Exhibit 99.01

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enable GP, LLC and

Unitholders of Enable Midstream Partners, LP

Oklahoma City, Oklahoma

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Enable Midstream Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 19, 2020, expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

Basis for Opinion

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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

1

Exhibit 99.01

Goodwill - Anadarko Basin Reporting Unit - Refer to Notes 1 and 10 to the consolidated financial statements

Critical Audit Matter Description

The Partnership’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its carrying value. The Partnership used the discounted cash flow model to estimate fair value, which requires management to make significant estimates and assumptions related to the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate. Changes in these assumptions could have a significant impact on either the fair value, the amount of any goodwill impairment charge, or both. The goodwill balance allocated to the Anadarko Basin Reporting Unit (“Anadarko”) was $86 million as of October 1, 2019. The carrying value of Anadarko exceeded its fair value as of the measurement date and the goodwill associated with Anadarko was completely impaired in the amount of $86 million.

Given the significant judgments made by management to estimate the fair value of Anadarko, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to selection of the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate, of Anadarko required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

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

•We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair value of Anadarko, such as controls related to management’s selection of the weighted average cost of capital and forecasts of future revenues, including the revenue growth rate.

•We evaluated management’s ability to accurately forecast future revenues by comparing actual results to management’s historical forecasts.

•We evaluated the reasonableness of management’s revenue forecasts by comparing the forecasts to:

▪Historical revenues.

▪Internal communications to management and the Board of Directors.

▪Forecasted information included in Partnership press releases as well as in analyst and industry reports for the Partnership and certain of its peer companies.

•With the assistance of our fair value specialists, we evaluated the reasonableness of the (1) valuation methodology and (2) weighted average cost of capital and revenue growth rate by:

–Testing the source information underlying the determination of the weighted average cost of capital and revenue growth rate and the mathematical accuracy of the calculation.

–Developing a range of independent estimates and comparing those to the weighted average cost of capital and revenue growth rate selected by management.

/s/ DELOITTE & TOUCHE

Oklahoma City, Oklahoma

February 19, 2020

We have served as the Partnership’s auditor since 2013.

2

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2019		2018		2017
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 16)):
Product sales	$	1,533	$	2,106	$	1,653
Service revenues	1,427		1,325		1,150
Total Revenues	2,960		3,431		2,803
Cost and Expenses (including expenses from affiliates (Note 16)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,279		1,819		1,381
Operation and maintenance	423		388		369
General and administrative	103		113		95
Depreciation and amortization	433		398		366
Impairment (Note 10)	86		—		—
Taxes other than income taxes	67		65		64
Total Cost and Expenses	2,391		2,783		2,275
Operating Income	569		648		528
Other Income (Expense):
Interest expense	(190)		(152)		(120)
Equity in earnings of equity method affiliate	17		26		28
Other, net	3		—		—
Total Other Expense	(170)		(126)		(92)
Income Before Income Tax	399		522		436
Income tax benefit	(1)		(1)		(1)
Net Income	$	400	$	523	$	437
Less: Net income attributable to noncontrolling interests	4		2		1
Net Income Attributable to Limited Partners	$	396	$	521	$	436
Less: Series A Preferred Unit distributions (Note 7)	36		36		36
Net Income Attributable to Common and Subordinated Units (Note 6)	$	360	$	485	$	400
Basic earnings per unit (Note 6)
Common units	$	0.83	$	1.12	$	0.92
Subordinated units	$	—	$	—	$	0.93
Diluted earnings per unit (Note 6)
Common units	$	0.82	$	1.11	$	0.92
Subordinated units	$	—	$	—	$	0.93

See Notes to the Consolidated Financial Statements

3

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Net income	$	400	$	523	$	437
Other comprehensive loss:
Unrealized losses on derivative instruments	(3)		—		—
Reclassification of derivative losses to net income	—		—		—
Other comprehensive loss	(3)		—		—
Comprehensive income	397		523		437
Less: Comprehensive income attributable to noncontrolling interests	4		2		1
Comprehensive income attributable to Limited Partners	$	393	$	521	$	436

See Notes to the Consolidated Financial Statements

4

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2019		2018
	(In millions, except units)
Current Assets:
Cash and cash equivalents	$	4	$	8
Restricted cash	—		14
Accounts receivable, net of allowance for doubtful accounts (Note 1)	244		290
Accounts receivable—affiliated companies	25		19
Inventory	46		50
Gas imbalances	35		29
Other current assets	35		39
Total current assets	389		449
Property, Plant and Equipment:
Property, plant and equipment	13,161		12,899
Less accumulated depreciation and amortization	2,291		2,028
Property, plant and equipment, net	10,870		10,871
Other Assets:
Intangible assets, net	601		663
Goodwill	12		98
Investment in equity method affiliate	309		317
Other	85		46
Total other assets	1,007		1,124
Total Assets	$	12,266	$	12,444
Current Liabilities:
Accounts payable	$	161	$	288
Accounts payable—affiliated companies	1		4
Short-term debt	155		649
Current portion of long-term debt	251		500
Taxes accrued	32		31
Gas imbalances	19		22
Accrued compensation	31		26
Customer deposits	17		38
Other	113		57
Total current liabilities	780		1,615
Other Liabilities:
Accumulated deferred income taxes, net	4		5
Regulatory liabilities	24		23
Other	80		54
Total other liabilities	108		82
Long-Term Debt	3,969		3,129
Commitments and Contingencies (Note 17)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2019 and December 31, 2018, respectively)	362		362
Common units (435,201,365 issued and outstanding at December 31, 2019 and 433,232,411 issued and outstanding at December 31, 2018, respectively)	7,013		7,218
Accumulated other comprehensive loss	(3)		—
Noncontrolling interests	37		38
Total Partners’ Equity	7,409		7,618
Total Liabilities and Partners’ Equity	$	12,266	$	12,444

