View Filing Data

Non-trading derivative assets

862

840

Notes receivable — affiliated companies

363

Current portion of long-term debt

2,505

2,594

Other

206

146

Total other assets

3,592

3,979

Total Assets

^[1]

9,218

9,141

Current Liabilities:

Short-term borrowings

^[2]

^[2]

250

325

Accounts payable

471

307

Accounts and notes payable — affiliated companies

Taxes accrued

Interest accrued

Customer deposits

Non-trading derivative liabilities

Other

124

158

Total current liabilities

1,147

1,059

Other Liabilities:

Deferred income taxes, net

1,925

1,774

Non-trading derivative liabilities

Benefit obligations

104

Regulatory liabilities

769

734

Other

221

210

Total other liabilities

3,024

2,812

Long-Term Debt, net

2,125

2,016

^[3]

Commitments and Contingencies (Note 14)

Stockholder’s Equity:

Common stock

Paid-in capital

2,489

2,417

Retained earnings

430

828

Accumulated comprehensive income

Total stockholder’s equity

2,922

3,254

Total Liabilities And Stockholder’s Equity

$ 9,218

$ 9,141

[1]	Amounts for 2015 and 2014 have been restated to reflect the adoption of ASU 2015-03.
[2]	Includes amounts due or exchangeable within one year of the date noted.
[3]	Includes $12 million of unamortized debt issuance costs to reflect adoption of ASU 2015-03.

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Balance Sheets Parenthetical [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 14	$ 19

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities:
Net income (loss)	$ 245	$ (912)	$ 323
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	249	227	206
Amortization of deferred financing costs	9	9	9
Deferred income taxes	156	(542)	178
Write-down of natural gas inventory	1	4	8
Equity in (earnings) losses of unconsolidated affiliates, net of distributions	(208)	1,779	(2)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net	(122)	347	7
Accounts receivable/payable–affiliated companies	4	9	1
Inventory	34	35	(81)
Taxes receivable	0	0	18
Accounts payable	117	(221)	17
Fuel cost recovery	(72)	43	(41)
Interest and taxes accrued	7	58	(3)
Non-trading derivatives, net	29	(6)	(34)
Margin deposits, net	101	(4)	(79)
Other current assets	(19)	13	8
Other current liabilities	2	(11)	(6)
Other assets	(21)	(6)	(11)
Other liabilities	(2)	(5)	11
Other, net	1	(1)	6
Net cash provided by operating activities	511	816	535
Cash Flows from Investing Activities:
Capital expenditures	(517)	(606)	(512)
Acquisitions, net of cash acquired	(102)	0	0
Distributions from unconsolidated affiliates in excess of cumulative earnings	297	148	0
Decrease in notes receivable–affiliated companies	363	0	0
Investment in unconsolidated affiliates	0	0	(1)
Other, net	1	6	0
Net cash provided by (used in) investing activities	42	(452)	(513)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net	(5)	(13)	10
Proceeds from (payments of) commercial paper, net	350	(122)	223
Payments of long-term debt	(325)	0	0
Dividends to parent	(643)	(43)	(405)
Contribution from parent	72	0	0
Increase (decrease) in notes payable–affiliated companies	0	(188)	150
Other, net	(1)	0	1
Net cash used in financing activities	(552)	(366)	(21)
Net Increase (Decrease) in Cash and Cash Equivalents	1	(2)	1
Cash and Cash Equivalents at Beginning of the Year	0	2	1
Cash and Cash Equivalents at End of the Year	1	0	2
Cash Payments:
Interest, net of capitalized interest	116	125	128
Income taxes (refunds), net	3	6	(1)
Non-cash transactions:
Accounts payable related to capital expenditures	35	37	37
Exercise of SESH put to Enable	$ 0	$ 1	$ 196

STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Defined Benefit Plans Adjustment [Member]	Accumulated Other Comprehensive Loss [Member]
Balance (in shares) at Dec. 31, 2013		1,000
Balance at Dec. 31, 2013		$ 0	$ 2,416	$ 1,865
Contribution from parent			0
Other			1
Net income (loss)	$ 323			323
Dividend to parent				(405)
Balance at Dec. 31, 2014	4,201	$ 0	2,417	1,783	$ 1	$ 1
Balance (in shares) at Dec. 31, 2014		1,000
Contribution from parent			0
Other			0
Net income (loss)	(912)			(912)
Dividend to parent				(43)
Balance at Dec. 31, 2015	3,254	$ 0	2,417	828	9	9
Balance (in shares) at Dec. 31, 2015		1,000
Contribution from parent			72
Other			0
Net income (loss)	245			245
Dividend to parent				(643)
Balance at Dec. 31, 2016	$ 2,922	$ 0	$ 2,489	$ 430	$ 3	$ 3
Balance (in shares) at Dec. 31, 2016		1,000

Background

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background [Text Block]

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 11. CERC Corp.’s operating subsidiaries 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 31 states.

As of December 31, 2016, CERC Corp. also owned approximately 54.1% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

For a description of CERC’s reportable business segments, see Note 16.

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2016
Significant Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Summary of Significant Accounting Policies (a) Use of Estimates 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. (b) Principles of Consolidation The accounts of CERC Corp. and its wholly-owned and majority owned subsidiaries are included in CERC’s consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. CERC uses the equity method of accounting for investments in entities in which CERC has an ownership interest between 20% and 50% and exercises significant influence. CERC also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable. In 2013, CenterPoint Energy, OGE and affiliates of ArcLight, formed Enable as a private limited partnership. CenterPoint Energy has the ability to significantly influence the operating and financial policies of, but not solely control, Enable and, accordingly, recorded an equity method investment, at the historical costs of net assets contributed. Under the equity method, CERC adjusts its investment in Enable each period for contributions made, distributions received, CERC’s share of Enable’s comprehensive income and amortization of basis differences, as appropriate. CERC evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. CERC’s investment in Enable is considered to be a VIE because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CERC is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. Other investments, excluding marketable securities, are carried at cost. (c) Revenues CERC records revenue for natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. (d) Long-lived Assets and Intangibles CERC records property, plant and equipment at historical cost. CERC expenses repair and maintenance costs as incurred. CERC periodically evaluates long-lived assets, including property, plant and equipment and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, compared to the carrying value of the assets. (e) Regulatory Assets and Liabilities CERC applies the guidance for accounting for regulated operations to the Natural Gas Distribution business segment. CERC’s rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. CERC had current regulatory assets of $70 million and $21 million as of December 31, 2016 and 2015, respectively, included in other current assets in its Consolidated Balance Sheets. CERC had current regulatory liabilities of $11 million and $55 million as of December 31, 2016 and 2015, respectively, included in other current liabilities in its Consolidated Balance Sheets. CERC’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2016 and 2015, these removal costs of $665 million and $632 million, respectively, are classified as regulatory liabilities in the Consolidated Balance Sheets. In addition, a portion of the amount of removal costs that relate to AROs has been reclassified from a regulatory liability to an asset retirement liability in accordance with accounting guidance for AROs. (f) Depreciation and Amortization Expense Depreciation and amortization is computed using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of regulatory assets and other intangibles. (g) Capitalization of Interest and AFUDC Interest and AFUDC are capitalized as a component of projects under construction and are amortized over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates. During 2016, 2015 and 2014, CERC capitalized interest and AFUDC of $2 million, $2 million and $1 million, respectively. (h) Income Taxes CERC is a member of the U.S. federal consolidated income tax return of CenterPoint Energy. CERC reports its income tax provision on a separate entity basis pursuant to a tax sharing agreement with CenterPoint Energy. CERC uses the asset and liability method of accounting for deferred income taxes in accordance with accounting guidance for income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy. CERC recognizes interest and penalties as a component of income tax expense. CERC reports the income tax provision associated with its interest in Enable in Income tax expense (benefit) in its Statements of Consolidated Income. (i) Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2016, 2015 and 2014 was $7 million, $19 million and $20 million, respectively. (j) Inventory Inventory consists principally of materials and supplies and natural gas. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Energy Services business segment are valued at the lower of average cost or market. Natural gas inventories of CERC’s Natural Gas Distribution business segment are primarily valued at weighted average cost. During 2016, 2015 and 2014, CERC recorded $1 million, $4 million and $8 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market. (k) 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 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 normal 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 and 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. (l) Environmental Costs CERC expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. CERC expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. CERC records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. (m) Statements of Consolidated Cash Flows For purposes of reporting cash flows, CERC considers cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. CERC considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classifies these distributions as operating activities in the Statements of Consolidated Cash Flows. CERC considers distributions received from equity method investments in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and classifies these distributions as investing activities in the Statements of Consolidated Cash Flows. (n) New Accounting Pronouncements In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships. The changes include, among others, modification of the evaluation of whether limited partnerships and similar legal entities are VIEs or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. CERC adopted ASU 2015-02 on January 1, 2016, which did not have a material impact on its financial position, results of operations, cash flows and disclosures. In April 2015, the FASB issued ASU No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CERC adopted ASU 2015-03 retrospectively on January 1, 2016, which resulted in a reduction of other long-term assets, indexed debt and total long-term debt on its Consolidated Balance Sheets. CERC had debt issuance costs, excluding amounts related to credit facility arrangements, of $10 million and $12 million as a reduction to long-term debt on its Consolidated Balance Sheets as of December 31, 2016 and 2015, respectively. In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07). ASU 2015-07 removes the requirement to categorize within the fair value hierarchy investments for which fair values are measured at NAV using the practical expedient. Entities will be required to disclose the fair value of investments measured using the NAV practical expedient so that financial statement users can reconcile amounts reported in the fair value hierarchy table to amounts reported on the balance sheet. CERC retrospectively adopted ASU 2015-07 on January 1, 2016, which impacts its employee benefit plan disclosures. See Note 7 for the impacts on the employee benefit plan disclosures. This standard did not have an impact on CERC’s financial position, results of operations or cash flows. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, an acquirer would recognize a measurement-period adjustment during the period in which the amount of the adjustment is determined. CERC prospectively adopted ASU 2015-16 on January 1, 2016, which did not have an impact on its financial position, results of operations or cash flows. 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 is currently assessing the impact that this standard will have 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 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 not 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 based, which we do not anticipate will be significantly impacted by these ASUs. CERC is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts when collectability is uncertain and its accounting for contributions in aid of construction. CERC expects to adopt these ASUs on January 1, 2018 and is evaluating the method of adoption. 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. 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. (o) Other Current Assets and Liabilities Included in other current assets on the Consolidated Balance Sheets as of December 31, 2016 and 2015 were less than $1 million and $31 million, respectively, of margin deposits and $40 million and $12 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets as of December 31, 2016 and 2015 were $10 million and $55 million, respectively, of over-recovered gas cost.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

