ENLINK MIDSTREAM, LLC Please read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. In addition, please refer to the Definitions page set forth in this report prior to Item 1-Business. Discussions of the year endedDecember 31, 2018 and year-to-year comparisons of the year endedDecember 31, 2019 and the year endedDecember 31, 2018 can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of ENLC's Annual Report on Form 10-K for the year endedDecember 31, 2019 . In this report, the terms "Company" or "Registrant," as well as the terms "ENLC," "our," "we," "us," or like terms, are sometimes used as abbreviated references toEnLink Midstream, LLC itself orEnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to "EnLink Midstream Partners, LP ," the "Partnership," "ENLK," or like terms refer toEnLink Midstream Partners, LP itself orEnLink Midstream Partners, LP together with its consolidated subsidiaries, including theOperating Partnership .
Overview
ENLC is aDelaware limited liability company formed inOctober 2013 . ENLC's material assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. All of our midstream energy assets are owned and operated by ENLK and its subsidiaries. We primarily focus on providing midstream energy services, including: •gathering, compressing, treating, processing, transporting, storing, and selling natural gas; •fractionating, transporting, storing, and selling NGLs; and •gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and condensate, in addition to brine disposal services. Our midstream energy asset network includes approximately 11,900 miles of pipelines, 22 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. 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
•Louisiana Segment. TheLouisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located inLouisiana and our crude oil operations in ORV; •Oklahoma Segment. TheOklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford ,Arkoma -Woodford , northern Oklahoma Woodford, STACK, and CNOW shale areas;
•North Texas Segment. The
•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV inOklahoma , our ownership interest in GCF inSouth Texas , our derivative activity, and our general corporate assets and expenses. 66 -------------------------------------------------------------------------------- Table of Contents 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 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 94% of our adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the year endedDecember 31, 2020 .
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 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 adjusted gross margin
received from transactions with these customers is material to us. No other
customers represented greater than 10% of our consolidated revenues.
Year Ended December 31,
2020 2019 2018
Devon 14.4 % 10.5 % 10.4 %
Dow Hydrocarbons and Resources LLC 13.2 % 10.0 % 11.1 %
Marathon Petroleum Corporation 12.2 % 13.8 % 11.5 %
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
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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 combination of these contractual arrangements. See "Item 7A. 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
COVID-19 Update
OnMarch 11, 2020 , theWorld Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The ongoing pandemic has 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 energy, volatility in the market prices for crude oil, condensate, natural gas and NGLs, and a significant reduction in the market price of crude oil during the first half of 2020. As a result of the demand destruction, reduced commodity prices, and an uncertain timeline for full recovery, many oil and natural gas producers, including some of our customers, curtailed their current drilling and production activity and reduced or slowed down their plans for future drilling and production activity. As a result of these decreases in producer activity, we experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems during the first half of 2020. Although volumes have since been restored nearly to pre-pandemic levels, capital investments by oil and natural gas producers remain at low levels. 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. In March, 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 maintain a crisis management team for health, safety and environmental matters and personnel issues and a cross-functional COVID-19 response team to address various impacts of the situation, as they develop. We also continue to follow modified business practices (including discontinuing non-essential business travel, implementing work-from-home policies during high-transmission periods, and staggered work-from-home policies for employees who can execute their work remotely in order to reduce office density, 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 theCenters for Disease Control and Prevention , theWorld 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 the COVID-19 pandemic 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 whether governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border 68 -------------------------------------------------------------------------------- Table of Contents closures, quarantines, shelter-in-place orders, and business and government shutdowns that exist as of the date of this report will be extended or whether new measures will be imposed. A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for oil, condensate natural gas and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders). As of the date of this report, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded results. Our systems, pipelines, and facilities have remained operational throughout the period. 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. We reduced our capital expenditures in 2020, including both growth and maintenance capital expenditures, to$262.6 million , a 65% reduction from 2019 total capital spending. We have also reduced costs across our platform. We reduced our general and administrative and operating expenses by$142.6 million for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . We have not requested any funding under any federal or other governmental programs related to COVID-19 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 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 effect of the pandemic on economic, social and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, and the timing and extent to which normal economic, social and operating conditions resume.
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."
Regulatory Developments
OnJanuary 20, 2021 , theBiden Administration came into office and immediately issued a number of executive orders related to the production of oil and gas that could affect our operations and those of our customers. OnJanuary 20, 2021 , the Acting Secretary for theDepartment of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then onJanuary 27, 2021 ,President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. In addition, onJanuary 20, 2021 ,President Biden issued an Executive Order on "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis" seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind, prior agency actions that are identified as conflicting with theBiden Administration's climate policies. Among the areas that could be affected by the review are regulations addressing methane emissions and the part of the extraction process known as hydraulic fracturing.The Biden Administration has also issued other orders that could ultimately affect our business, such as the executive order rejoining the Paris Agreement, and could seek, in the future, to put into place additional executive orders, policy and regulatory reviews, and seek to haveCongress pass legislation that could adversely affect the production of oil and gas assets and our operations and those of our customers. Only a small percentage of our operations are derived from customers operating on public land, mainly in theDelaware Basin , and these activities represented only approximately 3% of our total segment profit, net to EnLink, during 2020. 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 customers obtain permits and other approvals from the federal government. While we are still evaluating the effects of these recent orders on our operations and our customers' operations, and the status of recent and future rules and rulemaking initiatives under theBiden Administration remain uncertain, these orders, and the regulations and the policies that could result from them, could lead to increased costs for us or our customers, difficulties in obtaining permits and other approvals for us and our customers, reduced utilization of our gathering, processing and pipeline systems or reduced rates 69 -------------------------------------------------------------------------------- Table of Contents under renegotiated transportation or storage agreements in affected regions. These impacts could, in turn, adversely affect our business, financial condition, results of operation 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."
