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.
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 12,000 miles of pipelines, 21 natural gas processing plants with approximately 5.3 Bcf/d of processing capacity, seven fractionators with approximately 290,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography. We have five reportable segments:
•Permian Segment. The Permian segment includes our natural gas gathering,
processing, and transmission activities and our crude oil operations in the
Midland and Delaware Basins in
•North Texas Segment. The
•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; •Louisiana Segment. TheLouisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located inLouisiana and our crude oil operations in ORV; and •Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV inOklahoma , our ownership interest in GCF inSouth Texas , our derivative activity, and our general corporate assets and expenses. We manage our operations by focusing on gross operating margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, truck, or rail terminal. We define gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-GAAP financial measure and is explained in greater detail under "Non-GAAP Financial Measures" below. Approximately 94% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the six months endedJune 30, 2020 . We reflect revenue as "Product sales" and "Midstream services" on the consolidated statements of operations. 32
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The following customers individually represented greater than 10% of our consolidated revenues. These customers represent a significant percentage of revenues, and the loss of the customer would have a material adverse impact on our results of operations because the revenues and gross operating margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues. Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Devon 17.7 % (1) 15.0 % (1) Dow Hydrocarbons and Resources LLC 13.5 % 10.1 % 12.3 % 10.4 % Marathon Petroleum Corporation 10.3 % 15.2 % 14.8 % 14.7 %
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(1)Consolidated revenues for
Our revenues and gross operating margins are generated from eight primary sources:
•gathering and transporting natural gas, NGLs, and crude oil on the pipeline systems we own; •processing natural gas at our processing plants; •fractionating and marketing recovered NGLs; •providing compression services; •providing crude oil and condensate transportation and terminal services; •providing condensate stabilization services; •providing brine disposal services; and •providing natural gas, crude oil, and NGL storage. We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. We typically buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher gross operating margins from product upgrades during periods with higher NGL prices. We gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from producers at a market index less a stated transportation deduction. We then transport and resell the crude oil and condensate through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the net margin we will receive for each crude oil and condensate transaction. We realize gross operating margins from our gathering and processing services primarily through different contractual arrangements: processing margin ("margin") contracts, POL contracts, POP contracts, fixed-fee component contracts, or a combination of these contractual arrangements. "See Item 3. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk" for a detailed description of these contractual arrangements. Under any of these gathering and 33 -------------------------------------------------------------------------------- Table of Contents processing arrangements, we may earn a fee for the services performed, or we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize a net margin as our fee. Under margin contract arrangements, our gross operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our gross operating margins are driven by throughput volume. Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate moved through or by our assets.
Recent Developments Affecting Industry Conditions and Our Business
OnMarch 11, 2020 , theWorld Health Organization declared the ongoing coronavirus (COVID-19) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has now reached every region of the globe and has resulted in widespread adverse impacts on the global economy, on the energy industry as a whole and on midstream companies, and on our customers, suppliers, and other parties with whom we have business relations. The pandemic and related travel and operational restrictions, as well as business closures and curtailed consumer activity, have resulted in a reduction in global demand for condensate, natural gas, and NGLs and especially crude oil. While reductions in global demand for natural gas and NGLs were never as severe as for crude oil and the demand for crude oil has recovered from the steepest drops in April and May, global demand for energy is still reduced as of the date of this report from levels before the pandemic in mid-February. The decline in demand, coupled with the failure of OPEC+ to quickly agree on oil production cuts, resulted in a decline in the market price for these commodities, most severely for crude oil. Although OPEC+ agreed to production cuts in April, extended these cuts through July, and are expected to continue the production cuts beyond July, although at a more moderate level, and althoughUnited States oil producers have also curtailed their drilling programs, these cuts have not been enough to fully offset demand loss attributable to the COVID-19 pandemic and market prices remain lower than prior to the pandemic. As a result of the supply/demand imbalance, reduced commodity prices, and an uncertain timeline for recovery, oil and natural gas producers, including many of our customers, have curtailed their current drilling and production activity, including in some cases by shutting-in production, as well as reducing their plans for future drilling and production activity. As a result of these decreases in producer activity, we have experienced reduced volumes gathered, processed, fractionated, and transported on our assets in some of the regions that supply our systems. Since the outbreak began, our first priority has been the health and safety of our employees and those of our customers and other business counterparties. We have implemented preventative measures and developed a response plan to minimize unnecessary risk of exposure and prevent infection, while supporting our customers' operations. We have a crisis management team for health, safety and environmental matters and personnel issues, and we have established a cross-functional COVID-19 response team to address various impacts of the situation, as they have been developing. We also have modified certain business practices (including discontinuing all non-essential business travel, implementing a temporary work-from-home policy for employeeswho can execute their work remotely, and encouraging employees to adhere to local and regional social distancing recommendations) to support efforts to reduce the spread of COVID-19 and to conform to government restrictions and best practices encouraged by theCenters for Disease Control and Prevention , theWorld Health Organization , and other governmental and regulatory authorities. We also have promoted heightened awareness and vigilance, hygiene, and implementation of more stringent cleaning protocols across