Property, Plant and Equipment

(a) Property, Plant and Equipment

Property, plant and equipment includes the following:



	Weighted Average Useful Lives	December 31,
	(in years)	2016		2015
		(in millions)
Natural Gas Distribution	32	$	6,219	$	5,762
Energy Services	25	83		86
Other property	9	49		50
Total		6,351		5,898
Accumulated depreciation and amortization:
Natural Gas Distribution		1,722		1,575
Energy Services		29		34
Other property		31		31
Total accumulated depreciation and amortization		1,782		1,640
Property, plant and equipment, net		$	4,569	$	4,258

(b) Depreciation and Amortization

The following table presents depreciation and amortization expense for 2016, 2015 and 2014:



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Depreciation expense	$	230	$	211	$	195
Amortization expense	19		16		11
Total depreciation and amortization expense	$	249	$	227	$	206

A reconciliation of the changes in the ARO liability is as follows:



	December 31,
	2016		2015
	(in millions)
Beginning balance	$	156	$	139
Accretion expense	8		5
Revisions in estimates of cash flows	5		12
Ending balance	$	169	$	156

CERC recorded AROs associated with the removal of asbestos and asbestos-containing material in its buildings. CERC also recorded AROs relating to gas pipelines abandoned in place. The estimates of future liabilities were developed using historical information, and where available, quoted prices from outside contractors.

The increase of $5 million in the ARO from the revision in estimates in 2016 is primarily attributable to an increase in the labor rate associated with the abandonment of gas mains. The increase of $12 million in the ARO from the revision in estimates in 2015 is primarily attributable to a reduction in the estimated service lives of steel and plastic pipe. There were no material additions or settlements during the years ended December 31, 2016 or 2015.

Acquisition

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisition [Text Block]

Acquisition

On April 1, 2016, CES, a wholly-owned subsidiary of CERC, closed the previously announced agreement to acquire the retail energy services business and natural gas wholesale assets of Continuum. After working capital adjustments, the final purchase price was $102 million and 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	$	102
Receivables	$	76
Derivative assets	38
Property and equipment	1
Identifiable intangibles	38
Total assets acquired	153
Accounts payable	49
Derivative liabilities	24
Total liabilities assumed	73
Identifiable net assets acquired	80
Goodwill	22
Net assets acquired	$	102

The goodwill of $22 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, along with the scale, geographic reach and expanded capabilities.

Identifiable intangible assets were recorded at estimated fair value as determined by management based on available information, which includes a 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:



	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	34	15
Covenants not to compete	4		4
Total identifiable intangibles	$	38

Amortization expense related to the above identifiable intangible assets was $3 million for the year ended December 31, 2016.

Revenues of approximately $466 million and operating income of approximately $1 million attributable to the acquisition are included in CERC’s Statements of Consolidated Income for the year ended December 31, 2016.

As Continuum was a non-public company that did not prepare interim financial information and the acquisition included the purchase of both businesses and assets, the historical financial information for the businesses and assets acquired was impracticable to obtain. As a result, pro forma results of the acquired businesses and assets are not presented.

Goodwill and Intangible Assets Disclosure [Abstract]

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Goodwill

12 Months Ended

Dec. 31, 2016

Goodwill [Text Block]

Goodwill

Goodwill by reportable business segment as of December 31, 2015 and changes in the carrying amount of goodwill as of December 31, 2016 are as follows:



	December 31, 2015			Continuum Acquisition (1)		December 31, 2016
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	83		(2)	22		105		(2)
Other Operations	11			—		11
Total	$	840		$	22	$	862


(1)	See Note 4.


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

CERC performs goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

CERC performed its annual goodwill impairment test in the third quarter of each of 2016 and 2015 and determined, based on the results of the first step, that no goodwill impairment charge was required for any reportable segment. Other intangibles were not material as of December 31, 2016 and 2015.

Regulatory Accounting [Text Block]

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

Regulatory Accounting

12 Months Ended

Dec. 31, 2016

Regulatory Matters [Abstract]

Regulatory Accounting

The following is a list of regulatory assets/liabilities reflected on CERC’s Consolidated Balance Sheets as of December 31, 2016 and 2015:



	December 31,
	2016			2015
	(in millions)
Regulatory assets in other long-term assets (1)	$	125		$	105
Regulatory liabilities	(769		)	(734		)
Net	$	(644	)	$	(629	)

(1)

NGD’s actuarially determined pension and other postemployment expense in excess of the amount being recovered through rates is being deferred for rate making purposes. Deferred pension and other postemployment expenses of $6 million and $5 million as of December 31, 2016 and 2015, respectively, were not earning a return. Other regulatory assets that are not earning a return were not material as of December 31, 2016 or 2015.

Employee Benefit Plans

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans [Text Block]

Employee Benefit Plans

(a) Pension Plans

Substantially all of CERC’s employees participate in CenterPoint Energy’s qualified non-contributory defined benefit pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 5% of eligible earnings and accrued interest.

CenterPoint Energy’s funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to CERC based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy’s participating subsidiaries. CERC recognized pension expense of $35 million, $24 million and $27 million for the years ended December 31, 2016, 2015 and 2014, respectively.

In addition to the plan, CERC participates in CenterPoint Energy’s non-qualified benefit restoration plans, which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s non-contributory pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with the non-qualified pension plan was $3 million, $2 million and $2 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(b) Savings Plan

CERC participates in CenterPoint Energy’s qualified savings plan, which includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended. Under the plan, participating employees may contribute a portion of their compensation, on a pre-tax or after-tax basis, generally up to a maximum of 50% of eligible compensation. CERC matches 100% of the first 6% of each employee’s compensation contributed. The matching contributions are fully vested at all times.

Participating employees may elect to invest all (prior to January 1, 2016) or a portion of their contributions to the plan in CenterPoint Energy, Inc. common stock, to have dividends reinvested in additional shares or to receive dividend payments in cash on any investment in CenterPoint Energy, Inc. common stock, and to transfer all or part of their investment in CenterPoint Energy, Inc. common stock to other investment options offered by the plan.

Effective January 1, 2016 the savings plan was amended to limit the percentage of future contributions that could be invested in CenterPoint Energy, Inc. common stock to 25% and to prohibit transfers of account balances where the transfer would result in more than 25% of a participant’s total account balance invested in CenterPoint Energy, Inc. common stock.

