View Filing Data

$ 1,364

$ 1,067

1,107

1,054

^[1]

(33)

(8)

Natural Gas Distribution [Member]

2,400

2,093

1,143

907

Energy Services [Member]

Other Operations [Member]

1,257

1,185

Reportable Subsegments [Member] | Natural Gas Distribution [Member]

^[2]

1,186

925

^[2]

^[1],[2]

(33)

(9)

Reportable Subsegments [Member] | Energy Services [Member]

^[2]

1,143

907

^[3]

178

142

^[3]

1,107

1,054

^[1],[3]

Reportable Subsegments [Member] | Other Operations [Member]

^[3]

1,257

1,185

^[3]

^[3]

^[1],[3]

Intersegment Eliminations [Member]

^[3]

Intersegment Eliminations [Member] | Natural Gas Distribution [Member]

(38)

(20)

Intersegment Eliminations [Member] | Energy Services [Member]

(10)

(9)

Intersegment Eliminations [Member] | Other Operations [Member]

(28)

(11)

Intersegment Eliminations [Member] | Reportable Subsegments [Member]

^[2]

(10)

(9)

^[3]

(28)

(11)

Defined Benefit Plan Disclosure [Line Items]

$ (38)

$ (20)

[1]	Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. CERC recognizes ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.
[2]	Reflected in Utility revenues in the Condensed Statements of Consolidated Income.
[3]	Reflected in Non-utility revenues in the Condensed Statements of Consolidated Income.

Employee Benefit Plans (Details) - Other Postretirement Benefit Plans, Defined Benefit [Member] - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Net periodic cost

$ 1

Contribution expected in 2018

Contribution made in period

Other, net [Member]

Defined Benefit Plan Disclosure [Line Items]

Interest cost (1)

^[1]

$ 1

[1]	Included in Other, net in the Condensed Statements of Consolidated Income.

Regulatory Accounting (Details) - USD ($)
$ in Millions

Mar. 31, 2018

Dec. 31, 2017

^[1]

$ 172

$ 181

Total regulatory assets

237

311

Total regulatory liabilities

1,240

1,201

1,256

1,203

Total regulatory assets and liabilities, net

(1,019)

(892)

Hurricane [Member]

Amounts related to TCJA [Member]

^[2]

Pension and Other Postretirement Plans Costs [Member]

^[3]

Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided

Other Regulatory Assets (Liabilities) [Member]

Amounts related to TCJA [Member]

^[4]

150

160

^[3]

499

492

Removal Costs [Member]

Other Regulatory Assets (Liabilities) [Member]

600

593

Prepaid expenses and other current assets [Member]

141

116

Current regulatory assets (1)

^[5]

130

Other current liabilities [Member]

Current regulatory liabilities (6)

^[6]

$ 16

$ 2

[1]	Non-current regulatory assets are included in Other assets in CERC’s Condensed Consolidated Balance Sheets.
[2]	CERC is not earning a return on its Hurricane Harvey restoration costs.
[3]	The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities.
[4]	Includes a portion of NGD’s actuarially determined pension and other postemployment expense in excess of the amount being recovered through rates that is being deferred for rate making purposes. Deferred pension and other postemployment expenses of $6 million and $7 million as of March 31, 2018 and December 31, 2017, respectively, were not earning a return. Other long-term regulatory assets that are not earning a return were not material as of March 31, 2018 and December 31, 2017.
[5]	Current regulatory assets are included in Prepaid expenses and other current assets in CERC’s Condensed Consolidated Balance Sheets.
[6]	Current regulatory liabilities are included in Other current liabilities in CERC’s Condensed Consolidated Balance Sheets.