our facilities and operations. We continue to evaluate and adjust these preventative measures, response plans and business practices with the evolving impacts of COVID-19. There is considerable uncertainty regarding how long COVID-19 will persist and affect economic conditions and the extent and duration of changes in consumer behavior, such as the reluctance to travel, as well as governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders, and business and government shutdowns. As a result, there is significant uncertainty regarding how long the market dislocations will continue and how significantly and how long they will continue to affect us. We expect to see continued volatility in crude oil, condensate, natural gas, and NGL prices for the foreseeable future, which may, over the long term, adversely impact our business. A sustained significant decline in oil and natural gas exploration and production activities and related reduced demand for our services by our customers, whether due to decreases in consumer demand or reduction in the prices for oil, condensate natural gas and NGLs or otherwise, would have a material adverse effect on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to our unitholders). 34 -------------------------------------------------------------------------------- Table of Contents As of the date of this report, our efforts to respond to the challenges presented by the conditions described above and minimize the impacts to our business have yielded results. Our systems, pipelines, and facilities have remained operational. We have also moved quickly and decisively, and we continue to adapt and respond promptly, to implement strategies to reduce costs, increase operational efficiencies, and lower our capital spending. As we previously announced, we intend to reduce our capital expenditures in 2020, including both growth and maintenance capital expenditures, to between$190 million and$250 million , a 65% reduction from 2019 total capital spending. We have also reduced costs across our platform and we intend to reduce our general and administrative and operational expenses by$120 million for the full-year 2020 versus the twelve months endedDecember 31, 2019 . Also, as ofJune 30, 2020 , we had approximately$52 million of cash on our balance sheet and have drawn only approximately$400 million on the$1.75 billion Consolidated Credit Facility. We have not requested any funding under any federal or other governmental programs to support our operations, and we do not expect to utilize any such funding. We are continuing to address concerns to protect the health and safety of our employees and those of our customers and other business counterparties, and this includes changes to comply with health-related guidelines as they are modified and supplemented. We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, liquidity, financial condition, results of operations, and cash flows (including our ability to make distributions to unitholders) at this time due to numerous uncertainties. The ultimate impacts will depend on future developments, including, among others, the ultimate duration and persistence of the outbreak, the effect of the outbreak on economic, social and other aspects of everyday life, the consequences of governmental and other measures designed to prevent the spread of the virus, the development and timing of effective treatments and vaccines, actions taken by members of OPEC+ and other foreign, oil-exporting countries, actions taken by governmental authorities, customers, suppliers, and other third parties, workforce availability, and the timing and extent to which normal economic, social and operating conditions resume. For additional discussion regarding risks associated with the COVID-19 pandemic, see Part II, Item 1A "Risk Factors" in our Quarterly Report on Form 10-Q for the quarter endedMarch 31, 2020 . Other Recent Developments
Riptide Processing Plant. In
Delaware Basin Processing Plant. InAugust 2019 , we commenced construction of ourTiger Plant , which will expand ourDelaware Basin processing capacity by an additional 200 MMcf/d. We expect the plant to be operational in the third quarter of 2020. This processing plant is owned by theDelaware Basin JV.
Non-GAAP Financial Measures
To assist management in assessing our business, we use the following non-GAAP financial measures: Adjusted earnings before interest, taxes, and depreciation and amortization ("adjusted EBITDA"), distributable cash flow available to common unitholders ("distributable cash flow"), excess free cash flow, and gross operating margin. Adjusted EBITDA We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; loss on secured term loan receivable, (income) loss from unconsolidated affiliates; distributions from unconsolidated affiliates; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; (payments under onerous performance obligation); transaction costs; accretion expense associated with asset retirement obligations; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is a primary metric used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess: •the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; •the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders; •our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and •the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. 35 -------------------------------------------------------------------------------- Table of Contents The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted EBITDA in the same manner. Adjusted EBITDA does not include interest expense, net of interest income; income tax expense (benefit); and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance. The following table reconciles adjusted EBITDA to net income (loss) (in millions): Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Net income (loss)$ 29.8 $ 9.1 $ (230.6) $ (125.7) Interest expense, net of interest income 55.2 54.3 110.8 103.9 Depreciation and amortization 158.2 153.7 321.0 305.8 Impairments 1.5 - 354.5 186.5 Loss on secured term loan receivable (1) - 52.9 - 52.9 (Income) loss from unconsolidated affiliates 0.7 (4.7) (1.0) (10.0) Distributions from unconsolidated affiliates 0.2 7.6 2.0 10.1 Loss on disposition of assets 5.2 0.1 4.6 0.1 Gain on extinguishment of debt (26.7) - (32.0) - Unit-based compensation 7.4 8.0 16.2 19.1 Income tax expense (benefit) 11.7 (5.4) (22.0) (3.6) Unrealized (gain) loss on commodity swaps 18.8 (7.2) 5.8 (5.2)
Payments under onerous performance obligation offset to other current and long-term liabilities
- (4.5) - (9.0) Transaction costs (2) - 0.4 - 13.9 Other (3) (0.4) 0.1 (0.5) 0.4 Adjusted EBITDA before non-controlling interest 261.6 264.4 528.8 539.2 Non-controlling interest share of adjusted EBITDA from joint ventures (4) (6.5) (5.2) (13.7) (11.8) Adjusted EBITDA, net to ENLC$ 255.1 $ 259.2 $ 515.1 $ 527.4 ____________________________ (1)InMay 2018 , we restructured our natural gas gathering and processing contract withWhite Star , and, as a result, recognized the discounted present value of a secured term loan receivable granted to us byWhite Star . We recorded a$52.9 million loss in our consolidated statement of operations for the three and six months endedJune 30, 2019 related to the write-off of the secured term loan receivable. (2)Represents transaction costs attributable to costs incurred related to the Merger inJanuary 2019 . (3)Includes accretion expense associated with asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term. (4)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.