Organic Growth
War Horse Processing Plant. InDecember 2020 , we began moving equipment and facilities previously associated with theBattle Ridge processing plant inCentral Oklahoma to thePermian Basin . This relocation is expected to increase the processing capacity of ourPermian Basin processing facilities by approximately 80 MMcf/d. We expect to complete the relocation in the second half of 2021. Riptide Processing Plant. The Riptide processing plant is a gas processing plant located in theMidland Basin . InSeptember 2019 , we completed an expansion to our Riptide processing plant, which increased the processing capacity by 65 MMcf/d. InMarch 2020 , we completed an expansion to the Riptide processing plant, which increased the processing capacity by 55 MMcf/d. As ofDecember 31, 2020 , the total operational processing capacity of the Riptide processing plant was 220 MMcf/d.Tiger Plant . The Tiger plant is a gas processing plant located in theDelaware Basin . This processing plant is owned by theDelaware Basin JV. InAugust 2020 , we completed the construction of the Tiger plant, which expanded ourDelaware Basin processing capacity by an additional 240 MMcf/d, to handle expected future processing volume growth. The Tiger plant is not operating at this time. Central Oklahoma Plants. InJune 2019 , we completed construction on our Thunderbird plant, which expanded ourCentral Oklahoma gas processing capacity by an additional 200 MMcf/d, bringing our total processing capacity at ourCentral Oklahoma facilities to 1.2 Bcf/d. The Thunderbird plant is not operating at this time. Cajun-Sibon Pipeline. InApril 2019 , we completed the expansion of our Cajun-Sibon NGL pipeline capacity, which connected the Mont Belvieu NGL hub to our fractionation facilities inLouisiana . This was the third phase of our Cajun-Sibon system referred to as Cajun Sibon III, which increased throughput capacity from 130,000 Bbls/d to 185,000 Bbls/d. Lobo Natural Gas Gathering and Processing Facilities. In earlyApril 2019 , we completed construction of a 120 MMcf/d expansion to our Lobo III cryogenic gas processing plant, bringing the total operational processing capacity at our Lobo facilities to 395 MMcf/d. Avenger Crude Oil Gathering System. Avenger is a crude oil gathering system in the northernDelaware Basin supported by a long-term contract withDevon on dedicated acreage in their Todd andPotato Basin development areas inEddy andLea counties inNew Mexico . We commenced initial operations on Avenger during the third quarter of 2018 and began full-service operations during the second quarter of 2019.
Simplification of the Corporate Structure. On
Long-Term Debt Issuances, Redemption, and Repurchases
OnOctober 21, 2020 ,EnLink Midstream Funding, LLC , a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the "SPV") entered into the AR Facility to borrow up to$250.0 million . In connection with the AR Facility, certain subsidiaries of ENLC have sold and contributed, and will continue to sell or contribute, their accounts receivable to the SPV to be held as collateral for borrowings under the AR Facility. The SPV's assets are not available to satisfy the obligations of ENLC or any of its affiliates. OnDecember 14, 2020 , ENLC issued$500.0 million in aggregate principal amount of ENLC's 5.625% senior unsecured notes dueJanuary 15, 2028 (the "2028 Notes") at a price to the public of 100% of their face value. Interest payments on the 2028 Notes are payable onJanuary 15 andJuly 15 of each year, beginning onJuly 15, 2021 . The 2028 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately$494.7 million were used to repay a portion of the borrowings under the Term Loan dueDecember 2021 . 70
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OnApril 9, 2019 , ENLC issued$500.0 million in aggregate principal amount of ENLC's 5.375% senior unsecured notes dueJune 1, 2029 (the "2029 Notes") at a price to the public of 100% of their face value. Interest payments on the 2029 Notes are payable onJune 1 andDecember 1 of each year. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately$496.5 million were used to repay outstanding borrowings under the Consolidated Credit Facility, including borrowings incurred onApril 1, 2019 to repay at maturity all of the$400.0 million outstanding aggregate principal amount of ENLK's 2.70% senior unsecured notes due 2019, and for general limited liability company purposes. For the year endedDecember 31, 2020 , we made aggregate payments to partially repurchase the 2024, 2025, 2026, and 2029 Notes in open market transactions. Activity related to the partial repurchases of our outstanding debt consisted of the following (in millions): Year Ended December 31, 2020 Debt repurchased $ 67.7 Aggregate payments (36.0) Net discount on repurchased debt (0.3) Accrued interest on repurchased debt 0.6 Gain on extinguishment of debt $ 32.0
See "Item 8. Financial Statements and Supplementary Data-Note 6" for more information regarding the AR Facility, the Term Loan, and the senior unsecured notes.
