View Filing Data

Estimate Fair Value

Estimate Useful Life

(in millions)

(in years)

Customer relationships

Document and Entity Information - USD ($)	6 Months Ended
Document and Entity Information - USD ($)	Jun. 30, 2017	Jul. 27, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	CENTERPOINT ENERGY RESOURCES CORP
Entity Central Index Key	0001042773
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		1,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

CONDENSED STATEMENTS OF CONSOLIDATED INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues:
Utility revenues	$ 470	$ 414	$ 1,377	$ 1,302
Non-utility revenues	917	393	2,103	825
Total	1,387	807	3,480	2,127
Expenses:
Utility natural gas	150	126	600	564
Non-utility natural gas	882	370	2,011	784
Operation and maintenance	196	196	416	396
Depreciation and amortization	68	63	134	123
Taxes other than income taxes	38	34	72	76
Total	1,334	789	3,233	1,943
Operating Income	53	18	247	184
Other Income (Expense):
Interest and other finance charges	(31)	(31)	(60)	(64)
Equity in earnings of unconsolidated affiliate, net	59	31	131	91
Other, net	2	2	2	2
Total	30	2	73	29
Income Before Income Taxes	83	20	320	213
Income tax expense	29	14	119	87
Net Income	$ 54	$ 6	$ 201	$ 126

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 54	$ 6	$ 201	$ 126
Other comprehensive income, net of tax:
Adjustment to pension and other postretirement plans (net of tax of $-0-, $1, $-0- and $1)	0	1	0	1
Other comprehensive income	0	1	0	1
Comprehensive income	$ 54	$ 7	$ 201	$ 127

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Tax benefit (expense) on adjustment related to pension and postretirement plans	$ 0	$ (1)	$ 0	$ (1)

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 1	$ 1
Accounts receivable, less bad debt reserve of $18 and $14, respectively	482	512
Accrued unbilled revenues	76	229
Accounts and notes receivable–affiliated companies	5	5
Materials and supplies	56	47
Natural gas inventory	218	131
Non-trading derivative assets	67	51
Prepaid expenses and other current assets	90	81
Total current assets	995	1,057
Property, Plant and Equipment:
Property, plant and equipment	6,553	6,351
Less: accumulated depreciation and amortization	1,863	1,782
Property, plant and equipment, net	4,690	4,569
Other Assets:
Goodwill	867	862
Non-trading derivative assets	46	19
Investment in unconsolidated affiliate	2,487	2,505
Other	250	206
Total other assets	3,650	3,592
Total Assets	9,335	9,218
Current Liabilities:
Short-term borrowings	24	35
Current portion of long-term debt	550	250
Accounts payable	390	471
Accounts and notes payable–affiliated companies	39	40
Taxes accrued	47	73
Interest accrued	32	33
Customer deposits	78	80
Non-trading derivative liabilities	20	41
Other	86	124
Total current liabilities	1,266	1,147
Other Liabilities:
Deferred income taxes, net	2,041	1,925
Non-trading derivative liabilities	4	5
Benefit obligations	105	104
Regulatory liabilities	795	769
Other	232	221
Total other liabilities	3,177	3,024
Long-Term Debt	1,978	2,125
Commitments and Contingencies (Note 11)
Stockholder’s Equity:
Common stock	0	0
Paid-in capital	2,528	2,489
Retained earnings	383	430
Accumulated other comprehensive income	3	3
Total stockholder’s equity	2,914	2,922
Total Liabilities and Stockholder’s Equity	$ 9,335	$ 9,218

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Bad debt reserve	$ 18	$ 14

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash Flows from Operating Activities:
Net income	$ 201	$ 126
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	134	123
Amortization of deferred financing costs	4	4
Deferred income taxes	115	82
Write-down of natural gas inventory	0	1
Equity in earnings of unconsolidated affiliate, net of distributions	(131)	(91)
Changes in other assets and liabilities, excluding acquisitions:
Accounts receivable and unbilled revenues, net	295	221
Accounts receivable/payable–affiliated companies	(1)	(8)
Inventory	(18)	66
Accounts payable	(203)	(96)
Fuel cost recovery	(12)	(17)
Interest and taxes accrued	(27)	(21)
Non-trading derivatives, net	(49)	21
Margin deposits, net	(43)	65
Other current assets	19	(8)
Other current liabilities	(13)	16
Other assets	(18)	4
Other liabilities	24	13
Other, net	1	2
Net cash provided by operating activities	278	503
Cash Flows from Investing Activities:
Capital expenditures	(223)	(230)
Distribution from unconsolidated affiliate in excess of cumulative earnings	149	149
Decrease in notes receivable–unconsolidated affiliate	0	363
Acquisitions, net of cash acquired	(132)	(98)
Other, net	1	(2)
Net cash provided by (used in) investing activities	(205)	182
Cash Flows from Financing Activities:
Decrease in short-term borrowings, net	(11)	(23)
Proceeds from (payments of) commercial paper, net	149	(43)
Payments of long-term debt	0	(325)
Dividends to parent	(248)	(363)
Debt issuance costs	(1)	(1)
Contribution from parent	38	73
Other, net	0	(2)
Net cash used in financing activities	(73)	(684)
Net Increase in Cash and Cash Equivalents	0	1
Cash and Cash Equivalents at Beginning of Period	1	0
Cash and Cash Equivalents at End of Period	1	1
Cash Payments:
Interest, net of capitalized interest	56	63
Income taxes, net	3	3
Non-cash transactions:
Accounts payable related to capital expenditures	$ 44	$ 36

Background and Basis of Presentation

6 Months Ended

Jun. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background and Basis of Presentation [Text Block]

Background and Basis of Presentation

General. Included in this Form 10-Q are the Interim Condensed Financial Statements of CERC. The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the 2016 Form 10-K.

Background. CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, a public utility holding company. CERC Corp.’s operating subsidiaries own and operate natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and own interests in Enable as described in Note 7. CERC Corp.’s operating subsidiaries and divisions include:


•	NGD, which owns and operates natural gas distribution systems in six states; and


•	CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 33 states.

As of June 30, 2017, CERC Corp. also owned approximately 54.1% of the common and subordinated units representing limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles 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.

CERC’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in CERC’s Condensed Statements of Consolidated 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 and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of CERC’s reportable business segments, see Note 13.

New Accounting Pronouncements	6 Months Ended
New Accounting Pronouncements	Jun. 30, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements [Text Block]	New Accounting Pronouncements In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01). ASU 2016-01 requires equity investments that do not result in consolidation and are not accounted for under the equity method to be measured at fair value and to recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. It does not change the guidance for classifying and measuring investments in debt securities and loans. ASU 2016-01 also changes certain disclosure requirements and other aspects related to recognition and measurement of financial assets and financial liabilities. ASU 2016-01 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. As of the first reporting period in which the guidance is adopted, a cumulative-effect adjustment to beginning retained earnings will be made, with two features that will be adopted prospectively. CERC does not believe this standard will have a material impact on its financial position, results of operations, cash flows and disclosures. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 provides a comprehensive new lease model that requires lessees to recognize assets and liabilities for most leases and would change certain aspects of lessor accounting. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. A modified retrospective adoption approach is required. CERC is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). The new guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. CERC adopted this standard as of January 1, 2017. The adoption did not have a material impact on CERC’s financial position or results of operations. However, CERC’s statement of cash flows reflects a decrease in financing activity and a corresponding increase in operating activity of $1 million as of both June 30, 2017 and June 30, 2016 due to the retrospective application of the requirement that cash paid to a tax authority when shares are withheld to satisfy statutory income tax withholding obligations should be presented as a financing rather than as an operating activity. In 2016, the FASB issued ASUs which amended ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09, as amended, provides a comprehensive new revenue recognition model that requires revenue to be recognized in a manner that depicts the transfer of goods or services to a customer at an amount that reflects the consideration expected to be received in exchange for those goods or services. Early adoption is permitted, and entities have the option of using either a full retrospective or a modified retrospective adoption approach. CERC is currently evaluating its revenue streams under these ASUs and has not yet identified any significant changes as the result of these new standards. A substantial amount of CERC’s revenues are tariff and derivative based, which we do not anticipate will be significantly impacted by these ASUs. CERC expects to adopt these ASUs on January 1, 2018 using the modified retrospective adoption approach. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (ASU 2016-15). ASU 2016-15 provides clarifying guidance on the classification of certain cash receipts and payments in the statement of cash flows and eliminates the variation in practice related to such classifications. ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. CERC is currently assessing the impact that this standard will have on its statement of cash flows. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. As a result, the statement of cash flows will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. ASU 2016-18 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. A retrospective adoption approach is required. CERC is currently assessing the impact that this standard will have on its statement of cash flows and disclosures. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). ASU 2017-01 revises the definition of a business. If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, then under ASU 2017-01, the asset or group of assets is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs to be more closely aligned with how outputs are described in ASC 606. ASU 2017-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted in certain circumstances. A prospective adoption approach is required. ASU 2017-01 could have a potential impact on CERC’s accounting for future acquisitions. In January 2017, the FASB issued ASU No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 eliminates Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. A prospective adoption approach is required. ASU 2017-04 will have an impact on CERC’s future calculation of goodwill impairments if an impairment is identified. In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (ASU 2017-05). ASU 2017-05 clarifies when and how to apply ASC 610-20 Gains and Losses from the Derecognition of Nonfinancial Assets, which was issued as part of ASU 2014-09 Revenue from Contracts with Customers (Topic 606). ASU 2017-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. Companies can elect a retrospective or modified retrospective approach to adoption. CERC is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures. In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires an employer to report the service cost component of the net periodic pension cost and postretirement benefit cost in the same line item(s) as other employee compensation costs arising from services rendered during the period; all other components will be presented separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. ASU 2017-07 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. ASU 2017-07 should be applied retrospectively for the presentation of the service cost component and the other components and prospectively for the capitalization of the service cost component. CERC is currently assessing the impact that this standard will have on its financial position, results of operations, cash flows and disclosures. Management believes that other recently issued standards, which are not yet effective, will not have a material impact on CERC’s consolidated financial position, results of operations or cash flows upon adoption.