Distributable Cash Flow and Excess Free Cash Flow
We define distributable cash flow as adjusted EBITDA, net to ENLC, less interest expense, net of interest income; maintenance capital expenditures, excluding maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities; accrued cash distributions on Series B Preferred Units and Series C Preferred Units paid or expected to be paid; non-cash interest income; and current income taxes. Excess free cash flow 36 -------------------------------------------------------------------------------- Table of Contents is defined as distributable cash flow less distributions declared on common units and growth capital expenditures, excluding growth capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated joint ventures. Distributable cash flow and excess free cash flow are used as supplemental liquidity measures by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions, and make capital expenditures. Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income. The GAAP measure most directly comparable to distributable cash flow and excess free cash flow is net cash provided by operating activities. Distributable cash flow and excess free cash flow should not be considered alternatives to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Distributable cash flow and excess free cash flow have important limitations because they exclude some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Distributable cash flow and excess free cash flow may not be comparable to similarly titled measures of other companies because other companies may not calculate these non-GAAP metrics in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as distributable cash flow and excess free cash flow, to evaluate our overall liquidity. 37 -------------------------------------------------------------------------------- Table of Contents The following table reconciles excess free cash flow, distributable cash flow, and adjusted EBITDA to net cash provided by operating activities (in millions): Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Net cash provided by operating activities$ 134.8 $ 257.5 $ 316.8 $ 521.5 Interest expense (1) 54.0 53.9 108.7 103.4 Current income tax expense 0.4 0.3 0.7 1.3 Transaction costs (2) - 0.4 - 13.9 Other (3) (5.1) 1.6 0.5 0.1 Changes in operating assets and liabilities which (provided) used cash: Accounts receivable, accrued revenues, inventories, and other 50.2 (165.9) (119.1) (263.3) Accounts payable, accrued product purchases, and other accrued liabilities (4) 27.3 116.6 221.2 162.3 Adjusted EBITDA before non-controlling interest 261.6 264.4 528.8 539.2 Non-controlling interest share of adjusted EBITDA from joint ventures (5) (6.5) (5.2) (13.7) (11.8) Adjusted EBITDA, net to ENLC 255.1 259.2 515.1 527.4 Interest expense, net of interest income (55.2) (54.3) (110.8) (103.9) Maintenance capital expenditures, net to ENLC (6) (7.7) (13.2) (15.9) (21.7) ENLK preferred unit accrued cash distributions (7) (22.8) (23.1) (45.6) (45.8) Other (8) (0.3) (1.0) (0.6) (3.5) Distributable cash flow 169.1 167.6 342.2 352.5 Common distributions declared (46.4) (139.3) (92.9) (276.6) Growth capital expenditures, net to ENLC (6) (50.7) (141.9) (133.3) (361.5) Excess free cash flow$ 72.0 $ (113.6) $ 116.0 $ (285.6)
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(1)Net of amortization of debt issuance costs and discount and premium, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA. (2)Represents transaction costs attributable to costs incurred related to the Merger inJanuary 2019 . (3)Includes accruals for settled commodity swap transactions, distributions received from equity method investments to the extent those distributions exceed earnings from the investment, and non-cash rent, which relates to lease incentives pro-rated over the lease term. (4)Net of payments under onerous performance obligation offset to other current and long-term liabilities during the three and six months endedJune 30, 2019 . (5)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP's 49.9% share of adjusted EBITDA from theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests. (6)Excludes capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities. (7)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See "Item 1. Financial Statements- Note 7" for information on the cash distributions earned by holders of the Series B Preferred Units and Series C Preferred Units. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders. (8)Includes non-cash interest income and current income tax expense. 38 -------------------------------------------------------------------------------- Table of Contents Gross Operating Margin We define gross operating margin as revenues less cost of sales. We present gross operating margin by segment in "Results of Operations." We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because, in general, our business is to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to gross operating margin is operating income (loss). Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) as determined in accordance with GAAP. Gross operating margin has important limitations because it excludes all operating costs that affect operating income (loss) except cost of sales. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.
