Enable Midstream Partners (ENBL) 10-K2020 FY Annual report

Forward-looking statements speak only as of the date on which they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.

An investment in our common units involves a significant degree of risk. Below is a summary of certain risk factors that you should consider in evaluating us and our common units. However, this list is not exhaustive. Before you invest in our common units, you should carefully consider the risk factors discussed or referenced below and under Item 1A. “Risk Factors” in this Annual Report on Form 10-K. If any of the risks discussed below and under Item 1A. “Risk Factors” were actually to occur, our business, financial position or results of operations could be materially adversely affected, which may adversely impact our cash available for distribution or the trading price of our common units.

Enable Midstream Partners, LP owns, operates and develops midstream energy infrastructure assets strategically located to serve our customers. We are traded on the NYSE under the symbol “ENBL.” Our general partner is owned by CenterPoint Energy and OGE Energy. In this report, the terms “Partnership” and “Registrant” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to Enable Midstream Partners, LP together with its consolidated subsidiaries.

Our assets and operations are organized into 2 reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. Our transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers.

Our natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Our crude oil gathering assets are located in Oklahoma and North Dakota and serve crude oil production in the Anadarko and Williston Basins. Our natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma and our investment in SESH, a pipeline extending from Louisiana to Alabama.

Our primary business objective is to increase the cash available for distribution to our unitholders over time and maintain our financial flexibility. We strive to meet this objective through the following strategies:

Our website address is www.enablemidstream.com. Documents and information on our website are not incorporated by reference in this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed with or furnished to the SEC are available, free of charge, on our website as soon as reasonably practicable after we electronically file or furnish such materials.

Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. We report natural gas gathered, processed and transported by energy content stated in millions or trillions of British thermal units (MMBtu or TBtu). We report natural gas processing, transportation, and storage capacity by volume stated in millions or billions of cubic feet (MMcf or Bcf), and we also report processing inlet volumes in millions of cubic feet. An MMcf of pipeline quality natural gas generally has an energy content of 1,000 MMBtu. We report crude oil, condensate and produced water capacities, crude oil, condensate, and produced water gathered, NGLs production capacity, and NGLs produced and sold, by volume stated in barrels or thousands of barrels (Bbl or MBbl).

We own and operate substantial natural gas gathering and processing and crude oil, condensate and produced water gathering assets primarily in five states. Our gathering and processing operations consist primarily of natural gas gathering and

Our natural gas gathering systems consist of networks of pipelines that collect natural gas from points at or near our customers’ wells for delivery to plants for processing or pipelines for transportation. Natural gas is moved from the receipt points to the delivery points on our gathering systems by the use of compression.

The following table sets forth information with respect to our natural gas processing plants as of or for the year ended December 31, 2020:

Natural gas that is gathered, and when applicable, processed, is typically redelivered to our customers at interconnections with transportation pipelines. Our gathering lines interconnect with both our interstate and intrastate pipelines, as well as other interstate and intrastate pipelines, including the Acadian, ANR, ETC Tiger, Fayetteville Express Pipeline, Gulf South, Natural Gas Pipeline Company of America, Northern Natural, Panhandle Eastern, Ozark Gas Transmission, Regency, Southern Natural Gas, Tennessee Gas, Texas Eastern, Texas Gas, Oklahoma Gas Transmission and Energy Transfer Katy pipelines. These connections provide producers with access to a variety of natural gas markets.

Natural gas is comprised primarily of methane, but at the wellhead natural gas may contain varying amounts of NGLs which may be separated at our processing plants from the wellhead natural gas. We typically purchase the NGLs produced at our processing plants, and most of the NGLs are delivered into third-party pipelines and transported to Conway, Kansas, or Mont Belvieu, Texas, where the NGLs are exchanged for fractionated NGLs that are sold under contract or on the spot market. At our Cox City, Calumet and Wetumka plants, we operate depropanizers that allow us to extract propane from the NGL stream

Our Williston Basin crude oil and produced water gathering assets were designed and built to primarily serve the crude oil production of XTO. On our systems, crude oil is received on crude oil gathering pipelines near our customers’ wells for delivery to third-party transportation pipelines, and produced water is received by produced water gathering pipelines for delivery to third-party disposal wells. We do not take title to crude oil or produced water gathered on those systems, and we do not own or operate produced water disposal wells. Crude oil gathered on our Williston Basin gathering systems in Dunn and McKenzie Counties can be delivered to our interconnections, which can be further delivered to the BakkenLink Pipeline and the Dakota Access Pipeline. Crude oil gathered on our Williston Basin gathering systems in Williams and Mountrail Counties can be delivered to our interconnection, which can be further delivered to the Enbridge North Dakota Pipeline and the Dakota Access Pipeline.

For the year ended December 31, 2020, 83% of our gathering and processing gross margin was fee-based, and the remaining 17% of our gathering and processing gross margin was primarily from sales of commodities, including natural gas, natural gas liquids and condensate received under percent-of-proceeds, percent-of-liquids and keep-whole arrangements. For the year ended December 31, 2020, 61%, 33% and 6% of our natural gas processing inlet volumes were processed under arrangements that were fee-based, percent-of-proceeds or percent-of-liquids, and keep-whole, respectively.

Certain of our natural gas gathering contracts across our operating areas contain minimum volume commitments from our customers. Additionally, a portion of the crude oil gathered by our crude oil gathering system in the Williston Basin is under a contract with a minimum volume commitment. Under a minimum volume commitment, a customer agrees to either deliver a minimum volume of natural gas or crude oil to our system for service or pay the service fees for the minimum volume of natural gas or crude oil regardless of whether or not the minimum volume of natural gas or crude oil is delivered. We call any payment for the difference between the volume gathered and the minimum volume committed a shortfall payment. As of December 31, 2020, the percentage of our gathering and processing gross margin attributable to natural gas and crude oil gathering contracts with minimum volume commitments, and the volume commitment-weighted average remaining terms of those contracts, were as follows:

For our gathering and processing contracts that do not have minimum volume commitments, we strive to obtain acreage dedications. Under an acreage dedication, a customer agrees to deliver all of the natural gas, crude oil or condensate produced from a given area to our system for gathering, and, if applicable, processing. As of December 31, 2020, the gross acres dedicated under gathering agreements and the volume-weighted average remaining term for all gathering and processing contracts were as follows:

We own and operate interstate and intrastate natural gas transportation and storage systems primarily across nine states. Our transportation and storage systems consist primarily of our interstate systems, EGT and MRT, our intrastate system, EOIT, and our investment in SESH. Our transportation and storage assets transport natural gas from areas of production and interconnected pipelines to power plants, LDCs and industrial end users as well as interconnected pipelines for delivery to additional markets. Our transportation and storage assets also provide facilities where natural gas can be stored by customers.

The following table sets forth certain information regarding our transportation and storage assets as of or for the year ended December 31, 2020:

Our transportation and storage assets were designed and built to primarily serve large natural gas and electric utilities in our areas of operation. In addition, our transportation and storage assets serve natural gas producers, industrial end users and natural gas marketers. For the year ended December 31, 2020, our top transportation and storage customers by revenue were affiliates of CenterPoint Energy, Spire Inc. (Spire), Continental, OGE Energy, American Electric Power Co. (AEP), Ovintiv, Midcontinent Express Pipeline LLC, BP PLC, Entergy Corporation, and Associated Electric Cooperative.

From time to time, our transportation and storage business involves the construction of natural gas pipelines as needed to serve our existing and new customers. For example, during the year ended December 31, 2020, we invested $49 million of

Our interstate transportation and storage business consists of EGT and MRT. As interstate pipelines, EGT and MRT are subject to regulation as natural gas companies by FERC under the NGA.

Customer demand for natural gas transportation and storage services: on EGT and MRT is usually higher in winter, primarily to due to LDC demand to serve residential and commercial natural gas requirements and on EOIT and SESH is usually higher in summer, primarily due to electric utility demand for natural gas.