Acquisition

6 Months Ended

Jun. 30, 2017

Business Combinations [Abstract]

Acquisition [Text Block]

Acquisition

On January 3, 2017, CES, a wholly-owned subsidiary of CERC, completed its acquisition of AEM. After working capital adjustments, the final purchase price was $147 million and was allocated to identifiable assets acquired and liabilities assumed based on their estimated fair values on the acquisition date.

The following table summarizes the final purchase price allocation and the fair value amounts recognized for the assets acquired and liabilities assumed related to the acquisition:



	(in millions)
Total purchase price consideration	$	147
Cash	$	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	$	147

The goodwill of $5 million resulting from the acquisition reflects the excess of the purchase price over the fair value of the net identifiable assets acquired. The goodwill recorded as part of the acquisition primarily reflects the value of the complementary operational and geographic footprints, scale and expanded capabilities provided by the acquisition.

Identifiable intangible assets were recorded at estimated fair value as determined by management based on available information, which includes a preliminary valuation prepared by an independent third party. The significant assumptions used in arriving at the estimated identifiable intangible asset values included management’s estimates of future cash flows, the discount rate which is based on the weighted average cost of capital for comparable publicly traded guideline companies and projected customer attrition rates. The useful lives for the identifiable intangible assets were determined using methods that approximate the pattern of economic benefit provided by the utilization of the assets.

The estimated fair value of the identifiable intangible assets and related useful lives as included in the final purchase price allocation include:

Amortization expense related to the above identifiable intangible assets was $1 million for both the three and six months ended June 30, 2017.

Revenues of approximately $319 million and $678 million, respectively, and operating income of approximately $8 million and $25 million, respectively, attributable to the AEM acquisition are reported in the Energy Services business segment and included in CERC’s Condensed Statements of Consolidated Income for the three and six months ended June 30, 2017.

The following unaudited pro forma financial information reflects the consolidated results of operations of CERC, assuming the AEM acquisition had taken place on January 1, 2016. Adjustments to pro forma net income include intercompany sales, amortization of intangible assets, depreciation of fixed assets, interest expense associated with debt financing to fund the acquisition, and related income tax effects. The pro forma information does not include the mark-to-market impact of financial instruments designated as cash flow hedges of anticipated purchases and sales at index prices. The effective portion of these hedges are excluded from earnings and reported as changes in Other Comprehensive Income. Additionally, the pro forma information does not include the mark-to-market impact of physical forward transactions that were previously accounted for as normal purchase and sale transactions.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved had the acquisition taken place on the dates indicated or the future consolidated results of operations of the combined company.



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	1,387	$	1,006	$	3,480	$	2,585
Net Income	54		11		201		130

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

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+ Details

Employee Benefit Plans

6 Months Ended

Jun. 30, 2017

Compensation and Retirement Disclosure [Abstract]

Employee Benefits Plans [Text Block]

Employee Benefit Plans

CERC’s employees participate in CenterPoint Energy’s postretirement benefit plan. CERC’s net periodic cost includes the following components relating to postretirement benefits:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
	(in millions)
Interest cost	$	1	$	1	$	2	$	2
Amortization of prior service cost	1		—		1		—
Net periodic cost (1)	$	2	$	1	$	3	$	2


(1)	Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.

CERC expects to contribute approximately $5 million to its postretirement benefit plan in 2017, of which approximately $1 million and $3 million were contributed during the three and six months ended June 30, 2017, respectively.

Derivative Instruments

6 Months Ended

Jun. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments [Text Block]

Derivative Instruments

CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CERC utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on its operating results and cash flows. Such derivatives are recognized in CERC’s Condensed Consolidated Balance Sheets at their fair value unless CERC elects the normal purchase and sales exemption for qualified physical transactions. A derivative may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business.

CenterPoint Energy has a Risk Oversight Committee composed of corporate and business segment officers that oversees commodity price, weather and credit risk activities, including CERC’s marketing, risk management services and hedging activities. The committee’s duties are to establish CERC’s commodity risk policies, allocate board-approved commercial risk limits, approve the use of new products and commodities, monitor positions and ensure compliance with CERC’s risk management policies, procedures and limits established by CenterPoint Energy’s board of directors.

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

(a) Non-Trading Activities

Derivative Instruments. CERC enters into certain derivative instruments to mitigate the effects of commodity price movements. Certain financial instruments used to hedge portions of the natural gas inventory of the Energy Services business segment are designated as fair value hedges for accounting purposes. All other financial instruments do not qualify or are not designated as cash flow or fair value hedges.

Weather Hedges. CERC has weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD in Texas does not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to CERC’s other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas.

CERC entered into heating-degree day swaps for certain NGD Texas jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the 2017–2018 winter heating season, which contained a bilateral dollar cap of $8 million. However, CERC did not enter into heating-degree day swaps for NGD jurisdictions for the 2015–2016 or 2016–2017 winter heating seasons.

(b) Derivative Fair Values and Income Statement Impacts

The following tables present information about CERC’s derivative instruments and hedging activities. The first four tables provide a balance sheet overview of CERC’s Derivative Assets and Liabilities as of June 30, 2017 and December 31, 2016, while the last table provides a breakdown of the related income statement impacts for the three and six months ended June 30, 2017 and 2016.



Fair Value of Derivative Instruments
	June 30, 2017
Derivatives designated as fair value hedges:	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	6	$	1
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	1		—

Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	91		25
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	46		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	8		34
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	8		21
Total		$	160	$	81


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,906 Bcf or a net 17 Bcf short position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)

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 $89 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 $10 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.



Offsetting of Natural Gas Derivative Assets and Liabilities
	June 30, 2017
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	106		$	(39	)	$	67
Other Assets: Non-trading derivative assets	54			(8		)	46
Current Liabilities: Non-trading derivative liabilities	(60		)	40			(20		)
Other Liabilities: Non-trading derivative liabilities	(21		)	17			(4		)
Total	$	79		$	10		$	89


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	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.



Fair Value of Derivative Instruments
	December 31, 2016
Derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Total (4)		$	105	$	67


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position. Of the net long position, basis swaps constitute a net 126 Bcf long position.

(2)

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 $24 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 $14 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.


(4)	No derivatives were designated as fair value hedges as of December 31, 2016.



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2016
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	81		$	(30	)	$	51
Other Assets: Non-trading derivative assets	24			(5		)	19
Current Liabilities: Non-trading derivative liabilities	(57		)	16			(41		)
Other Liabilities: Non-trading derivative liabilities	(10		)	5			(5		)
Total	$	38		$	(14	)	$	24


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	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.

Realized and unrealized gains and losses on natural gas derivatives are recognized in the Condensed Statements of Consolidated Income as revenue for physical sales derivative contracts and as natural gas expense for financial natural gas derivatives and physical purchase natural gas derivatives.

