognized a $1.5
million impairment on property and equipment related to cancelled projects. See
"Item 1. Financial Statements-Note 2" for additional information on our property
and equipment impairments.

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt
of $26.7 million for the three months ended June 30, 2020 due to repurchases of
the 2024, 2025, 2026, and 2029 Notes in open market transactions. See "Item 1.
Financial Statements-Note 5" for additional information.

Interest Expense. Interest expense was $55.2 million for the three months ended
June 30, 2020 compared to $54.3 million for the three months ended June 30,
2019, an increase of $0.9 million, or 1.7%. Interest expense consisted of the
following (in millions):
                                                                           Three Months Ended
                                                                                June 30,
                                                                         2020               2019
ENLK and ENLC Senior Notes                                           $    43.3           $   43.4
Term Loan                                                                  4.2                8.5
Consolidated Credit Facility                                               4.1                3.7
Capitalized interest                                                      (1.3)              (1.8)
Amortization of debt issue costs and net discounts (premiums)              1.2                1.0
Interest rate swap                                                         3.7               (0.3)
Other                                                                        -               (0.2)
Total                                                                $    55.2           $   54.3



Income (Loss) from Unconsolidated Affiliate Investments. Loss from
unconsolidated affiliate investments was $0.7 million for the three months ended
June 30, 2020 compared to income of $4.7 million for the three months ended
June 30, 2019, a decrease of $5.4 million. The decrease was primarily
attributable to a reduction of income of $4.9 million from our GCF investment as
a result of lower fractionation revenues and lower operating expenses and a
reduction of income of $0.5 million from our Cedar Cove JV.

Income Tax Expense. Income tax expense was $11.7 million for the three months
ended June 30, 2020 compared to an income tax benefit of $5.4 million for the
three months ended June 30, 2019. The increase in income tax expense was
primarily attributable to higher income between periods and tax deficiencies
recorded upon the vesting of restricted incentive units. See "Item 1. Financial
Statements-Note 6" for additional information.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019



Gross Operating Margin. Gross operating margin was $748.0 million for the six
months ended June 30, 2020 compared to $825.7 million for the six months ended
June 30, 2019, a decrease of $77.7 million, or 9.4%, due to the following:

•Permian Segment. Gross operating margin in the Permian segment decreased $4.2 million, resulting from:



•An $11.6 million decrease due to the expiration of an MVC related to our South
Texas assets in July 2019.
•A $3.7 million increase due to volume growth in our Midland Basin crude assets.
•A $2.9 million increase due to volume growth in our Delaware Basin crude
assets.
•A $1.9 million decrease related to our Midland Basin gas assets.
•A $2.7 million increase related to our Delaware Basin gas assets.

•North Texas Segment. Gross operating margin in the North Texas segment decreased $18.2 million, which was primarily due to volume declines resulting from limited new drilling in the region.



•Oklahoma Segment. Gross operating margin in the Oklahoma segment decreased
$30.3 million. Gross operating margin contributed by our Oklahoma gas assets
decreased $31.2 million, which was partially due to lower volumes from our
existing customers, and was partially offset by a $0.9 million increase in gross
operating margin contributed by our Oklahoma crude assets.

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•Louisiana Segment. Gross operating margin in the Louisiana segment decreased
$13.1 million, resulting from:

•A $12.4 million decrease from our Louisiana gas assets due to lower processing
margins and volumes attributable to a less favorable processing environment, the
expiration of certain firm transportation contracts, and decreased volumes.
•A $6.1 million decrease from our ORV crude assets primarily due to lower
volumes.
•A $5.4 million increase from our NGL transmission and fractionation assets,
which was primarily due to higher volumes that resulted from the completion of
the Cajun-Sibon pipeline expansion in April 2019 and a settlement payment
received as the result of a contract dispute.

•Corporate Segment. Gross operating margin in the Corporate segment decreased $11.9 million, which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions):


                                              Six Months Ended
                                                  June 30,
                                              2020          2019
Realized swaps:
Crude swaps                               $    (3.0)      $ 0.8
NGL swaps                                       6.3         5.6
Gas swaps                                      (0.7)       (2.9)
Realized gain on derivatives                    2.6         3.5

Unrealized swaps:
Crude swaps                                     2.5         4.5
NGL swaps                                      (7.0)       (2.3)
Gas swaps                                      (1.3)        3.0
Change in fair value of derivatives            (5.8)        5.2

Gain (loss) on derivatives                $    (3.2)      $ 8.7



Certain gathering and processing agreements provide for quarterly or annual
MVCs. Under these agreements, our customers agree to ship and/or process a
minimum volume of commodity on our systems over an agreed time period. If a
customer under such an agreement fails to meet its MVC for a specified period,
the customer is obligated to pay a contractually determined fee based upon the
shortfall between actual commodity volumes and the MVC for that period. Some of
these agreements also contain make-up right provisions that allow a customer to
utilize gathering or processing fees in excess of the MVC in subsequent periods
to offset shortfall amounts in previous periods. We record revenue under MVC
contracts during periods of shortfall when it is known that the customer cannot,
or will not, make up the deficiency in subsequent periods.