The following table provides a reconciliation of operating income (loss) to gross operating margin (in millions):
Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Operating income (loss)$ 70.7 $ 53.1 $ (174.8) $ (35.6) Add: Operating expenses 88.1 117.9 188.8 232.4 General and administrative expenses 23.5 32.2 53.9 83.6 Loss on disposition of assets 5.2 0.1 4.6 0.1 Depreciation and amortization 158.2 153.7 321.0 305.8 Impairments 1.5 - 354.5 186.5 Loss on secured term loan receivable - 52.9 - 52.9 Gross operating margin$ 347.2 $ 409.9 $ 748.0 $ 825.7 39
-------------------------------------------------------------------------------- Table of Contents Results of Operations The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin, which we define as revenue less cost of sales as reflected in the table below (in millions, except volumes): Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Permian Segment Revenues$ 204.6 $ 742.3 $ 576.3 $ 1,484.9 Cost of sales (138.4) (680.5) (452.3) (1,356.7) Total gross operating margin$ 66.2 $ 61.8 $ 124.0 $ 128.2 North Texas Segment Revenues$ 106.4 $ 149.8 $ 227.1 $ 324.1 Cost of sales (18.9) (51.0) (45.9) (124.7) Total gross operating margin$ 87.5 $ 98.8 $ 181.2 $ 199.4 Oklahoma Segment Revenues$ 179.8 $ 299.2 $ 399.8 $ 618.9 Cost of sales (61.1) (159.4) (154.8) (343.6) Total gross operating margin$ 118.7 $ 139.8 $ 245.0 $ 275.3 Louisiana Segment Revenues$ 409.7 $ 730.5 $ 973.2 $ 1,528.6 Cost of sales (312.5) (627.9) (772.2) (1,314.5) Total gross operating margin$ 97.2 $ 102.6 $ 201.0 $ 214.1 Corporate Segment Revenues$ (155.6) $ (211.8) $ (275.4) $ (467.3) Cost of sales 133.2 218.7 272.2 476.0 Total gross operating margin$ (22.4) $ 6.9 $ (3.2) $ 8.7 Total Revenues$ 744.9 $ 1,710.0 $ 1,901.0 $ 3,489.2 Cost of sales (397.7) (1,300.1) (1,153.0) (2,663.5) Total gross operating margin$ 347.2 $
409.9
Midstream Volumes: Permian Segment Gathering and Transportation (MMBtu/d) 871,500 676,000 851,300 666,800 Processing (MMBtu/d) 896,100 724,100 878,900 718,100 Crude Oil Handling (Bbls/d) 112,300 145,100 122,900 146,200 North Texas Segment Gathering and Transportation (MMBtu/d) 1,485,900 1,646,900 1,531,800 1,664,900 Processing (MMBtu/d) 670,600 770,100 685,200 750,100 Oklahoma Segment Gathering and Transportation (MMBtu/d) 1,092,600 1,314,900 1,156,800 1,279,800 Processing (MMBtu/d) 1,082,100 1,298,800 1,118,300 1,265,400 Crude Oil Handling (Bbls/d) 30,000 53,800 33,300 41,600 Louisiana Segment Gathering and Transportation (MMBtu/d) 1,873,600 1,925,900 1,958,400 1,997,800 Processing (MMBtu/d) 197,200 337,100 183,400 402,200 Crude Oil Handling (Bbls/d) 15,700 20,000 16,600 17,500 NGL Fractionation (Gals/d) 7,344,800 7,477,400 7,764,500 7,227,000 Brine Disposal (Bbls/d) 1,400 3,400 1,600 3,400
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Three Months Ended
Gross Operating Margin. Gross operating margin was$347.2 million for the three months endedJune 30, 2020 compared to$409.9 million for the three months endedJune 30, 2019 , a decrease of$62.7 million , or 15.3%, due to the following: •Permian Segment. Gross operating margin in the Permian segment increased$4.4 million , resulting from (i) a$2.5 million increase in gross operating margin from our Permian crude assets primarily attributable to volume growth in ourDelaware Basin assets, which was partially offset by the expiration of an MVC related to ourSouth Texas assets inJuly 2019 , and (ii) a$1.9 million increase in gross operating margin from our Permian gas assets primarily attributable to volume growth.
•North Texas Segment. Gross operating margin in the
•Oklahoma Segment. Gross operating margin in the
•Louisiana Segment. Gross operating margin in the
•A$4.7 million decrease from ourLouisiana gas assets due to lower processing margins and volumes attributable to a less favorable processing environment, the expiration of certain firm transportation contracts, and decreased volumes. •A$4.3 million decrease from our ORV crude assets primarily due to lower volumes. •A$3.6 million increase from our NGL transmission and fractionation assets, which was primarily due to a settlement payment received as the result of a contract dispute.
