EX-99

We have audited the accompanying consolidated balance sheets of Enable Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, cash flows and partners' equity, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2021 (not presented herein), expressed an unqualified opinion on the Partnership's internal control over financial reporting.

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Evaluation of the estimated undiscounted cash flows in the long-lived assets impairment analysis - Refer to Notes 1 and 8 to the consolidated financial statements

The Partnership periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles other than goodwill, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets.

Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and the economic effects of the pandemic, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, events or changes in circumstances indicated that the carrying value of certain assets groups in the Gathering & Processing (“G&P”) segment may not be recoverable. The net book value of the G&P asset groups was $7,470 million as of December 31, 2020. The Partnership recognized a $16 million impairment during the year ended December 31, 2020.

Given the significant judgments made by management to estimate the recoverability of G&P asset groups, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenues, including the revenue growth rate, of G&P asset groups required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

Our audit procedures related to the forecasts of future revenues, including the revenue growth rate, used by management to estimate the recoverability of G&P asset groups included the following, among others:

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We tested the effectiveness of controls over management’s long-lived assets impairment evaluation, including those over the determination of the recoverability of G&P asset groups, such as controls related to management’s forecasts of future revenues, including the revenue growth rate.

Other-Than-Temporary-Impairment (“OTTI”) of the Southeast Supply Header, LLC (“SESH”) equity method investment - Refer to Notes 1 and 11 to the consolidated financial statements

SESH is an approximately 290-mile interstate pipeline that provides transportation services in Louisiana, Mississippi and Alabama. The Partnership own a 50% interest in SESH and provides field operations for the pipeline. Enbridge Inc. owns the remaining 50% interest in SESH and provides gas control and commercial operations for the pipeline.

The Partnership evaluates its investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the fair value of its investment has occurred and the fair value of its investment is less than the carrying amount.

During the third quarter of 2020, due to the expiration of a transportation contract and the current status of renewal negotiations, the Partnership evaluated its equity method investment in SESH for other-than-temporary impairment. The Partnership utilized the market and income approaches to measure the estimated fair value of its investment in SESH. The Partnership determined the decline in value of its investment in SESH was other-than-temporary, and recorded an impairment of its investment in SESH of $225 million.

Given the significant judgments made by management to estimate the fair value of SESH, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenues, including the revenue growth

rate, and the selection of the weighted average cost of capital and market multiple of SESH required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

Our audit procedures related to the weighted average cost of capital, market multiple, and forecasts of future revenues, including the revenue growth rate, used by management to estimate the fair value of SESH included the following, among others:

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We tested the effectiveness of controls over management’s equity method investment impairment evaluation, including those over the determination of the fair value of SESH, such as controls related to management’s forecasts of future revenues, including the revenue growth rate, and selection of the weighted average cost of capital and market multiple.

Enable Midstream Partners, LP (the Partnership) is a Delaware limited partnership formed on May 1, 2013. The Partnership’s 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.

CenterPoint Energy and OGE Energy each have 50% of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of two representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and three independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a 40% and 60% interest, respectively, in the incentive distribution rights held by Enable GP.

At December 31, 2020, CenterPoint Energy held approximately 53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 7 for further information related to the Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect Enable GP on an annual or continuing basis and may not remove Enable GP without at least a 75% vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.

For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2020, 2019 and 2018, the Partnership owned a 50% ownership interest in Atoka and consolidated Atoka in the accompanying Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, for the period of November 1, 2018 through December 31, 2020, the Partnership owned a 60% interest in ESCP, which is consolidated in the accompanying Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

The accompanying Consolidated Financial Statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial

statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The Partnership generates the majority of its revenues from midstream energy services, including natural gas gathering, processing, transportation and storage and crude oil, condensate and produced water gathering. The Partnership performs these services under various contractual arrangements, which include fee-based contract arrangements and arrangements pursuant to which it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. The Partnership reflects revenue as Product sales and Service revenues on the Consolidated Statements of Income as follows:

Product sales: Product sales represent the sale of natural gas, NGLs, crude oil and condensate where the product is purchased and used in connection with providing the Partnership’s midstream services.

Service revenues: Service revenues represent all other revenue generated as a result of performing the Partnership’s midstream services.

The Partnership recognizes revenue from natural gas gathering, processing, transportation and storage and crude oil, condensate and water gathering services to third parties in accordance with ASU No. 2014-09 “Revenue from Contracts with Customers” (Topic 606). Under Topic 606, revenue is recognized at an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services. The determination of that amount and the timing of recognition is based on identifying the contracts with customers, identifying the performance obligations in the contract, determining the transaction price, allocating the transaction price to the performance obligations in the contract, and ultimately recognizing revenue when (or as) the entity satisfies the performance obligation.

Service revenues for gathering, processing, transportation and storage services for the Partnership are recorded each month as services have been completed and performance obligations are met. Product revenues are recognized when control is transferred. Monthly revenues are based on the current month’s estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on the current month’s nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on the current month’s estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated revenues are reflected in Accounts receivable, net or Accounts receivable—affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Total revenues on the Consolidated Statements of Income.

The Partnership records deferred revenue when it receives consideration from a third party before achieving certain criteria that must be met for revenue to be recognized in accordance with GAAP.

The Partnership relies on certain key natural gas producer customers for a significant portion of natural gas and NGLs supply. The Partnership relies on certain key utilities for a significant portion of transportation and storage demand. The Partnership depends on third-party facilities to transport and fractionate NGLs that it delivers to third parties at the inlet of their facilities. For the year ended December 31, 2020, one non-affiliate customer accounted for approximately 13%, or $310 million of our consolidated revenue. For the year ended December 31, 2019, one non-affiliate customer accounted for approximately 11%, or $328 million of our consolidated revenue. These revenues were primarily included in our gathering and processing segment. There are no revenue concentrations with individual non-affiliate customers in the year ended December 31, 2018. See note 16 for more information on revenues from affiliates.

Cost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation and amortization, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for purchases are based on estimated volumes and contracted purchase prices. Estimated purchases are included in Accounts Payable or Accounts Payable-affiliated companies, as appropriate, on the Consolidated Balance Sheets and in Cost of natural gas and natural gas liquids, excluding Depreciation and amortization on the Consolidated Statements of Income.

Operation and maintenance expense represents the cost of our service related revenues and consists primarily of labor expenses, lease costs, utility costs, insurance premiums and repairs and maintenance expenses directly related to the operations of assets. General and administrative expense represents cost incurred to manage the business. This expense includes cost of general corporate services, such as treasury, accounting, legal, information technology and human resources and all other expenses necessary or appropriate to the conduct of business. Any Operation and maintenance expense and General and administrative expense associated with product sales is immaterial.

The Partnership expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Partnership expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. The Partnership records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. There are $3 million and $0 accrued at December 31, 2020 and 2019, respectively.

Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization of intangible assets is computed using the straight-line method over the respective lives of the intangible assets.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets at the time the assets are placed in service. As circumstances warrant, useful lives are adjusted when changes in planned use, changes in estimated production lives of affiliated natural gas basins or other factors indicate that a different life would be more appropriate. Such changes could materially impact future depreciation expense. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively. The computation of amortization expense on intangible assets requires judgment regarding the amortization method used. Intangible assets are amortized on a straight-line basis over their useful lives using a method of amortization that reflects the pattern in which the economic benefits of the intangible asset are consumed.

The Partnership’s earnings are not subject to income tax (other than Texas state margin tax and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. For more information, see Note 18.

We account for deferred income tax related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future taxes attributable to the difference between financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of tax net operating loss carryforwards. In the event future utilization is determined to be unlikely, a valuation allowance is provided to reduce the tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the period in which the temporary differences and carryforwards are

expected to be recovered or settled. The effect of a change in tax rates is recognized in the period which includes the enactment date. The Partnership recognizes interest and penalties as a component of income tax expense.

The Partnership considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. The Consolidated Balance Sheets have $3 million and $4 million of cash and cash equivalents as of December 31, 2020 and 2019, respectively.