Common Unit Repurchase Program. InNovember 2020 , the board of directors of the Managing Member authorized a common unit repurchase program for the repurchase of up to$100 million of outstanding ENLC common units. 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 Securities Exchange Act of 1934, as amended. The repurchases will depend on market conditions and may be discontinued at any time. For the year endedDecember 31, 2020 , ENLC repurchased 383,614 outstanding ENLC common units for an aggregate price of$1.2 million .
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"), distributable cash
flow available to common unitholders ("distributable cash flow"), 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):
Year Ended December 31,
2020 2019
Total revenues $ 3,893.8 $ 6,052.9 Cost of sales, exclusive of operating expenses and depreciation and amortization (1)
(2,388.5) (4,392.5)
Operating expenses (373.8) (467.1)
Depreciation and amortization (638.6) (617.0)
Gross margin 492.9 576.3
Operating expenses 373.8 467.1
Depreciation and amortization 638.6 617.0
Adjusted gross margin $ 1,505.3 $ 1,660.4 ____________________________
(1)Excludes all operating expenses as well as depreciation and amortization
related to our operating segments of
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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 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; (payments under onerous performance obligation); transaction costs;
relocation costs associated with the War Horse processing facility; accretion
expense associated with asset retirement obligations; (non-cash rent); and
(non-controlling interest share of adjusted EBITDA from joint ventures).
Adjusted EBITDA is the primary metric used in our short-term incentive program
for compensating employees. In addition, adjusted EBITDA is used as a
supplemental liquidity and performance measure by our management and by external
users of our financial statements, such as investors, commercial banks, research
analysts, and others, to assess:
•the financial performance of our assets without regard to financing methods,
capital structure, or historical cost basis;
•the ability of our assets to generate cash sufficient to pay interest costs,
support our indebtedness, and make cash distributions to our unitholders;
•our operating performance and return on capital as compared to those of other
companies in the midstream energy sector, without regard to financing methods or
capital structure; and
•the viability of acquisitions and capital expenditure projects and the overall
rates of return on alternative investment opportunities.
The GAAP measures most directly comparable to adjusted EBITDA are net income
(loss) and net cash provided by operating activities. Adjusted EBITDA should not
be considered an alternative to, or more meaningful than, net income (loss),
operating income (loss), net cash provided by operating activities, or any other
measure of financial performance presented in accordance with GAAP. Adjusted
EBITDA may not be comparable to similarly titled measures of other companies
because other companies may not calculate adjusted EBITDA in the same manner.
Adjusted EBITDA does not include interest expense, net of interest income;
income tax expense (benefit); and depreciation and amortization. Because we have
borrowed money to finance our operations, interest expense is a necessary
element of our costs and our ability to generate cash available for
distribution. Because we 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 loss to adjusted EBITDA (in millions):
Year Ended December 31,
2020 2019
Net loss $ (315.6) $ (999.6)
Interest expense, net of interest income 223.3 216.0
Depreciation and amortization 638.6 617.0
Impairments 362.8 1,133.5
Loss on secured term loan receivable (1) - 52.9
(Income) loss from unconsolidated affiliate investments (2) (0.6) 16.8
Distributions from unconsolidated affiliate investments 2.1 20.2
(Gain) loss on disposition of assets 8.8 (1.9)
Gain on extinguishment of debt (32.0) -
Unit-based compensation 28.4 39.4
Income tax expense 143.2 6.9
Unrealized loss on commodity swaps 10.5 0.1
Payments under onerous performance obligation offset to other current and long-term liabilities
- (9.0)
Transaction costs (3) - 13.9
Relocation costs associated with the War Horse processing facility (4)
0.8 -
Other (5) (1.1) (1.0)
Adjusted EBITDA before non-controlling interest 1,069.2 1,105.2
Non-controlling interest share of adjusted EBITDA from joint ventures (6)
(30.7) (25.7)
Adjusted EBITDA, net to ENLC $ 1,038.5 $ 1,079.5 ____________________________
(1)We recorded a$52.9 million loss in our consolidated statement of operations for the year endedDecember 31, 2019 related to the write-off of the secured term loan receivable. For additional information regarding this transaction, refer to "Item 8. Financial Statements and Supplementary Data-Note 2." (2)Includes loss of$31.4 million for the year endedDecember 31, 2019 related to the impairment of the carrying value of the Cedar Cove JV. (3)Represents transaction costs attributable to costs incurred related to the Merger inJanuary 2019 . (4)Represents cost incurred related to the relocation of equipment and facilities from theBattle Ridge processing plant, in theOklahoma segment, to the Permian segment that we expect to complete in 2021 and are not part of our ongoing operations. (5)Includes accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term. (6)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests. 74 -------------------------------------------------------------------------------- Table of