•Corporate Segment. Gross operating margin in the Corporate segment decreased
Three Months Ended June 30, 2020 2019 Realized swaps: Crude swaps$ (2.4) $ (2.5) NGL swaps (0.4) 3.7 Gas swaps (0.8) (1.5) Realized loss on derivatives (3.6) (0.3) Unrealized swaps: Crude swaps (3.6) 4.9 NGL swaps (14.4) 1.3 Gas swaps (0.8) 1.0 Change in fair value of derivatives (18.8) 7.2 Gain (loss) on derivatives$ (22.4) $ 6.9 Certain gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers agree to ship and/or process a minimum volume of commodity on our systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually determined fee based upon the shortfall between actual commodity volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. 41 -------------------------------------------------------------------------------- Table of Contents Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions): Three Months Ended June 30, 2020 2019 Permian Segment $ (1.7)$ 3.9 Oklahoma Segment 15.1 - Total $ 13.4$ 3.9
Our MVC revenue in the
Operating Expenses. Operating expenses were$88.1 million for the three months endedJune 30, 2020 compared to$117.9 million for the three months endedJune 30, 2019 , a decrease of$29.8 million , or 25.3%. The primary contributors to the total decrease by segment were as follows (in millions): Three Months Ended June 30, Change 2020 2019 $ %
Permian Segment
25.8 (7.3) (28.3) % Oklahoma Segment 19.4 26.1 (6.7) (25.7) % Louisiana Segment 27.5 37.6 (10.1) (26.9) % Total$ 88.1 $ 117.9 $ (29.8) (25.3) % •Permian Segment. Operating expenses in the Permian segment decreased$5.7 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in construction fees and services, and sales and use tax. •North Texas Segment. Operating expenses in theNorth Texas segment decreased$7.3 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in operations and maintenance, ad valorem tax, sales and use tax, and compressor rentals. •Oklahoma Segment. Operating expenses in theOklahoma segment decreased$6.7 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in materials and supplies expense, operations and maintenance, construction fees and services, and compressor and treater rentals. •Louisiana Segment. Operating expenses in theLouisiana segment decreased$10.1 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in materials and supplies expense, utilities, construction fees and services, ad valorem tax, and vehicle expenses. General and Administrative Expenses. General and administrative expenses were$23.5 million for the three months endedJune 30, 2020 compared to$32.2 million for the three months endedJune 30, 2019 , a decrease of$8.7 million , or 27.0%. The primary contributors to the decrease were as follows:
•Labor costs and unit-based compensation costs decreased
•Expenses related to fees and services, travel, rents and leases, and insurance
decreased
Depreciation and Amortization. Depreciation and amortization was$158.2 million for the three months endedJune 30, 2020 compared to$153.7 million for the three months endedJune 30, 2019 , an increase of$4.5 million , or 2.9%. This increase was primarily due to new assets placed in service in the Permian,Oklahoma , andLouisiana segments, as well as accelerated depreciation on certain non-core assets. These increases were partially offset by the impairment ofLouisiana segment assets in the first quarter of 2020 and the conclusion of a finance lease in theNorth Texas segment in 2019. 42 -------------------------------------------------------------------------------- Table of Contents Impairments. For the three months endedJune 30, 2020 , we recognized a$1.5 million impairment on property and equipment related to cancelled projects. See "Item 1. Financial Statements-Note 2" for additional information on our property and equipment impairments. Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of$26.7 million for the three months endedJune 30, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. See "Item 1. Financial Statements-Note 5" for additional information. Interest Expense. Interest expense was$55.2 million for the three months endedJune 30, 2020 compared to$54.3 million for the three months endedJune 30, 2019 , an increase of$0.9 million , or 1.7%. Interest expense consisted of the following (in millions): Three Months Ended June 30, 2020 2019 ENLK and ENLC Senior Notes$ 43.3 $ 43.4 Term Loan 4.2 8.5 Consolidated Credit Facility 4.1 3.7 Capitalized interest (1.3) (1.8) Amortization of debt issue costs and net discounts (premiums) 1.2 1.0 Interest rate swap 3.7 (0.3) Other - (0.2) Total$ 55.2 $ 54.3 Income (Loss) from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was$0.7 million for the three months endedJune 30, 2020 compared to income of$4.7 million for the three months endedJune 30, 2019 , a decrease of$5.4 million . The decrease was primarily attributable to a reduction of income of$4.9 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of$0.5 million from our Cedar Cove JV. Income Tax Expense. Income tax expense was$11.7 million for the three months endedJune 30, 2020 compared to an income tax benefit of$5.4 million for the three months endedJune 30, 2019 . The increase in income tax expense was primarily attributable to higher income between periods and tax deficiencies recorded upon the vesting of restricted incentive units. See "Item 1. Financial Statements-Note 6" for additional information.
