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. As ofMarch 31, 2023 , our midstream energy asset network includes approximately 13,600 miles of pipelines, 26 natural gas processing plants with approximately 6.0 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 geography and nature of activity. We have five reportable segments:
•Permian Segment. The Permian segment includes our natural gas gathering,
processing, and transmission activities and our crude oil operations in the
Midland and Delaware Basins in
•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 Cana-Woodford ,Arkoma -Woodford , northern Oklahoma Woodford, STACK, and adjacent areas;
•North Texas Segment. The
•Corporate Segment. The Corporate segment includes our unconsolidated affiliate
investments in the Cedar Cove JV in
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 85% of our adjusted gross margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the three months endedMarch 31, 2023 . 32
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Table of Contents 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, 2023 and 2022. No other customers represented greater than 10% of our consolidated revenues during the periods presented. Three Months Ended March 31, 2023 2022 Dow Hydrocarbons and Resources LLC 11.4 % 13.9 % Marathon Petroleum Corporation 20.1 % 16.1 % 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. 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. 33 -------------------------------------------------------------------------------- Table of Contents 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 building a carbon transportation business in support of CCS activity along theMississippi River corridor inLouisiana , one of the highest CO2 emitting regions inthe United States . We believe our existing asset footprint, including our extensive network of natural gas pipelines inLouisiana , our operating expertise and our customer relationships, provide us with an advantage in building a carbon transportation business and becoming the transporter of choice in the region.
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. Low prices for these commodities could reduce the demand for our services and the volumes in our systems. 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 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 rose especially rapidly in the first half of 2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical events, includingRussia's invasion ofUkraine . Since that time, both oil and especially natural gas prices have declined from their peaks during 2022, with natural gas prices declining significantly since the beginning of 2023 and returning to pre-pandemic price levels. 34
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The table below shows the range of closing prices for crude oil, NGL, and
natural gas during the three months ended
Three Months Ended
March 31,
2023 2022
Commodity Index Closing Price Date Closing Price Date
Crude oil (high) NYMEX $ 81.62 January 23, 2023 $ 123.70 March 8, 2022
Crude oil (low) NYMEX $ 66.74 March 17, 2023 $ 76.08 January 3, 2022
Crude oil (average) (1) NYMEX $ 75.99 - $ 95.01 -
NGL (high) OPIS Napoleonville $ 0.69 January 19, 2023 $ 1.12 March 8, 2022
NGL (low) OPIS Napoleonville $ 0.49 March 16, 2023 $ 0.75 January 3, 2022
NGL (average) (1) OPIS Napoleonville $ 0.61 - $ 0.92 -
Natural gas (high) Henry Hub Gas Daily $ 4.17 January 4, 2023 $ 5.64 March 31, 2022
Natural gas (low) Henry Hub Gas Daily $ 1.99 March 29, 2023 $ 3.72 January 4, 2022
Natural gas (average) (1) Henry Hub Gas Daily $ 2.74 - $ 4.56 -
____________________________(1)The average closing price was computed by taking the sum of the closing prices of each trading day divided by the number of trading days during the period presented.
The volatility in commodity prices may cause our adjusted gross margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. 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. This demand by investors for increased capital discipline from energy companies 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 2022, capital investments byUnited States oil and natural gas producers have risen, although global capital investments by oil and natural gas producers remain below 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 thePermian Basin , because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating inthe United States are operating in thePermian Basin . We continue to experience a robust increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity. As a result of this concentration of drilling activity in thePermian Basin , other basins, including those in which we operate inOklahoma andNorth Texas , experienced reduced investment and declines in volumes produced. However, the rise in commodity prices during 2022 led to renewed producer interest inOklahoma andNorth Texas which has continued into 2023. However, the recent decline in natural gas prices could cause producer activity to decrease in these areas during the second half of 2023. 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 2022 and has continued into 2023, 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
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Inflation
Inflation in the United States increased significantly in 2022 and has continued
during the first quarter of 2023. In addition, in order to reduce the inflation
rate, the Federal Reserve increased its target for the federal funds rate (the
benchmark for most interest rates) several times in 2022 and 2023. This trend
may continue during the remainder of 2023.
