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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

________________________________________________________________

FORM 10-K

________________________________________________________________


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020 or


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File No. 1-36413

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ENABLE MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

_______________________________________________________________

Delaware

72-1252419

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

499 West Sheridan Avenue, Suite 1500 Oklahoma City, Oklahoma

73102

(Address of principal executive offices)

(Zip Code)

(405) 525-7788

Registrant’s telephone number, including area code

_______________________________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading symbol(s)

Name of each exchange on which registered

Common Units Representing Limited Partner Interests

ENBL

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ Yes ☒ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. ☐ Yes ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer	☐	Accelerated filer	☒

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

The aggregate market value of the Common Units held by non-affiliates of the registrant, based upon the closing price of $4.68 per common unit on June 30, 2020, was approximately $424 million.

As of January 29, 2021, there were 435,565,067 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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ENABLE MIDSTREAM PARTNERS, LP

FORM 10-K

TABLE OF CONTENTS


			Page
GLOSSARY OF TERMS			1
FORWARD-LOOKING STATEMENTS			4
SUMMARY OF RISK FACTORS			5

Part I
Item 1. Business			7
Item 1A. Risk Factors			31
Item 1B. Unresolved Staff Comments			64
Item 2. Properties			64
Item 3. Legal Proceedings			64
Item 4. Mine Safety Disclosures			65

Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			66
Item 6. Selected Financial Data			67
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations			68
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			92
Item 8. Financial Statements and Supplementary Data			93
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			140
Item 9A. Controls and Procedures			140

Part III
Item 10. Directors, Executive Officers and Corporate Governance			143
Item 11. Executive Compensation			148
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			163
Item 13. Certain Relationships and Related Transactions, and Director Independence			165
Item 14. Principal Accounting Fees and Services			169

Part IV
Item 15. Exhibits, Financial Statement Schedules			170
Item 16. Form 10-K Summary			172
Signatures			173

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GLOSSARY


Measurements
Bbl.			Barrel.42 U.S. gallons of petroleum products.
Bbl/d.			Barrels per day.
Bcf.			Billion cubic feet.
Bcf/d.			Billion cubic feet per day.
Btu.			British thermal unit. When used in terms of volume, Btu refers to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
MBbl.			Thousand barrels.
MBbl/d.			Thousand barrels per day.
MMBtu.			Million British thermal units.
MMcf.			Million cubic feet of natural gas.
MMcf/d.			Million cubic feet per day.
TBtu.			Trillion British thermal units.
TBtu/d.			Trillion British thermal units per day.
Abbreviations
ASC.			Accounting Standards Codification.
ASU.			Accounting Standards Update.
CAA.			Clean Air Act, as amended.
CFTC.			Commodity Futures Trading Commission.
CWA.			Clean Water Act.
DCF.			Distributable Cash Flow. Please read “Key Performance Indicators and Metrics” under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the definition.
DOT.			Department of Transportation.
EBITDA.			Earnings before interest, taxes, depreciation and amortization.
EGT.			Enable Gas Transmission, LLC, a wholly owned subsidiary of the Partnership that operates an approximately 5,900-mile interstate pipeline that provides natural gas transportation and storage services to customers principally in the Anadarko, Arkoma and Ark-La-Tex Basins in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas.
EOCS.			Enable Oklahoma Crude Services, LLC, formerly Velocity Holdings, LLC, a wholly owned subsidiary of the Partnership that provides crude oil and condensate gathering services to customers in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.
EOIT.			Enable Oklahoma Intrastate Transmission, LLC, formerly Enogex LLC, a wholly owned subsidiary of the Partnership that operates an approximately 2,200-mile intrastate pipeline that provides natural gas transportation and storage services to customers in Oklahoma.
EPA.			Environmental Protection Agency.
ERISA.			Employee Retirement Income Security Act of 1974.
ESCP.			Enable South Central Pipeline, LLC, formerly Velocity Pipeline Partners, LLC, in which the Partnership, through EOCS, owns a 60% joint venture interest in a 26-mile pipeline system with a third party which owns and operates a refinery connected to the EOCS system.
ETGP.			Enable Texola Gathering & Processing, LLC, formerly Align Midstream, LLC, a wholly owned subsidiary of the Partnership that provides natural gas gathering and processing services to customers in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin in Texas.
FASB.			Financial Accounting Standards Board.
FERC.			Federal Energy Regulatory Commission.
GAAP.			Accounting principles generally accepted in the United States of America.
GHG.			Greenhouse gas.
ICA.			Interstate Commerce Act.
ICE.			Intercontinental Exchange.

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IRS.			Internal Revenue Service.
LDC.			Local distribution company involved in the delivery of natural gas to consumers within a specific geographic area.
LIBOR.			London Interbank Offered Rate.
LNG.			Liquefied natural gas.
MAOP.			Maximum allowable operating pressure for gas pipelines.
MOP.			Maximum operating pressure for hazardous liquid pipelines.
MRT.			Enable Mississippi River Transmission, LLC, a wholly owned subsidiary of the Partnership that operates an approximately 1,600-mile interstate pipeline that provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois.
NGA.			Natural Gas Act of 1938.
NGL(s).			Natural gas liquid(s), which are the hydrocarbon liquids contained within the natural gas stream including condensate.
NGPA.			Natural Gas Policy Act of 1978.
NWP 12.			United States Army Corps of Engineers Clean Water Act Section 404 Nationwide Permit 12.
NYMEX.			New York Mercantile Exchange.
NYSE.			New York Stock Exchange.
OCC.			Oklahoma Corporation Commission.
OPEC.			Organization of the Petroleum Exporting Countries.
PHMSA.			Pipeline and Hazardous Materials Safety Administration.
S&P.			Standard & Poor’s Rating Services.
SCOOP.			South Central Oklahoma Oil Province.
SEC.			Securities and Exchange Commission.
SESH.			Southeast Supply Header, LLC, in which the Partnership owns a 50% interest as of December 31, 2020, that operates an approximately 290-mile interstate natural gas pipeline from Perryville, Louisiana to southwestern Alabama near the Gulf Coast.
STACK.			Sooner Trend Anadarko Basin Canadian and Kingfisher Counties.
WTI.			West Texas Intermediate.
Terms and Definitions
2019 Notes.			$500 million aggregate principal amount of the Partnership’s 2.400% senior notes due 2019.
2019 Term Loan Agreement.			Unsecured term loan agreement dated January 29, 2019, by and among Enable Midstream Partners, LP and Bank of America, N.A., as administrative agent, and the several lenders from time to time party thereto.
2024 Notes.			$600 million aggregate principal amount of the Partnership’s 3.900% senior notes due 2024.
2027 Notes.			$700 million aggregate principal amount of the Partnership’s 4.400% senior notes due 2027.
2028 Notes.			$800 million aggregate principal amount of the Partnership’s 4.950% senior notes due 2028.
2029 Notes.			$550 million aggregate principal amount of the Partnership’s 4.150% senior notes due 2029.
2044 Notes.			$550 million aggregate principal amount of the Partnership’s 5.000% senior notes due 2044.
Adjusted EBITDA.			Please read “Key Performance Indicators and Metrics” under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the definition.
Adjusted interest expense.			Please read “Key Performance Indicators and Metrics” under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the definition.
Atoka.			Atoka Midstream LLC, in which the Partnership owns a 50% interest as of December 31, 2020, which provides gathering and processing services to customers in the Arkoma Basin in Oklahoma.
ATM Program.			The offer and sale, from time to time, of common units representing limited partner interests having an aggregate offering price of up to $200 million in quantities, by sales methods and at prices determined by market conditions and other factors at the time of such sales, pursuant to that certain ATM Equity Offering Sales Agreement, entered into on May 12, 2017.
Board of Directors.			The board of directors of Enable GP, LLC.
CenterPoint Energy.			CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries.

