ENLINK MIDSTREAM, LLC Please read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. In addition, please refer to the Definitions page set forth in this report prior to Part I-Financial Information. In this report, the terms "Company" or "Registrant," as well as the terms "ENLC," "our," "we," "us," or like terms, are sometimes used as abbreviated references toEnLink Midstream, LLC itself orEnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to "EnLink Midstream Partners, LP ," the "Partnership," "ENLK," or like terms refer toEnLink Midstream Partners, LP itself orEnLink Midstream Partners, LP together with its consolidated subsidiaries, including theOperating Partnership .
Overview
ENLC is aDelaware limited liability company formed inOctober 2013 . ENLC's 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 12,100 miles of pipelines, 22 natural gas processing plants with approximately 5.5 Bcf/d of processing capacity, seven fractionators with approximately 320,000 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 evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian,Louisiana ,Oklahoma , andNorth Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served:
•Permian Segment. The Permian segment includes our natural gas gathering,
processing, and transmission activities and our crude oil operations in the
Midland and Delaware Basins in
•Louisiana Segment. TheLouisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located inLouisiana and our crude oil operations in ORV; •Oklahoma Segment. TheOklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford ,Arkoma -Woodford , northern Oklahoma Woodford, STACK, and CNOW shale areas;
•North Texas Segment. The
•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV inOklahoma , our ownership interest in GCF inSouth Texas , and our corporate assets and expenses. We manage our consolidated operations by focusing on adjusted gross margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the 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 90% of our 29 -------------------------------------------------------------------------------- Table of Contents adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the three months endedMarch 31, 2022 .
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 for the three months endedMarch 31, 2022 and 2021. The loss of these customers 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 during the periods presented. Three Months Ended March 31, 2022 2021 Dow Hydrocarbons and Resources LLC 13.9 % 14.5 % Marathon Petroleum Corporation 16.1 % 14.8 % We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher adjusted gross margins from product upgrades during periods with higher NGL prices. We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction. We realize adjusted gross margins from our gathering and processing services primarily through different contractual arrangements: processing margin ("margin") contracts, POL contracts, POP contracts, fixed-fee based contracts, or a combination of these contractual arrangements. See "Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk" for a detailed description of these contractual arrangements. Under any of these gathering and processing arrangements, we may earn a fee for the services performed, or we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize a net margin as our fee. Under margin contract arrangements, our adjusted gross 30 -------------------------------------------------------------------------------- Table of Contents 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. CCS Business
We are currently developing an integrated offering to bring CCS services to
businesses along the
Recent Developments Affecting Industry Conditions and Our Business
Current Market Environment
The midstream energy business environment and our business are affected by the level of production of natural gas and oil in the areas in which we operate and the various factors that affect this production, including commodity prices, capital markets trends, competition, and regulatory changes. We believe these factors will continue to affect production and therefore the demand for midstream services and our business in the future. To the extent these factors vary from our underlying assumptions, our business and actual results could vary materially from market expectations and from the assumptions discussed in this section. Production levels by our exploration and production customers are driven in large part by the level of oil and natural gas prices. New drilling activity is necessary to maintain or increase production levels as oil and natural gas wells experience production declines over time. New drilling activity generally moves in the same direction as crude oil and natural gas prices as those prices drive investment returns and cash flow available for reinvestment by exploration and production companies. Accordingly, our operations are affected by the level of crude, natural gas, and NGL prices, the relationship among these prices, and related activity levels from our customers. There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. Commodity markets have now fully recovered from the reduction in global demand and low market prices experienced in 2020 due to the COVID-19 pandemic. However, oil and natural gas prices continue to remain volatile. Oil and natural gas prices, rose during 2021 and have risen very rapidly in 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical risks, includingRussia's invasion ofUkraine . As of the date of this report, the market price for both oil and natural gas are at higher levels than either has traded in many years. Capital markets and the demands of public investors also affect producer behavior, production levels, and our business. Over the last several years, public investors have exerted pressure on oil and natural gas producers to increase capital discipline and focus on higher investment returns even if it means lower growth. In addition, the ability of companies in the oil and gas industry to access the capital markets on favorable terms has been negatively impacted during this same period. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, led to more modest capital investment by producers, curtailed drilling and production activity, and, accordingly, slower growth for us and other midstream companies during the past few years. This trend was amplified in 2020 by the COVID-19 pandemic, which reduced demand for commodities. However, in response to the rise of oil and natural gas prices during 2021 and in 2022 to date, capital investments byUnited States oil and natural gas producers have begun to rise modestly, although global capital investments by oil and natural gas producers remain at relatively low levels compared to historical levels and producers continue to remain cautious. Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In the last few years, many producers have increasingly focused their activities in the Permian 31 -------------------------------------------------------------------------------- Table of Contents Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating inthe United States are operating in thePermian Basin . As a result of this concentration of drilling activity in thePermian Basin , other basins, including those in which we operate inOklahoma andNorth Texas , have experienced reduced investment and declines in volumes produced, although that situation has begun to change as producers now see more opportunity in bothOklahoma andNorth Texas , given higher oil and natural gas prices. We continue to experience an increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity. OurLouisiana segment, while subject to commodity price trends, is less dependent on gathering and processing activities and more affected by industrial demand for the natural gas and NGLs that we supply. Industrial demand along theGulf Coast region has remained strong throughout 2021 and through the first quarter of 2022, supported by regional industrial activity and export markets. Our activities and, in turn, our financial performance in theLouisiana segment are highly dependent on the availability of natural gas and NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to supply our customers, and maintaining such supply is a key business focus.