To the extent that a rising cost environment impacts our results, there are
typically offsetting benefits either inherent in our business or that result
from other steps we take proactively to reduce the impact of inflation on our
net operating results. These benefits include: (1) provisions included in our
long-term fee-based revenue contracts that offset cost increases in the form of
rate escalations based on positive changes in the U.S. Consumer Price Index,
Producer Price Index for Finished Goods, or other factors; (2) provisions in our
contracts that enable us to pass through higher costs to customers; and (3)
higher commodity prices, which generally enhance our results in the form of
increased volumetric throughput and demand for our services. For these reasons,
the increased cost environment, caused in part by inflation, has not had a
material impact on our historical results of operations for the periods
presented in this report. However, a significant or prolonged period of high
inflation could adversely impact our results if costs were to increase at a rate
greater than the increase in the revenues we receive.
Regulatory Developments
Any regulatory changes could 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 Item 1A-Risk Factors-"Environmental, Legal Compliance, and Regulatory Risk" in our Annual Report on Form 10-K for the year endedDecember 31, 2022 filed with the Commission onFebruary 15, 2023 .
Other Recent Developments
Organic Growth
Tiger II Processing Plant. In the first half of 2023, we plan to begin moving equipment and facilities associated with the non-operational Cowtown processing plant inNorth Texas to our Delaware JV operations in the Permian. The relocation is expected to increase the processing capacity of ourPermian Basin processing facilities by approximately 150 MMcf/d. We expect to complete the relocation in the second quarter of 2024.
GCF Operations. In January of 2023, we began the process to restart the GCF assets and expect operations to begin in 2024. We will continue to make capital contributions during 2023 associated with the restart of these assets.
Equity
Common Unit Repurchase Program. In the first quarter of 2023, we repurchased 2,207,305 outstanding common units in open market purchases, for an aggregate cost, including commissions, of$26.8 million , or an average of$12.14 per common unit. GIP Repurchase Agreement. OnFebruary 13, 2023 , we repurchased 2,237,110 ENLC common units held by GIP for an aggregate cost of$24.6 million , or an average of$11.01 per common unit.
See "Item 1. Financial Statements-Note 9" for more information regarding our common unit repurchases.
Repurchase of Series C Preferred Units. InFebruary 2023 , we repurchased 4,500 Series C Preferred Units for total consideration of$3.9 million . The repurchase price represented 87% of the preferred units' par value.
See "Item 1. Financial Statements-Note 8" for more information regarding the Series C Preferred Units.
Debt Senior Unsecured Notes Issuance. OnApril 3, 2023 , we completed the sale of an additional$300.0 million aggregate principal amount of 6.500% senior notes due 2030 (the "Additional Notes") at 99% of their face value. The Additional Notes were offered as an additional issue of our existing 6.500% senior notes due 2030 that we issued onAugust 31, 2022 in an aggregate principal amount of$700.0 million . Net proceeds of approximately$294.5 million were used to repay a portion of the borrowings under the Revolving Credit Facility. The Additional Notes are fully and unconditionally guaranteed by ENLK. 36 -------------------------------------------------------------------------------- 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, 2023 2022 Total revenues$ 1,767.5 $ 2,227.7 Cost of sales, exclusive of operating expenses and depreciation and amortization (1,271.9) (1,794.5) Operating expenses (132.4) (120.9) Depreciation and amortization (160.4) (152.9) Gross margin 202.8 159.4 Operating expenses 132.4 120.9 Depreciation and amortization 160.4 152.9 Adjusted gross margin$ 495.6 $ 433.2 37
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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 derivatives; costs associated with the
relocation of processing facilities; accretion expense associated with asset
retirement obligations; transaction costs; non-cash expense related to changes
in the fair value of contingent consideration; (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.