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Condensate.			A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
Corps.			United States Army Corps of Engineers.
Distribution coverage ratio.			Please read “Key Performance Indicators and Metrics” under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the definition.
Dodd-Frank Act.			Dodd-Frank Wall Street Reform and Consumer Protection Act.
Enable GP.			Enable GP, LLC, the general partner of Enable Midstream Partners, LP.
Enable Midstream Services.			Enable Midstream Services, LLC, a wholly owned subsidiary of Enable Midstream Partners, LP.
EOIT Senior Notes.			$250 million aggregate principal amount of EOIT’s 6.25% senior notes that were repaid in March 2020.
Energy Transfer.			Energy Transfer LP, a Delaware limited partnership.
Exchange Act.			Securities Exchange Act of 1934, as amended.
Fractionation.			The separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale.
Gas imbalance.			The difference between the actual amounts of natural gas delivered from or received by a pipeline, as compared to the amounts scheduled to be delivered or received.
General partner.			Enable GP, LLC, the general partner of Enable Midstream Partners, LP.
Gross margin.			Please read “Key Performance Indicators and Metrics” under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the definition.
Lean gas.			Natural gas that is primarily methane.
MASS project.			A supply driven project designed to deliver gas from the Anadarko and Arkoma Basins to delivery points with access to emerging Gulf Coast markets and growing demand markets in the Southeast.
Moody’s.			Moody’s Investor Services.
OGE Energy.			OGE Energy Corp., an Oklahoma corporation, and its subsidiaries.
Partnership.			Enable Midstream Partners, LP and its subsidiaries.
Partnership Agreement.			Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP dated as of November 14, 2017.
Revolving Credit Facility.			$1.75 billion senior unsecured revolving credit facility.
Rich gas.			Natural gas containing higher concentrations of NGLs.
Securities Act.			Securities Act of 1933, as amended.
Series A Preferred Units.			10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership.
Sponsors.			CenterPoint Energy and OGE Energy.
Wynnewood Refinery.			A refinery owned by CVR Energy, Inc. and connected to the ESCP system.

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FORWARD-LOOKING STATEMENTS

Some of the information in this report may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “could,” “will,” “should,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including revenue projections, capital expenditures and tax position, and matters relating to our pending merger with Energy Transfer. In particular, our statements with respect to continuity plans and preparedness measures we have implemented in response to the novel coronavirus (COVID-19) pandemic and its expected impact on our business, operations, earnings and results are forward-looking statements. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report. Those risk factors and other factors noted throughout this report could cause our actual results to differ materially from those disclosed in any forward-looking statement. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•our pending merger with Energy Transfer and the expected timing of the consummation of the merger;

•changes in general economic conditions, including world health events and the material and adverse consequences of the COVID-19 pandemic and its unfolding impact on the global and national economy;

•competitive conditions in our industry;

•actions taken by our customers and competitors;

•the supply and demand for natural gas, NGLs, crude oil and midstream services;

•the actions of OPEC and other significant producers and governments;

•our ability to successfully implement our business plan;

•our ability to complete internal growth projects on time and on budget;

•the price and availability of debt and equity financing;

•strategic decisions by CenterPoint Energy and OGE Energy regarding their ownership of us and Enable GP;

•operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, NGLs, crude oil and midstream products;

•natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•interest rates;

•the timing and extent of changes in labor and material prices;

•labor relations;

•large customer defaults;

•changes in the availability and cost of capital;

•changes in tax status;

•the effects of existing and future laws and governmental regulations;

•changes in insurance markets impacting costs and the level and types of coverage available;

•the timing and extent of changes in commodity prices;

•the suspension, reduction or termination of our customers’ obligations under our commercial agreements;

•disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;

•the effects of current or future litigation, including the recent U.S. Supreme Court ruling involving the Muscogee (Creek) Nation reservation in Eastern Oklahoma; and

•other factors set forth in this report and our other filings with the SEC.

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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.

SUMMARY OF RISK FACTORS

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.

Risks Related to Our Business

•Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.

•A pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, may materially adversely affect our business.

•Our businesses are dependent, in part, on the drilling and production decisions of others.

•If third-party pipelines and other facilities interconnected to our gathering, processing or transportation facilities become partially or fully unavailable to us for any reason, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

•An impairment of long-lived assets, including intangible assets or equity method investments could reduce our earnings.

•Because the exchange ratio is fixed and because the market price of Energy Transfer’s common units may fluctuate, our unitholders cannot be certain of the precise value of any merger consideration they may receive in the Energy Transfer merger.

•Our pending merger with Energy Transfer may not be completed and any failure to complete the merger could negatively impact the price of our common units, as well as our future businesses and financial results.

•The merger agreement limits our ability to pursue alternatives to the merger.

•We will be subject to business uncertainties while the merger with Energy Transfer is pending.

•The common units representing limited partner interests in Energy Transfer to be received by our common unitholders upon completion of the merger will have different rights than our common units.

•Completion of our pending merger with Energy Transfer may trigger change in control or other provisions in certain agreements to which we are a party.

•We will incur significant transaction and merger-related costs in connection with our pending merger with Energy Transfer, which may be in excess of those anticipated by us.

•We may be a target of securities class action and derivative lawsuits related to our pending merger with Energy Transfer, which could result in substantial costs and may delay or prevent the merger from being completed.

•We depend on a small number of customers for a significant portion of our gathering and processing revenues and our transportation and storage revenues.

•We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

•Our and our operating subsidiaries’ debt levels may limit our and their flexibility in obtaining additional financing and in pursuing other business opportunities.

•Our credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond our control, which could adversely affect our financial condition, results of operations and ability to make cash distributions to our unitholders.

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•An increase in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

•We may not be able to recover the costs of our substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than we anticipate.

•Our ability to grow is dependent in part on our ability to access external financing sources on acceptable terms.

•We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.

•Our operations may be impacted by certain indigenous rights protections.

•Increased regulation of hydraulic fracturing and wastewater injection wells could result in reductions or delays in natural gas and crude oil production by our customers, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Risks Related to Our Partnership Structure

•We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to maintain or increase the distributions to holders of our common units.

•The amount of cash we have available for distribution to our limited partners depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

•Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

•Affiliates of our general partner, including CenterPoint Energy and OGE Energy, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

•Our general partner and its affiliates, including CenterPoint Energy and OGE Energy, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.

•Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

•Our Partnership Agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

•Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

•Our general partner’s interest in us and control of our general partner may be transferred to a third party without unitholder consent.

•We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.

Tax Risks to Common Unitholders

•Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

•Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. A unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take.

•Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

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PART I

Item 1. Business

Development of Our Business

Overview

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 two 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.

As of December 31, 2020, our portfolio of midstream energy infrastructure assets primarily included:

•approximately 14,000 miles of natural gas, crude oil, condensate and produced water gathering pipelines;

•15 major processing plants with 2.6 Bcf/d of processing capacity;

•approximately 7,800 miles of interstate pipelines (including SESH);

•approximately 2,200 miles of intrastate pipelines; and

•seven natural gas storage facilities with 84.5 Bcf of storage capacity.