Derivative Instruments (Details)

3 Months Ended

12 Months Ended

Mar. 31, 2018

USD ($)

Bcf

Mar. 31, 2017

USD ($)

Dec. 31, 2017

USD ($)

Bcf

Mar. 26, 2018

USD ($)

$ 166,000,000

$ 218,000,000

Gross Amounts Offset in the Consolidated Balance Sheets

115,000,000

107,000,000

52,000,000

19,000,000

Gain (loss) on derivative instruments not designated as hedging instruments

(12,000,000)

$ 29,000,000

Total fair value of the derivative instruments that contain credit risk contingency features that are in a net liability position

2,000,000

The aggregate fair value of assets already posted as collateral

Credit risk contingent feature assets

2,000,000

$ 2,000,000

Gains (Losses) in Expense: Natural Gas [Member]

Change in unrealized gain (loss) on hedged item in fair value hedge

(2,000,000)

(4,000,000)

Gain (loss) on fair value hedges recognized in earnings

^[1]

$ (2,000,000)

(1,000,000)

Natural gas derivatives [Member]

Derivative gross volume notional amount (in Bcf) | Bcf

1,735

1,795

Gross Amounts Offset in the Consolidated Balance Sheets

^[2]

$ 51,000,000

$ 111,000,000

52,000,000

19,000,000

Net Amount Presented in the Consolidated Balance Sheets

^[3]

103,000,000

130,000,000

Natural gas derivatives [Member] | Current Assets [Member]

^[2]

105,000,000

165,000,000

Natural gas derivatives [Member] | Other Noncurrent Assets [Member]

(21,000,000)

(55,000,000)

Derivative Asset

^[3]

84,000,000

110,000,000

^[2]

61,000,000

53,000,000

Natural gas derivatives [Member] | Current Liabilities [Member]

(9,000,000)

Derivative Asset

^[3]

52,000,000

44,000,000

^[2]

(73,000,000)

(83,000,000)

Natural gas derivatives [Member] | Other Noncurrent Liabilities [Member]

52,000,000

63,000,000

Derivative Liability

^[3]

(21,000,000)

(20,000,000)

^[2]

(42,000,000)

(24,000,000)

Natural gas derivatives [Member] | Gains (Losses) in Revenue [Member]

30,000,000

20,000,000

Derivative Liability

^[3]

(12,000,000)

(4,000,000)

Gain (loss) on derivative instruments not designated as hedging instruments

57,000,000

96,000,000

Natural gas derivatives [Member] | Gains (Losses) in Expense: Natural Gas [Member]

Change in unrealized gain (loss) on fair value hedging instruments

3,000,000

Gain (loss) on derivative instruments not designated as hedging instruments

(69,000,000)

(67,000,000)

Natural gas derivatives [Member] | Designated as Fair Value Hedge [Member] | Current Liabilities [Member]

^[4]

1,000,000

^[5],[6]

13,000,000

^[7],[8]

Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Current Assets [Member]

^[4]

1,000,000

^[5],[6]

1,000,000

^[7],[8]

^[4]

86,000,000

^[5],[6]

114,000,000

^[7],[8]

Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member]

^[4]

2,000,000

^[5],[6]

4,000,000

^[7],[8]

^[4]

52,000,000

^[5],[6]

44,000,000

^[7],[8]

Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Current Liabilities [Member]

^[4]

^[5],[6]

^[7],[8]

^[4]

18,000,000

^[5],[6]

38,000,000

^[7],[8]

Natural gas derivatives [Member] | Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]

^[4]

70,000,000

^[5],[6]

78,000,000

^[7],[8]

^[4]

9,000,000

^[5],[6]

9,000,000

^[7],[8]

Natural gas derivatives [Member] | Long [Member]

^[4]

$ 42,000,000

^[5],[6]

$ 24,000,000

^[7],[8]

Derivative gross volume notional amount (in Bcf) | Bcf

437

224

Natural Gas Distribution [Member] | Weather Hedge Swaps [Member] | Gains (Losses) in Revenue [Member]

Recognized gain (loss) on weather hedges

^[9]

$ 0

Natural Gas Distribution [Member] | 2017 to 2018 [Member]

Weather hedge bilateral cap amount

^[9]

8,000,000

March [Member] | Treasury Lock [Member]

Aggregate notional amount

450,000,000

Effective portion of realized losses

$ 1,000,000

Senior Notes [Member]

Principal amount of debt issued

$ 600,000,000

[1]	Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.
[2]	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.
[3]	The derivative assets and liabilities on the Condensed Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.
[4]	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.
[5]	Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a $103 million asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $52 million.
[6]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,735 Bcf or a net 437 Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.
[7]	Natural gas contracts are presented on a net basis in the Condensed Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Condensed Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a $130 million asset as shown on CERC’s Condensed Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $19 million.
[8]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,795 Bcf or a net 224 Bcf long position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.
[9]	Weather hedge gains (losses) are recorded in Revenues in the Condensed Statements of Consolidated Income.