See Notes to the Consolidated Financial Statements

5

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Cash Flows from Operating Activities:
Net income	$	400	$	523	$	437
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	433		398		366
Deferred income taxes	(1)		(1)		(3)
Impairment	86		—		—
Loss on sale/retirement of assets	8		1		7
Equity in earnings of equity method affiliate	(17)		(26)		(28)
Return on investment in equity method affiliate	17		26		28
Equity-based compensation	16		16		15
Amortization of debt costs and discount (premium)	(1)		(1)		(2)
Changes in other assets and liabilities:
Accounts receivable, net	43		(10)		(23)
Accounts receivable—affiliated companies	(6)		(1)		(5)
Inventory	4		(10)		1
Gas imbalance assets	(6)		8		4
Other current assets	9		(21)		4
Other assets	11		(12)		1
Accounts payable	(75)		4		54
Accounts payable—affiliated companies	(3)		1		—
Gas imbalance liabilities	(3)		10		(23)
Other current liabilities	39		4		(4)
Other liabilities	(12)		15		5
Net cash provided by operating activities	942		924		834
Cash Flows from Investing Activities:
Capital expenditures	(432)		(728)		(416)
Acquisitions, net of cash acquired	—		(443)		(298)
Proceeds from sale of assets	1		8		1
Proceeds from insurance	1		2		2
Return of investment in equity method affiliate	8		7		5
Other, net	(8)		—		—
Net cash used in investing activities	(430)		(1,154)		(706)
Cash Flows from Financing Activities:
(Decrease) increase in short-term debt	(494)		244		405
Proceeds from long-term debt, net of issuance costs	1,544		787		691
Repayment of long-term debt	(700)		(450)		—
Proceeds from Revolving Credit Facility	—		350		1,200
Repayment of Revolving Credit Facility	(250)		(100)		(1,836)
Proceeds from issuance of common units, net of issuance costs	—		2		—
Distributions to common unitholders	(564)		(551)		(355)
Distributions to subordinated unitholders	—		—		(198)
Distributions to preferred unitholders	(36)		(36)		(36)
Distributions to non-controlling interests	(5)		(4)		(1)
Cash paid for employee equity-based compensation	(25)		(9)		(2)
Net cash (used in) provided by financing activities	(530)		233		(132)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(18)		3		(4)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	22		19		23
Cash, Cash Equivalents and Restricted Cash at End of Period	$	4	$	22	$	19

See Notes to the Consolidated Financial Statements

6

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

	Series A Preferred Units			Common Units			Subordinated Units			Accumulated Other Comprehensive Earnings		Noncontrolling Interest		Total Partners’ Equity
	Units	Value		Units	Value		Units	Value		Value		Value		Value
	(In millions)
Balance as of Balance as of December 31, 2016	15	$	362	224	$	3,737	208	$	3,683	$	—	$	12	$	7,794
Net income	—	36		—	266		—	134		—		1		437
Conversion of subordinated units	—	—		208	3,619		(208)	(3,619)		—		—		—
Distributions	—	(36)		—	(355)		—	(198)		—		(1)		(590)
Equity-based compensation, net of units for employee taxes	—	—		1	13		—	—		—		—		13
Balance as of 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 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

See Notes to the Consolidated Financial Statements

7

Exhibit 99.01

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (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. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The 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. The Partnership’s 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. Crude oil gathering assets are located in Oklahoma and serve crude oil production in the SCOOP and STACK plays of the Anadarko Basin and in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s 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, 2019, 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 the Partnership’s General Partner (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, 2019, 2018 and 2017, the Partnership owned a 50% interest in SESH. See Note 11 for further discussion of SESH. For the years ended December 31, 2019, 2018 and 2017, the Partnership held a 50% ownership interest in Atoka and consolidated Atoka in its 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 November 1, 2018 through December 31, 2019, the Partnership owned a 60% interest in ESCP, which is consolidated in its Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Basis of Presentation

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.

 For a description of the Partnership’s reportable segments, see Note 20.

Use of Estimates

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.

8

Exhibit 99.01

Revenue Recognition

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) upon its adoption on January 1, 2018. As the Partnership adopted using the modified retrospective method, revenue for all periods prior to January 1, 2018 were recognized in accordance with “Revenue Recognition” (Topic 605). Please see Note 3 for a description of the impact of adoption. 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 current-month nominations and contracted prices. Revenues associated with the production of NGLs are estimated based on current-month 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, 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 years ended December 31, 2018 and 2017. See note 16 for more information on revenues from affiliates.

Additionally, for the years ended December 31, 2019, 2018 and 2017, one third party purchased approximately 12%, 12% and 13%, respectively, of the NGLs delivered off our system, which accounted for approximately $131 million, $214 million and $140 million, or 4%, 6% and 5%, respectively, of total revenues. Additionally, in the years ended December 31, 2019, 2018 and 2017, another third party purchased 12%, 8% and 12%, respectively, of the NGLs delivered off our system, which accounted for $119 million, $152 million and $127 million, respectively, or 4%, 4% and 4%, respectively, of total revenues.

Natural Gas and Natural Gas Liquids Purchases

Cost of natural gas and natural gas liquids represents the cost of our natural gas and natural gas liquids purchased exclusive of depreciation, Operation and maintenance and General and administrative expenses and consists primarily of product and fuel costs. Estimates for gas purchases are based on estimated volumes and contracted purchase prices. Estimated

9

Exhibit 99.01

gas 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 and General and Administrative Expense

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.

Environmental Costs

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 no material amounts accrued at December 31, 2019 or 2018.

Depreciation and Amortization Expense

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.

Income Taxes

The Partnership’s earnings are not subject to income tax (other than Texas state margin taxes 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 taxes 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.

Cash and Cash Equivalents

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 $4 million and $8 million of cash and cash equivalents as of December 31, 2019 and 2018, respectively.

10

Exhibit 99.01

Restricted Cash

Restricted cash consists of cash which is restricted by agreements with third parties. The Consolidated Balance Sheets have $0 and $14 million of restricted cash as of December 31, 2019 and 2018, respectively.

Accounts Receivable and 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 upon specific identification and estimates of 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 at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $2 million allowance for doubtful accounts was required at each of the years ended December 31, 2019 and 2018.

Inventory

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, 2019 and 2018, and $1 million for the year ended December 31, 2017. 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, 2019, 2018 and 2017, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $8 million, $4 million and $2 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.

	December 31,
	2019		2018
	(In millions)
Materials and supplies	$	32	$	31
Natural gas and natural gas liquids	14		19
Total Inventory	$	46	$	50

Gas Imbalances

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.

Long-Lived Assets (including Intangible Assets)

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

11

Exhibit 99.01

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.

Assessing Impairment of Long-lived Assets (including Intangible Assets) and Goodwill

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. For more information, see Note 14.

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.

Regulatory Assets and Liabilities

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, 2019 and 2018, these removal costs of $24 million and $23 million, respectively, are classified as Regulatory liabilities in the Consolidated Balance Sheets.

Capitalization of Interest and Allowance for Funds Used During Construction

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, 2019, 2018 and 2017, the Partnership capitalized interest and AFUDC of $2 million, $6 million and $1 million, respectively.

Derivative Instruments

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.

12

Exhibit 99.01

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.

Fair Value Measurements

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.

Equity-Based Compensation

The Partnership awards equity-based compensation to officers, directors and 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.