The savings plan has significant holdings of CenterPoint Energy, Inc. common stock. As of December 31, 2016, 14,216,986 shares of CenterPoint Energy, Inc. common stock were held by the savings plan, which represented approximately 17% of its investments. Given the concentration of the investments in CenterPoint Energy, Inc. common stock, the savings plan and its participants have market risk related to this investment.

CenterPoint Energy allocates to CERC the savings plan benefit expense related to CERC’s employees. Savings plan benefit expense was $16 million, $14 million and $20 million for the years ended December 31, 2016, 2015 and 2014, respectively.

CERC’s employees participate in CenterPoint Energy’s plans, which provide certain healthcare and life insurance benefits for retired employees on both a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Such benefit costs are accrued over the active service period of employees. CERC is required to fund a portion of its obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.

The net postretirement benefit cost includes the following components:



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	4			5			5
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	—			1			1
Amortization of net loss	1			1			1
Curtailment (1)	(1		)	—			—
Net postretirement benefit cost	$	4		$	7		$	7


(1)	Effective January 1, 2017, a change in retiree medical coverage for Medicare eligible post-65 retirees from self-insured to a Medicare Advantage Program, an insured benefit, was implemented. A curtailment gain was recognized in October 2016 related to this implementation.

CERC used the following assumptions to determine net postretirement benefit costs:



	Year Ended December 31,
	2016		2015		2014
Discount rate	4.35	%	3.90	%	4.75	%
Expected return on plan assets	3.95	%	4.05	%	3.10	%

In determining net periodic benefits cost, CERC uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets.

Following are reconciliations of CERC’s beginning and ending balances of its postretirement benefit plan’s benefit obligation, plan assets and funded status for 2016 and 2015. The measurement dates for plan assets and obligations were December 31, 2016 and 2015.



	December 31,
	2016			2015
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	101		$	126
Service cost	1			1
Interest cost	4			5
Benefits paid	(13		)	(12		)
Participant contributions	5			4
Medicare reimbursement	1			1
Plan amendment (1)	10			(5		)
Actuarial (gain) loss	6			(19		)
Accumulated benefit obligation, end of year	$	115		$	101
Change in Plan Assets
Plan assets, beginning of year	$	25		$	26
Benefits paid	(13		)	(12		)
Employer contributions	7			7
Participant contributions	5			4
Actual investment return	1			—
Plan assets, end of year	$	25		$	25
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(4	)	$	(6	)
Other liabilities-benefit obligations	(86		)	(70		)
Net liability, end of year	$	(90	)	$	(76	)
Actuarial Assumptions
Discount rate	4.15		%	4.35		%
Expected long-term return on assets	3.60		%	3.95		%
Healthcare cost trend rate assumed for the next year - Pre 65	5.75		%	6.00		%
Healthcare cost trend rate assumed for the next year - Post 65	10.65		%	5.50		%
Prescription cost trend rate assumed for the next year	10.75		%	11.00		%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.50		%	5.00		%
Year that the healthcare rate reaches the ultimate trend rate	2024			2024
Year that the prescription drug rate reaches the ultimate trend rate	2024			2024


(1)	The postretirement plan was amended in 2016 to change the retiree medical coverage for Medicare eligible post-65 retirees from self-insured to a Medicare Advantage Program, an insured benefit which became effective January 1, 2017.

The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.

The expected rate of return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and the expected return for each asset class, based on the long-term capital market assumptions, adjusted for investment fees and diversification effects, in addition to expected inflation.

For measurement purposes, medical costs are assumed to increase to 5.75% and 10.65% for the pre-65 and post-65 retirees during 2017, respectively, and the prescription cost is assumed to increase to 10.75% during 2017, after which these rates decrease until reaching the ultimate trend rate of 4.50% in 2024.

CERC’s changes in accumulated comprehensive income (loss) related to postretirement and other postemployment plans are as follows:



	Year Ended December 31,
	2016			2015
	(in millions)
Beginning Balance	$	9		$	1
Other comprehensive income (loss) before reclassifications (1)	(10		)	13
Amounts reclassified from accumulated other comprehensive income:
Actuarial gains (2)	—			1
Tax benefit (expense)	4			(6		)
Net current period other comprehensive income (loss)	(6		)	8
Ending Balance	$	3		$	9


(1)	Total other comprehensive income (loss) related to the remeasurement of pension, postretirement and other postemployment plans.


(2)	These accumulated other comprehensive components are included in the computation of net periodic cost.

Amounts recognized in accumulated other comprehensive (income) loss consist of the following:



	December 31,
	2016			2015
	(in millions)
Unrecognized actuarial loss	$	5		$	3
Unrecognized prior service cost (credit)	7			(1		)
Total recognized in accumulated other comprehensive loss	12			2
Less: deferred tax benefit (1)	(15		)	(11		)
Net amount recognized in accumulated other comprehensive income	$	(3	)	$	(9	)


(1)	CERC’s postretirement benefit obligation is reduced by the impact of previously non-taxable government subsidies under the Medicare Prescription Drug Act. Because the subsidies were non-taxable, the temporary difference used in measuring the deferred tax impact was determined on the unrecognized losses excluding such subsidies.

The changes in plan assets and benefit obligations recognized in other comprehensive loss during 2016 are as follows:



	Postretirement Benefits
	(in millions)
Net loss	$	2
Amortization of prior service cost	8
Total recognized in other comprehensive loss	$	10

The total expense recognized in net periodic costs and other comprehensive gains was $14 million for postretirement benefits for the year ended December 31, 2016.

CERC expects to recognize $1 million of amortization of prior service cost in accumulated other comprehensive loss as components of net periodic benefit cost during 2017.

Assumed healthcare cost trend rates have a significant effect on the reported amounts for CERC’s postretirement benefit plans. A 1% change in the assumed healthcare cost trend rate would have the following effects:



	1% Increase		1% Decrease
	(in millions)
Effect on the postretirement benefit obligation	$	4	$	4
Effect on the total of service and interest cost	—		—

In managing the investments associated with the postretirement benefit plan, CERC’s objective is to preserve and enhance the value of plan assets while maintaining an acceptable level of volatility. These objectives are expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.

As part of the investment strategy discussed above, CERC maintained the following asset allocation ranges for its postretirement benefit plan as of December 31, 2016:



U.S. equity	15–25%
International equity	2–12%
Fixed income	68–78%
Cash	0–2%

The fair values of CERC’s postretirement plan assets at December 31, 2016 and 2015, by asset category are as follows:



	Fair Value Measurements as of December 31, 2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Mutual funds (1)	$	25	$	—	$	—	$	25
Total	$	25	$	—	$	—	$	25


(1)	73% of the amount invested in mutual funds was in fixed income securities; 20% was in U.S. equities and 7% was in international equities.



	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Mutual funds (1)	$	25	$	—	$	—	$	25
Total	$	25	$	—	$	—	$	25


(1)	70% of the amount invested in mutual funds was in fixed income securities; 23% was in U.S. equities and 7% was in international equities.

CERC expects to contribute $5 million to its postretirement benefits plan in 2017. The following benefit payments are expected to be made by the postretirement benefit plan:



	Benefit Payments
	(in millions)
2017	$	5
2018	6
2019	7
2020	8
2021	8
2022-2026	43

(d) Postemployment Benefits

CERC participates in CenterPoint Energy’s plan that provides postemployment benefits for certain former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily healthcare and life insurance benefits for participants in the long-term disability plan). CERC recorded postemployment benefit expense of $3 million, $4 million and $2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Amounts relating to postemployment benefits included in Benefit Obligations in the accompanying Consolidated Balance Sheets as of both December 31, 2016 and 2015 were $14 million.

(e) Other Non-Qualified Plans

CERC participates in CenterPoint Energy’s deferred compensation plans that provide benefits payable to directors, officers and certain key employees or their designated beneficiaries at specified future dates, upon termination, retirement or death. Benefit payments are made from the general assets of CERC. During 2016, 2015 and 2014, the benefit expense relating to these plans was less than $1 million each year. Amounts relating to deferred compensation plans included in Benefit Obligations in the accompanying Consolidated Balance Sheets as of both December 31, 2016 and 2015 were $3 million.

(f) Other Employee Matters

As of December 31, 2016, approximately 34% of CERC’s employees were covered by collective bargaining agreements. The collective bargaining agreement with the Professional Employees International Union Local 12, which covers approximately 3% of CERC’s employees, expired in May of 2016. CERC successfully negotiated the follow-on agreement in 2016. The new collective bargaining agreement with the Professional Employees International Union Local 12 expires in May of 2021.