Our Business Strategies

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:

•Capitalize on Organic Growth and Asset Optimization Opportunities Associated with Our Strategically Located Assets: We own and operate assets servicing four major producing basins and key natural gas and crude oil demand centers in the United States. We strive to grow our business by utilizing a disciplined approach emphasizing capital efficiency when operating our existing assets and developing new midstream energy infrastructure projects to support new and existing customers in these areas. We work to optimize our assets and operations by exploiting emerging opportunities and applying strict cost discipline while maintaining our commitment to safety and reliability.

•Maintain Strong Customer Relationships to Attract New Volumes and Expand Beyond Our Existing Asset Footprint and Business Lines: Management believes that we have built a strong and loyal customer base through exemplary customer service and reliable project execution. We have invested in organic growth projects in support of our existing and new customers. We work to build and maintain relationships with key customers both on the supply and demand sides of the natural gas and crude oil value chain, in an effort to attract new volumes and to expand our asset footprint and business lines.

•Continue to Minimize Direct Commodity Price Exposure Through Fee-Based Contracts: We continually seek ways to minimize our exposure to commodity price risk. Management believes that focusing on fee-based revenues

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reduces our direct commodity price exposure. We intend to maintain our focus on increasing the percentage of long-term, fee-based contracts with our customers.

•Grow Through Accretive Acquisitions: We continually evaluate potential acquisitions of complementary assets with the potential for attractive returns in new and existing operating areas and midstream business lines. We will continue to analyze acquisition opportunities using disciplined financial and operating practices, including evaluating and managing risks to cash available for distribution.

Our Sponsors

CenterPoint Energy and OGE Energy each own a significant interest in us. As of December 31, 2020, CenterPoint Energy owned 53.7% of our common units outstanding and 100% of our Series A Preferred Units, and OGE Energy owned 25.5% of our common units outstanding. In addition, our sponsors own Enable GP, our general partner. CenterPoint Energy owns a 50% management interest and a 40% economic interest in our general partner, and OGE Energy owns a 50% management interest and a 60% economic interest in our general partner. Enable GP owns the non-economic general partner interest in us and all of our incentive distribution rights.

CenterPoint Energy (NYSE: CNP) is a public utility holding company whose operating subsidiaries own and operate electric transmission, distribution and power generation facilities, own and operate natural gas distribution facilities, and supply natural gas to commercial, industrial and utility customers. OGE Energy (NYSE: OGE) is an energy services provider offering physical delivery and related services for electricity.

Our sponsors are customers of our transportation and storage business. For the year ended December 31, 2020, approximately 3% of our gross margin was derived from transportation and storage contracts with an electric utility owned by OGE Energy. For the year ended December 31, 2020, approximately 6% of our gross margin was derived from transportation and storage contracts servicing LDCs owned by CenterPoint Energy.

In addition, our sponsors have entered into a number of agreements affecting us. For a more detailed description of our relationship and agreements with CenterPoint Energy and OGE Energy, please read Item 13. “Certain Relationships and Related Transactions, and Director Independence.” Although management believes our relationships with CenterPoint Energy and OGE Energy are positive attributes, there can be no assurance that we will benefit from these relationships or that these relationships will continue.

On December 4, 2020, CenterPoint Energy disclosed it is in the process of evaluating its investment in the Partnership. CenterPoint Energy said that during this process it intends to consider various plans, proposals and other strategic alternatives with respect to the its investment in the Partnership and Enable GP, which may result in the disposition of a portion or all of its interests in the Partnership and the GP or other transactions involving the Partnership.

Available Information

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.

Description of Our Business

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).

Gathering and Processing

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

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processing assets serving the Anadarko, Arkoma and Ark-La-Tex Basins, crude oil and condensate gathering assets serving the Anadarko Basin, and crude oil and produced water gathering assets serving the Williston Basin. We provide a variety of services to the active producers in our operating areas, including gathering, compressing, treating, and processing natural gas, fractionating NGLs, and gathering crude oil, condensate and produced water. We serve shale and other unconventional plays in the basins in which we operate.

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Natural Gas

•Anadarko Basin (Oklahoma, Texas Panhandle). We have natural gas gathering and processing operations in those portions of the Anadarko Basin located in Oklahoma and the Texas Panhandle where, as of December 31, 2020, we served approximately 220 producers. Our operations include gathering and processing natural gas produced from the SCOOP, STACK, Granite Wash, Cleveland, Marmaton, Tonkawa, Cana Woodford and Mississippi Lime plays. The current focus of our Anadarko Basin gathering and processing operations is primarily on rich gas production.

•Arkoma Basin (Oklahoma, Arkansas). In the Arkoma Basin, our operations primarily serve the Woodford Shale play located in Oklahoma and the Fayetteville Shale play located in Arkansas. Our Arkoma Basin gathering and processing operations serve both rich and lean gas production. As of December 31, 2020, we served approximately 80 producers in the Arkoma Basin.

•Ark-La-Tex Basin (Arkansas, Louisiana and Texas). We have gathering and processing operations in the Ark-La-Tex Basin located in Arkansas, Louisiana and Texas. Our Ark-La-Tex gathering and processing operations primarily serve the Haynesville, Cotton Valley and the lower Bossier plays. As of December 31, 2020, we served approximately 90 producers in the Ark-La-Tex Basin where our gathering and processing operations provide service for both rich and lean gas production.

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Crude Oil, Condensate and Produced Water

•Anadarko Basin (Oklahoma). Our operations in the Anadarko Basin are located in Oklahoma and include the gathering of crude oil and condensate from producers in the SCOOP and STACK plays (including the area where the SCOOP and STACK come together known as the Merge play). As of December 31, 2020, our customers included six producers and one refinery.

•Williston Basin (North Dakota). Our Williston Basin operations are located in North Dakota, and are focused on gathering of crude oil and produced water primarily for XTO Energy Inc. (XTO), an affiliate of ExxonMobil Corporation, with pipeline gathering systems in Dunn, McKenzie, Williams and Mountrail Counties of North Dakota.

Natural Gas Gathering and Processing Assets. The following table sets forth certain information regarding our natural gas gathering and processing assets as of or for the year ended December 31, 2020:


Asset/Basin	Approximate Length (miles)	Approximate Compression (Horsepower)	Average Gathered Volume (TBtu/d)	Number of Processing Plants	Processing Capacity (MMcf/d)	NGLs Produced (MBbl/d) (1)
Anadarko Basin (2)	8,700	830,600	2.07	11	1,845	110.91
Arkoma Basin	3,000	133,200	0.42	1	60	3.88
Ark-La-Tex Basin (3)	1,800	162,400	1.77	3	645	8.87
Total	13,500	1,126,200	4.26	15	2,550	123.66

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(1)Excludes condensate.

(2)Anadarko Basin processing capacity does not include firm contracted capacity of 400 MMcf/d at Energy Transfer’s Godley plant.

(3)Ark-La-Tex Basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.

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.