Employee Benefit Plans

On January 1, 2015, the Partnership 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, 2019, 2018 and 2017, the Partnership contributed $20 million, $19 million and $18 million, respectively.

During the years ended December 31, 2019, 2018 and 2017, 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, 2019, 2018 and 2017, the Partnership reimbursed OGE Energy $3 million, $3 million and $5 million, respectively, for these benefits. See Note 16 for further information related to our related party transactions.

Fifth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP

On November 14, 2017, the General Partner adopted the Fifth Amended and Restated Agreement of Limited Partnership (the Partnership Agreement), to implement certain changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 relating to partnership audit and adjustment procedures. The Partnership Agreement also removed references to the subordinated units (all of which previously converted into common units) and related provisions.

(2) New Accounting Pronouncements

Accounting Standards to be Adopted in Future Periods

13

Exhibit 99.01

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely manner. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other

In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership elected to adopt the guidance in ASU 2017-04 effective October 1, 2019, and as a result applied the new guidance to its annual goodwill impairment test performed as of October 1, 2019. The impairment resulting from the October 1, 2019 annual impairment test was based upon the amount by which the carrying amount exceeded the reporting unit’s fair value up to the actual amount of goodwill recorded for the Anadarko Basin reporting unit.

Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other—Internal-Use Software

In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract,” which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Collaborative Arrangements

In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

14

Exhibit 99.01

Codification Improvements

In April 2019, the FASB issued ASU No. 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments,” which clarifies and improves areas of guidance related to recently issued standards on credit losses, hedging and recognition and measurement. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

In November 2019, FASB issued ASU No. 2019-11, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses,” which introduced an expected credit loss model for the impairment of financial assets measured at amortized cost basis to replace the probable, incurred loss model for those assets. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership expects to adopt this standard in the first quarter of 2020 and does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

(3) Revenues

The Partnership adopted ASU No. 2014-09, “Revenue from Contracts with Customers” (ASC 606) on January 1, 2018 using the modified retrospective method. Upon adoption, the Partnership did not recognize a material cumulative adjustment to Partners’ Equity and there were no material changes in the timing of revenue recognition or our accounting policies. The Partnership has applied the standard only to contracts that were not expired as of January 1, 2018.

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, 2019 and 2018.

	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

15

Exhibit 99.01

	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

Product Sales

Natural Gas, NGLs or Condensate

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.

Gain (Loss) on Derivative Activity

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

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.

Demand revenues

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

•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.

•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

16

Exhibit 99.01

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.

Volume-dependent revenues

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.

Accounts Receivable

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:

	December 31, 2019		December 31, 2018
	(In millions)
Accounts Receivable:
Customers	$	239	$	297
Contract assets (1)	18		6
Non-customers	12		6
Total Accounts Receivable (2)	$	269	$	309

____________________

(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 $6 million of contract assets related to firm transportation contracts with tiered rates, which are reflected in Other Assets.

(2)Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.

Contract Liabilities

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:

•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.

•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.

17

Exhibit 99.01

The table below summarizes the change in the contract liabilities for the year ended December 31, 2019:

	December 31, 2019		December 31, 2018		Amounts recognized in revenues
	(In millions)
Deferred revenues (1)	$	48	$	48	$	24

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2019:

	2020		2021		2022		2023		2024 and After
	(In millions)
Deferred revenues (1)	$	25	$	6	$	6	$	5	$	6

____________________

(1)Deferred revenues includes deferred revenue—affiliated companies. This amount is included in Other current liabilities and Other long-term liabilities.

Remaining Performance Obligations

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, 2019:

	2020		2021		2022		2023		2024 and After
	(In millions)
Transportation and Storage (1)	$	461	$	298	$	238	$	225	$	699
Gathering and Processing	137		121		123		121		313
Total remaining performance obligations	$	598	$	419	$	361	$	346	$	1,012

____________________

(1)The remaining performance obligations include certain obligations for MRT, which are calculated based on rates that are subject to FERC rate case approval.

(4) Leases

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

18

Exhibit 99.01

operating leases. The Partnership did not recognize a material cumulative adjustment to the Consolidated Statement 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 buildings, 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. Field equipment has an expected lease term of three to five years, with contractual base terms of one to three 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. Buildings have an expected lease term of seven to ten years, which is currently the same as the contractual base term. Building rental arrangements contain market-based renewal options of up to 15 years. Variable lease payments for buildings are generally comprised of costs for utilities, maintenance and building management services. Variable lease payments due under building rental arrangements began July 1, 2019, with amounts due monthly. The Partnership is generally not aware of the implicit rate for either field equipment or building 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, 2019, the weighted average remaining lease term is 6.4 years and the weighted average discount rate is 5.40%.

As of December 31, 2019, we have right-of-use assets of $37 million recorded as Other Assets, $9 million of corresponding obligations recorded as Other Current Liabilities and $31 million of corresponding obligations recorded as Other Liabilities on the Partnership’s Consolidated Balance Sheet. All lease obligations outstanding during the year ended December 31, 2019 were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities. Total lease costs comprised of field equipment rentals and buildings rentals were $29 million and $7 million in the Consolidated Statements of Income during the year ended December 31, 2019, respectively.

The table below summarizes lease cost for the year ended December 31, 2019:

	Year Ended December 31, 2019
	Gathering and Processing		Transportation and Storage		Total
	(In millions)
Lease Cost:
Operating lease cost	$	11	$	—	$	11
Short-term lease cost	22		2		24
Variable lease cost	1		—		1
Total Lease Cost	$	34	$	2	$	36

Under ASC 842, as of December 31, 2019, the Partnership has operating lease obligations expiring at various dates. The $4 million difference between undiscounted cash flows for operating leases and our $40 million of lease obligations is due to the impact of the applicable discount rate. Undiscounted cash flows for operating lease liabilities are as follows:

	Year Ended December 31,
	2020		2021		2022		2023		2024		2025 and After		Total
	(In millions)
Noncancellable operating leases	$	11	$	7	$	6	$	6	$	4	$	10	$	44

Description of Lease Contracts

The Partnership occupied 162,053 square feet of office space at its former principle executive offices under a lease that expired June 30, 2019. The lease payments were $19 million over the lease term, which began April 1, 2012. These lease costs are included in General and administrative expense in the Consolidated Statements of Income.

During 2017, the Partnership entered into a lease to occupy 48,642 square feet of office space in Houston, Texas, which

19

Exhibit 99.01

ends December 31, 2025. The lease payments are $4 million over the lease term, as well as a proportionate percentage of facility expenses. These lease costs are included in General and administrative expense in the Consolidated Statements of Income.