Competition for our natural gas transportation and storage systems are primarily a function of rates, terms of service, flexibility and reliability. For natural gas transportation and storage, rates include both fees for services and retained fuel. EGT competes with a variety of other interstate and intrastate pipelines across Texas, Oklahoma, Arkansas and Louisiana. MRT competes with various intrastate and interstate pipelines serving the St. Louis market. EOIT competes with a variety of interstate and intrastate pipelines across Oklahoma. SESH competes with other interstate and intrastate pipelines providing access to the Southeast power generation markets. For more information related to trends and uncertainties, please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Trends and Uncertainties Affecting Results of Operations.”

Our business is subject to a wide range of government regulations. The regulations with the most significant impact on our business are economic regulations, safety and health regulations and environmental regulations.

EGT, MRT and SESH are subject to regulation by FERC and are considered “natural gas companies” under the NGA. The NGA prohibits natural gas companies from granting any undue preference or advantage, or unduly discriminating against any person with respect to pipeline rates or terms and conditions of service, including unduly discriminatory or preferential access to information. FERC authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce includes:

From time-to-time, our interstate pipelines file rate cases with FERC which may propose, among other things increases in the maximum tariff rates for firm and interruptible services. For example, MRT filed general rate cases with FERC pursuant to Section 4 of the Natural Gas Act on June 29, 2018 (the 2018 Rate Case) and on October 30, 2019 (the 2019 Rate Case). On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. The settlements included contract extensions for most firm transportation and storage customers through July 31, 2024. Upon issuance of the order and approval of the settlements of the MRT rate cases, the Partnership recognized $17 million of revenues from amounts previously held in reserve related to transportation and storage services performed in 2019. In May 2020, $21 million previously held in reserve was refunded to customers, which was inclusive of interest.

FERC issued a Notice of Inquiry on April 19, 2018 (April 2018 NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. Though FERC has not taken any further action regarding the April 2018 NOI, we are unable to predict what, if any, changes may be proposed as a result of the April 2018 NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any changes in this policy would materially affect our plans and operations.

In addition, the Energy Policy Act of 2005 amended the Natural Gas Act to (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978 and FERC rules, regulations or orders thereunder. The anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional transactions. As a result of the Energy Policy Act of 2005, the FERC has the authority to impose civil penalties for violations of these statutes and FERC rules, regulations and orders, up to approximately $1.31 million per day, per violation.

In Oklahoma, our intrastate pipeline system, EOIT, is subject to limited regulation by the OCC. Oklahoma has a non-discriminatory access requirement, which is subject to a complaint-based review. EOIT’s rates and terms of service are not subject to regulation by the OCC.

Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. An intrastate natural gas pipeline system may transport natural gas in interstate commerce provided that the rates, terms and conditions of such transportation service comply with FERC’s regulations under Section 311 of the NGPA and Part 284 of FERC’s regulations. The NGPA regulates, among other things, the provision of transportation and storage services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a LDC served by an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The rates under Section 311 are maximum rates and an intrastate pipeline may agree to discount contractual rates at or below such maximum rates. Rates for service pursuant to Section 311 of the NGPA are

Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by FERC for Section 311 service, or failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal NGA jurisdiction by FERC and/or the imposition of administrative, civil and criminal penalties, as described in the “—Interstate Natural Gas Pipeline Regulation” section above.

EOIT currently has two zones under its Section 311 transportation rate structure—an East Zone and a West Zone. For Section 311 service, EOIT may charge up to its maximum established zonal East and West interruptible transportation rates for interruptible transportation in one zone or cumulative maximum rates for transportation in both zones. Finally, EOIT may charge the applicable fixed zonal fuel percentage(s) for the fuel used in transporting natural gas under Section 311 on our system. The fixed zonal fuel percentages are the same for firm and interruptible Section 311 services.

Under FERC Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA are required to report on a quarterly basis via FERC Form 549D more detailed information and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through an electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends FERC’s periodic review of the rates charged by the subject pipelines from three to five years. In Order No. 735-A, FERC generally reaffirmed Order No. 735 requiring Section 311 service providers to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract. Our intrastate storage assets at the Wetumka Storage Field offer both fee-based firm and interruptible storage services under Section 311 of the NGPA pursuant to terms and conditions specified in our statement of operating conditions for gas storage at market-based rates. Our intrastate Stuart Storage Field currently is used exclusively to provide intrastate storage service, even though FERC previously authorized the use of that storage facility for Section 311 interstate service.

Section 1(b) of the NGA exempts natural gas gathering and processing facilities from the jurisdiction of FERC. Although FERC has not made formal determinations with respect to all of our facilities that we consider to be natural gas gathering facilities, management believes that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is a natural gas gathering pipeline and is therefore not subject to FERC’s NGA jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated natural gas gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are natural gas gathering facilities on a case-by-case basis, so the classification and regulation of our natural gas gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.

Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our natural gas gathering operations could also be subject to additional safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities, such as the new rules being promulgated by PHMSA. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations.

Crude oil gathering pipelines that transport crude oil in interstate commerce may be regulated as common carriers by FERC under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. Our crude oil gathering systems in the Williston Basin transport crude oil in interstate commerce. The ICA and FERC regulations require that rates for interstate service pipelines that transport crude oil and refined petroleum products (collectively referred to as “petroleum pipelines”) and certain other liquids, be just and reasonable and are to be non-discriminatory or not confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. Under the ICA, FERC or interested persons may challenge existing or changed rates or services. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. FERC may also order a pipeline to change its rates and may require a common carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.

If our rate levels were investigated by FERC, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs, including:

Under the ICA, FERC does not have authority over the placement of crude oil transportation assets nor over the abandonment of facilities or services. Accordingly, no approval from FERC is necessary prior to placing a new petroleum pipeline project in operation. However, FERC highly encourages carriers to file a Petition for Declaratory Order to seek regulatory assurances for key terms of service offered during an open season. As long as the shippers on our Williston Basin crude oil gathering system move crude oil in interstate commerce, our crude oil gathering system will not be regulated by the North Dakota Public Service Commission.

FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. Many existing pipelines, including our Williston Basin crude oil gathering systems, utilize the FERC oil index to change transportation rates annually every July 1. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by the Producer Price Index plus 1.23%. On December 17, 2020, FERC established a new index level of Producer Price Index plus 0.78% for the five-year period from July 1, 2021, to June 30, 2026. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates, including indexed rates, beginning July 1, 2021.

Our crude oil and condensate gathering system in the Anadarko Basin is located in Oklahoma and is subject to limited regulation by the OCC. Crude oil and condensate gathering systems are common carriers under Oklahoma law and are prohibited from unjust or unlawful discrimination in favor of one customer over another. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. Our crude oil and condensate gathering results of operations and cash flows could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.

Our pipeline facilities are subject to regulation under federal pipeline safety statutes and comparable state statutes. Federal pipeline safety statutes include the Natural Gas Pipeline Safety Act of 1968 (NGPSA), which provides for safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, and the Hazardous Liquid Pipeline Safety Act of 1979 (HLPSA), which provides for safety requirements for the design, construction, operation and maintenance of hazardous liquids pipelines facilities, including NGL and crude oil pipelines. The NGPSA and the HLPSA have been subject to a number of amendments and supplements including the Pipeline Safety Act of 1992, the Accountable Pipeline Safety and Partnership Act of 1996, the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the PIPES Act of 2006), the Pipeline Safety, Regulatory Certainty, Job Creation Act of 2011 (the 2011 Pipeline Safety Act), the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the SAFE PIPES Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (the PIPES Act of 2020).

Passed as part of the Consolidated Appropriations Act of 2021, the PIPES Act of 2020 reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location

We are regulated under federal pipeline safety statutes by DOT through PHMSA. PHMSA sets and enforces pipeline safety regulations and standards. PHMSA’s enforcement authority includes the ability to assess civil penalties for violations of pipeline safety regulations. PHMSA has civil penalty authority of up to $222,504 per day per violation, with a maximum of $2,225,034 for any related series of violations. In addition to governing the design, construction, operation and maintenance of natural gas and hazardous liquids pipeline facilities, PHMSA’s regulations require the following for certain pipelines: an inspection and maintenance plan; an integrity management program, which includes the determination of pipeline integrity risks and periodic assessments of pipeline segments in high consequence areas; a drug and alcohol testing program; an operator qualification program, which includes training for personnel performing tasks covered by pipeline safety rules; a public awareness program, which provides relevant information to residents, public officials and emergency responders; and a control room management plan.