Hedge ineffectiveness is recorded as a component of natural gas expense and primarily results from differences in the location of the derivative instrument and the hedged item. Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. The impact of natural gas derivatives designated as fair value hedges, the related hedged item, and natural gas derivatives not designated as hedging instruments are presented in the table below.



Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	3		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(4		)	—
Total increase in Expenses: Natural Gas (1)		$	(1	)	$	—

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	36		$	(50	)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	59
Total - derivatives not designated as hedging instruments		$	27		$	9



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	12		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(14		)	—
Total increase in Expenses: Natural Gas (1)		$	(2	)	$	—

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	132		$	(30	)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(82		)	48
Total - derivatives not designated as hedging instruments		$	50		$	18

(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.

CERC enters into financial derivative contracts containing material adverse change provisions. These provisions could require CERC to post additional collateral if the S&P or Moody’s credit ratings of CERC are downgraded. The total fair value of the derivative instruments that contain credit risk contingent features that are in a net liability position as of both June 30, 2017 and December 31, 2016 was $1 million. CERC posted no assets as collateral toward derivative instruments that contain credit risk contingent features as of either June 30, 2017 or December 31, 2016. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered as of June 30, 2017 and December 31, 2016, $1 million and $-0-, respectively, of additional assets would be required to be posted as collateral.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

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-Name Accounting Standards Codification
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+ Details

Fair Value Measurements

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

Fair Value Measurements

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

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are exchange-traded derivatives and equity securities, as well as natural gas inventory that has been designated as the hedged item in a fair value hedge.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value CERC’s Level 2 assets or liabilities.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect CERC’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. CERC develops these inputs based on the best information available, including CERC’s own data. A market approach is utilized to value CERC’s Level 3 assets or liabilities. As of June 30, 2017, CERC’s Level 3 assets and liabilities are comprised of physical forward contracts and options. Level 3 physical forward contracts are valued using a discounted cash flow model which includes illiquid forward price curve locations (ranging from $1.18 to $6.01 per MMBtu) as an unobservable input. Level 3 options are valued through Black-Scholes (including forward start) option models which include option volatilities (ranging from 0% to 80%) as an unobservable input. CERC’s Level 3 physical forward contracts and options derivative assets and liabilities consist of both long and short positions (forwards and options) and their fair value is sensitive to forward prices and volatilities. If forward prices decrease, CERC’s long forwards lose value whereas its short forwards gain in value. If volatility decreases, CERC’s long options lose value whereas its short options gain in value.

CERC 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 six months ended June 30, 2017, there were no transfers between Level 1 and 2. CERC also recognizes purchases of Level 3 financial assets and liabilities at their fair market value at the end of the reporting period.

The following tables present information about CERC’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of June 30, 2017 and December 31, 2016, and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of June 30, 2017
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	2		125		33		(47		)	113
Hedged portion of natural gas inventory	107		—		—		—			107
Total assets	$	122	$	125	$	33	$	(47	)	$	233
Liabilities
Natural gas derivatives (3)	$	2	$	74	$	5	$	(57	)	$	24
Total liabilities	$	2	$	74	$	5	$	(57	)	$	24


(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 $10 million posted with the same counterparties.


(2)	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2016
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	24	$	74	$	20	$	(35	)	$	83
Liabilities
Natural gas derivatives (3)	$	4	$	56	$	7	$	(21	)	$	46
Total liabilities	$	4	$	56	$	7	$	(21	)	$	46


(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 $14 million held by CES from the same counterparties.


(2)	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which CERC has utilized Level 3 inputs to determine fair value:



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, Net
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	27		$	15		$	13		$	12
Purchases (1)	—			12			—			12
Total gains	7			—			23			4
Total settlements	—			(11		)	(4		)	(16		)
Transfers into Level 3	1			—			2			5
Transfers out of Level 3	(7		)	—			(6		)	(1		)
Ending balance (2)	$	28		$	16		$	28		$	16
The amount of total gains 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		$	3		$	21		$	11


(1)	Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.


(2)	CERC did not have significant Level 3 sales during either of the three or six months ended June 30, 2017 or 2016.

Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents and short-term borrowings are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by the market price. These assets and liabilities, which are not measured at fair value in the Condensed Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 1 or Level 2 in the fair value hierarchy.



	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,528	$	2,738	$	2,375	$	2,551

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Unconsolidated Affiliate

6 Months Ended

Jun. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Unconsolidated Affiliate [Text Block]

Unconsolidated Affiliate

CERC has the ability to significantly influence the operating and financial policies of Enable, a publicly traded MLP, and, accordingly, accounts for its investment in Enable’s common and subordinated units using the equity method of accounting.

CERC’s maximum exposure to loss related to Enable, a VIE in which CERC is not the primary beneficiary, is limited to its equity investment as presented in the Condensed Consolidated Balance Sheets as of June 30, 2017 and outstanding current accounts receivable from Enable.

Transactions with Enable:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Reimbursement of transition services (1)	$	1	$	2	$	3	$	5
Natural gas expenses, including transportation and storage costs	24		24		57		57
Interest income related to notes receivable from Enable	—		—		—		1


(1)	Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.



	June 30, 2017		December 31, 2016
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	1
Accounts payable for natural gas purchases from Enable	8		10

Limited Partner Interest in Enable:



	June 30, 2017
CERC	54.1	%
OGE	25.7	%

In November 2016, Enable completed a public offering of 11,500,000 common units of which 1,424,281 were sold by ArcLight Capital Partners, LLC. The common units issued and sold by Enable resulted in dilution of both CERC’s and OGE’s limited partner interest in Enable.

Enable Common and Subordinated Units Held:



	June 30, 2017
	Common	Subordinated
CERC	94,151,707	139,704,916
OGE	42,832,291	68,150,514

Generally, sales of more than 5% of the aggregate of the common units and subordinated units CERC owns in Enable or sales by OGE of more than 5% of the aggregate of the common units and subordinated units it owns in Enable are subject to mutual rights of first offer and first refusal.

Enable is controlled jointly by CERC Corp. and OGE, and each own 50% of the management rights in the general partner of Enable. Sale of CERC’s or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and CERC is not permitted to dispose of less than all of its interest in Enable’s general partner.

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	626	$	529	$	1,292	$	1,038
Cost of sales, excluding depreciation and amortization	279		254		587		449
Operating income	122		57		262		160
Net income attributable to Enable	86		35		197		121

Reconciliation of Equity in Earnings, net:
CERC’s interest	$	47	$	19	$	107	$	67
Basis difference amortization (1)	12		12		24		24
CERC’s equity in earnings, net	$	59	$	31	$	131	$	91


(1)	Equity in earnings of unconsolidated affiliates includes CERC’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

Summarized unaudited consolidated balance sheet information for Enable is as follows:



	June 30, 2017			December 31, 2016
	(in millions)
Current assets	$	351		$	396
Non-current assets	10,780			10,816
Current liabilities	298			362
Non-current liabilities	3,111			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,348			7,420

Reconciliation of Equity Method Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,025		$	4,067
CERC’s basis difference	(1,538		)	(1,562		)
CERC’s equity method investment in Enable	$	2,487		$	2,505

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common and subordinated units	$	75	$	75	$	149	$	149

As of June 30, 2017, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. To date, no incentive distributions have been made.

Goodwill

6 Months Ended

Jun. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill [Text Block]

Goodwill

Goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of June 30, 2017 are as follows:



	December 31, 2016			AEM Acquisition (1)		June 30, 2017
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	105		(2)	5		110		(2)
Other Operations	11			—		11
Total	$	862		$	5	$	867


(1)	See Note 3.


(2)	Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

- Definition

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

+ References + Details

Related Party Transactions

6 Months Ended

Jun. 30, 2017

Related Party Transactions [Text Block]

Related Party Transactions

CERC participates in a money pool through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. CERC had no investments in the money pool as of both June 30, 2017 and December 31, 2016, which would be included in accounts and notes receivable–affiliated companies in the Condensed Consolidated Balance Sheets. Affiliate related net interest income (expense) was not material for either the three or six months ended June 30, 2017 or 2016.

CenterPoint Energy provides some corporate services to CERC. The costs of services have been charged directly to CERC using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Houston Electric provides a number of services to CERC. These services are billed at actual cost, either directly or as an allocation, and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate of CenterPoint Energy. Amounts charged to and by CERC for these services were as follows and are included primarily in operation and maintenance expenses:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)
Corporate service charges	$	32		$	29		$	63		$	59
Charges from Houston Electric for services provided	5			3			8			7
Billings to Houston Electric for services provided	(1		)	(2		)	(3		)	(3		)

See Note 7 for related party transactions with Enable.