Contents Distributable Cash Flow and Free Cash Flow After Distributions We define distributable cash flow as adjusted EBITDA, net to ENLC, plus (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); (payments to terminate interest rate swaps); non-cash interest (income)/expense; and (current income taxes). Free cash flow after distributions is defined as distributable cash flow plus (less) (distributions declared on common units); (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); proceeds from the sale of equipment and land; and (relocation costs associated with the War Horse processing facility). Free cash flow after distributions is the principal cash flow metric used by the Company in its earnings announcements. In addition, distributable cash flow and free cash flow after distributions 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, pay back 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 free cash flow after distributions is net cash provided by operating activities. Distributable cash flow and free cash flow after distributions 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 free cash flow after distributions 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 free cash flow after distributions 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 free cash flow after distributions, to evaluate our overall liquidity. 75 -------------------------------------------------------------------------------- Table of Contents The following table reconciles net cash provided by operating activities to adjusted EBITDA, distributable cash flow, and free cash flow after distributions (in millions): Year Ended December 31, 2020 2019 Net cash provided by operating activities $ 731.1$ 991.9 Interest expense (1) 218.2 213.7 Payments to terminate interest rate swaps (2) 10.9 - Accruals for settled commodity swap transactions (4.3) (2.4) Current income tax expense 1.1 -
Distributions from unconsolidated affiliate investment in excess of earnings
0.5 3.7
Transaction costs (3) - 13.9
Relocation costs associated with the War Horse processing facility (4)
0.8 -
Other (5) (0.3) (1.4)
Changes in operating assets and liabilities which
(provided) used cash:
Accounts receivable, accrued revenues, inventories, and
other 6.4 (350.7)
Accounts payable, accrued product purchases, and other accrued liabilities (6)
104.8 236.5
Adjusted EBITDA before non-controlling interest 1,069.2 1,105.2
Non-controlling interest share of adjusted EBITDA from joint ventures (7)
(30.7) (25.7)
Adjusted EBITDA, net to ENLC 1,038.5 1,079.5
Interest expense, net of interest income (223.3) (216.0)
Maintenance capital expenditures, net to ENLC (8) (32.1) (45.8)
ENLK preferred unit accrued cash distributions (9) (91.4) (91.7)
Payments to terminate interest rate swaps (2) (10.9) -
Other (10) (0.9) (2.2)
Distributable cash flow 679.9 723.8
Common distributions declared (186.0) (508.1)
Growth capital expenditures, net to ENLC (8) (187.2) (599.8)
Proceeds from the sale of equipment and land (11) 4.6 8.2
Relocation costs associated with the War Horse processing facility (4)
(0.8) -
Free cash flow after distributions $ 310.5 ____________________________
(1)Net of amortization of debt issuance costs and discount and premium, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income/(expense), which is netted against interest expense but not included in adjusted EBITDA. (2)Represents cash paid for the early termination of$500.0 million of our interest rate swaps due to the partial repayment of the Term Loan inDecember 2020 . See "Item 8. Financial Statements and Supplementary Data-Note 12" for information on the partial termination of our interest rate swaps. (3)Represents transaction costs incurred related to the Merger inJanuary 2019 . (4)Represents cost incurred related to the relocation of equipment and facilities from theBattle Ridge processing plant, in theOklahoma segment, to the Permian segment that we expect to complete in 2021 and are not part of our ongoing operations. (5)Includes amortization of designated cash flow hedge and non-cash rent, which relates to lease incentives pro-rated over the lease term. (6)Net of payments under onerous performance obligation offset to other current and long-term liabilities during the year endedDecember 31, 2019 . (7)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests. (8)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities. (9)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See "Item 8. Financial Statements and Supplementary Data-Note 8" 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. (10)Includes non-cash interest (income)/expense and current income tax expense. (11)Represents proceeds from the sale of surplus or unused equipment and land. These sales occurred in the normal operation of our business and did not include major divestitures. 76 -------------------------------------------------------------------------------- Table of Contents Results of Operations
The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the table below (in millions, except volumes):
Permian Louisiana Oklahoma North Texas Corporate Totals
Year Ended December 31, 2020
Gross margin $ 44.9 $ 152.3 $
197.4
Add:
Depreciation and amortization 125.2 145.8 216.9 143.4 7.3 638.6 Segment profit 170.1 298.1 414.3 271.0 (22.0) 1,131.5 Operating expenses 94.2 120.0 82.2 77.4 - 373.8 Adjusted gross margin$ 264.3 $ 418.1 $ 496.5 $ 348.4 $ (22.0) $ 1,505.3 Permian Louisiana Oklahoma North Texas Corporate Totals Year EndedDecember 31, 2019 Gross margin$ 25.7 $ 139.8 $
255.2
Add:
Depreciation and amortization 119.8 154.1 194.9 139.8 8.4 617.0 Segment profit 145.5 293.9 450.1 289.4 14.4 1,193.3 Operating expenses 112.9 147.3 104.0 102.9 - 467.1 Adjusted gross margin$ 258.4 $ 441.2 $ 554.1 $ 392.3 $ 14.4 $ 1,660.4 Year Ended December 31, 2020 2019 Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d) 890,800 723,400
Processing (MMbtu/d) 899,000 771,400
Crude Oil Handling (Bbls/d) 116,200 132,000
Louisiana Segment
Gathering and Transportation (MMbtu/d) 1,993,900 2,050,000
Crude Oil Handling (Bbls/d) 16,900 18,900
NGL Fractionation (Gals/d) 7,597,800 7,341,700
Brine Disposal (Bbls/d) 1,300 2,700
Oklahoma Segment
Gathering and Transportation (MMbtu/d) 1,116,500 1,302,200
Processing (MMbtu/d) 1,105,900 1,276,700
Crude Oil Handling (Bbls/d) 28,700 47,300
North Texas Segment
Gathering and Transportation (MMbtu/d) 1,478,200 1,651,900
Processing (MMbtu/d) 671,000 750,500
77-------------------------------------------------------------------------------- Table of Contents Year EndedDecember 31, 2020 Compared to Year EndedDecember 31, 2019 Gross Margin. Gross margin was$492.9 million for the year endedDecember 31, 2020 compared to$576.3 million for the year endedDecember 31, 2019 , a decrease of$83.4 million . The primary contributors to the total decrease were as follows (in millions): •Permian Segment. Gross margin was$44.9 million for the year endedDecember 31, 2020 compared to$25.7 million for the year endedDecember 31, 2019 , an increase of$19.2 million primarily due to the following:
•Adjusted gross margin in the Permian segment increased
•A$5.9 million increase due to volume growth in ourDelaware Basin crude assets. •An$8.3 million increase related to volume growth from additional well connects on ourMidland Basin gas assets. •A$7.5 million increase related to volume growth from additional well connects on ourDelaware Basin gas assets. These increases were partially offset by a$15.8 million decrease on ourSouth Texas assets primarily due to the expiration of an MVC provision in one of our contracts inJuly 2019 and the sale of the VEX assets inOctober 2020 . •Operating expenses in the Permian segment decreased$18.7 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, vehicle expenses, and sales and use tax. •Depreciation and amortization in the Permian segment increased$5.4 million primarily due to new assets placed into service, including the expansion to our Riptide processing plant and the completed construction of our Tiger plant.
•Louisiana Segment. Gross margin was
•Adjusted gross margin in the
•A$12.8 million decrease from ourLouisiana gas assets due to the expiration of certain firm transportation contracts, and decreased gathering and transportation volumes. •A$16.9 million decrease from our ORV crude assets primarily due to lower volumes. These decreases were partially offset by a$6.6 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 inApril 2019 and a settlement payment received as the result of a contract dispute in the amount of$5.5 million .
•Operating expenses in the
•Depreciation and amortization in theLouisiana segment decreased$8.3 million primarily due to the impairment ofLouisiana segment assets in the first quarter of 2020.
•Oklahoma Segment. Gross margin was
•Adjusted gross margin in the
•A$5.9 million decrease due to volume decline in ourOklahoma crude assets primarily due to lower volumes from our existing customers. •A$51.7 million decrease due to volume decline in ourOklahoma gas assets primarily due to lower volumes from our existing customers. 78
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•Operating expenses in theOklahoma segment decreased$21.8 million primarily due to decreased labor and benefits expense as a result of reductions in workforce and reductions in materials and supplies expense, construction fees and services, and compressor rentals. •Depreciation and amortization in theOklahoma segment increased$22.0 million primarily due to the Thunderbird plant, which was operational inJune 2019 , as well as a change in the estimated useful lives of certain non-core assets.
•North Texas Segment. Gross margin was
•Adjusted gross margin in theNorth Texas segment decreased$43.9 million , which was primarily due to volume declines resulting from limited new drilling in the region.
•Operating expenses in the
•Depreciation and amortization in the
•Corporate Segment. Gross margin was negative$29.3 million for the year endedDecember 31, 2020 compared to$6.0 million for the year endedDecember 31, 2019 , a decrease of$35.3 million primarily due to the following: •Adjusted gross margin in the Corporate segment decreased$36.4 million , which was primarily due to the changes in fair value of our commodity swaps between the periods as summarized below (in millions): Year Ended December 31, 2020 2019 Realized swaps: Crude swaps$ (3.2) $ 11.7 NGL swaps (6.7) 6.5 Gas swaps (1.6) (3.7) Realized gain (loss) on derivatives (11.5) 14.5 Unrealized swaps: Crude swaps 3.1 (0.3) NGL swaps (15.7) (3.5) Gas swaps 2.1 3.7 Change in fair value of derivatives (10.5) (0.1) Gain (loss) on derivative activity$ (22.0) $ 14.4 79
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MVC Revenue. Revenue recorded for the shortfall between actual product volumes
and the MVCs were as follows (in millions):
Year Ended December 31,
2020 2019
Permian segment $ 1.0 $ 9.4
Oklahoma segment 56.2 10.3
Total $ 57.2 $ 19.7
Impairments. For the year ended December 31, 2020 , we recognized impairment
expense related to goodwill; property and equipment, including cancelled
projects; and lease right-of-use assets. For the year ended December 31, 2019 ,
we recognized impairment expense related to goodwill and property and equipment.