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


Processing Plant Assets (1)	Year Installed		Type of Plant	Average Daily Inlet Volumes (MMcf/d)	Inlet Capacity (MMcf/d)	NGL Production Capacity (Bbl/d)(2)
Anadarko
Bradley II	2016		Cryogenic	182	200	28,000
Bradley	2015		Cryogenic	183	200	28,000
McClure	2013		Cryogenic	182	200	22,000
Wheeler	2012		Cryogenic	138	200	22,000
South Canadian	2011		Cryogenic	197	200	26,000
Clinton	2009		Cryogenic	70	120	14,000
Roger Mills	2008		Refrigeration	2	100	—
Canute	1996		Cryogenic	26	60	4,300
Cox City	1994		Cryogenic	124	180	14,500
Thomas	1981		Cryogenic	1	135	9,900
Calumet	1969		Lean Oil	96	250	8,000
Arkoma
Wetumka	1983		Cryogenic	31	60	5,000
Ark-La-Tex
Panola	2007		Cryogenic	2	100	8,000
Sligo (3)	2004		Refrigeration	20	225	1,400
Waskom	1995	(4)	Cryogenic	195	320	14,500
Total				1,449	2,550	205,600

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(1)In addition to the processing plants listed above, the Partnership is a party to a 10-year gathering and processing agreement, which became effective on July 1, 2018, and provides for 400 MMcf/d of deliveries to Energy Transfer, LP’s Godley Plant in Johnson County, Texas.

(2)Excludes condensate.

(3)Average daily inlet volumes and inlet capacity includes 20 MMcf/d and 25 MMcf/d, respectively, related to a separate cryogenic unit.

(4)A processing plant has been in operation on the Waskom plant site since 1940. The Waskom plant was upgraded to cryogenic in 1995.

The natural gas processing assets in the Anadarko Basin include 11 processing plants, 10 of which are interconnected through our super-header system. The super-header system is configured to facilitate the flow of natural gas across our operating areas in western Oklahoma and the Texas Panhandle to the Bradley II, Bradley, McClure, Wheeler, South Canadian, Clinton, Canute, Cox City, Thomas and Calumet processing plants. The super-header system allows us to optimize the utilization of the connected processing plants and additional third-party contracted capacity at Energy Transfer, LP’s Godley plant. Similarly, the natural gas processing assets in the Ark-La-Tex Basin include three processing plants, of which Waskom and Panola are interconnected to optimize the utilization of these processing plants. Optimization of our interconnected processing plants may result in certain plants being temporarily idled.

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

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and sell propane to local markets. Additionally, we operate a fractionator at our Waskom plant and sell ethane, propane, butane and natural gasoline to local markets.

Crude Oil, Condensate and Produced Water Gathering Assets. The following table sets forth certain information regarding our crude oil gathering assets as of or for the year ended December 31, 2020:


Asset/Basin	Approximate Length (miles)	Design Capacity (MBbls/d)	Average Throughput Volume (MBbls/d)
Anadarko Basin crude oil and condensate	190	275	95.44
Williston Basin crude oil	180	58	29.40
Williston Basin produced water	160	19	19.16
Total	530	352	144.00

Our Anadarko Basin crude oil and condensate gathering assets were designed and built to serve the crude oil and condensate production in the SCOOP and STACK plays (including the area where the SCOOP and STACK come together known as the Merge play). A portion of our operations are conducted through ESCP, a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest. On our system, crude oil and condensate is either received on gathering lines near our customers’ wells or via truck unloading terminals. We do not take title to crude oil or condensate gathered on our system. Crude oil and condensate gathered on our Anadarko Basin gathering system can be redelivered to our customers through interconnections to the Basin Pipeline, the Red River Pipeline and the Wynnewood Refinery. For the year ended December 31, 2020, 56% of crude oil and condensate gathered on the system was delivered to the Wynnewood Refinery.

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.

Natural Gas Gathering and Processing Customers. For the year ended December 31, 2020, our top natural gas gathering and processing customers by gathered volumes were Continental Resources, Inc. (Continental), Vine Oil & Gas LP (Vine), GeoSouthern Energy Corporation (GeoSouthern), XTO, Marathon Oil Corporation (Marathon Oil), Tapstone Energy LLC, Ovintiv Inc. (Ovintiv), Unbridled Resources, LLC, Red Wolf Operating, LLC and Rockcliff Energy LLC. For the year ended December 31, 2020, our top ten natural gas producer customers accounted for approximately 70% of our natural gas gathered volumes.

Crude Oil, Condensate and Produced Water Gathering Customers. Our Anadarko Basin crude oil gathering system gathers crude oil and condensate from producers, which are primarily delivered to CVR Energy, Inc. Our Anadarko Basin crude oil and condensate gathering systems are intrastate pipeline systems, and the rates and terms of service are regulated by the OCC. Our Williston Basin crude oil and produced water gathering systems primarily serve XTO. Crude oil on the Williston Basin systems is delivered for transportation on third-party interstate pipeline systems, and produced water is delivered to third party injection wells. Our Williston Basin crude oil gathering systems, but not our produced water gathering systems, are considered interstate pipeline systems, and the rates and terms of service are regulated by FERC under the Interstate Commerce Act.

Contracts. Our contracts typically provide for crude oil, condensate and produced water gathering services that are fee-based, for natural gas gathering services that are fee-based and for natural gas processing arrangements that are fee-based, or percent-of-liquids, percent-of-proceeds or keep-whole based.

•Under a typical fee-based processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs from the producer less a fee, return the processed natural gas to the producer and sell the NGLs for our own account.

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•Under a typical percent-of-liquids processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs, less the value of the percentage of NGLs retained on our own account, from the producer, return the processed natural gas to the producer and sell the NGLs for our own account.

•Under a typical percent-of-proceeds processing arrangement, we process the raw natural gas to extract the NGLs, purchase the NGLs, less the value of the percentage of natural gas and NGLs retained on our own account, return the remaining percentage of processed natural gas to the producer and sell the purchased natural gas and NGLs for our own account.

•Under a typical keep-whole arrangement, we process raw natural gas to extract the NGLs, return a quantity of the processed natural gas to the producer that is equivalent to the raw natural gas on a Btu basis and retain and sell the NGLs for our own account.

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:


	Anadarko Basin		Arkoma Basin		Ark-La-Tex Basin		Williston Basin (2)		Total
Percentage of gathering and processing gross margin attributable to gathering contracts with minimum volume commitments	5	%	5	%	2	%	1	%	13	%
Percentage attributable to shortfall payments (1)	11	%	72	%	12	%	—	%	33	%
Natural gas volume commitment-weighted average remaining contract term (in years) (3)	7.5		3.7		1.8		—		5.1
Crude oil and condensate volume commitment-weighted average remaining contract term (in years) (3)	—		—		—		8.2		8.2

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(1)Represents the percentage of gathering and processing gross margin from gathering contracts with minimum volume commitments that were attributable to shortfall payments.

(2)Under the Williston Basin contracts, if the customer ships in excess of the minimum volume, this volume commitment could end before the expiration of the contract term.

(3)Weighted-average is based upon volumes for the year ended December 31, 2020.

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:


	Anadarko Basin	Arkoma Basin	Ark-La-Tex Basin	Williston Basin	Total
Gross acreage dedication (in millions)	4.9	1.6	0.8	0.3	7.6
Natural gas volume-weighted average remaining contract term (in years)	6.1	1.9	3.6	—	4.7
Crude oil and condensate volume-weighted average remaining contract term (in years)	11.3	—	—	8.3	10.3

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Construction. Our gathering and processing business involves the construction of gathering and processing assets as needed to serve our existing and new customers. For example, during the year ended December 31, 2020, we invested $59 million of expansion capital in the construction of gathering and processing assets, which primarily included well connections to our gathering system. The Partnership has taken steps to preserve the previously announced Wildhorse Plant, a cryogenic processing plant in Garvin County, Oklahoma for which construction was halted, so that construction can be resumed when the need for additional processing capacity on our super-header system arises.