Short-term Borrowings and Long-term Debt

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

Short-term Borrowings and Long-term Debt [Text Block]

Short-term Borrowings and Long-term Debt

(a)Short-term Borrowings

Inventory Financing. NGD currently has AMAs associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2020. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as an inventory financing and had an associated principal obligation of $24 million and $35 million as of June 30, 2017 and December 31, 2016, respectively.


(b)	Long-term Debt

Revolving Credit Facility. In June 2017, CERC entered into an amendment to its revolving credit facility to extend the termination date thereof from March 3, 2021 to March 3, 2022 and to terminate the swingline loan subfacility thereunder. The amendment also increased the aggregate commitments by $300 million to $900 million under its revolving credit facility. In connection with the amendment to increase the aggregate commitments under its revolving credit facility, CERC increased the size of its commercial paper program to permit the issuance of commercial paper notes in an aggregate principal amount not to exceed $900 million at any time outstanding.

As of June 30, 2017 and December 31, 2016, CERC had the following revolving credit facility and utilization of such facility:



June 30, 2017									December 31, 2016
Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
(in millions)
$	900	$	—	$	—	$	718	(1)	$	600	$	—	$	4	$	569	(1)


(1)	Weighted average interest rate was approximately 1.41% and 1.03% as of June 30, 2017 and December 31, 2016, respectively.



Execution Date	Size of Facility			Draw Rate of LIBOR plus (2)		Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of June 30, 2017	Termination Date (3)
	(in millions)
March 3, 2016	$	900	(1)	1.25	%	65	%	37.1%	March 3, 2022


(1)	Amended on June 16, 2017 to increase the aggregate commitment size as noted above.


(2)	Based on current credit ratings.


(3)	Amended on June 16, 2017 to extend the termination date as noted above.

CERC Corp. was in compliance with all financial debt covenants as of June 30, 2017.

Commitments and Contingencies

6 Months Ended

Jun. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies [Text Block]

Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to CERC’s Natural Gas Distribution and Energy Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in CERC’s Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 as these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of June 30, 2017, minimum payment obligations for natural gas supply commitments are approximately:



	(in millions)
Remaining six months of 2017	$	227
2018	488
2019	334
2020	167
2021	75
2022 and beyond	82

(b) Legal, Environmental and Other Matters

Legal Matters

Gas Market Manipulation Cases. CenterPoint Energy, Houston Electric or their predecessor, Reliant Energy, and certain of their former subsidiaries have been named as defendants in certain lawsuits described below. Under a master separation agreement between CenterPoint Energy and a former subsidiary, RRI, CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI and its successors for any losses, including certain attorneys’ fees and other costs, arising out of these lawsuits. In May 2009, RRI sold its Texas retail business to a subsidiary of NRG and RRI changed its name to RRI Energy, Inc. In December 2010, Mirant Corporation merged with and became a wholly-owned subsidiary of RRI, and RRI changed its name to GenOn. In December 2012, NRG acquired GenOn through a merger in which GenOn became a wholly-owned subsidiary of NRG. None of the sale of the retail business, the merger with Mirant Corporation, or the acquisition of GenOn by NRG alters RRI’s (now GenOn’s) contractual obligations to indemnify CenterPoint Energy and its subsidiaries, including Houston Electric, for certain liabilities, including their indemnification obligations regarding the gas market manipulation litigation.

A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000–2002. CenterPoint Energy and its affiliates have since been released or dismissed from all such cases. CES, a subsidiary of CERC Corp., was a defendant in a case now pending in federal court in Nevada alleging a conspiracy to inflate Wisconsin natural gas prices in 2000–2002. On May 24, 2016, the district court granted CES’s motion for summary judgment, dismissing CES from the case. The plaintiffs have appealed that ruling. CenterPoint Energy and CES intend to continue vigorously defending against the plaintiffs’ claims. In June 2017, GenOn and various affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code. If GenOn were unable to meet its indemnity obligations or satisfy a liability that has been assumed in the gas market manipulation litigation, then CERC, CenterPoint Energy or Houston Electric could incur liability and be responsible for satisfying the liability. CERC does not expect the ultimate outcome of the case against CES to have a material adverse effect on its financial condition, results of operations or cash flows.

Environmental Matters

MGP Sites. CERC and its predecessors operated MGPs in the past. With respect to certain Minnesota MGP sites, CERC has completed state-ordered remediation and continues state-ordered monitoring and water treatment. As of June 30, 2017, CERC had a recorded liability of $7 million for continued monitoring and any future remediation required by regulators in Minnesota. The estimated range of possible remediation costs for the sites for which CERC believes it may have responsibility was $4 million to $30 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.

In addition to the Minnesota sites, the Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC does not expect the ultimate outcome of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

Asbestos. Some facilities owned by CERC or its predecessors contain or have contained asbestos insulation and other asbestos-containing materials. CERC and its predecessor companies are from time to time named, along with numerous others, as defendants in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and CERC anticipates that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, CERC does not expect these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Environmental. From time to time, CERC identifies the presence of environmental contaminants during its operations or on property where its predecessor companies have conducted operations. Other such sites involving contaminants may be identified in the future. CERC has and expects to continue to remediate identified sites consistent with its legal obligations. From time to time, CERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, CERC has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, CERC does not expect these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows.

Other Proceedings

CERC is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, CERC is also a defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. CERC regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. CERC does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.

Income Taxes	6 Months Ended
Income Taxes	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes [Text Block]	Income Taxes The effective tax rate reported for the three months ended June 30, 2017 was 35% compared to 70% for the same period in 2016. The effective tax rate reported for the six months ended June 30, 2017 was 37% compared to 41% for the same period in 2016. The higher effective tax rate for both the three and six months ended June 30, 2016 was primarily due to a Louisiana state tax law change resulting in an increase to CERC’s deferred tax liability. CERC reported no uncertain tax liability as of June 30, 2017 and expects no significant change to the uncertain tax liability over the next twelve months. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through 2015. For the 2016 and 2017 tax years, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

Reportable Business Segments

6 Months Ended

Jun. 30, 2017

Segment Reporting [Abstract]

Reportable Business Segments [Text Block]

Reportable Business Segments

CERC’s determination of reportable business segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. CERC uses operating income as the measure of profit or loss for its business segments other than Midstream Investments, where it uses equity in earnings of unconsolidated affiliates.

CERC’s reportable business segments include the following: Natural Gas Distribution, Energy Services, Midstream Investments and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Energy Services represents CERC’s non-rate regulated gas sales and services operations. Midstream Investments consists of CERC’s equity investment in Enable. The Other Operations business segment includes unallocated corporate costs and inter-segment eliminations.

Financial data for business segments is as follows:



	For the Three Months Ended June 30, 2017
	Revenues from External Customers			Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	470		$	7		$	37
Energy Services	918			13			16
Midstream Investments (1)	—			—			—
Other Operations	(1		)	—			—
Reconciling Eliminations	—			(20		)	—
Consolidated	$	1,387		$	—		$	53



	For the Three Months Ended June 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
	(in millions)
Natural Gas Distribution	$	414	$	7		$	20
Energy Services	393		4			—
Midstream Investments (1)	—		—			—
Other Operations	—		—			(2		)
Reconciling Eliminations	—		(11		)	—
Consolidated	$	807	$	—		$	18



	For the Six Months Ended June 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of June 30, 2017
	(in millions)
Natural Gas Distribution	$	1,377	$	16		$	201		$	6,022
Energy Services	2,103		24			51			1,388
Midstream Investments (1)	—		—			—			2,487
Other Operations	—		—			(5		)	82
Reconciling Eliminations	—		(40		)	—			(644		)
Consolidated	$	3,480	$	—		$	247		$	9,335



	For the Six Months Ended June 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2016
	(in millions)
Natural Gas Distribution	$	1,302	$	14		$	180		$	6,099
Energy Services	825		11			6			1,102
Midstream Investments (1)	—		—			—			2,505
Other Operations	—		—			(2		)	75
Reconciling Eliminations	—		(25		)	—			(563		)
Consolidated	$	2,127	$	—		$	184		$	9,218


(1)	Midstream Investments’ equity earnings are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	59	$	31	$	131	$	91

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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-Name Accounting Standards Codification
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+ Details

Other Current Assets and Liabilities	6 Months Ended
Other Current Assets and Liabilities	Jun. 30, 2017
Other Current Assets and Liabilities [Abstract]
Other Current Assets and Liabilities [Text Block]	Other Current Assets and Liabilities Included in other current assets on the Condensed Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016 were $19 million and less than $1 million, respectively, of margin deposits and $42 million and $40 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Condensed Consolidated Balance Sheets at June 30, 2017 and December 31, 2016 were $5 million and $10 million, respectively, of over-recovered gas cost.