On August 28, 2018, the Partnership entered into a lease to occupy 154,584 feet of office space for its principle executive offices in Oklahoma City, Oklahoma, which expires June 30, 2029. The lease payments commenced on July 1, 2019, and total $25 million over the lease term, as well as a proportionate percentage of facility expenses. The Partnership relocated its headquarters to the new location during the second quarter of 2019. Minimum lease payments were $1 million in 2019 and are expected to be $2 million per year from 2020 through 2023.

The Partnership currently has 86 compression service agreements, of which 71 agreements are on a month-to-month basis and 15 agreements will expire in 2020. The Partnership also has nine gas treating lease agreements, of which seven are on a month-to-month basis, one agreement will expire in 2021 and one agreement will expire in 2022. These lease costs are reflected in Operation and maintenance expense in the Consolidated Statements of Income.

ASC 840 Lease Accounting

Under ASC 840 rental expense was $35 million and $27 million during the years ended December 31, 2018 and 2017, respectively.

As of December 31, 2018, the Partnership had the following future minimum payments for operating lease obligations as follows:

	Year Ended December 31,
	2019		2020-2021		2022-2023		After 2023		Total
	(In millions)
Noncancellable operating leases	$	14	$	6	$	6	$	14	$	40

(5) Acquisitions

EOCS Acquisition

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:

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

20

Exhibit 99.01

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 Partnership’s financial statements resulting in $28 million in non-controlling interest. The Partnership incurred approximately $6 million of acquisition costs associated with this transaction, 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 periods presented as the impact would not be material.

ETGP Acquisition

On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, now ETGP, a midstream service provider with natural gas gathering and processing facilities in the Cotton Valley and Haynesville plays of the Ark-La-Tex Basin, for approximately $298 million in cash. The acquisition was accounted for as a business combination and funded with borrowings under the Revolving Credit Facility. During the fourth quarter of 2017, the Partnership finalized the purchase price allocation as of October 4, 2017.

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

Purchase price allocation (in millions):
Assets acquired:
Accounts receivable	$	5
Property, plant and equipment	111
Intangibles	176
Goodwill	12
Liabilities assumed:
Current liabilities	6
Total identifiable net assets	$	298

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 10 years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Ark-La-Tex Basin and is allocated to the gathering and processing reportable segment. The Partnership incurred approximately $2 million of acquisition costs associated with this transaction, which are 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 periods presented as the impact would not be material.

(6) Earnings Per Limited Partner Unit

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 dilutive effect of the unit-based awards discussed in Note 19 was $0.01 per unit during the years ended December 31, 2019 and 2018 and less than $0.01 per unit during the year ended December 31, 2017.

21

Exhibit 99.01

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

	Year Ended December 31,
	2019		2018		2017
	(In millions, except per unit data)
Net income	$	400	$	523	$	437
Net income attributable to noncontrolling interests	4		2		1
Series A Preferred Unit distributions	36		36		36
General partner interest in net income	—		—		—
Net income available to common and subordinated units	$	360	$	485	$	400
Net income allocable to common units	$	360	$	485	$	273
Net income allocable to subordinated units	—		—		127
Net income available to common and subordinated units	$	360	$	485	$	400
Net income allocable to common units	$	360	$	485	$	273
Dilutive effect of Series A Preferred Unit distribution	—		—		—
Diluted net income allocable to common units	360		485		273
Diluted net income allocable to subordinated units	—		—		127
Total	$	360	$	485	$	400
Basic weighted average number of outstanding
Common units (1)	436		434		296
Subordinated units	—		—		137
Total	436		434		433
Basic earnings per unit
Common units	$	0.83	$	1.12	$	0.92
Subordinated units	$	—	$	—	$	0.93
Basic weighted average number of outstanding common units (1)	436		434		296
Dilutive effect of Series A Preferred Units	—		—		—
Dilutive effect of performance units	1		2		1
Diluted weighted average number of outstanding common units	437		436		297
Diluted weighted average number of outstanding subordinated units	—		—		137
Total	437		436		434
Diluted earnings per unit
Common units	$	0.82	$	1.11	$	0.92
Subordinated units	$	—	$	—	$	0.93

____________________

(1)Basic weighted average number of outstanding common units for the years ended December 31, 2019, 2018, and 2017 includes approximately one million time-based phantom units.

See Note 7 for discussion of the expiration of the subordination period.

(7) Partners’ Equity

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.

22

Exhibit 99.01

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2019, 2018 and 2017 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2019
December 31, 2019 (1)	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
2017
December 31, 2017	February 20, 2018	February 27, 2018	$	0.318	$	138
September 30, 2017	November 14, 2017	November 21, 2017	$	0.318	$	138
June 30, 2017	August 22, 2017	August 29, 2017	$	0.318	$	138
March 31, 2017	May 23, 2017	May 30, 2017	$	0.318	$	137

_____________________

(1)The Board of Directors declared a $0.3305 per common unit cash distribution on February 7, 2020, to be paid on February 25, 2020, to common unitholders of record at the close of business on February 18, 2020.

23

Exhibit 99.01

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2019, 2018, and 2017 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2019
December 31, 2019 (1)	February 7, 2020	February 14, 2020	$	0.625	$	9
September 30, 2019	November 5, 2019	November 14, 2019	$	0.625	$	9
June 30, 2019	August 2, 2019	August 14, 2019	$	0.625	$	9
March 31, 2019	April 29, 2019	May 15, 2019	$	0.625	$	9
2018
December 31, 2018	February 8, 2019	February 14, 2019	$	0.625	$	9
September 30, 2018	November 6, 2018	November 14, 2018	$	0.625	$	9
June 30, 2018	August 1, 2018	August 14, 2018	$	0.625	$	9
March 31, 2018	May 1, 2018	May 15, 2018	$	0.625	$	9
2017
December 31, 2017	February 9, 2018	February 15, 2018	$	0.625	$	9
September 30, 2017	October 31, 2017	November 14, 2017	$	0.625	$	9
June 30, 2017	July 31, 2017	August 14, 2017	$	0.625	$	9
March 31, 2017	May 2, 2017	May 12, 2017	$	0.625	$	9

_____________________

(1)The Board of Directors declared a $0.625 per Series A Preferred Unit cash distribution on February 7, 2020, to be paid on February 14, 2020 to Series A Preferred unitholders of record at the close of business on February 7, 2020.

General Partner Interest and Incentive Distribution Rights

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.