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The following table reconciles net income to adjusted EBITDA (in millions):
Three Months Ended
March 31,
2023 2022
Net income $ 94.2 $ 66.0
Interest expense, net of interest income 68.5 55.1
Depreciation and amortization 160.4 152.9
Loss from unconsolidated affiliate investments 0.1 1.1
Distributions from unconsolidated affiliate investments 0.1 0.2
(Gain) loss on disposition of assets (0.4) 5.1
Unit-based compensation 4.0 6.6
Income tax expense 10.9 3.2
Unrealized loss on commodity derivatives 1.4 15.1
Costs associated with the relocation of processing facilities (1)
0.4 11.3
Other (2) 0.3 0.3
Adjusted EBITDA before non-controlling interest 339.9 316.9
Non-controlling interest share of adjusted EBITDA from joint ventures (3)
(16.2) (12.6)
Adjusted EBITDA, net to ENLC $ 323.7 $ 304.3 ____________________________
(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 in theOklahoma segment to the Permian segment, where it is operating as the Phantom processing plant. The Phantom processing plant began operations inOctober 2022 . (2)Includes transaction costs, non-cash expense related to changes in the fair value of contingent consideration, 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. 39 -------------------------------------------------------------------------------- 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); (payment to redeem mandatorily redeemable non-controlling interest); (costs associated with the relocation of processing facilities); non-cash interest (income)/expense; (contributions to investment in unconsolidated affiliates); (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. It is also used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, pay back our indebtedness, make cash distributions, and make capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income. Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations. The GAAP measure most directly comparable to free cash flow after distributions is net cash provided by operating activities. Free cash flow after distributions should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Free cash flow after distributions has important limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Free cash flow after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate this non-GAAP metric in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as free cash flow after distributions, to evaluate our overall liquidity. 40
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Table of Contents The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):
Three Months Ended
March 31,
2023 2022
Net cash provided by operating activities $ 272.1 $ 307.7
Interest expense (1) 67.0 53.7
Utility credits redeemed (2) (1.4) (5.6)
Accruals for settled commodity derivative transactions - (2.2)
Distributions from unconsolidated affiliate investment in excess of earnings
0.1 0.2
Costs associated with the relocation of processing facilities (3) 0.4
11.3
Other (4) 0.1 1.7
Changes in operating assets and liabilities which (provided) used cash: Accounts receivable, accrued revenues, inventories, and other (169.4)
172.7
Accounts payable, accrued product purchases, and other accrued liabilities
171.0 (222.6)
Adjusted EBITDA before non-controlling interest 339.9 316.9
Non-controlling interest share of adjusted EBITDA from joint ventures (5)
(16.2) (12.6)
Adjusted EBITDA, net to ENLC 323.7 304.3
Growth capital expenditures, net to ENLC (6) (92.7) (40.5)
Maintenance capital expenditures, net to ENLC (6) (14.2) (13.9)
Interest expense, net of interest income (68.5) (55.1)
Distributions declared on common units (58.7) (55.5)
ENLK preferred unit accrued cash distributions (7) (23.6) (23.5)
Payment to redeem mandatorily redeemable non-controlling interest (8)
(10.5) -
Costs associated with the relocation of processing facilities (3) (0.4)
(11.3)
Contribution to investment in unconsolidated affiliates (49.7) -
Other (9) 0.3 0.4
Free cash flow after distributions $ 5.7 $ 104.9 ____________________________
(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA. (2)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. These utility credits are recorded as "Other current assets" on our consolidated balance sheets 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 in theOklahoma segment to the Permian segment, where it is operating as the Phantom processing plant. The Phantom processing plant began operations inOctober 2022 . (4)Includes transaction costs, 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 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. (8)InJanuary 2023 , we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries. See "Item 1. Financial Statements-Note 2" for more information regarding the redemption. (9)Includes current income tax expense and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business. 41 -------------------------------------------------------------------------------- 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, 2023
Total revenues $ 601.2 $ 1,103.9 $ 313.4 $ 191.7 $ (442.7) $ 1,767.5
Cost of sales, exclusive of
operating expenses and depreciation
and amortization (457.1) (973.9) (194.0) (89.6) 442.7 (1,271.9)
Adjusted gross margin 144.1 130.0 119.4 102.1 - 495.6