Six Months Ended
Gross Operating Margin. Gross operating margin was$748.0 million for the six months endedJune 30, 2020 compared to$825.7 million for the six months endedJune 30, 2019 , a decrease of$77.7 million , or 9.4%, due to the following:
•Permian Segment. Gross operating margin in the Permian segment decreased
•An$11.6 million decrease due to the expiration of an MVC related to ourSouth Texas assets inJuly 2019 . •A$3.7 million increase due to volume growth in ourMidland Basin crude assets. •A$2.9 million increase due to volume growth in ourDelaware Basin crude assets. •A$1.9 million decrease related to ourMidland Basin gas assets. •A$2.7 million increase related to ourDelaware Basin gas assets.
•North Texas Segment. Gross operating margin in the
•Oklahoma Segment. Gross operating margin in theOklahoma segment decreased$30.3 million . Gross operating margin contributed by ourOklahoma gas assets decreased$31.2 million , which was partially due to lower volumes from our existing customers, and was partially offset by a$0.9 million increase in gross operating margin contributed by ourOklahoma crude assets. 43 -------------------------------------------------------------------------------- Table of Contents •Louisiana Segment. Gross operating margin in theLouisiana segment decreased$13.1 million , resulting from: •A$12.4 million decrease from ourLouisiana gas assets due to lower processing margins and volumes attributable to a less favorable processing environment, the expiration of certain firm transportation contracts, and decreased volumes. •A$6.1 million decrease from our ORV crude assets primarily due to lower volumes. •A$5.4 million increase from our NGL transmission and fractionation assets, which was primarily due to higher volumes that resulted from the completion of the Cajun-Sibon pipeline expansion inApril 2019 and a settlement payment received as the result of a contract dispute.
•Corporate Segment. Gross operating margin in the Corporate segment decreased
Six Months Ended June 30, 2020 2019 Realized swaps: Crude swaps$ (3.0) $ 0.8 NGL swaps 6.3 5.6 Gas swaps (0.7) (2.9) Realized gain on derivatives 2.6 3.5 Unrealized swaps: Crude swaps 2.5 4.5 NGL swaps (7.0) (2.3) Gas swaps (1.3) 3.0 Change in fair value of derivatives (5.8) 5.2 Gain (loss) on derivatives$ (3.2) $ 8.7 Certain gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers agree to ship and/or process a minimum volume of commodity on our systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually determined fee based upon the shortfall between actual commodity volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods. Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions): Six Months Ended June 30, 2020 2019 Permian$ 0.3 $ 7.7 Oklahoma 24.9 - Total$ 25.2 $ 7.7
Our MVC revenue in the
44 -------------------------------------------------------------------------------- Table of Contents Operating Expenses. Operating expenses were$188.8 million for the six months endedJune 30, 2020 compared to$232.4 million for the six months endedJune 30, 2019 , a decrease of$43.6 million , or 18.8%. The primary contributors to the decrease by segment were as follows (in millions): Six Months Ended June 30, Change 2020 2019 $ % Permian Segment$ 48.2 $ 56.2 $ (8.0) (14.2) % North Texas Segment 39.0 51.5 (12.5) (24.3) % Oklahoma Segment 42.3 51.5 (9.2) (17.9) % Louisiana Segment 59.3 73.2 (13.9) (19.0) % Total$ 188.8 $ 232.4 $ (43.6) (18.8) % •Permian Segment. Operating expenses in the Permian segment decreased$8.0 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in materials and supplies expense, construction fees and services, sales and use tax, and vehicle expenses. •North Texas Segment. Operating expenses in theNorth Texas segment decreased$12.5 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in materials and supplies expense, operations and maintenance, construction fees and services, ad valorem tax, sales and use tax, and treater and compressor rentals. •Oklahoma Segment. Operating expenses in theOklahoma segment decreased$9.2 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in materials and supplies expense, construction fees and services, operations and maintenance, utilities, ad valorem tax, and treater rentals. •Louisiana Segment. Operating expenses in theLouisiana segment decreased$13.9 million primarily due to decreased labor and benefits expense as a result of a reduction in workforce inApril 2020 and reductions in materials and supplies expense, construction fees and services, ad valorem tax, and vehicle expenses. General and Administrative Expenses. General and administrative expenses were$53.9 million for the six months endedJune 30, 2020 compared to$83.6 million for the six months endedJune 30, 2019 , a decrease of$29.7 million , or 35.5%. The primary contributors to the decrease were as follows:
•Transaction costs decreased
•Labor costs and unit-based compensation decreased
•Fees and services expense, rents and leases, and insurance expenses decreased
Depreciation and Amortization. Depreciation and amortization was$321.0 million for the six months endedJune 30, 2020 compared to$305.8 million for the six months endedJune 30, 2019 , an increase of$15.2 million , or 5.0%. This increase was primarily due to new assets placed in service in theOklahoma segment, as well as accelerated depreciation on certain non-core assets. These increases were partially offset by the impairment ofLouisiana segment assets in the first quarter of 2020 and the conclusion of a finance lease in theNorth Texas segment in 2019. 45 -------------------------------------------------------------------------------- Table of Contents Impairments. For the six months endedJune 30, 2020 , we recognized impairment expense related to goodwill and property and equipment. For the six months endedJune 30, 2019 we recognized impairment expense related to goodwill. See "Item 1. Financial Statements-Note 2" for additional information on our property and equipment impairments and "Item 1. Financial Statements-Note 3" for additional information on our goodwill impairments. Impairment expense is composed of the following amounts (in millions): Six Months Ended June 30, 2020 2019 Goodwill impairment$ 184.6 $ 186.5 Property impairment 168.0 - Cancelled projects 1.9 - Total$ 354.5 $ 186.5 Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of$32.0 million for the six months endedJune 30, 2020 due to repurchases of the 2024, 2025, 2026, and 2029 Notes in open market transactions. See "Item 1. Financial Statements-Note 5" for additional information.