Trends in Market Demand and Competition. Competition for our gathering and processing systems is primarily a function of rates, terms of service, flexibility and reliability. For natural gas gathering and processing, rates include fees for services, retained fuel and prices paid for NGLs. Our gathering and processing systems compete with other midstream service providers, including those affiliated with producers. Our crude oil, condensate and produced water gathering systems also compete against trucking and railroad transportation companies. In the process of selling NGLs, we compete against other natural gas processors extracting and selling NGLs. 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.”

Seasonality. While the results of our gathering and processing segment are not materially affected by seasonality, from time to time our operations and construction of assets can be impacted by inclement weather.

Transportation and Storage

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:


Transportation and Storage
Asset	Length (miles)	Compression (Horsepower)	Average Throughput (TBtu/d)		Transportation Capacity (Bcf/d) (1)		Transportation Firm Contracted Capacity (Bcf/d) (2)		Storage Capacity (Bcf)		Storage Firm Contracted Capacity (Bcf/d)
EGT	5,900	397,000	3.02		6.2		4.60		29.0		22.92
MRT	1,600	121,700	0.64		1.7		1.45		31.5		26.03
EOIT	2,200	213,600	1.79	(3)	—	(3)	—		24.0		10.21
Subtotal	9,700	732,300	5.45		7.9		6.05		84.5		59.16
SESH	290	107,000	—	(5)	—	(4)	—	(5)	—	(5)	—	(5)
Total	9,990	839,300	5.45		7.9		6.05		84.5		59.16

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(1)Actual volumes transported per day may be less than total firm contracted capacity based on demand.

(2)Transportation Firm Contracted Capacity includes contracts with affiliates and our subsidiaries.

(3)Our EOIT pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits our ability to determine an overall system capacity. During the year ended December 31, 2020, the peak daily throughput was 2.4 TBtu/d or, on a volumetric basis, 2.4 Bcf/d.

(4)SESH has 1.09 Bcf/d of transportation capacity from Perryville, Louisiana to its endpoint in Mobile County, Alabama.

(5)We own a 50% interest in SESH and as such, do not include certain information regarding its transportation and storage assets in the table set forth above.

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

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expansion capital in the construction of transportation pipeline and facilities, including the acquisition of right-of-way, environmental permitting, regulatory filings and engineering related to the Gulf Run Pipeline project, and construction of the MASS project, which began during 2020. In September 2018, we executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. The Gulf Run Pipeline project is designed to connect U.S. natural gas supplies to the LNG export market on the Gulf Coast. On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. On February 28, 2020, the Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline. FERC issued the environmental assessment on October 29, 2020. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project just to serve Golden Pass LNG would be as much as $500 million and the project is backed by a 20-year firm transportation service agreement for 1.1 Bcf/d. The project scope filed for in the application is expected to provide for approximately 1.7 Bcf/d of capacity, which would both accommodate Golden Pass LNG’s 1.1 Bcf/d commitment and allow for additional capacity subscriptions that may develop from ongoing discussions, at an estimated cost of approximately $640 million, which excludes amounts related to allowance for funds used during construction. Ultimately, the project will be sized to meet contracted customer capacity commitments. The project is expected to be placed into service in late 2022.

Our transportation assets include approximately 9,990 miles of transportation pipelines in Texas, Oklahoma, Arkansas, Louisiana, Kansas, Mississippi, Alabama, Missouri and Illinois (including SESH), providing access to natural gas supplies from the Anadarko, Arkoma and Ark-La-Tex Basins to natural gas consuming markets in the Southeastern, Northeastern and Midwestern United States. Our storage assets, as of December 31, 2020, provide a combined capacity of 84.5 Bcf with 1.9 Bcf/d of aggregate maximum withdrawal capacity from our seven storage facilities in Oklahoma, Louisiana and Illinois. On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana. On January 27, 2020, FERC approved the sale. The Partnership closed the sale on April 1, 2020. See Note 17 “Commitments and Contingencies” in the Notes to the Consolidated Financial Statements in Part II, Item 8. “Financial Statements and Supplementary Data” for further discussion.

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Our transportation and storage assets are comprised of three categories: (1) interstate transportation and storage, (2) intrastate transportation and storage and (3) our investment in SESH.

Interstate Transportation and Storage

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.

EGT

EGT provides natural gas transportation and storage services primarily to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. In addition to 5,900 miles of interstate pipelines with capacity of 6.2 Bcf/d, EGT has two underground natural gas storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana, which, as of December 31, 2020, operate at a combined capacity of 29.0 Bcf with 739 MMcf/d of aggregate maximum withdrawal capacity.

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Interconnections and Delivery Points. In addition to delivering natural gas to utilities and industrial end users in Oklahoma, Louisiana, Texas and Arkansas, EGT receives natural gas from and delivers natural gas to a variety of intrastate and interstate pipelines through its numerous interconnections. Those interconnections include ANR, Columbia Gulf, El Paso Natural Gas, EOIT, Gulf South, Midcontinent Express Pipeline, MRT, Northern Natural Gas, Natural Gas Pipeline Company of America, Panhandle Eastern Pipe Line, SESH, SONAT, Southern Star, Tennessee Gas, Texas Eastern, Texas Gas and Trunkline. Through EGT’s interconnection with SESH, our customers have access to the Southeast power generation market. Through our interconnections with other pipelines, our customers have access to the Midwest and Northeast markets. Many of EGT’s interconnections are at the Perryville Hub, which provides the ability to move natural gas between 17 major interstate pipelines. As a result, EGT provides our customers with access to not only natural gas consuming markets in Oklahoma, Louisiana, Texas and Arkansas, but also most of the major natural gas consuming markets east of the Mississippi River. In addition, EGT provides our customers supplying those markets with access to natural gas from producing basins and shale

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plays across the Mid-continent, including the Anadarko, Arkoma and Ark-La-Tex Basins and the Barnett, Fayetteville, Granite Wash, Haynesville, SCOOP and STACK plays.

Customers. EGT primarily serves LDCs owned by CenterPoint Energy, producers in key plays in the Mid-continent, power plants, other LDCs and industrial end users. EGT’s customers are primarily located in Arkansas, Louisiana, Oklahoma and Texas. For the year ended December 31, 2020, approximately 28% of EGT’s service revenues were attributable to contracts with LDCs owned by CenterPoint Energy. As of December 31, 2020, contracts with LDCs owned by CenterPoint Energy had a volume-weighted average remaining contract life of 8.5 years for transportation and 6.3 years for storage. In addition to CenterPoint Energy’s LDCs, EGT’s other major customers include Continental and Ovintiv.

Contracts. Although EGT has established maximum rates for interstate transportation and storage services as required by FERC, EGT is authorized to enter into negotiated rate and discounted rate agreements with its customers. EGT’s services are typically provided under firm, fee-based transportation and storage agreements. As of December 31, 2020, approximately 44% of our aggregate contracted firm transportation capacity on EGT was subscribed under negotiated rate contracts and 100% of our aggregate contracted firm storage capacity on EGT was subscribed under negotiated rate contracts. For the year ended December 31, 2020, approximately 42% of our aggregate contracted firm transportation capacity on EGT was subscribed under discounted rate contracts. For the year ended December 31, 2020, approximately 55% of our transportation and storage gross margin was derived from EGT’s firm contracts, 74% of EGT’s transportation capacity was under firm contracts and 79% of EGT’s storage capacity was under firm contracts. EGT’s transportation capacity under firm contracts had a volume-weighted average remaining contract life of 4.0 years and EGT’s storage capacity under firm contracts had a volume-weighted average remaining contract life of 6.3 years. During 2020, CenterPoint’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas extended their transportation and storage services with EGT. As of December 31, 2020, EGT’s transportation contracts representing 3%, 8%, and 89% of CenterPoint Energy’s firm transportation capacity are scheduled to expire in 2021, 2024, and 2030, respectively. EGT’s firm storage contracts representing 33% and 67% of CenterPoint Energy’s firm storage capacity are scheduled to expire in 2021 and 2030, respectively.