Operating expenses (48.1) (33.6) (24.7) (26.0) - (132.4)
Segment profit 96.0 96.4 94.7 76.1 - 363.2
Depreciation and amortization (40.0) (38.3) (51.9) (28.8) (1.4) (160.4)
Gross margin $ 56.0 $ 58.1 $ 42.8 $ 47.3 $ (1.4) $ 202.8
Permian Louisiana Oklahoma North Texas Corporate Totals
Three Months Ended March 31, 2022
Total revenues $ 885.0 $ 1,512.2 $ 383.6 $ 242.0 $ (795.1) $ 2,227.7
Cost of sales, exclusive of
operating expenses and depreciation
and amortization (766.7) (1,388.7) (276.8) (157.4) 795.1 (1,794.5)
Adjusted gross margin 118.3 123.5 106.8 84.6 - 433.2
Operating expenses (45.3) (33.0) (21.0) (21.6) - (120.9)
Segment profit 73.0 90.5 85.8 63.0 - 312.3
Depreciation and amortization (36.7) (35.5) (50.9) (28.4) (1.4) (152.9)
Gross margin $ 36.3 $ 55.0 $ 34.9 $ 34.6 $ (1.4) $ 159.4
Three Months Ended
March 31,
2023 2022
Midstream Volumes:
Consolidated
Gathering and Transportation (MMbtu/d) 7,172,700 6,209,500
Processing (MMbtu/d) 3,469,600 2,900,100
Crude Oil Handling (Bbls/d) 188,100 190,400
NGL Fractionation (Gals/d) 7,690,000 8,033,900
Brine Disposal (Bbls/d) 3,000 3,000
Permian Segment
Gathering and Transportation (MMbtu/d) 1,683,700 1,347,100
Processing (MMbtu/d) 1,560,700 1,256,300
Crude Oil Handling (Bbls/d) 142,600 150,700
Louisiana Segment
Gathering and Transportation (MMbtu/d) 2,693,500 2,497,700
Crude Oil Handling (Bbls/d) 18,300 15,900
NGL Fractionation (Gals/d) 7,690,000 8,033,900
Brine Disposal (Bbls/d) 3,000 3,000
Oklahoma Segment
Gathering and Transportation (MMbtu/d) 1,178,400 1,000,700
Processing (MMbtu/d) 1,164,300 1,029,500
Crude Oil Handling (Bbls/d) 27,200 23,800
North Texas Segment
Gathering and Transportation (MMbtu/d) 1,617,100 1,364,000
Processing (MMbtu/d) 744,600 614,300
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Table of Contents
Three Months Ended
Revenues and Cost of Sales, Exclusive of Operating Expenses and Depreciation and Amortization.
Our consolidated and segment revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, are from natural gas, NGL, crude oil, and condensate product sales and purchases, midstream services that we perform on those commodities, and derivative activity. Fluctuations in our consolidated and segment revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, reflect in large part changes in commodity prices and volumes. Our adjusted gross margin is not directly affected by the commodity price environment because the commodities that we buy and sell are generally based on the same pricing indices. Both consolidated and segment product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, will fluctuate with market prices; however, the adjusted gross margin related to those sales and purchases will not necessarily have a corresponding increase or decrease. Additionally, fluctuations in these measures from changes in commodity prices may be offset by gains or losses from derivative instruments that we use to manage our exposure to commodity price risk associated with such sales and purchases.
Total revenues and cost of sales, exclusive of operating expenses and
depreciation and amortization, decreased
•Product sales revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased$567.6 million and$522.6 million , respectively, for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 primarily due to lower commodity prices in 2023. •Revenues from midstream services increased$64.3 million for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 primarily due to higher volumes in 2023. Of these higher volumes in 2023,$17.5 million was related to contributions from acquisitions completed during 2022. •Derivative losses decreased$43.1 million for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 due to$29.4 million of increased realized gains and$13.7 million of decreased unrealized losses. Operating Expenses. Operating expenses increased$11.5 million for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 primarily due to$5.1 million of higher utility costs,$4.9 million of increased compressor rentals,$3.4 million of higher materials and supplies expense, and$1.6 million of higher compressor overhaul costs. The increase was partially offset by$4.5 million of decreased construction fees and services. Depreciation and Amortization. Depreciation and amortization increased$7.5 million for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 primarily due to$5.8 million of depreciation due to changes in estimated useful lives,$3.7 million of depreciation due to acquisitions completed in 2022, and$3.4 million of depreciation due to additional assets placed in service. These increases were partially offset by decreased depreciation of$3.5 million related to assets reaching the end of their useful lives and a$1.9 million decrease due to accelerated depreciation recorded in the first quarter of 2022 related to the relocation of assets to the Phantom processing facility. Interest Expense, Net of Interest Income. Interest expense, net of interest income, was$68.5 million for the three months endedMarch 31, 2023 compared to$55.1 million for the three months endedMarch 31, 2022 , an increase of$13.4 million . Interest expense, net of interest income, consisted of the following (in millions): Three Months Ended March 31, 2023 2022 ENLK and ENLC senior notes$ 53.9 $ 50.3 Revolving Credit Facility 7.5 2.3 AR Facility 6.2 1.1