As part of regulating pipeline safety, PHMSA periodically promulgates pipeline safety regulations. For example, in October 2019, PHMSA published three final rules on pipeline safety. The Enhanced Emergency Order Procedures rule (effective December 2, 2019) implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if unsafe conditions or practices, or a combination thereof, constitutes or causes an imminent hazard. The Safety of Hazardous Liquid Pipelines rule (effective July 1, 2020) expands PHMSA’s regulation of the safety of hazardous liquid pipelines by extending reporting requirements to certain hazardous liquid gravity flow and rural gathering pipelines, establishing new requirements for integrity management programs for hazardous liquid pipelines in high consequence areas (HCAs) and certain other hazardous liquid pipelines, and expanding various inspection and leak detection requirements. The new integrity management requirements provide that operators of onshore pipeline segments that can accommodate in-line inspection (ILI) tools that are not currently subject to integrity management requirements to complete assessments using ILI tools at least once every ten years. The new integrity management rules also require that all hazardous liquids pipelines located in HCAs or areas that could affect HCAs be capable of accommodating ILI tools within 20 years unless certain limited exceptions apply. The Safety of Gas Transmission Pipelines rule (effective July 1, 2020) requires operators of certain gas transmission pipelines to reconfirm the MAOP of their lines and establishes a new Moderate Consequence Area (MCA) for determining regulatory requirements for gas transmission pipeline segments outside of HCAs. An MCA for gas pipelines is also based on population totals in addition to the existence of certain principal, high-capacity roadways, but an MCA does not meet the relative higher population totals required to be deemed an HCA and therefore such areas are located outside of HCA coverages. The rule also establishes new requirements for conducting baseline assessments and incorporates industry standards and guidelines as well as new requirements for integrity management on pipeline mileage located outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years of the publication date of the rule and at least once every 10 years thereafter. We estimate that we will incur an average of $10 million per year in additional costs to comply with these rules beginning in 2022.

PHMSA is working on two additional rules related to gas pipeline safety. The rule entitled “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments” is expected to adjust the repair criteria for pipelines in HCAs, create new criteria for pipelines in non-HCAs, and strengthen integrity management assessment requirements. The rule entitled “Safety of Gas Gathering Pipelines” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas. These additional rulemakings are expected to be published and effective in 2021. We will begin the process of assessing the impact of these rules when they are published.

Separately, on February 12, 2020, PHMSA published a final rule (effective March 13, 2020) regarding the safety of underground natural gas storage facilities. This rule maintains several elements from the earlier interim rule, incorporating American Petroleum Institute Recommended Practices 1170 and 1171 in PHMSA regulations; revises the definition of underground natural gas storage facility; and clarifies certain reporting and notification criteria. Although the rule may result in increased compliance costs, the changes are not expected to have a material impact on our future costs of operations and revenue from operations.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for administering and enforcing intrastate pipeline regulations at least as stringent as the federal standards. For example, the OCC administers the intrastate pipeline safety program in Oklahoma, and the Texas Railroad Commission administers the intrastate pipeline safety program in Texas. In practice, states vary in their authority and capacity to address pipeline safety.

We incur significant costs in complying with federal and state pipeline safety laws and regulations and otherwise administering our pipeline safety program. In 2020, we incurred maintenance capital expenditures and operation and maintenance expenses of $66 million under our pipeline safety program, including costs related to integrity assessments and repairs, threat and risk analyses, implementing preventative and mitigative measures, and conducting activities to support MAOP or MOP. We currently estimate that we will incur maintenance capital expenditures and operation and maintenance expenses of up to $68 million in 2021 under our pipeline safety program. While we cannot predict the outcome of pending or future legislative or regulatory initiatives, we anticipate that pipeline safety requirements will continue to become more stringent over time. As a result, we may incur significant additional costs to comply with the new pipeline safety regulations, the pending pipeline safety regulations, and any new pipeline safety laws and regulations associated with our pipeline facilities, which could have a material impact on our costs of operations and revenue from operations.

In addition to these pipeline safety requirements, we are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Act of 1970 (OSHA) and comparable state statutes, whose purpose is to protect the safety and health of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. We have an internal program of inspection designed to monitor and enforce compliance with worker safety and health requirements. We are also subject to EPA Risk Management Program (RMP) regulations. Under the RMP regulations, we have implemented a program to prevent or minimize the consequences of accidental chemical releases at our facilities that use, manufacture and store particular hazardous chemicals. The RMP regulations were amended by the EPA under a final rule published December 19, 2019. The amendments were intended to better address potential security risks and ensure regulatory consistency, and we do not anticipate that they will significantly increase our cost of compliance.

Our operations are subject to extensive federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business activities in many ways, such as requiring permits to conduct our activities, limiting our emissions of materials into the environment, requiring emissions control equipment, regulating our construction to mitigate harm to protected species, restricting the way we can handle or dispose of waste, and requiring remediation to mitigate the impact of materials discharged into the environment in connection with our current operations or attributable to former operations. Compliance with these laws and regulations increases our capital expenditures and operating expenses, and any failure to comply with these laws and regulations could result in the assessment of significant administrative, civil and criminal liabilities, injunctions or other penalties.

We have adopted policies, procedures, and practices to comply with environmental laws and regulations, and we incur significant costs in connection with compliance. In 2020, we incurred approximately $4 million in maintenance capital expenditures in connection with routine environmental compliance with existing laws and regulations, such as environmental controls, monitoring, testing and permit compliance. We expect to incur $3 million in 2021 in maintenance capital expenditures for routine environmental compliance with existing laws and regulations. We also incur, and expect to continue to incur, additional costs in connection with spill response and construction. With respect to construction, existing environmental laws and regulations impact the cost of planning, design, permitting, installation, and start-up. While we cannot predict the outcome of legislative or regulatory initiatives, we anticipate that environmental requirements will continue to become more restrictive over time. As a result, we may incur significant additional costs to comply with any new environmental laws and regulations applicable to our operations. For more information, please read Item 1A. “Risk Factors–Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.”

Our operations are subject to the federal CAA, as amended, and comparable state laws and regulations. These laws and

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our crude oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years; in September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, on January 20, 2021, President Biden signed an executive order calling for the suspension, revision, or recission of the September 2020 rule and the establishment of new standards applicable to existing oil and gas operations, including the transmission and storage segments. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States had withdrawn from the agreement, President Biden has signed executive orders recommitting the United States to the agreement and calling on the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by the recently elected administration. These have included promises to limit emissions and curtail the production of oil and gas on federal lands, such as through the cessation of leasing public land for hydrocarbon development. For example, on January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors. Separately, on January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order that, among other things, imposed a temporary suspension on the issuance of fossil fuel authorizations, including leases and permits on federal lands. Although the order says it does not limit existing operations under valid leases, on January 27, 2021, President Biden signed an executive order suspending new oil and gas leasing on federal lands, pending completion of a review of the federal government’s oil and gas permitting and leasing practices. Other actions that could be pursued may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities. Additionally, following the election of President Biden and a Democratic Congress, there is an increased chance for climate change legislation to be promulgated by the federal government. Litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest crude oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change. Suits have also been brought against such companies under shareholder and consumer protection laws, alleging that the companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, President Biden signed

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the crude oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation and financial risks may result in our crude oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.

National Environmental Policy Act (NEPA) provides for an environmental impact assessment process in connection with certain projects that involve federal lands or require approvals by federal agencies. The NEPA process implicates a number of other environmental laws and regulations, including the Endangered Species Act, Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden Eagle Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act. The NEPA review process can be lengthy and subjective and can cause delays in projects. Our projects that are subject to the NEPA can include pipeline construction and pipeline integrity projects that involve federal lands or require approvals by federal agencies. Ineffective implementation of the NEPA process could cause significant impacts to such projects in the form of delays or significant compliance costs. On July 15, 2020, the Council on Environmental Quality issued a final rulemaking to amend the regulations for implementing the procedural provisions of the NEPA. This rulemaking modernizes and clarifies these regulations, which had not been comprehensively revised since their promulgation in 1978. However, these amendments may be subject to change under the new presidential administration.