Revenue recorded for the shortfall between actual production volumes and the MVC
is as follows (in millions):
                                              Six Months Ended
                                                  June 30,
                                              2020          2019
                           Permian        $     0.3       $ 7.7
                           Oklahoma            24.9           -
                           Total          $    25.2       $ 7.7

Our MVC revenue in the Oklahoma segment is generated from a gathering and processing arrangement with Devon which expires in 2030, with the MVC provision under the agreement expiring in December 2020.


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Operating Expenses. Operating expenses were $188.8 million for the six months
ended June 30, 2020 compared to $232.4 million for the six months ended June 30,
2019, a decrease of $43.6 million, or 18.8%. The primary contributors to the
decrease by segment were as follows (in millions):
                          Six Months Ended
                              June 30,                              Change
                         2020          2019           $             %
Permian Segment       $  48.2       $  56.2       $  (8.0)       (14.2) %
North Texas Segment      39.0          51.5         (12.5)       (24.3) %
Oklahoma Segment         42.3          51.5          (9.2)       (17.9) %
Louisiana Segment        59.3          73.2         (13.9)       (19.0) %
Total                 $ 188.8       $ 232.4       $ (43.6)       (18.8) %



•Permian Segment. Operating expenses in the Permian segment decreased $8.0
million primarily due to decreased labor and benefits expense as a result of a
reduction in workforce in April 2020 and reductions in materials and supplies
expense, construction fees and services, sales and use tax, and vehicle
expenses.

•North Texas Segment. Operating expenses in the North Texas segment decreased
$12.5 million primarily due to decreased labor and benefits expense as a result
of a reduction in workforce in April 2020 and reductions in materials and
supplies expense, operations and maintenance, construction fees and services, ad
valorem tax, sales and use tax, and treater and compressor rentals.

•Oklahoma Segment. Operating expenses in the Oklahoma segment decreased $9.2
million primarily due to decreased labor and benefits expense as a result of a
reduction in workforce in April 2020 and reductions in materials and supplies
expense, construction fees and services, operations and maintenance, utilities,
ad valorem tax, and treater rentals.

•Louisiana Segment. Operating expenses in the Louisiana segment decreased $13.9
million primarily due to decreased labor and benefits expense as a result of a
reduction in workforce in April 2020 and reductions in materials and supplies
expense, construction fees and services, ad valorem tax, and vehicle expenses.

General and Administrative Expenses. General and administrative expenses were
$53.9 million for the six months ended June 30, 2020 compared to $83.6 million
for the six months ended June 30, 2019, a decrease of $29.7 million, or 35.5%.
The primary contributors to the decrease were as follows:

•Transaction costs decreased $13.9 million, which was primarily due to costs incurred related to the Merger, which closed during the first quarter of 2019.

•Labor costs and unit-based compensation decreased $8.9 million due to a reduction in workforce and lower bonus accrual.

•Fees and services expense, rents and leases, and insurance expenses decreased $4.1 million, which was primarily due to general cost saving initiatives.



Depreciation and Amortization. Depreciation and amortization was $321.0 million
for the six months ended June 30, 2020 compared to $305.8 million for the six
months ended June 30, 2019, an increase of $15.2 million, or 5.0%. This increase
was primarily due to new assets placed in service in the Oklahoma segment, as
well as accelerated depreciation on certain non-core assets. These increases
were partially offset by the impairment of Louisiana segment assets in the first
quarter of 2020 and the conclusion of a finance lease in the North Texas segment
in 2019.

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Impairments. For the six months ended June 30, 2020, we recognized impairment
expense related to goodwill and property and equipment. For the six months ended
June 30, 2019 we recognized impairment expense related to goodwill. See "Item 1.
Financial Statements-Note 2" for additional information on our property and
equipment impairments and "Item 1. Financial Statements-Note 3" for additional
information on our goodwill impairments. Impairment expense is composed of the
following amounts (in millions):
                            Six Months Ended
                                June 30,
                           2020          2019
Goodwill impairment     $ 184.6       $ 186.5
Property impairment       168.0             -
Cancelled projects          1.9             -
Total                   $ 354.5       $ 186.5



Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt
of $32.0 million for the six months ended June 30, 2020 due to repurchases of
the 2024, 2025, 2026, and 2029 Notes in open market transactions. See "Item 1.
Financial Statements-Note 5" for additional information.