For additional discussion regarding these factors, see "Item 1A-Risk
Factors-Business and Industry Risks" in our Annual Report on Form 10-K for the
year ended
Extreme Weather Events
From time to time our operations may be affected by extreme weather events such as ice storms and hurricanes. InFebruary 2021 , certain areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of approximately 10 days ("Winter Storm Uri"). Winter Storm Uri adversely affected our facilities and activities across our footprint, as it did for producers and other midstream companies located in these areas. The severe cold temperatures caused production freeze-offs and also led some producers to proactively shut-in their wells to preserve well integrity. As a result, our gathering and processing volumes were significantly reduced during this period, with peak volume declines ranging between 44% and 92%, depending on the region. We responded to the challenges presented by the storm by taking active steps to ensure the resiliency of our assets and the protection of the health and well-being of our employees. Our operations and gathering and processing volumes returned to normal levels by the end of the first quarter of 2021. Because of the magnitude and unprecedented nature of Winter Storm Uri, we cannot predict the full impact that the storm may have on our future results of operations. The ultimate impacts will depend on future developments, including, among other factors, the outcome of pending billing disputes or litigation with customers and regulatory actions by state legislatures and other entities responsible for the regulation and pricing of electricity and the electrical grid. COVID-19 Update OnMarch 11, 2020 , theWorld Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. Beginning inMarch 2020 , we implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers' operations, and we continue to evaluate our response plans and business practices to meet any evolving impacts of COVID-19 and its variants. Since the inception of the pandemic, we have not experienced any significant COVID-19 related operational disruptions. Although the global impacts of COVID-19 have reduced significantly since the beginning of year, there remains considerable uncertainty regarding how long the COVID-19 pandemic (including variants of the virus) will persist and affect economic conditions. We cannot predict the full impact that the COVID-19 pandemic or any related volatility in 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) due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the pandemic, including variants of the virus, the speed at which the population is vaccinated against the virus and the efficacy of the vaccines, the emergence of any new variants of the virus against which vaccines are less effective, the effect of the pandemic on economic, social, and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, and the timing and extent to which normal economic, social, and operating conditions fully resume. 32 -------------------------------------------------------------------------------- Table of Contents For additional discussion regarding risks associated with the COVID-19 pandemic, see "Item 1A-Risk Factors-The ongoing coronavirus (COVID-19) pandemic has adversely affected and could continue to adversely affect our business, financial condition, and results of operations" in our Annual Report on Form 10-K for the year endedDecember 31, 2021 filed with the Commission onFebruary 16, 2022 . Regulatory Developments OnJanuary 20, 2021 , theBiden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers. On his first day in office,President Biden signed an instrument reenteringthe United States into the Paris Agreement, effectiveFebruary 19, 2021 , and issued an executive order on "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis" seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind prior agency actions that are identified as conflicting with theBiden Administration's climate policies. In addition, onJanuary 27, 2021 ,President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of an ongoing comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. OnJune 15, 2021 , however, a judge in theU.S. District Court for the Western District of Louisiana issued a nationwide temporary injunction blocking the suspension.The Department of the Interior appealed theU.S. District Court's ruling but resumed oil and gas leasing pending resolution of the appeal. InNovember 2021 , theDepartment of the Interior completed its review and issued a report on the federal oil and gas leasing program.The Department of the Interior's report recommends several changes to federal leasing practices, including changes to royalty payments, bidding, and bonding requirements. OnApril 15, 2022 , theDepartment of the Interior announced it would make roughly 144,000 acres of federal land available for new drilling, a significant reduction from the footprint of land that had been under evaluation for leasing. The new leases would also require companies to pay royalties of 18.75% of the value of extracted oil and gas products, up from 12.5%. Furthermore, onApril 22, 2021 , at a global summit on climate change,President Biden committedthe United States to target emissions reductions of 50-52% of 2005 levels by 2030. Lastly, onJune 30, 2021 ,President Biden signed into law a reinstatement of regulations put in place during the Obama administration regarding methane emissions. The Company had previously complied with these regulations during the Obama administration and does not expect the reinstatement to have a material effect on the Company or its operations.The Biden Administration could also seek, in the future, to put into place additional executive orders, policy and regulatory reviews, or seek to haveCongress pass legislation that could adversely affect the production of oil and natural gas, and our operations and those of our customers. Only a small percentage of our operations are derived from customers operating on public land, mainly in theDelaware Basin . Our operations in theDelaware Basin are expected to represent only approximately 6% of our total segment profit, net to EnLink, during 2022. In addition, we have a robust program to monitor and prevent methane emissions in our operations and we maintain a comprehensive environmental program that is embedded in our operations. However, our activities that take place on public lands require that we and our producer customers obtain leases, permits, and other approvals from the federal government. While the status of recent and future rules and rulemaking initiatives under theBiden Administration remain uncertain, the regulations that might result from such initiatives, could lead to increased costs for us or our customers, difficulties in obtaining leases, permits, and other approvals for us and our customers, reduced utilization of our gathering, processing and pipeline systems or reduced rates under renegotiated transportation or storage agreements in affected regions. These impacts could, in turn, adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders.