Expiration of Subordination Period

Prior to the expiration of the subordination period, CenterPoint Energy and OGE Energy held 139,704,916 and 68,150,514 subordinated units, respectively. The financial tests required for conversion of all subordinated units were met and the 207,855,430 outstanding subordinated units converted into common units on a one-for-one basis on August 30, 2017. The conversion of the subordinated units did not change the aggregate amount of outstanding units, and the conversion of the subordinated units did not impact the amount of cash available for distribution by the Partnership.

Series A Preferred Units

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.

Pursuant to the Partnership Agreement, the Series A Preferred Units:

•rank senior to the Partnership’s common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up;

•have no stated maturity;

•are not subject to any sinking fund; and

24

Exhibit 99.01

•will remain outstanding indefinitely unless repurchased or redeemed by the Partnership or converted into its common units in connection with a change of control.

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.

ATM Program

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. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. For the year ended December 31, 2019, the Partnership did not sell any common units under the ATM Program. For the year ended December 31, 2018, 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 proceeds were used for general partnership purposes. As of December 31, 2019, approximately $197 million of common units of aggregate offering price remained available for issuance through the ATM Program.

25

Exhibit 99.01

(8) Property, Plant and Equipment

The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage reportable segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations.

Property, plant and equipment includes the following:

	Weighted Average Useful Lives (Years)	December 31,
		2019		2018
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	33	$	8,252	$	8,011
Transportation and Storage	39	4,778		4,740
Construction work-in-progress		131		148
Total		$	13,161	$	12,899
Accumulated depreciation:
Gathering and Processing		1,252		1,063
Transportation and Storage		1,039		965
Total accumulated depreciation		2,291		2,028
Property, plant and equipment, net		$	10,870	$	10,871

The Partnership recorded depreciation expense of $371 million, $351 million and $335 million during the years ended December 31, 2019, 2018 and 2017, respectively.

(9) Intangible Assets, Net

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:

	December 31,
	2019		2018
	(In millions)
Customer relationships:
Total intangible assets (1)	$	840	$	840
Accumulated amortization	239		177
Net intangible assets	$	601	$	663

____________________

(1)See Note 5 for discussion of the acquisition of EOCS and ETGP during the years ended December 31, 2018 and 2017, respectively.

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, $47 million and $31 million during the years ended December 31, 2019, 2018 and 2017, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:

26

Exhibit 99.01

	2020		2021		2022		2023		2024
	(In millions)
Expected amortization of intangible assets	$	62	$	62	$	62	$	62	$	62

(10) Goodwill

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 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 have been cutting back spending and shifting 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.

While the fair value of the Ark-La-Tex Basin reporting unit exceeded its carrying value as of December 31, 2019, a lower fair value estimate and an impairment of the Partnership’s $12 million of goodwill could result from sustained commodity price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, such as decreased prices in market-based transactions for similar assets. The change in carrying amount of goodwill in each of our reportable segments is as follows:

	Gathering and Processing		Transportation and Storage		Total
	(in millions)
Balance as of December 31, 2017	$	12	$	—	$	12
EOCS Acquisition (1)	86		—		86
Balance as of December 31, 2018	$	98	$	—	$	98
Goodwill impairment	$	(86)	$	—	$	(86)
Balance as of December 31, 2019	$	12	$	—	$	12

_____________________

(1)See Note 5 for further discussion.

(11) Investment in Equity Method Affiliate

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, 2019 and 2018. 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.

27

Exhibit 99.01

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, 2019, 2018 and 2017, the Partnership billed SESH $17 million, $18 million and $17 million, respectively, associated with these service agreements.

The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017.

SESH:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Equity in Earnings of Equity Method Affiliate	$	17	$	26	$	28
Distributions from Equity Method Affiliate (1)	25		33		33

____________________ 

(1)Distributions from equity method affiliate includes a $17 million, $26 million and $28 million return on investment and a $8 million, $7 million and $5 million return of investment for the years ended December 31, 2019, 2018 and 2017, respectively.

Summarized financial information of SESH:

	December 31,
	2019		2018
	(In millions)
Balance Sheets:
Current assets	$	49	$	30
Property, plant and equipment, net	1,060		1,078
Total assets	$	1,109	$	1,108
Current liabilities	$	30	$	13
Long-term debt	398		397
Members’ equity	681		698
Total liabilities and members’ equity	$	1,109	$	1,108
Reconciliation:
Investment in SESH	$	309	$	317
Less: Capitalized interest on investment in SESH	(1)		(1)
Add: Basis differential, net of amortization	33		33
The Partnership’s share of members’ equity	$	341	$	349

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Income Statements:
Revenues	$	109	$	112	$	113
Operating income	50		67		72
Net income	33		50		54

28

Exhibit 99.01

(12) Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2019 and 2018.

	December 31, 2019						December 31, 2018
	Outstanding Principal		Premium (Discount)(1)		Total Debt		Outstanding Principal		Premium (Discount)(1)		Total Debt
	(In millions)
Commercial Paper	$	155	$	—	$	155	$	649	$	—	$	649
Revolving Credit Facility	—		—		—		250		—		250
2019 Term Loan Agreement	800		—		800		—		—		—
2019 Notes	—		—		—		500		—		500
2024 Notes	600		—		600		600		—		600
2027 Notes	700		(2)		698		700		(2)		698
2028 Notes	800		(5)		795		800		(6)		794
2029 Notes	550		(1)		549		—		—		—
2044 Notes	550		—		550		550		—		550
EOIT Senior Notes	250		1		251		250		7		257
Total debt	$	4,405	$	(7)	$	4,398	$	4,299	$	(1)	$	4,298
Less: Short-term debt (2)					155						649
Less: Current portion of long-term debt (3)					251						500
Less: Unamortized debt expense (4)					23						20
Total long-term debt					$	3,969					$	3,129

___________________

(1)Unamortized premium (discount) on long-term debt is amortized over the life of the respective debt.

(2)Short-term debt includes $155 million and $649 million of commercial paper outstanding as of December 31, 2019 and 2018, respectively.

(3)As of December 31, 2019, Current portion of long-term debt includes the $251 million outstanding balance of the EOIT Senior Notes due March 15, 2020. At December 31, 2018, Current portion of long-term debt included the $500 million outstanding balance of the 2019 Notes due May 15, 2019.

(4)As of December 31, 2019 and 2018, there was an additional $4 million and $6 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):

2020	$	405
2021	—
2022	800
2023	—
2024	600
Thereafter	$	2,600

Commercial Paper

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 $155 million and $649 million outstanding under our commercial paper program at December 31, 2019 and December 31, 2018, respectively. The weighted average interest rate for the outstanding commercial paper was 2.29% as of December 31, 2019.