Amortization of debt issuance costs and net discount of senior unsecured notes
1.5 1.3
Interest rate swaps - realized (0.5) 0.1
Other (0.1) -
Interest expense, net of interest income $ 68.5 $ 55.1
43-------------------------------------------------------------------------------- Table of Contents Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was$0.1 million for the three months endedMarch 31, 2023 compared to a loss of$1.1 million for the three months endedMarch 31, 2022 , a reduction in loss of$1.0 million . The reduction in loss was primarily attributable to income of$1.6 million related to the Matterhorn JV for the three months endedMarch 31, 2023 . The reduction in loss was partially offset by an increase in loss of$0.4 million related to our GCF investment and$0.2 million related to the Cedar Cove JV. Income Tax Expense. Income tax expense was$10.9 million for the three months endedMarch 31, 2023 compared to an income tax expense of$3.2 million for the three months endedMarch 31, 2022 . The increase in income tax expense was primarily attributable to the increase in income between periods. See "Item 1. Financial Statements-Note 7" for additional information. Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was$36.0 million for the three months endedMarch 31, 2023 compared to net income of$30.8 million for the three months endedMarch 31, 2022 , an increase of$5.2 million . 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, and Marathon Petroleum Corporation's 50% share of the Ascension JV. The increase in income was primarily due to a$4.5 million increase attributable to NGP's 49.9% share of theDelaware Basin JV and a$2.4 million increase in income attributable to the Series C Preferred Units. The increase in income was partially offset by a$0.9 million decrease attributable to Marathon Petroleum Corporation's 50% share of the Ascension JV and a$0.8 million decrease in income attributable to the Series B Preferred Units.
Analysis of Operating Segments
We manage and report our activities primarily according to the geography and nature of activity. We have five reportable segments: Permian segment,Louisiana segment,Oklahoma segment,North Texas segment, and Corporate segment. We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. The GAAP measure most directly comparable to adjusted gross margin and segment profit is gross margin. We also believe that investors benefit from having access to the same financial measures that our management uses to evaluate segment results.
See below for our discussion of segment results for the three months ended
•Permian Segment.
•Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased$283.8 million and$309.6 million , respectively, resulting in an increase in adjusted gross margin in the Permian segment of$25.8 million , which was primarily driven by: •A$34.9 million increase in adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased$20.0 million , which was primarily due to higher volumes from existing customers and was partially offset by lower commodity prices. Derivative activity associated with our Permian gas assets increased adjusted gross margin by$14.9 million , which included$0.1 million from decreased realized losses and$14.8 million from increased unrealized gains. •A$9.1 million decrease in adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, decreased$4.8 million , which was primarily due to lower commodity prices. Derivative activity associated with our Permian crude assets decreased adjusted gross margin by$4.3 million , which included$1.7 million from increased realized losses and$2.6 million from decreased unrealized gains. •Operating expenses in the Permian segment increased$2.8 million primarily due to$2.7 million of higher compressor rentals,$2.2 million of higher utilities costs,$1.6 million of higher compressor overhaul costs,$0.7 million of higher labor and benefits costs, and$0.6 million of higher materials and supplies expense. These increases in operating expenses were principally due to an increase in operating activity. The increase was offset by$4.2 million of lower construction fees and services and$1.1 million of lower sales and use tax.
•Depreciation and amortization in the Permian segment increased
44
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•Louisiana Segment.
•Revenues and cost of sales, exclusive of operating expenses and depreciation
and amortization, decreased $408.3 million and $414.8 million , respectively,
resulting in an increase in adjusted gross margin in the Louisiana segment of
$6.5 million , resulting from:
•A $4.6 million increase in adjusted gross margin associated with our Louisiana
NGL transmission and fractionation assets. Adjusted gross margin, excluding
derivative activity, increased $0.2 million , which was primarily due to higher
seasonal fees for delivery of normal butane and was partially offset by
fluctuations in market prices. Derivative activity associated with our Louisiana
NGL transmission and fractionation assets increased adjusted gross margin by
$4.4 million , which included $3.7 million from increased realized gains and $0.7
million from decreased unrealized losses.