Fair Value Measurements (Details)

3 Months Ended

Mar. 31, 2018

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2017

USD ($)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value amount of Level 1 to Level 2 assets transferred

$ 0

Fair value amount of Level 2 to Level 1 assets transferred

Fair value amount of Level 1 to Level 2 liabilities transferred

Fair value amount of Level 2 to Level 1 liabilities transferred

Assets

Total derivative assets, netting adjustment

(30,000,000)

^[1]

$ (64,000,000)

^[2]

Derivative fair value offsets, net

149,000,000

182,000,000

52,000,000

19,000,000

Total derivative liabilities, netting adjustment

(82,000,000)

^[1]

(83,000,000)

^[2]

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]

41,000,000

24,000,000

Beginning balance

46,000,000

$ 13,000,000

Total gains

2,000,000

16,000,000

Total settlements

(34,000,000)

(4,000,000)

Transfers into Level 3

1,000,000

Transfers out of Level 3

(2,000,000)

1,000,000

Ending balance (1)

^[3]

12,000,000

27,000,000

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date

(4,000,000)

$ 15,000,000

Carrying Amount [Member]

Estimated Fair Value of FInancial Instruments

Long-term debt

2,882,000,000

2,457,000,000

Fair Value [Member]

Estimated Fair Value of FInancial Instruments

Long-term debt

3,078,000,000

2,708,000,000

Energy Related Derivative [Member]

Assets

Derivative fair value offsets, net

52,000,000

19,000,000

Fair Value, Inputs, Level 1 [Member]

Assets

13,000,000

28,000,000

Fair Value, Inputs, Level 2 [Member]

8,000,000

Assets

147,000,000

161,000,000

Fair Value, Inputs, Level 3 [Member]

108,000,000

96,000,000

Assets

19,000,000

57,000,000

Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Minimum [Member]

$ 7,000,000

11,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value inputs (price per MMBtu)

1.36

Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member] | Maximum [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value inputs (price per MMBtu)

3.26

Fair Value, Measurements, Recurring [Member]

Assets

$ 3,000,000

3,000,000

^[4]

10,000,000

11,000,000

14,000,000

Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member]

8,000,000

Assets

Derivative asset, netting adjustment

^[5]

(30,000,000)

^[1]

(64,000,000)

^[2]

Derivative assets

^[5]

136,000,000

154,000,000

Derivative liabilities, netting adjustment

^[5]

(82,000,000)

^[1]

(83,000,000)

^[2]

Derivative liabilities

^[5]

33,000,000

24,000,000

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Assets

3,000,000

^[4]

10,000,000

11,000,000

14,000,000

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Energy Related Derivative [Member]

8,000,000

Assets

Derivative asset

^[5]

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

Derivative liability

^[5]

Assets

^[4]

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Energy Related Derivative [Member]

Assets

Derivative asset

^[5]

147,000,000

161,000,000

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

Derivative liability

^[5]

108,000,000

96,000,000

Assets

^[4]

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Energy Related Derivative [Member]

Assets

Derivative asset

^[5]

19,000,000

57,000,000

Percentage sale of units which trigger right of first refusal

Derivative liability

^[5]

$ 7,000,000

$ 11,000,000

[1]	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $52 million posted with the same counterparties.
[2]	Amounts represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $19 million posted with the same counterparties.
[3]	CERC did not have significant Level 3 sales or purchases during either of the three months ended March 31, 2018 or 2017.
[4]	Amounts are included in Other assets in the Condensed Consolidated Balance Sheets.
[5]	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

Unconsolidated Affiliate (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

5.00%

Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]