29

Exhibit 99.01

Revolving Credit Facility

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 one-year term. As of December 31, 2019, there were no principal advances and $3 million in 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, 2019, 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, 2019, 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.

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.

2019 Term Loan Agreement

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. 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, 2019, 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, 2019, the weighted average interest rate of the 2019 Term Loan Agreement was 3.10%.

Prior to the expiration of the availability period for advances on July 26, 2019, the Partnership drew $1 billion in advances under the Term Loan Agreement, which were used for general partnership purposes and repayment of the 2019 Notes. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable. On September 16, 2019, the Partnership prepaid $200 million of the advances under the Term Loan Agreement, the repayment of which was not subject to LIBOR breakage costs. As of December 31, 2019, there was $800 million outstanding under the 2019 Term Loan Agreement.

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

30

Exhibit 99.01

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.

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.

Senior Notes

On September 13, 2019, the Partnership completed the public offering of $550 million aggregate principal amount of its 4.150% Senior Notes due 2029. The Partnership received net proceeds of approximately $544 million, after deducting the underwriting discount and offering expenses. The net proceeds were used to repay $200 million of borrowings outstanding under the 2019 Term Loan Agreement, to repay amounts outstanding under the commercial paper program, and for general partnership purposes. The 2029 Notes had an unamortized discount of $1 million and unamortized debt expense of $5 million at December 31, 2019, resulting in an effective interest rate of 4.31% from the issue date through December 31, 2019.

As of December 31, 2019, the Partnership’s debt also included the 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had $7 million of unamortized discount and $18 million of unamortized debt expense at December 31, 2019, resulting in effective interest rates of 4.01%, 4.57%, 5.20% and 5.08%, respectively, during the year ended December 31, 2019. In May 2019, the Partnership’s 2019 Notes matured and were paid using proceeds from the 2019 Term Loan Agreement.

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, 2019, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $1 million of unamortized premium at December 31, 2019, resulting in an effective interest rate of 3.84% during the year ended December 31, 2019. These senior notes do not contain any financial covenants other than a limitation on liens. This limitation on liens is subject to certain exceptions and qualifications.

As of December 31, 2019, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

(13) Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. 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.

Commodity Price Risk

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:

•NGL put options, NGL futures and swaps, and WTI crude oil futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

•natural gas futures and swaps, natural gas options, natural gas 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.

31

Exhibit 99.01

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, 2019 and 2018, the Partnership had no commodity derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

Interest Rate Risk

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, 2019, the Partnership had no interest rate derivative instruments that were designated as fair value hedges for accounting purposes. As of December 31, 2018, the Partnership had no outstanding interest rate derivative instruments.

Credit Risk

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.

Derivatives Not Designated as Hedging Instruments

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.

32

Exhibit 99.01

As of December 31, 2019 and 2018, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

	December 31, 2019		December 31, 2018
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	10	19	16	28
Financial basis futures/swaps	11	30	18	29
Financial swaptions (2)	—	2	—	1
Physical purchases/sales	—	6	—	11
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	990	—	945
Financial swaptions (2)	—	225	—	30
Natural gas liquids— MBbl (4)
Financial futures/swaps	2,490	2,415	270	2,535

____________________

(1)As of December 31, 2019December 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. As of December 31, 2018, 74.0% of the natural gas contracts had durations of one year or less, 24.2% had durations of more than one year and less than two years and 1.8% had durations of more 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, 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. As of December 31, 2018, 76.9% of the crude oil (for condensate) contracts had durations of one year or less and 23.1% had durations of more than one year and less than two years.

(4)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. As of December 31, 2018, 86.1% of the natural gas liquids contracts had durations of one year or less and 13.9% had durations of more than one year and less than two years.

Derivatives Designated as Hedging Instruments

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, 2019 and December 31, 2018, the Partnership had the following derivative instruments that were designated as hedging instruments for accounting purposes:

	December 31, 2019		December 31, 2018
	Gross Notional Value
	(In millions)
Interest rate swaps	$	300	$	—

33

Exhibit 99.01

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets at December 31, 2019 and 2018 that were not designated as hedging instruments for accounting purposes are as follows:

		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	7	$	5	$	3	$	5
Financial futures/swaps	Other	—		1		—		2
Physical purchases/sales	Other Current	5		—		3		—
Physical purchases/sales	Other	—		—		4		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	1		19		9		3
Financial futures/swaps	Other	—		8		2		—
Natural gas liquids
Financial futures/swaps	Other Current	25		3		10		1
Financial futures/swaps	Other	11		2		2		—
Total gross derivatives (1)		$	49	$	38	$	33	$	11

_____________________

(1)See Note 14 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and 2018.

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018 that were designated as hedging instruments for accounting purposes are as follows:

		December 31, 2019				December 31, 2018
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Interest rate swaps	Other Current	$	—	$	1	$	—	$	—
Interest rate swaps	Other	—		2		—		—
Total gross interest rate derivatives (1)		$	—	$	3	$	—	$	—

_____________________

(1)All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of December 31, 2019.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Consolidated Statements of Income for the years ended December 31, 2019, 2018 and 2017:

34

Exhibit 99.01

	Amounts Recognized in Income
	Year Ended December 31,
	2019		2018		2017
	(In millions)
Natural Gas
Financial futures/swaps gains (losses)	$	13	$	(8)	$	20
Physical purchases/sales gains	2		7		9
Crude oil (for condensate)
Financial futures/swaps (losses) gains	(41)		6		(1)
Natural gas liquids
Financial futures/swaps gains (losses)	42		6		(9)
Total	$	16	$	11	$	19

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2019, 2018 and 2017 are reported in Product sales. For derivatives designated as hedges, amounts recognized in income and reported in Interest expense for the year ended December 31, 2019 were approximately zero.

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, 2019, 2018 and 2017: 

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Change in fair value of derivatives	$	(11)	$	26	$	28
Realized gain (loss) on derivatives	27		(15)		(9)
Gain on derivative activity	$	16	$	11	$	19

Credit-Risk Related Contingent Features in Derivative Instruments

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, 2019, 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 no 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.

(14) Fair Value Measurements

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

35

Exhibit 99.01

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, 2019, 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, 2019, 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.

Estimated Fair Value of Financial Instruments

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, 2019 and 2018:

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$	—	$	—	$	250	$	250
2019 Term Loan Agreement (Level 2)	800		800		—		—
2019 Notes (Level 2)	—		—		500		497
2024 Notes (Level 2)	600		614		600		571
2027 Notes (Level 2)	698		698		698		642
2028 Notes (Level 2)	795		811		794		764
2029 Notes (Level 2)	549		526		—		—
2044 Notes (Level 2)	550		506		550		445
EOIT Senior Notes (Level 2)	251		252		257		256

______________________

36

Exhibit 99.01

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $155 million and $649 million of commercial paper was outstanding as of December 31, 2019 and 2018, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 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, 2019, 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, 2019, all of the asset groups were considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions could reduce forecasted undiscounted cash flows.