For more information, see our risk factors under "Environmental, Legal
Compliance, and Regulatory Risk" in Section 1A "Risk Factors" in our Annual
Report on Form 10-K for the year ended
Other Recent Developments
CCS-Talos Alliance . InFebruary 2022 , we signed a memorandum of understanding with Talos Energy Inc. ("Talos") to provide a complete CCS offering for industrial-scale emitters inLouisiana , utilizing our midstream assets combined with Talos' subsurface assets. Talos has secured approximately 26,000 acres inLouisiana , providing sequestration capacity of over 500 million metric tonnes. Phantom Processing Plant. InNovember 2021 , we began moving equipment and facilities associated with the Thunderbird processing plant inCentral Oklahoma to theMidland Basin . This processing plant relocation is expected to increase the processing capacity of ourPermian Basin processing facilities by approximately 200 MMcf/d. We expect to complete the relocation in the fourth quarter of 2022. Common Unit Repurchase Program. EffectiveJanuary 1, 2022 , the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to$100.0 million . For the three 33 -------------------------------------------------------------------------------- Table of Contents months endedMarch 31, 2022 , ENLC repurchased 2,093,842 outstanding ENLC common units for an aggregate cost, including commissions, of$17.0 million , or an average of$8.12 per common unit. GIP Repurchase Agreement. OnFebruary 15, 2022 , we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP's then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders. OnMay 2, 2022 , we repurchased 675,095 ENLC common units held by GIP for an aggregate cost of$6.0 million , or an average of$8.92 per common unit. These units represent GIP's pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the period fromFebruary 15, 2022 (the date on which the Repurchase Agreement was signed) throughMarch 31, 2022 . The$8.92 price per common unit is the average per unit price paid by us for the common units repurchased from public unitholders during the same period. For more information about our repurchase agreement with GIP, see Part II, "9B. Other Information" of our Annual Report on Form 10-K for the year endedDecember 31, 2021 filed with the Commission onFebruary 16, 2022 . Redemption of Series B Preferred Units. InJanuary 2022 , we redeemed 3,333,334 Series B Preferred Units for total consideration of$50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC ClassC Common Units were automatically cancelled. The redemption price represents 101% of the preferred units' par value. In connection with the Series B Preferred Unit redemption, we have agreed with the holders of the Series B Preferred Units that we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. See "Item 1. Financial Statements-Note 7" for more information regarding distributions with respect to the Series B Preferred Units. 34 -------------------------------------------------------------------------------- Table of Contents Non-GAAP Financial Measures To assist management in assessing our business, we use the following non-GAAP financial measures: adjusted gross margin; adjusted earnings before interest, taxes, and depreciation and amortization ("adjusted EBITDA"); and free cash flow after distributions. Adjusted Gross Margin We define adjusted gross margin as revenues less cost of sales, exclusive of operating expenses and depreciation and amortization. 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 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 that affect gross margin. Our adjusted gross margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner. The following table reconciles total revenues and gross margin to adjusted gross margin (in millions): Three Months Ended March 31, 2022 2021 Total revenues$ 2,227.7 $ 1,248.4 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,794.5) (934.7) Operating expenses (120.9) (56.3) Depreciation and amortization (152.9) (151.0) Gross margin 159.4 106.4 Operating expenses 120.9 56.3 Depreciation and amortization 152.9 151.0 Adjusted gross margin$ 433.2 $ 313.7 35
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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; (income) loss
from unconsolidated affiliate investments; distributions from unconsolidated
affiliate investments; (gain) loss on disposition of assets; (gain) loss on
extinguishment of debt; unit-based compensation; income tax expense (benefit);
unrealized (gain) loss on commodity swaps; costs associated with the relocation
of processing facilities; accretion expense associated with asset retirement
obligations; transaction costs; (non-cash rent); and (non-controlling interest
share of adjusted EBITDA from joint ventures). Adjusted EBITDA is one of the
primary metrics used in our short-term incentive program for compensating
employees. In addition, adjusted EBITDA is used as a supplemental liquidity and
performance measure by our management and by external users of our financial
statements, such as investors, commercial banks, research analysts, and others,
to assess:
•the financial performance of our assets without regard to financing methods,
capital structure, or historical cost basis;
•the ability of our assets to generate cash sufficient to pay interest costs,
support our indebtedness, and make cash distributions to our unitholders;
•our operating performance and return on capital as compared to those of other
companies in the midstream energy sector, without regard to financing methods or
capital structure; and
•the viability of acquisitions and capital expenditure projects and the overall
rates of return on alternative investment opportunities.