CERC Corp.’s equity in earnings, net

$ 69

$ 72

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]

CERC Corp.’s equity method investment in Enable

$ 2,467

$ 2,472

Enable Midstream Partners [Member]

Equity method investment limited partner interest in Enable

54.00%

Distributions received from equity method investment

$ 74

Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]

Operating revenues

748

666

Cost of sales, excluding depreciation and amortization

375

308

Operating income

139

140

Net income attributable to Enable

105

111

CERC Corp.’s interest

Basis difference amortization (1)

^[1]

CERC Corp.’s equity in earnings, net

$ 69

Basis difference amortization period

31 years

Equity Method Investment, Summarized Financial Information, Assets and Liabilities [Abstract]

Current assets

$ 413

416

Non-current assets

11,274

11,177

Current liabilities

1,404

1,279

Non-current liabilities

2,664

2,660

Non-controlling interest

Preferred equity

362

Enable partners’ capital

7,246

7,280

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract]

CERC’s ownership interest in Enable partners’ capital

3,913

3,935

CERC Corp.’s basis difference

(1,446)

(1,463)

CERC Corp.’s equity method investment in Enable

$ 2,467

2,472

OGE [Member]

Percentage sale of units which trigger right of first refusal

5.00%

Enable Midstream Partners [Member]

Limited partner interest in Enable

100.00%

Management rights ownership percentage

50.00%

Incentive distribution right

40.00%

Maximum incentive distribution right

50.00%

Enable Midstream Partners [Member] | OGE [Member]

Limited partner interest in Enable

25.60%

Management rights ownership percentage

50.00%

Incentive distribution right

60.00%

Enable Midstream Partners [Member] | Public unitholders [Member]

Limited partner interest in Enable

20.40%

Minimum [Member] | Enable Midstream Partners [Member]

Incentive distribution per unit

$ 0.2875

Maximum [Member] | Enable Midstream Partners [Member]

Incentive distribution per unit

$ 0.330625

Common Stock [Member] | Enable Midstream Partners [Member]

Enable equity method investment units held

233,856,623

Common Stock [Member] | Enable Midstream Partners [Member]

Enable units held

433,072,001

Common Stock [Member] | Enable Midstream Partners [Member] | OGE [Member]

Enable units held

110,982,805

Common Stock [Member] | Enable Midstream Partners [Member] | Public unitholders [Member]

Enable units held

88,232,573

Natural Gas Expenses [Member] | Enable Midstream Partners [Member]

Natural gas expenses, including transportation and storage costs

$ 37

Accounts payable for natural gas purchases from Enable

Transitional Service [Member] | Enable Midstream Partners [Member]

Reimbursement of transition services (1)

^[2]

$ 2

Accounts receivable for amounts billed for transition services

$ 1

[1]	Equity in earnings of unconsolidated affiliate includes CERC Corp.’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC Corp.’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 31 years, the average life of the assets to which the basis difference is attributed.
[2]	Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.

Goodwill and Other Intangibles (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

$ 867

105

(34)

(31)

Amortization expense of intangible assets

$ 3

$ 2

Customer Relationships [Member]

Intangible asset useful lives

15 years

$ 86

(23)

(21)

Noncompete Agreements [Member]

$ 63

Intangible asset useful lives

4 years

$ 4

(2)

Other Intangible Assets [Member]

(9)

(8)

Natural Gas Distribution [Member]

746

Energy Services [Member]

Accumulated goodwill impairment charge recorded in 2012

^[1]

110

252

Other Operations [Member]

CenterPoint Energy [Member] | Operation And Maintenance Expense [Member]

$ 11

[1]	Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

Related Party Transactions (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

Dividend to parent

$ 86

$ 108

Corporate service charges

CenterPoint Houston [Member] | Operation And Maintenance Expense [Member]

Corporate service charges

Billings to Houston Electric for services provided

$ (3)

$ (2)

Investment [Domain]

Weighted average interest rate

2.27%

1.90%

Accounts and notes receivable (payable) - affiliate companies [Member]

Money pool investments (borrowings) (1)

^[1]

$ 0

$ (570)

[1]	Included in Accounts and notes receivable (payable)–affiliated companies in the Condensed Consolidated Balance Sheets.