Loss on secured term loan receivable. We recorded a $52.9 million loss in our consolidated statement of operations for the six months ended June 30, 2019 related to the write-off of the secured term loan receivable.



Interest Expense. Interest expense was $110.8 million for the six months ended
June 30, 2020 compared to $103.9 million for the six months ended June 30, 2019,
an increase of $6.9 million, or 6.6%. Interest expense consisted of the
following (in millions):
                                                                     Six Months Ended
                                                                         June 30,
                                                                    2020          2019
ENLK and ENLC Senior Notes                                       $  87.3       $  83.4
Term Loan                                                           10.6          17.1
Consolidated Credit Facility                                         8.2           6.1
Capitalized interest                                                (2.5)         (3.8)

Amortization of debt issue costs and net discounts (premiums) 2.2


       2.8
Interest rate swap                                                   5.0          (0.3)
Other                                                                  -          (1.4)
Total                                                            $ 110.8       $ 103.9



Income (Loss) from Unconsolidated Affiliate Investments. Income from
unconsolidated affiliate investments was $1.0 million for the six months ended
June 30, 2020 compared to $10.0 million for the six months ended June 30, 2019,
a decrease of $9.0 million. The decrease was primarily attributable to a
reduction of income of $8.8 million from our GCF investment as a result of lower
fractionation revenues and lower operating expenses and a reduction of income of
$0.2 million from our Cedar Cove JV.

Income Tax Expense. Income tax benefit was $22.0 million for the six months
ended June 30, 2020 compared to an income tax benefit of $3.6 million for the
six months ended June 30, 2019. The increase in income tax benefit was primarily
attributable to lower 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 $52.1 million for the six months
ended June 30, 2020 compared to net income of $66.7 million for the six months
ended June 30, 2019, a decrease of $14.6 million. This decrease was primarily
due to the conversion of ENLK common units into ENLC common units as a result of
the Merger in the first quarter of 2019. Subsequent to the Merger, ENLC's
non-controlling interest is comprised of Series B Preferred Units, Series C
Preferred Units, NGP's 49.9% share of the Delaware Basin JV, Marathon Petroleum
Corporation's 50% share of the Ascension JV, and other minor non-controlling
interests.

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Critical Accounting Policies

Information regarding our critical accounting policies is included in Item 7 of
our Annual Report on Form 10-K for the year ended December 31, 2019, except as
described below.

Property and Equipment

In accordance with ASC 360, Property, Plant, and Equipment, we evaluate
long-lived assets of identifiable business activities for potential impairment
whenever events or changes in circumstances indicate that their carrying value
may not be recoverable. The carrying amount of a long-lived asset is not
recoverable when it exceeds the undiscounted sum of the future cash flows
expected to result from the use and eventual disposition of the asset. Estimates
of expected future cash flows represent management's best estimate based on
reasonable and supportable assumptions. When the carrying amount of a long-lived
asset is not recoverable, an impairment is recognized equal to the excess of the
asset's carrying value over its fair value, which is based on inputs that are
not observable in the market, and thus represent Level 3 inputs.

During March 2020, we determined that a sustained decline in our unit price and
weakness in the overall energy sector, driven by low commodity prices and lower
consumer demand due to the COVID-19 pandemic, caused a change in circumstances
warranting an interim impairment test. For the six months ended June 30, 2020,
we recognized a $168.0 million impairment on property and equipment related to a
portion of our Louisiana reporting segment because the carrying amounts were not
recoverable based on our expected future cash flows, and a $1.9 million
impairment on property and equipment related to cancelled projects.

Goodwill Impairment



We perform our goodwill assessments at the reporting unit level for all
reporting units. We use a discounted cash flow analysis to perform the
assessments. Key assumptions in the analysis include the use of an appropriate
discount rate, terminal year multiples, and estimated future cash flows,
including volume and price forecasts and estimated operating and general and
administrative costs. In estimating cash flows, we incorporate current and
historical market and financial information, among other factors. Impairment
determinations involve significant assumptions and judgments, and differing
assumptions regarding any of these inputs could have a significant effect on the
various valuations.