The GAAP measures most directly comparable to adjusted EBITDA are net income
(loss) and net cash provided by operating activities. Adjusted EBITDA should not
be considered an alternative to, or more meaningful than, net income (loss),
operating income (loss), net cash provided by operating activities, or any other
measure of financial performance presented in accordance with GAAP. Adjusted
EBITDA may not be comparable to similarly titled measures of other companies
because other companies may not calculate adjusted EBITDA in the same manner.
Adjusted EBITDA does not include interest expense, net of interest income;
income tax expense (benefit); and depreciation and amortization. Because we have
borrowed money to finance our operations, interest expense is a necessary
element of our costs and our ability to generate cash available for
distribution. Because we have capital assets, depreciation and amortization are
also necessary elements of our costs. Therefore, any measures that exclude these
elements have material limitations. To compensate for these limitations, we
believe that it is important to consider net income (loss) and net cash provided
by operating activities as determined under GAAP, as well as adjusted EBITDA, to
evaluate our overall performance.
36
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The following table reconciles net income to adjusted EBITDA (in millions):
Three Months Ended
March 31,
2022 2021
Net income $ 66.0 $ 12.6
Interest expense, net of interest income 55.1 60.0
Depreciation and amortization 152.9 151.0
Loss from unconsolidated affiliate investments 1.1 6.3
Distributions from unconsolidated affiliate investments 0.2 3.6
Loss on disposition of assets 5.1 -
Unit-based compensation 6.6 6.5
Income tax expense 3.2 1.4
Unrealized loss on commodity swaps 15.1 7.9
Costs associated with the relocation of processing facilities (1)
11.3 7.6
Other (2) 0.3 (0.4)
Adjusted EBITDA before non-controlling interest 316.9 256.5
Non-controlling interest share of adjusted EBITDA from joint ventures (3)
(12.6) (7.1)
Adjusted EBITDA, net to ENLC $ 304.3 $ 249.4 ____________________________
(1)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant andBattle Ridge processing plant in theOklahoma segment to the Permian segment. The relocation of equipment and facilities from theBattle Ridge processing plant was completed in the third quarter of 2021 and we expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022. (2)Includes accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term. (3)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV and Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV. 37 -------------------------------------------------------------------------------- Table of Contents Free Cash Flow After Distributions We define free cash flow after distributions as adjusted EBITDA, net to ENLC, plus (less) (growth and maintenance capital expenditures, excluding capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities); (interest expense, net of interest income); (distributions declared on common units); (accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid); (costs associated with the relocation of processing facilities); non-cash interest (income)/expense; (payments to terminate interest rate swaps); (current income taxes); and proceeds from the sale of equipment and land. Free cash flow after distributions is the principal cash flow metric used by the Company. Free cash flow after distributions is one of the primary metrics used in our short-term incentive program for compensating employees. It is also used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, pay back our indebtedness, make cash distributions, and make capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income. Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations. The GAAP measure most directly comparable to free cash flow after distributions is net cash provided by operating activities. Free cash flow after distributions should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Free cash flow after distributions has important limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Free cash flow after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate this non-GAAP metric in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as free cash flow after distributions, to evaluate our overall liquidity. 38
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Table of Contents The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):
Three Months Ended
March 31,
2022 2021
Net cash provided by operating activities $ 307.7 $ 225.8
Interest expense (1) 53.7 55.9
Utility credits (redeemed) earned (2) (5.6) 40.4
Accruals for settled commodity swap transactions (2.2) 0.1
Distributions from unconsolidated affiliate investment in excess of earnings
0.2 3.6