Subsequent Events	6 Months Ended
Subsequent Events	Jun. 30, 2017
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events On July 31, 2017, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended June 30, 2017. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the third quarter of 2017 to be made with respect to CERC Corp.’s investment in common and subordinated units of Enable for the second quarter of 2017. The subordination period will end on the first day after Enable’s second quarter distribution payment is made and the subordinated units held by CERC Corp. will be converted to common units on a one-for-one basis. At conversion, holders of common units resulting from the conversion of subordinated units will have all the rights and obligations of unitholders holding all other common units, including the right to receive distributions pro rata made with respect to common units.

Acquisition (Tables)

6 Months Ended

Jun. 30, 2017

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following table summarizes the final purchase price allocation and the fair value amounts recognized for the assets acquired and liabilities assumed related to the acquisition:



	(in millions)
Total purchase price consideration	$	147
Cash	$	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	$	147

Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block]

The estimated fair value of the identifiable intangible assets and related useful lives as included in the final purchase price allocation include:

Business Acquisition, Pro Forma Information [Table Text Block]



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Operating Revenue	$	1,387	$	1,006	$	3,480	$	2,585
Net Income	54		11		201		130

Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2017

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

CERC’s employees participate in CenterPoint Energy’s postretirement benefit plan. CERC’s net periodic cost includes the following components relating to postretirement benefits:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017		2016
	(in millions)
Interest cost	$	1	$	1	$	2	$	2
Amortization of prior service cost	1		—		1		—
Net periodic cost (1)	$	2	$	1	$	3	$	2


(1)	Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.

Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Instruments [Table Text Block]



Fair Value of Derivative Instruments
	December 31, 2016
Derivatives not designated as hedging instruments	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	79	$	14
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	24		5
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	2		43
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	—		5
Total (4)		$	105	$	67


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position. Of the net long position, basis swaps constitute a net 126 Bcf long position.

(2)

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 $24 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 $14 million.


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.


(4)	No derivatives were designated as fair value hedges as of December 31, 2016.



Fair Value of Derivative Instruments
	June 30, 2017
Derivatives designated as fair value hedges:	Balance Sheet Location	Derivative Assets Fair Value		Derivative Liabilities Fair Value
		(in millions)
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	$	6	$	1
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	1		—

Derivatives not designated as hedging instruments:
Natural gas derivatives (1) (2) (3)	Current Assets: Non-trading derivative assets	91		25
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	46		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	8		34
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	8		21
Total		$	160	$	81


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,906 Bcf or a net 17 Bcf short position. Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)


(3)	Derivative Assets and Derivative Liabilities include no material amounts related to physical forward transactions with Enable.

Derivative Instruments, Offsetting Assets and Liabilities [Table Text Block]



Offsetting of Natural Gas Derivative Assets and Liabilities
	December 31, 2016
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	81		$	(30	)	$	51
Other Assets: Non-trading derivative assets	24			(5		)	19
Current Liabilities: Non-trading derivative liabilities	(57		)	16			(41		)
Other Liabilities: Non-trading derivative liabilities	(10		)	5			(5		)
Total	$	38		$	(14	)	$	24


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	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.



Offsetting of Natural Gas Derivative Assets and Liabilities
	June 30, 2017
	Gross Amounts Recognized (1)			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount Presented in the Consolidated Balance Sheets (2)
	(in millions)
Current Assets: Non-trading derivative assets	$	106		$	(39	)	$	67
Other Assets: Non-trading derivative assets	54			(8		)	46
Current Liabilities: Non-trading derivative liabilities	(60		)	40			(20		)
Other Liabilities: Non-trading derivative liabilities	(21		)	17			(4		)
Total	$	79		$	10		$	89


(1)	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.


(2)	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.

Income Statement Impact of Derivative Activity [Table Text Block]



Income Statement Impact of Derivative Activity
		Three Months Ended June 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	3		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(4		)	—
Total increase in Expenses: Natural Gas (1)		$	(1	)	$	—

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	36		$	(50	)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(9		)	59
Total - derivatives not designated as hedging instruments		$	27		$	9



Income Statement Impact of Derivative Activity
		Six Months Ended June 30,
	Income Statement Location	2017			2016
Derivatives designated as fair value hedges:		(in millions)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	$	12		$	—
Fair value adjustments for natural gas inventory designated as the hedged item	Gains (Losses) in Expenses: Natural Gas	(14		)	—
Total increase in Expenses: Natural Gas (1)		$	(2	)	$	—

Derivatives not designated as hedging instruments:
Natural gas derivatives	Gains (Losses) in Revenues	$	132		$	(30	)
Natural gas derivatives	Gains (Losses) in Expenses: Natural Gas	(82		)	48
Total - derivatives not designated as hedging instruments		$	50		$	18

(1)

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value, Assets Measured on Recurring Basis [Table Text Block]



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of June 30, 2017
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	2		125		33		(47		)	113
Hedged portion of natural gas inventory	107		—		—		—			107
Total assets	$	122	$	125	$	33	$	(47	)	$	233
Liabilities
Natural gas derivatives (3)	$	2	$	74	$	5	$	(57	)	$	24
Total liabilities	$	2	$	74	$	5	$	(57	)	$	24


(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 $10 million posted with the same counterparties.


(2)	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of December 31, 2016
	(in millions)
Assets
Corporate equities	$	3	$	—	$	—	$	—		$	3
Investments, including money market funds (2)	10		—		—		—			10
Natural gas derivatives (3)	11		74		20		(35		)	70
Total assets	$	24	$	74	$	20	$	(35	)	$	83
Liabilities
Natural gas derivatives (3)	$	4	$	56	$	7	$	(21	)	$	46
Total liabilities	$	4	$	56	$	7	$	(21	)	$	46


(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 $14 million held by CES from the same counterparties.


(2)	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.


(3)	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]



	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative Assets and Liabilities, Net
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)
Beginning balance	$	27		$	15		$	13		$	12
Purchases (1)	—			12			—			12
Total gains	7			—			23			4
Total settlements	—			(11		)	(4		)	(16		)
Transfers into Level 3	1			—			2			5
Transfers out of Level 3	(7		)	—			(6		)	(1		)
Ending balance (2)	$	28		$	16		$	28		$	16
The amount of total gains 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		$	3		$	21		$	11


(1)	Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.


(2)	CERC did not have significant Level 3 sales during either of the three or six months ended June 30, 2017 or 2016.

Fair Value, by Balance Sheet Grouping [Table Text Block]

Estimated Fair Value of Financial Instruments



	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial liabilities:
Long-term debt	$	2,528	$	2,738	$	2,375	$	2,551

Unconsolidated Affiliate (Tables)

6 Months Ended

Jun. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

Transactions with Enable:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Reimbursement of transition services (1)	$	1	$	2	$	3	$	5
Natural gas expenses, including transportation and storage costs	24		24		57		57
Interest income related to notes receivable from Enable	—		—		—		1


(1)	Represents amounts billed under the Transition Agreements for certain support services provided to Enable. Actual transition services costs are recorded net of reimbursement.



	June 30, 2017		December 31, 2016
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	1
Accounts payable for natural gas purchases from Enable	8		10

Limited Partner Interest in Enable:



	June 30, 2017
CERC	54.1	%
OGE	25.7	%

Enable Common and Subordinated Units Held:



	June 30, 2017
	Common	Subordinated
CERC	94,151,707	139,704,916
OGE	42,832,291	68,150,514

Summarized unaudited consolidated income information for Enable is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Operating revenues	$	626	$	529	$	1,292	$	1,038
Cost of sales, excluding depreciation and amortization	279		254		587		449
Operating income	122		57		262		160
Net income attributable to Enable	86		35		197		121

Reconciliation of Equity in Earnings, net:
CERC’s interest	$	47	$	19	$	107	$	67
Basis difference amortization (1)	12		12		24		24
CERC’s equity in earnings, net	$	59	$	31	$	131	$	91


(1)	Equity in earnings of unconsolidated affiliates includes CERC’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.