•A $5.7 million increase in adjusted gross margin associated with our Louisiana
gas assets. Adjusted gross margin, excluding derivative activity, increased $1.8
million , which was primarily due to higher transportation volumes and gains on
storage activity partially offset by lower processing volumes. Derivative
activity associated with our Louisiana gas assets increased adjusted gross
margin by $3.9 million , which included $8.0 million from increased realized
gains and $4.1 million from increased unrealized losses.
•A $3.8 million decrease in adjusted gross margin associated with our ORV crude
assets. Adjusted gross margin, excluding derivative activity, decreased $5.9
million , which was primarily due to lower compression fee revenue resulting from
the sale of several compressor units and fluctuation in market prices.
Derivative activity associated with our ORV crude assets increased adjusted
gross margin by $2.1 million from increased realized gains.
•Operating expenses in the
•Depreciation and amortization in the
•Oklahoma Segment.
•Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased$70.2 million and$82.8 million , respectively, resulting in an increase in adjusted gross margin in theOklahoma segment of$12.6 million , resulting from: •A$12.7 million increase in adjusted gross margin associated with ourOklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased$1.4 million , which was primarily due to the Central Oklahoma Acquisition inDecember 2022 and was partially offset by lower commodity prices. Derivative activity associated with ourOklahoma gas assets increased adjusted gross margin by$11.3 million , which included$5.6 million from increased realized gains and$5.7 million from decreased unrealized losses. •A$0.1 million decrease in adjusted gross margin associated with ourOklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased$0.2 million , which was primarily due to fluctuation in market prices. Derivative activity associated with ourOklahoma crude assets increased adjusted gross margin by$0.1 million from increased realized gains. •Operating expenses in theOklahoma segment increased$3.7 million primarily due to$2.0 million of higher compressor rentals,$1.5 million of higher ad valorem taxes,$1.1 million of higher utility costs, and$0.6 million of higher materials and supplies expense due to an increase in operating activity. The increase was offset by$2.0 million of lower construction fees and services. •Depreciation and amortization in theOklahoma segment increased$1.0 million primarily due to increases of$2.0 million related to changes in estimated useful lives and$1.0 million related to the Central Oklahoma Acquisition, partially offset by a$1.9 million decrease related to the transfer of equipment to the Phantom processing facility. 45 -------------------------------------------------------------------------------- Table of Contents •North Texas Segment. •Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, decreased$50.3 million and$67.8 million , respectively, resulting in an increase in adjusted gross margin in theNorth Texas segment of$17.5 million . Adjusted gross margin, excluding derivative activity, increased$6.8 million , which was primarily due to the Barnett Shale Acquisition onJuly 1, 2022 and was partially offset by lower commodity prices. Derivative activity associated with ourNorth Texas segment increased adjusted gross margin by$10.7 million , which included$11.5 million from increased realized gains and$0.8 million from decreased unrealized gains. •Operating expenses in theNorth Texas segment increased$4.4 million primarily due to$2.0 million of higher materials and supplies expense,$1.5 million of higher construction fees and services,$0.7 million of higher ad valorem taxes,$0.6 million of higher labor and benefits costs, and$0.4 million of higher utility costs due to an increase in operating activity and theBarnett Shale Acquisition onJuly 1, 2022 . The increase was offset by$1.0 million of lower sales and use tax. •Depreciation and amortization in theNorth Texas segment increased$0.4 million primarily due to$2.7 million related to the Barnett Shale Acquisition onJuly 1, 2022 and$1.0 million related to changes in useful lives, partially offset by a$3.5 million decrease due to asset reaching the end of their depreciable lives.
•Corporate Segment.
•Revenues and cost of sales, exclusive of operating expenses and depreciation and amortization, each increased$352.4 million . The corporate segment includes offsetting eliminations related to intercompany revenues and cost of sales, exclusive of operating expenses and depreciation and amortization.
•Depreciation and amortization in the Corporate segment was
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, 2022 filed with the Commission onFebruary 15, 2023 .
