Exhibit 99.02

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, 2018 and 2017, the related consolidated statements of income, cash flows, and partners’ equity for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, 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, 2019, 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.

/s/ DELOITTE & TOUCHE LLP

Oklahoma City, Oklahoma

February 19, 2019

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

1

Exhibit 99.02

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2018			2017			2016
	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 15)):
Product sales	$	2,106		$	1,653		$	1,172
Service revenue	1,325			1,150			1,100
Total Revenues	3,431			2,803			2,272
Cost and Expenses (including expenses from affiliates (Note 15)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,819			1,381			1,017
Operation and maintenance	388			369			367
General and administrative	113			95			98
Depreciation and amortization	398			366			338
Impairments (Note 13)	—			—			9
Taxes other than income taxes	65			64			58
Total Cost and Expenses	2,783			2,275			1,887
Operating Income	648			528			385
Other Income (Expense):
Interest expense	(152		)	(120		)	(99		)
Equity in earnings of equity method affiliate	26			28			28
Total Other Income (Expense)	(126		)	(92		)	(71		)
Income Before Income Taxes	522			436			314
Income tax (benefit) expense	(1		)	(1		)	1
Net Income	$	523		$	437		$	313
Less: Net income attributable to noncontrolling interests	2			1			1
Net Income Attributable to Limited Partners	$	521		$	436		$	312
Less: Series A Preferred Unit distributions (Note 6)	36			36			22
Net Income Attributable to Common and Subordinated Units (Note 5)	$	485		$	400		$	290
Basic earnings per unit (Note 5)
Common units	$	1.12		$	0.92		$	0.69
Subordinated units	$	—		$	0.93		$	0.68
Diluted earnings per unit (Note 5)
Common units	$	1.11		$	0.92		$	0.69
Subordinated units	$	—		$	0.93		$	0.68

See Notes to the Consolidated Financial Statements

2

Exhibit 99.02

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2018		2017
	(In millions, except units)
Current Assets:
Cash and cash equivalents	$	8	$	5
Restricted cash	14		14
Accounts receivable, net	290		277
Accounts receivable—affiliated companies	19		18
Inventory	50		40
Gas imbalances	29		37
Other current assets	39		25
Total current assets	449		416
Property, Plant and Equipment:
Property, plant and equipment	12,899		12,079
Less accumulated depreciation and amortization	2,028		1,724
Property, plant and equipment, net	10,871		10,355
Other Assets:
Intangible assets, net	663		451
Goodwill	98		12
Investment in equity method affiliate	317		324
Other	46		35
Total other assets	1,124		822
Total Assets	$	12,444	$	11,593
Current Liabilities:
Accounts payable	$	288	$	263
Accounts payable—affiliated companies	4		3
Short-term debt	649		405
Current portion of long-term debt	500		450
Taxes accrued	31		32
Gas imbalances	22		12
Accrued compensation	26		32
Customer deposits	38		34
Other	57		48
Total current liabilities	1,615		1,279
Other Liabilities:
Accumulated deferred income taxes, net	5		6
Regulatory liabilities	23		21
Other	54		38
Total other liabilities	82		65
Long-Term Debt	3,129		2,595
Commitments and Contingencies (Note 16)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at December 31, 2018 and December 31, 2017, respectively)	362		362
Common units (433,232,411 issued and outstanding at December 31, 2018 and 432,584,080 issued and outstanding at December 31, 2017, respectively)	7,218		7,280
Noncontrolling interests	38		12
Total Partners’ Equity	7,618		7,654
Total Liabilities and Partners’ Equity	$	12,444	$	11,593

See Notes to the Consolidated Financial Statements

3

Exhibit 99.02

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2018			2017			2016
	(In millions)
Cash Flows from Operating Activities:
Net income	$	523		$	437		$	313
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	398			366			338
Deferred income taxes	(1		)	(3		)	2
Impairments	—			—			9
Loss on sale/retirement of assets	1			7			17
Equity in earnings of equity method affiliate	(26		)	(28		)	(28		)
Return on investment of equity method affiliate	26			28			28
Equity-based compensation	16			15			13
Amortization of debt costs and discount (premium)	(1		)	(2		)	(3		)
Changes in other assets and liabilities:
Accounts receivable, net	(10		)	(23		)	(4		)
Accounts receivable—affiliated companies	(1		)	(5		)	8
Inventory	(10		)	1			12
Gas imbalance assets	8			4			(18		)
Other current assets	(21		)	4			6
Other assets	(12		)	1			(1		)
Accounts payable	4			54			(34		)
Accounts payable—affiliated companies	1			—			(6		)
Gas imbalance liabilities	10			(23		)	10
Other current liabilities	4			(4		)	45
Other liabilities	15			5			14
Net cash provided by operating activities	924			834			721
Cash Flows from Investing Activities:
Capital expenditures	(728		)	(416		)	(383		)
Acquisitions, net of cash acquired	(443		)	(298		)	—
Proceeds from sale of assets	8			1			1
Proceeds from insurance	2			2			—
Return of investment in equity method affiliate	7			5			15
Net cash used in investing activities	(1,154		)	(706		)	(367		)
Cash Flows from Financing Activities:
Increase (decrease) in short-term debt	244			405			(236		)
Proceeds from long-term debt, net of issuance costs	787			691			—
Repayment of long-term debt	(450		)	—			—
Proceeds from revolving credit facility	350			1,200			1,734
Repayment of revolving credit facility	(100		)	(1,836		)	(1,408		)
Repayment of notes payable—affiliated companies	—			—			(363		)
Proceeds from issuance of common units, net of issuance costs	2			—			137
Proceeds from issuance of Series A Preferred Units, net of issuance costs	—			—			362
Distributions	(591		)	(590		)	(561		)
Cash paid for employee equity-based compensation	(9		)	(2		)	—
Net cash provided by (used in) financing activities	233			(132		)	(335		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	3			(4		)	19
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	19			23			4
Cash, Cash Equivalents and Restricted Cash at End of Period	$	22		$	19		$	23

See Notes to the Consolidated Financial Statements

4

Exhibit 99.02

ENABLE MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

	Series A Preferred Units				Common Units				Subordinated Units					Noncontrolling Interest			Total Partners’ Equity
	Units	Value			Units	Value			Units		Value			Value			Value
	(In millions)
Balance as of December 31, 2015	—	$	—		214	$	3,714		208		$	3,805		$	12		$	7,531
Net income	—	22			—	147			—		143			1			313
Issuance of Series A Preferred Units	15	362			—	—			—		—			—			362
Issuance of common units	—	—			10	137			—		—			—			137
Distributions	—	(22		)	—	(274		)	—		(265		)	(1		)	(562		)
Equity-based compensation, net of units for employee taxes	—	—			—	13			—		—			—			13
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 December 31, 2017	15	$	362		433	$	7,280		—		$	—		$	12		$	7,654
Net income	—	36			—	485			—		—			2			523
Issuance of common units	—	—			—	2			—		—			—			2
Acquisition of EOCS	—	—			—	—			—		—			28			28
Distributions	—	(36		)	—	(551		)	—		—			(4		)	(591		)
Equity-based compensation, net of units for employee taxes	—	—			—	2			—		—			—			2
Balance as of December 31, 2018	15	$	362		433	$	7,218		—		$	—		$	38		$	7,618

See Notes to the Consolidated Financial Statements

5

Exhibit 99.02

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 by CenterPoint Energy, OGE Energy and ArcLight, pursuant to the terms of the Master Formation Agreement. 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, 2018, CenterPoint Energy held approximately 54.0% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.6% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. See Note 6 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, 2018, 2017 and 2016, the Partnership owned a 50% interest in SESH. See Note 10 for further discussion of SESH. For the years ended December 31, 2018, 2017 and 2016, 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, 2018, the Partnership owned a 60% interest in VPP, which is consolidated in its Consolidated Financial Statements as EOCS acted as the managing member of VPP and had control over the operations of VPP.

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 19.

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.

6

Exhibit 99.02

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 revenue 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 revenue: Service revenue represents 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. “Revenues” in the Notes to the Consolidated Financial Statements under Item 8. “Financial Statements and Supplementary Data” 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 had$48 million and $34 millionof deferred revenues, including deferred revenue—affiliated companies, included in Other current liabilities and Other long-term liabilities on the Consolidated Balance Sheets at December 31, 2018 and 2017, respectively.

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. Additionally, for the years ended December 31, 2018, 2017 and 2016, one third party purchased approximately 12%, 13% and 22%, respectively, of the NGLs delivered off our system, which accounted for approximately $214 million, $140 million and $129 million, or 6%, 5% and 6%, respectively, of total revenues. Additionally, in the year ended December 31, 2018 and 2017, another third party purchased 8% and 12%, respectively, of the NGLs delivered off our system, which accounted for $152 million and $127 million, respectively, or 4% and 4%, respectively, of total revenues. Other than revenues from affiliates discussed in Note 15, there are no other revenue concentrations with individual customers in the years ended December 31, 2018, 2017 and 2016.

Natural Gas and Natural Gas Liquids Purchases

Cost of natural gas and natural gas liquids represents 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 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.

7

Exhibit 99.02

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 with 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, 2018 or 2017.

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 17.

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 $8 million and $5 million of cash and cash equivalents as of December 31, 2018 and 2017, respectively.

Restricted Cash

Restricted cash consists of cash which is restricted by agreements with third parties. The Consolidated Balance Sheets have $14 million and $14 million of restricted cash as of December 31, 2018 and 2017, respectively.

8

Exhibit 99.02

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 and $3 million allowance for doubtful accounts was required at December 31, 2018 and 2017, respectively.

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 the year ended December 31, 2018 and $1 million for each of the years ended December 31, 2017 and 2016. 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 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 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, 2018, 2017 and 2016, the Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of $4 million, $2 million and $3 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,
	2018		2017
	(In millions)
Materials and supplies	$	31	$	29
Natural gas and natural gas liquids	19		11
Total Inventory	$	50	$	40

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 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.

9

Exhibit 99.02

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 13.

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. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference. The Partnership performs its goodwill impairment testing one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 9.

Regulatory Assets and Liabilities

The Partnership applies the guidance for accounting for regulated operations to portions of the transportation and storage 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, 2018 and 2017, these removal costs of $23 million and $21 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, 2018, 2017 and 2016, the Partnership capitalized interest and AFUDC of $6 million, $1 million and $4 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 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 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 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.

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

10

Exhibit 99.02

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, 2018, 2017 and 2016, the Partnership contributed $19 million, $18 million and $16 million, respectively.

During the years ended December 31, 2018, 2017 and 2016, 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, 2018, 2017 and 2016, the Partnership reimbursed OGE Energy $3 million, $5 million and $7 million, respectively, for these benefits. See Note 15 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

Leases

In February 2016, the FASB issued 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.

11

Exhibit 99.02

In January 2018, the FASB issued ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This standard permits an entity to elect an 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 intends to elect this transition provision.

In July 2018, the FASB issued ASU No. 2018-10, “Codification Improvements to Topic 842, Leases” to address implementation issues that could arise as organizations comply with ASC 842.

In July 2018, the FASB issued ASU No. 2018-11, “Leases (Topic 842) - Targeted Improvements” to assist stakeholders with implementation questions and issues as organizations prepare to adopt ASC 842. These questions and issues relate primarily to (1) comparative reporting requirements for initial adoption; and (2) for lessors only, separating lease and non-lease components in a contract and allocating the consideration in the contract to the separate components.

In December 2018, the FASB issued ASU No. 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors” to address stakeholders’ concerns regarding: (1) sales taxes and similar taxes collected from lessees; (2) certain lessor costs paid directly by lessees; and (3) recognition of variable payments for contracts with lease and non-lease components.

Based upon the Partnership’s continuing assessment of contracts and easements relative to the provisions of the ASU No. 2016-02 lease standard, the ASU No. 2018-01 easement standard, the ASU No. 2018-10 codification improvements standard, the ASU No. 2018-11 targeted improvements standard and ASU No. 2018-20 improvements for lessors standard, the Partnership anticipates the adoption of ASC No. 842 will increase 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 are currently classified as operating leases. We continue to develop the underlying reports, internal controls and disclosures to record activity under Topic 842 upon adoption. The Partnership adopted Topic 842 on January 1, 2019 on a retrospective basis as of that date. Upon adoption, the Partnership did not recognize a material cumulative adjustment to the Consolidated Statement of Partners’ Equity and we do not expect any material changes in the timing of expense recognition or our accounting policies.

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 matter. 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 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. The Partnership does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Compensation—Stock Compensation

In June 2018, the FASB issued ASU No. 2018-07, “Compensation-Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting.” This standard requires entities to include share-based payment transactions for acquiring goods and services from non-employees. The standard is effective for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

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

12

Exhibit 99.02

notes to the financial statements by facilitating clear communication of the information required by 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 these standards in the first quarter of 2020 and continues to evaluate the other impacts of the new standards 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 does not expect the adoption of this standard to have a material impact on our Consolidated Financial Statements and related disclosures.

Derivatives and Hedging

In October 2018, the FASB issued ASU No. 2018-16, “Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (SOFR) Overnight Index Swap (OIS) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes,” which expands the list of United States (U.S.) benchmark interest rates permitted in the application of hedge accounting. This standard allows the use of the Overnight Index Swap (OIS) Rate based on the Secured Overnight Financing Rate (SOFR) as a U.S. benchmark interest rate for hedge accounting purposes. The standard is effective for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have 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 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 to only contracts that were not expired as of January 1, 2018.

13

Exhibit 99.02

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

	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 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 12 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 may contain performance obligations that are settled over time. For these types of contracts with customers, service revenue is recognized when the right to invoice has been met, which is 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

14

Exhibit 99.02

addition to the fees paid for the minimum volume of natural gas or crude oil. Certain of our contracts provide our customers the option to elect to pay a higher gathering fee over the remaining term of the contract in lieu of making a contractually agreed upon shortfall payment. Once the services have been completed, or the customer no longer has the ability to utilize the services, the performance obligation is met, and revenue is recognized. In addition, when certain minimum volume commitment fee arrangements include commitments of one year or more, significant judgment is used in interim commitment periods in which a customer’s actual volumes are deficient in relation to the minimum volume commitment. Revenue is recognized in proportion to the pattern of past performance exercised by the customer or when the likelihood of the customer meeting the minimum volume commitment becomes remote.

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 fees are dependent on throughput by third party customers, which results in performance obligations for each individual unit of volume and revenue is recognized as the service is performed. Our other fee revenue arrangements 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.

	December 31, 2018		January 1, 2018
	(In millions)
Accounts Receivable:
Customers	$	297	$	265
Contract assets (1)	6		27
Non-customers	6		3
Total Accounts Receivable (2)	$	309	$	295

____________________

(1) Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets decreased $21 million compared to January 1, 2018 due to increased throughput on certain minimum volume commitment arrangements resulting in lower recognized contract assets as of December 31, 2018. Total Accounts Receivable does not include $3 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.

15

Exhibit 99.02

The table below summarizes the change in the contract liabilities for the year ended December 31, 2018:

	December 31, 2018		December 31, 2017		Amounts recognized in revenues
	(In millions)
Deferred revenues	$	48	$	34	$	19

The table below summarizes the timing of recognition of these contract liabilities as of December 31, 2018:

	2019		2020		2021		2022		2023 and After
	(In millions)
Deferred revenues	$	25	$	5	$	5	$	5	$	8

Remaining Performance Obligations

Our remaining performance obligations consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and 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, 2018:

	2019		2020		2021		2022		2023 and After
	(In millions)
Transportation and Storage	$	438	$	319	$	175	$	133	$	745
Gathering and Processing	280		164		136		138		461
Total remaining performance obligations	$	718	$	483	$	311	$	271	$	1,206

Impact of Adoption

Upon adoption of ASC 606, the recognition of revenues for certain contractual arrangements was impacted as follows:

• Natural gas and natural gas liquids purchase arrangements - For certain arrangements within our gathering and processing segment, the Partnership purchases and controls the entire hydrocarbon stream at the point of receipt. As of January 1, 2018, these arrangements are considered supplier contracts rather than contracts with customers. Therefore, beginning January 1, 2018, the gathering and processing fees for these arrangements that were previously recognized as Service revenues under ASC 605 are recognized as reductions to Cost of natural gas and natural gas liquids.

• Percent-of-proceeds and percent-of-liquids processing arrangements - Under percent-of-proceeds and percent-of-liquids arrangements within our gathering and processing segment, the Partnership has previously recognized the value of natural gas and natural gas liquids received in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the natural gas and NGLs received as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the natural gas or NGLs are sold and Product sales are recognized.

• Keep-whole arrangements - Under keep-whole arrangements within our gathering and processing segment, the Partnership has previously recognized the value of NGLs received in Product sales and the value of the thermally equivalent quantity of natural gas provided in our purchase cost within Cost of natural gas and natural gas liquids. As of January 1, 2018, the Partnership recognizes the value of the NGLs received less the value of the thermally equivalent volume of natural gas provided as Service revenues and as an increase to Cost of natural gas and natural gas liquids when the NGLs are sold and Product sales are recognized.

• Fixed fuel arrangements - Under certain gathering arrangements within our gathering and processing segment as well as under certain transportation arrangements within our transportation and storage segment we receive a fixed amount of fuel regardless of actual fuel usage. Previously, revenue for fuel in excess of actual usage was recognized when such fuel was received, and additional revenue was recognized when such fuel was sold. As of January 1, 2018, fuel in excess of actual usage is treated as a byproduct obtained through the fulfillment of a contract, and

16

Exhibit 99.02

the Partnership will recognize revenue at the time the excess fuel is sold. This results in a reduction of Product sales and a corresponding reduction in Cost of natural gas and natural gas liquids.

• Natural gas and natural gas liquids sales arrangements - For certain arrangements within our gathering and processing segment, the Partnership sells the entire hydrocarbon stream at the point of delivery to a third-party processing facility. As of January 1, 2018, these arrangements are considered sales once control has transferred to the third-party processing facility. Therefore, beginning January 1, 2018, the costs and fees for these arrangements that were previously recognized as a component of cost of gas and natural gas liquids, are recognized as reductions to the transaction price under ASC 606.

Below is a summary of the impact of the changes on revenues as it relates to the year ended December 31, 2018:

	Year Ended December 31, 2018
	Under ASC 606		Under ASC 605		Increase/(Decrease)
	(In millions)
Revenues:
Product sales:
Natural gas	$	564	$	635	$	(71	)
Natural gas liquids	1,405		1,434		(29		)
Condensate	126		126		—
Total revenues from natural gas, natural gas liquids, and condensate	2,095		2,195		(100		)
Gain on derivative activity	11		11		—
Total Product sales	$	2,106	$	2,206	$	(100	)
Service revenues:
Demand revenues	$	724	$	724	$	—
Volume-dependent revenues	601		577		24
Total Service revenues	$	1,325	$	1,301	$	24
Total Revenues	$	3,431	$	3,507	$	(76	)

As described above, each of the identified increases/(decreases) in revenue resulted in a corresponding change in the Cost of natural gas and natural gas liquids.

(4) Acquisitions

Velocity Holdings, LLC 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, subject to certain customary working capital adjustments. 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.

17

Exhibit 99.02

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
Accounts receivable	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

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 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 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.

Align Midstream, LLC Acquisition

On October 4, 2017, the Partnership acquired all of the equity interests in Align Midstream, LLC, now Enable Texola Gathering and Processing, LLC, 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 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.

18

Exhibit 99.02

(5) Earnings Per Limited Partner Unit

Basic and diluted earnings per limited partner unit is calculated by dividing net income allocable to common and subordinated unitholders 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 18 was $0.01 per unit during the year ended December 31, 2018 and less than $0.01 per unit during the years ended December 31, 2017 and 2016.

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

	Year Ended December 31,
	2018		2017		2016
	(In millions, except per unit data)
Net income	$	523	$	437	$	313
Net income attributable to noncontrolling interests	2		1		1
Series A Preferred Unit distributions	36		36		22
General partner interest in net income	—		—		—
Net income available to common and subordinated unitholders	$	485	$	400	$	290
Net income allocable to common units	$	485	$	273	$	148
Net income allocable to subordinated units	—		127		142
Net income available to common and subordinated unitholders	$	485	$	400	$	290
Net income allocable to common units	$	485	$	273	$	148
Dilutive effect of Series A Preferred Unit distribution	—		—		—
Diluted net income allocable to common units	485		273		148
Diluted net income allocable to subordinated units	—		127		142
Total	$	485	$	400	$	290
Basic weighted average number of outstanding
Common units (1)	434		296		216
Subordinated units	—		137		208
Total	434		433		424
Basic earnings per unit
Common units	$	1.12	$	0.92	$	0.69
Subordinated units	$	—	$	0.93	$	0.68
Basic weighted average number of outstanding common units	434		296		216
Dilutive effect of Series A Preferred Units	—		—		—
Dilutive effect of performance units	2		1		—
Diluted weighted average number of outstanding common units	436		297		216
Diluted weighted average number of outstanding subordinated units	—		137		208
Total	436		434		424
Diluted earnings per unit
Common units	$	1.11	$	0.92	$	0.69
Subordinated units	$	—	$	0.93	$	0.68

____________________

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

19

Exhibit 99.02

See Note 6 for discussion of the expiration of the subordination period.

(6) Enable Midstream Partners, LP Partners’ Equity

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

The Partnership paid or has authorized payment of the following cash distributions to common and subordinated unitholders, as applicable, during 2018, 2017 and 2016 (in millions, except for per unit amounts):

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2018
December 31, 2018 (1)	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
2016
December 31, 2016	February 21, 2017	February 28, 2017	$	0.318	$	137
September 30, 2016	November 14, 2016	November 22, 2016	$	0.318	$	134
June 30, 2016	August 16, 2016	August 23, 2016	$	0.318	$	134
March 31, 2016	May 6, 2016	May 13, 2016	$	0.318	$	134

_____________________

(1) The board of directors of Enable GP declared this $0.318 per common unit cash distribution on February 8, 2019, to be paid on February 26, 2019, to common unitholders of record at the close of business on February 19, 2019.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2018, 2017, and 2016 (in millions, except for per unit amounts):

20

Exhibit 99.02

Quarter Ended	Record Date	Payment Date	Per Unit Distribution		Total Cash Distribution
2018
December 31, 2018 (1)	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
2016
December 31, 2016	February 10, 2017	February 15, 2017	$	0.625	$	9
September 30, 2016	November 1, 2016	November 14, 2016	$	0.625	$	9
June 30, 2016	August 2, 2016	August 12, 2016	$	0.625	$	9
March 31, 2016 (2)	May 6, 2016	May 13, 2016	$	0.2917	$	4

_____________________

(1) The board of directors of Enable GP declared this $0.625 per Series A Preferred Unit cash distribution on February 8, 2019, which was paid on February 14, 2019 to Series A Preferred unitholders of record at the close of business on February 8, 2019.

(2) The prorated quarterly distribution for the Series A Preferred Units is for a partial period beginning on February 18, 2016, and ending on March 31, 2016, which equates to $0.625 per unit on a full-quarter basis or $2.50 per unit on an annualized basis.

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

On February 18, 2016, the Partnership completed the private placement of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. The Partnership incurred approximately $1 million of expenses related to the offering, which is shown as an offset to the proceeds. In connection with the closing of the private placement, the Partnership redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CenterPoint Energy.

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;

21

Exhibit 99.02

• are not subject to any sinking fund; and

• 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 five years after the original issue date, 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. In addition, the Partnership (or a third-party with its prior written consent) may redeem the Series A Preferred Units following certain changes in the methodology employed by ratings agencies, changes of control or fundamental transactions as set forth in the Partnership Agreement. 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. The Series A Preferred Units are also required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange.

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.

On February 18, 2016, the Partnership entered into a registration rights agreement with CenterPoint Energy, pursuant to which, among other things, the Partnership gave CenterPoint Energy 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 at-the-market program (the “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, 2018, the Partnership issued 140,920 common units under the ATM Program, which generated proceeds of approximately $2 million (net of approximately $25,000 of commissions). For the year ended December 31, 2017, the Partnership issued 18,500 units under the ATM Program, which generated proceeds of approximately $303,000 (net of approximately $3,000 of commissions). The proceeds were used for general partnership purposes. As of December 31, 2018, $197 million of common units remained available for issuance through the ATM Program.

2016 Equity Issuance

On November 29, 2016, the Partnership closed a public offering of 10,000,000 common units at a price to the public of $14.00 per common unit. In connection with the offering, the Partnership, the underwriters and an affiliate of ArcLight entered into an underwriting agreement that provided an option for the underwriters to purchase up to an additional 1,500,000 common units, with 75,719 common units to be sold by the Partnership and 1,424,281 to be sold by the affiliate of ArcLight. The underwriters exercised the option to purchase all of the additional common units, and the Partnership received proceeds (net of underwriting discounts, structuring fees and offering expenses) of $137 million from the offering.

22

Exhibit 99.02

(7) Property, Plant and Equipment

Property, plant and equipment includes the following:

	Weighted Average Useful Lives (Years)	December 31,
		2018		2017
		(In millions)
Property, plant and equipment, gross:
Gathering and Processing	37	$	8,011	$	7,322
Transportation and Storage	36	4,740		4,538
Construction work-in-progress		148		219
Total		$	12,899	$	12,079
Accumulated depreciation:
Gathering and Processing		1,063		865
Transportation and Storage		965		859
Total accumulated depreciation		2,028		1,724
Property, plant and equipment, net		$	10,871	$	10,355

The Partnership recorded depreciation expense of $351 million, $335 million and $311 million during the years ended December 31, 2018, 2017 and 2016, respectively.

(8) Intangible Assets, Net

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

	December 31,
	2018		2017
	(In millions)
Customer relationships:
Total intangible assets (1)	$	840	$	581
Accumulated amortization	177		130
Net intangible assets	$	663	$	451

____________________

(1) See Note 4 for discussion of the acquisition of Velocity Holdings, LLC and Align Midstream, LLC 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 $47 million, $31 million and $27 million during the years ended December 31, 2018, 2017 and 2016, respectively. The following table summarizes the Partnership’s expected amortization of intangible assets for each of the next five years:

	2019		2020		2021		2022		2023
	(In millions)
Expected amortization of intangible assets	$	62	$	62	$	62	$	62	$	62

23

Exhibit 99.02

(9) Goodwill

In the fourth quarter of 2017, as a result of the acquisition of Align, the Partnership recorded $12 million of goodwill, included in the gathering and processing reportable segment. In the fourth quarter of 2018, as a result of the acquisition of Velocity, the Partnership recorded $86 million of goodwill, included in the gathering and processing reportable segment.

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, 2016	$	—	$	—	$	—
Align Midstream, LLC Acquisition (1)	12		—		12
Balance as of December 31, 2017	$	12	$	—	$	12
Velocity Holdings, LLC Acquisition (1)	86		—		86
Balance as of December 31, 2018	$	98	$	—	$	98

_____________________

(1) See Note 4 for further discussion.

(10) 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, 2018 and 2017. 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 our interest in SESH at fair market value, subject to certain exceptions.

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, 2018, 2017 and 2016, the Partnership billed SESH $18 million, $17 million and $13 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, 2018, 2017 and 2016.

SESH:

	Year Ended December 31,
	2018		2017		2016
	(In millions)
Equity in Earnings of Equity Method Affiliate	$	26	$	28	$	28
Distributions from Equity Method Affiliate (1)	33		33		43

____________________ 

(1) Distributions from equity method affiliate includes a $26 million, $28 million and $28 million return on investment and a $7 million, $5 million and $15 million return of investment for the years ended December 31, 2018, 2017 and 2016, respectively.

24

Exhibit 99.02

Summarized financial information of SESH:

	December 31,
	2018			2017
	(In millions)
Balance Sheet Data:
Current assets	$	30		$	32
Property, plant and equipment, net	1,078			1,093
Total assets	$	1,108		$	1,125
Current liabilities	$	13		$	14
Long-term debt	397			397
Members’ equity	698			714
Total liabilities and members’ equity	$	1,108		$	1,125
Reconciliation:
Investment in SESH	$	317		$	324
Less: Capitalized interest on investment in SESH	(1		)	(1		)
Add: Basis differential, net of amortization	33			34
The Partnership’s share of members’ equity	$	349		$	357

	Year Ended December 31,
	2018		2017		2016
	(In millions)
Income Statement Data:
Revenues	$	112	$	113	$	115
Operating income	$	67	$	72	$	73
Net income	$	50	$	54	$	55

25

Exhibit 99.02

(11) Debt

The following table presents the Partnership’s outstanding debt as of December 31, 2018 and 2017.

	December 31, 2018							December 31, 2017
	Outstanding Principal		Premium (Discount)(1)			Total Debt		Outstanding Principal		Premium (Discount)(1)			Total Debt
	(In millions)
Commercial Paper	$	649	$	—		$	649	$	405	$	—		$	405
Revolving Credit Facility	250		—			250		—		—			—
2015 Term Loan Agreement	—		—			—		450		—			450
2019 Notes	500		—			500		500		—			500
2024 Notes	600		—			600		600		—			600
2027 Notes	700		(2		)	698		700		(3		)	697
2028 Notes	800		(6		)	794		—		—			—
2044 Notes	550		—			550		550		—			550
EOIT Senior Notes	250		7			257		250		13			263
Total debt	$	4,299	$	(1	)	$	4,298	$	3,455	$	10		$	3,465
Less: Short-term debt (2)						649							405
Less: Current portion of long-term debt (3)						500							450
Less: Unamortized debt expense (4)						20							15
Total long-term debt						$	3,129						$	2,595

___________________

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

(2) Short-term debt includes $649 million and $405 million of commercial paper outstanding as of December 31, 2018 and 2017, respectively.

(3) As of December 31, 2018, Current portion of long-term debt includes the $500 million outstanding balance of the 2019 Notes due May 15, 2019. At December 31, 2017, Current portion of long-term debt included the $450 million outstanding balance of the 2015 Term Loan Agreement which the Partnership repaid in May 2018.

(4) As of December 31, 2018 and 2017, there was an additional $6 million and $3 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other long-term 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):

2019	$	1,149
2020	250
2021	—
2022	—
2023	250
Thereafter	$	2,650

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 $649 million and $405 million outstanding under our commercial paper program at December 31, 2018 and December 31, 2017, respectively. The weighted average interest rate for the outstanding commercial paper was 3.40% as of December 31, 2018.

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, in aggregate. The Revolving Credit Facility is scheduled to mature

26

Exhibit 99.02

on April 6, 2023, subject to an extension option, which may 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, 2018, there were $250 million 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 applicable credit ratings. As of December 31, 2018, 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 rating from the rating agencies. As of December 31, 2018, 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.

2015 Term Loan Agreement

On July 31, 2015, the Partnership entered into a term loan facility, providing for an unsecured three-year $450 million term loan agreement, which was scheduled to mature on July 31, 2018. The 2015 Term Loan Agreement is included as Current portion of long-term debt in the Partnership’s Consolidated Balance Sheets as of December 31, 2017. In May 2018, we used a portion of the proceeds from the issuance of the 2028 Notes to repay all amounts outstanding under the 2015 Term Loan Agreement.

Senior Notes

On May 10, 2018, the Partnership completed the public offering of $800 million aggregate principal amount of its 4.95% Senior Notes due 2028. The Partnership received net proceeds of approximately $787 million. The proceeds were used for general partnership purposes, including to repay all amounts outstanding under the 2015 Term Loan Agreement, as well as amounts outstanding under the commercial paper program. The 2028 Notes had an unamortized discount of $6 million and unamortized debt expense of $7 million at December 31, 2018, resulting in an effective interest rate of 5.21% during the year ended December 31, 2018.

In addition to the 2028 Notes, as of December 31, 2018, the Partnership’s debt included the 2019 Notes, 2024 Notes, 2027 Notes and 2044 Notes, which had $2 million of unamortized discount and $13 million of unamortized debt expense at December 31, 2018, resulting in effective interest rates of 2.57%, 4.02%, 4.58% and 5.08%, respectively, during the year ended December 31, 2018.

The indenture governing the 2019 Notes, 2024 Notes, 2027 Notes, 2028 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, 2018, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had $7 million of unamortized premium at December 31, 2018, resulting in an effective interest rate of 3.83% during the year ended December 31,

27

Exhibit 99.02

2018. 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, 2018, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.

(12) Derivative Instruments and Hedging Activities

The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.

Commodity Price Risk

The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. 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 exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s 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, 2018 and 2017, the Partnership had no derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.

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 in the Partnership’s asset management activities. 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

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.

28

Exhibit 99.02

As of December 31, 2018 and 2017, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:

	December 31, 2018		December 31, 2017
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas—TBtu (1)
Financial fixed futures/swaps	16	28	17	13
Financial basis futures/swaps	18	29	17	17
Financial swaptions (3)	—	1	—	—
Physical purchases/sales	—	11	1	37
Crude oil (for condensate)—MBbl (2)
Financial futures/swaps	—	945	—	564
Financial swaptions (3)	—	30	—	—
Natural gas liquids—MBbl (4)
Financial futures/swaps	270	2,535	—	1,615

____________________

(1) 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. As of December 31, 2017, 67.7% of the natural gas contracts had durations of one year or less, 16.1% had durations of more than one year and less than two years and 16.2% had durations of more than two years.

(2) 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. As of December 31, 2017, 100% of the crude oil (for condensate) contracts had durations of one year or less.

(3) 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.

(4) 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. As of December 31, 2017, 100% of the natural gas liquid contracts had durations of one year or less.

29

Exhibit 99.02

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Partnership’s Consolidated Balance Sheet at December 31, 2018 and 2017 that were not designated as hedging instruments for accounting purposes are as follows:

		December 31, 2018				December 31, 2017
		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
		(In millions)
Natural gas
Financial futures/swaps	Other Current	$	3	$	5	$	5	$	2
Financial futures/swaps	Other	—		2		—		2
Physical purchases/sales	Other Current	3		—		1		—
Physical purchases/sales	Other	4		—		2		—
Crude oil (for condensate)
Financial futures/swaps	Other Current	9		3		—		4
Financial futures/swaps	Other	2		—		—		—
Financial swaptions	Other	—		—		—		—
Natural gas liquids
Financial futures/swaps	Other Current	10		1		1		5
Financial futures/swaps	Other	2		—		—		—
Total gross derivatives (1)		$	33	$	11	$	9	$	13

_____________________

(1) See Note 13 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheets as of December 31, 2018 and 2017.

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, 2018, 2017 and 2016:

	Amounts Recognized in Income
	Year Ended December 31,
	2018			2017			2016
	(In millions)
Natural Gas
Financial futures/swaps (losses) gains	$	(8	)	$	20		$	(19	)
Physical purchases/sales gains (losses)	7			9			(7		)
Crude oil (for condensate)
Financial futures/swaps gains (losses)	6			(1		)	(4		)
Financial swaptions gains (losses)	—			—			—
Natural gas liquids
Financial futures/swaps gains (losses)	6			(9		)	(13		)
Total	$	11		$	19		$	(43	)

For derivatives not designated as hedges in the tables above, amounts recognized in income for the years ended December 31, 2018, 2017 and 2016, if any, are reported in Product sales.

30

Exhibit 99.02

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, 2018, 2017 and 2016: 

	Year Ended December 31,
	2018			2017			2016
	(In millions)
Change in fair value of derivatives	$	26		$	28		$	(60	)
Realized (loss) gain on derivatives	(15		)	(9		)	17
Gain (loss) on derivative activity	$	11		$	19		$	(43	)

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Services or Standard & Poor’s Ratings Services 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 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, 2018, under these obligations, the Partnership has posted no cash collateral related to NGL swaps and crude oil swaps and swaptions 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.

(13) 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 NYMEX or ICE and settled through either a NYMEX or ICE clearing broker.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, and over-the-counter WTI crude oil swaps and swaptions for condensate sales.

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, 2018, there were no contracts classified as Level 3.

31

Exhibit 99.02

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 period ended December 31, 2018, all instruments previously classified as Level 3 were transferred to Level 2 as the inputs for these liabilities became observable for classification in Level 2.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services 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, 2018 and 2017:

	December 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$	250	$	250	$	—	$	—
2015 Term Loan Agreement (Level 2)	—		—		450		450
2019 Notes (Level 2)	500		497		500		497
2024 Notes (Level 2)	600		571		600		602
2027 Notes (Level 2)	698		642		697		712
2028 Notes (Level 2)	794		764		—		—
2044 Notes (Level 2)	550		445		550		550
EOIT Senior Notes (Level 2)	257		256		263		265

______________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $649 million and $405 million of commercial paper was outstanding as of December 31, 2018 and 2017, respectively.

The fair value of the Partnership’s Revolving Credit Facility, 2015 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 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).

During the year ended December 31, 2016, the Partnership remeasured the Service Star assets at fair value and reassessed the carrying value of the Service Star business line, a component of the gathering and processing segment that provides measurement and communication services to third parties. The impairment, which impaired substantially all of the remaining net book value of the Service Star business line, was primarily driven by the impact of planned technology changes affecting Service Star. Based on forecasted future undiscounted cash flows management determined that the carrying value of the Service Star assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs are forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment and reviewing the associated materials and supplies inventory, during the year ended December 31, 2016, the Partnership recognized a $9 million impairment. The impairment consisted of an $8 million write-down of property, plant and equipment and a $1 million write-down of materials and supplies inventory considered either excess or obsolete.

Based upon review of forecasted undiscounted cash flows as of December 31, 2018, all of the asset groups were considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political

32

Exhibit 99.02

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.

The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2018 and 2017:

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

December 31, 2017	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		$	3		$	—	$	—
Significant other observable inputs (Level 2)	4			5			27		12
Unobservable inputs (Level 3)	—			5			—		—
Total fair value	9			13			27		12
Netting adjustments	(5		)	(5		)	—		—
Total	$	4		$	8		$	27	$	12

______________________

(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, 2018 and 2017.

(2) Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $11 million and $10 million at December 31, 2018 and 2017, 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 $5 million and none at December 31, 2018 and 2017, 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.

33

Exhibit 99.02

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, 2016	$	(8	)
Losses included in earnings	(9		)
Settlements	12
Transfers out of Level 3	—
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	$	—

(14)Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:

	Year Ended December 31,
	2018		2017		2016
	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	148	$	114	$	105
Income taxes, net of refunds	3		—		—
Non-cash transactions:
Accounts payable related to capital expenditures	54		39		18

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,
	2018		2017
	(In millions)
Cash and cash equivalents	$	8	$	5
Restricted cash	14		14
Cash, cash equivalents and restricted cash shown in the Consolidated Statement of Cash Flows	$	22	$	19

(15) 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.

34

Exhibit 99.02

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, no-notice transportation with storage and maximum rate firm transportation. The contracts for firm transportation with seasonal demand will remain in effect through March 31, 2021. The contracts for firm transportation, firm storage and firm no-notice transportation with storage, as well as the contracts for maximum rate firm transportation for Oklahoma and portions of Northeast Texas, are in effect through March 31, 2021, and will remain in effect thereafter unless and until terminated by either party upon 180 days’ prior written notice. The contracts for maximum rate firm transportation for Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. 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 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 year ended December 31, 2018, 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 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 OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy for four of its generating facilities, with a primary term of May 1, 2014 through April 30, 2019. On October 24, 2018, EOIT entered into a no-notice load-following transportation agreement with OGE Energy, with a primary term of April 1, 2019 through May 1, 2024. Following the primary term, the agreement will remain in effect from year to year thereafter unless and until either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period.On December 6, 2016, EOIT entered into an additional firm transportation agreement with OGE Energy, for one of its generating facilities with a primary term that began on December 1, 2018 through December 1, 2038.

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 5%, 5% and 7% of total revenues during the years ended December 31, 2018, 2017 and 2016, 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,
	2018		2017		2016
	(In millions)
Gas transportation and storage service revenue — CenterPoint Energy	$	111	$	110	$	110
Natural gas product sales — CenterPoint Energy	11		6		1
Gas transportation and storage service revenue — OGE Energy	37		35		36
Natural gas product sales — OGE Energy	4		2		12
Total revenues — affiliated companies	$	163	$	153	$	159

35

Exhibit 99.02

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,
	2018		2017		2016
	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$	3	$	1	$	—
Cost of natural gas purchases — OGE Energy	23		19		14
Total cost of natural gas purchases — affiliated companies	$	26	$	20	$	14

Corporate services, operating lease expense and seconded employee

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under service agreements for an initial term that ended on April 30, 2016. The service 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 service 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 2018 are $4 million and $1 million, respectively.

The Partnership leases 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 extends through December 31, 2019. As of December 31, 2018, the Partnership expects to incur approximately $1 million in rent and maintenance expenses under the lease during the remaining term of the lease.

During the years ended December 31, 2018, 2017 and 2016, 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 2018and thereafter, unless and until secondment is terminated.

Amounts charged to the Partnership by affiliates for seconded employees, an operating lease and corporate services, included primarily 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,
	2018		2017		2016
	(In millions)
Corporate Services — CenterPoint Energy	$	1	$	3	$	6
Operating Lease — CenterPoint Energy	1		1		—
Seconded Employee Costs — OGE Energy	29		31		29
Corporate Services — OGE Energy	1		3		5
Total corporate services, operating lease and seconded employee expense	$	32	$	38	$	40

Series A Preferred Units

On February 18, 2016, the Partnership completed the private placement, with CenterPoint Energy, of 14,520,000 Series A Preferred Units representing limited partner interests in the Partnership for a cash purchase price of $25.00 per Series A Preferred Unit, resulting in proceeds of $362 million, net of issuance costs. See Note 6 for further discussion of the Series A Preferred Units.

36

Exhibit 99.02

(16) Commitments and Contingencies

Operating Lease Obligations. The Partnership has operating lease obligations expiring at various dates. Future minimum payments for noncancellable operating leases are as follows:

	Year Ended December 31,
	2019		2020		2021		2022		2023		After 2023		Total
	(In millions)
Noncancellable operating leases	$	14	$	3	$	3	$	3	$	3	$	14	$	40

Total rental expense for all operating leases was $35 million, $27 million and $27 million during the years ended December 31, 2018, 2017 and 2016, respectively.

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

On August 28, 2018, the Partnership entered into the Bank of Oklahoma Park Plaza lease to occupy 154,584 feet of office space in Oklahoma City, Oklahoma, which ends June 30, 2029. The lease payments commence on July 1, 2019, and total $25 million over the lease term, as well as a proportionate percentage of facility expenses. The Partnership will relocate its headquarters to the new location during the third quarter of 2019. Minimum lease payments are expected to be $1 million in 2019 and $2 million per year from 2020 through 2023.

The Partnership currently has 110 compression service agreements, of which 46 agreements are on a month-to-month basis, 60 agreements will expire in 2019 and four agreements 2020. The Partnership also has seven gas treating lease agreements, all of which are on a month-to-month basis. These lease expenses are reflected in Operation and maintenance expense in the Consolidated Statements of Income.

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, 2018, the Partnership estimates the remaining associated 10-year minimum volume commitment fee to be $215 million in the aggregate. Minimum volume commitment fees are expected to be $23 million per year from 2019 through 2027 and $11 million in 2028.

On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project. On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by the 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 $550 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.

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.

37

Exhibit 99.02

(17) Income Taxes

The Partnership’s earnings are generally 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. 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,
	2018			2017			2016
	(In millions)
Provision (benefit) for current income taxes
Federal	$	—		$	1		$	(1	)
State	—			1			—
Total provision (benefit) for current income taxes	—			2			(1		)
Provision (benefit) for deferred income taxes, net
Federal	$	(1	)	(2		)	$	3
State	—			(1		)	(1		)
Total provision (benefit) for deferred income taxes, net	(1		)	(3		)	2
Total income tax (benefit) expense	$	(1	)	$	(1	)	$	1

The components of Deferred Income Taxes as of December 31, 2018 and 2017 were as follows:

	December 31,
	2018			2017
	(In millions)
Deferred tax liabilities, net:
Non-current:
Intercompany management fee	$	16		$	18
Depreciation	5			5
Accrued compensation	(16		)	(17		)
Total deferred tax liabilities, net	5			6

Uncertain Income Tax Positions

There were no unrecognized tax benefits as of December 31, 2018, 2017 and 2016.

Tax Audits and Settlements

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

(18) 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,

38

Exhibit 99.02

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, 2018, 2017 and 2016 related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:

	Year Ended December 31,
	2018		2017		2016
	(In millions)
Performance units	$	9	$	10	$	9
Restricted units	1		2		3
Phantom units	6		3		1
Total equity-based compensation expense	$	16	$	15	$	13

Performance Units

Awards of performance based phantom units (performance units) have been made under the LTIP in 2018, 2017 and 2016 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 2018, 2017 and 2016 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, rather than actual performance, of the performance goals during the award cycle.

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 2018 and 2017 is based on three years of daily stock price observations, to determine the total unitholder return ranking. The expected price volatility for the awards granted in 2016 is based on two years of daily stock price observations, combined with the average of the one-year volatility of the applicable peer group companies used 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.

39

Exhibit 99.02

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.

	2018			2017			2016
Number of units granted	551,742			468,626			1,235,429
Fair value of units granted	$	17.70		$	19.27		$10.42 - $27.77
Expected price volatility	44.2		%	47.3		%	43.2% - 46.0%
Risk-free interest rate	2.36		%	1.57		%	0.86% - 0.90%
Distribution yield	8.56		%	9.10		%	10.70% - 12.10%
Expected life of units (in years)	3			3			3

Phantom Units

Awards of phantom units have been made under the LTIP in 2018, 2017 and 2016 to certain officers and employees providing services to the Partnership and certain directors of Enable GP. Phantom units 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 distributions equivalent rights paid in cash. Phantom units cliff-vest at the end of the vesting period. 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.

	2018	2017	2016
Phantom units granted	546,708	392,338	653,286
Fair value of phantom units granted	$13.74 - $17.00	$15.44 - $16.93	$8.12 - $15.30

Other Awards

In 2018, 2017 and 2016, 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.

	2018		2017		2016
Common units granted	16,335		16,653		14,914
Fair value of common units granted	$	14.94	$	15.03	$	15.35

40

Exhibit 99.02

Units Outstanding

A summary of the activity for the Partnership’s performance units, restricted units and phantom units as of December 31, 2018 and changes during 2018 are shown in the following table.

	Performance Units					Restricted Stock					Phantom Units
	Number of Units			Weighted Average Grant-Date Fair Value, Per Unit		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 12/31/2017	2,040,407			$	13.86	222,434			$	17.87	987,380			$	11.38
Granted (1)	551,742			17.70		—			—		546,708			14.23
Vested (2)(3)	(401,772		)	16.59		(221,068		)	17.87		(25,287		)	13.80
Forfeited	(80,542		)	14.30		(1,366		)	16.75		(61,211		)	12.39
Units outstanding at 12/31/2018	2,109,835			14.33		—			—		1,447,590			12.38
Aggregate intrinsic value of units outstanding at December 31, 2018	$	29				$	—				$	20

_____________________

(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 percent to 200 percent of the target.

(2) Performance units vested as of December 31, 2018 include 401,772 units from the annual grant, which were approved by the Board of Directors in 2015 and paid out at 200% of target, or 803,544 units, based on the level of achievement of a performance goal established by the Board of Directors over the performance period.

(3) Performance units outstanding as of December 31, 2018 include 1,109,676 units from the 2016 annual grant, which were approved by the Board of Directors in 2016. The results of the performance units were certified by the Compensation Committee in February 2019, at a 200% payout based on the level of achievement of a performance goal established by the Board of Directors over a performance period of January 1, 2016 through December 31, 2018. The increase 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, 2018, 2017 and 2016 are shown in the following tables.

	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		—

	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		—

41

Exhibit 99.02

	Year Ended December 31, 2016
	Performance Units		Restricted Stock		Phantom Units
	(In millions)
Aggregate intrinsic value of units vested	$	—	$	1	$	—
Fair value of units vested	—		3		—

Unrecognized Compensation Expense

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

	December 31, 2018
	Unrecognized Compensation Cost (In millions)		Weighted Average to be Recognized (In years)
Performance Units	$	11	0.92
Restricted Units	—		0.00
Phantom Units	8		1.15
Total	$	19

As of December 31, 2018, there were 7,555,026 units available for issuance under the long-term incentive plan.

(19) 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 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.

Financial data for reportable segments are as follows:

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 revenue	802		537		(14		)	1,325
Total Revenues (2)	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
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

42

Exhibit 99.02

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 revenue	632		525		(7		)	1,150
Total Revenues (2)	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, including acquisitions	$	601	$	113	$	—		$	714

Year Ended December 31, 2016	Gathering and Processing		Transportation and Storage (1)		Eliminations			Total
	(In millions)
Product sales	$	1,081	$	479	$	(388	)	$	1,172
Service revenue	559		545		(4		)	1,100
Total Revenues (2)	1,640		1,024		(392		)	2,272
Cost of natural gas and natural gas liquids, excluding depreciation and amortization shown separately	915		492		(390		)	1,017
Operation and maintenance, General and administrative	276		191		(2		)	465
Depreciation and amortization	212		126		—			338
Impairments	9		—		—			9
Taxes other than income tax	32		26		—			58
Operating Income	$	196	$	189	$	—		$	385
Total Assets	$	7,453	$	4,963	$	(1,204	)	$	11,212
Capital expenditures	$	312	$	71	$	—		$	383

_____________________

(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 10 for discussion regarding ownership interest in SESH and related equity earnings included in the transportation and storage segment for the years ended December 31, 2018, 2017 and 2016.

(2) The Partnership had no external customers accounting for 10% or more of Total revenues in periods shown. See Note 15 for revenues from affiliated companies.

43

Exhibit 99.02

(20) Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2018 and 2017 are as follows:

	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 and subordinated units	105		86		129		165
Basic earnings per unit
Common units	$	0.24	$	0.20	$	0.30	$	0.38
Subordinated units (1)	$	—	$	—	$	—	$	—
Diluted earnings per unit
Common units	$	0.24	$	0.20	$	0.30	$	0.38
Subordinated units	$	—	$	—	$	—	$	—
	Quarters Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017
	(in millions, except per unit data)
Total Revenues	$	666	$	626	$	705	$	806
Cost of natural gas and natural gas liquids	308		279		349		445
Operating income	140		122		137		129
Net income	120		96		113		108
Net income attributable to limited partners	120		95		113		108
Net income attributable to common and subordinated units	111		86		104		99
Basic earnings per unit
Common Units	$	0.26	$	0.20	$	0.24	$	0.23
Subordinated units	$	0.25	$	0.20	$	0.24	$	—
Diluted earnings per unit
Common Units	$	0.26	$	0.20	$	0.24	$	0.23
Subordinated units (1)	$	0.25	$	0.20	$	0.24	$	—

_____________________

(1) See Note 6 for discussion of the conversion of the subordinated units.

(21) Subsequent Event

On January 29, 2019, the Partnership entered into a term loan facility, providing for an unsecured three-year $1 billion term loan agreement. As of January 31, 2019, there is a principal advance of $200 million outstanding under the 2019 Term Loan Agreement, and a delayed-draw feature permits the Partnership to borrow up to an additional $800 million within 180 days of the closing date, subject to the terms and conditions of the 2019 Term Loan Agreement. 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 designated ratings from Standard & Poor’s Rating Services,

44

Exhibit 99.02

Moody’s Investor Services and Fitch Ratings. As of January 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. The 2019 Term Loan Agreement contains substantially the same covenants as the Revolving Credit Facility.

The 2019 Term Loan Agreement requires the Partnership to, starting April 29, 2019 and continuing until the date on which all commitments have expired or been terminated or the amount available to be drawn is zero, pay a ticking fee on each lender’s unused commitment amount. The ticking fee shall equal 0.125% on the actual daily amount of such lender’s portion of the unused commitments.

Advances under the 2019 Term Loan Agreement are subject to certain conditions precedent, including the accuracy in all material respects of certain representations and warranties and the absence of any default or event of default. Advances under the 2019 Term Loan Agreement may be used to refinance indebtedness outstanding from time to time and for other general corporate purposes, including to fund acquisitions, investments and capital expenditures. 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.

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

The 2019 Term Loan Agreement also contains covenant s that restrict the Partnership and certain of its subsidiaries in respect of, amoung other things, mergers and consolidations, sales of all or substantially all assets, incurrenece of subisdary 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, amoung 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 judgements in excess of $100 million, and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.

45