Certain federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures. The designation of previously unprotected species, such as the Lesser Prairie Chicken, as threatened or endangered in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our customer’s exploration and production activities that could have an adverse impact on demand for our services. Portions of our areas of operations are designated as critical or suitable habitat for threatened and endangered species. If additional portions of our areas of operations were designated as critical or suitable habitat for threatened and endangered species, it could adversely impact the cost of operating our systems and of constructing new facilities. Compliance with all applicable laws providing special protection for designated species has not posed a material cost on our business and operations to date.

Our operations are subject to federal and state environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. For instance, our operations are subject to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA or Superfund), as amended, and comparable state cleanup laws that impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may, jointly and severally, be subject to strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible

Our operations also generate solid and hazardous wastes that are subject to the federal Resource Conservation and Recovery Act of 1976 (RCRA) as well as comparable state laws. While RCRA regulates both solid and hazardous wastes, it imposes detailed requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly disposal requirements. Such changes to the law could have an impact on our capital expenditures and operating expenses.

Our operations are subject to the federal CWA and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from some of our facilities. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. In 2015, the EPA and the Corps published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States (WOTUS). Following the change in U.S. presidential administrations, there have been several attempts to modify or eliminate this rule. For example, on January 23, 2020, the EPA and the Corps finalized the Navigable Waters Protection Rule, which narrows the definition of “waters of the United States” relative to the 2015 WOTUS rule. Legal challenges to both this and prior revisions to the definition of WOTUS are ongoing, and it is possible that the new presidential administration could propose a broader interpretation of the CWA’s jurisdiction. Therefore, the scope of jurisdiction under the CWA is uncertain at this time, and any increase in scope could result in increased costs or delays with respect to obtaining permits for such activities as dredge and fill operations in wetland areas. Separately, spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with many of these requirements.

Certain of our operations are also subject to the Oil Pollution Act of 1990 (OPA) which amends and augments oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. Under OPA, joint and several liability, without regard to fault, may be assigned for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of a crude oil discharge or substantial threat of discharge, we may be liable for costs and damages.

In April 2020, the federal district court for the district of Montana issued an order vacating the NWP 12 for alleged failure to comply with consultation requirements under the federal Endangered Species Act. Pipeline companies and other developers of underground infrastructure frequently rely upon NWP 12 and other general permits for construction and maintenance projects in jurisdictional wetland areas. Subsequent proceedings limited this order to the Keystone XL pipeline, which is not related to our operations. Additionally, in response to the vacatur, the Corps published a reissuance of the NWP 12 for oil and natural gas pipeline activities, including certain revisions to the conditions for the use of NWP 12; however, the rule may be subject to further revisions or suspension under the Biden administration. While the full extent and impact of the court’s action, as well as the NWP 12 re-issuance, is unclear at this time, a disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are required to seek individual permits from the Corps.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state’s commission that regulates oil and gas production. A number of federal agencies, including the EPA and the U.S. Department of Energy, have

State and federal regulatory agencies also recently focused on a possible connection between the operation of injection wells used for oil and gas wastewater disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity: Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity through restrictions on disposal wells or enhanced well construction and monitoring requirements. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the wastewater disposal process.

If new laws or regulations that significantly restrict hydraulic fracturing or wastewater disposal wells are adopted, such laws could lead to greater opposition to, and litigation concerning, related oil and gas producing activities and to operational delays or increased operating costs for our customers, which in turn could reduce the demand for our services. For more information, please read Item 1A. “Risk Factors–Risks Related to Our Business–Increased regulation of hydraulic fracturing and wastewater injection wells could result in reductions or delays in natural gas production by our customers, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.”

As of December 31, 2020, we have approximately 1,706 employees, including 75 employees seconded from OGE Energy. These employees remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy, in order to continue their participation in OGE Energy’s defined benefit and retiree medical plans. Please read Item 13. “Certain Relationships and Related Transactions, and Director Independence—Employee Secondment” for a description of the agreements governing these relationships.

Of our approximately 1,706 employees: 1,231 are employed in our operations departments, which include field operations, pipeline safety, engineering and construction, and safety, health and technical services and 475 are employed in our administrative departments, which include accounting, commercial, enterprise technology, finance, human resources, legal and other functions; and 1,706 are employed in full-time positions and none are employed in part-time positions. Because our workforce primarily consists of full-time, skilled labor and professionals, we seek to attract and retain employees with competitive pay and benefits. During 2020, our voluntary turnover rate was 3.7% and our total turnover rate was 10%. Because voluntary turnover includes both employees who retire and employees who voluntarily leave the Partnership for other reasons, we closely monitor retirement eligibility and proactively engage in succession planning. As of December 31, 2020, we have approximately 163 employees who are retirement eligible, of which 66 of these retirement eligible employees accepted an offer under our voluntary retirement program. Please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Trends and Uncertainties” for more information related to our voluntary retirement program and impact of the COVID 19 pandemic on our workforce.

We also seek to attract and retain employees by creating and maintaining a culture based upon our values of safety, integrity, customer service, teamwork and accountability. Based on these values, we prioritize the well-being and safety of our employees. Safety is not only a core value for the Partnership, it is critical to our business. We know that our success as a company depends on providing a safe working environment for employees. To assess the success of our safety program, we monitor our Total Recordable Incident Rate (TRIR), Lost Time Incident Rate (LTIR) and Preventable Vehicle Incident Rate (PVIR). For 2020, our TRIR was 1.205, LTIR was 0.663 and PVIR was 0.920.

As contracts with our existing suppliers and customers expire, we generally seek to negotiate extensions or renewals of those contracts or enter into new contracts with other suppliers and customers. We may be unable to extend or renew existing contracts or enter into new contracts on favorable commercial terms, if at all. Depending on prevailing market conditions at the time of an extension or renewal, gathering and processing customers with fee-based contracts may desire to enter into contracts under different fee arrangements, and gathering and processing customers with contracts that contain minimum volume commitments may desire to enter into contracts without minimum volume commitments. Likewise, our transportation and storage customers may choose not to extend or renew expiring contracts based on the economics of the related areas of production. To the extent we are unable to renew or replace our expiring contracts on terms that are favorable to us, if at all, or successfully manage our overall contract mix over time, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

Our businesses are dependent on the drilling and production of natural gas and crude oil. We have no control over the level of drilling activity in our areas of operation, or the amount of natural gas, NGLs and crude oil reserves associated with wells connected to our systems, or the amount of natural gas, NGLs and crude oil produced from the wells connected to our systems. In addition, as the rate at which production from wells currently connected to our system naturally declines over time, our gross margin associated with those wells will also decline. To maintain or increase throughput levels on our gathering and transportation systems and the asset utilization rates at our natural gas processing plants, our customers must continually obtain new natural gas, NGLs and crude oil supplies. Drilling activity in the areas served by our systems significantly impacts our ability to obtain new volumes of natural gas, NGLs and crude oil on our systems. If we are not able to obtain new volumes of natural gas, NGLs and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering, processing, transportation and storage facilities would decline, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders. We have no control over producers or their drilling and production decisions, which are affected by, among other things:

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems and in our processing plants, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, we may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time.

We compete with other midstream service providers in our areas of operation. The principal elements of competition for both gathering and processing services and transportation and storage services are rates, terms of service, flexibility and reliability. Our competitors include other midstream service providers, including those affiliated with producers, that may have greater financial resources or greater access to new volumes of natural gas, NGLs and crude oil than we do. Our competitors may create additional competition by expanding existing or constructing new gathering, processing, transportation and storage systems. Our producer customers may become competitors by developing their own midstream systems. Excess gathering processing, transportation or storage capacity in the areas we serve may increase competitive pressure by decreasing rates and adversely impact our ability to renew existing or enter into new contracts. Natural gas, NGLs and crude oil used as or to produce fuel compete with other forms of energy, including electricity and coal. Increased demand for one form of energy over another could lead to a reduction in demand for associated midstream services. All of these competitive pressures could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Our financial position, results of operations and ability to make cash distributions to unitholders could be negatively affected by adverse changes in the prices of natural gas, NGLs and crude oil depending on factors that are beyond our control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, LNG, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption, global or national health concerns, and the extent of governmental regulation and taxation. For example, the price of, and demand for, natural gas, NGLs and crude oil declined significantly in response to the ongoing spread and economic effects of the COVID-19 pandemic, including significant governmental measures being implemented to control the spread of the virus, including quarantines, travel restrictions and business shutdowns, and Russia’s March 2020 rejection of a plan backed by Saudi Arabia and other members of OPEC to reduce production of crude oil in response to declining global demand. Following the rejection of the plan, Saudi Arabia significantly reduced the prices at which it sells crude oil, and both Saudi Arabia and Russia announced plans to increase production. While a coalition of 23 nations led by Saudi Arabia and Russia subsequently agreed to reduce production of crude oil by 9.7 million barrels per day in May and June of 2020, NGL and

Our natural gas processing arrangements expose us to commodity price fluctuations. In 2020, 6%, 33%, and 61% of our processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids, and fee-based, respectively. If the price at which we sell natural gas or NGLs is less than the cost at which we purchase natural gas or NGLs under these arrangements, then our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected. We use certain derivative instruments to manage our commodity price risk exposures.