Impairment expense is composed of the following amounts (in millions):
Year Ended December 31,
2020 2019
Goodwill impairment (1) $ 184.6 $ 1,125.6
Property and equipment impairment (2) 168.0 7.9
Lease right-of-use asset impairment (3) 6.8 - Cancelled projects (2) 3.4 - Total impairments$ 362.8 $ 1,133.5
____________________________
(1)For additional information see "Item 8. Financial Statements and Supplementary Data-Note 3." (2)For additional information see "Item 8. Financial Statements and Supplementary Data-Note 2." (3)For additional information see "Item 8. Financial Statements and Supplementary Data-Note 5." Gain (loss) on disposition of assets. For the year endedDecember 31, 2020 , we recorded an$8.8 million loss on disposition of assets primarily related to the sale of our non-core crude pipeline assets inSouth Texas . For the year endedDecember 31, 2019 , we recorded a$1.9 million gain on disposition of assets primarily related to sale of non-core assets. General and administrative expenses. General and administrative expenses were$103.3 million for the year endedDecember 31, 2020 compared to$152.6 million for the year endedDecember 31, 2019 , a decrease of$49.3 million . The primary contributors to the decrease were as follows:
•Transaction costs decreased
•Labor costs and unit-based compensation decreased
•Expenses related to fees and services, travel, rents and leases, and insurance
decreased
Loss on secured term loan receivable. We have recorded a$52.9 million loss in our consolidated statement of operations for the year endedDecember 31, 2019 related to the write-off of theWhite Star secured term loan receivable. For additional information regarding this transaction, refer to "Item 8. Financial Statements and Supplementary Data-Note 2." 80 -------------------------------------------------------------------------------- Table of Contents Interest Expense. Interest expense was$223.3 million for the year endedDecember 31, 2020 compared to$216.0 million for the year endedDecember 31, 2019 , an increase of$7.3 million , or 3.4%. Net interest expense consisted of the following (in millions): Year Ended December 31, 2020 2019 ENLC and ENLK senior notes$ 175.0 $ 171.4 Term Loan 17.5 32.5 Consolidated Credit Facility 13.9 13.9 AR Facility 0.9 - Capitalized interest (3.4) (5.8)
Amortization of debt issuance costs, net (premium) discount of notes
4.6 4.9
Interest rate swaps - realized 14.5 0.4
Other 0.3 (1.3)
Total interest expense, net of interest income $
223.3
Gain on extinguishment of debt. We recognized a gain on extinguishment of debt of$32.0 million for the year endedDecember 31, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. See "Item 8. Financial Statements and Supplementary Data-Note 6" for additional information. Income (loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was$0.6 million for the year endedDecember 31, 2020 compared to a loss of$16.8 million for the year endedDecember 31, 2019 , an increase in income of$17.4 million . The increase in income was primarily due to a$31.4 million impairment of the carrying value of the Cedar Cove JV for the year endedDecember 31, 2019 , as we determined that the carrying value of our investment was not recoverable based on the forecasted cash flows from the Cedar Cove JV. This was partially offset by a reduction in income of$13.5 million from our GCF investment as a result of lower fractionation revenues. See "Item 8. Financial Statements and Supplementary Data-Note 10" for additional information. Income Tax Benefit (Expense). Income tax expense was$143.2 million for the year endedDecember 31, 2020 compared to income tax expense of$6.9 million for the year endedDecember 31, 2019 , an increase of tax expense of$136.3 million primarily due to a change in the valuation allowance recorded on our deferred tax assets. See "Item 8. Financial Statements and Supplementary Data-Note 7" for additional information. Net Income (Loss) Attributable to Non-controlling Interest. Net income attributable to non-controlling interest was$105.9 million for the year endedDecember 31, 2020 compared to net income of$119.7 million for the year endedDecember 31, 2019 , a decrease of$13.8 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 theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of the Ascension JV, and other minor non-controlling interests.
Critical Accounting Policies
The selection and application of accounting policies is an important process
that has developed as our business activities have evolved and as the accounting
rules have developed. Accounting rules generally do not involve a selection
among alternatives but involve an interpretation and implementation of existing
rules and the use of judgment to the specific set of circumstances existing in
our business. Compliance with the rules involves reducing a number of very
subjective judgments to a quantifiable accounting entry or valuation. We make
every effort to properly comply with all applicable rules on or before their
adoption, and we believe the proper implementation and consistent application of
the accounting rules is critical.
Our critical accounting policies are discussed below. See "Item 8. Financial
Statements and Supplementary Data-Note 2" for further details on our accounting
policies and future accounting standards to be adopted.
81
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Impairment of Long-Lived Assets
We evaluate long-lived assets, including property and equipment, intangible
assets, equity method investments, and lease right-of-use assets, for potential
impairment whenever events or changes in circumstances indicate that their
carrying value may not be recoverable. The carrying amount of a long-lived asset
is not recoverable when it exceeds the undiscounted sum of the future cash flows
expected to result from the use and eventual disposition of the asset. Estimates
of expected future cash flows represent management's best estimate based on
reasonable and supportable assumptions. When the carrying amount of a long-lived
asset is not recoverable, an impairment is recognized equal to the excess of the
asset's carrying value over its fair value, which is based on inputs that are
not observable in the market, and thus represent Level 3 inputs. For additional
information about our long-lived asset impairment tests, refer to "Item 8.