The collective bargaining agreements with Gas Workers Union, Local 340 and the IBEW, Local 949, covering approximately 19% of CERC’s employees, will expire in April and December of 2020, respectively. These two agreements were last negotiated in 2015.

The two collective bargaining agreements with the United Steelworkers Union, Locals 13-227 and 13-1, which cover approximately 12% of CERC’s employees, are scheduled to expire in June and July of 2017, respectively. CERC believes it has good relationships with these bargaining units and expects to negotiate new agreements in 2017.

Related Party Transactions

12 Months Ended

Dec. 31, 2016

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 December 31, 2016 and December 31, 2015, which are included in accounts and notes receivable–affiliated companies in the Consolidated Balance Sheets. Affiliate related net interest income (expense) was not material for the years ended December 31, 2016, 2015 and 2014.

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 from CERC for these services were as follows and are included primarily in operation and maintenance expenses:



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Corporate service charges	$	125		$	118		$	115

Charges from Houston Electric for services provided	15			18			17

Billings to Houston Electric for services provided	(7		)	(6		)	(5		)
	$	133		$	130		$	127

Dividends of $643 million, $43 million and $405 million were paid to the parent in 2016, 2015 and 2014, respectively.

See Note 11 for related party transactions with Enable.

Derivative Instruments

12 Months Ended

Dec. 31, 2016

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.

(a) Non-Trading Activities

Derivative Instruments. CERC enters into certain derivative instruments to mitigate the effects of commodity price movements. These 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 compared to NGD’s other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas.

CERC has historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season, which contained a bilateral dollar cap of $16 million in 2014–2015. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. The swaps are based on 10-year normal weather. During the years ended December 31, 2016, 2015 and 2014, CERC recognized losses of $-0-, $4 million and $10 million, respectively, related to these swaps. Weather hedge gains and losses are included in revenues in the Statements of Consolidated Income.

(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 December 31, 2016 and 2015, while the last table provides a breakdown of the related income statement impacts for the years ending December 31, 2016, 2015 and 2014.



Fair Value of Derivative Instruments
	December 31, 2016
Total 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		$	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 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 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 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.



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 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, 2015
Total 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	$	90	$	2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	36		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	10		60
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	4		25
Total		$	140	$	87


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 767 Bcf or a net 112 Bcf long position. Of the net long position, basis swaps constitute 133 Bcf.

(2)

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts 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 Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $109 million asset as shown on CERC’s 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 $56 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
	December 31, 2015
	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	$	100		$	(11	)	$	89
Other Assets: Non-trading derivative assets	40			(4		)	36
Current Liabilities: Non-trading derivative liabilities	(62		)	51			(11		)
Other Liabilities: Non-trading derivative liabilities	(25		)	20			(5		)
Total	$	53		$	56		$	109


(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 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 Statements of Consolidated Income as revenue for retail sales derivative contracts and as natural gas expense for financial natural gas derivatives and non-retail related physical natural gas derivatives.



Income Statement Impact of Derivative Activity
		Year Ended December 31,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	(18	)	$	134		$	35
Natural gas derivatives	Gains (Losses) in Expense: Natural Gas	70			(105		)	11
Total		$	52		$	29		$	46

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 December 31, 2016 and 2015 was $1 million and $3 million, respectively. CERC posted no assets as collateral towards derivative instruments that contain credit risk contingent features as of either December 31, 2016 or 2015. If all derivative contracts (in a net liability position) containing credit risk contingent features were triggered at December 31, 2016 and 2015, $-0- and $2 million, respectively, of additional assets would be required to be posted as collateral.

(d) Credit Quality of Counterparties

In addition to the risk associated with price movements, credit risk is also inherent in CERC’s non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of counterparties to the non-trading derivative assets of CERC as of December 31, 2016 and 2015:



	December 31, 2016					December 31, 2015
	Investment Grade(1)		Total			Investment Grade(1)		Total
	(in millions)
Energy marketers	$	1	$	4		$	4	$	10
Financial institutions	33		33			—		—
End users (2)	2		47			2		115
Total	$	36	$	84	(3)	$	6	$	125


(1)	“Investment grade” is primarily determined using publicly available credit ratings, and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis, and considers contractual rights and restrictions and collateral.


(2)	End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.


(3)	The net of total non-trading natural gas derivative assets was $70 million and $125 million as of December 31, 2016 and 2015, respectively, as shown on CERC’s Consolidated Balance Sheets, and was comprised of the natural gas contracts derivatives assets separately shown above, impacted by collateral netting of $14 million and $-0- as of December 31, 2016 and 2015, respectively.

Fair Value Measurements [Text Block]

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.

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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Assets and liabilities that are recorded at fair value in the 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.

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. At December 31, 2016, 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 $2.24 to $7.01 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 86%) as an unobservable input. CERC’s Level 3 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 year ended December 31, 2016, 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 and indicate the fair value hierarchy of the valuation techniques utilized by CERC to determine such fair value.



	December 31, 2016
	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
	(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 Consolidated Balance Sheets.


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



	December 31, 2015
	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
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	4		115		21		(15		)	125
Total assets	$	17	$	115	$	21	$	(15	)	$	138
Liabilities
Natural gas derivatives (3)	$	13	$	65	$	9	$	(71	)	$	16
Total liabilities	$	13	$	65	$	9	$	(71	)	$	16


(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 $56 million posted with the same counterparties.


(2)	Amounts are included in Other Assets in the 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
	Year Ended December 31,
	2016			2015			2014
	(in millions)
Beginning balance	$	12		$	17		$	3
Purchases	12			—			—
Total gains	12			7			14
Total settlements	(27		)	(12		)	1
Transfers out of Level 3	(1		)	(1		)	—
Transfers into Level 3	5			1			(1		)
Ending balance (1)	$	13		$	12		$	17
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	$	11		$	6		$	16


(1)	During 2016, 2015 and 2014, CERC did not have significant Level 3 sales.

Items Measured at Fair Value on a Nonrecurring Basis

In 2015, CERC determined that an other than temporary decrease in the value of its investment in Enable had occurred and, using multiple valuation methodologies under both the market and income approaches, recorded an impairment on its investment in Enable of $1,225 million. Key assumptions in the market approach included recent market transactions of comparable companies and EBITDA to total enterprise multiples for comparable companies. Due to volatility of the quoted price of Enable’s units at the valuation date, a volume weighted average price was used under the market approach to best approximate fair value at the measurement date. Key assumptions in the income approach included Enable’s forecasted cash distributions, projected cash flows of incentive distribution rights, forecasted growth rate of Enable’s cash distributions beyond 2020, and the discount rate used to determine the present value of the estimated future cash flows. A weighing of the different approaches was utilized to determine the estimated fair value of our investment in Enable. Based on the significant unobservable estimates and assumptions required, CERC concluded that the fair value estimate should be classified as a Level 3 measurement within the fair value hierarchy. See Note 11 for further discussion of the impairments. As of December 31, 2016, there were no significant assets or liabilities measured at fair value on a nonrecurring basis.

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 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.



	December 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	—	$	—	$	363	$	356
Financial liabilities:
Long-term debt	$	2,375	$	2,551	$	2,341	$	2,539

Equity Method Investments and Joint Ventures [Abstract]

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 Affiliates

12 Months Ended

Dec. 31, 2016

Unconsolidated Affiliates [Text Block]

Unconsolidated Affiliates

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. See Note 2 for information on the formation of Enable.

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 Consolidated Balance Sheet as of December 31, 2016 and outstanding current accounts receivable from Enable. In connection with CenterPoint Energy’s purchase of Series A Preferred Units from Enable, Enable redeemed $363 million of notes owed to a wholly-owned subsidiary of CERC Corp., which bore interest at an annual rate of 2.10% to 2.45%.

Effective on the Formation Date, CenterPoint Energy and Enable entered into the Transition Agreements. Under the Services Agreement, CERC agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term, which ended on April 30, 2016. CERC is providing certain services to Enable on a year-to-year basis. Enable may terminate (i) the entire Services Agreement with at least 90 days’ notice prior to the end of any extension term, or (ii) either any service provided under the Services Agreement, or the entire Services Agreement, at any time upon approval by its board of directors and with at least 180 days’ notice.

CERC provided seconded employees to Enable to support its operations for a term ending on December 31, 2014. Enable, at its discretion, had the right to select and offer employment to seconded employees from CERC. During the fourth quarter of 2014, Enable notified CERC that it selected seconded employees and provided employment offers to substantially all of the seconded employees from CERC. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.

In accordance with the Enable formation agreements, CERC had certain put rights, and Enable had certain call rights, exercisable with respect to the 25.05% interest in SESH retained by CenterPoint Energy. As of June 30, 2015, CERC’s remaining interest in SESH was transferred to Enable.