MRT

MRT provides natural gas transportation and storage services principally in Texas, Arkansas, Louisiana, Missouri and Illinois. In addition to 1,600 miles of interstate pipelines with capacity of 1.7 Bcf/d, MRT has underground natural gas storage facilities in Louisiana, which includes the East Unionville and West Unionville fields, and one underground natural gas storage facility in Illinois, which, as of December 31, 2020, operate at a combined capacity of 31.5 Bcf with 590 MMcf/d of aggregate maximum withdrawal capacity.

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Interconnections and Delivery Points. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections and delivers natural gas primarily to the St. Louis market. Those interconnections include EGT, Gulf South, Natural Gas Pipeline Company of America, Ozark Gas Transmission, Texas Eastern, Texas Gas, Trunkline and STL Pipeline. From MRT’s west line, we provide our customers with access to supply from East Texas and North Louisiana, including the Haynesville Shale. From MRT’s mainline, we provide our customers with access to supply from the Anadarko, Arkoma and Ark-La-Tex Basins. Supply from the Fayetteville Shale is transported though our interconnection with EGT, Texas Gas and Ozark Gas Transmission. From MRT’s east line, we provide our customers with access to supply from the Mid-continent and the Marcellus Shale through our interconnections with Natural Gas Pipeline Company of America and Trunkline. As a result, MRT provides the St. Louis market with access to natural gas from a variety of major producing basins across the U.S.

Customers. MRT primarily serves the St. Louis LDC owned by Spire. For the year ended December 31, 2020, 63% of MRT’s service revenues were attributable to contracts with Spire. As of December 31, 2020, contracts with Spire had a volume-weighted average remaining contract life of 4.1 years for transportation and 3.3 years for storage. MRT’s other customers include utilities and industrial end users. MRT’s customers are primarily located in Arkansas, Missouri and Illinois.

Contracts. MRT’s services are typically provided under firm, fee-based transportation and storage agreements, with rates and terms of service regulated by FERC. On March 26, 2020, MRT received FERC approval of its uncontested rate case settlements with customers. As a result of the settlements, effective August 1, 2019, MRT’s maximum firm transportation rates for service across both of MRT’s pipeline zones increased by approximately 60% and storage deliverability and capacity rates increased by approximately 30%, as compared to the rates in effect immediately prior to January 1, 2019. The settlements also included contract extensions for most firm transportation and storage customers through July 31, 2024. Although MRT has established maximum rates for interstate transportation and storage services as required by FERC, MRT is authorized to enter into negotiated rate and discounted rate agreements with its customers. As of December 31, 2020, approximately 14% of our aggregate contracted firm transportation capacity on MRT was subscribed under negotiated rate contracts and approximately 12% of our aggregate contracted firm storage capacity on MRT was subscribed under negotiated rate contracts. For the year ended December 31, 2020, approximately 69% of our aggregate contracted firm transportation capacity on MRT was

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subscribed under discounted rate contracts and approximately 78% of our aggregate contracted firm storage capacity on MRT was subscribed under discounted rate contracts. For the year ended December 31, 2020, approximately 17% of our transportation and storage gross margin was derived from MRT’s firm contracts, 83% of MRT’s transportation capacity was under firm contracts and 85% of MRT’s storage capacity was under firm contracts. As of December 31, 2020, MRT’s transportation capacity under firm contracts had a volume-weighted average remaining contract life of 3.9 years and MRT’s storage capacity under firm contracts had a volume-weighted average remaining contract life of 3.3 years. MRT’s firm transportation contracts representing 63%, 24% and 12% of Spire’s firm transportation capacity are scheduled to expire in 2024, 2025 and 2026, respectively. All of Spire’s firm storage contracts are scheduled to expire in 2024.

Intrastate Transportation and Storage

Our intrastate natural gas transportation and storage assets consist primarily of EOIT. EOIT provides transportation and storage services in Oklahoma. Our EOIT system delivers natural gas from the Anadarko and Arkoma Basins, including the SCOOP, STACK, Cana Woodford, Granite Wash, Cleveland, Tonkawa, and Mississippi Lime Shale plays in western Oklahoma, to utilities and industrial end users connected to EOIT and to interstate and intrastate pipelines interconnected with EOIT. EOIT had 1.79 TBtu/d of average daily throughput for the year ended December 31, 2020. In addition to 2,200 miles of intrastate pipelines, EOIT has two underground natural gas storage facilities in Oklahoma, which, as of December 31, 2020 operate at a combined capacity of 24 Bcf with 605 MMcf/d of aggregate maximum withdrawal capacity.

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Interconnections and Delivery Points. EOIT has 80 interconnections, which include interconnects with EGT and 11 third-party interstate and intrastate natural gas pipelines, including ANR Pipeline, El Paso Natural Gas Pipeline, Gulf Crossing Pipeline Company LLC, Midcontinent Express Pipeline, Natural Gas Pipeline Company of America, Northern Natural Gas Company, ONEOK Gas Transmission, Ozark Gas Transmission, Panhandle Eastern Pipe Line, Postrock KPC Pipeline, LLC, and Southern Star Central Gas Pipeline. In addition, EOIT connects to 46 end-user customers, including 15 natural gas-fired electric generation facilities in Oklahoma.

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Customers. EOIT’s customers include Oklahoma’s two largest electric utilities, OG&E, an affiliate of OGE Energy and Public Service Company of Oklahoma (PSO), an affiliate of AEP. For the year ended December 31, 2020, approximately 7% of our transportation and storage gross margin was attributable to firm contracts with OG&E, and approximately 3% of our transportation and storage gross margin was attributable to a firm contract with PSO. Our no-notice load-following transportation agreement with OG&E for three of its generating facilities extends through May 1, 2024 and will remain in effect year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. Our firm transportation agreement with OG&E, for one of its generating facilities extends through December 1, 2038. Our transportation agreement with PSO extends through December 31, 2023. EOIT’s customers also include other electric generators, LDCs, Arkoma and Anadarko Basin producers and industrial end users.

Contracts. EOIT provides fee-based firm and interruptible transportation and storage services on both an intrastate basis and, pursuant to Section 311 of the NGPA, on an interstate basis. For the year ended December 31, 2020, approximately 22% of our transportation and storage gross margin was derived from EOIT’s firm contracts. EOIT’s transportation capacity was under firm contracts with a volume-weighted average remaining contract life of 7.0 years and EOIT’s storage capacity was under firm contracts with a volume-weighted average remaining contract life of 1.2 years.

Our Investment in SESH

SESH is an approximately 290-mile interstate pipeline that provides transportation services in Louisiana, Mississippi and Alabama. We own a 50% interest in SESH and provide field operations for the pipeline. Enbridge Inc. owns the remaining 50% interest in SESH and provides gas control and commercial operations for the pipeline. As of December 31, 2020, SESH operates at 1.09 Bcf/d of transportation capacity from the Perryville Hub in Louisiana to its endpoint in Mobile County, Alabama.