Financial Statements and Supplementary Data-Note 2."
Property and Equipment Impairments. 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
related to our property and equipment carrying amounts. For the year ended
December 31, 2020 , we recognized a $168.0 million impairment on property and
equipment related to a portion of our Louisiana reporting segment because the
carrying amounts were not recoverable based on our expected future cash flows,
and $3.4 million of impairments related to certain cancelled projects. For the
year ended December 31, 2019 , we recognized a $7.9 million impairment on
property and equipment related to certain decommissioned and removed non-core
assets.
Lease Right-of-Use Asset Impairment. During the fourth quarter of 2020, we
determined that we would cease using a portion of our Dallas , Houston , and
Midland offices. We are attempting to sublease the vacated space; however, as we
believe the terms of a sublease would be below our current rental rates, we
evaluated the related right-of-use assets for impairment by comparing the
estimated fair values of the right-of-use assets to their carrying values.
Estimated fair values were calculated using a discounted cash flow analysis that
utilized Level 3 inputs, which included estimated future cash flows and a
discount rate derived from market data. As the carrying value of each
right-of-use asset exceeded its estimated fair value, we recognized impairment
expense of $6.8 million for the year ended December 31, 2020 .
To the extent conditions further deteriorate in the current worldwide economic
and commodity price environment, we may identify additional triggering events
that may require future evaluations of the recoverability of the carrying value
of our long-lived assets, which could result in further impairment charges.
Liquidity and Capital Resources
Cash Flows from Operating Activities. Net cash provided by operating activities was$731.1 million for the year endedDecember 31, 2020 compared to$991.9 million for the year endedDecember 31, 2019 . Operating cash flows and changes in working capital for comparative periods were as follows (in millions): Year Ended December
31,
2020 2019
Operating cash flows before working capital$ 842.3 $ 886.7 Changes in working capital (111.2) 105.2 Operating cash flows before changes in working capital decreased$44.4 million for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . The primary contributors to the decrease in operating cash flows were as follows: •Gross margin, excluding depreciation and amortization, non-cash commodity swap activity, and unit-based compensation, decreased$49.1 million . For more information regarding the changes in gross margin for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 , see "Results of Operations."
•Distribution of earnings from unconsolidated affiliates decreased
•Interest expense, excluding amortization of debt issue costs and net discounts,
increased
•A$10.9 million cash payment for the early termination of$500.0 million of our interest rate swaps due to the partial repayment of the Term Loan inDecember 2020 . 82 -------------------------------------------------------------------------------- Table of Contents These changes to operating cash flows were offset by the following: •General and administrative expenses excluding unit-based compensation decreased$37.9 million , primarily due to a reduction in costs across our platform, reductions in workforce, and transaction costs related to the Merger in 2019. For more information, see "Results of Operations." The changes in working capital for the years endedDecember 31, 2020 and 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. Historically, we have had net operating losses that eliminated substantially all of our taxable income, and thus, we have not historically paid significant amounts of income taxes. We anticipate generating net operating losses for tax purposes during 2021, and as a result, do not expect to incur material amounts of federal and state income tax liabilities. In the event that we do generate taxable income that exceeds our utilizable net operating loss carryforwards, federal and state income tax liabilities will increase cash taxes paid. Refer to "Item 8. Financial Statements and Supplementary Data-Note 7" for additional information. Cash Flows from Investing Activities. Net cash used in investing activities was$317.7 million for the year endedDecember 31, 2020 compared to$741.5 million for the year endedDecember 31, 2019 . The primary contributors to the decrease in investing cash flows were as follows: •Capital expenditures decreased from$754.9 million for the year endedDecember 31, 2019 to$302.2 million for the year endedDecember 31, 2020 . The decrease was primarily due to higher overall capital expenditures in 2019 related to the Lobo III cryogenic gas processing plant expansion, the Thunderbird plant, the expansion of the Cajun-Sibon NGL pipeline, and the expansion of the Riptide processing plant, compared to the capital expenditures in 2020 related to an additional expansion of the Riptide processing plant and the completion of the Tiger plant. •Proceeds from the sale of assets increased from$14.3 million for the year endedDecember 31, 2019 to$17.6 million for the year endedDecember 31, 2020 related to the sale of non-core assets for each period. These decreases to investing cash flows were partially offset by$32.3 million related to cash paid for the acquisition of assets for the year endedDecember 31, 2020 . 83 -------------------------------------------------------------------------------- Table of Contents Cash Flows from Financing Activities. Net cash used in financing activities was$451.2 million for the year endedDecember 31, 2020 compared to$273.4 million for the year endedDecember 31, 2019 . Our primary financing activities consisted of the following (in millions):
Year Ended
2020 2019
Net borrowings on the AR Facility (1) $ 250.0 $ -
Net borrowings on ENLC senior unsecured notes (1) 499.2 500.0
Net repayments on the Term Loan (1) (500.0) -
Net borrowings (repayments) on the Consolidated Credit Facility (1) (350.0)
350.0
Net repurchases on ENLK's senior unsecured notes (1) (35.2) -
Net repayments on ENLK's 2019 unsecured senior notes (1) - (400.0)