Transactions with Enable:



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Reimbursement of transition services (1)	$	7	$	16	$	163
Natural gas expenses, including transportation and storage costs	110		117		130
Interest income related to notes receivable from Enable	1		8		8


(1)	Represents amounts billed under the Transition Agreements, including the costs of seconded employees. Actual transition services costs are recorded net of reimbursement.



	Year Ended December 31,
	2016		2015
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	3
Interest receivable related to notes receivable from Enable	—		4
Accounts payable for natural gas purchases from Enable	10		11

CERC evaluates its equity method investments for impairment when factors indicate that a decrease in the value of its investment has occurred and the carrying amount of its investment may not be recoverable. An impairment loss, based on the excess of the carrying value over estimated fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Based on the sustained low Enable common unit price and further declines in such price during the year ended December 31, 2015, as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas industry, CERC determined that an other than temporary decrease in the value of its equity method investment in Enable had occurred. CERC wrote down the value of its equity method investment in Enable to its estimated fair value which resulted in impairment charges of $1,225 million for the year ended December 31, 2015. Both the income approach and market approach were utilized to estimate the fair value of CERC’s total investment in Enable, which includes the limited partner common and subordinated units, general partner interest and incentive distribution rights held by CERC. The determination of fair value considered a number of relevant factors including Enable’s common unit price and forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. See Note 10 for further discussion of the determination of fair value of CERC’s equity method investment in Enable in 2015.

As of December 31, 2016, the carrying value of CERC’s equity method investment in Enable was $10.71 per unit, which includes limited partner common and subordinated units, a general partner interest and incentive distribution rights. On December 31, 2016, Enable’s common unit price closed at $15.73. There was no impairment indicated in 2016.

Investment in Unconsolidated Affiliates:



	As of December 31,
	2016		2015
	(in millions)
Enable	$	2,505	$	2,594

Equity in Earnings (Losses) of Unconsolidated Affiliates, net:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Enable	$	208	$	(1,633	)	$	303
SESH (1)	—		—			5
Total	$	208	$	(1,633	)	$	308


(1)	CERC contributed a 24.95% interest in SESH to Enable on May 30, 2014 and its remaining 0.1% interest in SESH to Enable on June 30, 2015.

Limited Partner Interest in Enable:



	As of December 31,
	2016			2015		2014
CenterPoint Energy	54.1	%	(1)	55.4	%	55.4	%
OGE	25.7	%		26.3	%	26.3	%


(1)	In November 2016, Enable closed a public offering of 10,000,000 common units. In connection with the offering, Enable and an affiliate of ArcLight sold an additional combined 1,500,000 common units to the underwriters.

Enable Common and Subordinated Units Held:

Sales of more than 5% of the aggregate of the common units and subordinated units we own 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 our 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 we are not permitted to dispose of less than all of our interest in Enable’s general partner.

Summarized consolidated income (loss) information for Enable is as follows:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Operating revenues	$	2,272	$	2,418		$	3,367
Cost of sales, excluding depreciation and amortization	1,017		1,097			1,914
Impairment of goodwill and other long-lived assets	9		1,134			8
Operating income (loss)	385		(712		)	586
Net income (loss) attributable to Enable	290		(752		)	530

Reconciliation of Equity in Earnings (Losses), net:
CERC’s interest	$	160	$	(416	)	$	298
Basis difference amortization (1)	48		8			5
Impairment of CERC’s equity method investment in Enable	—		(1,225		)	—
CERC’s equity in earnings (losses), net (2)	$	208	$	(1,633	)	$	303


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


(2)	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Summarized consolidated balance sheet information for Enable is as follows:



	December 31,
	2016			2015
	(in millions)
Current assets	$	396		$	381
Non-current assets	10,816			10,845
Current liabilities	362			615
Non-current liabilities	3,056			3,080
Non-controlling interest	12			12
Preferred equity	362			—
Enable partners’ capital	7,420			7,519

Reconciliation of Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,067		$	4,163
CERC’s basis difference	(1,562		)	(1,569		)
CERC’s investment in Enable	$	2,505		$	2,594

Distributions Received from Unconsolidated Affiliates:



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Investment in Enable’s common and subordinated units	$	297	$	294	$	298
Interest in SESH (1)	—		—		7
Total	$	297	$	294	$	305


(1)	CERC contributed a 24.95% interest in SESH to Enable on May 30, 2014 and its remaining 0.1% interest in SESH to Enable on June 30, 2015.

As of December 31, 2016, 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.

Short-term Borrowings and Long-term Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

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

Short-term Borrowings and Long-term Debt



	December 31, 2016					December 31, 2015
	Long-Term			Current (1)		Long-Term (2)			Current (1)
	(in millions)
Short-term borrowings:
Inventory financing (3)	$	—		$	35	$	—		$	40
Total short-term borrowings	—			35		—			40
Long-term debt:
Senior notes 4.50% to 6.625% due 2017 to 2041	1,593			250		1,843			325
Commercial paper (4)	569			—		219			—
Unamortized debt issuance costs	(10		)	—		(12		)	—
Unamortized discount and premium	(27		)	—		(34		)	—
Total long-term debt	2,125			250		2,016			325
Total debt	$	2,125		$	285	$	2,016		$	365


(1)	Includes amounts due or exchangeable within one year of the date noted.


(2)	Includes $12 million of unamortized debt issuance costs to reflect adoption of ASU 2015-03.

(3)

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.


(4)	Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

CERC’s short-term borrowings from the money pool are not reflected in the table above. For information regarding CERC’s money pool borrowings, please see Note 8.

Long-term Debt

Debt Retirements. In May 2016, CERC retired approximately $325 million aggregate principal amount of its 6.15% senior notes at their maturity. The retirement of senior notes was financed by the issuance of commercial paper.

Revolving Credit Facility. As of December 31, 2016 and 2015, CERC had the following revolving credit facility and utilization of such facility:



		December 31, 2016							December 31, 2015
Size of Facility		Loans		Letters of Credit		Commercial Paper			Loans		Letters of Credit		Commercial Paper
(in millions)
$	600	$	—	$	4	$	569	(1)	$	—	$	2	$	219	(1)


(1)	Weighted average interest rate was approximately 1.03% and 0.81% as of December 31, 2016 and 2015, respectively.

Execution Date

Size of

Facility

Draw Rate of LIBOR plus (1)

Financial Covenant Limit on Debt to Capital Ratio

Debt to Capital

Ratio as of December 31, 2016

Termination Date

(in millions)

March 3, 2016

600

1.25%

65%

35.8%

March 3, 2021


(1)	Based on current credit ratings.

CERC Corp. was in compliance with all financial covenants in its revolving credit facility as of December 31, 2016.

Maturities. CERC Corp. has the following long-term debt maturities:



	(in millions)
2017	$	250
2018	300
2019	—
2020	—
2021	1,162

Income Taxes

12 Months Ended

Dec. 31, 2016

Income Taxes [Abstract]

Income Taxes [Text Block]

Income Taxes

The components of CERC’s income tax expense (benefit) were as follows:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Current income tax expense:
State	$	6	$	3		$	10
Total current expense	6		3			10
Deferred income tax expense (benefit):
Federal	130		(488		)	171
State	26		(54		)	7
Total deferred expense (benefit)	156		(542		)	178
Total income tax expense (benefit)	$	162	$	(539	)	$	188

A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Income (loss) before income taxes	$	407		$	(1,451	)	$	511
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense (benefit)	142			(508		)	179
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	17			(33		)	11
State valuation allowance, net of federal income tax	3			—			—
Other, net	—			2			(2		)
Total	20			(31		)	9
Total income tax expense (benefit)	$	162		$	(539	)	$	188
Effective tax rate	40		%	37		%	37		%

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:



	December 31,
	2016			2015
	(in millions)
Deferred tax assets:
Benefits and compensation	$	45		$	39
Loss and credit carryforwards	451			388
AROs	64			59
Other	18			39
Valuation allowance	(5		)	(2		)
Total deferred tax assets	573			523
Deferred tax liabilities:
Property, plant, and equipment	1,017			929
Investment in unconsolidated affiliates	1,383			1,277
Regulatory assets/liabilities, net	8			—
Other	90			91
Total deferred tax liabilities	2,498			2,297
Net deferred tax liabilities	$	1,925		$	1,774

CERC is a member of the U.S. federal consolidated income tax return of CenterPoint Energy. CERC reports its income tax provision on a separate entity basis pursuant to a tax sharing agreement with CenterPoint Energy.