During March 2020, we determined that a sustained decline in our unit price and
weakness in the overall energy sector, driven by low commodity prices and lower
consumer demand due to the COVID-19 pandemic, caused a change in circumstances
warranting an interim impairment test. Based on these triggering events, we
performed a quantitative goodwill impairment analysis on the remaining goodwill
in the Permian reporting unit. Based on this analysis, a goodwill impairment
loss for our Permian reporting unit in the amount of $184.6 million was
recognized as an impairment loss on the consolidated statement of operations for
the six months ended June 30, 2020.

Liquidity and Capital Resources



Cash Flows from Operating Activities. Net cash provided by operating activities
was $316.8 million for the six months ended June 30, 2020 compared to $521.5
million for the six months ended June 30, 2019. Operating cash flows and changes
in working capital for comparative periods were as follows (in millions):
                                                    Six Months Ended
                                                        June 30,
                                                   2020          2019

Operating cash flows before working capital $ 418.9 $ 429.5 Changes in working capital

                       (102.1)         92.0



Operating cash flows before changes in working capital decreased $10.6 million
for the six months ended June 30, 2020 compared to the six months ended June 30,
2019. The primary contributors to the decrease in operating cash flows were as
follows:

•Gross operating margin, excluding non-cash commodity swap activity, decreased $67.9 million.

•Interest expense, excluding amortization of debt issue costs and net discounts (premium) of notes, increased $7.5 million.


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These changes to operating cash flows were offset by the following:

•Operating expenses excluding unit-based compensation decreased $45.4 million
primarily due to a reduction in workforce. For more information, see "Results of
Operations."

•General and administrative expenses excluding unit-based compensation decreased
$25.0 million primarily due to a reduction in costs across our platform. For
more information, see "Results of Operations."

The changes in working capital for the six months ended June 30, 2020 compared
to the six months ended June 30, 2019 were primarily due to fluctuations in
trade receivable and payable balances due to timing of collection and payments,
changes in inventory balances attributable to normal operating fluctuations, and
fluctuations in accrued revenue and accrued cost of sales.

Cash Flows from Investing Activities. Net cash used in investing activities was
$202.0 million for the six months ended June 30, 2020, compared to $426.9
million for the six months ended June 30, 2019. Investing cash flows are
primarily related to capital expenditures, which decreased from $428.4 million
for the six months ended June 30, 2019 to $203.6 million for the six months
ended June 30, 2020. The decrease was primarily due to reduced capital spending
plans for 2020.

Cash Flows from Financing Activities. Net cash used in financing activities was
$140.2 million for the six months ended June 30, 2020 compared to $136.0 million
for the six months ended June 30, 2019. Our primary financing activities
consisted of the following (in millions):
                                                                                   Six Months Ended
                                                                                       June 30,
                                                                               2020                2019
Net borrowings on the Consolidated Credit Facility                         $     50.0          $   200.0
Net repurchases on ENLK senior unsecured notes                                  (35.2)                 -
Net borrowings (repurchases) on the 2029 Notes                                   (0.8)             500.0
Net repayments on the ENLK 2019 unsecured senior notes                              -             (400.0)
Net repayments on the ENLC Credit Facility                                          -             (111.4)
Contributions by non-controlling interests (1)                                   50.3               45.2
Distribution to members                                                        (139.8)            (188.2)

Distributions to ENLK common units held by public unitholders (2)

         -             (104.8)
Distributions to Series B Preferred Unitholders (3)                             (33.6)             (33.2)
Distributions to Series C Preferred Unitholders (3)                             (12.0)             (12.0)
Distributions to joint venture partners (4)                                     (15.0)             (12.7)


____________________________


(1)Represents contributions from NGP to the Delaware Basin JV.
(2)Subsequent to the closing of the Merger, ENLK no longer has publicly held
common units.
(3)See "Item 1. Financial Statements-Note 7" for information on distributions to
holders of the Series B 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 minor non-controlling interests.

Capital Requirements. We expect our remaining 2020 capital expenditures,
including capital contributions to our unconsolidated affiliate investments, to
be approximately $40 million to $100 million, which is net of approximately $10
million to $20 million from our joint venture partners. Our primary capital
projects for the remainder of 2020 include the construction of the Tiger Plant
in the Delaware Basin and continued development of our existing systems. See
"Other Recent Developments" for further details.

We expect to fund capital expenditures from operating cash flows and capital
contributions by joint venture partners that relate to the non-controlling
interest share of our consolidated entities. In 2020, it is possible that not
all of our planned projects will be commenced or completed. Our ability to pay
distributions to our unitholders, to fund planned capital expenditures, and to
make acquisitions will depend upon our future operating performance, which will
be affected by prevailing economic conditions in the industry, financial,
business, and other factors, some of which are beyond our control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of June 30, 2020.