The Partnership adopted ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” on January 1, 2020. Upon adoption, the Partnership recognized a $3 million cumulative adjustment to Partners’ Equity and a corresponding adjustment to Allowance for doubtful accounts.

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecast information that could result in future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.

Materials and supplies inventory is valued at cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership recorded no write-downs to net realizable value related to materials and supplies inventory disposed or identified as excess or obsolete for each of the years ended December 31, 2020, 2019 and 2018. Materials and supplies are recorded to inventory when purchased and, as appropriate, subsequently charged to operation and maintenance expense on the Consolidated Statements of Income or capitalized to property, plant and equipment on the Consolidated Balance Sheets when installed.

Natural gas inventory is held, through the transportation and storage reportable segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing reportable segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. During the years ended December 31, 2020, 2019 and 2018, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $10 million, $8 million and $4 million, respectively. The cost of gas associated with sales of natural gas and natural gas liquids inventory is

presented in Cost of natural gas and natural gas liquids, excluding depreciation and amortization on the Consolidated Statements of Income.

Gas imbalances occur when the actual amounts of natural gas delivered from or received by the Partnership’s pipeline systems differ from the amounts scheduled to be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or natural gas depending on contractual terms. The Partnership values all imbalances at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value.

The Partnership records property, plant and equipment and intangible assets at historical cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and capitalized interest. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and charged to Accumulated depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Operation and maintenance expense. The Partnership expenses repair and maintenance costs as incurred. Repair, removal and maintenance costs are included in the Consolidated Statements of Income as Operation and maintenance expense.

The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 11.

The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 10.

The Partnership applies the guidance for accounting for regulated operations to portions of the transportation and storage reportable segment. The Partnership’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of each of December 31, 2020 and 2019, these removal costs of $25 million and $24 million, respectively, are classified as Regulatory liabilities in the Consolidated Balance Sheets.

Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for entities that apply guidance for accounting for regulated operations. Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. For the years ended December 31, 2020, 2019 and 2018, the Partnership capitalized interest and AFUDC of $2 million, $2 million and $6 million, respectively.

The Partnership is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. At times, the Partnership utilizes commodity derivative instruments such as physical forward contracts, financial futures and swaps to mitigate the impact of changes in commodity prices on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value unless the Partnership elects hedge accounting or the normal purchase and sales exemption for qualified physical transactions. For commodity derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized in Product sales in the Consolidated Statements of Income. A commodity derivative may be designated as a normal purchase or normal sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

At times, the Partnership utilizes interest rate derivative instruments such as swaps to mitigate the impact of changes in interest rates on its operating results and cash flows. Such derivatives are recognized in the Partnership’s Consolidated Balance Sheets at their fair value. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period in which the hedged transaction is recognized in earnings.

The Partnership’s policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As required, the Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy included in current accounting guidance. The Partnership generally applies the market approach to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The Partnership awards equity-based compensation to officers, directors and certain employees under the Long-Term Incentive Plan. All equity-based awards to officers, directors and employees under the Long-Term Incentive Plan, including grants of performance units, time-based phantom units (phantom units) and time-based restricted units (restricted units) are recognized in the Consolidated Statements of Income based on their fair values. The fair value of the phantom units and restricted units are based on the closing market price of the Partnership’s common unit on the grant date. The fair value of the performance units is estimated on the grant date using a lattice-based valuation model that factors in information, including the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the phantom unit and restricted unit awards is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a vesting period. The vesting of the performance unit awards is also contingent upon the probable outcome of the market condition. Depending on forfeitures and actual vesting, the compensation expense recognized related to the awards could increase or decrease.

The Partnership has adopted the 401(k) Savings Plan, covering all full-time employees. Participant contributions are discretionary, and can be up to 70% of compensation, as pre-tax, Roth, and /or after-tax contributions, subject to certain limits. We match 100% of employee contributions up to 6% of each participant’s eligible annual compensation, subject to certain limits. Matching contributions provided by the Partnership are immediately vested. The Partnership may also make discretionary profit sharing contributions. Allocations of such profit sharing contributions are based on the proportion of each participant’s eligible compensation of the plan year to the total of all participants’ eligible compensation, as defined. A participant must be employed on the last day of the Plan year in order to receive an allocation of profit sharing contributions. Profit sharing contributions must be approved by the Board of Directors annually. For the years ended December 31, 2020, 2019 and 2018, the Partnership contributed $20 million, $20 million and $19 million, respectively.

During the years ended December 31, 2020, 2019 and 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. For the years ended December 31, 2020, 2019 and 2018, the Partnership reimbursed OGE Energy $2 million, $3 million and $3 million, respectively, for these benefits. See Note 16 for further information related to our related party transactions.

In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This standard provides optional guidance, for a limited time, to ease the potential burden in accounting for or recognizing the effects of reference rate reform on financial reporting. The standard was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2020-04 during the year ended December 31, 2020. The implementation had no material impact on the Consolidated Financial Statements and related disclosures.

In January 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This standard clarifies that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. ASU 2021-01 also amends the expedients and exceptions in ASC 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. ASU 2021-01 was effective upon issuance and generally can be applied through December 31, 2022. The Partnership expects to adopt this standard in the first quarter of 2021 and does not expect the adoption of this standard to have a material impact on the Consolidated Financial Statements and related disclosures.

The following tables disaggregate total revenues by major source from contracts with customers and the gain on derivative activity for the years ended December 31, 2020, 2019 and 2018.

We deliver natural gas, NGLs and condensate to purchasers at contractually agreed-upon delivery points at which the purchaser takes custody, title, and risk of loss of the commodity. We recognize revenue at the point in time when control transfers to the purchaser at the delivery point based on the contractually agreed upon fixed or index-based price received.

Included in Product sales are gains and losses on natural gas, natural gas liquids, and crude oil (for condensate) derivatives that are accounted for under guidance in ASC 815. See Note 13 for further discussion of our derivative and hedging activity.

Service revenues include demand revenues and volume-dependent revenues, both of which include contracts with customers that typically contain a series of distinct services performed on discrete volumes. For these types of contracts with customers, we typically have a right to consideration from our customers in an amount that corresponds directly with the value to the customer of our performance completed to date and recognize service revenues in accordance with our election to use the right to invoice practical expedient.

Our demand revenue arrangements are generally structured in one of the following ways:

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Under a firm arrangement, a customer agrees to pay a fixed fee for a contractually agreed upon pipeline or storage capacity, which results in performance obligations for each individual period of reservation. Once the services have been completed, or the customer no longer has access to the contracted capacity, revenue is recognized.

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Under a minimum volume commitment arrangement, a customer agrees to pay the contractually agreed upon gathering, compressing and treating fees for a minimum volume of natural gas or crude oil irrespective of whether or not the minimum volume of natural gas or crude oil is delivered, which results in performance obligations for each individual unit of volume. If the actual volumes exceed the minimum volume of natural gas or crude oil, the customer pays the contractually agreed upon gathering, compressing and treating fees for the excess volumes in addition to the fees paid for the minimum volume of natural gas or crude oil. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of one year or more, significant judgment is used in interim commitment periods in which a customer’s actual volumes are deficient in relation to the minimum volume commitment. Revenue is recognized in proportion to the pattern of past performance exercised by the customer or when the likelihood of the customer meeting the minimum volume commitment becomes remote.

Our volume-dependent revenues primarily consist of gathering, compressing, treating, processing, transportation or storage services fees on contracts that exceed their contractually committed volume or do not have firm arrangements or minimum volume commitment arrangements. These revenues are generally variable because the volumes are dependent on throughput by third-party customers for which the service provided is only specified on a daily or monthly basis. Our other fee revenue arrangements typically recognize revenue as the service is performed and have pricing terms that are generally structured in one of the following ways: (1) Contractually agreed upon monetary fee for service or (2) contractually agreed upon consideration received in the form of natural gas or natural gas liquids, which are valued at the current month index-based price, which approximates fair value.

In June 2018, MRT filed a general NGA rate case (the 2018 Rate Case), and in October 2019, MRT filed a second rate case (the 2019 Rate Case). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. Upon issuance of the order and approval of the settlement 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 is inclusive of interest.