Tax Attribute Carryforwards and Valuation Allowance. CERC has $1.1 billion of federal net operating loss carryforwards that begin to expire in 2031. CERC has $958 million of state net operating loss carryforwards that expire between 2017 and 2036, $11 million of state tax credits that do not expire and $244 million of state capital loss carryforwards that expire in 2017. CERC reported a tax-effected valuation allowance of $5 million because it is more likely than not that the benefit from certain state carryforwards will not be realized.

Uncertain Income Tax Positions. CERC reported no uncertain tax liability as of December 31, 2016, 2015 and 2014. We expect no significant change to the uncertain tax liability over the next twelve months ending December 31, 2017.

Tax Audits and Settlements. Tax years through 2014 have been audited and settled with the IRS. For the 2015, 2016 and 2017 tax years, CenterPoint Energy is a participant in the IRS’s Compliance Assurance Process.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

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 Consolidated Balance Sheets as of December 31, 2016 and 2015 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 December 31, 2016, minimum payment obligations for natural gas supply commitments are approximately:



	(in millions)
2017	$	461
2018	467
2019	268
2020	125
2021	127
2022 and beyond	8

(b) AMAs

NGD has had AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. Generally, AMAs are contracts between NGD and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these AMAs, NGD agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for NGD and to use the released capacity for other purposes when it is not needed for NGD. NGD is compensated by the asset manager through payments made over the life of the AMAs based in part on the results of the asset optimization. NGD has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs. NGD has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the AMA proceeds. NGD currently has AMAs in Arkansas, north Louisiana and Oklahoma that extend through 2020.

The following table sets forth information concerning CERC’s obligations under non-cancelable long-term operating leases as of December 31, 2016, which primarily consist of rental agreements for building space, data processing equipment, compression equipment and rights-of-way:



	(in millions)
2017	$	5
2018	4
2019	4
2020	3
2021	2
2022 and beyond	7
Total	$	25

Total lease expense for all operating leases was $9 million, $8 million and $9 million during 2016, 2015 and 2014, respectively.

(d) 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. CERC does not expect the ultimate outcome of this matter 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 December 31, 2016, 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 $5 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 EPA 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.

Unaudited Quarterly Information

12 Months Ended

Dec. 31, 2016

Unaudited Quarterly Information [Abstract]

Unaudited Quarterly Information [Text Block]

Unaudited Quarterly Information

Summarized quarterly financial data is as follows:



	Year Ended December 31, 2016
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in millions)
Revenues	$	1,320	$	807	$	978	$	1,349
Operating income	166		18		26		108
Net income	120		6		43		76



	Year Ended December 31, 2015
	First Quarter		Second Quarter		Third Quarter (1)			Fourth Quarter (2)
	(in millions)
Revenues	$	1,817	$	824	$	799		$	1,087
Operating income	160		27		18			108
Net income (loss)	109		22		(508		)	(535		)


(1)	CERC recognized $862 million ($537 million after tax) in impairment charges related to Enable during the three months ended September 30, 2015.


(2)	CERC recognized $984 million ($620 million after tax) in impairment charges related to Enable during the three months ended December 31, 2015.

Reportable Business Segments

12 Months Ended

Dec. 31, 2016

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.

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.

Long-lived assets include net property, plant and equipment, goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.

Financial data for business segments and products and services are as follows:



	Revenues from External Customers		Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)			Expenditures for Long- Lived Assets
	(in millions)
As of and for the year ended December 31, 2016:
Natural Gas Distribution	$	2,380	$	29		$	242	$	303		$	6,099		$	510
Energy Services	2,073		26			7		20			1,102			5
Midstream Investments (2)	—		—			—		—			2,505			—
Other	1		—			—		(5		)	75			—
Reconciling Eliminations	—		(55		)	—		—			(563		)	—
Consolidated	$	4,454	$	—		$	249	$	318		$	9,218		$	515
As of and for the year ended December 31, 2015:
Natural Gas Distribution	$	2,603	$	29		$	222	$	273		$	5,657		$	601
Energy Services	1,924		33			5		42			857			5
Midstream Investments (2)	—		—			—		—			2,594			—
Other	—		—			—		(2		)	777			—
Reconciling Eliminations	—		(62		)	—		—			(744		)	—
Consolidated	$	4,527	$	—		$	227	$	313		$	9,141		$	606
As of and for the year ended December 31, 2014:
Natural Gas Distribution	$	3,271	$	30		$	201	$	287		$	5,464		$	525
Energy Services	3,095		84			5		52			978			3
Midstream Investments (2)	—		—			—		—			4,521			—
Other	1		—			—		(4		)	1,031			—
Reconciling Eliminations	—		(114		)	—		—			(964		)	—
Consolidated	$	6,367	$	—		$	206	$	335		$	11,030		$	528


(1)	Amounts for 2015 and 2014 have been restated to reflect the adoption of ASU 2015-03.


(2)	Midstream Investments’ equity earnings (losses) are as follows:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Enable (a)	$	208	$	(1,633	)	$	303
SESH	—		—			5
Total	$	208	$	(1,633	)	$	308


(a)	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.



	Year Ended December 31,
Revenues by Products and Services:	2016		2015		2014
	(in millions)
Retail gas sales	$	3,329	$	3,725	$	5,049
Wholesale gas sales	977		657		1,159
Gas transportation and processing	23		26		38
Energy products and services	125		119		121
Total	$	4,454	$	4,527	$	6,367

Property, Plant and Equipment [Abstract]

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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+ Details