Loss on secured term loan receivable. We recorded a
Interest Expense. Interest expense was$110.8 million for the six months endedJune 30, 2020 compared to$103.9 million for the six months endedJune 30, 2019 , an increase of$6.9 million , or 6.6%. Interest expense consisted of the following (in millions): Six Months Ended June 30, 2020 2019 ENLK and ENLC Senior Notes$ 87.3 $ 83.4 Term Loan 10.6 17.1 Consolidated Credit Facility 8.2 6.1 Capitalized interest (2.5) (3.8)
Amortization of debt issue costs and net discounts (premiums) 2.2
2.8 Interest rate swap 5.0 (0.3) Other - (1.4) Total$ 110.8 $ 103.9 Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was$1.0 million for the six months endedJune 30, 2020 compared to$10.0 million for the six months endedJune 30, 2019 , a decrease of$9.0 million . The decrease was primarily attributable to a reduction of income of$8.8 million from our GCF investment as a result of lower fractionation revenues and lower operating expenses and a reduction of income of$0.2 million from our Cedar Cove JV. Income Tax Expense. Income tax benefit was$22.0 million for the six months endedJune 30, 2020 compared to an income tax benefit of$3.6 million for the six months endedJune 30, 2019 . The increase in income tax benefit was primarily attributable to lower income between periods. See "Item 1. Financial Statements-Note 6" for additional information. Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was$52.1 million for the six months endedJune 30, 2020 compared to net income of$66.7 million for the six months endedJune 30, 2019 , a decrease of$14.6 million . This decrease was primarily due to the conversion of ENLK common units into ENLC common units as a result of the Merger in the first quarter of 2019. Subsequent to the Merger, ENLC's non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP's 49.9% share of theDelaware Basin JV, Marathon Petroleum Corporation's 50% share of the Ascension JV, and other minor non-controlling interests. 46 -------------------------------------------------------------------------------- Table of Contents Critical Accounting Policies Information regarding our critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year endedDecember 31, 2019 , except as described below. Property and Equipment In accordance with ASC 360, Property, Plant, and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset's carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs. DuringMarch 2020 , we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. For the six months endedJune 30, 2020 , we recognized a$168.0 million impairment on property and equipment related to a portion of ourLouisiana reporting segment because the carrying amounts were not recoverable based on our expected future cash flows, and a$1.9 million impairment on property and equipment related to cancelled projects.
Goodwill Impairment
We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. DuringMarch 2020 , we determined that a sustained decline in our unit price and weakness in the overall energy sector, driven by low commodity prices and lower consumer demand due to the COVID-19 pandemic, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a quantitative goodwill impairment analysis on the remaining goodwill in the Permian reporting unit. Based on this analysis, a goodwill impairment loss for our Permian reporting unit in the amount of$184.6 million was recognized as an impairment loss on the consolidated statement of operations for the six months endedJune 30, 2020 .