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Interconnections and Delivery Points. SESH runs from the Perryville Hub in northeastern Louisiana to southwestern Alabama near the Gulf Coast. SESH has 20 interconnects with third-party natural gas pipelines and provides access to major Southeast and Northeast markets. Natural gas transported by SESH is transported directly to generating facilities in Mississippi

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and Alabama and to interconnecting pipelines that supply companies generating electricity for the Florida power market. SESH also interconnects with three high-deliverability storage facilities, Mississippi Hub Storage, Petal Gas Storage and Southern Pines Energy Center.

Customers and Contracts. SESH’s customers are primarily companies that generate electricity for the Southeast power market. The rates charged by SESH for interstate transportation services are regulated by FERC. SESH’s transportation services are typically provided under firm, fee-based negotiated rate agreements. As of December 31, 2020, SESH’s transportation contracts have a volume-weighted average remaining contract life of 3.7 years.

Seasonality

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.

Trends in Market Demand and Competition

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.”

Regulatory Compliance

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.

Economic Regulation

Interstate Natural Gas Pipeline Regulation

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:

•rates, terms and conditions of service and service contracts;

•certification and construction of new facilities or expansion of existing facilities;

•abandonment of facilities;

•maintenance of accounts and records;

•acquisition and disposition of facilities;

•initiation, extension or abandonment of services;

•accounting, depreciation and amortization policies;

•conduct and relationship with certain affiliates;

•market manipulation in connection with the purchase or sale of natural gas or transportation in interstate commerce; and

•various other matters.

Under the NGA, the rates for service on interstate facilities must be just and reasonable and not unduly discriminatory. Generally, the maximum recourse rates for interstate pipelines are based on the pipeline’s cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are the total costs of providing service, allowed rate of return and throughput projections. Our interstate pipeline operations may be affected by

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changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.

Rate and tariff changes can only be implemented upon approval by FERC. Two primary methods are available for changing the rates, terms and conditions of service of an interstate natural gas pipeline. Under the first method, the pipeline voluntarily seeks a rate or tariff change by making a filing with FERC justifying the proposed change. FERC provides notice of the proposed change to the public through publication on its website and in the Federal Register. If FERC determines that a proposed change is just and reasonable, FERC grants approval of and allows the pipeline to implement the change. If FERC determines that a proposed change may not be just and reasonable, FERC may suspend the proposed change for up to five months. Subsequent to any suspension period ordered by FERC, the proposed change may be placed into effect by the company, pending final FERC approval. In most cases, a proposed rate change is placed into effect before a final FERC determination on such rate change, and the pipeline is permitted to collect the proposed rate subject to refund with interest. Under the second method, FERC may, on its own motion or based on a complaint filed by a third party, initiate a proceeding seeking to compel the company to change its rates, terms and/or conditions of service. If FERC determines that the existing rates, terms and/or conditions of service are unjust, unreasonable, unduly discriminatory or preferential, then any rate reduction or change that it orders generally will be effective prospectively from the date of the FERC order requiring this change.

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.

Intrastate Natural Gas Pipeline and Storage Regulation

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

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generally subject to review and approval by FERC at least once every five years. Should FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our results of operations and cash flows may be adversely affected.

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.

Natural Gas Gathering and Processing Regulation

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.

States may regulate gathering pipelines. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, requirements prohibiting undue discrimination, and in some instances complaint-based rate regulation. Our natural gas gathering operations may be subject to ratable take and common purchaser statutes in the states in which they operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source

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of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

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.

Sales of Natural Gas

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.

Interstate Crude Oil Gathering Regulation

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:

•the overall cost of service, including operating costs and overhead;

•the allocation of overhead and other administrative and general expenses to the regulated entity;

•the appropriate capital structure to be utilized in calculating rates;

•the appropriate rate of return on equity and interest rates on debt;

•the rate base, including the proper starting rate base; and

•the throughput underlying the rate.

For some time now, FERC has been issuing regulatory assurances that necessarily balance the anti-discrimination and undue preference requirements of common carriage with the expectations of investors in new and expanding petroleum pipelines. There is an inherent tension between the requirements imposed upon a common carrier and the need for owners of petroleum pipelines to be able to enter into long-term, firm contracts with shippers willing to make the commitments which underpin such large capital investments. For example, FERC has found that shipper contract rates are not per se violations of

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the duty of non-discrimination, provided that such rates are available to all similarly-situated shippers. In the same vein, FERC has approved varying term commitments with tiered rate discounts on the basis that committed shippers were not similarly situated with uncommitted shippers and further that different types of committed shippers were not similarly situated with each other if their commitment level materially differed. FERC has also found that shippers making certain capacity commitments to the pipeline can take advantage of priority or firm service, which is service that is not subject to typical capacity allocation requirements, so long as any interested shipper has an equal opportunity to make such a commitment to the carrier. FERC’s solution has been to allow carriers to hold an “open season” prior to the in-service date of a pipeline, during which time interested shippers can make commitments to the proposed pipeline project. Throughput commitments from interested shippers during an open season can be for firm service or for non-firm service. Typically, such an open season is for a 30-day period, must be publicly announced, and culminates in interested parties entering into transportation agreements with the carrier. Under FERC precedent, a carrier typically may reserve up to 90% of available capacity for the provision of firm or priority service to shippers making a commitment. At least 10% of capacity ordinarily is reserved for uncommitted shippers, i.e., “walk-up” shippers.

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.

Intrastate Crude Oil and Condensate Gathering Regulation

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.

Safety and Health Regulation

Pipeline Safety

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

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Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

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.

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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.

Occupational Health and Safety

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.

Environmental Regulation

General

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.”

Air

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

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regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and impose various monitoring and reporting requirements. Such laws and regulations require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions (including greenhouse gas emissions as discussed below), obtain and strictly comply with air permits containing various emissions and operational limitations, and incur expenditures to install and maintain emissions control equipment.

Climate Change

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

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an executive order calling for the development of a climate finance plan and, separately, the Federal Reserve announced that it has joined 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 midstream 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 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

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.

Protected Species

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.

Hazardous Substances and Waste

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

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classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Because we utilize various products and generate wastes that are considered hazardous substances for purposes of CERCLA, we could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment.

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.

Water

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

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

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analyzed, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPA finalized regulations under the CWA in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations.

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.”

Human Capital Management

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.

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Item 1A. Risk Factors

You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our business and the industry in which we operate, while others relate principally to tax matters, ownership of our common units, our preferred units and securities markets generally. If any of the following risks 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.

Risks Related to Our Business

Results of Operations and Financial Condition

Our contracts are subject to renewal risks.

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, in part, on the drilling and production decisions of others. In response to sharp declines in demand for oil and gas as well as commodity prices resulting from the economic impact of the COVID-19 pandemic, many producers have significantly reduced previously anticipated drilling and production activities and may make additional reductions in the future

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:

•the availability and cost of capital;

•prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

•demand for natural gas, NGLs and crude oil;

•levels of reserves;

•geological considerations;

•global or national health events, including epidemics and pandemics such as the ongoing COVID-19 pandemic;

•environmental or other governmental regulations, including the availability of drilling permits, the regulation of hydraulic fracturing, and the regulation of air emissions; and

•the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new natural gas, NGLs and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, NGLs, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and

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a variety of additional factors that are beyond our control. Because of these and other factors, even if new reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Declines in natural gas, NGLs or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. For instance, the recent COVID-19 pandemic has adversely affected our business by (i) reducing the demand for natural gas, NGLs and crude oil due to reduced global and national economic activity, leading to significantly lower prices for natural gas, NGLs and crude oil, (ii) impairing the supply chain of certain of our customers for which we provide gathering and processing services, which could lead to further reduction of the utilization of our systems, and (iii) reducing producer activity across our footprint, which is expected to continue to result in reduced utilization of our services. We currently cannot predict the duration or magnitude of the effects of the COVID-19 pandemic on supply and demand for natural gas, NGLs and crude oil or the exploration, development and production activity of the producers across our areas of operation. In addition, concerns about global economic growth, as well as uncertainty regarding the timing, pace and extent of an economic recovery in the United States and abroad, have had a significant adverse impact on global financial markets and commodity prices, and sustained low natural gas, NGLs or crude oil prices could also lead producers to shut in production from their existing wells. Sustained reductions in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders and result in the impairment of our assets.