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events On January 3, 2017, CES closed the previously announced agreement to acquire AEM for approximately $140 million, including estimated working capital of $100 million. With the addition of this business, CES now operates in a total of 33 states, including seven states where CES previously had no commercial or industrial natural gas sales customers though CES did have other operations in five of those states. CES has begun to integrate AEM into its existing business. Due to the limited amount of time since the acquisition, the initial accounting for the acquisition is incomplete, principally with regard to the valuation of derivatives, property, plant and equipment, intangible assets and goodwill. CERC intends to provide additional business combination disclosures, if material, in its Form 10-Q for the first quarter of 2017. On February 10, 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 December 31, 2016. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the first quarter of 2017 to be made with respect to CERC Corp.’s limited partner interest in Enable for the fourth quarter of 2016.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2016
Significant Accounting Policies [Abstract]
Use Of Estimates	Use of Estimates 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.
Principles of Consolidation	Principles of Consolidation The accounts of CERC Corp. and its wholly-owned and majority owned subsidiaries are included in CERC’s consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. CERC uses the equity method of accounting for investments in entities in which CERC has an ownership interest between 20% and 50% and exercises significant influence. CERC also uses the equity method for investments in which it has ownership percentages greater than 50%, when it exercises significant influence, does not have control and is not considered the primary beneficiary, if applicable. In 2013, CenterPoint Energy, OGE and affiliates of ArcLight, formed Enable as a private limited partnership. CenterPoint Energy has the ability to significantly influence the operating and financial policies of, but not solely control, Enable and, accordingly, recorded an equity method investment, at the historical costs of net assets contributed. Under the equity method, CERC adjusts its investment in Enable each period for contributions made, distributions received, CERC’s share of Enable’s comprehensive income and amortization of basis differences, as appropriate. CERC evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. CERC’s investment in Enable is considered to be a VIE because the power to direct the activities that most significantly impact Enable’s economic performance does not reside with the holders of equity investment at risk. However, CERC is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. Other investments, excluding marketable securities, are carried at cost.
Revenues	Revenues CERC records revenue for natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates.
Long-lived Assets and Intangibles	Long-lived Assets and Intangibles CERC records property, plant and equipment at historical cost. CERC expenses repair and maintenance costs as incurred. CERC periodically evaluates long-lived assets, including property, plant and equipment and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, compared to the carrying value of the assets.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities CERC applies the guidance for accounting for regulated operations to the Natural Gas Distribution business segment. CERC’s rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. CERC had current regulatory assets of $70 million and $21 million as of December 31, 2016 and 2015, respectively, included in other current assets in its Consolidated Balance Sheets. CERC had current regulatory liabilities of $11 million and $55 million as of December 31, 2016 and 2015, respectively, included in other current liabilities in its Consolidated Balance Sheets. CERC’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2016 and 2015, these removal costs of $665 million and $632 million, respectively, are classified as regulatory liabilities in the Consolidated Balance Sheets. In addition, a portion of the amount of removal costs that relate to AROs has been reclassified from a regulatory liability to an asset retirement liability in accordance with accounting guidance for AROs.
Depreciation and Amortization Expense	Depreciation and Amortization Expense Depreciation and amortization is computed using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of regulatory assets and other intangibles.
Capitalization of Interest and AFUDC	Capitalization of Interest and AFUDC Interest and AFUDC are capitalized as a component of projects under construction and are amortized over the assets’ estimated useful lives once the assets are placed in service. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates. During 2016, 2015 and 2014, CERC capitalized interest and AFUDC of $2 million, $2 million and $1 million, respectively.
Income Taxes	Income Taxes CERC is a member of the U.S. federal consolidated income tax return of CenterPoint Energy. CERC reports its income tax provision on a separate entity basis pursuant to a tax sharing agreement with CenterPoint Energy. CERC uses the asset and liability method of accounting for deferred income taxes in accordance with accounting guidance for income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy. CERC recognizes interest and penalties as a component of income tax expense. CERC reports the income tax provision associated with its interest in Enable in Income tax expense (benefit) in its Statements of Consolidated Income.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are recorded at the invoiced amount and do not bear interest. It is the policy of management to review the outstanding accounts receivable monthly, as well as the bad debt write-offs experienced in the past, and establish an allowance for doubtful accounts. Account balances are charged off against the allowance when management determines it is probable the receivable will not be recovered. The provision for doubtful accounts in CERC’s Statements of Consolidated Income for 2016, 2015 and 2014 was $7 million, $19 million and $20 million, respectively.
Inventory	Inventory Inventory consists principally of materials and supplies and natural gas. Materials and supplies are valued at the lower of average cost or market. Materials and supplies are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Natural gas inventories of CERC’s Energy Services business segment are valued at the lower of average cost or market. Natural gas inventories of CERC’s Natural Gas Distribution business segment are primarily valued at weighted average cost. During 2016, 2015 and 2014, CERC recorded $1 million, $4 million and $8 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.
Derivative Instruments	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 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 normal 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 and 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.
Environmental Costs	Environmental Costs CERC expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. CERC expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit. CERC records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Statement of Consolidated Cash Flows	Statements of Consolidated Cash Flows For purposes of reporting cash flows, CERC considers cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. CERC considers distributions received from equity method investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classifies these distributions as operating activities in the Statements of Consolidated Cash Flows. CERC considers distributions received from equity method investments in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and classifies these distributions as investing activities in the Statements of Consolidated Cash Flows.
New Accounting Pronouncements	New Accounting Pronouncements In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (ASU 2015-02). ASU 2015-02 changes the analysis that reporting organizations must perform to evaluate whether they should consolidate certain legal entities, such as limited partnerships. The changes include, among others, modification of the evaluation of whether limited partnerships and similar legal entities are VIEs or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. ASU 2015-02 does not amend the related party guidance for situations in which power is shared between two or more entities that hold interests in a VIE. CERC adopted ASU 2015-02 on January 1, 2016, which did not have a material impact on its financial position, results of operations, cash flows and disclosures. In April 2015, the FASB issued ASU No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. CERC adopted ASU 2015-03 retrospectively on January 1, 2016, which resulted in a reduction of other long-term assets, indexed debt and total long-term debt on its Consolidated Balance Sheets. CERC had debt issuance costs, excluding amounts related to credit facility arrangements, of $10 million and $12 million as a reduction to long-term debt on its Consolidated Balance Sheets as of December 31, 2016 and 2015, respectively. In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07). ASU 2015-07 removes the requirement to categorize within the fair value hierarchy investments for which fair values are measured at NAV using the practical expedient. Entities will be required to disclose the fair value of investments measured using the NAV practical expedient so that financial statement users can reconcile amounts reported in the fair value hierarchy table to amounts reported on the balance sheet. CERC retrospectively adopted ASU 2015-07 on January 1, 2016, which impacts its employee benefit plan disclosures. See Note 7 for the impacts on the employee benefit plan disclosures. This standard did not have an impact on CERC’s financial position, results of operations or cash flows. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 eliminates the requirement for an acquirer in a business combination to account for measurement-period adjustments retrospectively. Instead, an acquirer would recognize a measurement-period adjustment during the period in which the amount of the adjustment is determined. CERC prospectively adopted ASU 2015-16 on January 1, 2016, which did not have an impact on its financial position, results of operations or cash flows. 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 is currently assessing the impact that this standard will have 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 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 not 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 based, which we do not anticipate will be significantly impacted by these ASUs. CERC is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts when collectability is uncertain and its accounting for contributions in aid of construction. CERC expects to adopt these ASUs on January 1, 2018 and is evaluating the method of adoption. 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. 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.
Other Current Assets and Liabilities	Other Current Assets and Liabilities Included in other current assets on the Consolidated Balance Sheets as of December 31, 2016 and 2015 were less than $1 million and $31 million, respectively, of margin deposits and $40 million and $12 million, respectively, of under-recovered gas cost. Included in other current liabilities on the Consolidated Balance Sheets as of December 31, 2016 and 2015 were $10 million and $55 million, respectively, of over-recovered gas cost.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Table Text Block]

Property, plant and equipment includes the following:



	Weighted Average Useful Lives	December 31,
	(in years)	2016		2015
		(in millions)
Natural Gas Distribution	32	$	6,219	$	5,762
Energy Services	25	83		86
Other property	9	49		50
Total		6,351		5,898
Accumulated depreciation and amortization:
Natural Gas Distribution		1,722		1,575
Energy Services		29		34
Other property		31		31
Total accumulated depreciation and amortization		1,782		1,640
Property, plant and equipment, net		$	4,569	$	4,258

Depreciation And Amortization [Table Text Block]

The following table presents depreciation and amortization expense for 2016, 2015 and 2014:



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Depreciation expense	$	230	$	211	$	195
Amortization expense	19		16		11
Total depreciation and amortization expense	$	249	$	227	$	206

Asset Retirement Obligation [Table Text Block]

A reconciliation of the changes in the ARO liability is as follows:



	December 31,
	2016		2015
	(in millions)
Beginning balance	$	156	$	139
Accretion expense	8		5
Revisions in estimates of cash flows	5		12
Ending balance	$	169	$	156

Acquisition (Tables)

12 Months Ended

Dec. 31, 2016

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	$	102
Receivables	$	76
Derivative assets	38
Property and equipment	1
Identifiable intangibles	38
Total assets acquired	153
Accounts payable	49
Derivative liabilities	24
Total liabilities assumed	73
Identifiable net assets acquired	80
Goodwill	22
Net assets acquired	$	102

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:



	Estimate Fair Value		Estimate Useful Life
	(in millions)		(in years)
Customer relationships	$	34	15
Covenants not to compete	4		4
Total identifiable intangibles	$	38

Goodwill (Tables)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

Goodwill by reportable business segment as of December 31, 2015 and changes in the carrying amount of goodwill as of December 31, 2016 are as follows:



	December 31, 2015			Continuum Acquisition (1)		December 31, 2016
	(in millions)
Natural Gas Distribution	$	746		$	—	$	746
Energy Services	83		(2)	22		105		(2)
Other Operations	11			—		11
Total	$	840		$	22	$	862


(1)	See Note 4.


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

Regulatory Accounting (Tables)

12 Months Ended

Dec. 31, 2016

Regulatory Matters [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

The following is a list of regulatory assets/liabilities reflected on CERC’s Consolidated Balance Sheets as of December 31, 2016 and 2015:



	December 31,
	2016			2015
	(in millions)
Regulatory assets in other long-term assets (1)	$	125		$	105
Regulatory liabilities	(769		)	(734		)
Net	$	(644	)	$	(629	)

(1)

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

CERC’s changes in accumulated comprehensive income (loss) related to postretirement and other postemployment plans are as follows:



	Year Ended December 31,
	2016			2015
	(in millions)
Beginning Balance	$	9		$	1
Other comprehensive income (loss) before reclassifications (1)	(10		)	13
Amounts reclassified from accumulated other comprehensive income:
Actuarial gains (2)	—			1
Tax benefit (expense)	4			(6		)
Net current period other comprehensive income (loss)	(6		)	8
Ending Balance	$	3		$	9


(1)	Total other comprehensive income (loss) related to the remeasurement of pension, postretirement and other postemployment plans.


(2)	These accumulated other comprehensive components are included in the computation of net periodic cost.

Amounts recognized in accumulated other comprehensive (income) loss consist of the following:



	December 31,
	2016			2015
	(in millions)
Unrecognized actuarial loss	$	5		$	3
Unrecognized prior service cost (credit)	7			(1		)
Total recognized in accumulated other comprehensive loss	12			2
Less: deferred tax benefit (1)	(15		)	(11		)
Net amount recognized in accumulated other comprehensive income	$	(3	)	$	(9	)


(1)	CERC’s postretirement benefit obligation is reduced by the impact of previously non-taxable government subsidies under the Medicare Prescription Drug Act. Because the subsidies were non-taxable, the temporary difference used in measuring the deferred tax impact was determined on the unrecognized losses excluding such subsidies.