Net repayments on the ENLC Credit Facility - (111.4)
Debt financing costs (7.7) (10.0)
Distributions to Series B and Series C Preferred unitholders (2) (91.3)
(91.4)
Distributions to joint venture partners (3) (29.9) (24.1)
Distributions to members (232.7) (467.2)
Contributions by non-controlling interest (4) 52.6 97.5
Common unit repurchases (5) (1.2) -
Distributions to ENLK common units held by public unitholders (6)
- (105.0)
____________________________
(1)See "Item 8. Financial Statements and Supplementary Data-Note 6" for more information regarding the AR Facility, the Term Loan, the Consolidated Credit Facility, and the senior unsecured notes. (2)See "Item 8. Financial Statements and Supplementary Data-Note 8" for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units. (3)Represents distributions to NGP for its ownership in theDelaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other non-controlling interests. (4)Represents contributions from NGP to theDelaware Basin JV. (5)See "Item 8. Financial Statements and Supplementary Data-Note 9" for more information regarding the ENLC common unit repurchase program. (6)Subsequent to the closing of the Merger, ENLK no longer has publicly held common units. Capital Requirements. We consider a number of factors in determining whether our capital expenditures are growth capital expenditures or maintenance capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income. Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations. We expect our 2021 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately$115 million to$155 million , which is net of approximately$3 million to$5 million from our joint venture partners. Our primary capital projects for 2021 include continued development of our existing systems through well connects and other small projects. Additionally, we expect to incur$25 million of operating expenses related to the movement of equipment and facilities previously associated with theBattle Ridge processing plant inCentral Oklahoma to thePermian Basin , which is not included in our expected 2021 capital expenditures. We expect to fund capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. In 2021, it is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control. 84 -------------------------------------------------------------------------------- Table of Contents Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as ofDecember 31, 2020 and 2019.
Total Contractual Cash Obligations. A summary of our total contractual cash
obligations as of
Payments Due by Period
Total 2021 2022 2023 2024 2025 Thereafter
ENLC's & ENLK's senior unsecured
notes $ 4,032.3 $ - $
- $ -
350.0 350.0 - - - - -
Consolidated Credit Facility (2) - - - - - - -
AR Facility (3) 250.0 - - 250.0 - - -
Interest payable on fixed
long-term debt obligations 2,523.2 188.2 201.2 201.2 189.7 163.3 1,579.6
Operating lease obligations 121.7 19.6 13.7 10.2 9.5 9.8 58.9 Purchase obligations 2.0 2.0 - - - - - Pipeline and trucking capacity and deficiency agreements (4) 156.4 41.4 31.9 28.1 19.0 16.0 20.0 Inactive easement commitment (5) 10.0 - 10.0 - - - - Total contractual obligations$ 7,445.6 $ 601.2 $ 256.8 $ 489.5 $ 740.0 $ 909.9 $ 4,448.2 ____________________________ (1)The Term Loan matures onDecember 10, 2021 . (2)The Consolidated Credit Facility will mature onJanuary 25, 2024 . As ofDecember 31, 2020 , there were no amounts outstanding under the Consolidated Credit Facility. (3)The AR Facility is scheduled to terminate onOctober 20, 2023 . (4)Consists of pipeline capacity payments for firm transportation and deficiency agreements. (5)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, the Term Loan, and the AR Facility are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Consolidated Credit Facility, the Term Loan, and the AR Facility, which vary from time to time.
Our contractual cash obligations for 2021 are expected to be funded from cash flows generated from our operations and the available capacity under Consolidated Credit Facility or other debt sources.
Indebtedness
In
As of
In addition, as of
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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
See "Item 8. Financial Statements and Supplementary Data-Note 6" for more information on our outstanding debt instruments. Credit Risk
Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders.
Inflation
Inflation inthe United States has been relatively low in recent years in the economy as a whole. The midstream natural gas industry's labor and material costs remained relatively unchanged in 2019 and 2020. Although the impact of inflation has been insignificant in recent years, it is still a factor inthe United States economy and may increase the cost to acquire or replace property and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation, and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.
Environmental
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see "Item 1. Business-Environmental Matters."
Contingencies
See "Item 8. Financial Statements and Supplementary Data-Note 14."
Recent Accounting Pronouncements
See "Item 8. Financial Statements and Supplementary Data-Note 2" for more information on recently issued and adopted accounting pronouncements.
Disclosure Regarding Forward-Looking Statements
This Annual Report on Form 10-K 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 Annual Report constitute forward-looking statements,
including but not limited to statements identified by the words "forecast,"
"may," "believe," "will," "should," "plan," "predict,"
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Table of Contents "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 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 or prepayment event under our credit facility and certain of our other debt, (e) the dependence onDevon for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affectDevon or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, and (t) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Annual Report, the risk factors set forth in "Item 1A. Risk Factors" 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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