At any given time, our overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that we are a net buyer of natural gas) and a net long position in NGLs (meaning that we are a net seller of NGLs). As a result, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected to the extent the price of NGLs decreases in relation to the price of natural gas.

A global or national pandemic, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, travel restrictions and business shutdowns, to address the COVID-19 pandemic and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. For example, many of our employees have been temporarily required to work remotely which may disrupt our operations or increase the risk of a cybersecurity incident. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.

The effects of the COVID-19 pandemic and concerns regarding its continued global spread have negatively impacted domestic and international demand for natural gas, NGLs and crude oil, which has and could continue to contribute to price volatility and materially and adversely affect our customers’ operations and future production, resulting in less demand for our services and/or the reduction of commercial opportunities that might otherwise be available to us. The effects of the COVID-19 pandemic have also negatively impacted domestic and international economic conditions, which has and could continue to contribute to price declines and volatility in the financial markets. While it is not possible to predict their extent or duration, these economic conditions could materially and adversely affect the availability of debt or equity financing to us, which may result in a significant reduction of our liquidity.

We have been authorized by FERC to provide transportation and storage services at our facilities at negotiated rates. As of December 31, 2020, approximately 37% of our aggregate contracted firm transportation capacity on EGT and MRT and 52% of our aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies. If our costs increase and we are not able to recover any shortfall of revenue associated with our negotiated rate contracts, the cash flow realized by our systems could decrease and, therefore, the cash we have available for distribution to our unitholders could also decrease.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We may obtain the rights to construct and operate our pipelines for a specific period of time on lands owned by governmental agencies, American Indian tribes, or other third parties, including on American Indian allotments, title to which is held in trust by the United States. A loss of these rights, through our inability to renew right-of-way contracts or otherwise, could cause us to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Equity method investments are evaluated for impairment when events or circumstances indicate that the carrying value of the investment might not be recoverable. An impairment of an equity method investment is recognized if the fair value of the investment as a whole, and not the underlying assets, has declined and the decline is other than temporary. An example of an investment that we account for under the equity method is our investment in SESH. If we enter into additional joint ventures, we could have additional equity method investments. At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and then current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH for the year ended December 31, 2020, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Consolidated Statements of Income.

We could experience future events or circumstances that result in an impairment of long-lived assets, including intangible assets, equity method investments, or goodwill. If we recognize an impairment, we would take an immediate non-cash charge to

These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could adversely affect our results of operations. We are not fully insured against all risks inherent in our business. We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles. We have business interruption insurance coverage for some but not all of our operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without adversely affecting our financial position, results of operations and our ability to make cash distributions to unitholders.

We and our subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Our business is dependent on our ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

As of December 31, 2020, we have 75 employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who are seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. If seconding is terminated, employees of OGE Energy that we determine to hire are under no obligation to accept our offer of employment on the terms we provide, or at all.

We have become increasingly dependent on the systems, networks and technology that we use to conduct almost all aspects of our business, including the operation of our gathering, processing, transportation and storage assets, the recording of commercial transactions, and the reporting of financial information. We depend on both our own systems, networks, and technology as well as the systems, networks and technology of our vendors, customers and other business partners. Any disruption of these systems, networks and technology could disrupt the operation of our business. Disruptions can result from a variety of causes, including natural disasters, the failure of software or equipment, and manmade events, such as cybersecurity attacks or information security breaches. Cybersecurity attacks and information security breaches could result in the unauthorized use of confidential, proprietary or other information and in the disruption of our critical business functions and operations, adversely affecting our reputation, and subjecting us to possible legal claims and liability. In addition, we are not fully insured against all cybersecurity risks.

As cybersecurity attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cybersecurity attacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. To date we have not experienced any material losses relating to cybersecurity attacks; however, there can be no assurance that we will not suffer such losses in the future. Consequently, it is possible that any of these occurrences, or a combination of them, could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Our gathering, processing, transportation and storage assets may be targets of terrorist activities or other physical security threats that could disrupt our ability to conduct our business. It is possible that any of these occurrences, or a combination of them, could adversely affect our financial position, results of operations, and ability to make cash distributions to unitholders. In addition, any physical damage to our assets resulting from acts of terrorism may not be fully covered by our insurance.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are unable to maintain adequate controls over our financial processes and reporting in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

At the time the Energy Transfer merger is completed, each issued and outstanding common unit of the Partnership will be converted into the right to receive the merger consideration of 0.8595 of one common unit representing limited partner interests in Energy Transfer. The exchange ratio for the merger consideration is fixed, and there will be no adjustment to the merger consideration for changes in the market price of Energy Transfer common units or our common units prior to the completion of the merger. If the merger is completed, there will be a time lapse between the date of signing the merger agreement and the date on which our unitholders who are entitled to receive the merger consideration actually receive the merger consideration. The market value of Energy Transfer’s common units may fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in Energy Transfer’s businesses, operations and prospects and regulatory considerations. Such factors are difficult to predict and in many cases may be beyond our and Energy Transfer’s control. The actual value of any merger consideration received by our unitholders upon the completion of the merger will depend on the market value of the common units of Energy Transfer at that time. This market value may differ, possibly materially, from the

The merger is subject to a number of conditions that must be satisfied or waived prior to the completion of the merger, including (i) the receipt of the required approvals from our unitholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, (iii) the absence of any governmental order or law that prohibits or makes illegal the consummation of the merger, (iv) Energy Transfer common units issuable in connection with the merger having been authorized for listing on the New York Stock Exchange, subject to official notice of issuance and (v) Energy Transfer’s registration statement on Form S-4 having been declared effective by the SEC under the Securities Act. The obligation of each party to consummate the merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the merger agreement. Our obligation to consummate the merger is further conditioned upon the receipt of a customary tax opinion of counsel that for U.S. federal income tax purposes, subject to certain exceptions, (i) we should not recognize any income or gain as a result of the merger and (ii) no gain or loss should be recognized by holders of our common units or Series A Preferred Units as a result of the merger. These conditions to the completion of the merger may not be satisfied or waived in a timely manner or at all, and, accordingly, the merger may be delayed or may not be completed.

Moreover, if the merger is not completed by November 30, 2021, either Energy Transfer or we may choose not to proceed with the Energy Transfer merger, and the parties can mutually decide to terminate the merger agreement at any time, before or after approval by the Partnership’s common unitholders. In addition, Energy Transfer and we may elect to terminate the merger agreement in certain other circumstances as further detailed in the merger agreement.

The merger agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our unitholders than the merger, or may result in a potential competing acquirer proposing to pay a lower per unit price to acquire us than it might otherwise have proposed to pay. These provisions include covenants not to solicit, initiate or knowingly encourage or facilitate proposals relating to alternative transactions or, subject to certain exceptions, enter into discussions concerning or provide any non-public information in connection with alternative transactions.

The merger agreement contains a number of conditions that must be satisfied or waived prior to the completion of the merger. There can be no assurance that all of the conditions to the completion of the merger will be so satisfied or waived. If these conditions are not satisfied or waived, we will be unable to complete the merger.