Summarized unaudited consolidated balance sheet information for Enable is as follows:



	June 30, 2017			December 31, 2016
	(in millions)
Current assets	$	351		$	396
Non-current assets	10,780			10,816
Current liabilities	298			362
Non-current liabilities	3,111			3,056
Non-controlling interest	12			12
Preferred equity	362			362
Enable partners’ equity	7,348			7,420

Reconciliation of Equity Method Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,025		$	4,067
CERC’s basis difference	(1,538		)	(1,562		)
CERC’s equity method investment in Enable	$	2,487		$	2,505

Distributions Received from Unconsolidated Affiliate:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Investment in Enable’s common and subordinated units	$	75	$	75	$	149	$	149

Goodwill (Tables)

6 Months Ended

Jun. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by reportable business segment as of December 31, 2016 and changes in the carrying amount of goodwill as of June 30, 2017 are as follows:



	December 31, 2016			AEM Acquisition (1)		June 30, 2017
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	105		(2)	5		110		(2)
Other Operations	11			—		11
Total	$	862		$	5	$	867


(1)	See Note 3.


(2)	Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2017



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)
Corporate service charges	$	32		$	29		$	63		$	59
Charges from Houston Electric for services provided	5			3			8			7
Billings to Houston Electric for services provided	(1		)	(2		)	(3		)	(3		)

Short-term Borrowings and Long-term Debt (Tables)

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

As of June 30, 2017 and December 31, 2016, CERC had the following revolving credit facility and utilization of such facility:



June 30, 2017									December 31, 2016
Size of Facility		Loans		Letters of Credit		Commercial Paper			Size of Facility		Loans		Letters of Credit		Commercial Paper
(in millions)
$	900	$	—	$	—	$	718	(1)	$	600	$	—	$	4	$	569	(1)


(1)	Weighted average interest rate was approximately 1.41% and 1.03% as of June 30, 2017 and December 31, 2016, respectively.



Execution Date	Size of Facility			Draw Rate of LIBOR plus (2)		Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio		Debt for Borrowed Money to Capital Ratio as of June 30, 2017	Termination Date (3)
	(in millions)
March 3, 2016	$	900	(1)	1.25	%	65	%	37.1%	March 3, 2022


(1)	Amended on June 16, 2017 to increase the aggregate commitment size as noted above.


(2)	Based on current credit ratings.


(3)	Amended on June 16, 2017 to extend the termination date as noted above.

Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]



	(in millions)
Remaining six months of 2017	$	227
2018	488
2019	334
2020	167
2021	75
2022 and beyond	82

Reportable Business Segments (Tables)

6 Months Ended

Jun. 30, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

Financial data for business segments is as follows:



	For the Three Months Ended June 30, 2017
	Revenues from External Customers			Inter-segment Revenues			Operating Income
	(in millions)
Natural Gas Distribution	$	470		$	7		$	37
Energy Services	918			13			16
Midstream Investments (1)	—			—			—
Other Operations	(1		)	—			—
Reconciling Eliminations	—			(20		)	—
Consolidated	$	1,387		$	—		$	53



	For the Three Months Ended June 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)
	(in millions)
Natural Gas Distribution	$	414	$	7		$	20
Energy Services	393		4			—
Midstream Investments (1)	—		—			—
Other Operations	—		—			(2		)
Reconciling Eliminations	—		(11		)	—
Consolidated	$	807	$	—		$	18



	For the Six Months Ended June 30, 2017
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of June 30, 2017
	(in millions)
Natural Gas Distribution	$	1,377	$	16		$	201		$	6,022
Energy Services	2,103		24			51			1,388
Midstream Investments (1)	—		—			—			2,487
Other Operations	—		—			(5		)	82
Reconciling Eliminations	—		(40		)	—			(644		)
Consolidated	$	3,480	$	—		$	247		$	9,335



	For the Six Months Ended June 30, 2016
	Revenues from External Customers		Inter-segment Revenues			Operating Income (Loss)			Total Assets as of December 31, 2016
	(in millions)
Natural Gas Distribution	$	1,302	$	14		$	180		$	6,099
Energy Services	825		11			6			1,102
Midstream Investments (1)	—		—			—			2,505
Other Operations	—		—			(2		)	75
Reconciling Eliminations	—		(25		)	—			(563		)
Consolidated	$	2,127	$	—		$	184		$	9,218


(1)	Midstream Investments’ equity earnings are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	59	$	31	$	131	$	91

Midstream Investments [Table Text Block]

Midstream Investments’ equity earnings are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)
Enable	$	59	$	31	$	131	$	91

Background and Basis of Presentation (Details)	Jun. 30, 2017 state
Enable Midstream Partners [Member]
Ownership percentage of equity method investment	54.10%
Natural Gas Distribution [Member]
Number of states in which entity operates	6
Energy Services [Member]
Number of states in which entity operates	33

New Accounting Pronouncements (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Payments related to tax withholding for share-based compensation	$ 1	$ 1

Acquisition (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
Acquisition (Details) - USD ($) $ in Millions	Jan. 03, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Goodwill		$ 867		$ 867		$ 862
Atmos Energy Marketing [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Total purchase price consideration	$ 147
Cash	15
Receivables	140
Natural gas inventory	78
Derivative assets	35
Prepaid expenses and other current assets	5
Property and equipment	8
Identifiable intangibles	25
Total assets acquired	306
Accounts payable	113
Derivative liabilities	43
Other current liabilities	7
Other liabilities	1
Total liabilities assumed	164
Identifiable net assets acquired	142
Goodwill	5
Net assets acquired	147
Amortization of intangible assets		1		1
Business Acquisition, Pro Forma Information [Abstract]
Revenue of acquiree since acquisition date		319		678
Operating income of acquiree since acquisition date		8		25
Operating Revenue		1,387	$ 1,006	3,480	$ 2,585
Net Income		$ 54	$ 11	$ 201	$ 130
Customer Relationships [Member] \| Atmos Energy Marketing [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Intangibles estimated fair value	$ 25
Intangibles estimated useful life	15 years

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

3 Months Ended

6 Months Ended

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Defined Benefit Plan Disclosure [Line Items]

Interest cost on accumulated benefit obligation

$ 1

$ 2

Amortization of prior service cost

Net periodic cost (1)

^[1]

$ 1

$ 2

Contribution expected in 2017

Contribution made in period

$ 1

$ 3

[1]	Net periodic cost in this table is before considering amounts subject to overhead allocations for capital expenditure projects or for amounts subject to deferral for regulatory purposes.

Derivative Instruments (Details)

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2017

USD ($)

Jun. 30, 2016

USD ($)

Jun. 30, 2017

USD ($)

Bcf

Jun. 30, 2016

USD ($)

Dec. 31, 2016

USD ($)

Bcf

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

$ 160,000,000

$ 105,000,000

Derivative Liabilities Fair Value

81,000,000

67,000,000

Gross Amounts Offset in the Consolidated Balance Sheets

10,000,000

(14,000,000)

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

27,000,000

$ 9,000,000

50,000,000

$ 18,000,000

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

1,000,000

The aggregate fair value of assets already posted as collateral

Credit risk contingent feature assets

1,000,000

$ 0

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

Derivatives, Fair Value [Line Items]

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

(4,000,000)

(14,000,000)

Gain (loss) on fair value hedges recognized in earnings

^[1]

(1,000,000)

$ (2,000,000)

Natural gas derivatives [Member]

Derivatives, Fair Value [Line Items]

Derivative gross volume notional amount (in Bcf) | Bcf

1,906

1,035

Gross Amounts Recognized

^[2]

79,000,000

$ 79,000,000

$ 38,000,000

Gross Amounts Offset in the Consolidated Balance Sheets

10,000,000

(14,000,000)

Net Amount Presented in the Consolidated Balance Sheets

^[3]

89,000,000

24,000,000

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

Derivatives, Fair Value [Line Items]

Gross Amounts Recognized

^[2]

106,000,000

81,000,000

Gross Amounts Offset

(39,000,000)

(30,000,000)

Derivative Asset

^[3]

67,000,000

51,000,000

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

Derivatives, Fair Value [Line Items]

Gross Amounts Recognized

^[2]

54,000,000

24,000,000

Gross Amounts Offset

(8,000,000)

(5,000,000)

Derivative Asset

^[3]

46,000,000

19,000,000

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

Derivatives, Fair Value [Line Items]

Gross Amounts Recognized

^[2]

(60,000,000)

(57,000,000)

Gross Amounts Offset

40,000,000

16,000,000

Derivative Liability

^[3]

(20,000,000)

(41,000,000)

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

Derivatives, Fair Value [Line Items]

Gross Amounts Recognized

^[2]

(21,000,000)

(10,000,000)

Gross Amounts Offset

17,000,000

5,000,000

Derivative Liability

^[3]