Costs associated with the relocation of processing facilities (3)
11.3 7.6 Other (4) 1.7 1.2
Changes in operating assets and liabilities which (provided) used cash: Accounts receivable, accrued revenues, inventories, and other
172.7 17.5
Accounts payable, accrued product purchases, and other accrued liabilities
(222.6) (95.6)
Adjusted EBITDA before non-controlling interest 316.9 256.5
Non-controlling interest share of adjusted EBITDA from joint ventures (5)
(12.6) (7.1)
Adjusted EBITDA, net to ENLC 304.3 249.4
Growth capital expenditures, net to ENLC (6) (40.5) (15.9)
Maintenance capital expenditures, net to ENLC (6) (13.9) (4.7)
Interest expense, net of interest income (55.1) (60.0)
Distributions declared on common units (55.5) (46.7)
ENLK preferred unit accrued cash distributions (7) (23.5) (23.0)
Costs associated with the relocation of processing facilities (3) (11.3)
(7.6)
Other (8) 0.4 2.7
Free cash flow after distributions $ 104.9 $ 94.2 ____________________________
(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA. (2)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. These utility credits are recorded as "Other current assets" or "Other assets, net" on our consolidated balance sheets depending on the timing of their expected usage, and amortized as we incur utility expenses. (3)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant andBattle Ridge processing plant in theOklahoma segment to the Permian segment. The relocation of equipment and facilities from theBattle Ridge processing plant was completed in the third quarter of 2021 and we expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022. (4)Includes current income tax expense and non-cash rent, which relates to lease incentives pro-rated over the lease term. (5)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV and Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV. (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 current income tax expense, non-cash interest (income)/expense, and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business. 39 -------------------------------------------------------------------------------- Table of Contents Results of Operations
The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the tables below (in millions, except volumes):
Permian Louisiana Oklahoma North Texas Corporate Totals
Three Months Ended March 31, 2022
Gross margin $ 36.3 $ 55.0 $ 34.9 $ 34.6 $ (1.4) $ 159.4
Depreciation and amortization 36.7 35.5 50.9 28.4 1.4 152.9
Segment profit 73.0 90.5 85.8 63.0 - 312.3
Operating expenses 45.3 33.0 21.0 21.6 - 120.9
Adjusted gross margin $ 118.3 $ 123.5 $ 106.8 $ 84.6 $ - $ 433.2
Three Months Ended March 31, 2021
Gross margin $ 9.3 $ 46.1 $ 4.8 $ 48.2 $ (2.0) $ 106.4
Depreciation and amortization 33.5 36.1 50.7 28.7 2.0 151.0
Segment profit 42.8 82.2 55.5 76.9 - 257.4
Operating expenses (11.8) 29.2 19.7 19.2 - 56.3
Adjusted gross margin $ 31.0 $ 111.4 $ 75.2 $ 96.1 $ - $ 313.7
Three Months Ended
March 31,
2022 2021
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d) 1,347,100 925,600
Processing (MMbtu/d) 1,256,300 876,100
Crude Oil Handling (Bbls/d) 150,700 108,200
Louisiana Segment
Gathering and Transportation (MMbtu/d) 2,497,700 2,151,300
Crude Oil Handling (Bbls/d) 15,900 15,000
NGL Fractionation (Gals/d) 8,033,900 7,106,200
Brine Disposal (Bbls/d) 3,000 1,400
Oklahoma Segment
Gathering and Transportation (MMbtu/d) 1,000,700 937,300
Processing (MMbtu/d) 1,029,500 955,400
Crude Oil Handling (Bbls/d) 23,800 17,500
North Texas Segment
Gathering and Transportation (MMbtu/d) 1,364,000 1,356,900
Processing (MMbtu/d) 614,300 624,600
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Three Months Ended
Gross Margin. Gross margin was$159.4 million for the three months endedMarch 31, 2022 compared to$106.4 million for the three months endedMarch 31, 2021 , an increase of$53.0 million . The primary contributors to the increase were as follows: •Permian Segment. Gross margin was$36.3 million for the three months endedMarch 31, 2022 compared to$9.3 million for the three months endedMarch 31, 2021 , an increase of$27.0 million primarily due to the following:
•Adjusted gross margin in the Permian segment increased