If the merger is not completed for any reason, including the failure to receive the required approval of holders of our common units, our future businesses and financial results may be adversely affected, including as follows:

In addition to the above risks, if the merger agreement is terminated and the Board of Directors seeks an alternative transaction, our unitholders cannot be certain that we will be able to find a party willing to engage in a transaction on more attractive terms than the merger. If the merger agreement is terminated under specified circumstances, we may be required to pay Energy Transfer a termination fee.

Uncertainties about the effect of the merger on employees and customers may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter and could cause customers and others that deal with us to seek to change their existing business relationships with us. Employee retention may be particularly challenging during the pendency of the merger, as employees may experience uncertainty about their roles with Energy Transfer following the merger. In addition, the merger agreement restricts us from entering into certain corporate transactions and taking other specified actions without the consent of Energy Transfer, and generally requires us to continue our operations in the ordinary course, until completion of the merger. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the merger.

Upon completion of the merger, our unitholders will no longer be unitholders of the Partnership. Instead, our former unitholders will become Energy Transfer unitholders and while their rights as Energy Transfer unitholders will continue to be governed by the laws of the state of Delaware, their rights will be subject to and governed by the terms of the Energy Transfer Certificate of Limited Partnership, as amended, and the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer, as amended. The laws of the state of Delaware and terms of the Energy Transfer certificate of limited partnership and the Energy Transfer Third Amended and Restated Agreement of Limited Partnership are in some respects different than the terms of our Certificate of Limited Partnership and our Partnership Agreement, which currently govern the rights of our unitholders.

The completion of the merger may trigger change in control or other provisions in certain agreements to which we are a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements, or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to us.

We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the merger, combining the operations of the two partnerships and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees. Many of these costs will be borne by us even if the merger is not completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the merger, then that injunction may delay or prevent the merger from being completed, which may adversely affect our business, financial position and results of operation. Currently, we are unaware of any securities class action lawsuits or derivative lawsuits having been filed in connection with the merger.

For the year ended December 31, 2020, 61% of our natural gas gathered volumes were attributable to the affiliates of Continental, Vine, GeoSouthern, XTO and Marathon Oil and 46% of our transportation and storage service revenues were attributable to affiliates of CenterPoint Energy, Spire, Continental, OGE Energy, and AEP. The loss of any portion of the gathering, processing, transportation and storage systems serving any of these customers, the failure to extend existing contracts at their expiration or the extension or replacement of these contracts on less favorable terms, could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Our and our operating subsidiaries’ ability to service our and their debt will depend upon, among other things, their future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond our and their control. If operating results are not sufficient to service our or our operating subsidiaries’ current or future indebtedness, we and they may be forced to take actions

Our credit facilities also require us to maintain certain financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we cannot assure you that we will meet those ratios. In addition, our credit facilities contain events of default customary for agreements of this nature.

Our ability to comply with the covenants and restrictions contained in our credit facilities may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facilities, a significant portion of our indebtedness may become immediately due and payable. In addition, our lenders’ commitments to make further loans to us under the Revolving Credit Facility may be suspended or terminated. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of our credit ratings are below investment grade, we may have higher future borrowing costs and we or our subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price of our common units is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue additional equity to make acquisitions or for other purposes, our financial position, results of operations and our ability to make cash distributions at our intended levels.

Our business plan calls for investment in capital improvements and additions. The construction of additions or modifications to our existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond our control and may require the expenditure of significant amounts of capital, which may exceed our estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs and availability of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, our revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand an existing pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues or cash flows until the project is completed. In addition, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve our expected investment return, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

In connection with our capital investments, we may estimate, or engage a third party to estimate, potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent we rely on estimates of future production in deciding to construct additions to our systems, those estimates may prove to be inaccurate either in volume or timing due to numerous uncertainties inherent in estimating future production. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and we may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

Our operating subsidiaries distribute all of their available cash to us, and we distribute all of our available cash to our unitholders. As a result, we and our operating subsidiaries rely significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. To the extent we or our operating subsidiaries are unable to finance growth externally or through internally generated cash flows, our and our operating subsidiaries’ cash distribution policy may significantly impair our and our operating subsidiaries’ ability to grow. In addition, because we and our operating subsidiaries distribute all available cash, our and our operating subsidiaries’ growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. For further information related to distributions of available cash, please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our Partnership Agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by us or our operating subsidiaries to finance our growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that our operating subsidiaries have to distribute to us, and that we have to distribute to our unitholders.

We depend in part on access to the capital markets and other external financing sources to fund our expansion capital expenditures, although we have also increasingly relied on cash flow generated from our operations to fund our expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors. As a result of capital market volatility, we may be unable to issue equity or debt on satisfactory terms, or at all, which may limit our ability to expand our operations or make future acquisitions.

In addition, our growth strategy includes, in part, the ability to make acquisitions on economically acceptable terms. If we are unable to make acquisitions or if our acquisitions do not perform as anticipated, our future growth may be adversely affected.

Performance of our operations require that we obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect our ability to initiate or continue operations at the affected location or facility and on our financial condition, results of operations and ability to make cash distributions to unitholders. For example, in April 2020, the federal district court for the District of Montana issued an order vacating NWP 12, which authorizes pipeline crossings of streams and wetlands. Subsequent proceedings limited this order to the Keystone XL pipeline, which is not related to our operations. Pending appeal of the court’s decision, the Corps has published a proposal to reissue its existing Nationwide Permits and associated general conditions and definitions, with certain modifications, including to NWP 12. While the full extent and impact of the court’s action, as well as the proposed NWP 12 re-issuance, is unclear at this time, a disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are required to seek individual permits from the Corps.

Additionally, in order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and American Indian tribal lands. Certain approval procedures may require preparation of archaeological surveys, wetland delineations, endangered species surveys and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt our project construction schedules.

Parts of our operations cross land that has historically been apportioned to various Native American tribes, who may exercise significant jurisdiction and sovereignty over their lands. Our operations may be impacted to the extent these tribal governments are found to have and choose to act upon such jurisdiction over lands where we operate. For example, a U.S. Supreme Court ruling in 2020 found that the Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished, and subsequent court rulings applying this precedent have found similarly for other reservations. This ruling could lead to some confusion as to which agencies have authority to regulate activities in this area of Oklahoma. Please see

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our crude oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. For more information, see Item 1A. “Risk Factors—Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.” Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had withdrawn from the Paris Agreement, on January 20, 2021, President Biden signed executive orders recommitting the United States to the agreement and calling on the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. 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. A material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our services.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products. Additionally, political, litigation and financial risks may result in our oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to unitholders.

Finally, many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect our results of operations and ability to make cash distributions to unitholders. 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.

The rates charged by several of our pipeline systems, including for interstate gas transportation service provided by our intrastate pipelines, are regulated by FERC. FERC and state regulatory agencies also regulate other terms and conditions of the services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose or offer, the profitability of our pipeline businesses could suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit our profitability. Furthermore, competition from other transportation and storage systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to approximately $1.31 million per day for each violation as well as possible criminal penalties.

FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from FERC. Certain minor expansions are authorized by blanket certificates that FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Our inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.

FERC conducts audits to verify compliance with FERC’s regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. FERC’s regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, FERC. In the event that FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.

The rates, terms and conditions for transporting natural gas in interstate commerce on certain of our intrastate pipelines and for services offered at certain of our storage facilities are subject to the jurisdiction of FERC under Section 311 of the NGPA. Rates to provide such interstate transportation service must be “fair and equitable” under the NGPA and are subject to review, refund with interest if found not to be fair and equitable, and approval by FERC at least once every five years.

Our crude oil gathering systems in the Williston Basin are subject to common carrier regulation by FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain tariffs on file with FERC setting forth the rates we charge for providing transportation services, as well as the rules and regulations governing such services. The ICA also requires, among other things, that our rates must be “just and reasonable” and that we provide service in a manner that is nondiscriminatory. Shippers on our FERC-regulated crude oil gathering systems may protest our tariff filings, file complaints against our existing rates, or FERC can investigate our rates on its own initiative. If FERC finds that our existing or proposed rates are unjust and unreasonable, it could deny requested rate increases or could order us to reduce our rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.