Payments for all types of revenues are typically received within 30 days of invoice. Invoices for all revenue types are sent on at least a monthly basis, except for the shortfall provisions under certain minimum volume commitment arrangements, which are typically invoiced annually. Accounts receivable includes accrued revenues associated with certain minimum volume commitments that will be invoiced at the conclusion of the measurement period specified under the respective contracts.

The following table summarizes the components of accounts receivable, net of allowance for doubtful accounts.

(1)

Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include contract assets related to firm transportation contracts with tiered rates of $9 million as of December 31, 2020 and $6 million as of December 31, 2019, which are reflected in Other Assets.

Our contract liabilities primarily consist of the following prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment:

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Under certain firm arrangements, customers pay their demand fee prior to the month of contracted capacity. These fees are applied to the subsequent month’s activity and are included in other current liabilities on the Consolidated Balance Sheets.

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Under certain demand and volume dependent arrangements, customers make contributions of aid in construction payments. For payments that are related to contracts under ASC 606, the payment is deferred and amortized over the life of the associated contract and the unamortized balance is included in other current or long-term liabilities on the Consolidated Balance Sheets.

The table below summarizes the change in the contract liabilities for the year ended December 31, 2020:

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2020:

We apply certain practical expedients as permitted by ASC 606, in which we are not required to disclose information regarding remaining performance obligations associated with agreements with original expected durations of one year or less, agreements in which we have elected to recognize revenue in the amount to which we have the right to invoice, and agreements where the variable consideration is allocated entirely to wholly unsatisfied performance obligations that generally do not get resolved until actual volumes are delivered and the prices are known. However, certain agreements do not qualify for practical expedients, which consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, revenue is recognized as Service revenues in the Consolidated Statements of Income.

The table below summarizes the timing of recognition of the remaining performance obligations as of December 31, 2020.

On January 1, 2019, the Partnership adopted ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and

(2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership has applied the standard only to contracts that were not expired as of January 1, 2019.

The Partnership elected the optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership’s adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Consolidated Balance Sheets by approximately $35 million due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as operating leases. The Partnership did not recognize a material cumulative adjustment to the Consolidated Statements of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.

Our lease obligations are primarily comprised of rentals of field equipment and office space, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. The Partnership is generally not aware of the implicit rate for either field equipment or office space rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of December 31, 2020, the weighted average remaining lease term is 7.0 years and the weighted average discount rate is 5.47%. A description of our lease contracts follows:

Field equipment: Field equipment has an expected lease term of 3 to 5 years, with contractual base terms of 1 to 3 years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. The Partnership has compression service agreements, some of which are on a month-to-month basis and some of which expire in 2021. The Partnership also has gas treating lease agreements, of which some are on a month-to-month basis, while others will expire in 2021 and in 2022. Field equipment lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income.

Office space: Office spaces have an expected lease term of 7 to 10 years, which is currently the same as the contractual base term. Office space rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for office spaces are generally comprised of costs for utilities, maintenance and building management services. Variable lease payments due under office space rental arrangements began July 1, 2019, with amounts due monthly. The Partnership occupies principal executive offices in Oklahoma City, Oklahoma, as well as office space in Houston, Texas. Our office leases are long-term in nature and represent $17 million of our right-of-use assets and $20 million of our lease liability as of December 31, 2020. Office space lease costs, including a proportionate percentage of facility expenses, are reflected in General and administrative expense in the Consolidated Statements of Income.

The table below summarizes the operating leases included in the Consolidated Balance Sheets.

As of December 31, 2020, all lease obligations were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

The following table presents the Partnership’s rental costs associated with field equipment and office space.

The Partnership recorded short-term lease costs of $1 million and $2 million in the transportation and storage reportable segment during the years ended December 31, 2020 and 2019, respectively. All other lease costs were included in the gathering and processing reportable segment.

Under ASC 842, as of December 31, 2020, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:

Under ASC 840 rental expense was $35 million during the year ended December 31, 2018.

On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately $444 million in cash. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018.

The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:

The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing reportable segment. Included within the acquisition was 60% of a 26-mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the accompanying Consolidated Financial Statements. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction during the year ended December 31, 2018, which were included in General and administrative expense in the Consolidated Statements of Income. The Partnership determined not to include pro forma Consolidated Financial Statements for the year ended December 31, 2018, as the impact would not be material.

Basic and diluted earnings per limited partner unit is calculated by dividing net income allocable to common and subordinated units by the weighted average number of common and subordinated units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding.

The following table illustrates the Partnership’s calculation of earnings per unit for common units:

(1)

For the years ended December 31, 2020, 2019, and 2018, the issuance of “if-converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings per common unit as the impact was anti-dilutive.

The Partnership Agreement requires that, within 60 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2020, 2019 and 2018 (in millions, except for per unit amounts):

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2020, 2019, and 2018 (in millions, except for per unit amounts):

Enable GP owns a non-economic general partner interest in the Partnership and, except as provided below with respect to incentive distribution rights, will not be entitled to distributions that the Partnership makes prior to the liquidation of the Partnership in respect of such general partner interest. Enable GP currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash the Partnership distributes from operating surplus (as defined in the Partnership Agreement) in excess of $0.330625 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Enable GP or its affiliates may receive on common units that they own.

The Partnership has 14,520,000 Series A Preferred Units, representing limited partner interests in the Partnership, which were issued at a price of $25.00 per Series A Preferred Unit on February 18, 2016.

Holders of the Series A Preferred Units receive a quarterly cash distribution on a non-cumulative basis if and when declared by the General Partner, and subject to certain adjustments, equal to an annual rate of: 10% on the stated liquidation preference of $25.00 from the date of original issue to, but not including, the five year anniversary of the original issue date; and thereafter a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%.

At any time on or after February 18, 2021, the Partnership may redeem the Series A Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.50 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Following changes of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units. If, upon a change of control or certain fundamental transactions, the Partnership (or a third-party with its prior written consent) does not exercise this option, then the holders of the Series A Preferred Units have the option to convert the Series A Preferred Units into a number of common units per Series A Preferred Unit as set forth in the Partnership Agreement. If under certain circumstances the Series A Preferred Units are not eligible for trading on the New York Stock Exchange, the Series A Preferred Units are required to be redeemed by the Partnership.

In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units at any time following a reduction by any of the ratings agencies in the amount of equity content attributed to the Series A Preferred Units. On July 30, 2019, S&P announced that it was reclassifying the Series A Preferred Units from having 50% equity content to having minimal equity content. S&P’s announcement followed a revision of its criteria for evaluating the amount of equity credit attributable to hybrid securities. As a result the reduction of equity content attributed to the Series A Preferred Units by S&P, the Partnership may redeem the Series A Preferred Units at any time, upon not less than 30 days’ nor more than 60 days’ notice, at a price of $25.50 per Series A Preferred Unit plus an amount equal to all unpaid distributions thereon from the issuance date through the redemption date.

Holders of Series A Preferred Units have no voting rights except for limited voting rights with respect to potential amendments to the Partnership Agreement that have a material adverse effect on the existing terms of the Series A Preferred Units, the issuance by the Partnership of certain securities, approval of certain fundamental transactions and as required by law.

Upon the transfer of any Series A Preferred Unit to a non-affiliate of CenterPoint Energy, the Series A Preferred Units will automatically convert into a new series of preferred units (the Series B Preferred Units) on the later of the date of transfer and the second anniversary of the date of issue. The Series B Preferred Units will have the same terms as the Series A Preferred Units except that unpaid distributions on the Series B Preferred Units will accrue on a cumulative basis until paid.

At the closing of the private placement of Series A Preferred Units, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, CenterPoint Energy has certain rights to require the Partnership to file and maintain a registration statement with respect to the resale of the Series A Preferred Units and any other series of preferred units or common units representing limited partner interests in the Partnership that are issuable upon conversion of the Series A Preferred Units.