Contracts with Master Netting Arrangements

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, 2019, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments. 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, 2019 and December 31, 2018:

December 31, 2019	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	5	$	31	$	—	$	—
Significant other observable inputs (Level 2)	44		7		14		11
Unobservable inputs (Level 3)	—		—		—		—
Total fair value	49		38		14		11
Netting adjustments	(37)		(37)		—		—
Total	$	12	$	1	$	14	$	11

December 31, 2018	Commodity Contracts				Gas Imbalances (1)
	Assets		Liabilities		Assets (2)		Liabilities (3)
	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$	4	$	9	$	—	$	—
Significant other observable inputs (Level 2)	29		2		18		17
Unobservable inputs (Level 3)	—		—		—		—
Total fair value	33		11		18		17
Netting adjustments	(9)		(9)		—		—
Total	$	24	$	2	$	18	$	17

37

Exhibit 99.01

______________________

(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, 2019 and 2018.

(2)Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $21 million and $11 million at December 31, 2019 and 2018, 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 $8 million and $5 million at December 31, 2019 and 2018, 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.

Changes in Level 3 Fair Value Measurements

The following tables provides a reconciliation of changes in the fair value of our Level 3 commodity contracts between the periods presented. Transfers out of Level 3 represent liabilities that were previously classified as Level 3 for which the inputs became observable for classification in Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Partnership’s derivative contracts is subject to change.

	Commodity Contracts
	Natural gas liquids financial futures/swaps
	(In millions)
Balance as of December 31, 2017	$	(5)
Losses included in earnings	(23)
Settlements	7
Transfers out of Level 3	21
Balance as of December 31, 2018	$	—

For the year ended December 31, 2019, there were no Level 3 commodity contracts.

(15)Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	185	$	148	$	114
Income taxes, net of refunds	1		3		—
Non-cash transactions:
Accounts payable related to capital expenditures	10		54		39
Lease liabilities arising from the application of ASC 842	45		—		—

38

Exhibit 99.01

The following table reconciles cash and cash equivalents and restricted cash on the Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows:

	December 31,
	2019		2018
	(In millions)
Cash and cash equivalents	$	4	$	8
Restricted cash	—		14
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	4	$	22

As of December 31, 2018, Restricted cash included $14 million of cash collateral which was provided by a third party as credit assurance. The cash collateral was released in 2019.

39

Exhibit 99.01

(16) Related Party Transactions

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.

Transportation and Storage Agreements

Transportation and Storage Agreements with CenterPoint Energy

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 term of these contracts is through March 31, 2021. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.

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. For the years ended December 31, 2019 and 2018, we reimbursed CenterPoint Energy’s LDCs $2 million and $1 million, respectively, in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines and in connection with a reimbursement associated with an unplanned pipeline outage. For the year ended December 31, 2017, we reimbursed CenterPoint Energy’s LDCs $1 million in connection with receipt facility modifications that were necessitated by the repair and maintenance of our pipelines.

Transportation and Storage Agreement with OGE Energy

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 of April 1, 2019 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 of December 1, 2018 through December 1, 2038. EOIT has agreed to pay OGE Energy $2 million and to waive $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.

Gas Sales and Purchases Transactions

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%, 5% and 5% of total revenues during the years ended December 31, 2019, 2018 and 2017, respectively. Amounts of total revenues from affiliated companies included in the Partnership’s Consolidated Statements of Income are summarized as follows:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$	108	$	111	$	110
Natural gas product sales — CenterPoint Energy	8		11		6
Gas transportation and storage service revenues — OGE Energy	41		37		35
Natural gas product sales — OGE Energy	10		4		2
Total revenues — affiliated companies	$	167	$	163	$	153

40

Exhibit 99.01

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

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	—	$	3	$	1
Cost of natural gas purchases — OGE Energy	33		23		19
Total cost of natural gas purchases — affiliated companies	$	33	$	26	$	20

Corporate services, operating lease expense and seconded employee

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 2019 are $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, 2019, 2018 and 2017, 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 2019 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:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Corporate Services — CenterPoint Energy	$	—	$	1	$	3
Operating Lease — CenterPoint Energy	1		1		1
Seconded Employee Costs — OGE Energy	18		29		31
Corporate Services — OGE Energy	—		1		3
Total corporate services, operating lease and seconded employee expense	$	19	$	32	$	38

(17) Commitments and Contingencies

Commercial Obligations

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, 2019, the Partnership estimates the remaining associated minimum volume commitment fee to be $192 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2020 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,

41

Exhibit 99.01

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 may transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as $500 million and the project is backed by a 20-year firm transportation service. 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 2022.

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. Until such time as the sale closes, the Partnership will continue to utilize this facility to provide storage services to its customers. On January 27, 2020, FERC approved the sale. The Partnership anticipates closing the sale on April 1, 2020.

Legal, Regulatory and Other Matters

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.

(18) Income Taxes

The Partnership’s earnings are generally not subject to income tax ( 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 taxes 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). On December 22, 2017, the act known as the “Tax Cuts and Jobs Act,” was signed into law which lowered the corporate tax rate from 35% to 21% for tax years beginning after December 31, 2017. As a result of this new law, the Partnership’s corporate subsidiaries re-valued their deferred income tax assets and liabilities as of December 31, 2017, which resulted in recording a federal deferred income tax benefit of $1 million for the year ended December 31, 2017.

The items comprising income tax expense are as follows:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Provision for current income taxes
Federal	$	—	$	—	$	1
State	—		—		1
Total provision for current income taxes	—		—		2
Benefit for deferred income taxes, net
Federal	$	(1)	$	(1)	$	(2)
State	—		—		(1)
Total benefit for deferred income taxes, net	(1)		(1)		(3)
Total income tax benefit	$	(1)	$	(1)	$	(1)

42

Exhibit 99.01

The components of Deferred Income Taxes as of December 31, 2019 and 2018 were as follows:

	December 31,
	2019		2018
	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	17	$	16
Depreciation	6		5
Accrued compensation	(19)		(16)
Total deferred tax liabilities, net	$	4	$	5

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2019, 2018 and 2017.