Our pipeline operations that are not regulated by FERC may be subject to state and local regulation applicable to intrastate natural and transportation services. State and local regulations generally focus on safety, environmental and, in some circumstances, prohibition of undue discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business. Any such state or local regulation could have an adverse effect on our business and our financial position, results of operations and ability to make cash distributions to unitholders. For more information, please read Item 1, “Business—Regulatory Compliance.”

Our natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of FERC under the NGA, and our crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of FERC under the ICA. Nevertheless, FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although FERC has not made a formal determination with respect to all of our facilities we consider to be engaged in natural gas gathering or a formal determination with respect to our facilities that we consider to be engaged in intrastate crude oil gathering, management believes that our natural gas gathering facilities meet the traditional tests that FERC has used to determine that a pipeline is a natural gas gathering pipeline and our intrastate crude oil gathering facilities meet the traditional tests that FERC has used to determine that a pipeline is not engaged in interstate crude oil transportation. The distinction between FERC-regulated facilities, however, has been the subject of substantial litigation, and FERC determines whether facilities are subject to regulation under the NGA or the ICA on a case-by-case basis, so the classification and regulation of our facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and ability to make cash distributions to our unitholders. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, NGPA or ICA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, these operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Certain of our pipeline operations are subject to pipeline safety laws and regulations. PHMSA regulates safety requirements for the design, construction, maintenance and operation of jurisdictional natural gas and hazardous liquids pipeline facilities. All of our interstate and intrastate natural gas transportation pipeline facilities are PHMSA jurisdictional and certain of our natural gas gathering, NGLs, and crude oil pipeline facilities are PHMSA jurisdictional. Among other things, these laws and regulations require pipeline operators to develop integrity management programs, including more frequent inspections and other measures for pipelines located in “high consequence areas.” The regulations require operators, including us, to, among other things:

Failure to comply with PHMSA or comparable state pipeline safety regulations could result in a number of consequences which may have an adverse effect on our operations. We incur significant costs associated with our compliance with existing PHMSA and comparable state pipeline regulations. We incurred maintenance capital expenditures and operation and maintenance expenses of $66 million in 2020 and currently estimate that we will incur maintenance capital expenditures and operation and maintenance expenses of up to $68 million in 2021 under our pipeline safety program, including costs related to integrity assessments and repairs, threat and risk analyses, implementing preventative and mitigative measures, and conducting activities to support MAOP or MOP. We may incur significant cost associated with repair, remediation, preventive and mitigation measures associated with our integrity management programs for pipelines that are not currently subject to regulation by PHMSA.

Changes to existing pipeline safety regulations may result in increased operating and compliance costs. For example, in October 2019, PHMSA published three final rules on pipeline safety that create or expand reporting, inspection, maintenance and other pipeline safety obligations. Please see Item 1. “Business—Safety and Health Regulation.” While we have estimated the impact of these rules on our future costs of operations, actual costs to comply may be significantly higher.

PHMSA is working on two additional rules related to gas pipeline safety, though we cannot predict when they will be finalized. The rule entitled “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments” is expected to adjust the repair criteria for pipelines in HCAs, create new criteria for pipelines in non-HCAs, and strengthen integrity management assessment requirements. The rule entitled “Safety of Gas Gathering Pipelines” is expected to require all gas gathering pipeline operators to report incidents and annual pipeline data and to extend regulatory safety requirements to certain gas gathering pipelines in rural areas. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased and potentially significant operational costs.

At times, we may hedge all or a portion of our commodity risk and our interest rate risk. The federal government regulates the derivatives markets and entities, including businesses like ours, that participate in those markets through the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which requires the Commodity Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the legislation. Under the CFTC’s regulations, we are subject to reporting and recordkeeping obligations for transactions involving non-financial swap transactions. The CFTC initially adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. In December 2013, the CFTC published a Notice of Proposed Rulemaking designed to implement new position limits regulation and in December 2016, the CFTC re-proposal position limits regulations. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain.

The CFTC has imposed mandatory clearing requirements on certain categories of swaps, including certain interest rate swaps, but has exempted derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where a counterparty such as us has a required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. Management believes our hedging transactions qualify for this “commercial end-user” exception. The Dodd-Frank Act may also require us to comply with margin requirements in connection with our hedging activities, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.

The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for our industry (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties, particularly if we are unable to utilize the commercial end user exception with respect to certain of our hedging transactions. If we reduce our use of hedging as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.

We derive a substantial portion of our gross margin from, and hold a substantial portion of our assets through, our subsidiaries. As a result, we depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.

Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

We conduct a portion of our operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream Partners, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. We may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside of our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn adversely affect our financial position, results of operations and ability to make cash distributions to unitholders. The agreements under which we formed certain joint ventures may subject us to various risks, limit the actions we may take with respect to the assets subject to the joint venture and require us to grant rights to our joint venture partners that could limit our ability to benefit fully from future positive developments. Some joint ventures require us to make significant capital expenditures. If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of our joint venture partners may have substantially greater financial resources than we have, and we may not be able to secure the funding necessary to participate in operations our joint venture partners propose, thereby reducing our ability to benefit from the joint venture.

We own a 50% ownership interest in SESH. The remaining 50% ownership interests are held by Enbridge Inc. As of December 31, 2020, CenterPoint Energy owns 53.7% of our common units, 100% of our Series A Preferred Units and a 40% economic interest in our general partner. Pursuant to the terms of the limited liability company agreement of SESH, as amended (the SESH LLC Agreement), if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its interests in us and in our general partner, or does not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase our interest in SESH at fair market value, subject to certain exceptions.

Affiliates of CenterPoint Energy and OGE Energy own and control our general partner and appoint all of the directors of our general partner. Some of the directors of our general partner are appointed to represent CenterPoint Energy or OGE Energy

Our Partnership Agreement includes certain requirements regarding those investors who may own our common and preferred units. Eligible Holders are limited partners whose (i) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (ii) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If the unitholder is not an Eligible Holder, in certain circumstances as set forth in our Partnership Agreement, the unitholder’s units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

The credit and business risk profiles and the business plans of our sponsors may be factors in credit evaluations of us because, through their indirect ownership of our general partner, they can influence our business activities, including our cash distribution strategy, acquisition strategy, and business risk profile. The financial conditions of CenterPoint Energy and OGE Energy, including the degree of their financial leverage and their dependence on cash flows from us, as well as their business plans with respect to their investment in us, may be considered by credit rating agencies in their assessment of our credit ratings and profile.

CenterPoint Energy and OGE Energy, which indirectly own our general partner, have indebtedness outstanding and are partially dependent on the cash distributions from their general partner and limited partner interests in us to service such indebtedness and pay dividends on their common stock. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or riskier than ours.

Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the Partnership Agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above.

Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth sub-bullets above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our general partner has the right, if it has received incentive distributions at the highest level to which it is entitled (50%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, respectively, to reset the initial minimum quarterly distribution and cash target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as 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 amount.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.

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 have no right to elect our general partner or its Board of Directors on an annual or other continuing basis. Because CenterPoint Energy and OGE Energy collectively indirectly own 100% of our general partner, the Board of Directors has been, and, as long as CenterPoint Energy and OGE Energy own 100% of our general partner, will continue to be, chosen by CenterPoint Energy and OGE Energy. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Please see “—Even if holders of our common units are dissatisfied, they will not be able to remove our general partner without its consent.” 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. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

The unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent its removal. The vote of the holders of at least 75% of all outstanding units voting together as a single class is required to remove our general partner. As of January 29, 2021, affiliates of our general partner owned 79.2% of our aggregate outstanding common units.

Unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors, cannot vote on any matter.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Our Partnership Agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective limited liability company interest in our general partner to a third party. The new owners 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 choices and thereby influence the decisions taken by the Board of Directors and officers.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest,

In addition, upon a change of control or certain fundamental transactions, our Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

As of January 29, 2021, CenterPoint Energy held 233,856,623 common units and 14,520,000 Series A Preferred Units, and OGE Energy held 110,982,805 common units. Our Series A Preferred Units are convertible into common units upon a change of control or certain fundamental transactions at the option of the holders of such units. Both our common units held by CenterPoint Energy and OGE Energy, as well as our Series A Preferred Units held by CenterPoint Energy, are subject to certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop. In addition, any sale of our general partner by CenterPoint Energy or OGE Energy may impact our strategic direction, business or results of operations.