(4,000,000)

(5,000,000)

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

Derivatives, Fair Value [Line Items]

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

36,000,000

(50,000,000)

132,000,000

(30,000,000)

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

Derivatives, Fair Value [Line Items]

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

3,000,000

12,000,000

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

(9,000,000)

$ 59,000,000

(82,000,000)

$ 48,000,000

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

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

^[4],[5],[6]

6,000,000

Derivative Liabilities Fair Value

^[4],[5],[6]

1,000,000

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

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

^[4],[5],[6]

1,000,000

Derivative Liabilities Fair Value

^[4],[5],[6]

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

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

^[4]

91,000,000

^[5],[6]

91,000,000

^[5],[6]

79,000,000

^[7],[8]

Derivative Liabilities Fair Value

^[4]

25,000,000

^[5],[6]

25,000,000

^[5],[6]

14,000,000

^[7],[8]

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

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

^[4]

46,000,000

^[5],[6]

46,000,000

^[5],[6]

24,000,000

^[7],[8]

Derivative Liabilities Fair Value

^[4]

^[5],[6]

5,000,000

^[7],[8]

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

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

^[4]

8,000,000

^[5],[6]

8,000,000

^[5],[6]

2,000,000

^[7],[8]

Derivative Liabilities Fair Value

^[4]

34,000,000

^[5],[6]

34,000,000

^[5],[6]

43,000,000

^[7],[8]

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

Derivatives, Fair Value [Line Items]

Derivative Assets Fair Value

^[4]

8,000,000

^[5],[6]

8,000,000

^[5],[6]

^[7],[8]

Derivative Liabilities Fair Value

^[4]

$ 21,000,000

^[5],[6]

$ 21,000,000

^[5],[6]

$ 5,000,000

^[7],[8]

Natural gas derivatives [Member] | Short [Member]

Derivatives, Fair Value [Line Items]

Derivative gross volume notional amount (in Bcf) | Bcf

Natural gas derivatives [Member] | Long [Member]

Derivatives, Fair Value [Line Items]

Derivative gross volume notional amount (in Bcf) | Bcf

Swap [Member] | Natural gas derivatives [Member] | Long [Member]

Derivatives, Fair Value [Line Items]

Derivative gross volume notional amount (in Bcf) | Bcf

126

Natural Gas Distribution [Member] | 2017to2018 [Member]

Derivatives, Fair Value [Line Items]

Weather hedge bilateral cap amount

$ 8,000,000

[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 $89 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 $10 million.
[6]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,906 Bcf or a net 17 Bcf short 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 $24 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 $14 million.
[8]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,035 Bcf or a net 59 Bcf long position. Of the net long position, basis swaps constitute a net 126 Bcf long position.

Fair Value Measurements (Details)

3 Months Ended

6 Months Ended

Jun. 30, 2017

USD ($)

Jun. 30, 2016

USD ($)

Jun. 30, 2017

USD ($)

Jun. 30, 2016

USD ($)

Dec. 31, 2016

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

(47,000,000)

^[1]

(47,000,000)

^[1]

$ (35,000,000)

^[2]

Total assets

233,000,000

83,000,000

Derivative fair value offsets, net

10,000,000

(14,000,000)

Liabilities

Total derivative liabilities, netting adjustment

(57,000,000)

^[1]

(57,000,000)

^[1]

(21,000,000)

^[2]

Total liabilities

24,000,000

46,000,000

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

Beginning balance

27,000,000

$ 15,000,000

13,000,000

$ 12,000,000

Purchases (1)

^[3]

12,000,000

Total gains

7,000,000

23,000,000

4,000,000

Total settlements

(11,000,000)

(4,000,000)

(16,000,000)

Transfers into Level 3

1,000,000

2,000,000

5,000,000

Transfers out of Level 3

(7,000,000)

(6,000,000)

(1,000,000)

Ending balance (2)

^[4]

28,000,000

16,000,000

28,000,000

16,000,000

The amount of total gains 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

$ 3,000,000

21,000,000

$ 11,000,000

Carrying Amount [Member]

Estimated Fair Value of FInancial Instruments

Long-term debt

2,528,000,000

2,375,000,000

Fair Value [Member]

Estimated Fair Value of FInancial Instruments

Long-term debt

2,738,000,000

$ 2,738,000,000

2,551,000,000

Atmos Energy Marketing [Member]

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

Mark-to-market value of Level 3 derivative assets acquired

less than $1 million

Natural gas derivatives [Member]

Assets

Derivative fair value offsets, net

10,000,000

$ 10,000,000

(14,000,000)

Fair Value, Inputs, Level 1 [Member]

Assets

Total assets

122,000,000

24,000,000

Liabilities

Total liabilities

2,000,000

4,000,000

Fair Value, Inputs, Level 2 [Member]

Assets

Total assets

125,000,000

74,000,000

Liabilities

Total liabilities

74,000,000

56,000,000

Fair Value, Inputs, Level 3 [Member]

Assets

Total assets

33,000,000

20,000,000

Liabilities

Total liabilities

5,000,000

$ 5,000,000

7,000,000

Fair Value, Inputs, Level 3 [Member] | Options Held [Member] | Minimum [Member]

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

Fair value options volatility rate

0.00%

Fair Value, Inputs, Level 3 [Member] | Options Held [Member] | Maximum [Member]

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

Fair value options volatility rate

80.00%

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

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

Fair value inputs (price per MMBtu)

1.18

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

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

Fair value inputs (price per MMBtu)

6.01

Fair Value, Measurements, Recurring [Member]

Assets

Corporate equities

3,000,000

$ 3,000,000

3,000,000

Investments, including money market funds (2)

^[5]

10,000,000

Hedged portion of natural gas inventory

107,000,000

Fair Value, Measurements, Recurring [Member] | Natural gas derivatives [Member]

Assets

Derivative asset, netting adjustment

^[6]

(47,000,000)

^[1]

(47,000,000)

^[1]

(35,000,000)

^[2]

Derivative assets

^[6]

113,000,000

70,000,000

Liabilities

Derivative liabilities, netting adjustment

^[6]

(57,000,000)

^[1]

(57,000,000)

^[1]

(21,000,000)

^[2]

Derivative liabilities

^[6]

24,000,000

46,000,000

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

Assets

Corporate equities

3,000,000

Investments, including money market funds (2)

^[5]

10,000,000

Hedged portion of natural gas inventory

107,000,000

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

Assets

Derivative asset

^[6]

2,000,000

11,000,000

Liabilities

Derivative liability

^[6]

2,000,000

4,000,000

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

Assets

Corporate equities

Investments, including money market funds (2)

^[5]

Hedged portion of natural gas inventory

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

Assets

Derivative asset

^[6]

125,000,000

74,000,000

Liabilities

Derivative liability

^[6]

74,000,000

56,000,000

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

Assets

Corporate equities

Investments, including money market funds (2)

^[5]

Hedged portion of natural gas inventory

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

Assets

Derivative asset

^[6]

33,000,000

20,000,000

Liabilities

Derivative liability

^[6]

$ 5,000,000

$ 7,000,000

[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 $10 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 $14 million held by CES from the same counterparties.
[3]	Mark-to-market value of Level 3 derivative assets acquired through the purchase of AEM was less than $1 million at the acquisition date.
[4]	CERC did not have significant Level 3 sales during either of the three or six months ended June 30, 2017 or 2016.
[5]	Amounts are included in Other Assets in the Condensed Consolidated Balance Sheets.
[6]	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

6 Months Ended

Nov. 22, 2016

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Dec. 31, 2016

Percentage sale of units which trigger right of first refusal

5.00%

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

CERC’s equity in earnings, net

$ 59

$ 31

$ 131

$ 91

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

CERC’s equity method investment in Enable

$ 2,487

$ 2,505

Enable Midstream Partners [Member]

Equity method investment limited partner interest in Enable

54.10%

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

Operating revenues

$ 626

529

$ 1,292

1,038

Cost of sales, excluding depreciation and amortization

279

254

587

449

Operating income

122

262

160

Net income attributable to Enable

197

121

CERC’s interest

107

Basis difference amortization (1)

^[1]

CERC’s equity in earnings, net

$ 131

Basis difference amortization period

33 years

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

Current assets

351

$ 351

396

Non-current assets

10,780

10,816

Current liabilities

298

362

Non-current liabilities

3,111

3,056

Non-controlling interest

Preferred equity

362

Enable partners’ capital

7,348

7,420

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

CERC’s ownership interest in Enable partners’ capital

4,025

4,067

CERC’s basis difference

(1,538)