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.

Our industry is highly competitive and increased competitive pressure could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

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.

Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders. Prices for all three of these commodities have been adversely affected by the impact of the COVID-19 pandemic, with crude oil prices reaching historic lows in April 2020.

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

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crude oil prices have remained depressed. These events, combined with the continuing COVID-19 pandemic and uncertainty regarding the length of time it will take for the United States and the rest of the world to slow the spread of COVID-19 to the point where applicable authorities are comfortable easing current restrictions on various commercial and economic activities, contributed to a sharp drop in prices for crude oil in the first and second quarters of 2020.

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 pandemic, epidemic or outbreak of an infectious disease, such as the COVID-19 pandemic, may materially adversely affect our business.

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 provide certain transportation and storage services under fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

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.

If third-party pipelines and other facilities interconnected to our gathering, processing or transportation facilities become partially or fully unavailable to us for any reason, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

We depend upon (i) third-party pipelines to deliver natural gas to, and take natural gas from, our natural gas transportation systems, (ii) third-party pipelines and other facilities to take crude oil, condensate and produced water from our crude oil, condensate and produced water gathering systems, and, in some cases, (iii) third-party facilities to process natural gas from our gathering systems. We also depend on third-party facilities to transport and fractionate NGLs that are delivered to the third

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party at the tailgates of our processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. An outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of our processing plants and gathering systems, and a prolonged outage or disruption could ultimately result in a reduction in the volume of natural gas we gather and NGLs we are able to produce. For example, substantially all of the crude oil gathered by our Williston Basin systems is delivered indirectly for transport to the Dakota Access Pipeline (DAPL). Although the crude oil gathered by our Williston Basin crude oil systems may also be delivered for transport to other pipelines, such as BakkenLink Pipeline and Enbridge North Dakota Pipeline, a shutdown of DAPL, or any other significant pipeline providing transportation services from the Williston Basin, could result in the shut-in of wells connected to our Williston Basin crude oil systems if our customers are unable to obtain sufficient capacity on those pipelines at an effective cost. In July 2020, the federal district court for the District of Columbia vacated the Corps’ grant of an easement to DAPL and issued an order requiring DAPL to be shut down and emptied of crude oil by August 5, 2020, pending the completion of an environmental impact analysis for the pipeline. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. However, the Court of Appeals stated that the Corps may require the pipeline to shut down pending the required environmental review. The District Court is currently considering whether to enjoin the operation of the pipeline due to the lack of an easement and has not yet ruled on this matter. We are unable to predict the likelihood or extent of any shut down or the resulting impact on our operations in the Williston Basin. Additionally, we depend on third parties to provide electricity for compression, pumping and other operational activities at many of our facilities. Since we do not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines or other facilities become partially or fully unavailable to us for any reason, our financial position, results of operations and ability to make cash distributions to unitholders could be adversely affected.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

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.

An impairment of long-lived assets, including intangible assets or equity method investments could reduce our earnings.

Long-lived assets, including intangible assets with finite useful lives and property, plant and equipment, are evaluated for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment of long-lived assets is recognized if the carrying amount is not recoverable and exceeds fair value. Due to decreases in natural gas and NGL market prices during 2020 as a result of the economic effects of the ongoing COVID-19 pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not fully recoverable. The Partnership recognized a $16 million impairment, which is included in Impairments of property, plant and equipment and goodwill on the Consolidated Statements of Income for the year ended December 31, 2020.

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

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earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. As a result, an impairment could have an adverse effect on our results of operations and our ability to satisfy the financial ratios or other covenants under our existing or future debt agreements.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely affect our financial position, results of operations and our ability to make cash distributions to unitholders.

Our operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:

•damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;

•inadvertent damage from construction, vehicles and farm and utility equipment;

•leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;

•ruptures, fires and explosions; and

•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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.

The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could adversely affect 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.

Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.

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.

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Cybersecurity attacks or other disruptions of our systems, networks and technology could adversely impact our financial position, results of operations and ability to make cash distributions to unitholders.

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.

Terrorist attacks or other physical security threats could adversely affect our business.

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.

If we fail to maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

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.

Pending Merger with Energy Transfer

Because the exchange ratio is fixed and because the market price of Energy Transfer’s common units may fluctuate, our unitholders cannot be certain of the precise value of any merger consideration they may receive in the Energy Transfer merger.

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

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market value of Energy Transfer’s common units at the time the merger agreement was entered into or at any other time. Our unitholders should obtain current quotations for Energy Transfer’s common units and for our common units.

The merger may not be completed and the merger agreement may be terminated in accordance with its terms.

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 limits our ability to pursue alternatives to the merger.

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.

Failure to complete the merger could negatively impact the price of our common units, as well as our future businesses and financial results.

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:

•we may experience negative reactions from the financial markets, including negative impacts on the market price of our common units;

•the manner in which customers, vendors, business partners and other third parties perceive us may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;

•we will still be required to pay certain significant costs relating to the merger, such as legal, accounting, financial advisor and printing fees;

•we may experience negative reactions from employees; and

•we will have expended time and resources that could otherwise have been spent on our existing businesses and the pursuit of other opportunities that could have been beneficial to the Partnership.

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.

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We will be subject to business uncertainties while the merger is pending, which could adversely affect our businesses.

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.

The common units representing limited partner interests in Energy Transfer to be received by our common unitholders upon completion of the merger will have different rights than our common units.

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.

Completion of the merger may trigger change in control or other provisions in certain agreements to which we are a party.

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 will incur significant transaction and merger-related costs in connection with the merger, which may be in excess of those anticipated by 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.

We may be a target of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the merger from being 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.

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Customers

We depend on a small number of customers for a significant portion of our gathering and processing revenues and our transportation and storage revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of our gathering and processing or transportation and storage services and adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

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.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our financial position, results of operations and ability to make cash distributions to unitholders.

Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. For example, some of our customers have experienced significantly reduced liquidity as a result of the economic effects caused by the COVID-19 pandemic. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

Indebtedness; Financing

Our and our operating subsidiaries’ debt levels may limit our and their flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2020, we had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on senior notes. In addition, as of December 31, 2020, we had $250 million outstanding under our commercial paper program. We have a $1.75 billion Revolving Credit Facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.50 billion in borrowing capacity was undrawn as of December 31, 2020. As of January 29, 2021, we had $204 million outstanding under our commercial paper program and $1.54 billion of undrawn borrowing capacity under the Revolving Credit Facility. We have the ability to incur additional debt, subject to limitations in our credit facilities. The levels of our debt could have important consequences, including the following:

•the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;

•a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;

•our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•our debt level may limit our flexibility in responding to changing business and economic conditions.

For a further discussion of the impact of the limitations in our credit facilities, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

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