If at any time our general partner and its affiliates own more than 90% of our 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 not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any positive return on their investment. Our unitholders may also incur a tax liability upon any such sale of their units. As of January 29, 2021, affiliates of our general partner owned approximately 79.2% of our outstanding common units. If we assume the conversion of our Series A Preferred Units using the closing price of our units as of January 29, 2021, affiliates of our general partner will then own 82.1% of our aggregate outstanding common units. Affiliates of our general partner may acquire additional common units from us in connection with future transactions or through open-market or negotiated purchases.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for both the obligations of the transferor to make contributions to the Partnership that are known to the transferee at the time of transfer and for unknown obligations if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the Partnership are counted for purposes of determining whether a distribution is permitted.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are non-recourse to our general partner. Our Partnership Agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the

Our Series A Preferred Units rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. We cannot declare or pay a distribution to our common unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by our general partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10% on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date, and an annual rate of LIBOR plus a spread of 850 bps on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the “other preferred units”) on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as our Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Our Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on our Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

The holders of our Series A Preferred Units may request that we list those units for trading on the NYSE. If we are unable to list the Series A Preferred Units in certain circumstances, we will be required to redeem the Series A Preferred Units. There can be no assurance that we would have sufficient financial resources available to satisfy our obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of our Series A Preferred Units could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS regarding our qualification as a partnership for tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21% and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to such unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. This could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the distributable cash flow. Our Partnership Agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including the repeal of the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the U.S. Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships.

There can be no assurance that there will not be further changes to U.S. federal income tax laws or the U.S. Department of the Treasury’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future. Any modification to the U.S. federal income tax laws and interpretations thereof could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

A unitholder’s allocable share of our taxable income will be taxable to the unitholder, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.

A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. The ratio of a unitholder’s share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the Tax Cuts and Jobs Act, subject to the exceptions in the Coronavirus Aid, Relief, and Economic Security Act, or the CARES Act, discussed below, for taxable years beginning after 2017 the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. For our 2020 taxable year, the CARES Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase. For purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income, which may result in a greater business interest expense deduction. In addition, unitholders may treat 50% of any excess business interest allocated to them in 2019 as deductible in the 2020 taxable year without regard to the 2020 business interest expense limitations. The remaining 50% of such unitholder’s excess business interest is carried forward and subject to the same limitations as other taxable years. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

From time to time, in connection with an offering of our units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse effect on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders and our general partner because the costs would likely reduce our distributable cash flow to our unitholders.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. 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 tax year under audit, but there can be no assurance that such election will be practical, permissible or effective under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by the amount of any suspended passive loss carryovers of specified unitholders (without any compensation from us to such unitholders). Such reduction, if approved by the IRS, will be binding on any affected unitholders.

If any of our unitholders sells their common units, such unitholders must recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and such unitholder’s tax basis in those common units. Because distributions in excess of such unitholder’s allocable share of our net taxable income decrease such unitholder’s tax basis in such unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units such unitholder sells will, in effect, become taxable income if such unitholder sells such common units at a price greater than its tax basis in those common units, even if the price such unitholder receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of such unitholder’s common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, it may incur a tax liability in excess of the amount of cash it receives from the sale. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than the unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its common units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (UBTI) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year the exempt organization is allocated the income. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to non-U.S. unitholders will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. While the “amount realized” generally includes a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Non-U.S. persons should consult a tax advisor before investing in our common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to such unitholder’s tax returns.

We generally prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, such unitholder may 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 may recognize gain or loss from such disposition. 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. Therefore, our 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 loaning their common units.

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. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to 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.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in a number of states, most of which currently impose a personal income tax on individuals, and most of which also impose an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose an income tax or similar tax. In certain states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent tax years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholders’ income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

Our material properties consist of our principal executive offices, gathering systems, processing plants, transportation systems and storage facilities. Our principal executive offices are located in approximately 154,584 square feet of leased office space at 499 West Sheridan Avenue, Suite 1500, Oklahoma City, Oklahoma 73102. For descriptions of the location and general character of our other material properties, please see Item 1. “Business—Description of Our Business.”

Our processing plants are located on fee property, except for our Roger Mills plant which is located on leased property. Our other gathering, processing, transportation, and storage assets are located on property that we have the right to use under easements, leases, licenses, or permits granted by governmental agencies, American Indian tribes, railroads, utilities, and other third parties. In some cases, title to our properties or other land rights may be subject to renewals, require periodic payments, or be subject to revocation at the option of the grantor. For example, certain easements granted across American Indian allotted land to which title is held in trust by the United States are subject to renewal, and certain licenses and permits granted by governmental agencies are subject to revocation at the option of the grantor. In other cases, title to our property or other land rights may be subject to encumbrances, restrictions, or imperfections. For example, our title in certain instances may be subject to liens that are not subordinated to our rights, and our title in certain locations may reflect names of predecessors until we have made the appropriate filings. We believe that we generally have sufficient title to our properties and other land rights necessary to operate our assets and conduct our business, subject to such renewals, period payments, revocation rights, restrictions, encumbrances and imperfections that do not materially either detract from the value of our assets or interfere with the conduct of our business.

In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management’s opinion, we have incurred a

At the present time, based on currently available information, management believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to our financial statements and would not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Our common units are listed on the NYSE under the symbol “ENBL.”

As of January 29, 2021, there were 435,565,067 common units outstanding and approximately 15 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.

Our minimum quarterly distribution to our common units as set forth in the Partnership Agreement is $0.2875 per common unit per quarter. Our current quarterly distribution is $0.16525 per common unit per quarter. There is no guarantee that we will pay any specific distribution on our common units in any quarter, and we have no obligation to pay in arrears any distribution below the minimum quarterly distribution. For more information on cash distributions, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources” contained herein.

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Financial Statements and Supplementary Data” and “Notes to the Consolidated Financial Statements” included in Item 8 of this report. Our 2018 financial conditions and results of operations, as well as the discussion of our year-to-year comparisons between financial conditions and results of operations for 2019 and 2018 can be found in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Our assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. For more information related to our segments, see Item 1. “Business—Description of Our Business”

On February 16, 2021, we entered into a definitive merger agreement (the “merger agreement” and the transactions contemplated therein, the “merger”) with Energy Transfer, pursuant to which, and subject to the conditions of the merger agreement, all outstanding common units of the Partnership will be acquired by Energy Transfer in an all-equity transaction.

Our principal liquidity and capital resources requirements are to finance operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. We expect that our liquidity and capital resource needs will be met by our sources of liquidity, which as of December 31, 2020, included cash on hand, operating cash flow, proceeds from commercial paper issuances, borrowings under our revolving credit facility, debt issuances and the issuance of equity. For more information on our commercial paper program, our revolving credit agreement, our other outstanding debt agreements and preferred equity, please see Note 7 “Partners’ Equity” and Note 12 “Debt” in the Notes to the Consolidated Financial Statements under Item 8. “Financial Statements and Supplementary Data.”

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by debt maturities, changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from, customers, and the level and timing of spending for maintenance and expansion activity. As of December 31, 2020, we had a working capital deficit of $201 million. The deficit is primarily due to $250 million of commercial paper outstanding as of December 31, 2020. We utilize our commercial paper program and revolving credit facility to manage the timing of cash flows and fund short-term working capital deficits.

The following tables reflect cash flows for the applicable periods:

The decrease of $185 million, or 20%, in net cash provided by operating activities for the year ended December 31, 2020 as compared to the year ended December 31, 2019 is primarily due to a decrease in net income of $317 million and a decrease of $37 million in the timing of cash receipts and disbursements and changes in other working capital assets and liabilities, partially offset by an increase in adjustments for non-cash items of $169 million, which is primarily related to an increase in losses of equity in earnings of equity method affiliate, offset by a decrease in impairments of property, plant and equipment and goodwill.

The decrease of $248 million, or 58%, in net cash used in investing activities for the year ended December 31, 2020 as compared to the year ended December 31, 2019 was primarily due to lower capital expenditures of $217 million, an increase in proceeds of $19 million due to the sale of the Partnership’s interest in the Bistineau Storage Facility in 2020, and an increase in other investing inflows of $12 million.

The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Our capital requirements generally consist of the following: