EX-99

EX-99 19 oge-ex99_04.htm EX-99.04 EX-99

Exhibit 99.04

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions, except per unit data)
Revenues (including revenues from affiliates (Note 13)):
Product sales	$ 623	$ 280	$ 1,710	$ 764
Service revenues	333	316	1,003	995
Total Revenues	956	596	2,713	1,759
Cost and Expenses (including expenses from affiliates (Note 13)):
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	565	250	1,510	653
Operation and maintenance	92	96	267	313
General and administrative	27	28	89	73
Depreciation and amortization	104	105	313	314
Impairments of property, plant and equipment and goodwill (Note 7)	—	—	—	28
Taxes other than income tax	16	17	52	52
Total Cost and Expenses	804	496	2,231	1,433
Operating Income	152	100	482	326
Other Income (Expense):
Interest expense	(41)	(43)	(125)	(136)
Equity in earnings (losses) of equity method affiliate, net	4	(222)	5	(211)
Other, net	1	2	7	7
Total Other Expense	(36)	(263)	(113)	(340)
Income (Loss) Before Income Tax	116	(163)	369	(14)
Income tax benefit	—	—	—	—
Net Income (Loss)	$ 116	$ (163)	$ 369	$ (14)
Less: Net income (loss) attributable to noncontrolling interest	—	1	2	(6)
Net Income (Loss) Attributable to Limited Partners	$ 116	$ (164)	$ 367	$ (8)
Less: Series A Preferred Unit distributions (Note 6)	9	9	26	27
Net Income (Loss) Attributable to Common Units (Note 5)	$ 107	$ (173)	$ 341	$ (35)

Basic and diluted earnings (loss) per unit (Note 5)
Basic	$ 0.24	$ (0.40)	$ 0.78	$ (0.08)
Diluted	$ 0.24	$ (0.40)	$ 0.76	$ (0.08)

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Net income (loss)	$ 116	$ (163)	$ 369	$ (14)
Other comprehensive income (loss):
Change in fair value of interest rate derivative instruments	—	—	—	(7)
Reclassification of interest rate derivative losses to net income	1	2	4	3
Other comprehensive income (loss)	1	2	4	(4)
Comprehensive income (loss)	117	(161)	373	(18)
Less: Comprehensive income (loss) attributable to noncontrolling interest	—	1	2	(6)
Comprehensive income (loss) attributable to Limited Partners	$ 117	$ (162)	$ 371	$ (12)

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

See Notes to the Unaudited Condensed Consolidated Financial Statements


	September 30, 2021	December 31, 2020

	(In millions)
Current Assets:
Cash and cash equivalents	$ 36	$ 3
Accounts receivable, net of allowance for doubtful accounts (Note 1)	384	248
Accounts receivable—affiliated companies	9	15
Inventory	43	42
Gas imbalances	26	42
Other current assets, net of allowance for doubtful accounts (Note 1)	38	31
Total current assets	536	381
Property, Plant and Equipment:
Property, plant and equipment	13,396	13,220
Less: Accumulated depreciation and amortization	2,785	2,555
Property, plant and equipment, net	10,611	10,665
Other Assets:
Intangible assets, net	492	539
Investment in equity method affiliate	76	76
Other	65	68
Total other assets	633	683
Total Assets	$ 11,780	$ 11,729
Current Liabilities:
Accounts payable	$ 220	$ 149
Accounts payable—affiliated companies	2	2
Current portion of long-term debt	800	—
Short-term debt	50	250
Taxes accrued	55	34
Gas imbalances	28	19
Other	144	128
Total current liabilities	1,299	582
Other Liabilities:
Accumulated deferred income taxes, net	4	5
Regulatory liabilities	27	25
Other	63	71
Total other liabilities	94	101
Long-Term Debt	3,154	3,951
Commitments and Contingencies (Note 14)
Partners’ Equity:
Series A Preferred Units (14,520,000 issued and outstanding at September 30, 2021 and December 31, 2020)	362	362
Common Units (435,877,546 issued and outstanding at September 30, 2021 and 435,549,892 issued and outstanding at December 31, 2020)	6,848	6,713

See Notes to the Unaudited Condensed Consolidated Financial Statements


Accumulated other comprehensive loss	(2)	(6)
Noncontrolling interest	25	26
Total Partners’ Equity	7,233	7,095
Total Liabilities and Partners’ Equity	$ 11,780	$ 11,729

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See Notes to the Unaudited Condensed Consolidated Financial Statements


	Nine Months Ended September 30,
	2021	2020

	(In millions)
Cash Flows from Operating Activities:
Net income (loss)	$ 369	$ (14)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	313	314
Deferred income taxes	—	1
Impairments of property, plant and equipment and goodwill	—	28
Net loss on sale/retirement of assets	1	17
Equity in (earnings) losses of equity method affiliate, net	(5)	211
Return on investment in equity method affiliate	5	14
Equity-based compensation	12	10
Amortization of debt costs and discount	4	3
Other, net	(7)	(5)
Changes in other assets and liabilities:
Accounts receivable, net	(136)	14
Accounts receivable—affiliated companies	6	13
Inventory	(1)	4
Gas imbalance assets	16	(3)
Other current assets, net	(11)	—
Other assets	3	4
Accounts payable	67	(47)
Accounts payable—affiliated companies	—	1
Gas imbalance liabilities	9	(5)
Other current liabilities	42	(14)
Other liabilities	(9)	(3)
Net cash provided by operating activities	678	543
Cash Flows from Investing Activities:
Capital expenditures (excluding equity AFUDC)	(204)	(152)
Proceeds from sale of assets	3	19
Proceeds from insurance	—	1
Return of investment in equity method affiliate	—	9
Other, net	3	3
Net cash used in investing activities	(198)	(120)
Cash Flows from Financing Activities:
Decrease in short-term debt	(200)	179
Repayment of long-term debt	—	(267)
Proceeds from Revolving Credit Facility	—	869
Repayment of Revolving Credit Facility	—	(869)

See Notes to the Unaudited Condensed Consolidated Financial Statements


Distributions to common unitholders	(216)	(288)
Distributions to preferred unitholders	(26)	(27)
Distributions to non-controlling interests	(3)	(5)
Cash paid for employee equity-based compensation	(2)	(1)
Net cash used in financing activities	(447)	(409)
Net Increase in Cash, Cash Equivalents and Restricted Cash	33	14
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	3	4
Cash, Cash Equivalents and Restricted Cash at End of Period	$ 36	$ 18

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

(Unaudited)


	Nine Months Ended September 30, 2021
	Series A Preferred Units		Common Units		Accumulated Other Comprehensive Loss	Noncontrolling Interest	Total Partners’ Equity
	Units	Value	Units	Value	Value	Value	Value

	(In millions)
Balance as of December 31, 2020	15	$ 362	435	$ 6,713	$ (6)	$ 26	$ 7,095
Net income	—	9	—	155	—	1	165
Other comprehensive income	—	—	—	—	1	—	1
Distributions	—	(9)	—	(72)	—	(1)	(82)
Equity-based compensation, net of units for employee taxes	—	—	1	2	—	—	2
Balance as of March 31, 2021	15	$ 362	436	$ 6,798	$ (5)	$ 26	$ 7,181
Net income	—	8	—	79	—	1	88
Other comprehensive income	—	—	—	—	2	—	2
Distributions	—	(8)	—	(72)	—	(2)	(82)
Equity-based compensation, net of units for employee taxes	—	—	—	4	—	—	4
Balance as of June 30, 2021	15	$ 362	436	$ 6,809	$ (3)	$ 25	$ 7,193
Net income	—	9	—	107	—	—	116
Other comprehensive income	—	—	—	—	1	—	1
Distributions	—	(9)	—	(72)	—	—	(81)
Equity-based compensation, net of units for employee taxes	—	—	—	4	—	—	4
Balance as of September 30, 2021	15	$ 362	436	$ 6,848	$ (2)	$ 25	$ 7,233

See Notes to the Unaudited Condensed Consolidated Financial Statements


	Nine Months Ended September 30, 2020
	Series A Preferred Units		Common Units		Accumulated Other Comprehensive Loss	Noncontrolling Interest	Total Partners’ Equity
	Units	Value	Units	Value	Value	Value	Value

	(In millions)
Balance as of December 31, 2019	15	$ 362	435	$ 7,013	$ (3)	$ 37	$ 7,409
Net income (loss)	—	9	—	103	—	(7)	105
Other comprehensive loss	—	—	—	—	(6)	—	(6)
Distributions	—	(9)	—	(144)	—	(3)	(156)
Equity-based compensation, net of units for employee taxes	—	—	—	3	—	—	3
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	—	—	(3)	—	—	(3)
Balance as of March 31, 2020	15	$ 362	435	$ 6,972	$ (9)	$ 27	$ 7,352
Net income	—	9	—	35	—	—	44
Distributions	—	(9)	—	(72)	—	—	(81)
Equity-based compensation, net of units for employee taxes	—	—	—	2	—	—	2
Balance as of June 30, 2020	15	$ 362	435	$ 6,937	$ (9)	$ 27	$ 7,317
Net income (loss)	—	9	—	(173)	—	1	(163)
Other comprehensive loss	—	—	—	—	2	—	2
Distributions	—	(9)	—	(72)	—	(2)	(83)
Equity-based compensation, net of units for employee taxes	—	—	—	3	—	—	3
Balance as of September 30, 2020	15	$ 362	435	$ 6,695	$ (7)	$ 26	$ 7,076

See Notes to the Unaudited Condensed Consolidated Financial Statements

ENABLE MIDSTREAM PARTNERS, LP

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Organization

Enable Midstream Partners, LP (the Partnership) is a Delaware limited partnership whose assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. 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. Our natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. 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.

As of September 30, 2021, CenterPoint Energy held approximately 53.7% or 233,856,623 of the Partnership’s common units, and OGE Energy held approximately 25.5% or 110,982,805 of the Partnership’s common units. Additionally, CenterPoint Energy holds 14,520,000 Series A Preferred Units. 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 on an annual or continuing basis and may not remove Enable GP, its current general partner, 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.

As of September 30, 2021, the Partnership owned a 50% interest in SESH. See Note 8 for further discussion of SESH. For the nine months ended September 30, 2021, the Partnership owned a 50% ownership in Atoka and consolidated Atoka in the accompanying Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, the Partnership held a 60% interest in ESCP, which is consolidated in the accompanying Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.

Merger Agreement

On February 16, 2021, the Partnership and Energy Transfer entered into a Merger Agreement, whereby the Partnership will be acquired by Energy Transfer in an all-equity transaction, including the assumption of debt and other liabilities. Under the terms of the Merger Agreement, which has been unanimously approved by the Boards of Directors of both companies, Partnership common unitholders will receive 0.8595 of an Energy Transfer common unit for each Partnership common unit. Each of the Partnership’s Series A Preferred Units will be exchanged for 0.0265 Series G preferred units of Energy Transfer. The transaction will also include a $10 million cash payment for the Partnership’s general partner.

Generally, the Merger, including the receipt of equity consideration by common unitholders is expected to be treated as a tax-free transaction subject to certain exceptions as described in a Registration Statement on Form S-4 filed by Energy Transfer. The transaction, which is expected to close in the fourth quarter of 2021, is subject to customary closing conditions. CenterPoint Energy and OGE Energy, who collectively own approximately 79% of the outstanding Partnership common units, delivered their consents to the transaction. The Merger Agreement includes certain customary restrictions on the Partnership until closing of the

Merger, such as limitations on distributions, equity issuances, and incurring and prepaying indebtedness. If the Merger does not occur, under certain circumstances, the Partnership may be required to pay Energy Transfer a termination fee of $97.5 million. Until the closing, we must continue to operate the Partnership as a stand-alone company.

Basis of Presentation

The accompanying Condensed Consolidated Financial Statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying Condensed Consolidated Financial Statements and related notes should be read in conjunction with the Consolidated Financial Statements and related notes included in our Annual Report.

The Condensed Consolidated Financial Statements and the related notes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures, (d) acquisitions and dispositions of businesses, assets and other interests, and (e) the impact of the ongoing COVID-19 pandemic and its economic effects, which have continued to cause significant volatility in natural gas, NGLs and crude oil prices.

For a description of the Partnership’s reportable segments, see Note 16.

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.

Sales and Retirements of Assets

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

In April 2020, we sustained damage to an approximately 100-mile gas gathering system in the Ark-La-Tex Basin of our gathering and processing segment. We have ceased operation of this system and are in the process of retiring it. We recognized a loss on retirement of approximately $20 million during the nine months ended September 30, 2020, which is included in Operation and maintenance expense in the Condensed Consolidated Statements of Income.

Accounts Receivable and Allowance for Doubtful Accounts

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

Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based primarily upon the historical loss-rate method established for various pools of accounts receivables with similar levels of credit risk. The historical loss-rates are then adjusted, as necessary, based on current conditions and forecast information that could result in future uncollectable amounts. On an ongoing basis, we evaluate

our customers’ financial strength and liquidity based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable and other receivable balances within other assets at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecast economic conditions over the assets contractual lives. The following table summarizes the required allowance for doubtful accounts.


	September 30, 2021	December 31, 2020

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

Inventory

Natural gas inventory is held, through the transportation and storage segment, to provide operational support for 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. The Partnership recorded write-downs to net realizable value related to natural gas and natural gas liquids inventory of zero and $2 million during the three months ended September 30, 2021 and 2020, respectively, and $1 million and $9 million during the nine months ended September 30, 2021 and 2020, respectively.

Impairment of Long-Lived Assets (including Intangible Assets)

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 7.

Impairment of Goodwill

The Partnership assesses its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. The Partnership utilizes the market or income approaches to estimate the fair value of the reporting unit, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the reporting unit is then compared to the carrying amount of the reporting unit and an impairment charge is recorded to goodwill for the difference. The Partnership performs its goodwill impairment testing at the reporting unit, which is one level below the transportation and storage and gathering and processing reportable segment level. For more information, see Note 7.

Impairment of Investment in Equity Method Affiliate

The Partnership evaluates its Investment in equity method affiliate for impairment when factors indicate that an other than temporary decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. The Partnership utilizes the market or income approaches to estimate the fair value of the investment, also giving consideration to the alternative cost approach. Under the market approach, historical and current year forecasted cash flows are multiplied by

a market multiple to determine fair value. Under the income approach, anticipated cash flows over a period of years plus a terminal value are discounted to present value using appropriate discount rates. The resulting fair value of the investment is then compared to the carrying amount of the investment and an impairment charge equal to the difference, is recorded to Equity in earnings (losses) of equity method affiliate, net. Any basis difference between our recognized Investment in equity method affiliate and the underlying financial statements of the affiliate are assigned to the applicable net assets of the affiliate. For more information, see Note 8.

Capitalization of Interest and Allowance for Funds Used During Construction

Capitalized interest represents the approximate net composite interest cost of borrowed funds used for construction of assets other than those assets regulated by FERC. Allowance for funds used during construction (AFUDC) is separated into two components, borrowed funds (debt AFUDC) and equity funds (equity AFUDC). AFUDC is calculated under guidelines prescribed by FERC, and represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of FERC regulated assets. Although equity 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. Interest and AFUDC are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. Capitalized interest and the borrowed funds component of AFUDC are recognized as an offset to Interest expense and the equity funds component of AFUDC is recognized in Other, net on the Condensed Consolidated Statements of Income. The Partnership capitalized interest and combined debt and equity AFUDC of $3 million and $1 million during the three months ended September 30, 2021 and 2020, respectively, and $10 million and $2 million during the nine months ended September 30, 2021 and 2020, respectively.

(2) New Accounting Pronouncements

Reference Rate Reform

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

In January 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This standard clarifies that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition. ASU 2021-01 also amends the expedients and exceptions in ASC 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. ASU 2021-01 was effective upon issuance and generally can be applied through December 31, 2022. The Partnership adopted ASU 2021-01 during the first quarter of 2021. The implementation had no material impact on the Condensed Consolidated Financial Statements and related disclosures.

(3) Revenues

The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the three and nine months ended September 30, 2021 and 2020.


	Three Months Ended September 30, 2021
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 128	$ 158	$ (154)	$ 132
Natural gas liquids	485	5	(5)	485
Condensate	34	—	—	34
Total revenues from natural gas, natural gas liquids, and condensate	647	163	(159)	651
Loss on derivative activity	(22)	(6)	—	(28)
Total Product sales	$ 625	$ 157	$ (159)	$ 623
Service revenues:
Demand revenues	$ 30	$ 110	$ —	$ 140
Volume-dependent revenues	184	12	(3)	193
Total Service revenues	$ 214	$ 122	$ (3)	$ 333
Total Revenues	$ 839	$ 279	$ (162)	$ 956


	Three Months Ended September 30, 2020
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 58	$ 77	$ (68)	$ 67
Natural gas liquids	208	2	(2)	208
Condensate	15	—	—	15
Total revenues from natural gas, natural gas liquids, and condensate	281	79	(70)	290
Loss on derivative activity	(10)	—	—	(10)
Total Product sales	$ 271	$ 79	$ (70)	$ 280
Service revenues:
Demand revenues	$ 32	$ 116	$ —	$ 148
Volume-dependent revenues	160	10	(2)	168
Total Service revenues	$ 192	$ 126	$ (2)	$ 316
Total Revenues	$ 463	$ 205	$ (72)	$ 596


	Nine Months Ended September 30, 2021
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 331	$ 621	$ (415)	$ 537
Natural gas liquids	1,143	13	(13)	1,143
Condensate	101	—	—	101
Total revenues from natural gas, natural gas liquids, and condensate	1,575	634	(428)	1,781
Loss on derivative activity	(61)	(10)	—	(71)
Total Product sales	$ 1,514	$ 624	$ (428)	$ 1,710
Service revenues:
Demand revenues	$ 87	$ 344	$ —	$ 431
Volume-dependent revenues	535	46	(9)	572
Total Service revenues	$ 622	$ 390	$ (9)	$ 1,003
Total Revenues	$ 2,136	$ 1,014	$ (437)	$ 2,713


	Nine Months Ended September 30, 2020
	Gathering and Processing	Transportation and Storage	Eliminations	Total

	(In millions)
Revenues:
Product sales:
Natural gas	$ 161	$ 207	$ (181)	$ 187
Natural gas liquids	523	7	(7)	523
Condensate	49	—	—	49
Total revenues from natural gas, natural gas liquids, and condensate	733	214	(188)	759
Gain (loss) on derivative activity	6	(1)	—	5
Total Product sales	$ 739	$ 213	$ (188)	$ 764
Service revenues:
Demand revenues	$ 105	$ 371	$ —	$ 476
Volume-dependent revenues	487	38	(6)	519
Total Service revenues	$ 592	$ 409	$ (6)	$ 995
Total Revenues	$ 1,331	$ 622	$ (194)	$ 1,759

MRT Rate Case Settlements

In June 2018, MRT filed a general NGA rate case (the 2018 Rate Case), and in October 2019, MRT filed a second rate case (the 2019 Rate Case). MRT began collecting the rates proposed in the 2018 Rate Case, subject to refund, on January 1, 2019. On March 26, 2020, FERC issued an order approving settlements filed in the 2018 Rate Case and the 2019 Rate Case. Upon issuance of the order and approval of the settlement of the MRT rate cases, the Partnership recognized $17 million of revenues from

amounts previously held in reserve related to transportation and storage services performed in 2019. In May 2020, $21 million previously held in reserve was refunded to customers, which was inclusive of interest.

Accounts Receivable

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


	September 30, 2021	December 31, 2020

	(In millions)
Accounts Receivable:
Customers	$ 385	$ 245
Contract assets (1)	3	12
Non-customers	5	6
Total Accounts Receivable (2)	$ 393	$ 263

____________________

(1)

Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets are primarily attributable to revenues associated with estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include contract assets related to firm service transportation contracts with tiered rates of $11 million as of September 30, 2021 and $9 million as of December 31, 2020, which are reflected in Other Assets.

(2)

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

Contract Liabilities

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

The table below summarizes the change in the contract liabilities.


	September 30, 2021	December 31, 2020

	(In millions)
Deferred revenues, beginning of period (1)	$ 44	$ 48
Amounts recognized in revenues related to the beginning balance	(21)	(25)
Net additions	20	21
Deferred revenues, end of period (1)	$ 43	$ 44

____________________

(1)

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

The table below summarizes the timing of recognition of these contract liabilities as of September 30, 2021.


	2021	2022	2023	2024	2025 and After
	(In millions)
Deferred revenues (1)	$ 17	$ 8	$ 8	$ 7	$ 3

____________________

(1)

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

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 Condensed Consolidated Statements of Income.

The table below summarizes the timing of recognition of the remaining performance obligations as of September 30, 2021.


	2021	2022	2023	2024	2025 and After
	(In millions)
Transportation and Storage	$ 114	$ 422	$ 364	$ 270	$ 1,143
Gathering and Processing	30	122	121	101	213
Total remaining performance obligations	$ 144	$ 544	$ 485	$ 371	$ 1,356

(4) Leases

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


	Balance Sheet Location	September 30, 2021	December 31, 2020

		(In millions)
Operating lease asset	Other Assets	$ 23	$ 25
Total right-of-use assets		$ 23	$ 25

Operating lease liabilities	Other Current Liabilities	$ 4	$ 4
Operating lease liabilities	Other Liabilities	22	24
Total lease liabilities		$ 26	$ 28

As of September 30, 2021, all lease obligations outstanding were classified as operating leases. Therefore, all cash flows are reflected in Cash Flows from Operating Activities.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Rental Costs:
Field equipment	$ 2	$ 3	$ 7	$ 12
Office space	2	1	5	3

As of September 30, 2021, the weighted average remaining lease term is 6.1 years and the weighted average discount rate is 5.54%.

The following table presents the Partnership’s lease cost.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Lease Cost:
Operating lease cost	$ 1	$ 2	$ 4	$ 5
Short-term lease cost	2	2	6	9
Variable lease cost	1	—	2	1
Total Lease Cost	$ 4	$ 4	$ 12	$ 15

All lease costs were included in the gathering and processing reportable segment during the three and nine months ended September 30, 2021 and 2020.

Under ASC 842, as of September 30, 2021, the Partnership has operating lease obligations expiring at various dates. Undiscounted cash flows for operating lease liabilities are as follows:


	Non-cancellable operating leases

	(In millions)
Year Ending December 31,
2021 - remainder	$ 1
2022	6
2023	6
2024	4
2025	3
2026	2
After 2026	6
Total	28
Less: impact of the applicable discount rate	2
Total lease liabilities	$ 26

(5) Earnings Per Limited Partner Unit

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions, except per unit data)
Net income (loss)	$ 116	$ (163)	$ 369	$ (14)
Net income (loss) attributable to noncontrolling interest	—	1	2	(6)
Series A Preferred Unit distributions	9	9	26	27
Net income (loss) available to common units	$ 107	$ (173)	$ 341	$ (35)

Net income (loss) allocable to common units	$ 107	$ (173)	$ 341	$ (35)
Dilutive effect of Series A Preferred Unit distributions	8	—	26	—
Diluted net income (loss) allocable to common units	$ 115	$ (173)	$ 367	$ (35)

Basic weighted average number of common units outstanding (1)	438	437	438	437
Dilutive effect of Series A Preferred Units (2)	46	—	46	—
Dilutive effect of performance units (3)	1	—	1	—
Diluted weighted average number of common units outstanding	485	437	485	437

Basic and diluted earnings (losses) per unit
Basic	$ 0.24	$ (0.40)	$ 0.78	$ (0.08)
Diluted	$ 0.24	$ (0.40)	$ 0.76	$ (0.08)

____________________

(1)

Basic weighted average number of outstanding common units includes approximately two million time-based phantom units for each of the three months ended September 30, 2021 and 2020, respectively, and two million time-based phantom units for each of the nine months ended September 30, 2021 and 2020, respectively.

(2)

For the three and nine months ended September 30, 2020, the issuance of “if converted” common units attributable to the Series A Preferred Units were excluded in the calculation of diluted earnings (loss) per unit as the impact was anti-dilutive.

(3)

The contingent effect of the performance unit awards was anti-dilutive for the three and nine months ended September 30, 2020.

(6) Partners’ Equity

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

The Partnership paid or has authorized payment of the following cash distributions to common unitholders, as applicable, during 2021 and 2020 (in millions, except for per unit amounts):


Three Months Ended	Record Date	Payment Date	Per Unit Distribution	Total Cash Distribution
September 30, 2021 (1)	November 8, 2021	November 17, 2021	$ 0.16525	$ 72
June 30, 2021	August 12, 2021	August 24, 2021	$ 0.16525	$ 72
March 31, 2021	May 13, 2021	May 25, 2021	$ 0.16525	$ 72
December 31, 2020	February 22, 2021	March 1, 2021	$ 0.16525	$ 72
September 30, 2020	November 17, 2020	November 24, 2020	$ 0.16525	$ 72
June 30, 2020	August 18, 2020	August 25, 2020	$ 0.16525	$ 72
March 31, 2020	May 19, 2020	May 27, 2020	$ 0.16525	$ 72

_____________________

(1)

The Board of Directors declared a $0.16525 per common unit cash distribution on October 26, 2021, to be paid on November 17, 2021 to common unitholders of record at the close of business on November 8, 2021.

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, February 18, 2016, to, but not including, the five-year anniversary of the original issue date, February 18, 2021. Thereafter, the holders receive a quarterly cash distribution based on a percentage of the stated liquidation preference equal to the sum of the three-month LIBOR plus 8.5%, which is included for each relevant period in the table below.

The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during 2021 and 2020 (in millions, except for per unit amounts):


Three Months Ended	Record Date	Payment Date	Distribution Rate	Per Unit Distribution	Total Cash Distribution
September 30, 2021 (1)	October 26, 2021	November 12, 2021	8.6449 %	$ 0.5403	$ 8
June 30, 2021	July 30, 2021	August 13, 2021	8.7016 %	$ 0.5439	$ 8
March 31, 2021 (2)	April 26, 2021	May 14, 2021	8.7375 %	$ 0.5873	$ 9
December 31, 2020	February 12, 2021	February 12, 2021	10.0 %	$ 0.625	$ 9
September 30, 2020	November 3, 2020	November 13, 2020	10.0 %	$ 0.625	$ 9
June 30, 2020	August 4, 2020	August 14, 2020	10.0 %	$ 0.625	$ 9
March 31, 2020	May 5, 2020	May 15, 2020	10.0 %	$ 0.625	$ 9

_____________________

(1)

The Board of Directors declared a $0.5403 per Series A Preferred Unit cash distribution on October 26, 2021, to be paid on November 12, 2021, to Series A Preferred unitholders of record at the close of business on October 26, 2021.

(2)

The distribution rate for the three months ended March 31, 2021 reflects 10% through February 18, 2021, and the sum of the three-month LIBOR plus 8.5% for the remaining days in the period.

(7) Impairments of Property, Plant and Equipment and Goodwill

Impairment of Property, Plant and Equipment

The Partnership periodically evaluates property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. Due to decreases in natural gas and NGL market prices during 2020 as a result of the ongoing COVID-19 pandemic and its economic effects, together with the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia, as of March 31, 2020, management reassessed the carrying value of the Atoka assets, in which the Partnership owns a 50% interest in the consolidated joint venture, which is a component of the gathering and processing segment. Based on forecasted future undiscounted cash flows, management determined that the carrying value of the Atoka assets were not fully recoverable. The Partnership utilized the income approach (generally accepted valuation approach) to estimate the fair value of these assets. The primary inputs were forecasted cash flows and the discount rate. The fair value measurement is based on inputs that are not observable in the market and thus represent Level 3 inputs. Applying a discounted cash flow model to the property, plant and equipment, the Partnership recognized a $16 million impairment, which is included in Impairments of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income during the nine months ended September 30, 2020.

Impairment of Goodwill

The Partnership tests its goodwill for impairment annually on October 1st, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. During 2020, the commodity price declines due to the existing oversupply of crude oil, NGLs and natural gas were exacerbated by the ongoing COVID-19 pandemic and its economic effects, in addition to the dispute over crude oil production levels between Russia and members of OPEC led by Saudi Arabia in the first quarter. Despite the subsequent agreement in April 2020 by a coalition of nations including Russia and Saudi Arabia to reduce production of crude oil, the price of NGLs and crude oil had remained significantly lower than pre-pandemic levels. Amid such crude oil, NGL and natural gas price declines, producers had been cutting back spending and shifting their focus from emphasizing reserves growth, to increasing net cash flows and reducing outstanding debt, which consequently resulted in a decrease in rig count and in forecasted producer activity in the Ark-La-Tex Basin reporting unit during the first quarter of 2020. At the same time, unit prices and market multiples for midstream companies with gathering and processing operations had dropped to their lowest levels in the last three years. Due to the continuing decrease in forward commodity prices, the reduction in forecasted producer activities, the resulting decrease in our forecasted cash flows and the increase in the weighted average cost of capital, the Partnership determined that the fair value of the goodwill associated with our Ark-La-Tex Basin reporting unit would more likely than not be impaired. As a result, the Partnership performed a quantitative test for our goodwill and determined that the carrying value of the Ark-La-Tex Basin reporting unit exceeded its fair value and that goodwill associated with the Ark-La-Tex Basin was completely impaired in the amount of $12 million. The impairment is included in Impairments of property, plant and equipment and goodwill on the Condensed Consolidated Statements of Income for the nine months ended September 30, 2020. The Partnership had no goodwill recorded as of September 30, 2021 and December 31, 2020.

(8) 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. 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 interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge, Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.

At September 30, 2020, the Partnership estimated the fair value of its investment in SESH was below the carrying value and concluded the decline in value was other than temporary due to the expiration of a transportation contract and the current status of renewal negotiations. As a result, the Partnership recorded a $225 million impairment on its investment in SESH for the three and nine months ended September 30, 2020, which is included in Equity in earnings (losses) of equity method affiliate, net in the Partnership’s Condensed Consolidated Statements of Income. The impairment analysis of the Partnership’s investment in SESH compared the estimated fair value of the investment to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches. Due to the significant unobservable estimates and assumptions required, the Partnership concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. The basis difference for our investment in SESH has been assigned to its property, plant and equipment and will be amortized over its approximately 50-year remaining useful life. See Note 1 for further information concerning the method used to evaluate and measure the impairment on the Partnership’s investment in SESH.

The Partnership shares operations of SESH with Enbridge, Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. The Partnership billed SESH $2 million and $3 million during the three months ended September 30, 2021 and 2020, respectively, and $7 million and $11 million during the nine months ended September 30, 2021 and 2020, respectively, associated with these service agreements.

The Partnership includes equity in earnings (losses) of equity method affiliate, net under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income. The following table presents the amount of Equity in earnings of equity method affiliate recognized, Impairment of equity method affiliate investment and Distributions from equity method affiliate received.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Equity in earnings of equity method affiliate	$ 4	$ 3	$ 5	$ 14
Impairment of equity method affiliate investment	—	(225)	—	(225)
Equity in earnings (losses) of equity method affiliate, net	$ 4	$ (222)	$ 5	$ (211)
Distributions from equity method affiliate (1)	1	4	5	23

___________________

(1)

Distributions from equity method affiliate includes a $5 million and $14 million return on investment and a zero and $9 million return of investment for the nine months ended September 30, 2021 and 2020, respectively.

The following table includes the summarized financial information of SESH.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Income Statements:
Revenues	$ 20	$ 24	$ 51	$ 79
Operating income	8	11	14	40
Net income	3	6	1	27

(9) Debt

The following table presents the Partnership’s outstanding debt.


	September 30, 2021			December 31, 2020
	Outstanding Principal	Discount (1)	Total Debt	Outstanding Principal	Discount (1)	Total Debt

	(In millions)
Commercial Paper	$ 50	$ —	$ 50	$ 250	$ —	$ 250
Revolving Credit Facility	—	—	—	—	—	—
2019 Term Loan Agreement	800	—	800	800	—	800
2024 Notes	600	—	600	600	—	600
2027 Notes	700	(1)	699	700	(2)	698
2028 Notes	800	(4)	796	800	(5)	795
2029 Notes	547	(1)	546	547	(1)	546
2044 Notes	531	—	531	531	—	531
Total debt	$ 4,028	$ (6)	$ 4,022	$ 4,228	$ (8)	$ 4,220
Less: Short-term debt (2)			50			250
Less: Current portion of long-term debt (3)			800			—
Less: Unamortized debt expense (4)			18			19
Total long-term debt			$ 3,154			$ 3,951

____________________

(1)

Unamortized discount on long-term debt is amortized over the life of the respective debt.

(2)

Short-term debt includes $50 million and $250 million of outstanding commercial paper as of September 30, 2021 and December 31, 2020, respectively.

(3)

As of September 30, 2021, Current portion of long-term debt included $800 million outstanding balance of the 2019 Term Loan Agreement.

(4)

As of September 30, 2021 and December 31, 2020, there was an additional $2 million and $3 million, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.

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 $50 million and $250 million outstanding under our commercial paper program at September 30, 2021 and December 31, 2020, respectively. As of September 30, 2021, the weighted average interest rate for the outstanding commercial paper was 0.40%.

Revolving Credit Facility

The Partnership’s Revolving Credit Facility is a $1.75 billion, five-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional $875 million. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised two times to extend the term of the Revolving Credit Facility, in each case, for an additional one-year term. As of September 30, 2021, there were no principal advances, $3 million letters of credit outstanding and our available borrowing capacity was approximately $1.5 billion under our Revolving Credit Facility.

The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated credit ratings from S&P, Moody’s and Fitch Ratings. As of September 30, 2021, 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 credit ratings. As of September 30, 2021, the commitment fee under the restated 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 Condensed Consolidated Statements of Income.

2019 Term Loan Agreement

On January 29, 2019, the Partnership entered into an unsecured term loan agreement with Bank of America, N.A., as administrative agent, and the several lenders thereto. As of September 30, 2021, there was $800 million outstanding under the 2019 Term Loan Agreement. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s credit ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between 0.75% and 1.50% per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between 0% and 0.50% per annum. As of September 30, 2021, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was 1.25% based on the Partnership’s credit ratings. As of September 30, 2021, the weighted average interest rate of the 2019 Term Loan Agreement was 2.06%, including the impact of the associated interest rate derivatives designated as hedging instruments for accounting purposes.

Senior Notes

As of September 30, 2021, the Partnership’s debt included the 2024 Notes, 2027 Notes, 2028 Notes, 2029 Notes and 2044 Notes, which had $6 million of unamortized discount and $18 million of unamortized debt expense at September 30, 2021, resulting in effective interest rates of 4.00%, 4.56%, 5.18%, 4.30% and 5.08%, respectively, during the nine months ended September 30, 2021. In March 2020, the Partnership’s EOIT Senior Notes matured and were paid using proceeds from the Revolving Credit Facility.

During the nine months ended September 30, 2020, the Partnership repurchased $22 million aggregate principal amount of the 2029 Notes and 2044 Notes in open market transactions for approximately $17 million plus accrued interest, which resulted in a $5 million gain on extinguishment of debt. The gain is included in Other, net in the Condensed Consolidated Statements of Income.

As of September 30, 2021, the Partnership was in compliance with all of its debt agreements, including financial covenants.

(10) Derivative Instruments and Hedging Activities

The primary risks managed using derivative instruments are commodity price and interest rate risks.

Derivatives Not Designated as Hedging Instruments

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

Quantitative Disclosures Related to Derivative Instruments Not Designated as Hedging Instruments

The following table presents the Partnership’s derivative instruments that were not designated as hedging instruments for accounting purposes.


	September 30, 2021		December 31, 2020
	Gross Notional Volume
	Purchases	Sales	Purchases	Sales
Natural gas— TBtu (1)
Financial fixed futures/swaps	—	4	—	18
Financial basis futures/swaps	1	11	—	27
Financial swaptions (2)	—	2	—	7
Crude oil (for condensate)— MBbl (3)
Financial futures/swaps	—	180	—	465
Financial swaptions (2)	—	60	—	90
Natural gas liquids— MBbl (4)
Financial futures/swaps	30	300	855	1,210
Financial options	—	—	—	45

____________________

(1)

As of September 30, 2021, 97.6% of the natural gas contracts had durations of one year or less and 2.4% had durations of more than one year and less than two years. As of December 31, 2020, 95.7% of the natural gas contracts had durations of one year or less and 4.3% had durations of more than one year and less than two years.

(2)

The notional volume 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 volume hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.

(3)

As of September 30, 2021, 93.7% of the crude oil (for condensate) contracts had durations of one year or less and 6.3% had durations of more than one year and less than two years. As of December 31, 2020, 100.0% of the crude oil (for condensate) contracts had durations of one year or less.

(4)

As of September 30, 2021, 95.5% of the natural gas liquids contracts had durations of one year or less and 4.5% had durations of more than one year and less than two years. As of December 31, 2020, 100.0% of the natural gas liquids contracts had durations of one year or less.

Derivatives Designated as Hedging Instruments

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

Quantitative Disclosures Related to Derivative Instruments Designated as Hedging Instruments

The following table presents the Partnership’s derivative instruments that were designated as hedging instruments for accounting purposes.


	September 30, 2021	December 31, 2020
	Gross Notional Value
	(In millions)
Interest rate swaps	$ 300	$ 300

Balance Sheet Presentation Related to Derivative Instruments

The following table presents the fair value of the derivative instruments that are included in the Partnership’s Condensed Consolidated Balance Sheets that were not designated as hedging instruments for accounting purposes.


		September 30, 2021		December 31, 2020
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Natural gas
Financial futures/swaps	Other Current	$ —	$ 13	$ 2	$ 2
Financial swaptions	Other Current	—	12	1	2
Crude oil (for condensate)
Financial futures/swaps	Other Current	—	5	1	13
Financial swaptions	Other Current	—	2	—	—
Financial swaptions	Other	—	—	—	—
Natural gas liquids
Financial futures/swaps	Other Current	3	9	15	3
Financial swaptions	Other Current	—	—	—	1
Total gross commodity derivatives (1)		$ 3	$ 41	$ 19	$ 21

_____________________

(1)

See Note 11 for a reconciliation of the Partnership’s commodity derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020.

The following table presents the fair value of the derivative instruments that are included in the Partnership’s Condensed Consolidated Balance Sheets that were designated as hedging instruments for accounting purposes.


		September 30, 2021		December 31, 2020
		Fair Value
Instrument	Balance Sheet Location	Assets	Liabilities	Assets	Liabilities

		(In millions)
Interest rate swaps (1)	Other Current	$ —	$ 2	$ —	$ 6

_____________________

(1)

All interest rate derivative instruments that were designated as cash flow hedges are considered Level 2 as of September 30, 2021 and December 31, 2020.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income.


	Amounts Recognized in Income
	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Natural gas
Financial futures/swaps losses	$ (16)	$ (5)	$ (29)	$ (2)
Financial swaptions losses	(6)	(4)	(11)	(6)
Physical purchases/sales losses	—	(1)	—	—
Crude oil (for condensate)
Financial futures/swaps gains (losses)	(1)	—	(13)	12
Financial swaptions gains (losses)	—	—	(2)	2
Natural gas liquids
Financial futures/swaps losses	(5)	—	(16)	(1)
Total	$ (28)	$ (10)	$ (71)	$ 5

For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended September 30, 2021 and 2020, if any, are reported in Product sales.

The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Change in fair value of commodity derivatives	$ (7)	$ (15)	$ (36)	$ (17)
Realized gains (losses) on commodity derivatives	(21)	5	(35)	22
Gains (losses) on commodity derivative activity	$ (28)	$ (10)	$ (71)	$ 5

The following table presents the effect of derivative instruments that were designated as hedging instruments on the Partnership’s Condensed Consolidated Statements of Income.


	Amounts Recognized in Income
	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Interest rate swaps losses	$ (1)	$ (2)	$ (4)	$ (3)

Interest rate derivatives designated as hedges are recognized in income once settled. Settlement amounts recognized in income for the periods ended September 30, 2021 and 2020 are reported in Interest expense.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s or S&P were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of 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 September 30, 2021, under these obligations, the Partnership had posted $10 million of cash collateral related to natural gas swaps and swaptions, crude oil swaps and swaptions and NGL swaps and $6 million of additional collateral would be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating. In certain situations where the Partnership’s credit rating is lowered by Moody’s or S&P, the Partnership could be subject to an early termination event related to certain derivative instruments, which could result in a cash settlement of the instruments at market values on the date of such early termination.

(11) Fair Value Measurements

Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. 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 three and nine months ended September 30, 2021, there were no transfers between levels. As of September 30, 2021, there were no contracts classified as Level 3.

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 Condensed 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.


	September 30, 2021		December 31, 2020
	Carrying Amount	Fair Value	Carrying Amount	Fair Value

	(In millions)
Debt
Revolving Credit Facility (Level 2) (1)	$ —	$ —	$ —	$ —
2019 Term Loan Agreement (Level 2)	800	800	800	800
2024 Notes (Level 2)	600	637	600	612
2027 Notes (Level 2)	699	776	698	709
2028 Notes (Level 2)	796	900	795	817
2029 Notes (Level 2)	546	593	546	544
2044 Notes (Level 2)	531	581	531	499

____________________

(1) Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program. $50 million and $250 million of commercial paper was outstanding as of September 30, 2021 and December 31, 2020, respectively.

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

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

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of September 30, 2021, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.

Based upon review of forecasted undiscounted cash flows as of September 30, 2021, all of the asset groups were considered recoverable. Based upon review for other than temporary declines in fair value, the investment in equity method affiliate was considered recoverable. Future price declines, throughput declines, contracted capacity declines, cost increases, regulatory or political environment changes and other changes in market conditions, including the supply of and demand for crude oil, NGLs and natural gas as well as the ongoing COVID-19 pandemic and its economic effects, could reduce forecasted undiscounted cash flows for the asset groups and result in other than temporary declines in the fair value of the investment in equity method affiliate.

Contracts with Master Netting Arrangements

As of September 30, 2021, the Partnership’s Level 2 interest rate derivatives are recorded as liabilities with no netting adjustments.

The following tables summarize the Partnership’s other assets and liabilities that are measured at fair value on a recurring basis.


September 30, 2021	Commodity Contracts		Gas Imbalances (1)
	Assets	Liabilities	Assets (2)	Liabilities (3)

	(In millions)
Quoted market prices in active market for identical assets (Level 1)	$ —	$ 11	$ —	$ —
Significant other observable inputs (Level 2)	3	30	23	26
Total fair value	3	41	23	26
Netting adjustments	(3)	(3)	—	—
Total	$ —	$ 38	$ 23	$ 26


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

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

______________________

(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 September 30, 2021 and December 31, 2020.

(2)

Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $3 million and $19 million at September 30, 2021 and December 31, 2020, 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 $2 million and $3 million at September 30, 2021 and December 31, 2020, 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.

(12) Supplemental Disclosure of Cash Flow Information

The following table provides information regarding supplemental cash flow information:


	Nine Months Ended September 30,
	2021	2020

	(In millions)
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest and debt AFUDC	$ 112	$ 129
Income taxes, net of refunds	(1)	1
Non-cash transactions:
Accounts payable related to capital expenditures	13	9
Lease liabilities related to derecognition of right-of-use assets	(1)	(5)
Impact of adoption of financial instruments-credit losses accounting standard (Note 1)	—	(3)

(13) Related Party Transactions

The Partnership’s revenues from affiliated companies accounted for 5% and 6% of total revenues during the nine months ended September 30, 2021 and 2020, respectively. The following table presents the amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Gas transportation and storage service revenues — CenterPoint Energy	$ 15	$ 17	$ 58	$ 76
Natural gas product sales — CenterPoint Energy	—	—	5	1
Gas transportation and storage service revenues — OGE Energy	10	9	29	28
Natural gas product sales — OGE Energy	1	4	34	9
Total revenues — affiliated companies	$ 26	$ 30	$ 126	$ 114

The following table presents the amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Cost of natural gas purchases — CenterPoint Energy	$ —	$ —	$ —	$ 1
Cost of natural gas purchases — OGE Energy	13	6	56	20
Total cost of natural gas purchases — affiliated companies	$ 13	$ 6	$ 56	$ 21

Corporate services and seconded employees

The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least 90 days’ notice prior to the end of any extension. Additionally, the Partnership may terminate the services agreements at any time with 180 days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2021 are both less than $1 million.

As of September 30, 2021, 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 an annual cap of $5 million until secondment is terminated.

The following table presents the amounts charged to the Partnership by affiliates for seconded employees, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Seconded Employee Costs — OGE Energy	$ 4	$ 5	$ 11	$ 13

(14) Commitments and Contingencies

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

On January 1, 2017, the Partnership entered into a 10-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer for deliveries to the Godley Plant in Johnson County, Texas. As of September 30, 2021, the Partnership estimates the remaining associated minimum volume commitment fee to be $153 million. Minimum volume commitment fees are expected to be $4 million for the remainder of 2021, $23 million per year from 2022 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 liquefied natural gas facility to be served by the Gulf Run Pipeline project. Subject to approval of the project by FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership requested approval to transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. The Partnership filed applications with FERC to obtain authorization to construct and operate the pipeline on February 28, 2020. FERC issued the environmental assessment on October 29, 2020. On June 1, 2021, FERC issued the Order Issuing Certificates and Approving Abandonment, which authorizes construction and operation of the Gulf Run Pipeline and transfer of certain existing EGT infrastructure to the Gulf Run Pipeline. On October 19, 2021, FERC issued the Notice to Proceed with Construction. The Partnership estimates the total cost of the Gulf Run Pipeline project would be as much as $540 million, excluding AFUDC. The project is backed by a 20-year firm transportation service agreement. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in late 2022.

(15) Equity-Based Compensation

The following table summarizes the Partnership’s equity-based compensation expense related to performance units and phantom units for the Partnership’s employees and independent directors.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2021	2020	2021	2020

	(In millions)
Performance units	$ 3	$ 1	$ 7	$ 5
Phantom units	1	2	5	5
Total compensation expense	$ 4	$ 3	$ 12	$ 10

The following table presents the assumptions related to the performance units granted in 2021.


	2021
Number of units granted	1,453,897
Fair value of units granted	$ 10.26
Expected distribution yield	12.90 %
Expected price volatility	100.00 %
Risk-free interest rate	0.27 %
Expected life of units (in years)	3

The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2021.


	2021
Phantom Units granted	1,371,001
Fair value of phantom units granted	$5.41 - $6.87

Units Outstanding

A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at September 30, 2021 and changes during 2021 are shown in the following table.


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

	(In millions, except unit data)
Units outstanding at December 31, 2020	1,765,508	$ 13.10	1,790,845	$ 10.29
Granted (1)	1,453,897	10.26	1,371,001	6.86
Vested (2)	(398,614)	17.70	(485,662)	13.08
Forfeited	(45,945)	9.94	(139,975)	8.52
Units outstanding at September 30, 2021	2,774,846	$ 11.00	2,536,209	$ 7.99
Aggregate intrinsic value of units outstanding at September 30, 2021	$ 23		$ 21

_____________________

(1)

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

(2)

Performance units vested as of September 30, 2021 include 398,614 units from the 2018 annual grant, which were approved by the Board of Directors in 2018 and, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2018 through December 31, 2020, no performance units vested.

Unrecognized Compensation Cost

The following table summarizes the Partnership’s unrecognized compensation cost for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized.


	September 30, 2021
	Unrecognized Compensation Cost (In millions)	Weighted Average Period for Recognition (In years)
Performance Units	$ 16	1.76
Phantom Units	10	1.61
Total	$ 26

As of September 30, 2021, there were 3,151,858 units available for issuance under the long-term incentive plan.

(16) 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 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 excerpt in the Partnership’s audited 2020 Notes to Consolidated Financial Statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.

The Partnership’s assets and operations are organized into two reportable segments: (i) gathering and processing and (ii) transportation and storage. Our gathering and processing segment primarily provides natural gas gathering and processing services to our producer customers and crude oil, condensate and produced water gathering services to our producer and refiner customers. 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:


Three Months Ended September 30, 2021	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 625	$ 157	$ (159)	$ 623
Service revenues	214	122	(3)	333
Total Revenues	839	279	(162)	956
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	571	154	(160)	565
Operation and maintenance, General and administrative	77	43	(1)	119
Depreciation and amortization	74	30	—	104
Taxes other than income tax	10	6	—	16
Operating income	$ 107	$ 46	$ (1)	$ 152
Total Assets	$ 10,953	$ 6,130	$ (5,303)	$ 11,780
Capital expenditures (excluding equity AFUDC)	$ 27	$ 26	$ —	$ 53


Three Months Ended September 30, 2020	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 271	$ 79	$ (70)	$ 280
Service revenues	192	126	(2)	316
Total Revenues	463	205	(72)	596
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	244	78	(72)	250
Operation and maintenance, General and administrative	77	47	—	124
Depreciation and amortization	75	30	—	105
Taxes other than income tax	10	7	—	17
Operating income	$ 57	$ 43	$ —	$ 100
Total assets as of December 31, 2020	$ 10,830	$ 5,729	$ (4,830)	$ 11,729
Capital expenditures (excluding equity AFUDC)	$ 21	$ 29	$ —	$ 50


Nine Months Ended September 30, 2021	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 1,514	$ 624	$ (428)	$ 1,710
Service revenues	622	390	(9)	1,003
Total Revenues	2,136	1,014	(437)	2,713
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	1,406	539	(435)	1,510
Operation and maintenance, General and administrative	229	129	(2)	356
Depreciation and amortization	222	91	—	313
Taxes other than income tax	32	20	—	52
Operating income	$ 247	$ 235	$ —	$ 482
Total Assets	$ 10,953	$ 6,130	$ (5,303)	$ 11,780
Capital expenditures (excluding equity AFUDC)	$ 68	$ 136	$ —	$ 204


Nine Months Ended September 30, 2020	Gathering and Processing	Transportation (1) and Storage	Eliminations	Total

	(In millions)
Product sales	$ 739	$ 213	$ (188)	$ 764
Service revenues	592	409	(6)	995
Total Revenues	1,331	622	(194)	1,759
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)	631	215	(193)	653
Operation and maintenance, General and administrative	250	137	(1)	386
Depreciation and amortization	223	91	—	314
Impairments of property, plant and equipment and goodwill	28	—	—	28
Taxes other than income tax	32	20	—	52
Operating income	$ 167	$ 159	$ —	$ 326
Total assets as of December 31, 2020	$ 10,830	$ 5,729	$ (4,830)	$ 11,729
Capital expenditures (excluding equity AFUDC)	$ 79	$ 73	$ —	$ 152

_____________________

(1)

See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the three and nine months ended September 30, 2021 and 2020.