Liquidity and Capital Resources
Cash Flows from Operating Activities. Net cash provided by operating activities was$272.1 million for the three months endedMarch 31, 2023 compared to$307.7 million for the three months endedMarch 31, 2022 . Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions): Three Months EndedMarch 31, 2023 2022
Operating cash flows before working capital
(1.6) 49.9
Operating cash flows before changes in working capital increased $15.9 million
for the three months ended March 31, 2023 compared to the three months ended
March 31, 2022 . The primary contributor to the increase in operating cash flows
before working capital was as follows:
•Gross margin, excluding depreciation and amortization, non-cash commodity
derivative activity, utility credits redeemed or earned, and unit-based
compensation, increased $30.1 million . The increase in gross margin is due to a
$46.5 million increase in adjusted gross margin, excluding non-cash commodity
derivative activity, which was partially offset by a $16.4 million increase in
operating expenses, excluding utility credits redeemed or earned and unit-based
compensation. For more information regarding the changes in gross margin for the
three months ended March 31, 2023 compared to the three months ended March 31,
2022 , see "Results of Operations."
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Table of Contents The increase in operating cash flows were partially offset by the following:
•Interest expense, net of interest income, excluding amortization of debt issue
costs and net discounts, increased
•General and administrative expenses, excluding unit-based compensation,
increased
The changes in working capital for the three months endedMarch 31, 2023 compared to the three months endedMarch 31, 2022 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,
2023 2022
Additions to property and equipment (1) $ (100.7) Contributions to unconsolidated affiliate investments (2) (49.7)
-
____________________________
(1)The increase in capital expenditures was due to expansion projects to accommodate increased volumes on our systems. (2)Represents contributions to the Matterhorn JV and GCF. See "Item 1. Financial Statements-Note 10" for more information regarding the contributions to unconsolidated affiliate investments.
Cash Flows from Financing Activities. Net cash used in financing activities was
Three Months Ended
March 31,
2023 2022
Net repayments on the AR Facility (1) $ (144.4) $ (35.0)
Net borrowings (repayments) on the Revolving Credit Facility (1) 250.0 (15.0)
Distributions to members (61.7) (56.4)
Distributions to Series B Preferred Unitholders (2) (17.3) (18.6)
Distributions to Series C Preferred Unitholders (2) (8.4) -
Distributions to joint venture partners (3) (16.7) (16.0)
Payment to redeem mandatorily redeemable non-controlling interest (4)
(10.5) - Redemption of Series B Preferred Units (2) - (50.5) Repurchase of Series C Preferred Units (2) (3.9) - Contributions from non-controlling interests (5) 8.4 7.3 Common unit repurchases (6) (51.4) (17.0) Conversion of unit-based awards for common units, net of units withheld for taxes (16.8) (4.2) ____________________________ (1)See "Item 1. Financial Statements-Note 6" for more information regarding the AR Facility and the Revolving Credit Facility. (2)See "Item 1. Financial Statements-Note 8" for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and information on the partial redemption of the Series B Preferred Units and the repurchase of the Series C Preferred Units. (3)Represents distributions to NGP for its ownership in theDelaware Basin JV and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV. (4)InJanuary 2023 , we settled the redemption of the mandatorily redeemable non-controlling interest in one of our non-wholly owned subsidiaries. See "Item 1. Financial Statements-Note 2" for more information regarding the redemption. (5)Represents contributions from NGP to theDelaware Basin JV. (6)See "Item 1. Financial Statements-Note 9" for more information regarding our common unit repurchase program. 47 -------------------------------------------------------------------------------- Table of Contents Capital Requirements
As of
Capital expenditures, net to ENLC (1)
15
Contributions to unconsolidated affiliate investments (3) 25
Total $ 353
____________________________
(1)Excludes capital expenditures that are 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 the equipment and facilities associated with the
non-operational Cowtown processing plant in North Texas to our Delaware JV
operations in the Permian, where it is expected to operate as the Tiger II
processing plant. These costs exclude amounts that will be contributed by other
entities and relate to the non-controlling interest share of our consolidated
entities.
(3)Includes contributions made to our GCF investment and the Matterhorn JV.
Our primary remaining capital projects for 2023 include the relocation of the
Cowtown processing plant, CCS-related initiatives, the restart of the GCF
assets, contributions to unconsolidated affiliate investments, continued
development of our existing systems through well connects, and other low-cost
development projects. We expect to fund our remaining 2023 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, to make contributions to unconsolidated affiliate
investments, and to make acquisitions will depend upon our future operating
performance, which will be affected by prevailing economic conditions in the
industry, financial, business, and other factors, some of which are beyond our
control.
Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of
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Total Contractual Cash Obligations. A summary of our total contractual cash
obligations as of
Payments Due by Period
Total Remainder 2023 2024 2025 2026 2027 Thereafter
ENLC's & ENLK's senior unsecured
notes $ 4,009.2 $ -
505.0 - - - - 505.0 -
AR Facility (2) 355.6 - - 355.6 - - -
Acquisition contingent consideration
(3) 6.2 - 0.9 0.4 4.6 0.3 -
Interest payable on fixed long-term debt obligations 2,390.0 166.9 213.5 202.6 193.8 170.0
1,443.2
Operating lease obligations 122.4 24.1 22.3 16.1 9.2 8.2 42.5 Purchase obligations 8.7 8.7 - - - - - Pipeline and trucking capacity and deficiency agreements (4) 970.0 54.7 81.9 113.1 100.0 87.9
532.4
Total contractual obligations
____________________________
(1)The Revolving Credit Facility permits us to borrow up to$1.40 billion on a revolving credit basis and will mature onJune 3, 2027 . (2)The AR Facility will terminate onAugust 1, 2025 . (3)The estimated fair value of the contingent consideration for theAmarillo Rattler Acquisition and the Central Oklahoma Acquisition 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 13" for additional information. (4)Consists of pipeline capacity payments for firm transportation and deficiency agreements. 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 Revolving Credit Facility and the AR Facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Revolving Credit Facility and the AR Facility, which vary from time to time.
Our contractual cash obligations for the remainder of 2023 are expected to be funded from cash flows generated from our operations.
49
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Indebtedness
Revolving Credit Facility. As of March 31, 2023 , there were $505.0 million in
outstanding borrowings and $43.6 million in outstanding letters of credit under
the Revolving Credit Facility.
AR Facility. As of March 31, 2023 , the AR Facility had a borrowing base of
$355.6 million and there were $355.6 million in outstanding borrowings under the
AR Facility. In connection with the AR Facility, certain subsidiaries of ENLC
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.
Senior Unsecured Notes. As of March 31, 2023 , we had $4.0 billion in aggregate
principal amount of outstanding unsecured senior notes maturing from 2024 to
2047 and there were no meaningful near-term senior unsecured note maturities. On
April 3, 2023 , we completed the sale of an additional $300.0 million aggregate
principal amount of 6.500% senior notes due 2030 (the "Additional Notes") at 99%
of their face value. The Additional Notes were offered as an additional issue of
our existing 6.500% senior notes due 2030 that we issued on August 31, 2022 in
an aggregate principal amount of $700.0 million .
Guarantees. The amounts outstanding on our senior unsecured notes and the
Revolving Credit Facility are guaranteed in full by our subsidiary ENLK,
including 105% of any letters of credit outstanding under the Revolving 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 Revolving 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 of March 31, 2023 , 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 6" for more information on our outstanding debt.
Inflation
Inflation inthe United States increased significantly in 2022 and has continued during the first quarter of 2023. See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations-Recent Developments Affecting Industry Conditions and Our Business-Inflation" for more information.
Recent Accounting Pronouncements
We have reviewed recently issued accounting pronouncements that became effective during the three months endedMarch 31, 2023 and have determined that none had a material impact to our consolidated financial statements. 50 -------------------------------------------------------------------------------- Table of Contents Disclosure Regarding Forward-Looking Statements This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report on Form 10-Q 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 future results and growth of our CCS business, when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, cost savings or operational, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of 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) 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, (b) 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, (c) 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, (d) the dependence on key customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (e) developments that materially and adversely affect our key customers or other customers, (f) adverse developments in the midstream business that may reduce our ability to make distributions, (g) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (h) decreases in the volumes that we gather, process, fractionate, or transport, (i) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (j) our ability to receive or renew required permits and other approvals, (k) 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, (l) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (m) changes in the availability and cost of capital, (n) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (o) 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, (p) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (q) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (r) impairments to goodwill, long-lived assets and equity method investments, (s) construction risks in our major development projects, (t) challenges we may face in or in connection with our strategy to enter into new lines of business related to the energy transition, (u) the impact of the coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) and similar pandemics, (v) our ability to effectively integrate and manage assets we acquire through acquisitions, and (w) 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 "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year endedDecember 31, 2022 , filed with the Commission onFebruary 15, 2023 , 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. 51
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