•A$71.5 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased$20.1 million , which was primarily due to higher volumes from existing customers. Derivative activity associated with our Permian gas assets increased margin by$51.4 million , which included$56.7 million from decreased realized losses, primarily due to realized losses from Winter Storm Uri inFebruary 2021 , and$5.3 million from increased unrealized losses. •A$15.8 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased$13.3 million , which was primarily due to higher volumes from existing customers and the timing of physical trades. Derivative activity associated with our Permian crude assets increased margin by$2.5 million , which included$2.2 million from increased realized losses and$4.7 million from increased unrealized gains. •Operating expenses in the Permian segment increased$57.1 million primarily due to$40.0 million of utility credits that we received because our electricity usage was below our contractual base load amounts during Winter Storm Uri inFebruary 2021 . Operating expenses also increased due to higher construction fees and services and increases in materials and supplies expense and compressor rentals due to higher volumes. •Depreciation and amortization in the Permian segment increased$3.2 million primarily due to new assets placed into service, including gathering and processing assets associated with the acquisition ofAmarillo Rattler, LLC inApril 2021 . •Louisiana Segment. Gross margin was$55.0 million for the three months endedMarch 31, 2022 compared to$46.1 million for the three months endedMarch 31, 2021 , an increase of$8.9 million primarily due to the following:
•Adjusted gross margin in the
•A$10.3 million increase to adjusted gross margin associated with ourLouisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased$7.6 million , which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by$2.7 million , which included$7.0 million from decreased realized losses and$4.3 million from increased unrealized losses. •A$0.9 million increase to adjusted gross margin associated with ourLouisiana gas assets. Adjusted gross margin, excluding derivative activity, increased$4.4 million , which was primarily due to higher volumes from existing customers. Derivative activity associated with ourLouisiana gas assets decreased margin by$3.5 million , which included$2.6 million from increased realized losses and$0.9 million from increased unrealized losses. •A$0.9 million increase to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased$1.2 million , which was primarily due to higher volumes from existing customers. Derivative activity associated with our ORV crude assets decreased margin by$0.3 million from increased realized losses.
•Operating expenses in the
•Depreciation and amortization in theLouisiana segment decreased$0.6 million primarily due to changes in estimated useful lives of certain non-core assets that were fully depreciated in the second quarter of 2021. 41 -------------------------------------------------------------------------------- Table of Contents •Oklahoma Segment. Gross margin was$34.9 million for the three months endedMarch 31, 2022 compared to$4.8 million for the three months endedMarch 31, 2021 , an increase of$30.1 million primarily due to the following:
•Adjusted gross margin in the
•A$29.5 million increase to adjusted gross margin associated with ourOklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased$32.9 million , which was primarily due to higher volumes from existing customers. Derivative activity associated with ourOklahoma gas assets decreased margin by$3.4 million , which included$2.3 million from decreased realized losses and$5.7 million from increased unrealized losses. •A$2.1 million increase to adjusted gross margin associated with ourOklahoma crude assets. Adjusted gross margin, excluding derivative activity, increased$1.7 million , which was primarily due to higher volumes from existing customers. Derivative activity associated with ourOklahoma crude assets increased margin by$0.4 million from decreased unrealized losses. •Operating expenses in theOklahoma segment increased$1.3 million primarily due to increases in materials and supplies expense and construction fees and services. These increases were partially offset by a decrease in operation and maintenance costs and ad valorem taxes. •Depreciation and amortization in theOklahoma segment increased$0.2 million due to additional assets placed in service, partially offset by the transfer of equipment to the Phantom and Warhorse processing facilities. •North Texas Segment. Gross margin was$34.6 million for the three months endedMarch 31, 2022 compared to$48.2 million for the three months endedMarch 31, 2021 , a decrease of$13.6 million primarily due to the following: •Adjusted gross margin in theNorth Texas segment decreased$11.5 million . Adjusted gross margin, excluding derivative activity, decreased$13.9 million , which was primarily due to favorable market pricing resulting from Winter Storm Uri inFebruary 2021 . Derivative activity associated with ourNorth Texas segment increased margin by$2.4 million , which included$1.5 million from increased realized losses and$3.9 million from increased unrealized gains. •Operating expenses in theNorth Texas segment increased$2.4 million primarily due to increases in materials and supplies expense, sales and use taxes, and utility costs. These increases were partially offset by a decrease in operations and maintenance costs.