(1,562)

CERC’s equity method investment in Enable

2,487

2,505

Distributions received from equity method investment

$ 149

149

Enable and ArcLight [Member]

Units sold in public offering

1,424,281

OGE [Member]

Percentage sale of units which trigger right of first refusal

5.00%

Enable Midstream Partners [Member]

Units sold in public offering

11,500,000

Enable Midstream Partners [Member]

Interest income related to notes receivable from Enable

$ 0

Enable Midstream Partners [Member]

Management rights ownership percentage

50.00%

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

Incentive distribution right

40.00%

Maximum incentive distribution right

50.00%

Enable Midstream Partners [Member] | OGE [Member]

Limited partner interest in Enable

25.70%

Management rights ownership percentage

50.00%

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

Incentive distribution right

60.00%

Minimum [Member] | Enable Midstream Partners [Member]

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

Incentive distribution per unit

$ 0.2875

Maximum [Member] | Enable Midstream Partners [Member]

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

Incentive distribution per unit

$ 0.330625

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

Natural gas expenses, including transportation and storage costs

$ 57

Accounts payable for natural gas purchases from Enable

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

Reimbursement of transition services (1)

^[2]

$ 2

$ 5

Accounts receivable for amounts billed for transition services

$ 1

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

Enable equity method investment units held

94,151,707

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

Enable units held

42,832,291

Subordinated Units [Member] | Enable Midstream Partners [Member]

Enable equity method investment units held

139,704,916

Subordinated Units [Member] | Enable Midstream Partners [Member] | OGE [Member]

Enable units held

68,150,514

[1]	Equity in earnings of unconsolidated affiliates includes CERC’s share of Enable’s earnings adjusted for the amortization of the basis difference of CERC’s original investment in Enable and its underlying equity in Enable’s net assets. The basis difference is amortized over approximately 33 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 (Details)
$ in Millions

6 Months Ended

Jun. 30, 2017

USD ($)

Goodwill [Line Items]

Goodwill, Beginning Balance

$ 862

Goodwill, Acquired During Period

^[1]

Goodwill, Ending Balance

867

Natural Gas Distribution [Member]

Goodwill [Line Items]

Goodwill, Beginning Balance

746

Goodwill, Acquired During Period

^[1]

Goodwill, Ending Balance

746

Energy Services [Member]

Goodwill [Line Items]

Goodwill, Beginning Balance

105

^[2]

Goodwill, Acquired During Period

^[1]

Goodwill, Ending Balance

110

^[2]

Goodwill, Impaired, Accumulated Impairment Loss

252

Other Operations [Member]

Goodwill [Line Items]

Goodwill, Beginning Balance

Goodwill, Acquired During Period

^[1]

Goodwill, Ending Balance

$ 11

[1]	See Note 3.
[2]	Amount presented is net of the accumulated goodwill impairment charge of $252 million recorded in 2012.

Related Party Transactions (Details) - USD ($)	3 Months Ended		6 Months Ended
Related Party Transactions (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Investments in the Money Pool	$ 0		$ 0		$ 0
CenterPoint Energy [Member] \| Operation And Maintenance Expense [Member]
Corporate service charges	32,000,000	$ 29,000,000	63,000,000	$ 59,000,000
CenterPoint Houston [Member] \| Operation And Maintenance Expense [Member]
Corporate service charges	5,000,000	3,000,000	8,000,000	7,000,000
Billings to Houston Electric for services provided	$ (1,000,000)	$ (2,000,000)	$ (3,000,000)	$ (3,000,000)

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

3 Months Ended

6 Months Ended

Jun. 30, 2017

Dec. 31, 2016

Debt Instrument [Line Items]

Size of credit facility

$ 900

^[1]

$ 900

^[1]

$ 600

Credit facility size increase

300

Short-term Debt [Line Items]

Short-term borrowings

Product Financing Arrangement [Member]

Short-term Debt [Line Items]

Short-term borrowings

$ 24

Line of Credit [Member]

Debt Instrument [Line Items]

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

65.00%

Ratio of indebtedness to net capital

0.371

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

Debt Instrument [Line Items]

Basis spread on LIBOR

^[2]

1.25%

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Long-term line of credit

$ 0

Letter of Credit [Member]

Debt Instrument [Line Items]

Long-term line of credit

Commercial Paper [Member]

Debt Instrument [Line Items]

Size of credit facility

900

Long-term line of credit

^[3]

$ 718

$ 569

Weighted average interest rate of debt

1.41%

1.03%

[1]	Amended on June 16, 2017 to increase the aggregate commitment size as noted above.
[2]	Based on current credit ratings.
[3]	Weighted average interest rate was approximately 1.41% and 1.03% as of June 30, 2017 and December 31, 2016, respectively.

Commitments and Contingencies (Details) $ in Millions	6 Months Ended
Commitments and Contingencies (Details) $ in Millions	Jun. 30, 2017 USD ($)
Minnesota Service Territory [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Liability recorded for remediation of Minnesota sites	$ 7
Minnesota Service Territory [Member] \| Minimum [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Estimated remediation costs for the Minnesota sites	$ 4
Years to resolve contingency	30 years
Minnesota Service Territory [Member] \| Maximum [Member]
LegalEnvironmentalAndOtherRegulatoryMattersLegalMattersGasMarketManipulationCasesAbstract
Estimated remediation costs for the Minnesota sites	$ 30
Years to resolve contingency	50 years
Natural Gas Supply Commitments [Member]
Recorded Unconditional Purchase Obligation Payment Schedule [Abstract]
Remaining six months of 2017	$ 227
2018	488
2019	334
2020	167
2021	75
2022 and beyond	$ 82

Income Taxes (Details)	3 Months Ended		6 Months Ended
Income Taxes (Details)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Effective income tax rate	35.00%	70.00%	37.00%	41.00%

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

3 Months Ended

6 Months Ended

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2017

Jun. 30, 2016

Dec. 31, 2016

Segment Reporting Information [Line Items]

Revenues from External Customers

$ 1,387

$ 807

$ 3,480

$ 2,127

Operating Income (Loss)

247

184

Total Assets

9,335

$ 9,218

Equity in earnings of unconsolidated affiliate, net

131

Natural Gas Distribution [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

470

414

1,377

1,302

Operating Income (Loss)

201

180

Energy Services [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

918

393

2,103

825

Operating Income (Loss)

Midstream Investments [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

^[1]

Operating Income (Loss)

^[1]

Other Operations [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

(1)

Operating Income (Loss)

(2)

(5)

(2)

Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

(20)

(11)

(40)

(25)

Total Assets

(644)

(563)

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

Segment Reporting Information [Line Items]

Revenues from External Customers

(7)

(16)

(14)

Intersegment Eliminations [Member] | Energy Services [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

(13)

(4)

(24)

(11)

Intersegment Eliminations [Member] | Midstream Investments [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

^[1]

Intersegment Eliminations [Member] | Other Operations [Member]

Segment Reporting Information [Line Items]

Revenues from External Customers

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

Segment Reporting Information [Line Items]

Total Assets

6,022

6,099

Operating Segments [Member] | Energy Services [Member]

Segment Reporting Information [Line Items]

Total Assets

1,388

1,102

Operating Segments [Member] | Midstream Investments [Member]

Segment Reporting Information [Line Items]

Total Assets

^[1]

2,487

2,505

Operating Segments [Member] | Other Operations [Member]

Segment Reporting Information [Line Items]

Total Assets

$ 75

Enable Midstream Partners [Member]

Segment Reporting Information [Line Items]

Equity in earnings of unconsolidated affiliate, net

131

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

Segment Reporting Information [Line Items]

Equity in earnings of unconsolidated affiliate, net

$ 59

$ 31

$ 131

$ 91

[1]	Midstream Investments’ equity earnings are as follows: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions)Enable $59 $31 $131 $91

Other Current Assets and Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Prepaid Expenses and Other Current Assets [Member]
Margin deposits	$ 19	$ 1
Under recovered gas costs	42	40
Other Current Liabilities [Member]
Over recovered gas costs	$ 5	$ 10

Subsequent Events (Details) - Enable Midstream Partners [Member] - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		6 Months Ended
	Jul. 31, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Subsequent Event [Line Items]
Expected cash distribution from equity method investment		$ 75	$ 75	$ 149	$ 149
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividends payable, date declared	Jul. 31, 2017
Quarterly cash distribution per unit declared	$ 0.318
Expected cash distribution from equity method investment	$ 74