Liquidity and Capital Resources
Cash Flows from Operating Activities. Net cash provided by operating activities was$316.8 million for the six months endedJune 30, 2020 compared to$521.5 million for the six months endedJune 30, 2019 . Operating cash flows and changes in working capital for comparative periods were as follows (in millions): Six Months EndedJune 30, 2020 2019
Operating cash flows before working capital
(102.1) 92.0 Operating cash flows before changes in working capital decreased$10.6 million for the six months endedJune 30, 2020 compared to the six months endedJune 30, 2019 . The primary contributors to the decrease in operating cash flows were as follows:
•Gross operating margin, excluding non-cash commodity swap activity, decreased
•Interest expense, excluding amortization of debt issue costs and net discounts
(premium) of notes, increased
47 -------------------------------------------------------------------------------- Table of Contents These changes to operating cash flows were offset by the following: •Operating expenses excluding unit-based compensation decreased$45.4 million primarily due to a reduction in workforce. For more information, see "Results of Operations." •General and administrative expenses excluding unit-based compensation decreased$25.0 million primarily due to a reduction in costs across our platform. For more information, see "Results of Operations." The changes in working capital for the six months endedJune 30, 2020 compared to the six months endedJune 30, 2019 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales. Cash Flows from Investing Activities. Net cash used in investing activities was$202.0 million for the six months endedJune 30, 2020 , compared to$426.9 million for the six months endedJune 30, 2019 . Investing cash flows are primarily related to capital expenditures, which decreased from$428.4 million for the six months endedJune 30, 2019 to$203.6 million for the six months endedJune 30, 2020 . The decrease was primarily due to reduced capital spending plans for 2020. Cash Flows from Financing Activities. Net cash used in financing activities was$140.2 million for the six months endedJune 30, 2020 compared to$136.0 million for the six months endedJune 30, 2019 . Our primary financing activities consisted of the following (in millions): Six Months Ended June 30, 2020 2019 Net borrowings on the Consolidated Credit Facility$ 50.0 $ 200.0 Net repurchases on ENLK senior unsecured notes (35.2) - Net borrowings (repurchases) on the 2029 Notes (0.8) 500.0 Net repayments on the ENLK 2019 unsecured senior notes - (400.0) Net repayments on the ENLC Credit Facility - (111.4) Contributions by non-controlling interests (1) 50.3 45.2 Distribution to members (139.8) (188.2)
Distributions to ENLK common units held by public unitholders (2)
- (104.8) Distributions to Series B Preferred Unitholders (3) (33.6) (33.2) Distributions to Series C Preferred Unitholders (3) (12.0) (12.0) Distributions to joint venture partners (4) (15.0) (12.7)
____________________________
(1)Represents contributions from NGP to theDelaware Basin JV. (2)Subsequent to the closing of the Merger, ENLK no longer has publicly held common units. (3)See "Item 1. Financial Statements-Note 7" for information on distributions to holders of the Series B and Series C Preferred Units. (4)Represents distributions to NGP for its ownership in theDelaware Basin JV, distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV, and distributions to other minor non-controlling interests. Capital Requirements. We expect our remaining 2020 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be approximately$40 million to$100 million , which is net of approximately$10 million to$20 million from our joint venture partners. Our primary capital projects for the remainder of 2020 include the construction of the Tiger Plant in theDelaware Basin and continued development of our existing systems. See "Other Recent Developments" for further details. We expect to fund capital expenditures from operating cash flows and capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities. In 2020, it is possible that not all of our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.
Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of
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Table of Contents
Total Contractual Cash Obligations. A summary of our total contractual cash
obligations as of
Payments Due by Period Total Remainder 2020 2021 2022 2023 2024 Thereafter Long-term debt obligations$ 3,532.3 $ - $ - $ - $ -$ 521.8 $ 3,010.5 Term Loan 850.0 - 850.0 - - - - Consolidated Credit Facility 400.0 - - - - 400.0 - Interest payable on fixed long-term debt obligations 2,412.4 86.7 173.1 173.1 173.1 161.7
1,644.7
Operating lease obligations 128.2 10.6 17.0 12.2 10.2 9.5 68.7 Purchase obligations 13.0 13.0 - - - - - Pipeline and trucking capacity and deficiency agreements (1) 199.6 31.0 39.8 31.8 28.1 33.0
35.9
Inactive easement commitment (2) 10.0 - - 10.0 - - - Total contractual obligations$ 7,545.5 $ 141.3 $ 1,079.9 $ 227.1 $ 211.4 $ 1,126.0 $ 4,759.8 ____________________________ (1)Consists of pipeline capacity payments for firm transportation and deficiency agreements. (2)Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized. The above table does not include any physical or financial contract purchase commitments for natural gas and NGLs due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount that is not already disclosed in the table above. The interest payable related to the Consolidated Credit Facility and the Term Loan are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Consolidated Credit Facility and the Term Loan, which vary from time to time.
Our contractual cash obligations for the remainder of 2020 are expected to be funded from cash flows generated from our operations.
Indebtedness
InDecember 2018 , we entered into the Consolidated Credit Facility, which permits us to borrow up to$1.75 billion on a revolving credit basis and includes a$500.0 million letter of credit subfacility. As ofJune 30, 2020 , there was$400.0 million in outstanding borrowings under the Consolidated Credit Facility and$23.0 million in outstanding letters of credit.
In addition, as of
See "Item 1. Financial Statements-Note 5" for more information on our outstanding debt instruments.
Recent Accounting Pronouncements
See "Item 1. Financial Statements-Note 2" for more information on recently issued and adopted accounting pronouncements.
Disclosure Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words "forecast," "may," "believe," "will," "should," "plan," "predict," "anticipate," "intend," "estimate," "expect," "continue," and similar expressions. Such forward-looking 49
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Table of Contents statements include, but are not limited to, statements about when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, future cost savings or operational initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic on us and our financial results and operations, and other statements that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operation, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) outbreak on our business, financial condition, and results of operation, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP's own interests to the detriment of our unitholders, (c) GIP's ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or businesses, (d) a default under GIP's credit facility could result in a change in control of us, could adversely affect the price of our common units, and could result in a default under our credit facility, (e) the dependence onDevon for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affectDevon or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) construction risks in our major development projects, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, and (t) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year endedDecember 31, 2019 and in Part II, "Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter endedMarch 31, 2020 may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.
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