On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement in connection with an ATM Program. Pursuant to the ATM Program, the Partnership may issue and sell common units having an aggregate offering price of up to $200 million, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. For the year ended December 31, 2020, the Partnership did not sell any common units under the ATM Program. For the year ended December 31, 2019, the Partnership sold an aggregate of 140,920 common units under the ATM Program, which generated proceeds of approximately $2 million (net of approximately $25,000 of commissions). The registration statement filed with the SEC for the ATM Program expired on May 12, 2020, and the Partnership did not file a replacement registration statement.

The Partnership recorded depreciation expense of $358 million, $371 million and $351 million during the years ended December 31, 2020, 2019 and 2018, respectively. Effective January 1, 2019, the Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable segments and the new depreciation rates were applied prospectively as a change in accounting estimate. On March 26, 2020, FERC issued an order approving MRT’s 2018 Rate Case and 2019 Rate Case settlements. As a result of the settlements, the new depreciation rates for MRT have been applied in accordance with the order. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

The Partnership periodically evaluates property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and the economic effects of the 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 utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs are forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent Level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment, 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 during the year ended December 31, 2020.

The Partnership recognizes gains or losses on sale or retirement when the net book value differs from the consideration received from sales proceeds, insurance recovery or other exchanges.

On September 23, 2019, the Partnership entered into an agreement to sell its undivided 1/12th interest in the Bistineau Storage Facility in Louisiana for approximately $19 million. On January 27, 2020, FERC approved the sale. The Partnership closed the sale on April 1, 2020. We did not recognize a gain or loss on this transaction.

In April 2020, we sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million for the year ended December 31, 2020, which is included in Operation and maintenance expense in the Consolidated Statements of Income.

Additionally, for the years ended December 31, 2020, 2019 and 2018, the Partnership recognized other net losses on sale or retirement of approximately $4 million, $8 million and $1 million, respectively, which are included in Operation and maintenance expense in the Consolidated Statements of Income.

The Partnership has intangible assets associated with customer relationships related to the acquisitions of Enogex LLC, Monarch Natural Gas, LLC, ETGP and EOCS as follows:

Intangible assets related to customer relationships have a weighted average useful life of 14 years. Intangible assets do not have any significant residual value or renewal options of existing terms. There are no intangible assets with indefinite useful lives.

The Partnership recorded amortization expense of $62 million, $62 million and $47 million during the years ended December 31, 2020, 2019 and 2018, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:

In the fourth quarter of 2017, as a result of the acquisition of ETGP, the Partnership recorded $12 million of goodwill associated with the Ark-La-Tex Basin reporting unit, included in the gathering and processing reportable segment. In the fourth quarter of 2018, as a result of the acquisition of EOCS, the Partnership recorded $86 million of goodwill associated with the Anadarko Basin reporting unit, included in the gathering and processing reportable segment.

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. During 2020, the commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and the economic effects of the pandemic, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil have remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers cut back spending and shifted their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Ark-La-Tex Basin reporting unit was more likely than not impaired as of March 31, 2020. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments of property plant, and equipment and goodwill on the Consolidated Statements of Income for the year ended December 31, 2020.

During 2019, the crude oil and natural gas industry was impacted by current and forward commodity price declines. Amid such crude oil, natural gas and NGL price declines, producers cut back spending and shifted their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Anadarko Basin reporting unit during the fourth quarter of 2019. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations have dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Anadarko Basin reporting unit would more likely than not be impaired. As a result, the Partnership performed a quantitative test for our annual goodwill impairment analysis as of October 1, 2019, and determined that the carrying value of the Anadarko Basin reporting unit exceeded its fair value and that goodwill associated with the Anadarko Basin reporting unit was completely impaired in the amount of $86 million. The impairment is included in Impairments on the Consolidated Statements of Income for the year ended December 31, 2019.

The change in carrying amount of goodwill in each of our reportable segments is as follows:

The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between 20% and 50% and exercises significant influence.

SESH is owned 50% by Enbridge Inc. and 50% by the Partnership for the years ended December 31, 2020 and 2019. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than 50% of our distributions through its limited partner interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

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, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Consolidated Statements of Income for the year ended December 31, 2020. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

The Partnership shares operations of SESH with Enbridge Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. During the years ended December 31, 2020, 2019 and 2018, the Partnership billed SESH $15 million, $17 million and $18 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings (losses) of equity method affiliate, net under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018.

(1)

Distributions from equity method affiliate includes a $15 million, $17 million and $26 million return on investment and a $8 million, $8 million and $7 million return of investment for the years ended December 31, 2020, 2019 and 2018, respectively.

The following table presents the Partnership’s outstanding debt as of December 31, 2020 and 2019.

(4)

As of December 31, 2020 and 2019, there was an additional $3 million and $4 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above. Unamortized debt expense is amortized over the life of the respective debt.

Maturities of outstanding debt, excluding unamortized premiums (discounts), are as follows (in millions):

The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to $1.4 billion of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were $250 million and $155 million outstanding under our commercial paper program at December 31, 2020 and December 31, 2019, respectively. The weighted average interest rate for the outstanding commercial paper was 0.86% as of December 31, 2020.

On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a $1.75 billion, five-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit facility, in each case, for an additional two-year term. As of December 31, 2020, there were no principal advances and no letters of credit outstanding under the restated Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of December 31, 2020, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was 1.50% based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit ratings. As of December 31, 2020, the commitment fee under the Revolving Credit Facility was 0.20% per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Consolidated Statements of Income.

The Revolving Credit Facility contains a financial covenant requiring us to maintain a ratio of consolidated funded debt to consolidated EBITDA as defined under the Revolving Credit Facility as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions by us or certain of our subsidiaries with a purchase price of at least $25 million in the aggregate, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00. Additionally, for the period of time during the construction by the Partnership or certain of its subsidiaries of a qualified project with a cost greater than $15 million and before the date such qualified project is substantially complete and commercially operable, the Partnership may make Qualified Project EBITDA Adjustments (as defined in the Revolving Credit Facility and 2019 Term Loan Agreement) by determining an amount as projected consolidated EBITDA attributable to such qualified project, which may be added to the actual consolidated EBITDA for the Partnership and those certain subsidiaries; provided that such amount (i) shall be no greater than 20% of the total actual consolidated EBITDA of the Partnership and those certain subsidiaries (as determined without the projected consolidated EBITDA attributable to such qualified project) and (ii) shall be subject to approval by the administrative agent.

The Revolving Credit Facility also contains covenants that restrict us and certain subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the Revolving Credit Facility), restricted payments, changes in the nature of their respective businesses and entering into certain restrictive agreements. Borrowings under the Revolving Credit Facility are subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured money judgments in excess of $100 million and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. As of December 31, 2020, there was $800 million outstanding under the 2019 Term Loan Agreement. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term, subject to lender approval. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the Eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the Eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of December 31, 2020, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of December 31, 2020, the weighted average interest rate of the 2019 Term Loan Agreement was 2.10%.

The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for a certain period time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is equal to or greater than $25 million, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to 5.50 to 1.00. For further discussion of Qualified Project EBITDA Adjustments, see “Revolving Credit Facility” above.

The 2019 Term Loan Agreement also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100 million or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject, where applicable, to specified cure periods.

As of December 31, 2020, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $8 million of unamortized discount and $19 million of unamortized debt expense at December 31, 2020, resulting in effective interest rates of 4.01%, 4.56%, 5.19%, 4.29% and 4.99%, respectively, during the year ended December 31, 2020. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement. In March 2020, the EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the year ended December 31, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Consolidated Statements of Income.

The indenture governing the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes contains certain restrictions, including, among others, limitations on our ability and the ability of our principal subsidiaries to: (i) consolidate or merge and sell all or substantially all of our and our subsidiaries’ assets and properties; (ii) create, or permit to be created or to exist, any lien upon any of our or our principal subsidiaries’ principal property, or upon any shares of stock of any principal subsidiary, to secure any debt; and (iii) enter into certain sale-leaseback transactions. These covenants are subject to certain exceptions and qualifications.

As of December 31, 2020, the Partnership was in compliance with all of their debt agreements, including financial covenants.