•Depreciation and amortization in the
•Corporate Segment. Gross margin was negative
General and Administrative Expenses. General and administrative expenses were$29.0 million for the three months endedMarch 31, 2022 compared to$26.0 million for the three months endedMarch 31, 2021 , an increase of$3.0 million . The increase was primarily due to labor and benefits costs and consulting fees and services. 42 -------------------------------------------------------------------------------- Table of Contents Interest Expense. Interest expense was$55.1 million for the three months endedMarch 31, 2022 compared to$60.0 million for the three months endedMarch 31, 2021 , a decrease of$4.9 million . Interest expense consisted of the following (in millions): Three Months Ended March 31, 2022 2021 ENLK and ENLC Senior Notes$ 50.3 $ 50.3 Term Loan - 1.4 Consolidated Credit Facility 2.3 1.3 AR Facility 1.1 1.2 Capitalized interest - (0.2)
Amortization of debt issuance costs and net discount of senior unsecured notes
1.3 1.2
Interest rate swaps - realized 0.1 4.8
Total $ 55.1 $ 60.0
Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated
affiliate investments was $1.1 million for the three months ended March 31, 2022
compared to a loss of $6.3 million for the three months ended March 31, 2021 , a
reduction in loss of $5.2 million . The reduction in loss was primarily
attributable to a reduction in loss of $5.0 million from our GCF investment, as
a result of the GCF assets being idled beginning in January 2021 , and a
reduction in loss of $0.2 million from our Cedar Cove JV.
Income Tax Expense. Income tax expense was $3.2 million for the three months
ended March 31, 2022 compared to an income tax expense of $1.4 million for the
three months ended March 31, 2021 . The increase in income tax expense was
primarily attributable to the increase in income between periods. See "Item 1.
Financial Statements-Note 6" for additional information.
Net Income Attributable to Non-Controlling Interest. Net income attributable to
non-controlling interest was $30.8 million for the three months ended March 31,
2022 compared to net income of $25.3 million for the three months ended
March 31, 2021 , an increase of $5.5 million . ENLC's non-controlling interest is
comprised of Series B Preferred Units, Series C Preferred Units, NGP's 49.9%
share of the Delaware Basin JV, and Marathon Petroleum Corporation's 50% share
of the Ascension JV. The increase in income was primarily due to a $4.6 million
increase attributable to NGP's 49.9% share of the Delaware Basin JV and a $1.0
million increase attributable to Marathon Petroleum Corporation's 50% share of
the Ascension JV. These increases were offset by $0.1 million reduction in
income attributable to the Series B Preferred Units following the partial
redemptions of the Series B Units in December 2021 and January 2022 .
Critical Accounting Policies
Information regarding our critical accounting policies is included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the year endedDecember 31, 2021 filed with the Commission onFebruary 16, 2022 .
Liquidity and Capital Resources
Cash Flows from Operating Activities. Net cash provided by operating activities was$307.7 million for the three months endedMarch 31, 2022 compared to$225.8 million for the three months endedMarch 31, 2021 . Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions): Three Months EndedMarch 31, 2022 2021
Operating cash flows before working capital
49.9 78.1
Operating cash flows before changes in working capital increased $110.1 million
for the three months ended March 31, 2022 compared to the three months ended
March 31, 2021 . The primary contributor to the increase in operating cash flows
was as follows:
•Gross margin, excluding depreciation and amortization, non-cash commodity swap
activity, utility credits redeemed or earned, and unit-based compensation,
increased
43
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Table of Contents
margin for the three months ended March 31, 2022 compared to the three months
ended March 31, 2021 , see "Results of Operations."
The changes in working capital for the three months ended March 31, 2022
compared to the three months ended March 31, 2021 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
Three Months Ended
March 31,
2022 2021
Additions to property and equipment (1)
____________________________
(1)The increase in capital expenditures was due to expansion projects to accommodate increased volumes on our systems.
Cash Flows from Financing Activities. Net cash used in financing activities was
Three Months Ended
March 31,
2022 2021
Net repayments on the AR Facility (1) $ (35.0) $ (100.0)
Net repayments on the Consolidated Credit Facility (1) (15.0)
-
Contributions by non-controlling interests (2) 7.3
0.9
Distributions to members (56.4)
(47.1)
Distributions to Series B Preferred Unitholders (3) (18.6)
(16.9)
Redemption of Series B Preferred Units (3) (50.5)
-
Distributions to joint venture partners (4) (16.0) (9.1) Common unit repurchases (5) (17.0) - ____________________________ (1)See "Item 1. Financial Statements-Note 5" for more information regarding the AR Facility and the Consolidated Credit Facility. (2)Represents contributions from NGP to theDelaware Basin JV. (3)See "Item 1. Financial Statements-Note 7" for information on distributions to holders of the Series B Preferred Units and information on the partial redemption of the Series B Preferred Units. (4)Represents distributions to NGP for its ownership in theDelaware Basin JV and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV. (5)See "Item 1. Financial Statements-Note 8" for more information regarding the ENLC common unit repurchase program. 44 -------------------------------------------------------------------------------- Table of Contents Capital Requirements
The following table summarizes our expected remaining capital requirements for 2022 (in millions):
Capital expenditures, net to ENLC (1)$ 245 Operating expenses associated with the relocation of processing facilities (2) 34 Total$ 279
____________________________
(1)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities. (2)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant in theOklahoma segment to the Permian segment. We expect to complete the relocation of equipment and facilities from the Thunderbird processing plant in the fourth quarter of 2022.