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Table of Contents Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of June 30, 2020 is as follows (in millions):


                                                                                         Payments Due by Period
                                        Total            Remainder 2020            2021              2022             2023              2024            Thereafter
Long-term debt obligations           $ 3,532.3          $           -          $       -          $     -          $     -          $   521.8          $ 3,010.5
Term Loan                                850.0                      -              850.0                -                -                  -                  -
Consolidated Credit Facility             400.0                      -                  -                -                -              400.0                  -
Interest payable on fixed long-term
debt obligations                       2,412.4                   86.7              173.1            173.1            173.1              161.7           

1,644.7


Operating lease obligations              128.2                   10.6               17.0             12.2             10.2                9.5               68.7
Purchase obligations                      13.0                   13.0                  -                -                -                  -                  -
Pipeline and trucking capacity and
deficiency agreements (1)                199.6                   31.0               39.8             31.8             28.1               33.0           

35.9


Inactive easement commitment (2)          10.0                      -                  -             10.0                -                  -                  -
Total contractual obligations        $ 7,545.5          $       141.3          $ 1,079.9          $ 227.1          $ 211.4          $ 1,126.0          $ 4,759.8


____________________________
(1)Consists of pipeline capacity payments for firm transportation and deficiency
agreements.
(2)Amounts related to inactive easements paid as utilized by us with balance due
in 2022 if not utilized.

The above table does not include any physical or financial contract purchase
commitments for natural gas and NGLs due to the nature of both the price and
volume components of such purchases, which vary on a daily or monthly basis.
Additionally, we do not have contractual commitments for fixed price and/or
fixed quantities of any material amount that is not already disclosed in the
table above.

The interest payable related to the Consolidated Credit Facility and the Term
Loan are not reflected in the above table because such amounts depend on the
outstanding balances and interest rates of the Consolidated Credit Facility and
the Term Loan, which vary from time to time.

Our contractual cash obligations for the remainder of 2020 are expected to be funded from cash flows generated from our operations.

Indebtedness



In December 2018, we entered into the Consolidated Credit Facility, which
permits us to borrow up to $1.75 billion on a revolving credit basis and
includes a $500.0 million letter of credit subfacility. As of June 30, 2020,
there was $400.0 million in outstanding borrowings under the Consolidated Credit
Facility and $23.0 million in outstanding letters of credit.

In addition, as of June 30, 2020, we have $3.5 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047 and $850.0 million in outstanding principal on the Term Loan.

See "Item 1. Financial Statements-Note 5" for more information on our outstanding debt instruments.

Recent Accounting Pronouncements

See "Item 1. Financial Statements-Note 2" for more information on recently issued and adopted accounting pronouncements.

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
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  Table of Contents
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 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) outbreak 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 under our credit facility, (e) the
dependence on Devon for a substantial portion of the natural gas and crude that
we gather, process, and transport, (f) developments that materially and
adversely affect Devon or other customers, (g) adverse developments in the
midstream business that may reduce our ability to make distributions, (h)
competition for crude oil, condensate, natural gas, and NGL supplies and any
decrease in the availability of such commodities, (i) decreases in the volumes
that we gather, process, fractionate, or transport, (j) construction risks in
our major development projects, (k) our ability to receive or renew required
permits and other approvals, (l) increased federal, state, and local
legislation, and regulatory initiatives, as well as government reviews relating
to hydraulic fracturing resulting in increased costs and reductions or delays in
natural gas production by our customers, (m) climate change legislation and
regulatory initiatives resulting in increased operating costs and reduced demand
for the natural gas and NGL services we provide, (n) changes in the availability
and cost of capital, including as a result of a change in our credit rating, (o)
volatile prices and market demand for crude oil, condensate, natural gas, and
NGLs that are beyond our control, (p) our debt levels could limit our
flexibility and adversely affect our financial health or limit our flexibility
to obtain financing and to pursue other business opportunities, (q) operating
hazards, natural disasters, weather-related issues or delays, casualty losses,
and other matters beyond our control, (r) reductions in demand for NGL products
by the petrochemical, refining, or other industries or by the fuel markets, (s)
impairments to goodwill, long-lived assets and equity method investments, and
(t) the effects of existing and future laws and governmental regulations,
including environmental and climate change requirements and other uncertainties.
In addition to the specific uncertainties, factors, and risks discussed above
and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth
in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the
year ended December 31, 2019 and in Part II, "Item 1A. Risk Factors" of our
Quarterly Report on Form 10-Q for the quarter ended March 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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