The primary risks managed using derivative instruments are commodity price and interest rate risks. The Partnership is also exposed to credit risk in its business operations.

The Partnership uses forward physical contracts, commodity price swap contracts and commodity price option features to manage its commodity price risk exposures. Commodity derivative instruments used by the Partnership are as follows:

•

natural gas options, futures, swaps and swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas price exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by its gathering and processing business.

The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.

As of December 31, 2020 and 2019, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

The Partnership uses interest rate swap contracts to manage its interest rate risk exposures. The Partnership recognizes its interest rate derivative instruments as Other Assets or Liabilities in the Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. The Partnership’s interest rate swap contracts are designated as cash flow hedging instruments for accounting purposes. For interest rate derivative instruments designated as cash flow hedging instruments, the gain or loss on the derivative is recognized currently in Accumulated other comprehensive loss and will be reclassified to Interest expense in the same period the hedged transaction affects earnings. As of December 31, 2020 and 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes.

Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.

Derivative instruments not designated as hedging instruments for accounting purposes are utilized to manage the Partnership’s exposure to commodity price risk. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.

As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

(1)

As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years. As of December 31, 2019, 86.6% of the natural gas contracts had durations of one year or less and 13.4% had durations of more than one year and less than two years.

(2)

The notional value contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.

(3)

As of December 31, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less. As of December 31, 2019, 72.8% of the crude oil (for condensate) contracts had durations of one year or less and 27.2% had durations of more than one year and less than two years.

(4)

As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less. As of December 31, 2019, 72.2% of the natural gas liquids contracts had durations of one year or less and 27.8% had durations of more than one year and less than two years.

Derivative instruments designated as hedging instruments for accounting purposes are utilized in managing the Partnership’s interest rate risk exposures.

Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments

The derivative instruments designated as hedges for accounting purposes are interest rate derivative instruments priced on monthly interest rates.

As of December 31, 2020 and 2019, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2020 and 2019 that were not designated as hedging instruments for accounting purposes are as follows:

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2020 and December 31, 2019 that were designated as hedging instruments for accounting purposes are as follows:

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018:

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2020, 2019 and 2018 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the years ended December 31, 2020 and 2019 were approximately $4 million and zero, respectively.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Consolidated Statements of Income for the years ended December 31, 2020, 2019 and 2018:

In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters or credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of December 31, 2020, under these obligations, the Partnership has posted no cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions, and NGL swaps and less than $1 million of additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

Certain assets and liabilities are recorded at fair value in the Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on either the NYMEX or the ICE and settled through either a NYMEX or ICE clearing broker.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, over-the-counter WTI crude oil swaps and swaptions for condensate sales, and over-the-counter interest rate swaps traded in observable markets with less volume and transaction frequency than active markets. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.

The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3. As of December 31, 2020, there were no contracts classified as Level 3.

The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the year ended December 31, 2020, there were no transfers between levels.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on S&P’s and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments at December 31, 2020 and 2019:

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $250 million and $155 million of commercial paper was outstanding as of December 31, 2020 and 2019, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes, 2044 Notes, and EOIT Senior Notes, is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of December 31, 2020, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Based upon review of forecasted undiscounted cash flows as of December 31, 2020, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions including the oversupply of crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and the economic effects of the pandemic, could reduce forecast undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

As of December 31, 2020 and 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. As of December 31, 2020 and 2019, there were no Level 3 commodity contracts. The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2020 and 2019:

(1)

The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of December 31, 2020 and 2019.

(2)

Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $19 million and $21 million at December 31, 2020 and 2019, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3)

Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $3 million and $8 million at December 31, 2020 and 2019, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table provides information regarding supplemental cash flow information:

The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.

MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. As part of the MRT rate case settlements, contracts for these services were extended and are in effect through July 31, 2028 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, firm no-notice transportation with storage and maximum rate firm transportation. The firm transportation, firm transportation with seasonal demand, firm storage and no-notice transportation with storage contracts were extended and have terms running through March 31, 2030. The maximum rate firm transportation contracts were also extended and have terms running through March 31, 2024.

The Partnership may agree to reimburse the costs that its customers incur to make required modifications for the repair and maintenance of pipelines that impact customer delivery points. We reimbursed CenterPoint Energy’s LDCs less than $1 million for the year ended December 31, 2020, and $2 million for the year ended December 31, 2019, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines. For the year ended December 31, 2018, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with a reimbursement associated with an unplanned pipeline outage.

EOIT provides no-notice load-following transportation and storage services to four of OGE Energy’s generating facilities. Service is provided to three generating facilities under a transportation agreement with a primary term through May 1, 2024, which will remain in effect from 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. Service is provided to one additional generating facility in Muskogee, Oklahoma under a transportation agreement with a primary term through December 1, 2038. EOIT paid OGE Energy $2 million and waived $5 million of demand fee charges as a result of damage that occurred to the Muskogee facility during commissioning as a result of the failure of certain filters on the connected transportation pipeline, which is included in the Partnership’s results of operations as of December 31, 2019.

The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.

The Partnership’s revenues from affiliated companies accounted for 6%, 6% and 5% of total revenues during the years ended December 31, 2020, 2019 and 2018, respectively. Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:

Amounts of natural gas purchased from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate these services agreements at any time with 180 days’ notice, if approved by the Board of Enable

GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2020 are less than $1 million and $1 million, respectively.

The Partnership leased office and data center space from an affiliate of CenterPoint Energy in Shreveport, Louisiana. The term of the lease was effective on October 1, 2016 and ended on December 31, 2019.

During the years ended December 31, 2020, 2019 and 2018, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of $5 million in 2020 and thereafter, unless and until secondment is terminated.

Amounts charged to the Partnership by affiliates for corporate services, operating lease and seconded employees, are primarily included in Operation and maintenance expenses and General and administrative expenses in the Partnership’s Consolidated Statements of Income are as follows:

The Partnership is involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

On January 1, 2017, the Partnership entered into a 10-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer, LP for 400 MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of December 31, 2020, the Partnership estimates the remaining associated minimum volume commitment fee to be $172 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2021 through 2027 and $11 million in 2028.

On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. 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. The Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. 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 would be as much as $500 million. The project is backed by a 20-year firm transportation service agreement. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in late 2022.

The Partnership’s earnings are generally not subject to income tax (other than Texas state margin tax and taxes associated with the Partnership’s corporate subsidiary Enable Midstream Services) and are taxable at the individual partner level. The Partnership and its non-corporate subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income tax in the Consolidated Financial Statements. Consequently, the Consolidated Statements of Income do not include an income tax provision (other than Texas state margin taxes and taxes associated with the Partnership’s corporate subsidiary).

The components of Deferred Income Tax as of December 31, 2020 and 2019 were as follows:

The federal income tax return of the Partnership has been audited through the 2013 tax year.

The Partnership’s corporate subsidiary, Enable Midstream Services, has federal and state net operating losses (NOL) the tax benefits of which are recorded as deferred tax assets. As of December 31, 2020, the Partnership had approximately $4 million of Federal NOLs, which can be carried forward indefinitely and approximately $8 million of various State NOLs, of which approximately $2 million will expire between 2023 and 2039. Additionally, as of December 31, 2020, the Partnership had a deferred tax asset related to Federal and State NOLs of $1 million and zero, respectively.

Enable GP has adopted the Enable Midstream Partners, LP Long Term Incentive Plan (LTIP) for officers, directors and employees of the Partnership and its affiliates, including any individual who provides services to the Partnership as a seconded employee. The LTIP provides for the following types of awards: restricted units, phantom units, appreciations rights, option rights, cash incentive awards, performance units, distribution equivalent rights, and other awards denominated in, payable in, valued in or otherwise based on or related to common units.

The LTIP is administered by the Compensation Committee of the Board of Directors. With respect to any grant of equity as long-term incentive awards to our independent directors and our officers subject to reporting under Section 16 of the Exchange Act, the Compensation Committee makes recommendations to the Board of Directors and any such awards will only be effective upon the approval of the Board of Directors. The LTIP limits the number of units that may be delivered pursuant to vested awards to 13,100,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units cancelled, forfeited, expired or cash settled are available for delivery pursuant to other awards.

The Board of Directors may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made, including amending the long-term incentive plan to increase the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would be adverse to the participant without the consent of the participant.

Performance unit, restricted unit and phantom unit awards are classified as equity on the Partnership’s Consolidated Balance Sheets. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2020, 2019 and 2018 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:

Awards of performance based phantom units (performance units) have been made under the LTIP in 2020, 2019 and 2018 to certain officers and employees providing services to the Partnership. Subject to the achievement of performance goals, the performance unit awards cliff vest three years from the grant date, with distribution equivalent rights paid at vesting. The performance goals for 2020, 2019 and 2018 awards are based on total unitholder return over a three-calendar year performance cycle. Total unitholder return is based on the relative performance of the Partnership’s common units against a peer group. The performance unit awards have a payout from zero to 200% of the target based on the level of achievement of the performance goal. Performance unit awards are paid out in common units, with distribution equivalent rights paid in cash at vesting. Any unearned performance units are cancelled. Pay out requires the confirmation of the achievement of the performance level by the Compensation Committee. Prior to vesting, performance units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control. In the event of retirement, a participant will receive a prorated payment based on the target performance or a prorated payment based on the actual performance of the performance goals during the award cycle, based on the grant year.

The fair value of each performance unit award was estimated on the grant date using a lattice-based valuation model. The valuation information factored into the model includes the expected distribution yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition over the expected life of the performance units. Equity-based compensation expense for each performance unit award is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Distributions are accumulated and paid at vesting and, therefore, are included in the fair value calculation of the performance unit award. The expected price volatility for the awards granted in 2020, 2019 and 2018 is based on three years of daily stock price observations, to determine the total unitholder return ranking. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. There are no post-vesting restrictions related to the Partnership’s performance units.

The number of performance units granted based on total unitholder return and the assumptions used to calculate the grant date fair value of the performance units based on total unitholder return are shown in the following table.

Awards of phantom units have been made under the LTIP in 2020, 2019 and 2018 to certain officers and employees providing services to the Partnership. Except for phantom units granted to retirement eligible employees, which vest in annual tranches, phantom units cliff-vest on the first, second or third anniversary of the grant date with distribution equivalent rights paid during the vesting period. Phantom unit awards are paid out in common units, with distribution equivalent rights paid in cash. Any unearned phantom units are cancelled. Prior to vesting, phantom units are subject to forfeiture if the recipient’s employment with the Partnership is terminated for any reason other than death, disability, retirement or termination other than for cause within two years of a change in control.

The fair value of the phantom units was based on the closing market price of the Partnership’s common unit on the grant date. Equity-based compensation expense for the phantom unit is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over the vesting period. Distributions on phantom units are paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the phantom unit is based on the applicable vesting period. The number of phantom units granted and the grant date fair value are shown in the following table.

In 2020, 2019 and 2018, the Board of Directors granted common units to the independent directors of Enable GP, for their service as directors, which vested immediately. The fair value of the common units was based on the closing market price of the Partnership’s common unit on the grant date.

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2020 and changes during 2020 are shown in the following table.

(2)

Performance units vested as of December 31, 2020 include 376,292 from the 2017 annual grant, which were approved by the Board of Directors in 2017 and, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2017 through December 31, 2019, no performance units vested.

(3)

Performance units outstanding as of December 31, 2020 include 389,817 units from the 2018 annual grants, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2018 through December 31, 2020, will vest at 0%. The decrease in outstanding units for a payout percentage of an amount other than 100% is not reflected above until the vesting date.

A summary of the Partnership’s performance, restricted and phantom units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for each of the years ended December 31, 2020, 2019 and 2018 are shown in the following tables.

A summary of the Partnership’s unrecognized compensation expense for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

As of December 31, 2020, there were 5,234,214 units available for issuance under the long-term incentive plan.

The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of

significant accounting policies described in Note 1. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s 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.

(2)

The Partnership recorded impairments to goodwill of $12 million and $86 million during the first quarter 2020 related to the Ark-La-Tex Basin reporting unit and the fourth quarter of 2019 related to the Anadarko Basin reporting unit, respectively, included in the gathering and processing reportable segment. See Note 10 for further information.

On February 17, 2021, the Partnership and Energy Transfer announced their entry into a definitive merger agreement pursuant to which Energy Transfer, through wholly owned subsidiaries, will acquire the Partnership. Under the terms of the merger agreement, the Partnership’s common unitholders will receive 0.8595 of one common unit representing limited partner interests in Energy Transfer in exchange for each Partnership common unit. In addition, each issued and outstanding Series A preferred unit of the Partnership will be exchanged for 0.0265 of an Energy Transfer Series G preferred unit, and Energy Transfer will make a $10 million cash payment for the limited liability company interests in the Partnership’s general partner.

The transaction has been approved by the Conflicts Committee and the Board of Directors of Enable GP. CenterPoint Energy and OGE Energy, who collectively own approximately 79.2% of Partnership common units, have entered into support agreements pursuant to which they have agreed to vote their common units in favor of the merger. The transaction is subject to the satisfaction of customary closing conditions.


	Year Ended December 31,
	2020	2019	2018

	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 16)):
Product sales	$ 1,132	$ 1,533	$ 2,106
Service revenues	1,331	1,427	1,325
Total Revenues	2,463	2,960	3,431
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	965	1,279	1,819
Operation and maintenance	418	423	388
General and administrative	98	103	113
Depreciation and amortization	420	433	398
Impairments of property, plant and equipment and goodwill (Notes 8 and 10)	28	86	—
Taxes other than income tax	69	67	65
Total Cost and Expenses	1,998	2,391	2,783
Operating Income	465	569	648
Other Income (Expense):
Interest expense	(178)	(190)	(152)
Equity in earnings (losses) of equity method affiliate, net	(210)	17	26
Other, net	6	3	—
Total Other Expense	(382)	(170)	(126)
Income Before Income Tax	83	399	522
Income tax benefit	—	(1)	(1)
Net Income	$ 83	$ 400	$ 523
Less: Net income (loss) attributable to noncontrolling interests	(5)	4	2
Net Income Attributable to Limited Partners	$ 88	$ 396	$ 521
Less: Series A Preferred Unit distributions (Note 7)	36	36	36
Net Income Attributable to Common Units (Note 6)	$ 52	$ 360	$ 485

Basic and diluted earnings per common unit (Note 6)
Basic	$ 0.12	$ 0.83	$ 1.12
Diluted	$ 0.12	$ 0.82	$ 1.11


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Net income	$ 83	$ 400	$ 523
Other comprehensive loss:
Change in fair value of interest rate derivative instruments	(7)	(3)	—
Reclassification of interest rate derivative losses to net income	4	—	—
Other comprehensive loss	(3)	(3)	—
Comprehensive income	80	397	523
Less: Comprehensive income (loss) attributable to noncontrolling interests	(5)	4	2
Comprehensive income attributable to Limited Partners	$ 85	$ 393	$ 521


	December 31,
	2020	2019

	(In millions, except units)
Current Assets:
Cash and cash equivalents	$ 3	$ 4
Accounts receivable, net of allowance for doubtful accounts (Note 1)	248	244
Accounts receivable—affiliated companies	15	25
Inventory	42	46
Gas imbalances	42	35
Other current assets	31	35
Total current assets	381	389
Property, Plant and Equipment:
Property, plant and equipment	13,220	13,161
Less accumulated depreciation and amortization	2,555	2,291
Property, plant and equipment, net	10,665	10,870
Other Assets:
Intangible assets, net	539	601
Goodwill	—	12
Investment in equity method affiliate	76	309
Other	68	85
Total other assets	683	1,007
Total Assets	$ 11,729	$ 12,266
Current Liabilities:
Accounts payable	$ 149	$ 161
Accounts payable—affiliated companies	2	1
Short-term debt	250	155
Current portion of long-term debt	—	251
Taxes accrued	34	32
Gas imbalances	19	19
Accrued compensation	43	31
Customer deposits	18	17
Other	67	113
Total current liabilities	582	780
Other Liabilities:
Accumulated deferred income tax, net	5	4
Regulatory liabilities	25	24
Other	71	80
Total other liabilities	101	108
Long-Term Debt	3,951	3,969
Commitments and Contingencies (Note 17)


Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2020 and December 31, 2019, respectively)	362	362
Common Units (435,549,892 issued and outstanding at December 31, 2020 and 435,201,365 issued and outstanding at December 31, 2019)	6,713	7,013
Accumulated other comprehensive loss	(6)	(3)
Noncontrolling interests	26	37
Total Partners’ Equity	7,095	7,409
Total Liabilities and Partners’ Equity	$ 11,729	$ 12,266


	Year Ended December 31,
	2020	2019	2018

	(In millions)
Cash Flows from Operating Activities:
Net income	$ 83	$ 400	$ 523
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	420	433	398
Deferred income tax	1	(1)	(1)
Impairments of property, plant and equipment and goodwill	28	86	—
Net loss on sale/retirement of assets	24	8	1
Gain on extinguishment of debt	(5)	—	—
Equity in (earnings) losses of equity method affiliate, net	210	(17)	(26)
Return on investment in equity method affiliate	15	17	26
Equity-based compensation	13	16	16
Amortization of debt costs and discount (premium)	4	(1)	(1)
Changes in other assets and liabilities:
Accounts receivable, net	(5)	43	(10)
Accounts receivable—affiliated companies	10	(6)	(1)
Inventory	4	4	(10)
Gas imbalance assets	(7)	(6)	8
Other current assets	3	9	(21)
Other assets	5	11	(12)
Accounts payable	(10)	(75)	4
Accounts payable—affiliated companies	1	(3)	1
Gas imbalance liabilities	—	(3)	10
Other current liabilities	(32)	39	4
Other liabilities	(5)	(12)	15
Net cash provided by operating activities	757	942	924
Cash Flows from Investing Activities:
Capital expenditures	(215)	(432)	(728)
Acquisitions, net of cash acquired	—	—	(443)
Proceeds from sale of assets	20	1	8
Proceeds from insurance	1	1	2
Return of investment in equity method affiliate	8	8	7
Other, net	4	(8)	—
Net cash used in investing activities	(182)	(430)	(1,154)
Cash Flows from Financing Activities:
Increase (decrease) increase in short-term debt	95	(494)	244
Proceeds from long-term debt, net of issuance costs	—	1,544	787
Repayment of long-term debt	(267)	(700)	(450)


Proceeds from Revolving Credit Facility	869	—	350
Repayment of Revolving Credit Facility	(869)	(250)	(100)
Proceeds from issuance of common units, net of issuance costs	—	—	2
Distributions to common unitholders	(360)	(564)	(551)
Distributions to preferred unitholders	(36)	(36)	(36)
Distributions to non-controlling interests	(6)	(5)	(4)
Cash paid for employee equity-based compensation	(2)	(25)	(9)
Net cash (used in) provided by financing activities	(576)	(530)	233
Net (Decrease) Increase in Cash and Cash Equivalents	(1)	(18)	3
Cash and Cash Equivalents at Beginning of Period	4	22	19
Cash and Cash Equivalents at End of Period	$ 3	$ 4	$ 22


	Series A Preferred Units		Common Units		Accumulated Other Comprehensive Earnings	Noncontrolling Interest	Total Partners’ Equity
	Units	Value	Units	Value	Value	Value	Value

	(In millions)
Balance as of December 31, 2017	15	$ 362	433	$ 7,280	$ —	$ 12	$ 7,654
Net income	—	36	—	485	—	2	523
Issuance of common units	—	—	—	2	—	—	2
Acquisition of EOCS	—	—	—	—	—	28	28
Distributions	—	(36)	—	(551)	—	(4)	(591)
Equity-based compensation, net of units for employee taxes	—	—	—	2	—	—	2
Balance as of December 31, 2018	15	$ 362	433	$ 7,218	$ —	$ 38	$ 7,618
Net income	—	36	—	360	—	4	400
Other comprehensive loss	—	—	—	—	(3)	—	(3)
Distributions	—	(36)	—	(564)	—	(5)	(605)
Equity-based compensation, net of units for employee taxes	—	—	2	(1)	—	—	(1)
Balance as of December 31, 2019	15	$ 362	435	$ 7,013	$ (3)	$ 37	$ 7,409
Net income (loss)	—	36	—	52	—	(5)	83
Other comprehensive loss	—	—	—	—	(3)	—	(3)
Distributions	—	(36)	—	(360)	—	(6)	(402)
Equity-based compensation, net of units for employee taxes	—	—	—	11	—	—	11
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—	—	(3)	—	—	(3)
Balance as of December 31, 2020	15	$ 362	435	$ 6,713	$ (6)	$ 26	$ 7,095


	December 31, 2020	January 1, 2020

	(In millions)
Accounts receivable	$ 1	$ 2
Other assets	3	3
Total Allowance for doubtful accounts	$ 4	$ 5


	Year Ended December 31, 2020
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 249	$ 328	$ (285)	$ 292
Natural gas liquids	762	10	(10)	762
Condensate	68	—	—	68
Total revenues from natural gas, natural gas liquids, and condensate	1,079	338	(295)	1,122
Gain on derivative activity	8	2	—	10
Total Product sales	$ 1,087	$ 340	$ (295)	$ 1,132
Service revenues:
Demand revenues	$ 135	$ 491	$ —	$ 626
Volume-dependent revenues	664	50	(9)	705
Total Service revenues	$ 799	$ 541	$ (9)	$ 1,331
Total Revenues	$ 1,886	$ 881	$ (304)	$ 2,463


	Year Ended December 31, 2019
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 368	$ 464	$ (384)	$ 448
Natural gas liquids	943	19	(19)	943
Condensate	126	—	—	126
Total revenues from natural gas, natural gas liquids, and condensate	1,437	483	(403)	1,517
Gain on derivative activity	12	4	—	16
Total Product sales	$ 1,449	$ 487	$ (403)	$ 1,533
Service revenues:
Demand revenues	$ 274	$ 489	$ —	$ 763
Volume-dependent revenues	615	62	(13)	664
Total Service revenues	$ 889	$ 551	$ (13)	$ 1,427
Total Revenues	$ 2,338	$ 1,038	$ (416)	$ 2,960


	Year Ended December 31, 2018
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 480	$ 590	$ (506)	$ 564
Natural gas liquids	1,405	30	(30)	1,405
Condensate	126	—	—	126
Total revenues from natural gas, natural gas liquids, and condensate	2,011	620	(536)	2,095
Gain on derivative activity	5	5	1	11
Total Product sales	$ 2,016	$ 625	$ (535)	$ 2,106
Service revenues:
Demand revenues	$ 252	$ 472	$ —	$ 724
Volume-dependent revenues	550	65	(14)	601
Total Service revenues	$ 802	$ 537	$ (14)	$ 1,325
Total Revenues	$ 2,818	$ 1,162	$ (549)	$ 3,431


	December 31, 2020	December 31, 2019

	(In millions)
Accounts Receivable:
Customers	$ 245	$ 239
Contract assets (1)	12	18
Non-customers	6	12
Total Accounts Receivable (2)	$ 263	$ 269


	2021	2022	2023	2024	2025 and After

	(In millions)
Deferred revenues (1)	$ 23	$ 7	$ 6	$ 6	$ 2


	Balance Sheet Location	December 31, 2020	December 31, 2019

		(In millions)
Operating lease asset	Other Assets	$ 25	$ 37
Total right-of-use assets		$ 25	$ 37

Operating lease liabilities	Other Current Liabilities	$ 4	$ 9
Operating lease liabilities	Other Liabilities	24	31
Total lease liabilities		$ 28	$ 40


	Non-cancellable operating leases
	(In millions)
Year Ending December 31,
2021	$ 6
2022	5
2023	5
2024	4
2025	3
After 2025	8
Total	31
Less: impact of the applicable discount rate	3
Total lease liabilities	$ 28


