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NGL Energy Partners LP

NGL Energy Partners LPNGLEarnings & Financial Report

NYSE · Utilities · Natural Gas Transmission

NGL Energy Partners LP is a U.S.-based midstream energy services firm. It offers transportation, storage, and logistics solutions for crude oil, natural gas liquids, and renewable fuels, plus water management services for upstream energy producers, operating primarily across North American markets.

What changed in NGL Energy Partners LP's 10-K — 2022 vs 2023

Top changes in NGL Energy Partners LP's 2023 10-K

457 paragraphs added · 463 removed · 373 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

79 edited+3 added−18 removed158 unchanged
The terminal features advantaged connectivity to other terminals and pipelines including important connections to our Grand Mesa Pipeline and to TC Energy’s terminal with access to the United States Gulf Coast via Marketlink. Our terminal is situated on 200 acres and is designed to be expanded based on customer demand.
The terminal features advantaged connectivity to other terminals and pipelines including important connections to the Grand Mesa Pipeline and to TC Energy’s terminal with access to the United States Gulf Coast via Marketlink. Our terminal is situated on 200 acres and is designed to be expanded based on customer demand.
Cushing is one of the most liquid crude oil trading hubs in the world and is the delivery point for the West Texas Intermediate futures contracts.
Cushing is one of the most liquid crude oil trading hubs in the world and is the delivery point for West Texas Intermediate futures contracts.
Changes in future mandates and incentives, or decisions by the federal government related to future reinstatement of the biodiesel tax credit, could result in changes in demand for ethanol and biodiesel. Trade Names. Our Liquids Logistics segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Centennial Energy, NGL Crude Logistics and Centennial Gas Liquids trade names.
Changes in future mandates and incentives, or decisions by the federal government related to future reinstatement of the biodiesel tax credit, could result in changes in demand for ethanol and biodiesel. Trade Names. Our Liquids Logistics segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Centennial Energy, Centennial Gas Liquids and NGL Crude Logistics trade names.
Certain environmental statutes impose strict and joint and several liability for costs required to clean up and restore sites where substances such as crude oil or wastes have been disposed or otherwise unlawfully released. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment.
Certain environmental statutes impose strict and/or joint and several liability for costs required to clean up and restore sites where substances such as crude oil or wastes have been disposed or otherwise unlawfully released. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment.
Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies.
Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and/or joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies.
Railcar Regulation We transport a significant portion of our natural gas liquids, crude oil and biodiesel via rail transportation, and we own and/or lease a fleet of crude oil, high-pressure and general purpose railcars for this purpose.
Railcar Regulation We transport a significant portion of our natural gas liquids and biodiesel via rail transportation, and we own and/or lease a fleet of crude oil, high-pressure and general purpose railcars for this purpose.
These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities 18 into or upon the navigable waters of the United States.
These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States.
In addition, we have several minimum volume commitments and other commercial agreements covering the Delaware, Midland, Eagle Ford, DJ and Pinedale Anticline Basins. Our focus in building our Water Solutions business has been to secure long-term, fixed fee contracts that contain minimum volume commitments, acreage dedications or similarly strong contractual relationships with large, well-capitalized producer customers.
In addition, we have several minimum volume commitments and other commercial agreements covering the Delaware, DJ, Eagle Ford and Pinedale Anticline Basins. Our focus in building our Water Solutions business has been to secure long-term, fixed fee contracts that contain minimum volume commitments, acreage dedications or similarly strong contractual relationships with large, well-capitalized producer customers.
Our water processing facilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Delaware Basin, the Midland Basin, the Denver-Julesburg (“DJ”) Basin and the Eagle Ford Basin. These assets are underpinned by long-term, fixed fee contracts and acreage dedications, some of which contain minimum volume commitments.
Our water processing facilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Delaware Basin, the Denver-Julesburg (“DJ”) Basin and the Eagle Ford Basin. These assets are underpinned by long-term, fixed fee contracts and acreage dedications, some of which contain minimum volume commitments.
Earl Blumenauer (D-OR) as H.R. 795 and in the Senate by Sen. Bernie Sanders (I-VT), which would require the President of the United States to declare a national climate emergency and take various actions to address climate change. The ultimate outcome of any possible future federal legislative initiatives is uncertain.
Earl Blumenauer (D-OR) as H.R. 795 and in the Senate by Sen. Bernie Sanders (I-VT), which would require the President of the United States to declare a national climate emergency and take various actions to address climate change. The ultimate outcome of any possible future federal legislative initiatives is 19 uncertain.
When markets are in 11 backwardation, our inventory values decrease during the time period between when we purchase inventory and when we sell it and the declining prices also typically have an unfavorable impact on our storage tank lease rates. To help mitigate the impact of changing prices, we enter into derivative instruments to hedge our inventory. Trade Names.
When markets are in backwardation, our inventory values decrease during the time period between when we purchase inventory and when we sell it and the declining prices also typically have an unfavorable impact on our storage tank lease rates. To help mitigate the impact of changing prices, we enter into derivative instruments to hedge our inventory. Trade Names.
Safety and Transportation All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, state agencies administer these laws, while in other states, municipalities administer these laws. We 20 conduct training programs to help ensure that our operations comply with applicable governmental regulations.
Safety and Transportation All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, state agencies administer these laws, while in other states, municipalities administer these laws. We conduct training programs to help ensure that our operations comply with applicable governmental regulations.
Debt Refinancing As previously disclosed, on February 4, 2021, we closed on a private offering of $2.05 billion of 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) and a new credit agreement which consisted of a $500.0 million asset-based revolving credit facility (“ABL Facility”).
Debt Refinancing As previously disclosed, on February 4, 2021, we closed on a private offering of $2.05 billion of our 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) and a new credit agreement which consisted of a $500.0 million asset-based revolving credit facility (“ABL Facility”).
Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. 17 The following is a discussion of the material environmental laws and regulations that relate to our businesses. Hazardous Substances and Waste.
Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of the material environmental laws and regulations that relate to our businesses. Hazardous Substances and Waste.
For additional information related to the ABL Facility and 2026 Senior Secured Notes, see Note 7 to our consolidated financial statements included in this Annual Report. 4 Primary Service Areas The following map shows the primary service areas of our businesses at March 31, 2022: 5 Organizational Chart The following chart provides a summarized overview of our legal entity structure at March 31, 2022: (1) Includes (i) NGL Water Solutions, LLC, which includes the operations of our Water Solutions segment, (ii) NGL Crude Logistics, LLC, which includes the operations of our Crude Oil Logistics segment and certain of our businesses within our Liquids Logistics segment and (iii) NGL Liquids, LLC, which includes the operations of certain of our businesses within our Liquids Logistics segment. 6 Our Business Strategies Our principal business objectives are to maximize the profitability and stability of our businesses, grow our businesses in an accretive and prudent manner, and maintain a strong balance sheet.
For additional information related to the ABL Facility and 2026 Senior Secured Notes, see Note 7 to our consolidated financial statements included in this Annual Report. 4 Primary Service Areas The following map shows the primary service areas of our businesses at March 31, 2023: 5 Organizational Chart The following chart provides a summarized overview of our legal entity structure at March 31, 2023: (1) Includes (i) NGL Water Solutions, LLC, which includes the operations of our Water Solutions segment, (ii) NGL Crude Logistics, LLC, which includes the operations of our Crude Oil Logistics segment and certain of our businesses within our Liquids Logistics segment and (iii) NGL Liquids, LLC, which includes the operations of certain of our businesses within our Liquids Logistics segment. 6 Our Business Strategies Our principal business objectives are to maximize the profitability and stability of our businesses, grow our businesses in an accretive and prudent manner, and maintain a strong balance sheet.
Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical 19 constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress.
Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress.
Our Water Solutions segment operates primarily under the NGL Water Solutions and Anticline Disposal trade names. Technology. We hold multiple patents for processing technologies. We believe that the technological capabilities of our Water Solutions business can be quickly implemented at new facilities and locations. Crude Oil Logistics Overview.
Our Water Solutions segment operates primarily under the NGL Water Solutions and Anticline Disposal trade names. 9 Technology. We hold multiple patents for processing technologies. We believe that the technological capabilities of our Water Solutions business can be quickly implemented at new facilities and locations. Crude Oil Logistics Overview.
Our facilities in Colorado, New Mexico and Texas dispose of produced water primarily into deep underground formations via injection wells. At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells.
Our facilities in Colorado, New Mexico and Texas dispose of produced water primarily into deep underground formations via injection wells. At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells. Customers.
The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as navigable waters, defined as waters of the United States (“WOTUS”), and impose requirements affecting our ability to conduct construction activities in waters and wetlands.
The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as navigable waters, defined as waters of the United States (“WOTUS”), and impose 18 requirements affecting our ability to conduct construction activities in waters and wetlands.
We also generate revenue from the sale of crude oil we recover in 9 processing the produced water. In addition, we may charge fees for the sale of produced water for reuse by our customers, pipeline transportation fees, pipeline interconnection fees and solids disposal fees. Trade Names.
We also generate revenue from the sale of crude oil we recover in processing the produced water. In addition, we may charge fees for the sale of produced water for reuse by our customers, pipeline transportation fees, pipeline interconnection fees and solids disposal fees. Trade Names.
We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, which authorizes the FERC to impose fines of up to $1 million per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations.
We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, which authorizes the FERC to impose fines of up to $1 million per day per violation of the Natural Gas Act, the NGPA, 16 or their implementing regulations.
The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404.
The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers or a delegated state agency pursuant to Section 404.
We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the Midland Basin in Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas.
We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas.
We used the net proceeds from the issuance to repay all outstanding borrowings under and terminate our former revolving credit facility and our term credit agreement, as well as to pay fees and expenses.
We used the net proceeds from the issuance to repay all outstanding 3 borrowings under and terminate our former revolving credit facility and our term credit agreement, as well as to pay fees and expenses.
Our operations are concentrated in and around four prolific crude oil producing regions in the United States - the DJ Basin in Colorado, the Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas and the United States Gulf Coast.
Our operations are concentrated in and around four prolific crude oil producing regions in the United States, including the DJ Basin in Colorado, the Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas and the United States Gulf Coast.
We intend to focus on generating revenues under long-term fixed fee contracts in addition to back-to-back contracts which minimize direct commodity price exposure.
We intend to focus on generating revenues under long-term fixed fee contracts in addition to back-to-back contracts which minimize commodity price exposure.
Our foundational asset in this segment is the Grand Mesa Pipeline (“Grand Mesa”), a 550-mile pipeline that transports crude oil from its origin in Weld County, Colorado to our terminal in Cushing, Oklahoma. Grand Mesa commenced operations on November 1, 2016 and has operated continuously since then.
Our foundational asset in this segment is the Grand Mesa Pipeline, a 550-mile pipeline that transports crude oil from its origin in Weld County, Colorado to our terminal in Cushing, Oklahoma. The Grand Mesa Pipeline commenced operations on November 1, 2016 and has operated continuously since then.
These assets complement our existing assets in the upper Midwest and will expand our presence in Michigan, one of the top propane markets in the United States. We utilize a fleet of approximately 4,400 high-pressure and general purpose leased railcars of which 34 railcars are subleased by third parties.
These assets complement our existing assets in the upper Midwest and will expand our presence in Michigan, one of the top propane markets in the United States. We utilize a fleet of approximately 4,400 high-pressure and general purpose leased railcars of which 145 railcars are subleased by third parties.
We own a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a marine export/import terminal in Norfolk, Virginia. The Port Hudson terminal is located near Baton Rouge, Louisiana, and is in proximity to other refined products infrastructure along the Colonial pipeline.
We own a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a marine export/import terminal in Chesapeake, Virginia. The Port Hudson terminal is located near Baton Rouge, Louisiana, and is in proximity to other refined products infrastructure along the Colonial pipeline.
Our strategically deployed terminals, towboats and barges, as well as our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to optimal markets.
Our strategically deployed terminals, as well as our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to optimal markets.
During the year ended March 31, 2022, in the Delaware Basin we received approximately 98% of produced and flowback water via pipelines. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.
During the year ended March 31, 2023, in the Delaware Basin, we received approximately 98% of produced and flowback water via pipelines. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.
The facility has an aggregate storage capacity of 20,378,000 gallons. We own 25 transloading units, which enable customers to transfer product from railcars to trucks.
The facility has an aggregate storage capacity of 20,378,000 gallons. We own 28 transloading units, which enable customers to transfer product from railcars to trucks.
We own and operate a large scale crude oil terminal located in Cushing, Oklahoma with 3,626,000 barrels of storage capacity, seven off-loading lease automatic custody transfer units (“LACTs”), a full control room, on-site laboratory, and three 24-inch bi-directional pipelines each capable of moving 360,000 barrels per day.
We own and operate a large scale crude oil terminal located in Cushing, Oklahoma with 3,626,000 barrels of storage capacity, seven off-loading lease automatic custody transfer units (“LACTs”), a full control room, on-site quality management building, and three 24-inch bi-directional pipelines each capable of moving 360,000 barrels per day.
For more information regarding our dispositions and acquisitions transactions and the impact to our operations, see Note 17 and Note 18 to our consolidated financial statements included in this current Annual Report and our Annual Report on Form 10-K for the years ended March 31, 2021 and 2020 .
For more information regarding our dispositions and acquisitions transactions and the impact to our operations, see Note 17 and Note 18 to our consolidated financial statements included in this current Annual Report and our Annual Reports on Form 10-K for the years ended March 31, 2022 and 2021 .
Our Liquids Logistics segment serves approximately 1,300 customers in 48 states, Mexico and Canada, including national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. During the year ended March 31, 2022, 22% of the revenues of our Liquids Logistics segment were generated from our ten largest customers of the segment. Seasonality .
Our Liquids Logistics segment serves approximately 1,300 customers in 48 states, Mexico and Canada, including national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. During the year ended March 31, 2023, 23% of the revenues of our Liquids Logistics segment were generated from our ten largest customers of the segment. Seasonality .
Customers. The primary customers of our operations consist mainly of large publicly traded, oil and gas companies with diversified acreage positions across multiple leading oil and gas plays. During the year ended March 31, 2022, 69% of the revenues of our Water Solutions segment were generated from our ten largest customers of the segment. Competition.
The primary customers of our operations consist mainly of large publicly traded, oil and gas companies with diversified acreage positions across multiple leading oil and gas plays. During the year ended March 31, 2023, 70% of the revenues of our Water Solutions segment were generated from our ten largest customers of the segment. Competition.
The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density.
These regulations include potential fines and penalties for violations. 20 The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density.
The flexible, non-exclusive nature of this joint effort allows each of us to continue to operate produced water reuse and recycling activities independent of one another. During 8 the year ended March 31, 2022, we sold approximately 34.1 million barrels of recycled water, which includes the sale of produced water and recycled water for use in our customers’ completion activities.
The flexible, non-exclusive nature of this joint effort allows each of us to continue to operate produced water reuse and recycling activities independent of one another. During 8 the year ended March 31, 2023, we sold approximately 43.4 million barrels of recycled water, which includes the sale of produced water and recycled water for use in our customers’ completion activities.
The primary factors on which we compete are: • price; • availability of supply and refinery demand; • reliability of service; • open credit; • logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars and towboats; and • long-term customer relationships. Supply.
The primary factors on which we compete are: • price; • availability of supply and refinery demand; • reliability of service; • open credit; • logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipeline and railcars; and • long-term customer relationships. Supply.
We obtain crude oil from a large base of suppliers, which consists primarily of crude oil producers. We currently purchase crude oil from approximately 350 producers at approximately 5,700 leases. Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma, St.
We obtain crude oil from a large base of suppliers, which consists primarily of crude oil producers. We currently purchase crude oil from approximately 276 producers at approximately 2,875 leases. Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma, St.
Catharines, Ontario, Canada is operated by a third party under a year-to-year agreement. We own the land on which 15 of the 24 natural gas liquids terminals are located and we either have easements or lease the land on which the remaining terminals are located.
The terminal in St. Catharines, Ontario, Canada is operated by a third party under a year-to-year agreement. We own the land on which 15 of the 25 natural gas liquids terminals are located and we either have easements or lease the land on which the remaining terminals are located.
We are not currently aware of any facts, events, or conditions related to oil spills that could materially impact our consolidated results of operations or financial position. In 1973, the EPA adopted oil pollution prevention regulations under the CWA.
We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our consolidated results of operations or financial position. Oil Pollution Prevention . In 1973, the EPA adopted oil pollution prevention regulations under the CWA.
Our primary focus is to reduce our absolute debt and leverage and maintain sufficient liquidity to reduce our overall leverage below 4.75 to 1.00 and reinstate the payment of distributions. We are also focused on maintaining credit metrics to manage existing and future capital requirements as well as to take advantage of market opportunities.
Our primary focus is to reduce our absolute debt and leverage and maintain sufficient liquidity to continue to reduce our overall leverage and reinstate the payment of distributions. We are also focused on maintaining credit metrics to manage existing and future capital requirements as well as to take advantage of market opportunities.
Available Information on our Website Our website address is www.nglenergypartners.com. We make available on our website, free of charge, the periodic reports that we file with or furnish to the Securities and Exchange Commission (“SEC”), as well as all amendments to these reports, as soon as reasonably practicable after such reports are filed with or furnished to the SEC.
We make available on our website, free of charge, the periodic reports that we file with or furnish to the Securities and Exchange Commission (“SEC”), as well as all amendments to these reports, as soon as reasonably practicable after such reports are filed with or furnished to the SEC.
Our strategically located terminals, large leased railcar fleet, shipper status on common carrier pipelines, and substantial leased storage enable us to be a preferred 7 purchaser and seller of natural gas liquids.
Our strategically located terminals, propane pipeline system in Michigan, large leased railcar fleet, shipper status on common carrier pipelines, and substantial leased 7 storage enable us to be a preferred purchaser and seller of natural gas liquids.
HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations.
HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation.
Operations. We own 111 water treatment and disposal facilities, including 212 injection wells. The location and permitted processing capacities of these facilities are summarized below.
Operations. We own 93 water treatment and disposal facilities, including 197 injection wells. The location and permitted processing capacities of these facilities are summarized below.
With a system that handled approximately 656.2 million barrels of produced water across its areas of operation during the year ended March 31, 2022, we believe that we are the largest independent produced water transportation and disposal company in the United States. We currently have over 660,000 acres dedicated to our system under long-term agreements in the Northern Delaware Basin.
With a system that handled approximately 849.5 million barrels of produced water across its areas of operation during the year ended March 31, 2023, we believe that we are the largest independent produced water transportation and disposal company in the United States. We currently have approximately 670,000 acres dedicated to our system under long-term agreements in the Northern Delaware Basin.
In that regard, at the end of fiscal year 2021, we implemented $20 per hour 15 minimum wage for all regular, full-time employees. More than 95% of our eligible employees participate in the NGL 401(k) Plan, and we increased our employer match in our 401(k) Plan in fiscal year 2021.
In that regard, at the end of fiscal year 2021, we implemented $20 per hour 15 minimum wage for all regular, full-time employees. More than 95% of our eligible employees participated in the NGL 401(k) Plan in fiscal year 2023.
Storage Capacity (in gallons) Location Number of Facilities Own (1) Lease (2) Total Terminal Interconnects Virginia 2 20,720,000 — 20,720,000 Rail Facility; Marine Facility Arkansas 3 3,765,000 90,000 3,855,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility Minnesota 1 1,829,000 — 1,829,000 Connected to Enterprise Mid-America Pipeline; Rail Facility Missouri 2 1,770,000 — 1,770,000 Connected to Phillips66 Blue Line Pipeline Indiana 1 1,530,000 — 1,530,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility Wisconsin 2 714,000 390,000 1,104,000 Connected to Enterprise Mid-America Pipeline; Rail Facility Massachusetts 2 668,400 120,000 788,400 Rail Facility Louisiana 1 720,000 — 720,000 Truck Facility Washington 3 300,000 355,000 655,000 Rail Facility Illinois 1 480,000 — 480,000 Connected to Phillips66 Blue Line Pipeline Michigan 1 480,000 480,000 Connected to Ambassador Pipeline New York 1 — 270,000 270,000 Rail Facility Pennsylvania 1 180,000 — 180,000 Rail Facility Maine 1 — 120,000 120,000 Rail Facility Vermont 1 — 120,000 120,000 Rail Facility United States Total 23 33,156,400 1,465,000 34,621,400 Ontario, Canada 1 — 120,000 120,000 Truck Facility Canada Total 1 — 120,000 120,000 Total 24 33,156,400 1,585,000 34,741,400 (1) These facilities are located on lands we own.
Storage Capacity (in gallons) Location Number of Facilities Own (1) Lease (2) Total Terminal Interconnects Virginia 2 20,888,000 — 20,888,000 Rail Facility; Marine Facility Arkansas 3 3,765,000 90,000 3,855,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility Minnesota 1 1,829,000 — 1,829,000 Connected to Enterprise Mid-America Pipeline; Rail Facility Missouri 2 1,770,000 — 1,770,000 Connected to Phillips66 Blue Line Pipeline Indiana 1 1,530,000 — 1,530,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail Facility Wisconsin 2 696,000 390,000 1,086,000 Connected to Enterprise Mid-America Pipeline; Rail Facility Massachusetts 2 668,400 120,000 788,400 Rail Facility Louisiana 1 720,000 — 720,000 Truck Facility Washington 3 300,000 355,000 655,000 Rail Facility Illinois 1 480,000 — 480,000 Connected to Phillips66 Blue Line Pipeline Michigan 1 480,000 480,000 Connected to Ambassador Pipeline New York 2 — 450,000 450,000 Rail Facility Pennsylvania 1 180,000 — 180,000 Rail Facility Maine 1 — 120,000 120,000 Rail Facility Vermont 1 — 120,000 120,000 Rail Facility United States Total 24 33,306,400 1,645,000 34,951,400 Ontario, Canada 1 — 120,000 120,000 Truck Facility Canada Total 1 — 120,000 120,000 Total 25 33,306,400 1,765,000 35,071,400 (1) These facilities are located on lands we own.
(2) These facilities are located on lands we lease. We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri are operated for us by a third party for a monthly fee under an operating and maintenance agreement that expires in November 2022. The terminal in St.
(2) These facilities are located on lands we lease. We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri were operated for us by a third party for a monthly fee under an operating and maintenance agreement that we terminated as of March 31, 2023.
Our system has approximately 650 miles of newly-built, in-service large diameter produced water pipelines connected to 58 active saltwater disposal facilities and 122 active disposal wells. We have over 660,000 acres dedicated to the Northern Delaware system providing a multi-decade drilling inventory and significant growth opportunity.
Our system has approximately 730 miles of newly-built, in-service large diameter produced water pipelines connected to 57 active saltwater disposal facilities and 125 active disposal wells. We currently have approximately 670,000 acres dedicated to the Northern Delaware system providing a multi-decade drilling inventory and significant growth opportunity.
These operations are conducted through our 24 owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and expect to commence operations on our propane pipeline in Michigan in June 2022.
These operations are conducted through our 25 owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and we own a propane pipeline system in Michigan.
We purchased an additional barge in April 2022. All of our 396 owned railcars and 210 leased railcars are compliant with the standards for railcars built subsequent to 2011 for the commodities they are transporting. (See Part I, Item 1 “Government Regulation”). We also own 27 strategically located pipeline injection stations, the locations of which are summarized below.
All of our 396 owned railcars are compliant with the standards for railcars built subsequent to 2011 for the commodities they are transporting. (See Part I, Item 1 “Government Regulation”). 10 We also own 27 strategically located pipeline injection stations, the locations of which are summarized below.
We purchase crude oil from producers and marketers and transport it to refineries or for resale. Our strategically deployed terminals, towboats and barges, as well as our owned and contracted pipeline capacity, provide access to a wide range of customers and markets.
We purchase crude oil from producers and marketers and transport it to refineries or for resale. Our strategically deployed terminals, as well as our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to optimal markets.
Our operations are subject to a myriad of federal, state and local laws and regulations relating to the protection of the environment.
Environmental Regulation General. Our operations are subject to federal, state and local laws and regulations relating to the protection of the environment.
In addition, the Federal Trade Commission (“FTC”) holds statutory authority under the 16 Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1 million per violation.
In addition, the Federal Trade Commission (“FTC”) holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1 million per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets.
We retained ownership of our previously acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements, to the extent such easements remain in effect, for projects involving the transportation of crude oil and condensate.
With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements, to the extent such easements remain in effect, for projects involving the transportation of crude oil and condensate.
The following table summarizes our significant leased storage space at natural gas liquids and refined products storage facilities and interconnects to those facilities: Leased Storage Space (in gallons) Storage Facility Location Beginning April 1, 2022 At March 31, 2022 Storage Interconnects Kansas 56,700,000 56,700,000 Connected to Enterprise Mid-America Pipeline, NuStar Pipelines and ONEOK North System Pipeline; Rail Facility; Truck Facility Michigan 22,260,000 10,500,000 Rail Facility; Truck Facility Utah 8,400,000 22,050,000 Rail Facility Missouri 7,560,000 7,560,000 Truck Facility Arizona 7,056,000 7,056,000 Rail Facility; Truck Facility Texas 4,410,000 4,410,000 Connected to Enterprise Texas Eastern Products Pipeline; Truck Facility Mississippi 2,100,000 2,520,000 Connected to Enterprise Dixie Pipeline; Rail Facility Oregon 554,400 554,400 Connected to Kinder Morgan Pipeline and Olympic Pipeline United States Total 109,040,400 111,350,400 Ontario, Canada 8,467,200 15,750,000 Rail Facility Alberta, Canada 3,970,092 3,440,800 Connected to Cochin Pipeline; Rail Facility Canada Total 12,437,292 19,190,800 Total 121,477,692 130,541,200 Customers .
The following table summarizes our significant leased storage space at natural gas liquids and refined products storage facilities and interconnects to those facilities: Leased Storage Space (in gallons) Storage Facility Location Beginning April 1, 2023 At March 31, 2023 Storage Interconnects Kansas 56,700,000 56,700,000 Connected to Enterprise Mid-America Pipeline, NuStar Pipelines and ONEOK North System Pipeline; Rail Facility; Truck Facility Michigan 23,520,000 24,780,000 Rail Facility; Truck Facility Utah 15,750,000 16,800,000 Rail Facility Arizona 7,056,000 7,056,000 Rail Facility; Truck Facility Texas 4,830,000 3,150,000 Connected to Enterprise Texas Eastern Products Pipeline; Truck Facility Mississippi 3,780,000 3,780,000 Connected to Enterprise Dixie Pipeline; Rail Facility Oregon 2,100,000 554,400 Connected to Kinder Morgan Pipeline and Olympic Pipeline United States Total 113,736,000 112,820,400 Ontario, Canada 8,467,200 8,467,200 Rail Facility Alberta, Canada 3,970,092 3,970,092 Connected to Cochin Pipeline; Rail Facility Canada Total 12,437,292 12,437,292 Total 126,173,292 125,257,692 Customers .
Human Capital At March 31, 2022, we had 842 employees in 28 states and Canada. Of those employees, 220 provide work primarily for our Water Solutions segment, 245 provide work primarily for our Crude Oil Logistics segment, 169 provide work primarily for our Liquids Logistics segment, and 208 provide administrative services to the various business segments.
Human Capital At March 31, 2023, we had 638 employees in 29 states and Canada. Of those employees, 229 provide work primarily for our Water Solutions segment, 67 provide work primarily for our Crude Oil Logistics segment, 167 provide work primarily for our Liquids Logistics segment, and 175 provide administrative services to the various business segments.
On November 15, 2021, the EPA issued a proposal to revise the GHG NSPS regulations that, if finalized, would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program.
On November 15, 2021, the EPA issued a proposal to revise the GHG NSPS regulations that, if finalized, would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program. On November 11, 2022, the EPA supplemented its 2021 proposal, the comment period for which supplement ended February 13, 2023.
Our Crude Oil Logistics segment faces significant competition, as many entities are engaged in the crude oil logistics business, some of which are larger and have greater financial resources than we do.
Any loss of those customers or their contracts could have an adverse impact on our financial results. Competition. Our Crude Oil Logistics segment faces significant competition, as many entities are engaged in the crude oil logistics business, some of which are larger and have greater financial resources than we do.
In addition, the federal government has in recent years granted certain tax credits for the use of biodiesel, although on several occasions these tax credits have expired. In December 2019, the federal government passed a law to reinstate the tax credit retroactively to January 1, 2018, with the credit expiring on December 31, 2022.
In addition, the federal government has in recent years granted certain tax credits for the use of biodiesel, although on several occasions these tax credits have expired. In August 2022, the federal government extended the tax credit, with the tax credit now expiring on December 31, 2024.
Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets.
The Commodity Futures Trading Commission (“CFTC”) is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets.
These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act “(CAA”), the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act (“CWA”) , the Safe Drinking Water Act, the Oil Spills Prevention and Preparedness Regulations, and comparable state statutes.
These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act (“CAA”), the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act (“CWA”), the Safe Drinking Water Act, the Oil Spills Prevention and Preparedness Regulations, and comparable state statutes. 17 CERCLA, also known as the “Superfund” law, and similar state laws, impose liability on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment.
Number of Number of Permitted Processing Capacity (barrels per day) Location Facilities Wells Own (1) Lease (2) Total Permian Basin Delaware Basin (3) - Texas and New Mexico 58 122 1,514,000 3,297,300 4,811,300 Midland Basin (3) - Texas 14 14 358,300 — 358,300 Eagle Ford Basin (3)(4) - Texas 22 36 549,000 362,000 911,000 DJ Basin - Colorado 13 32 393,000 162,500 555,500 Granite Wash (3) - Texas 2 3 60,000 — 60,000 Pinedale Anticline Basin (5) - Wyoming 1 4 — 90,240 90,240 Eaglebine - Texas 1 1 20,000 — 20,000 Total - All Facilities 111 212 2,894,300 3,912,040 6,806,340 (1) These facilities are located on lands we own.
Number of Number of Permitted Processing Capacity (barrels per day) Location Facilities Wells Own (1) Lease (2) Total Permian Basin Delaware Basin (3) - Texas and New Mexico 57 125 1,489,000 3,462,300 4,951,300 Eagle Ford Basin (3)(4) - Texas 19 33 474,000 362,000 836,000 DJ Basin - Colorado 13 31 373,000 162,500 535,500 Granite Wash (3) - Texas 2 3 60,000 — 60,000 Pinedale Anticline Basin - Wyoming 1 4 — 90,240 90,240 Eaglebine - Texas 1 1 20,000 — 20,000 Total - All Facilities 93 197 2,416,000 4,077,040 6,493,040 (1) These facilities are located on lands we own.
State Number of Pipeline Injection Stations Texas 13 New Mexico 6 Oklahoma 5 Kansas 3 Total 27 Customers. Our customers include crude oil refiners, producers, and marketers.
State Number of Pipeline Injection Stations Texas 13 New Mexico 6 Oklahoma 5 Kansas 3 Total 27 On March 30, 2023, we sold our marine assets (see Note 17 to our consolidated financial statements included in this Annual Report). Customers. Our customers include crude oil refiners, producers, and marketers.
The main line portion of this pipeline is comprised of an undivided interest with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) in which we have the right to use 150,000 barrels per day of capacity of the pipeline.
The main line portion of this pipeline is comprised of an undivided interest with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) in which we have ownership of 150,000 barrels per day of capacity of the pipeline. During the year ended March 31, 2023, approximately 27.7 million barrels of crude oil were transported on the Grand Mesa Pipeline.
During the year ended March 31, 2022, we sold approximately 2.8 billion gallons of natural gas liquids, refined products and renewables products, or 7.61 million gallons (approximately 181,000 barrels) per day. Operations .
We employ a number of contractual and hedging strategies to minimize commodity exposure and maximize earnings stability of this segment. During the year ended March 31, 2023, we sold approximately 2.7 billion gallons of natural gas liquids, refined products and renewables products, or 7.45 million gallons (approximately 177,000 barrels) per day. Operations .
We also own and operate origin terminals at Lucerne and Riverside, Colorado, where we aggregate crude volumes of different types and grades and store them until they are ready for transfer to our Grand Mesa Pipeline. The Lucerne terminal has 950,000 barrels of operational tankage and a 12 bay truck loading facility.
Operating costs associated with the Grand Mesa Pipeline are allocated to us based on our proportionate ownership interest and throughput. We also own and operate origin terminals at Lucerne and Riverside, Colorado, where we aggregate crude oil volumes of different types and grades and store them until they are ready for transfer to the Grand Mesa Pipeline.
We use this expansive network of transportation assets to deliver crude oil to optimal markets. 10 We currently transport crude oil using the following assets: • The Grand Mesa Pipeline, which is described above, and 20 other common carrier pipelines owned by third parties; • 396 owned and 210 leased railcars (all of which are leased or subleased to third parties); and • 13 owned towboats and 24 owned barges operating primarily in the intercoastal waterways of the United States Gulf Coast and along the Mississippi and Arkansas River systems.
We currently transport crude oil using the following assets: • The Grand Mesa Pipeline, which is described above, and 19 other common carrier pipelines owned by third parties; and • 396 owned railcars (all of which are leased or subleased to third parties).
In 21 general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However, these expenditures cannot be accurately estimated at this time, but we do not expect compliance with these standards to have a material adverse effect on our business.
However, these expenditures cannot be accurately estimated at this time, but we do not expect compliance with these standards to have a material adverse effect on our business. Available Information on our Website Our website address is www.nglenergypartners.com.
We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States Coast Guard.
We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above.
Our Liquids Logistics segment conducts supply operations for natural gas liquids, refined petroleum products and biodiesel to a broad range of commercial, retail and industrial customers across the United States and Canada. These operations are conducted through our 24 owned terminals, third-party storage and terminal facilities, nine common carrier pipelines and a fleet of leased railcars.
Our Crude Oil Logistics segment operates primarily under the NGL Crude Logistics, NGL Crude Transportation, NGL Crude Terminals and NGL Crude Cushing trade names. Liquids Logistics Overview . Our Liquids Logistics segment conducts supply operations for natural gas liquids, refined petroleum products and biodiesel to a broad range of commercial, retail and industrial customers across the United States and Canada.
The Riverside terminal has 20,000 barrels of storage and a four bay truck loading facility. Through our undivided interest in the Grand Mesa Pipeline, we have sufficient capacity to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments.
Through our ownership in the Grand Mesa Pipeline, we have sufficient capacity to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments. We retained ownership of our previously acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate.
During the year ended March 31, 2022, 90% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment, of which CITGO Petroleum Corporation accounted for 12.8% of our consolidated revenues for the year ended March 31, 2022.
During the year ended March 31, 2023, 85% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment. Additionally, certain key customers of the Crude Oil Logistics segment contribute significantly to the cash flows and profitability of the organization.
We are currently working on a Marysville, Michigan connection, which has an estimated completion date of June 2022 and will allow the Ambassador Pipeline to be fully operational. The Wheeler propane terminal, in central Michigan, was fully permitted and operational on February 1, 2022.
The Marysville, Michigan connection was completed in August 2022 and this allowed the Ambassador Pipeline to be fully operational. The Wheeler propane terminal, in central Michigan, is located at the mid-point of the pipeline.
(5) This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard. Our customers bring produced and flowback water generated by crude oil and natural gas exploration and production operations to our facilities for treatment through pipeline gathering systems and by truck.
On March 31, 2023, we sold certain saltwater disposal assets in the Midland Basin (see Note 17 to our consolidated financial statements included in this Annual Report). Our customers bring produced and flowback water generated by crude oil and natural gas exploration and production operations to our facilities for treatment through pipeline gathering systems and by truck.
We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and expect to commence operations on our propane pipeline in Michigan in June 2022. We employ a number of contractual and hedging strategies to minimize commodity exposure and maximize earnings stability of this segment.
These operations are conducted through our 25 owned terminals, third-party storage and terminal facilities, nine common 11 carrier pipelines and a fleet of leased railcars. We also provide services for marine exports of butane through our facility located in Chesapeake, Virginia, and we own a propane pipeline system in Michigan.
Removed
These steps included the sale of the following: • Our Retail Propane segment during the years ended March 31, 2018 and 2019; • Certain non-core water disposal businesses in the Permian and Bakken Basins during the year ended March 31, 2019; • Certain refined products businesses including TransMontaigne Product Services, LLC (“TPSL”), our refined products business in the mid-continent region of the United States (“Mid-Con”) and our gas blending business in the southeastern and eastern regions of the United States (“Gas Blending”) during the year ended March 31, 2020; and • Our interest in Sawtooth Caverns, LLC (“Sawtooth”) during the year ended March 31, 2022. 3 In our Water Solutions segment we acquired strategic water infrastructure assets including Mesquite Disposals Unlimited, LLC (“Mesquite”) and the equity interests of Hillstone Environmental Partners, LLC (“Hillstone”) during the year ended March 31, 2020, while in our Liquids Logistics segment, we acquired DCP Midstream LP’s natural gas liquids business during the year ended March 31, 2019 and an approximately 225-mile propane pipeline in Michigan (the “Ambassador Pipeline”) during the year ended March 31, 2021.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make 31 such acquisitions or an inability to successfully integrate those operations into our overall business operations.
In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being 31 accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make such acquisitions or an inability to successfully integrate those operations into our overall business operations.
Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file federal income tax returns and pay tax on their share of our taxable income.
If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units.
If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose common units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units.
Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize a gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of those common units, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize a gain or loss from the disposition.
The amount of cash we will have to fund our operations, repay indebtedness or pay distributions principally depends on the amount of cash we generate from our operations, not profitability, which will fluctuate from quarter to quarter based on, among other things: • the cost of crude oil, natural gas liquids, gasoline, diesel, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers; • the volume of produced water delivered to our processing facilities; • disruptions in the availability of crude oil and/or natural gas liquids supply; • our ability to renew leases for storage and railcars; • the effectiveness of our commodity price hedging strategy; • weather conditions across the United States; • the level of competition from other energy providers; and • prevailing economic conditions.
The amount of cash we will have to fund our operations, repay indebtedness or pay distributions principally depends on the amount of cash we generate from our operations, not profitability, which will fluctuate from quarter to quarter based on, among other things: • the cost of crude oil, natural gas liquids, gasoline, diesel, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers; 23 • the volume of produced water delivered to our processing facilities; • disruptions in the availability of crude oil and/or natural gas liquids supply; • our ability to renew leases for storage and railcars; • the effectiveness of our commodity price hedging strategy; • weather conditions across the United States; • the level of competition from other energy providers; and • prevailing economic conditions.
Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce crude oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for crude oil and natural gas, environmental restrictions on the exploration and production of crude oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in crude oil and natural gas producing countries and merger and divestiture activity among our current or potential customers.
Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce crude oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for crude oil and natural gas, environmental restrictions on the exploration and production of crude oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in crude oil and natural gas producing countries 26 and merger and divestiture activity among our current or potential customers.
You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that: • we were conducting business in a state but had not complied with that particular state’s partnership statute; or • a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that: • we were conducting business in a state but had not complied with that particular state’s partnership statute; or • a unitholder’s right to act with other unitholders to remove or replace our GP, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.
In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate 35 the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
The risk to our unitholders due to such conflicts may arise because of the following factors, among others: • our general partner is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group, in resolving conflicts of interest; • neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us; • except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; • our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; • our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus.
The risk to our unitholders due to such conflicts may arise because of the following factors, among others: • our GP is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group, in resolving conflicts of interest; • neither our Partnership Agreement nor any other agreement requires owners of our GP to pursue a business strategy that favors us; • except in limited circumstances, our GP has the power and authority to conduct our business without unitholder approval; • our GP determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; • our GP determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus.
In addition to the factors discussed elsewhere in this Annual Report, you should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business, financial condition or results of operations, including our ability to generate cash to fund our operations, repay indebtedness and pay distributions.
In addition to the factors discussed elsewhere in this Annual Report, you should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business, financial condition or results of operations, including our ability to generate cash to 21 fund our operations, repay indebtedness and pay distributions.
If our operating results are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all.
If our operating results are not sufficient to service our future indebtedness, we would be 24 forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all.
It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. 45 There are limits on the deductibility of our losses that may adversely affect our unitholders.
It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. There are limits on the deductibility of our losses that may adversely affect our unitholders.
The Crude Oil Logistics and Liquids Logistics segments are “margin-based” businesses in which our realized margins depend on the differential of sales prices over our total supply costs. Our profitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other market conditions.
The Crude Oil Logistics and Liquids Logistics segments are “margin-based” businesses in which our realized margins depend on the differential of sales prices over our supply costs. Our profitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other market conditions.
Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the production of or the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off.
Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the 28 occurrence of certain events, some of which are beyond our control, including force majeure events wherein the production of or the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off.
All holders of our Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Preferred Units. General Risks The default by significant customers and counterparties or loss of one or more significant customers could materially or adversely affect our business, financial condition, results of operations and cash flows.
All holders of our Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Preferred Units. 46 General Risks The default by significant customers and counterparties or loss of one or more significant customers could materially or adversely affect our business, financial condition, results of operations and cash flows.
If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders could be substantially reduced. 43 Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders could be substantially reduced. Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We seek to mitigate this risk by entering into 27 NYMEX futures contracts. However, price changes in locations where we operate do not correspond directly with changes in prices in the NYMEX futures market, and as a result these futures contracts cannot be perfect hedges of our commodity price risk.
We seek to mitigate this risk by entering into NYMEX futures contracts. However, price changes in locations where we operate do not correspond directly with changes in prices in the NYMEX futures market, and as a result these futures contracts cannot be perfect hedges of our commodity price risk.
Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our 44 unitholders.
Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders.
Any disallowed business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the partner level. 42 These limitations might cause interest expense to be deducted by our unitholders in a later period than recognized in the GAAP financial statements.
Any disallowed business interest expense is then generally carried forward as a deduction in a succeeding taxable year at the partner level. These limitations might cause interest expense to be deducted by our unitholders in a later period than recognized in the GAAP financial statements.
Factors that could lead to a decrease in market demand include: • a recession, rising inflation, or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel; • higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline; • an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers; • an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and • the increased use of alternative fuel sources, such as battery-powered engines.
Factors that could lead to a decrease in market demand include: • a recession, rising inflation, or other adverse economic conditions that results in lower spending by consumers on gasoline, diesel, and travel; • higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline; • an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers; • an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and • the increased use of alternative fuel sources, such as battery-powered engines.
Our competitors include major integrated oil companies, other midstream or wholesale marketing companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gas liquids.
Our competitors include major integrated oil companies, other midstream or wholesale marketing companies, interstate and intrastate pipelines and companies that gather, compress, treat, 27 process, transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gas liquids.
The United States Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize all aspects of the proration method we have adopted.
The United States Department of the Treasury adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize all aspects of the proration method we have adopted.
In addition, cyber security attacks on our customer and employee data may result in a financial loss, 48 including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure.
In addition, cyber security attacks on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure.
If the 25 payment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
If the payment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.
The widespread outbreak pandemics (like COVID-19) or any other public health crises that impacts the global demand for energy commodities may have material adverse effects on our business, financial position, results or operations and/or cash flows.
The widespread outbreak of pandemics (like COVID-19) or any other public health crises that impacts the global demand for energy commodities may have material adverse effects on our business, financial position, results or operations and/or cash flows.
Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.
Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. 43 Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.
Customers’ expectations of lower 26 market prices for crude oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment.
Customers’ expectations of lower market prices for crude oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment.
Fiduciary duties owed to our unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Revised Uniform Limited Partnership Act (“Delaware LP Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership.
Fiduciary duties owed to our unitholders by our GP are prescribed by law and our Partnership Agreement. The Delaware Revised Uniform Limited Partnership Act (“Delaware LP Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership.
Examples include the exercise of its limited call right, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the Partnership; • provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner subjectively believed that the decision was in, or not opposed to, the best interests of the Partnership; • generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and • provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
Examples include the exercise of its limited call right, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the Partnership; 37 • provides that our GP shall not have any liability to us or our unitholders for decisions made in its capacity as GP so long as it acted in good faith, meaning our GP subjectively believed that the decision was in, or not opposed to, the best interests of the Partnership; • generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our GP and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our GP may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and • provides that our GP and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our GP or those other persons acted in bad faith or engaged in fraud or willful misconduct.
With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are 33 administered by the DOT.
With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are administered by the DOT.
In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities impact the utilization and 28 value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers.
In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities impact the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers.
If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units 46 may be required to file U.S. federal income tax returns in order to seek a refund of such excess.
If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units may be required to file U.S. federal income tax returns in order to seek a refund of such excess.
Any of these occurrences could disrupt our business, resulting in potential liability or reputational damage or otherwise have an adverse effect on our financial results. Item 1B. Unresolved Staff Comments None.
Any of these occurrences could disrupt our business, resulting in potential liability or reputational damage or otherwise have an adverse effect on our financial results. Item 1B. Unresolved Staff Comments None. 48
We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies.
We also own and lease a fleet of railcars, the operation of which is subject to the regulatory 33 jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies.
The payment of the liquidation preference could result in common unitholders not receiving any consideration if we were to 41 liquidate, dissolve or wind up, either voluntarily or involuntarily.
The payment of the liquidation preference could result in common unitholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or involuntarily.
Because we expect to be treated as a partnership for United States federal income tax purposes, our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us.
Because we expect to be treated as a partnership for federal income tax purposes, our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us.
The warrants will not participate in cash distributions. Tax Risks to Our Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes.
The warrants will not participate in cash distributions. 41 Tax Risks to Our Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes.
Risk Factor Summary Risks Related to Liquidity and Financing • We may not have sufficient cash, which depends on cash flow rather than profitability, to enable us to fund our operations, repay indebtedness or pay distributions. • Our substantial indebtedness and restrictions contained in our debt and preferred unit agreements may limit our flexibility to obtain financing to pursue other business opportunities and restrict our current and future operations. • Increasing interest rates could impact our financing costs, common unit price, distributions on our Class B Preferred Units (as defined herein) and Class C Preferred Units (as defined herein) and our ability to issue equity and incur debt.
Risk Factor Summary Risks Related to Liquidity and Financing • We may not have sufficient cash, which depends on cash flow rather than profitability, to enable us to fund our operations, repay indebtedness or pay distributions. • Our substantial indebtedness and restrictions contained in our debt and preferred unit agreements may limit our flexibility to obtain financing to pursue other business opportunities and restrict our current and future operations. • Increasing interest rates could impact our financing costs, common unit price, distributions on our Class B Preferred Units (as defined herein) and Class C Preferred Units (as defined herein) and our ability to issue equity and incur debt. • Failure of our banking institutions.
Weather conditions have a significant impact on the demand for propane for heating and agriculture purposes. Accordingly, our sales volumes of propane are highest during the five-month winter-heating season of November through March and are directly affected by the temperatures during these months.
Weather conditions have a significant impact on the demand for propane for heating and agriculture purposes. Accordingly, our sales volumes of propane are highest during the winter-heating season of November through March and are directly affected by the temperatures during these months.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement.
If at any time our GP and its affiliates own more than 80% of the common units, our GP will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement.
It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels.
It is possible, however, that our GP could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels.
For example, from time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships, including as a result of any fundamental tax reform.
For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect the tax treatment of publicly traded partnerships, including as a result of any fundamental tax reform.
Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand.
Furthermore, since certain executive officers and directors of our GP are executive officers or directors of affiliates of our GP, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our GP, on the one hand, and us and our unitholders, on the other hand.
This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner.
This entitles our GP to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner.
Furthermore, our partnership agreement does not restrict the ability of the members of the NGL Energy GP Investor Group to transfer all or a portion of their ownership interest in our general partner to a third party.
Furthermore, our Partnership Agreement does not restrict the ability of the members of the NGL Energy GP Investor Group to transfer all or a portion of their ownership interest in our GP to a third party.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our GP or its board of directors.
Risks Related to Our Partnership Structure and in an Investment in Us • Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders. • Conflicts of interest by our general partner and its affiliates. • Our unitholders have limited voting rights. • Control of our general partner or the IDRs (as defined herein) may be transferred to a third party. • Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price. • Our partnership agreement requires that we distribute all of our available cash. • We may issue additional units without the approval of our unitholders. • Our general partner may elect to cause us to issue common units while also maintaining its general partner interest in connection with a resetting of the target distribution levels related to its IDRs. • Our unitholders liability may not be limited if a court finds that unitholder action constitutes control of our business. • Our unitholders may have liability to repay distributions that were wrongfully distributed to them. • The Preferred Units (as defined herein) give the holders thereof liquidation and distribution preferences over our common unitholders. • The issuance of common units upon exercise of certain warrants would cause dilution to existing common unitholders.
Risks Related to Our Partnership Structure and in an Investment in Us • Our amended and restated limited partnership agreement (the “Partnership Agreement”) limits the fiduciary duties of our GP to our unitholders and restricts the remedies available to our unitholders. • Conflicts of interest by our GP and its affiliates. • Our unitholders have limited voting rights. • Control of our GP or the IDRs (as defined herein) may be transferred to a third party. • Our GP has a limited call right that may require our unitholders to sell their common units at an undesirable time or price. • Our Partnership Agreement requires that we distribute all of our available cash. • We may issue additional units without the approval of our unitholders. 22 • Our GP may elect to cause us to issue common units while also maintaining its GP interest in connection with a resetting of the target distribution levels related to its IDRs. • Our unitholders liability may not be limited if a court finds that unitholder action constitutes control of our business. • Our unitholders may have liability to repay distributions that were wrongfully distributed to them. • The Preferred Units (as defined herein) give the holders thereof liquidation and distribution preferences over our common unitholders. • The issuance of common units upon exercise of certain warrants would cause dilution to existing common unitholders.
As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders (see “– Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty ,” above).
As a result of these conflicts, our GP may favor its own interests and the interests of its affiliates over the interests of our unitholders (see “– Our Partnership Agreement limits the fiduciary duties of our GP to our unitholders and restricts the remedies available to our unitholders for actions taken by our GP that might otherwise be breaches of fiduciary duty ,” above).
Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Furthermore, if our unitholders are dissatisfied with the performance of our GP, they will have limited ability to remove our GP. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties to our unitholders, and they may favor their own interests to the detriment of us and our unitholders.
By purchasing a common unit, a common unitholder will become bound by the provisions of our Partnership Agreement, including the provisions described above. Our GP and its affiliates have conflicts of interest with us and limited fiduciary duties to our unitholders, and they may favor their own interests to the detriment of us and our unitholders.
In addition, the actual amount of cash we will have available to fund our operations, repay indebtedness or pay distributions also depends on other factors, some of which are beyond our control, including: • fluctuations in working capital needs; • the level of capital expenditures we make; • the cost of acquisitions, if any; • restrictions contained in the ABL Facility and the indentures governing our outstanding 7.5% senior notes due 2023, 6.125% senior notes due 2025, 7.5% senior notes due 2026 and 2026 Senior Secured Notes (collectively, the “Indentures”) and other debt service requirements; • restrictions contained in the agreements relating to our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”), 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and 9.00% Class D Preferred Units (“Class D Preferred Units”) (collectively the “Preferred Units”); • our ability to borrow funds and access capital markets; • the amount, if any, of cash reserves established by our general partner; and • other business risks discussed in this Annual Report that may affect our cash levels.
In addition, the actual amount of cash we will have available to fund our operations, repay indebtedness or pay distributions also depends on other factors, some of which are beyond our control, including: • fluctuations in working capital needs; • the level of capital expenditures we make; • the cost of acquisitions, if any; • restrictions contained in the ABL Facility and the indentures governing our outstanding 6.125% senior unsecured notes due 2025, 7.5% senior unsecured notes due 2026 and 2026 Senior Secured Notes (collectively, the “Indentures”); • restrictions contained in the agreements relating to our 9.00% Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”), 9.625% Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class C Preferred Units”) and 9.00% Class D Preferred Units (“Class D Preferred Units”) (collectively the “Preferred Units”); • our ability to borrow funds and access capital markets; • the amount, if any, of cash reserves established by our GP; and • other business risks discussed in this Annual Report that may affect our cash levels.
We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances.
We will generally have the ability to shift any such tax liability to our GP and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our GP. Our methodology may be viewed as understating the value of our assets.
This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our general partner or its directors.
This may create actual and potential conflicts of interest between us and affiliates of our GP and result in less than favorable treatment of us and our unitholders. Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our GP or its directors.
These approval rights supplement the existing approval rights in our Amended and Restated Partnership Agreement for the Class D Preferred Majority. They became effective upon the closing of the transaction and will remain in effect until we are no longer in arrears on the Class D Preferred Unit distributions.
These approval rights supplement the existing approval rights in our Partnership Agreement for the Class D Preferred Majority. They became effective upon the closing of the transaction and will remain in effect until we are no longer in arrears 25 on the Class D Preferred Unit distributions.
Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our GP because the costs will reduce our cash available for distribution.
Risks Related to Liquidity and Financing We may not have sufficient cash to enable us to fund our operations, repay indebtedness or pay distributions to our unitholders following the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.
Risks Related to Liquidity and Financing We may not have sufficient cash to enable us to fund our operations, repay indebtedness or pay distributions to our unitholders following the establishment of cash reserves by our GP and the payment of costs and expenses, including reimbursement of expenses to our GP.
The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. The IDRs of our general partner may be transferred to a third party.
The new owner of our GP would then be in a position to replace the board of directors and officers of our GP with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. The IDRs of our GP may be transferred to a third party.
The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations.
The board of directors of our GP is chosen entirely by its members and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations.
The IRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.
The IRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the GP and certain of our unitholders.
Risks Related to Our Partnership Structure and in an Investment in Us Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty.
Risks Related to Our Partnership Structure and in an Investment in Us Our Partnership Agreement limits the fiduciary duties of our GP to our unitholders and restricts the remedies available to our unitholders for actions taken by our GP that might otherwise be breaches of fiduciary duty.
The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters.
The number of common units to be issued to our GP will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our GP on the IDRs in the prior two quarters.
As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law; 37 • permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner.
As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law; • permits our GP to make a number of decisions in its individual capacity, as opposed to in its capacity as our GP.
As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner interests to our general partner in connection with resetting the target distribution levels.
As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common 40 unitholders would have otherwise received had we not issued new common units and GP interests to our GP in connection with resetting the target distribution levels.
We anticipate that our general partner would exercise this reset right to facilitate acquisitions or organic growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion.
We anticipate that our GP would exercise this reset right to facilitate acquisitions or organic growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion.
The Class D Preferred Consent modifies certain voting and approval rights granted to the Class D Preferred Majority under our Amended and Restated Partnership Agreement.
The Class D Preferred Consent modifies certain voting and approval rights granted to the Class D Preferred Majority under our Partnership Agreement.
Recently, the Federal Reserve announced that it has applied to join the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
The U.S. Federal Reserve announced that it has applied to join the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us.
Our Partnership Agreement provides that our GP will be restricted from engaging in any business activities other than acting as our GP and those activities incidental to its ownership interest in us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners.
Pursuant to the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our GP or any of its affiliates, including its executive officers, directors and owners.
Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
Following a reset election by our GP, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
Our barge transportation operations are subject to the Jones Act, a federal law generally restricting marine transportation in the United States to vessels built and registered in the United States, and manned/owned by United States citizens, as well as setting forth the rules and regulations of the United States Coast Guard.
Barge transportation is subject to the Jones Act, a federal law generally restricting marine transportation in the United States to vessels built and registered in the United States, and manned/owned by United States citizens, as well as setting forth the rules and regulations of the United States Coast Guard.
We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
We have adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our GP and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
In addition, the distribution rates on our Class B Preferred Units and Class C Preferred Units convert from fixed rates to floating rates, beginning on and after July 1, 2022, and on and after April 15, 2024, respectively. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates.
In addition, the distribution rates on our Class C Preferred Units convert from fixed rates to floating rates beginning on and after April 15, 2024. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates.
In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders.
In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the GP, which may be unfavorable to such unitholders.
Non-compliance with any of these regulations could result in increased costs related to the transportation of our products and could have an adverse effect on our business. In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials.
Non-compliance with any of these regulations could result in increased costs related to the transportation of our products. In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units.
If our GP elects to reset the target distribution levels, it will be entitled to receive a number of common units.
Recently, in December 2021, as a result of increased seismic activity, the Texas Railroad Commission suspended all deep oil and gas produced water injection in an area which spans approximately 100 square miles in Midland and Ector counties, which directly impacted one of our idled disposal wells.
In December 2021, as a result of increased seismic activity, the Texas Railroad Commission suspended all deep oil and gas produced water injection in an area which spans approximately 100 square miles in Midland and Ector counties, which directly impacted one of our idled disposal wells. This idled well was subsequently plugged and abandoned.
Our general partner may transfer its IDRs to a third party at any time without the consent of our unitholders.
Our GP may transfer its IDRs to a third party at any time without the consent of our unitholders.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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For information related to legal proceedings, see the discussion under the captions “ Legal Contingencies ” and “ Environmental Matters ” in Note 8 and “Third-party Bankruptcy” in Note 17 to our consolidated financial statements included in this Annual Report, which is incorporated by reference into this Item 3. Item 4. Mine Safety Disclosures Not applicable. 49 PART II
For information related to legal proceedings, see the discussion under the caption “ Legal Contingencies ” in Note 8 to our consolidated financial statements included in this Annual Report, which is incorporated by reference into this Item 3.
Added
Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe will exceed a specified threshold. Pursuant to SEC regulations, we use a threshold of $1 million for such proceedings.
Added
We believe that such threshold is reasonably designed to result in disclosure of environmental proceedings that are material to our business or financial condition. Item 4. Mine Safety Disclosures Not applicable. 49 PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Marginal Percentage Interest In Distributions Total Quarterly Distribution Per Unit Limited Partner Unitholders General Partner (1) Minimum quarterly distribution $ 0.337500 99.9 % 0.1 % First target distribution above $ 0.337500 up to $ 0.388125 99.9 % 0.1 % Second target distribution above $ 0.388125 up to $ 0.421875 86.9 % 13.1 % Third target distribution above $ 0.421875 up to $ 0.506250 76.9 % 23.1 % Thereafter above $ 0.506250 51.9 % 48.1 % (1) The maximum distribution of 48.1% does not include distributions that our general partner may receive on common units that it owns. 50 Restrictions on the Payment of Distributions As described in Note 7 to our consolidated financial statements included in this Annual Report, the indenture to the 2026 Senior Secured Notes restricts us from paying distributions until our total leverage ratio (as defined in the indenture) for the most recently ended four full fiscal quarters at the time of the distribution is not greater than 4.75 to 1.00.
Marginal Percentage Interest In Distributions Total Quarterly Distribution Per Unit Limited Partner Unitholders General Partner (1) Minimum quarterly distribution $ 0.337500 99.9 % 0.1 % First target distribution above $ 0.337500 up to $ 0.388125 99.9 % 0.1 % Second target distribution above $ 0.388125 up to $ 0.421875 86.9 % 13.1 % Third target distribution above $ 0.421875 up to $ 0.506250 76.9 % 23.1 % Thereafter above $ 0.506250 51.9 % 48.1 % (1) The maximum distribution of 48.1% does not include distributions that our GP may receive on common units that it owns. 50 Restrictions on the Payment of Distributions As described in Note 7 to our consolidated financial statements included in this Annual Report, the indenture to the 2026 Senior Secured Notes restricts us from paying distributions until our total leverage ratio (as defined in the indenture) for the most recently ended four full fiscal quarters at the time of the distribution is not greater than 4.75 to 1.00.
General Partner Interest Our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.
General Partner Interest Our GP is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our GP has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% GP interest.
These distributions are referred to as “incentive distributions” or “IDRs.” Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest. The following table illustrates the percentage allocations of available cash from operating surplus between our limited partner unitholders and our general partner based on the specified target distribution levels.
These distributions are referred to as “incentive distributions” or “IDRs.” Our GP currently holds the IDRs, but may transfer these rights separately from its GP interest. The following table illustrates the percentage allocations of available cash from operating surplus between our limited partner unitholders and our GP based on the specified target distribution levels.
The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of our general partner and our limited partner unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any.
The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of our GP and our limited partner unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any.
Available cash for any quarter generally consists of all cash on hand at the end of that quarter, less the amount of cash reserves established by our general partner, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
Available cash for any quarter generally consists of all cash on hand at the end of that quarter, less the amount of cash reserves established by our GP, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our GP for any one or more of the next four quarters.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Market Information Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NGL.” At June 1, 2022, there were approximately 100 common unitholders of record which does not include unitholders for whom common units may be held in “street name.” Cash Distribution Policy Available Cash Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders as of the record date.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Market Information Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NGL.” At May 26, 2023, there were approximately 100 common unitholders of record which does not include unitholders for whom common units may be held in “street name.” Cash Distribution Policy Available Cash Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our Partnership Agreement) to unitholders as of the record date.
The board of directors of our general partner decided to temporarily suspend all distributions in order to deleverage our balance sheet until we meet the 4.75 to 1.00 total leverage ratio set forth within the indenture of the 2026 Senior Secured Notes, as discussed further above.
The board of directors of our GP decided to temporarily suspend all distributions in order to deleverage our balance sheet until we meet the 4.75 to 1.00 total leverage ratio set forth within the indenture of the 2026 Senior Secured Notes, as discussed further above.
The percentage interests shown for our limited partner unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
The percentage interests shown for our limited partner unitholders and our GP for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Our general partner’s interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.
Our GP’s interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon a reset of the IDRs) and our GP does not contribute a proportionate amount of capital to us to maintain its 0.1% GP interest.
The percentage interests set forth below for our general partner include its 0.1% general partner interest, and assume that our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs.
The percentage interests set forth below for our GP include its 0.1% GP interest, and assume that our GP has contributed any additional capital necessary to maintain its 0.1% GP interest and has not transferred its IDRs.
As of March 31, 2022, we owned 8.69% of our general partner. Incentive Distribution Rights The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners.
As of March 31, 2023, we owned 8.69% of our GP. Incentive Distribution Rights The GP will also receive, in addition to distributions on its 0.1% GP interest, additional distributions based on the level of distributions to the limited partners.
Securities Authorized for Issuance Under Equity Compensation Plans In connection with the completion of our initial public offering, our general partner adopted the NGL Energy Partners LP Long-Term Incentive Plan.
These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units. Securities Authorized for Issuance Under Equity Compensation Plans In connection with the completion of our initial public offering, our GP adopted the NGL Energy Partners LP Long-Term Incentive Plan.
Common Unit Repurchase Program The following table summarizes the repurchase of common units during the three months ended March 31, 2022: Period Total Number of Common Units Purchased Average Price Paid Per Common Unit January 1-31, 2022 — $ — February 1-28, 2022 35,868 $ 2.00 March 1-31, 2022 — $ — 35,868 The common units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units.
Common Unit Repurchases During February 2023, 23,874 common units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are deeming the surrenders to be “repurchases.” The average price paid per common unit was $2.40.
Added
The board of directors of our GP expects to evaluate the reinstatement of the common unit and all preferred unit distributions in due course, taking into account a number of important factors, including our leverage, liquidity, the sustainability of cash flows, upcoming debt maturities, capital expenditures and the overall performance of our businesses.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

156 edited+53 added−52 removed118 unchanged
Seismic Activity The subsurface injection of produced water for disposal has been associated with recent induced seismic events in Texas and New Mexico. While these events have been relatively low magnitude, industry and relevant state regulators are, nevertheless, taking proactive measures to attempt to prevent similar induced seismic events.
Seismic Activity The subsurface injection of produced water for disposal has been associated with recent induced seismic events in Texas and New Mexico. While these events have been of relatively low magnitude, industry and relevant state regulators are, nevertheless, taking proactive measures to attempt to prevent similar induced seismic events.
Refined Products Revenues and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due to an increase in refined products prices. This was offset by a reduction in volumes sold due to tighter supply in the market.
Refined Products Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due to an increase in refined products prices. This was offset by a reduction in volumes sold due to tighter supply in the market.
Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales were due to higher commodity prices. The increase in propane prices was the result of lower domestic inventories and a strong export market due to the increase in international prices.
Propane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due to higher commodity prices. The increase in propane prices was the result of lower domestic inventories and a strong export market due to the increase in international prices.
Our margin was also impacted by lower product allocation from certain suppliers and lower storage utilization due to decreased demand and the backwardated market structure. Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales were due primarily to higher commodity prices.
Our margin was also impacted by lower product allocation from certain suppliers and lower storage utilization due to decreased demand and the backwardated market structure. Butane Sales and Cost of Sales-Excluding Impact of Derivatives. The increases in revenues and cost of sales, excluding the impact of derivatives, were due primarily to higher commodity prices.
EBITDA and Adjusted EBITDA should not be considered alternatives to net loss, loss from continuing operations before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations.
EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss), income (loss) from continuing operations before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations.
During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report) and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report). 59 Liquids Logistics The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands, except per gallon amounts) Refined products sales: Revenues-excluding impact of derivatives (1) $ 1,899,898 $ 1,124,087 $ 775,811 Cost of sales-excluding impact of derivatives 1,876,728 1,108,493 768,235 Derivative loss 2,907 930 1,977 Product margin 20,263 14,664 5,599 Propane sales: Revenues (1) 1,325,941 1,027,582 298,359 Cost of sales-excluding impact of derivatives 1,313,765 949,402 364,363 Derivative (gain) loss (20,519) 10,994 (31,513) Product margin 32,695 67,186 (34,491) Butane sales: Revenues (1) 863,348 517,857 345,491 Cost of sales-excluding impact of derivatives 794,180 469,394 324,786 Derivative loss 18,690 22,353 (3,663) Product margin 50,478 26,110 24,368 Other product sales: Revenues-excluding impact of derivatives (1) 791,125 446,744 344,381 Cost of sales-excluding impact of derivatives 748,392 424,191 324,201 Derivative loss (gain) 15,812 (7,078) 22,890 Product margin 26,921 29,631 (2,710) Service revenues: Revenues (1) 16,200 33,915 (17,715) Cost of sales 1,404 4,751 (3,347) Product margin 14,796 29,164 (14,368) Expenses: Operating expenses 55,907 55,273 634 General and administrative expenses 7,166 8,507 (1,341) Depreciation and amortization expense 18,714 29,184 (10,470) Loss on disposal or impairment of assets, net 71,807 3,350 68,457 Total expenses 153,594 96,314 57,280 Segment operating (loss) income $ (8,441) $ 70,441 $ (78,882) 60 Year Ended March 31, 2022 2021 Change (in thousands, except per gallon amounts) Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3) 156,219 427,975 (271,756) Refined products sold (gallons) 776,797 834,717 (57,920) Refined products sold ($/gallon) $ 2.446 $ 1.347 $ 1.099 Cost per refined products sold ($/gallon) (4) $ 2.416 $ 1.328 $ 1.088 Refined products product margin ($/gallon) (4) $ 0.030 $ 0.019 $ 0.011 Refined products inventory (gallons) (2) 1,090 1,223 (133) Propane sold (gallons) 1,034,706 1,364,224 (329,518) Propane sold ($/gallon) $ 1.281 $ 0.753 $ 0.528 Cost per propane sold ($/gallon) (4) $ 1.270 $ 0.696 $ 0.574 Propane product margin ($/gallon) (4) $ 0.011 $ 0.057 $ (0.046) Propane inventory (gallons) (2) 37,719 51,026 (13,307) Propane storage capacity leased to third parties (gallons) (2)(3) — 53,947 (53,947) Butane sold (gallons) 588,032 655,256 (67,224) Butane sold ($/gallon) $ 1.468 $ 0.790 $ 0.678 Cost per butane sold ($/gallon) (4) $ 1.351 $ 0.716 $ 0.635 Butane product margin ($/gallon) (4) $ 0.117 $ 0.074 $ 0.043 Butane inventory (gallons) (2) 19,825 20,066 (241) Butane storage capacity leased to third parties (gallons) (2)(3) — 56,700 (56,700) Other products sold (gallons) 376,906 471,245 (94,339) Other products sold ($/gallon) $ 2.099 $ 0.948 $ 1.151 Cost per other products sold ($/gallon) (4) $ 1.986 $ 0.900 $ 1.086 Other products product margin ($/gallon) (4) $ 0.113 $ 0.048 $ 0.065 Other products inventory (gallons) (2) 18,614 19,195 (581) (1) Revenues include $1.3 million and $6.1 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
During the year ended March 31, 2021, we recorded a net loss of $145.8 million for the impairment of an intangible asset, related to a rejected transportation agreement with Extraction (see Note 17 to our consolidated financial statements included in this Annual Report) and a net loss of $237.8 million for the impairment of goodwill (see Note 5 to our consolidated financial statements included in this Annual Report). 68 Liquids Logistics The following table summarizes the operating results of our Liquids Logistics segment for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands, except per gallon amounts) Refined products sales: Revenues-excluding impact of derivatives (1) $ 1,899,898 $ 1,124,087 $ 775,811 Cost of sales-excluding impact of derivatives 1,876,728 1,108,493 768,235 Derivative loss 2,907 930 1,977 Product margin 20,263 14,664 5,599 Propane sales: Revenues (1) 1,325,941 1,027,582 298,359 Cost of sales-excluding impact of derivatives 1,313,765 949,402 364,363 Derivative (gain) loss (20,519) 10,994 (31,513) Product margin 32,695 67,186 (34,491) Butane sales: Revenues (1) 863,348 517,857 345,491 Cost of sales-excluding impact of derivatives 794,180 469,394 324,786 Derivative loss 18,690 22,353 (3,663) Product margin 50,478 26,110 24,368 Other product sales: Revenues-excluding impact of derivatives (1) 791,125 446,744 344,381 Cost of sales-excluding impact of derivatives 748,392 424,191 324,201 Derivative loss (gain) 15,812 (7,078) 22,890 Product margin 26,921 29,631 (2,710) Service revenues: Revenues (1) 16,200 33,915 (17,715) Cost of sales 1,404 4,751 (3,347) Product margin 14,796 29,164 (14,368) Expenses: Operating expenses 55,907 55,273 634 General and administrative expenses 7,166 8,507 (1,341) Depreciation and amortization expense 18,714 29,184 (10,470) Loss on disposal or impairment of assets, net 71,807 3,350 68,457 Total expenses 153,594 96,314 57,280 Segment operating (loss) income $ (8,441) $ 70,441 $ (78,882) 69 Year Ended March 31, 2022 2021 Change (in thousands, except per gallon amounts) Natural gas liquids and refined products storage capacity - owned and leased (gallons) (2)(3) 156,219 427,975 (271,756) Refined products sold (gallons) 776,797 834,717 (57,920) Refined products sold ($/gallon) $ 2.446 $ 1.347 $ 1.099 Cost per refined products sold ($/gallon) (4) $ 2.416 $ 1.328 $ 1.088 Refined products product margin ($/gallon) (4) $ 0.030 $ 0.019 $ 0.011 Refined products inventory (gallons) (2) 1,090 1,223 (133) Propane sold (gallons) 1,034,706 1,364,224 (329,518) Propane sold ($/gallon) $ 1.281 $ 0.753 $ 0.528 Cost per propane sold ($/gallon) (4) $ 1.270 $ 0.696 $ 0.574 Propane product margin ($/gallon) (4) $ 0.011 $ 0.057 $ (0.046) Propane inventory (gallons) (2) 37,719 51,026 (13,307) Propane storage capacity leased to third parties (gallons) (2)(3) — 53,947 (53,947) Butane sold (gallons) 588,032 655,256 (67,224) Butane sold ($/gallon) $ 1.468 $ 0.790 $ 0.678 Cost per butane sold ($/gallon) (4) $ 1.351 $ 0.716 $ 0.635 Butane product margin ($/gallon) (4) $ 0.117 $ 0.074 $ 0.043 Butane inventory (gallons) (2) 19,825 20,066 (241) Butane storage capacity leased to third parties (gallons) (2)(3) — 56,700 (56,700) Other products sold (gallons) 376,906 471,245 (94,339) Other products sold ($/gallon) $ 2.099 $ 0.948 $ 1.151 Cost per other products sold ($/gallon) (4) $ 1.986 $ 0.900 $ 1.086 Other products product margin ($/gallon) (4) $ 0.113 $ 0.048 $ 0.065 Other products inventory (gallons) (2) 18,614 19,195 (581) (1) Revenues include $1.3 million and $6.1 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
The guarantee of our Senior Unsecured Notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and 83 discharge of the indentures governing our Senior Unsecured Notes, the designation of such Guarantor Subsidiary as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our Senior Unsecured Notes, the release of such Guarantor Subsidiary from its guarantee under our revolving credit facility, the liquidation or dissolution of such Guarantor Subsidiary or upon the consolidation, merger or transfer of all assets of the Guarantor Subsidiary to us or another Guarantor Subsidiary in which the Guarantor Subsidiary dissolves or ceases to exist (collectively, the “Releases”).
The guarantee of our Senior Unsecured Notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our Senior Unsecured Notes, the designation of such Guarantor Subsidiary as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our Senior Unsecured Notes, the release of such Guarantor Subsidiary from its guarantee under our revolving credit facility, the liquidation or dissolution of such Guarantor Subsidiary or upon the consolidation, merger or transfer of all assets of the Guarantor Subsidiary to us or another Guarantor Subsidiary in which the Guarantor Subsidiary dissolves or ceases to exist (collectively, the “Releases”).
The decrease in other expense, net of $38.8 million during the year ended March 31, 2022 was due primarily to a $40.0 million fee paid to the holders of the 9.00% Class D Preferred Units (“Class D Preferred Units”) during the year ended March 31, 2021 to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the $500.0 million asset-based revolving credit facility (“ABL Facility”) (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.
The decrease in other expense, net of $38.8 million during the year ended March 31, 2022 was due primarily to a $40.0 million fee paid to the holders of the 9.00% Class D Preferred Units (“Class D Preferred Units”) during the year ended March 31, 2021 to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the asset-based revolving credit facility (“ABL Facility”) (see Note 12 to our consolidated financial statements included in this Annual Report), partially offset by proceeds received from a litigation settlement during the year ended March 31, 2021.
In our Liquids Logistics segment, we typically experience operating losses or lower operating income during our first and second quarters, or the six months ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming butane blending and heating seasons, which generally begin in late fall, under normal demand conditions, and run 81 through February or March.
In our Liquids Logistics segment, we typically experience operating losses or lower operating income during our first and second quarters, or the six months ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming butane blending and heating seasons, which generally begin in late fall, under normal demand conditions, and run through February or March.
The amounts for the year ended March 31, 2022 includes net realized losses of $83.5 million and unrealized gains of $45.0 million associated with derivative instruments related to our hedge of the CMA Differential Roll, defined and discussed below under “Non-GAAP Financial Measures.” Our cost of sales during the year ended March 31, 2021 included $25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives.
The amounts for the year ended March 31, 2022 includes net realized losses of $83.5 million and net unrealized gains of $45.0 67 million associated with derivative instruments related to our hedge of the CMA Differential Roll, defined and discussed below under “Non-GAAP Financial Measures.” Our cost of sales during the year ended March 31, 2021 included $25.9 million of net realized losses on derivatives and $23.4 million of net unrealized losses on derivatives.
See further discussion of our cash distribution policy in Part II, Item 5–“Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” included in this Annual Report. Contractual Obligations Our contractual obligations primarily consist of purchase commitments, outstanding debt principal and interest obligations, operating lease obligations, pipeline commitments, asset retirement obligations and other commitments.
See further discussion of our cash distribution policy in Part II, Item 5–“Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” included in this Annual Report. Contractual Obligations Our contractual obligations primarily consist of purchase commitments, outstanding debt principal and interest obligations, lease obligations, pipeline commitments, asset retirement obligations and other commitments.
See Note 14 to our consolidated financial statements included in this Annual Report for a further discussion of our revenue recognition policies. Asset Retirement Obligations We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired.
See Note 14 to our consolidated financial statements included in this Annual Report for a further discussion of our revenue recognition policies. 84 Asset Retirement Obligations We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement or removal activities when the assets are retired.
During the year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million due to the write down in value of a terminal we have ceased operating. 62 Corporate and Other The operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands) Other revenues: Revenues $ — $ 1,255 $ (1,255) Cost of sales — 1,816 (1,816) Loss — (561) 561 Expenses: General and administrative expenses 41,491 47,520 (6,029) Depreciation and amortization expense 6,959 5,062 1,897 (Gain) loss on disposal or impairment of assets, net (50) 11,001 (11,051) Total expenses 48,400 63,583 (15,183) Operating loss $ (48,400) $ (64,144) $ 15,744 General and Administrative Expenses .
During the year ended March 31, 2021, we recorded an impairment loss of approximately $3.3 million due to the write down in value of a terminal we have ceased operating. 71 Corporate and Other The operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands) Other revenues: Revenues $ — $ 1,255 $ (1,255) Cost of sales — 1,816 (1,816) Loss — (561) 561 Expenses: General and administrative expenses 41,491 47,520 (6,029) Depreciation and amortization expense 6,959 5,062 1,897 (Gain) loss on disposal or impairment of assets, net (50) 11,001 (11,051) Total expenses 48,400 63,583 (15,183) Operating loss $ (48,400) $ (64,144) $ 15,744 General and Administrative Expenses .
During the year ended March 31, 2022, there was a decrease in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers, resulting in a decrease to the expected future royalty payment.
During the year ended March 31, 2022, there was a decrease in expense for the valuation of our contingent consideration 57 liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers, resulting in a decrease to the expected future royalty payment.
None of the assets of the Guarantor Subsidiaries (other than the investments in non-guarantor subsidiaries) are restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended. The rights of holders of our Senior Unsecured Notes against the Guarantor Subsidiaries may be limited under the U.S.
None of the assets of the Guarantor Subsidiaries (other than the investments in non-guarantor subsidiaries) are restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended. 82 The rights of holders of our Senior Unsecured Notes against the Guarantor Subsidiaries may be limited under the U.S.
A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities.
A long-lived asset group is considered 83 impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities.
Additionally, an increase in the number of wells completed 56 in our area of operations during the period with increased flowback activity resulted in higher skim oil volumes per barrel of produced water processed. Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers’ completion activities.
Additionally, an increase in the number of wells completed in our area of operations during the period with increased flowback activity resulted in higher skim oil volumes per barrel of produced water processed. Recycled Water Revenues. Revenue from recycled water includes the sale of produced water and recycled water for use in our customers’ completion activities.
Most of these retirement obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. These estimates and assumptions are very subjective and can vary 86 over time.
Most of these retirement obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. These estimates and assumptions are very subjective and can vary over time.
During the year ended March 31, 2021, we sold certain permits, land and a saltwater disposal facility to a third-party (see Note 17 to our consolidated financial statements included in this Annual Report). Seasonality Seasonality impacts our Liquids Logistics segment.
During the year ended March 31, 2021, we sold certain permits, land and a saltwater disposal facility to a third-party (see Note 17 to our consolidated financial statements included in this Annual Report). 55 Seasonality Seasonality impacts our Liquids Logistics segment.
Consequently, for our Liquids Logistics segment, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of our fiscal year. We generally 55 borrow under the revolving credit facility to supplement our operating cash flows during the periods in which we are building inventory.
Consequently, for our Liquids Logistics segment, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of our fiscal year. We generally borrow under the revolving credit facility to supplement our operating cash flows during the periods in which we are building inventory.
Our activities in this segment are underpinned 52 by long-term, fixed fee contracts and acreage dedications, some of which contain minimum volume commitments with leading oil and gas companies including large, investment grade producer customers.
Our activities in this segment are underpinned by long-term, fixed fee contracts and acreage dedications, some of which contain minimum volume commitments with leading oil and gas companies including large, investment grade producer customers.
The increase was due primarily to increasing demand for water to be used in completions, driven by an increase in drilling and completion activity primarily in the Delaware Basin, and our customers transition from brackish non-potable water to recycled water. Other Revenues.
The increase was due primarily to increasing demand for water to be used in completions, driven by an increase in drilling and completion activity primarily in the Delaware Basin, and our customers transition from brackish non-potable water to recycled water. 65 Other Revenues.
The decrease was offset by an increase in utility expenses due to Grand Mesa increased utility rates, as well as increased business insurance due to policy rate increases for the year ended March 31, 2022. Depreciation and Amortization Expense.
The decrease was offset by an increase in utility expenses due to Grand Mesa Pipeline increased utility rates, as well as increased business insurance due to policy rate increases for the year ended March 31, 2022. Depreciation and Amortization Expense.
We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the Midland Basin in Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas.
We operate in a number of the most prolific crude oil and natural gas producing areas in the United States including the Delaware Basin in New Mexico and Texas, the DJ Basin in Colorado and the Eagle Ford Basin in Texas.
This increase was partially offset by the termination of the term credit agreement as well as the repurchases of a portion of our senior unsecured notes to mature in 2023 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report). 63 Gain (Loss) on Early Extinguishment of Liabilities, Net Gain on early extinguishment of liabilities, net was $1.8 million during the year ended March 31, 2022, compared to a loss on early extinguishment of liabilities, net of $16.7 million during the year ended March 31, 2021.
This increase was partially offset by the termination of the term credit agreement as well as the repurchases of a portion of our senior unsecured notes to mature in 2023 and 2026 (see Note 7 to our consolidated financial statements included in this Annual Report). 72 Gain (Loss) on Early Extinguishment of Liabilities, Net Gain on early extinguishment of liabilities, net was $1.8 million during the year ended March 31, 2022, compared to a loss on early extinguishment of liabilities, net of $16.7 million during the year ended March 31, 2021.
Acquisitions and Dispositions We completed several acquisitions and dispositions during the years ended March 31, 2022 and 2021. These transactions impact the comparability of our results of operations between our current and prior fiscal years.
Acquisitions and Dispositions We completed several acquisitions and dispositions during the years ended March 31, 2023, 2022 and 2021. These transactions impact the comparability of our results of operations between our current and prior fiscal years.
Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories.
Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories and decreases in natural gas liquids prices typically increase our 80 operating cash flows due to lower cash requirements to fund increases in inventories.
This was partially offset by lower propane volumes sold driven by reduced 61 demand due to warmer than normal autumn temperatures, which resulted in lower product demand for crop drying, unusually warm weather during the early winter months and reduced volumes due to the loss of two producer services agreements. Propane Derivative (Gain) Loss.
This was partially offset by lower propane volumes sold driven by reduced demand due to warmer than normal autumn temperatures, which resulted in 70 lower product demand for crop drying, unusually warm weather during the early winter months and reduced volumes due to the loss of two producer services agreements. Propane Derivative (Gain) Loss .
Guarantor Summarized Financial Information NGL Energy Partners LP (parent) and NGL Energy Finance Corp. are co-issuers of the Senior Unsecured Notes (see Note 7 to our consolidated financial statements included in this Annual Report). Certain of our wholly owned subsidiaries (“Guarantor Subsidiaries”) have, jointly and severally, fully and unconditionally guaranteed the Senior Unsecured Notes.
Supplemental Guarantor Information NGL Energy Partners LP (parent) and NGL Energy Finance Corp. are co-issuers of the Senior Unsecured Notes (see Note 7 to our consolidated financial statements included in this Annual Report). Certain of our wholly owned subsidiaries (“Guarantor Subsidiaries”) have, jointly and severally, fully and unconditionally guaranteed the Senior Unsecured Notes.
During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.
During the year ended March 31, 2023, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment.
We expect our primary cash outflows to be related to purchases of inventory, capital expenditures, interest and repayment of debt maturities. On February 4, 2021, we closed on our $2.05 billion 2026 Senior Secured Notes offering and entered into a $500.0 million ABL Facility.
We expect our primary cash outflows to be related to capital expenditures, interest and repayment of debt maturities. On February 4, 2021, we closed on our $2.05 billion 2026 Senior Secured Notes offering and entered into a $500.0 million ABL Facility.
See “–Liquidity, Sources of Capital and Capital Resource Activities–Cash Flows.” Subsequent Events See Note 19 to our consolidated financial statements included in this Annual Report for a discussion of transactions that occurred subsequent to March 31, 2022.
See “–Liquidity, Sources of Capital and Capital Resource Activities–Cash Flows.” Subsequent Events See Note 19 to our consolidated financial statements included in this Annual Report for a discussion of transactions that occurred subsequent to March 31, 2023.
Our derivatives of other products included $15.8 million of net realized losses on derivatives and there are no unrealized gains or losses on derivatives during the year ended March 31, 2022.
Our derivatives of other products during the year ended March 31, 2022 included $15.8 million of net realized losses on derivatives and there was no unrealized gains or losses on derivatives.
The board of directors of our general partner expects to evaluate the reinstatement of the common unit and all preferred unit distributions in due course, taking into account a number of important factors, including our leverage, liquidity, the sustainability of cash flows, upcoming debt maturities, capital expenditures and the overall performance of our businesses.
The board of directors of our GP expects to evaluate the reinstatement of the common unit and all preferred unit distributions in due course, taking into account a number of important factors, including our leverage, liquidity, the sustainability of cash flows, upcoming debt maturities, capital expenditures and the overall performance of our businesses.
(6) Represents the fee paid to the holders of the Class D Preferred Units to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 12 to our consolidated financial statements included in this Annual Report).
(5) Amount represents the fee paid to the holders of the Class D Preferred Units to obtain their consent in order to complete the issuance of the 2026 Senior Secured Notes and the ABL Facility (see Note 12 to our consolidated financial statements included in this Annual Report).
Distributions Declared The board of directors of our general partner decided to temporarily suspend all distributions in order to deleverage our balance sheet until we meet the 4.75 to 1.00 total leverage ratio set forth within the indenture of the 2026 Senior Secured Notes.
Distributions Declared The board of directors of our GP decided to temporarily suspend all distributions in order to deleverage our balance sheet until we meet the 4.75 to 1.00 total leverage ratio set forth within the indenture of the 2026 Senior Secured Notes.
The decrease in net cash used in financing activities was due primarily to: • an increase of $1.6 billion in borrowings on the revolving credit facilities (net of repayments) during the year ended March 31, 2022; • the repayment and termination of our $250.0 million term credit agreement in February 2021; • a decrease of $144.6 million in distributions paid to our general partners and common unitholders, preferred unitholders and noncontrolling interest owners during the year ended March 31, 2022 due primarily to the reduction and subsequent suspension of the quarterly common unit and preferred unit distributions; 82 • $93.4 million in contingent consideration payments during the year ended March 31, 2021 due to installment payments related to the Mesquite acquisition; • a make-whole fee of $55.6 million related to the termination of our term credit agreement in February 2021; • a decrease of $50.6 million in debt issuance costs related to the termination of our term credit agreement and the issuance of the 2026 Senior Secured Notes in February 2021; and • a decrease of $32.6 million paid in cash to repurchase a portion of our Senior Unsecured Notes during the year ended March 31, 2022.
The decrease in net cash used in financing activities was due primarily to: • an increase of $1.6 billion in borrowings on the revolving credit facilities (net of repayments) during the year ended March 31, 2022; • the repayment and termination of our $250.0 million term credit agreement in February 2021; • a decrease of $144.6 million in distributions paid to our GP and common unitholders, preferred unitholders and noncontrolling interest owners during the year ended March 31, 2022 due primarily to the reduction and subsequent suspension of the quarterly common unit and preferred unit distributions; • $93.4 million in contingent consideration payments during the year ended March 31, 2021 due to installment payments related to the Mesquite Disposals Unlimited, LLC acquisition; • a make-whole fee of $55.6 million related to the termination of our term credit agreement in February 2021; • a decrease of $50.6 million in debt issuance costs related to the termination of our term credit agreement and the issuance of the 2026 Senior Secured Notes in February 2021; and • a decrease of $32.6 million paid in cash to repurchase a portion of our Senior Unsecured Notes during the year ended March 31, 2022.
The decrease in net cash provided by operating activities during the year ended March 31, 2022 was due primarily to fluctuations in the value of accounts receivable and accounts payable, increased inventory valuations and higher interest expense during the year ended March 31, 2022.
The decrease in net cash provided by operating activities during the year ended March 31, 2022 was due primarily to fluctuations in the value of accounts receivable and accounts payable, increased inventory valuations and higher interest expense during the year ended March 31, 2022. Investing Activities-Continuing Operations .
Interest Expense The following table summarizes the components of our consolidated interest expense for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands) Senior secured notes $ 153,750 $ 24,344 $ 129,406 Senior unsecured notes 87,766 96,711 (8,945) Amortization of debt issuance costs 16,960 13,420 3,540 Revolving credit facility 10,077 46,500 (36,423) Other 3,087 17,824 (14,737) Total $ 271,640 $ 198,799 $ 72,841 The increase of $72.8 million during the year ended March 31, 2022 was primarily due to the issuance of the 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) which resulted in us paying a higher interest rate on certain refinanced indebtedness.
Interest Expense The following table summarizes the components of our consolidated interest expense for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands) Senior secured notes $ 153,750 $ 24,344 $ 129,406 Senior unsecured notes 87,766 96,711 (8,945) Revolving credit facility 10,077 46,500 (36,423) Other indebtedness 3,087 17,824 (14,737) Total debt interest expense 254,680 185,379 69,301 Amortization of debt issuance costs 16,960 13,420 3,540 Total interest expense $ 271,640 $ 198,799 $ 72,841 The debt interest expense increased $69.3 million during the year ended March 31, 2022 due primarily to the issuance of the 7.5% senior secured notes due 2026 (“2026 Senior Secured Notes”) which resulted in us paying a higher interest rate on certain refinanced indebtedness.
We believe volatility in commodity prices will continue into the near term, our ability to adjust to and manage this volatility may impact our financial results. Our Crude Oil Logistics segment generated operating income of $45.0 million during the year ended March 31, 2022.
We believe volatility in commodity prices will continue into the near term, our ability to adjust to and manage this volatility may impact our financial results. Our Crude Oil Logistics segment generated operating income of $81.5 million during the year ended March 31, 2023, compared to operating income of $45.0 million during the year ended March 31, 2022.
Segment Operating Results for the Years Ended March 31, 2022 and 2021 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated.
Segment Operating Results for the Years Ended March 31, 2023 and 2022 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated.
Other product sales product margins during the year ended March 31, 2022 increased due to an increase in demand for biodiesel and biodiesel renewable identification number market prices, as well as securing favorable biodiesel supply contracts in the Midwest and transporting the product for sale in more favorable markets.
Other product sales product margins, excluding the impact of derivatives, during the year ended March 31, 2022 increased due to an increase in demand for biodiesel and biodiesel renewable identification number market prices, as well as securing favorable biodiesel supply contracts in the Midwest and transporting the product for sale in more favorable markets.
The following table summarizes the range of low and high crude oil spot prices per barrel of New York Mercantile Exchange (“NYMEX”) West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices at period end: Crude Oil Spot Price Per Barrel Year Ended March 31, Low High At Period End 2022 $ 58.65 $ 123.70 $ 100.28 2021 (1) $ (37.63) $ 66.09 $ 59.16 2020 $ 20.09 $ 66.30 $ 20.48 (1) On April 20, 2020, crude oil prices collapsed due to low demand as a result of the COVID-19 lockdowns, the price war between Russia and Saudi Arabia and a lack of available storage.
The following table summarizes the range of low and high crude oil spot prices per barrel of New York Mercantile Exchange (“NYMEX”) West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices at period end: Crude Oil Spot Price Per Barrel Year Ended March 31, Low High At Period End 2023 $ 66.74 $ 122.11 $ 75.67 2022 $ 58.65 $ 123.70 $ 100.28 2021 (1) $ (37.63) $ 66.09 $ 59.16 (1) On April 20, 2020, crude oil prices collapsed due to low demand as a result of the COVID-19 lockdowns, the price war between Russia and Saudi Arabia and a lack of available storage.
Our refined products margin during the year ended March 31, 2022 included a realized loss of $2.9 million and the year ended March 31, 2021 included a realized loss of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions.
Our Refined Products product margin during the year ended March 31, 2022 included realized losses of $2.9 million and the year ended March 31, 2021 included realized losses of $0.9 million from our risk management activities due primarily to NYMEX future prices increasing on our short future positions.
On October 29, 2020, we entered into an equipment loan for $45.0 million which bears interest at a rate of 8.6% and is secured by certain of our barges and towboats.
Other Long-term Debt On October 29, 2020, we entered into an equipment loan for $45.0 million which bears interest at a rate of 8.6% and is secured by certain of our barges and towboats.
Refined Products product margins per gallon of refined products sold for the year ended March 31, 2022 increased from the year ended March 31, 2021 primarily due to supply being short during the three months ended December 31, 2021, as a result of extended refinery downtime in certain markets in which we compete, and being well positioned during the extreme volatility surrounding global events occurring in the three months ended March 31, 2022.
Refined Products product margins, excluding the impact of derivatives, for the year ended March 31, 2022 increased from the year ended March 31, 2021 primarily due to supply being short during the three months ended December 31, 2021, as a result of extended refinery downtime in certain markets in which we compete, and being well positioned during the extreme volatility surrounding global events occurring in the three months ended March 31, 2022.
Noncontrolling Interests Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Noncontrolling interest income was $0.7 million during the year ended March 31, 2022, compared to $0.6 million during the year ended March 31, 2021.
Noncontrolling Interests Noncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Noncontrolling interest income was $1.1 million during the year ended March 31, 2023, compared to $0.7 million during the year ended March 31, 2022.
Our consolidated balance sheet at March 31, 2022 includes a liability of $29.9 million related to asset retirement obligations, which is reported within other noncurrent liabilities. In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets.
Our consolidated balance sheet at March 31, 2023 includes a liability of $35.2 million related to asset retirement obligations, which is reported within other noncurrent liabilities. In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets.
Butane product margins per gallon of butane sold were higher during year ended March 31, 2022 than during the year ended March 31, 2021 due primarily to a tight supply market, driven by an increase in demand for exports and an increase in blending demand, which are driving favorable sales differentials.
Butane product margins, excluding the impact of derivatives, were higher during year ended March 31, 2022 than during the year ended March 31, 2021 due primarily to a tight supply market, driven by an increase in demand for exports and an increase in blending demand, which are driving favorable sales differentials.
If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. During the years ended March 31, 2021 and 2020, we recorded goodwill impairments of $237.8 million and $250.0 million, respectively. We did not record a goodwill impairment during the year ended March 31, 2022.
If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. During the year ended March 31, 2021, we recorded a goodwill impairment of $237.8 million. We did not record a goodwill impairment during the years ended March 31, 2023 and 2022.
Crude Oil Logistics The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands, except per barrel amounts) Revenues: Crude oil sales $ 2,432,393 $ 1,574,699 $ 857,694 Crude oil transportation and other 84,171 153,588 (69,417) Total revenues (1) 2,516,564 1,728,287 788,277 Expenses: Cost of sales-excluding impact of derivatives 2,271,973 1,473,330 798,643 Derivative loss 92,027 49,314 42,713 Operating expenses 54,606 56,918 (2,312) General and administrative expenses 7,537 8,038 (501) Depreciation and amortization expense 48,489 60,874 (12,385) (Gain) loss on disposal or impairment of assets, net (3,101) 384,143 (387,244) Total expenses 2,471,531 2,032,617 438,914 Segment operating income (loss) $ 45,033 $ (304,330) $ 349,363 Crude oil sold (barrels) 31,091 38,349 (7,258) Crude oil transported on owned pipelines (barrels) 28,410 32,797 (4,387) Crude oil storage capacity - owned and leased (barrels) (2) 5,232 5,239 (7) Crude oil storage capacity leased to third parties (barrels) (2) 1,501 1,501 — Crude oil inventory (barrels) (2) 1,339 1,201 138 Crude oil sold ($/barrel) $ 78.235 $ 41.062 $ 37.173 Cost per crude oil sold ($/barrel) (3) $ 73.075 $ 38.419 $ 34.656 Crude oil product margin ($/barrel) (3) $ 5.160 $ 2.643 $ 2.517 (1) Revenues include $11.1 million and $6.7 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
During the year ended March 31, 2021, there was an increase in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to higher expected production from new customers, resulting in an increase to the expected future royalty payment. 66 Crude Oil Logistics The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated: Year Ended March 31, 2022 2021 Change (in thousands, except per barrel amounts) Revenues: Crude oil sales $ 2,432,393 $ 1,574,699 $ 857,694 Crude oil transportation and other 84,171 153,588 (69,417) Total revenues (1) 2,516,564 1,728,287 788,277 Expenses: Cost of sales-excluding impact of derivatives 2,271,973 1,473,330 798,643 Derivative loss 92,027 49,314 42,713 Operating expenses 54,606 56,918 (2,312) General and administrative expenses 7,537 8,038 (501) Depreciation and amortization expense 48,489 60,874 (12,385) (Gain) loss on disposal or impairment of assets, net (3,101) 384,143 (387,244) Total expenses 2,471,531 2,032,617 438,914 Segment operating income (loss) $ 45,033 $ (304,330) $ 349,363 Crude oil sold (barrels) 31,091 38,349 (7,258) Crude oil transported on owned pipelines (barrels) 28,410 32,797 (4,387) Crude oil storage capacity - owned and leased (barrels) (2) 5,232 5,239 (7) Crude oil storage capacity leased to third parties (barrels) (2) 1,501 1,501 — Crude oil inventory (barrels) (2) 1,339 1,201 138 Crude oil sold ($/barrel) $ 78.235 $ 41.062 $ 37.173 Cost per crude oil sold ($/barrel) (3) $ 73.075 $ 38.419 $ 34.656 Crude oil product margin ($/barrel) (3) $ 5.160 $ 2.643 $ 2.517 (1) Revenues include $11.1 million and $6.7 million of intersegment sales during the years ended March 31, 2022 and 2021, respectively, that are eliminated in our consolidated statements of operations.
During the year ended March 31, 2022, we recorded a net loss of $29.8 million primarily related to the write-down of an inactive saltwater disposal facility and damaged equipment and wells at other facilities, abandonment of certain capital projects and the sale of certain other miscellaneous assets and a gain of $4.3 million on the sale of certain land and a landfill permit.
During the year ended March 31, 2022, we recorded a net loss of $29.8 million primarily related to the write-down of an inactive saltwater disposal facility and damaged equipment and wells at other facilities, abandonment of certain capital projects and the sale of certain other miscellaneous assets.
Purchase Commitments Our fixed-price and index-price commodity purchase commitments result from contracts we have entered into for which we expect the parties to physically settle and deliver the inventory in future periods. As of March 31, 2022, our purchase commitments totaled $10.1 billion, with $5.5 billion due within one year.
Purchase Commitments Our fixed-price and index-price commodity purchase commitments result from contracts we have entered into for which we expect the parties to physically settle and deliver the inventory in future periods. As of March 31, 2023, our purchase 79 commitments totaled $7.7 billion, with $5.4 billion due within one year.
See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our commodity purchase commitments and timing of our expected purchase commitments payments. 80 Debt Principal and Interest Obligations As of March 31, 2022, our aggregate principal amount of outstanding debt was $3.4 billion, with $2.4 million due within one year.
See Note 8 to our consolidated financial statements included in this Annual Report for information regarding our commodity purchase commitments and timing of our expected purchase commitments payments. Debt Principal and Interest Obligations As of March 31, 2023, our aggregate principal amount of outstanding debt was $2.9 billion, with nothing due within one year.
Prior to the pandemic, we saw the level of crude oil production increase, particularly in the Permian and DJ Basins, due to increasing or stable crude oil prices, which positively impacted our disposal volumes. Lower crude oil prices provide producers with less incentive to drill and complete new wells, which results in lower production and negatively impacts our disposal volumes.
Recently, our disposal volumes have been positively impacted by the increase in the level of crude oil production, particularly in the Permian and DJ Basins, due to increasing or stable crude oil prices. Lower crude oil prices provide producers with less incentive to drill and complete new wells, which results in lower production and negatively impacts our disposal volumes.
Our Water Solutions segment generated operating income of $94.9 million during the year ended March 31, 2022.
Our Water Solutions segment generated operating income of $198.9 million during the year ended March 31, 2023, compared to operating income of $94.9 million during the year ended March 31, 2022.
During the year ended March 31, 2020, there was a reduction in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers and an increase in facilities due to acquisitions, resulting in a decrease to the expected future royalty payment.
Revaluation of Liabilities. During the year ended March 31, 2022, there was a decrease in expense for the valuation of our contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations due primarily to lower expected production from new customers, resulting in a decrease to the expected future royalty payment.
Belvieu, Texas Propane Spot Price Per Gallon Propane Spot Price Per Gallon Year Ended March 31, Low High At Period End Low High At Period End 2022 $ 0.67 $ 1.64 $ 1.37 $ 0.72 $ 1.63 $ 1.39 2021 $ 0.23 $ 1.53 $ 0.86 $ 0.25 $ 1.07 $ 0.92 2020 $ 0.18 $ 0.60 $ 0.25 $ 0.19 $ 0.68 $ 0.28 The following table summarizes the range of low and high butane spot prices per gallon at Mt.
Belvieu, Texas Propane Spot Price Per Gallon Propane Spot Price Per Gallon Year Ended March 31, Low High At Period End Low High At Period End 2023 $ 0.63 $ 1.34 $ 0.74 $ 0.64 $ 1.39 $ 0.78 2022 $ 0.67 $ 1.64 $ 1.37 $ 0.72 $ 1.63 $ 1.39 2021 $ 0.23 $ 1.53 $ 0.86 $ 0.25 $ 1.07 $ 0.92 The following table summarizes the range of low and high butane spot prices per gallon at Mt.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview We are a Delaware limited partnership (“we,” “us,” “our,” or the “Partnership”) formed in September 2010. NGL Energy Holdings LLC serves as our general partner.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview We are a Delaware limited partnership (“we,” “us,” “our,” or the “Partnership”) formed in September 2010. NGL Energy Holdings LLC serves as our general partner (“GP”). At March 31, 2023, our operations included three segments as discussed below.
Other revenues primarily include brackish non-potable water revenues, water pipeline revenues, land surface use revenues and solids disposal revenues.
Other revenues primarily include brackish non-potable water revenues, water pipeline revenues, land surface use revenues, solids disposal revenues and reimbursements from construction projects.
The increase of less than $0.1 million during the year ended March 31, 2022 was due primarily to higher income from certain recycling operations, partially offset by a higher loss from operations of the Sawtooth joint venture primarily due to the sale of Sawtooth in June 2021 and lower income from certain water solutions operations. 64 Segment Operating Results for the Years Ended March 31, 2021 and 2020 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated.
The increase of $0.4 million during the year ended March 31, 2023 was due primarily to higher income from certain water solutions operations during the year ended March 31, 2023 and a loss of $0.2 million from the operations of Sawtooth during the year ended March 31, 2022, partially offset by lower income from certain recycling operations during the year ended March 31, 2023. 64 Segment Operating Results for the Years Ended March 31, 2022 and 2021 Water Solutions The following table summarizes the operating results of our Water Solutions segment for the periods indicated.
Net cash used in financing activities was $100.4 million during the year ended March 31, 2021, compared to net cash provided by financing activities of $978.8 million during the year ended March 31, 2020.
Net cash provided by financing activities was $5.6 million during the year ended March 31, 2022, compared to net cash used in financing activities of $100.4 million during the year ended March 31, 2021.
These decreases in net cash used in investing activities were partially offset by a $167.1 million increase in payments to settle derivatives. Financing Activities-Continuing Operations. Net cash provided by financing activities was $5.6 million during the year ended March 31, 2022, compared to net cash used in financing activities of $100.4 million during the year ended March 31, 2021.
These decreases in net cash used in investing activities were partially offset by a $71.7 million increase in payments to settle derivatives. Financing Activities-Continuing Operations. Net cash used in financing activities was $507.8 million during the year ended March 31, 2023, compared to net cash provided by financing activities of $5.6 million during the year ended March 31, 2022.
Belvieu, Texas for the periods indicated and the prices at period end: Butane Spot Price Per Gallon Year Ended March 31, Low High At Period End 2022 $ 0.78 $ 2.01 $ 1.71 2021 $ 0.28 $ 1.16 $ 0.98 2020 $ 0.19 $ 0.80 $ 0.29 The following table summarizes the range of low and high Gulf Coast gasoline spot prices per barrel using NYMEX gasoline prompt-month futures for the periods indicated and the prices at period end: Gasoline Spot Price Per Gallon Year Ended March 31, Low High At Period End 2022 $ 81.95 $ 154.67 $ 133.96 2021 $ 21.43 $ 90.30 $ 82.04 2020 $ 17.30 $ 89.55 $ 24.07 The following table summarizes the range of low and high diesel spot prices per barrel using NYMEX ULSD prompt-month futures for the periods indicated and the prices at period end: Diesel Spot Price Per Gallon Year Ended March 31, Low High At Period End 2022 $ 74.44 $ 186.37 $ 155.03 2021 $ 25.64 $ 82.64 $ 74.39 2020 $ 40.08 $ 89.17 $ 42.51 54 We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.
Belvieu, Texas for the periods indicated and the prices at period end: Butane Spot Price Per Gallon Year Ended March 31, Low High At Period End 2023 $ 0.85 $ 1.65 $ 0.92 2022 $ 0.78 $ 2.01 $ 1.71 2021 $ 0.28 $ 1.16 $ 0.98 The following table summarizes the range of low and high Gulf Coast gasoline spot prices per barrel using NYMEX gasoline prompt-month futures for the periods indicated and the prices at period end: Gasoline Spot Price Per Gallon Year Ended March 31, Low High At Period End 2023 $ 86.06 $ 179.60 $ 113.42 2022 $ 81.95 $ 154.67 $ 133.96 2021 $ 21.43 $ 90.30 $ 82.04 The following table summarizes the range of low and high diesel spot prices per barrel using NYMEX ULSD prompt-month futures for the periods indicated and the prices at period end: Diesel Spot Price Per Gallon Year Ended March 31, Low High At Period End 2023 $ 109.41 $ 215.69 $ 112.40 2022 $ 74.44 $ 186.37 $ 155.03 2021 $ 25.64 $ 82.64 $ 74.39 We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.
During the year ended March 31, 2020, our cost of wholesale propane sales included $1.5 million of net unrealized losses on derivatives and $2.0 million of net realized losses on derivatives.
During the year ended March 31, 2022, our cost of wholesale propane sales included $2.0 million of net unrealized gains on derivatives and 61 $18.5 million of net realized gains on derivatives.
Cash Flows The following table summarizes the sources (uses) of our cash flows from continuing operations for the periods indicated: Year Ended March 31, Cash Flows Provided by (Used in): 2022 2021 2020 (in thousands) Operating activities, before changes in operating assets and liabilities $ 342,362 $ 295,301 $ 342,736 Changes in operating assets and liabilities (136,516) 10,462 39,690 Operating activities-continuing operations $ 205,846 $ 305,763 $ 382,426 Investing activities-continuing operations $ (212,408) $ (221,493) $ (1,737,620) Financing activities-continuing operations $ 5,555 $ (100,376) $ 978,833 Operating Activities-Continuing Operations.
Cash Flows The following table summarizes the sources (uses) of our cash flows from continuing operations for the periods indicated: Year Ended March 31, Cash Flows Provided by (Used in): 2023 2022 2021 (in thousands) Operating activities, before changes in operating assets and liabilities $ 447,024 $ 342,362 $ 295,301 Changes in operating assets and liabilities (1,838) (136,516) 10,462 Operating activities-continuing operations $ 445,186 $ 205,846 $ 305,763 Investing activities-continuing operations $ 64,188 $ (212,408) $ (221,493) Financing activities-continuing operations $ (507,765) $ 5,555 $ (100,376) Operating Activities-Continuing Operations.
(4) Amounts represent expenses we incurred related to legal and advisory costs associated with acquisitions, including Mesquite and Hillstone. (5) Amounts for the years ended March 31, 2022 and 2021 represent the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment.
(3) Amounts represent expenses we incurred related to legal and advisory costs associated with acquisitions. 74 (4) Amounts represent the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment.
The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our consolidated statements of operations and consolidated statements of cash flows for the periods indicated: Year Ended March 31, 2022 2021 2020 (in thousands) Reconciliation to consolidated statements of operations: Depreciation and amortization per EBITDA table $ 287,943 $ 314,476 $ 265,147 Intangible asset amortization recorded to cost of sales (281) (307) (349) Depreciation and amortization of unconsolidated entities (768) (756) (561) Depreciation and amortization attributable to noncontrolling interests 1,826 3,814 3,535 Depreciation and amortization attributable to discontinued operations — — (2,460) Depreciation and amortization per consolidated statements of operations $ 288,720 $ 317,227 $ 265,312 Reconciliation to consolidated statements of cash flows: Depreciation and amortization per EBITDA table $ 287,943 $ 314,476 $ 265,147 Amortization of debt issuance costs recorded to interest expense 16,960 13,419 10,901 Amortization of royalty expense recorded to operating expense 247 247 286 Depreciation and amortization of unconsolidated entities (768) (756) (561) Depreciation and amortization attributable to noncontrolling interests 1,826 3,814 3,535 Depreciation and amortization attributable to discontinued operations — — (2,460) Depreciation and amortization per consolidated statements of cash flows $ 306,208 $ 331,200 $ 276,848 The following table reconciles interest expense per the EBITDA table above to interest expense reported in our consolidated statements of operations for the periods indicated: Year Ended March 31, 2022 2021 2020 (in thousands) Interest expense per EBITDA table $ 271,689 $ 198,823 $ 181,357 Interest expense attributable to noncontrolling interests 16 47 — Interest expense attributable to unconsolidated entities (65) (71) (62) Interest expense attributable to discontinued operations — — (111) Interest expense per consolidated statements of operations $ 271,640 $ 198,799 $ 181,184 75 The following table summarizes additional amounts attributable to discontinued operations in the EBITDA table above for the periods indicated: Year Ended March 31, 2021 2020 (in thousands) Income tax (benefit) expense $ (53) $ 20 Inventory valuation adjustment $ 27 $ (27,526) Lower of cost or net realizable value adjustments $ (27) $ (991) Loss on disposal or impairment of assets, net $ 1,174 $ 203,990 The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated.
The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our consolidated statements of operations and consolidated statements of cash flows for the periods indicated: Year Ended March 31, 2023 2022 2021 (in thousands) Depreciation and amortization per EBITDA table $ 273,544 $ 287,943 $ 314,476 Intangible asset amortization recorded to cost of sales (274) (281) (307) Depreciation and amortization of unconsolidated entities (783) (768) (756) Depreciation and amortization attributable to noncontrolling interests 1,134 1,826 3,814 Depreciation and amortization per consolidated statements of operations $ 273,621 $ 288,720 $ 317,227 Depreciation and amortization per EBITDA table $ 273,544 $ 287,943 $ 314,476 Amortization of debt issuance costs recorded to interest expense 16,737 16,960 13,419 Amortization of royalty expense recorded to operating expense 247 247 247 Depreciation and amortization of unconsolidated entities (783) (768) (756) Depreciation and amortization attributable to noncontrolling interests 1,134 1,826 3,814 Depreciation and amortization per consolidated statements of cash flows $ 290,879 $ 306,208 $ 331,200 The following table reconciles interest expense per the EBITDA table above to interest expense reported in our consolidated statements of operations for the periods indicated: Year Ended March 31, 2023 2022 2021 (in thousands) Interest expense per EBITDA table $ 275,505 $ 271,689 $ 198,823 Interest expense attributable to unconsolidated entities (60) (65) (71) Interest expense attributable to noncontrolling interests — 16 47 Interest expense per consolidated statements of operations $ 275,445 $ 271,640 $ 198,799 The following table summarizes additional amounts attributable to discontinued operations in the EBITDA table above for the year ended March 31, 2021 (in thousands): Income tax benefit $ (53) Inventory valuation adjustment $ 27 Lower of cost or net realizable value adjustments $ (27) Loss on disposal or impairment of assets, net $ 1,174 75 The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated.
During the year ended March 31, 2022, physical volumes on the Grand Mesa Pipeline averaged approximately 78,000 barrels per day, compared to approximately 90,000 barrels per day for the year ended March 31, 2021 (volume amounts are from both internal and external parties).
During the year ended March 31, 2022, physical volumes on the Grand Mesa Pipeline averaged approximately 78,000 barrels per day, compared to approximately 90,000 barrels per day for the year ended March 31, 2021 (volume amounts are from both internal and external parties). The decline was primarily due to the court approved rejection of the Extraction Oil & Gas, Inc.
The following table reconciles net loss to EBITDA and Adjusted EBITDA for the periods indicated: Year Ended March 31, 2022 2021 2020 (in thousands) Net loss $ (184,101) $ (639,187) $ (398,780) Less: Net (income) loss attributable to noncontrolling interests (655) (632) 1,773 Net loss attributable to NGL Energy Partners LP (184,756) (639,819) (397,007) Interest expense 271,689 198,823 181,357 Income tax expense (benefit) 971 (3,444) 365 Depreciation and amortization 287,943 314,476 265,147 EBITDA 375,847 (129,964) 49,862 Net unrealized (gains) losses on derivatives (14,977) 47,366 (38,557) CMA Differential Roll net losses (gains) (1) 67,738 — — Inventory valuation adjustment (2) 8,409 1,224 (29,676) Lower of cost or net realizable value adjustments 10,862 (30,102) 31,202 Loss on disposal or impairment of assets, net 94,059 476,601 464,483 (Gain) loss on early extinguishment of liabilities, net (1,851) 16,692 (1,341) Equity-based compensation expense (3) (1,052) 6,727 26,510 Acquisition expense (4) 67 1,711 19,722 Revaluation of liabilities (5) (6,495) 6,261 9,194 Class D Preferred Unitholder consent fee (6) — 40,000 — Other (7) 9,909 11,135 15,788 Adjusted EBITDA $ 542,516 $ 447,651 $ 547,187 Adjusted EBITDA - Discontinued Operations (8) $ — $ (621) $ (42,270) Adjusted EBITDA - Continuing Operations $ 542,516 $ 448,272 $ 589,457 (1) Adjustment to align, within Adjusted EBITDA, the net gains and losses of the Partnership’s CMA Differential Roll derivative instruments positions with the physical margin being hedged.
The following table reconciles net income (loss) to EBITDA and Adjusted EBITDA for the periods indicated: Year Ended March 31, 2023 2022 2021 (in thousands) Net income (loss) $ 52,492 $ (184,101) $ (639,187) Less: Net income attributable to noncontrolling interests (1,106) (655) (632) Net income (loss) attributable to NGL Energy Partners LP 51,386 (184,756) (639,819) Interest expense 275,505 271,689 198,823 Income tax expense (benefit) 271 971 (3,444) Depreciation and amortization 273,544 287,943 314,476 EBITDA 600,706 375,847 (129,964) Net unrealized (gains) losses on derivatives (50,438) (14,977) 47,366 CMA Differential Roll net losses (gains) (1) 3,547 67,738 — Inventory valuation adjustment (2) (7,795) 8,409 1,224 Lower of cost or net realizable value adjustments (11,534) 10,862 (30,102) Loss on disposal or impairment of assets, net 86,872 94,059 476,601 (Gain) loss on early extinguishment of liabilities, net (6,177) (1,851) 16,692 Equity-based compensation expense 2,718 (1,052) 6,727 Acquisition expense (3) 118 67 1,711 Revaluation of liabilities (4) 9,665 (6,495) 6,261 Class D Preferred Unitholder consent fee (5) — — 40,000 Other (6) 4,993 9,909 11,135 Adjusted EBITDA $ 632,675 $ 542,516 $ 447,651 Adjusted EBITDA - Discontinued Operations (7) $ — $ — $ (621) Adjusted EBITDA - Continuing Operations $ 632,675 $ 542,516 $ 448,272 (1) Adjustment to align, within Adjusted EBITDA, the net gains and losses of the Partnership’s CMA Differential Roll derivative instruments positions with the physical margin being hedged.
Our cost of butane sales during the year ended March 31, 2021 included $3.2 million of net unrealized losses on derivatives and $19.1 million of net realized losses on derivatives. Our cost of butane sales included $0.5 million of net unrealized losses on derivatives and $8.8 million of net realized gains on derivatives during the year ended March 31, 2020.
Our cost of butane sales during the year ended March 31, 2023 included $3.9 million of net unrealized gains on derivatives and $19.1 million of net realized gains on derivatives. Our cost of butane sales included $1.0 million of net unrealized gains on derivatives and $19.7 million of net realized losses on derivatives during the year ended March 31, 2022.
The increase of $0.6 million during the year ended March 31, 2021 was due primarily to higher earnings from certain membership interests acquired in November 2019 related to specific land and water services operations, partially offset by a higher loss from our interest in an aircraft company during the year ended March 31, 2021.
The increase of $2.7 million during the year ended March 31, 2023 was due primarily to higher earnings from certain membership interests related to specific land and water services operations and a lower loss from our interest in an aircraft company.
Equity in Earnings of Unconsolidated Entities Equity in earnings of unconsolidated entities was $1.9 million during the year ended March 31, 2021, compared to $1.3 million during the year ended March 31, 2020.
Equity in Earnings of Unconsolidated Entities Equity in earnings of unconsolidated entities was $4.1 million during the year ended March 31, 2023, compared to $1.4 million during the year ended March 31, 2022.
The “inventory valuation adjustment” row in the reconciliation table reflects the difference between the market value of the inventory of these businesses at the balance sheet date and its cost, adjusted for the impact of seasonal market movements related to our base inventory and the related hedge.
The “inventory valuation adjustment” row in the reconciliation table reflects the difference between the market value of the inventory of these businesses at the balance sheet date and its cost.
Senior Secured Notes On February 4, 2021, we issued $2.05 billion of 2026 Senior Secured Notes in a private placement. The 2026 Senior Secured Notes bear interest at 7.50%, which is payable on February 1 and August 1 of each year, beginning on August 1, 2021. The 2026 Senior Secured Notes mature on February 1, 2026.
The 2026 Senior Secured Notes bear interest at 7.50%, which is payable on February 1 and August 1 of each year, beginning on August 1, 2021. The 2026 Senior Secured Notes mature on February 1, 2026.
Our cost of sales during the year ended March 31, 2022 included $115.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $23.7 million of net unrealized gains on derivatives.
The increase was partially offset by a reduction in volumes, as discussed above in “ Crude Oil Sales Revenues .” Derivative Loss. Our cost of sales during the year ended March 31, 2022 included $115.7 million of net realized losses on derivatives, driven by increasing crude oil prices, partially offset by $23.7 million of net unrealized gains on derivatives.
The decrease in net cash used in investing activities was due primarily to: • net proceeds (gross cash proceeds less the amount of cash sold, excluding accrued expenses) of $63.5 million from the sale of our interest in Sawtooth in June 2021 (see Note 17 to our consolidated financial statements included in this Annual Report); • a decrease in capital expenditures from $186.8 million (includes payment of amounts accrued as of March 31, 2020) during the year ended March 31, 2021 to $142.4 million (includes payment of amounts accrued as of March 31, 2021) during the year ended March 31, 2022 due primarily to fewer expansion projects in our Water Solutions segment; and • proceeds of $18.5 million from certain asset sales during the year ended March 31, 2022 (see Note 4 to our consolidated financial statements included in this Annual Report).
The decrease in net cash used in investing activities was due primarily to: • a decrease in capital expenditures from $186.8 million (includes payment of amounts accrued as of March 31, 2020) during the year ended March 31, 2021 to $142.4 million (includes payment of amounts accrued as of March 31, 2021) during the year ended March 31, 2022 due primarily to fewer expansion projects in our Water Solutions segment; and • a $36.2 million increase in proceeds received from the sale of certain assets and businesses primarily related to the sale of our interest in Sawtooth in June 2021 and the sale of certain permits, land and a saltwater disposal facility to a third-party during the year ended March 31, 2021 (see Note 4 and Note 17 to our consolidated financial statements included in this Annual Report).
Our cost of sales of other products during the year ended March 31, 2021 included $0.5 million of net unrealized gains on derivatives and $6.6 million of net realized gains on derivatives.
Other Products Derivatives Loss. Our derivatives of other products included $24.6 million of net realized losses on derivatives and $0.1 million unrealized gains on derivatives during the year ended March 31, 2023.
See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion. Noncontrolling Interests Noncontrolling interest income was $0.6 million during the year ended March 31, 2021, compared to a noncontrolling interest loss of $1.8 million during the year ended March 31, 2020.
Income Tax Expense Income tax expense was $0.3 million during the year ended March 31, 2023, compared to income tax expense of $1.0 million during the year ended March 31, 2022. See Note 2 to our consolidated financial statements included in this Annual Report for a further discussion.
Operating Lease Obligations As of March 31, 2022, our undiscounted operating lease obligation was $145.9 million, with $46.6 million due within one year. See Note 15 to our consolidated financial statements included in this Annual Report for information regarding our lease obligations and timing of our expected lease payments.
See Note 7 to our consolidated financial statements included in this Annual Report for information regarding our outstanding debt principal and interest obligations and timing of our expected debt principal and interest payments. Operating Lease Obligations As of March 31, 2023, our undiscounted operating lease obligation was $121.4 million, with $40.8 million due within one year.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

10 edited+3 added−4 removed6 unchanged
Credit risk is monitored daily and we try to minimize exposure through the following, • requiring certain customers to prepay or place deposits for our products and services; • requiring certain customers to post letters of credit or other forms of surety; • monitoring individual customer receivables relative to previously-approved credit limits; • requiring certain customers to take delivery of their contracted volume ratably rather than allow them to take delivery at their discretion; 88 • entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions; • reviewing the receivable aging regularly to identify issues or trends that may develop; and • requiring marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid outstanding invoices.
Credit risk is monitored daily and we try to minimize exposure through the following, • requiring certain customers to prepay or place deposits for our products and services; • requiring certain customers to post letters of credit or other forms of surety; • monitoring individual customer receivables relative to previously-approved credit limits; • requiring certain customers to take delivery of their contracted volume ratably rather than allow them to take delivery at their discretion; • entering into master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions; • reviewing the receivable aging regularly to identify issues or trends that may develop; and • requiring marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid outstanding invoices.
For our Class C Preferred Units, distributions on and after April 15, 2024 will 87 accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) plus a spread of 7.384%.
For our Class C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, distributions on and after April 15, 2024 will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in the amended and restated limited partnership agreement (the “Partnership Agreement”)) plus a spread of 7.384%.
At March 31, 2022, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. 89
At March 31, 2023, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. 87
As a result, our profitability may be impacted by sudden and significant changes in the price of crude oil, natural gas liquids, and refined and renewables products.
We have no control over market conditions. As a result, our profitability may be impacted by sudden and significant changes in the price of crude oil, natural gas liquids, and refined and renewables products.
At March 31, 2022, we had $116.0 million of outstanding borrowings under the ABL Facility at a weighted average interest rate of 4.64%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $0.1 million, based on borrowings outstanding at March 31, 2022.
At March 31, 2023, we had $138.0 million of outstanding borrowings under the ABL Facility at a weighted average interest rate of 8.70%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $0.2 million, based on borrowings outstanding at March 31, 2023.
Commodity Price Risk Our operations are subject to certain business risks, including commodity price risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions.
Commodity price risk is the risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response to changing market conditions. Procedures and limits for managing commodity price risks are specified in our market risk policy.
The following table summarizes the hypothetical impact on the March 31, 2022 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands): Increase (Decrease) To Fair Value Crude oil (Water Solutions segment) $ (4,838) Crude oil (Crude Oil Logistics segment) $ (8,612) Propane (Liquids Logistics segment) $ 532 Butane (Liquids Logistics segment) $ (3,026) Refined Products (Liquids Logistics segment) $ (2,598) Other Products (Liquids Logistics segment) $ 4,106 Changes in commodity prices may also impact the volumes that we are able to transport, dispose, store and market, which also impact our cash flows.
See “Critical Accounting Estimates” above for a discussion of how we determine the fair value of our financial derivative instruments. 86 The following table summarizes the hypothetical impact on the March 31, 2023 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands): Increase (Decrease) To Fair Value Crude oil (Crude Oil Logistics segment) $ 2,048 Propane (Liquids Logistics segment) $ (1,414) Butane (Liquids Logistics segment) $ (4,096) Refined Products (Liquids Logistics segment) $ (4,660) Other Products (Liquids Logistics segment) $ 8,957 Canadian dollars (Liquids Logistics segment) $ 124 Changes in commodity prices may also impact the volumes that we are able to transport, dispose, store and market, which also impact our cash flows.
For our Class B Preferred Units, distributions on and after July 1, 2022 will accumulate at a percentage of the $25.00 liquidation preference equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) plus a spread of 7.213%.
On or after July 1, 2024, the holders of our Class D Preferred Units can elect, from time to time, for the distributions to be calculated based on a floating rate equal to the applicable three-month LIBOR interest rate (or alternative rate as determined in the Partnership Agreement) plus a spread of 7.00% (“Class D Variable Rate”, as defined in the Partnership Agreement).
The crude oil, natural gas liquids, and refined and renewables products industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. We have no control over market conditions.
Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. The crude oil, natural gas liquids, and refined and renewables products industries are “margin-based” and “cost-plus” businesses in which our realized margins depend on the differential of sales prices over our supply costs.
The ABL Facility is variable-rate debt with interest rates that are generally indexed to the Wall Street Journal prime rate or LIBOR interest rate (or successor rate, which has since been determined to be an adjusted forward-looking term rate based on the secured overnight financing rate).
Conversely, changes in interest rates impact the fair value of our fixed-rate debt but do not impact its cash flows. 85 The ABL Facility is variable-rate debt with interest rates that are generally indexed to the prime rate or SOFR, an adjusted forward-looking term rate based on the secured overnight financing rate.
Removed
Conversely, changes in interest rates impact the fair value of our fixed-rate debt but do not impact its cash flows.
Added
On July 1, 2022, the Class B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Class B Preferred Units”) distribution rate changed from a fixed rate of 9.00% to a floating rate of the three-month London Interbank Offered Rate (“LIBOR”) interest rate (4.77% for the quarter ended March 31, 2023) plus a spread of 7.213%.
Removed
In addition, on and after certain dates, distributions for our Class B Preferred Units and Class C Preferred Units will be calculated using the applicable three-month LIBOR interest rate (or alternative rate as determined in the partnership agreement) plus a spread.
Added
A change in interest rates of 0.125% would result in an increase or decrease of our Class B Preferred Unit distribution of $0.1 million, based on the Class B Preferred Units outstanding at March 31, 2023.
Removed
Procedures and limits for managing commodity price risks are specified in our market risk policy. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel.
Added
Each Class D Variable Rate election shall be effective for at least four quarters following such election. Commodity Price Risk Our operations are subject to certain business risks, including commodity price risk.
Removed
See “Critical Accounting Estimates” above for a discussion of how we determine the fair value of our financial derivative instruments.

Other NGL 10-K year-over-year comparisons