Tax Audits and Settlements

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

(19) Equity-Based Compensation

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 Sheet. The following table summarizes the Partnership’s equity-based compensation expense for the years ended December 31, 2019, 2018 and 2017 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:

	Year Ended December 31,
	2019		2018		2017
	(In millions)
Performance units	$	9	$	9	$	10
Restricted units	—		1		2
Phantom units	7		6		3
Total equity-based compensation expense	$	16	$	16	$	15

43

Exhibit 99.01

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2019, 2018 and 2017 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 2019, 2018 and 2017 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 2019, 2018 and 2017 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.

	2019			2018			2017
Number of units granted	638,798			551,742			468,626
Fair value of units granted	$	19.95		$	17.70		$	19.27
Expected price volatility	34.2		%	44.2		%	47.3		%
Risk-free interest rate	2.54		%	2.36		%	1.57		%
Distribution yield	8.38		%	8.56		%	9.10		%
Expected life of units (in years)	3			3			3

Phantom Units

Awards of phantom units have been made under the LTIP in 2019, 2018 and 2017 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.

	2019	2018	2017
Phantom units granted	695,486	546,708	392,338
Fair value of phantom units granted	$8.95 - $15.04	$13.74 - $17.00	$15.44 - $16.93

44

Exhibit 99.01

Other Awards

In 2019, 2018 and 2017, 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.

	2019		2018		2017
Common units granted	28,221		16,335		16,653
Fair value of common units granted	$	10.43	$	14.94	$	15.03

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units as of December 31, 2019 and changes during 2019 are shown in the following table.

	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 12/31/2018	2,109,835		$	14.33	1,447,590		$	12.38
Granted (1)	638,798		19.95		695,486		14.26
Vested (2)(3)	(1,174,597)		11.09		(608,755)		8.71
Forfeited	(180,707)		18.96		(141,761)		14.89
Units outstanding at 12/31/2019	1,393,329		19.04		1,392,560		14.65
Aggregate intrinsic value of units outstanding at December 31, 2019	$	14			$	14

_____________________

(1)For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0% to 200% of the target.

(2)Performance units vested as of December 31, 2019 include 1,097,846 and 26,986 units from 2016 grants, which were approved by the Board of Directors in 2016 and paid out at 200%, or 2,195,692 units on March 1, 2019 and 53,972 units on September 6, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through December 31, 2018.

(3)Performance units outstanding as of December 31, 2019 include 378,109 units from the 2017 annual grants, 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 a performance period of January 1, 2017 through December 31, 2019, will not vest. 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, 2019, 2018 and 2017 are shown in the following tables.

	Year Ended December 31, 2019
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	34	$	—	$	9
Fair value of units vested	13		—		5

	Year Ended December 31, 2018
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	11	$	3	$	1
Fair value of units vested	7		4		—

45

Exhibit 99.01

	Year Ended December 31, 2017
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	5	$	2	$	—
Fair value of units vested	10		4		—

Unrecognized Compensation Expense

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.

	December 31, 2019
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	12	1.32
Phantom Units	9		1.24
Total	$	21

As of December 31, 2019, there were 6,353,205 units available for issuance under the long-term incentive plan.

(20) Reportable Segments

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

Financial data for reportable segments are as follows:

Year Ended December 31, 2019	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total
	(In millions)
Product sales	$	1,449	$	487	$	(403)	$	1,533
Service revenues	889		551		(13)		1,427
Total Revenues	2,338		1,038		(416)		2,960
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,203		491		(415)		1,279
Operation and maintenance, General and administrative	320		207		(1)		526
Depreciation and amortization	308		125		—		433
Impairments	86		—		—		86
Taxes other than income tax	41		26		—		67
Operating Income	$	380	$	189	$	—	$	569
Total Assets	$	9,739	$	5,886	$	(3,359)	$	12,266
Capital expenditures	$	314	$	118	$	—	$	432

46

Exhibit 99.01

Year Ended December 31, 2018	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total
	(In millions)
Product sales	$	2,016	$	625	$	(535)	$	2,106
Service revenues	802		537		(14)		1,325
Total Revenues	2,818		1,162		(549)		3,431
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,741		628		(550)		1,819
Operation and maintenance, General and administrative	312		189		—		501
Depreciation and amortization	263		135		—		398
Impairments	—		—		—		—
Taxes other than income tax	38		27		—		65
Operating Income	$	464	$	183	$	1	$	648
Total Assets	$	9,874	$	5,805	$	(3,235)	$	12,444
Capital expenditures, including acquisitions	$	981	$	190	$	—	$	1,171

Year Ended December 31, 2017	Gathering and Processing		Transportation and Storage (1)		Eliminations		Total
	(In millions)
Product sales	$	1,538	$	621	$	(506)	$	1,653
Service revenues	632		525		(7)		1,150
Total Revenues	2,170		1,146		(513)		2,803
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	1,285		604		(508)		1,381
Operation and maintenance, General and administrative	289		179		(4)		464
Depreciation and amortization	232		134		—		366
Impairments	—		—		—		—
Taxes other than income tax	37		27		—		64
Operating Income	$	327	$	202	$	(1)	$	528
Total Assets	$	9,079	$	5,616	$	(3,102)	$	11,593
Capital expenditures	$	601	$	113	$	—	$	714

_____________________

(1)Equity in earnings of equity method affiliate is included in Other Income (Expense) on the Consolidated Statements of Income and is not included in the table above. See Note 11 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage reportable segment for the years ended December 31, 2019, 2018 and 2017.

47

Exhibit 99.01

(21) Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2019 and 2018 are as follows:

	Quarters Ended
	March 31, 2019		June 30, 2019		September 30, 2019		December 31, 2019
	(in millions, except per unit data)
Total Revenues	$	795	$	735	$	699	$	731
Cost of natural gas and natural gas liquids	378		317		263		321
Operating income (1)	165		167		175		62
Net income	123		124		133		20
Net income attributable to limited partners	122		124		132		18
Net income attributable to common units	113		115		123		9
Basic earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02
Diluted earnings per unit
Common units	$	0.26	$	0.26	$	0.28	$	0.02
	Quarters Ended
	March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018
	(in millions, except per unit data)
Total Revenues	$	748	$	805	$	928	$	950
Cost of natural gas and natural gas liquids	375		444		516		484
Operating income	139		126		171		212
Net income	114		95		139		175
Net income attributable to limited partners	114		95		138		174
Net income attributable to common units	105		86		129		165
Basic earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38
Diluted earnings per unit
Common Units	$	0.24	$	0.20	$	0.30	$	0.38

_____________________

(1)The Partnership recorded an impairment to goodwill of $86 million during the fourth quarter related to the Anadarko Basin reporting unit, included in the gathering and processing reportable segment. See Note 10 for further information.

48