Purchase price allocation (in millions):
Assets acquired:
Cash	$ 1
Current Assets	3
Property, plant and equipment	124
Intangibles	259
Goodwill	86
Liabilities assumed:
Current liabilities	1
Less: Noncontrolling interest at fair value	28
Total identifiable net assets	$ 444


Quarter Ended	Record Date	Payment Date	Per Unit Distribution	Total Cash Distribution
2020
December 31, 2020 (1)	February 22, 2021	March 1, 2021	$ 0.16525	$ 72
September 30, 2020	November 17, 2020	November 24, 2020	0.16525	72
June 30, 2020	August 18, 2020	August 25, 2020	0.16525	72
March 31, 2020	May 19, 2020	May 27, 2020	0.16525	72

2019
December 31, 2019	February 18, 2020	February 25, 2020	$ 0.3305	$ 144
September 30, 2019	November 19, 2019	November 26, 2019	0.3305	144
June 30, 2019	August 20, 2019	August 27, 2019	0.3305	144
March 31, 2019	May 21, 2019	May 29, 2019	0.318	138

2018
December 31, 2018	February 19, 2019	February 26, 2019	$ 0.318	$ 138
September 30, 2018	November 16, 2018	November 29, 2018	0.318	138
June 30, 2018	August 21, 2018	August 28, 2018	0.318	138
March 31, 2018	May 22, 2018	May 29, 2018	0.318	138


	Weighted Average Useful Lives (Years)	December 31,
	Weighted Average Useful Lives (Years)		2020		2019

		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	34.5	$ 8,275		$ 8,252
Transportation and Storage	40.6	4,802		4,778
Construction work-in-progress		143		131
Total		$ 13,220		$ 13,161
Accumulated depreciation:
Gathering and Processing		1,429		1,252
Transportation and Storage		1,126		1,039
Total accumulated depreciation		2,555		2,291
Property, plant and equipment, net		$ 10,665		$ 10,870


	December 31, 2020			December 31, 2019
	Outstanding Principal	Premium (Discount)(1)	Total Debt	Outstanding Principal	Premium (Discount)(1)	Total Debt

	(In millions)
Commercial Paper	$ 250	$ —	$ 250	$ 155	$ —	$ 155
Revolving Credit Facility	—	—	—	—	—	—
2019 Term Loan Agreement	800	—	800	800	—	800
2024 Notes	600	—	600	600	—	600
2027 Notes	700	(2)	698	700	(2)	698
2028 Notes	800	(5)	795	800	(5)	795
2029 Notes	547	(1)	546	550	(1)	549
2044 Notes	531	—	531	550	—	550
EOIT Senior Notes	—	—	—	250	1	251
Total debt	$ 4,228	$ (8)	$ 4,220	$ 4,405	$ (7)	$ 4,398
Less: Short-term debt (2)			250			155
Less: Current portion of long-term debt (3)			—			251
Less: Unamortized debt expense (4)			19			23
Total long-term debt			$ 3,951			$ 3,969


	December 31, 2020		December 31, 2019
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	18	10	19
Financial basis futures/swaps	—	27	11	30
Financial swaptions (2)	—	7	—	2
Physical purchases/sales	—	—	—	6
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	465	—	990
Financial swaptions (2)	—	90	—	225
Natural gas liquids— MBbl (4)
Financial futures/swaps	855	1,210	2,490	2,415
Financial swaptions (2)	—	45	—	—


	December 31, 2020	December 31, 2019
	Gross Notional Value
	(In millions)
Interest rate swaps	$ 300	$ 300


		December 31, 2020		December 31, 2019
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$ 2	$ 2	$ 7	$ 5
Financial swaptions	Other Current	1	2	—	—
Physical purchases/sales	Other Current	—	—	5	—
Financial futures/swaps	Other	—	—	—	1
Crude oil (for condensate)
Financial futures/swaps	Other Current	1	13	1	19
Financial futures/swaps	Other	—	—	—	8
Natural gas liquids
Financial futures/swaps	Other Current	15	3	25	3
Financial swaptions	Other Current	—	1	—	—
Financial futures/swaps	Other	—	—	11	2
Total gross derivatives (1)		$ 19	$ 21	$ 49	$ 38


	Amounts Recognized in Income
	Year Ended December 31,
	2020	2019	2018

	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$ 4	$ 13	$ (8)
Financial swaptions gains (losses)	(2)	—	—
Physical purchases/sales gains	—	2	7
Crude oil (for condensate)
Financial futures/swaps gains (losses)	10	(41)	6
Natural gas liquids
Financial futures/swaps gains (losses)	(2)	42	6
Total	$ 10	$ 16	$ 11


	December 31, 2020		December 31, 2019
	Carrying Amount	Fair Value	Carrying Amount	Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$ —	$ —	$ —	$ —
2019 Term Loan Agreement (Level 2)	800	800	800	800
2024 Notes (Level 2)	600	612	600	614
2027 Notes (Level 2)	698	709	698	698
2028 Notes (Level 2)	795	817	795	811
2029 Notes (Level 2)	546	544	549	526
2044 Notes (Level 2)	531	499	550	506
EOIT Senior Notes (Level 2)	—	—	251	252


December 31, 2020	Commodity Contracts		Gas Imbalances (1)
	Assets	Liabilities	Assets (2)	Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$ 2	$ 14	$ —	$ —
Significant other observable inputs (Level 2)	17	7	23	16
Total fair value	19	21	23	16
Netting adjustments	(19)	(19)	—	—
Total	$ —	$ 2	$ 23	$ 16


	Performance Units		Phantom Units
	Number of Units	Weighted Average Grant-Date Fair Value, Per Unit	Number of Units	Weighted Average Grant-Date Fair Value, Per Unit

	(In millions, except unit data)
Units outstanding at 12/31/2019	1,393,329	$ 19.04	1,392,560	$ 14.65
Granted (1)	933,738	7.00	1,002,345	6.44
Vested (2)(3)	(390,079)	19.21	(399,406)	15.76
Forfeited	(171,480)	14.25	(204,654)	10.46
Units outstanding at 12/31/2020	1,765,508	13.10	1,790,845	$ 10.29
Aggregate intrinsic value of units outstanding at December 31, 2020	$ 9		$ 9


	Year Ended December 31, 2020
	Performance Units	Restricted Stock	Phantom Units

	(In millions)
Aggregate intrinsic value of units vested	$ —	$ —	$ 3
Fair value of units vested	7	—	6


	December 31, 2020
	Unrecognized Compensation Cost (In millions)	Weighted Average Period for Recognition (In years)
Performance Units	$ 9	1.43
Phantom Units	6	1.30
Total	$ 15


Year Ended December 31, 2020	Gathering and Processing	Transportation and Storage (1)	Eliminations	Total

	(In millions)
Product sales	$ 1,087	$ 340	$ (295)	$ 1,132
Service revenues	799	541	(9)	1,331
Total Revenues	1,886	881	(304)	2,463
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	936	332	(303)	965
Operation and maintenance, General and administrative	334	183	(1)	516
Depreciation and amortization	299	121	—	420
Impairments of property, plant and equipment and goodwill	28	—	—	28
Taxes other than income tax	42	27	—	69
Operating Income	$ 247	$ 218	$ —	$ 465
Total Assets	$ 10,830	$ 5,729	$ (4,830)	$ 11,729
Capital expenditures	$ 107	$ 108	$ —	$ 215


	Quarters Ended
	March 31, 2020	June 30, 2020	September 30, 2020	December 31, 2020

	(in millions, except per unit data)
Total Revenues	$ 648	$ 515	$ 596	$ 704
Cost of natural gas and natural gas liquids	226	177	250	312
Operating income	146	80	100	139
Net income (loss) (1)	105	44	(163)	97
Net income (loss) attributable to limited partners	112	44	(164)	96
Net income (loss) attributable to common units	103	35	(173)	87

Basic and diluted earnings per unit
Basic	$ 0.24	$ 0.08	$ (0.40)	$ 0.20
Diluted	$ 0.19	$ 0.08	$ (0.40)	$ 0.19

	Quarters Ended