Short-term Borrowings and Long-term Debt (Details) - USD ($)

3 Months Ended

Mar. 26, 2018

Mar. 31, 2018

Dec. 31, 2017

Size of credit facility

$ 900,000,000

Short-term Debt [Line Items]

Short-term borrowings

$ 0

39,000,000

Line of Credit [Member]

Percentage on limitation of debt to total capitalization under covenant (in hundredths)

65.00%

Ratio of indebtedness to net capital

0.387

Line of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member]

Revolving Credit Facility [Member]

Basis spread on LIBOR

^[1]

1.25%

Letter of Credit [Member]

Long-term line of credit

$ 0

Commercial Paper [Member]

Long-term line of credit

1,000,000

Weighted average interest rate of debt

Long-term line of credit

^[2]

$ 726,000,000

$ 898,000,000

2.34%

1.72%

Senior Notes Due 2023 [Member]

Principal amount of debt issued

$ 300,000,000

Interest rate of debt issued

3.55%

Maturity date of debt issued

Apr. 01, 2023

Senior Notes Due 2028 [Member]

Principal amount of debt issued

$ 300,000,000

Interest rate of debt issued

4.00%

Maturity date of debt issued

Apr. 01, 2028

Product Financing Arrangement [Member]

Short-term Debt [Line Items]

Short-term borrowings

$ 0

$ 39,000,000

[1]	Based on current credit ratings.
[2]	Weighted average interest rate was 2.34% and 1.72% as of March 31, 2018 and December 31, 2017, respectively.

Commitments and Contingencies (Details)	3 Months Ended
Commitments and Contingencies (Details)	Mar. 31, 2018 USD ($)
Minnesota Service Territory [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Liability recorded for remediation of Minnesota sites	$ 7,000,000
Minnesota Service Territory [Member] \| Minimum [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Estimated remediation costs for the Minnesota sites	$ 5,000,000
Years to resolve contingency	30 years
Minnesota Service Territory [Member] \| Maximum [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Estimated remediation costs for the Minnesota sites	$ 30,000,000
Years to resolve contingency	50 years
Natural Gas Supply Commitments [Member]
Recorded Unconditional Purchase Obligation Payment Schedule [Abstract]
Remaining nine months of 2018	$ 289,000,000
2019	311,000,000
2020	170,000,000
2021	81,000,000
2022	51,000,000
2023 and beyond	125,000,000
Minnehaha Academy Gas Explosion [Member]
Contested amount of fines imposed	$ 200,000

Income Taxes (Details)	3 Months Ended
Income Taxes (Details)	Mar. 31, 2018	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Effective income tax rate	22.00%	38.00%
Federal statutory income tax rate	21.00%	35.00%

Reportable Business Segments (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2018

Mar. 31, 2017

Dec. 31, 2017

$ 2,400

$ 2,093

131

199

^[1]

Natural Gas Distribution [Member]

9,855

$ 10,112

Enable

1,143

907

156

168

^[1]

Energy Services [Member]

1,257

1,185

Midstream Investments [Member]

(26)

^[1]

^[2]

Other Operations [Member]

^[2]

^[1]

Intersegment Eliminations [Member]

(4)

^[1]

(38)

(20)

Intersegment Eliminations [Member] | Natural Gas Distribution [Member]

(460)

(559)

Intersegment Eliminations [Member] | Energy Services [Member]

(10)

(9)

Intersegment Eliminations [Member] | Midstream Investments [Member]

(28)

(11)

Intersegment Eliminations [Member] | Other Operations [Member]

^[2]

Operating Segments [Member] | Natural Gas Distribution [Member]

Operating Segments [Member] | Energy Services [Member]

6,438

6,608

Operating Segments [Member] | Midstream Investments [Member]

1,329

1,521

Operating Segments [Member] | Other Operations [Member]

^[2]

2,467

2,472

Enable Midstream Partners [Member]

$ 70

Enable Midstream Partners [Member] | Midstream Investments [Member]

Enable