Our primary capital projects for 2022 include the relocation of the Phantom processing plant, CCS-related initiatives, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our remaining 2022 capital requirements from operating cash flows.
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
Total Contractual Cash Obligations. A summary of our total contractual cash
obligations as of
Payments Due by Period
Total Remainder 2022 2023 2024 2025 2026 Thereafter
ENLC's & ENLK's senior unsecured notes$ 4,032.3 $ -
$ -
2,298.7
Consolidated Credit Facility (1) - - - - - - - AR Facility (2) 315.0 - - 315.0 - - - Acquisition installment payable (3) 10.0 10.0 - - - -
-
Acquisition contingent consideration (4) 6.9 - - 2.3 2.4 2.2
-
Interest payable on fixed long-term debt obligations 2,308.9 175.2 201.2 189.7 163.3 148.3
1,431.2
Operating lease obligations 116.6 17.7 19.2 10.5 9.8 8.9 50.5 Purchase obligations 4.6 4.6 - - - - - Pipeline and trucking capacity and deficiency agreements (5) 297.8 38.1 55.7 44.2 39.4 30.9
89.5
Inactive easement commitment (6) 10.0 10.0 - - - -
-
Total contractual obligations
3,869.9
____________________________
(1)The Consolidated Credit Facility will mature onJanuary 25, 2024 . As ofMarch 31, 2022 , there were no amounts outstanding under the Consolidated Credit Facility. (2)The AR Facility will terminate onSeptember 24, 2024 , unless extended or earlier terminated in accordance with its terms. (3)Amount related to the consideration of theAmarillo Rattler, LLC acquisition, which was paid onApril 30, 2022 . (4)The estimated fair value of theAmarillo Rattler, LLC contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from these estimated fair values. See "Item 1. Financial Statements-Note 11" for additional information. (5)Consists of pipeline capacity payments for firm transportation and deficiency agreements. (6)Amount related to inactive easements paid as utilized by us with the balance due inAugust 2022 if not utilized. 45 -------------------------------------------------------------------------------- Table of Contents 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 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 and the AR Facility, which vary from time to time. Our contractual cash obligations for the remainder of 2022 are expected to be funded from cash flows generated from our operations and the available capacity under the Consolidated Credit Facility, the AR Facility, or other debt sources.
Indebtedness
As of
In addition, as ofMarch 31, 2022 , we have$4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. There were no outstanding borrowings under the Consolidated Credit Facility and$44.3 million outstanding letters of credit as ofMarch 31, 2022 . Guarantees. The amounts outstanding on our senior unsecured notes 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 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 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 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 ofMarch 31, 2022 , ENLC records, on a stand-alone basis, transactions that do not occur at ENLK, which are primarily related to the taxation of ENLC and the elimination of intercompany borrowings.
See "Item 1. Financial Statements-Note 5" for more information on our outstanding debt.
Inflation
Inflation inthe United States has been relatively low in recent years. However, the annualU.S. inflation rate accelerated in 2021 and through the first quarter of 2022. It is widely expected that this trend will continue for the remainder of 2022. In addition, at itsMarch 2022 meeting, theFederal Reserve announced that it would be increasing its target for the federal funds rate (the benchmark for most interest rates) for the first time since 2018. Although we do not expect inflation to have a material effect on our results, higher inflation may increase the cost to acquire or replace property and equipment and the cost 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. Additionally, certain of our revenue generating contracts contain clauses that increase our fees based on changes in inflation metrics.
Recent Accounting Pronouncements
We have reviewed recently issued accounting pronouncements that became effective during the three months endedMarch 31, 2022 and have determined that none would have a material impact to our consolidated financial statements.
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
46--------------------------------------------------------------------------------
Table of Contents statements. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words "forecast," "may," "believe," "will," "should," "plan," "predict," "anticipate," "intend," "estimate," "expect," "continue," and similar expressions. Such forward-looking statements include, but are not limited to, statements about when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, future cost savings or operational, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic, Winter Storm Uri, and other weather related events on us and our financial results and operations, and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operations, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) on our business, financial condition, and results of operations, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP's own interests to the detriment of our unitholders, (c) GIP's ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or businesses, (d) a default under GIP's credit facility could result in a change in control of us, could adversely affect the price of our common units, and could result in a default or prepayment event under our credit facility and certain of our other debt, (e) the dependence on our significant customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect our significant customers or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, and (t) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year endedDecember 31, 2021 filed with the Commission onFebruary 16, 2022 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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