The changes in plan assets and benefit obligations recognized in other comprehensive loss during 2016 are as follows:



	Postretirement Benefits
	(in millions)
Net loss	$	2
Amortization of prior service cost	8
Total recognized in other comprehensive loss	$	10

The following benefit payments are expected to be made by the postretirement benefit plan:



	Benefit Payments
	(in millions)
2017	$	5
2018	6
2019	7
2020	8
2021	8
2022-2026	43

As part of the investment strategy discussed above, CERC maintained the following asset allocation ranges for its postretirement benefit plan as of December 31, 2016:



U.S. equity	15–25%
International equity	2–12%
Fixed income	68–78%
Cash	0–2%

The net postretirement benefit cost includes the following components:



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Service cost — benefits earned during the period	$	1		$	1		$	1
Interest cost on accumulated benefit obligation	4			5			5
Expected return on plan assets	(1		)	(1		)	(1		)
Amortization of prior service cost	—			1			1
Amortization of net loss	1			1			1
Curtailment (1)	(1		)	—			—
Net postretirement benefit cost	$	4		$	7		$	7


(1)	Effective January 1, 2017, a change in retiree medical coverage for Medicare eligible post-65 retirees from self-insured to a Medicare Advantage Program, an insured benefit, was implemented. A curtailment gain was recognized in October 2016 related to this implementation.

CERC used the following assumptions to determine net postretirement benefit costs:



	Year Ended December 31,
	2016		2015		2014
Discount rate	4.35	%	3.90	%	4.75	%
Expected return on plan assets	3.95	%	4.05	%	3.10	%



	December 31,
	2016			2015
	(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	101		$	126
Service cost	1			1
Interest cost	4			5
Benefits paid	(13		)	(12		)
Participant contributions	5			4
Medicare reimbursement	1			1
Plan amendment (1)	10			(5		)
Actuarial (gain) loss	6			(19		)
Accumulated benefit obligation, end of year	$	115		$	101
Change in Plan Assets
Plan assets, beginning of year	$	25		$	26
Benefits paid	(13		)	(12		)
Employer contributions	7			7
Participant contributions	5			4
Actual investment return	1			—
Plan assets, end of year	$	25		$	25
Amounts Recognized in Balance Sheets
Current liabilities-other	$	(4	)	$	(6	)
Other liabilities-benefit obligations	(86		)	(70		)
Net liability, end of year	$	(90	)	$	(76	)
Actuarial Assumptions
Discount rate	4.15		%	4.35		%
Expected long-term return on assets	3.60		%	3.95		%
Healthcare cost trend rate assumed for the next year - Pre 65	5.75		%	6.00		%
Healthcare cost trend rate assumed for the next year - Post 65	10.65		%	5.50		%
Prescription cost trend rate assumed for the next year	10.75		%	11.00		%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.50		%	5.00		%
Year that the healthcare rate reaches the ultimate trend rate	2024			2024
Year that the prescription drug rate reaches the ultimate trend rate	2024			2024


(1)	The postretirement plan was amended in 2016 to change the retiree medical coverage for Medicare eligible post-65 retirees from self-insured to a Medicare Advantage Program, an insured benefit which became effective January 1, 2017.

Defined Benefit Plan Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Table Text Block]



	1% Increase		1% Decrease
	(in millions)
Effect on the postretirement benefit obligation	$	4	$	4
Effect on the total of service and interest cost	—		—

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Table Text Block]

The fair values of CERC’s postretirement plan assets at December 31, 2016 and 2015, by asset category are as follows:



	Fair Value Measurements as of December 31, 2016
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Mutual funds (1)	$	25	$	—	$	—	$	25
Total	$	25	$	—	$	—	$	25


(1)	73% of the amount invested in mutual funds was in fixed income securities; 20% was in U.S. equities and 7% was in international equities.



	Fair Value Measurements as of December 31, 2015
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total

Mutual funds (1)	$	25	$	—	$	—	$	25
Total	$	25	$	—	$	—	$	25


(1)	70% of the amount invested in mutual funds was in fixed income securities; 23% was in U.S. equities and 7% was in international equities.

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2016



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Corporate service charges	$	125		$	118		$	115

Charges from Houston Electric for services provided	15			18			17

Billings to Houston Electric for services provided	(7		)	(6		)	(5		)
	$	133		$	130		$	127

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]



Fair Value of Derivative Instruments
	December 31, 2016
Total 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		$	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)


(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
	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 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, 2015
Total 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	$	90	$	2
Natural gas derivatives (1) (2) (3)	Other Assets: Non-trading derivative assets	36		—
Natural gas derivatives (1) (2) (3)	Current Liabilities: Non-trading derivative liabilities	10		60
Natural gas derivatives (1) (2) (3)	Other Liabilities: Non-trading derivative liabilities	4		25
Total		$	140	$	87


(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 767 Bcf or a net 112 Bcf long position. Of the net long position, basis swaps constitute 133 Bcf.

(2)


(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
	December 31, 2015
	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	$	100		$	(11	)	$	89
Other Assets: Non-trading derivative assets	40			(4		)	36
Current Liabilities: Non-trading derivative liabilities	(62		)	51			(11		)
Other Liabilities: Non-trading derivative liabilities	(25		)	20			(5		)
Total	$	53		$	56		$	109


(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 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.

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]



Income Statement Impact of Derivative Activity
		Year Ended December 31,
Total derivatives not designated as hedging instruments	Income Statement Location	2016			2015			2014
		(in millions)
Natural gas derivatives	Gains (Losses) in Revenue	$	(18	)	$	134		$	35
Natural gas derivatives	Gains (Losses) in Expense: Natural Gas	70			(105		)	11
Total		$	52		$	29		$	46

Credit Quality Of Counterparties [Table Text Block]



	December 31, 2016					December 31, 2015
	Investment Grade(1)		Total			Investment Grade(1)		Total
	(in millions)
Energy marketers	$	1	$	4		$	4	$	10
Financial institutions	33		33			—		—
End users (2)	2		47			2		115
Total	$	36	$	84	(3)	$	6	$	125


(1)	“Investment grade” is primarily determined using publicly available credit ratings, and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis, and considers contractual rights and restrictions and collateral.


(2)	End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.


(3)	The net of total non-trading natural gas derivative assets was $70 million and $125 million as of December 31, 2016 and 2015, respectively, as shown on CERC’s Consolidated Balance Sheets, and was comprised of the natural gas contracts derivatives assets separately shown above, impacted by collateral netting of $14 million and $-0- as of December 31, 2016 and 2015, respectively.

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

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



	December 31, 2016
	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
	(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 Consolidated Balance Sheets.


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



	December 31, 2015
	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
	(in millions)
Assets
Corporate equities	$	2	$	—	$	—	$	—		$	2
Investments, including money market funds (2)	11		—		—		—			11
Natural gas derivatives (3)	4		115		21		(15		)	125
Total assets	$	17	$	115	$	21	$	(15	)	$	138
Liabilities
Natural gas derivatives (3)	$	13	$	65	$	9	$	(71	)	$	16
Total liabilities	$	13	$	65	$	9	$	(71	)	$	16


(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 $56 million posted with the same counterparties.


(2)	Amounts are included in Other Assets in the 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
	Year Ended December 31,
	2016			2015			2014
	(in millions)
Beginning balance	$	12		$	17		$	3
Purchases	12			—			—
Total gains	12			7			14
Total settlements	(27		)	(12		)	1
Transfers out of Level 3	(1		)	(1		)	—
Transfers into Level 3	5			1			(1		)
Ending balance (1)	$	13		$	12		$	17
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	$	11		$	6		$	16


(1)	During 2016, 2015 and 2014, CERC did not have significant Level 3 sales.

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



	December 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Financial assets:
Notes receivable - affiliated companies	$	—	$	—	$	363	$	356
Financial liabilities:
Long-term debt	$	2,375	$	2,551	$	2,341	$	2,539

Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

Investment in Unconsolidated Affiliates:



	As of December 31,
	2016		2015
	(in millions)
Enable	$	2,505	$	2,594

Equity in Earnings (Losses) of Unconsolidated Affiliates, net:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Enable	$	208	$	(1,633	)	$	303
SESH (1)	—		—			5
Total	$	208	$	(1,633	)	$	308


(1)	CERC contributed a 24.95% interest in SESH to Enable on May 30, 2014 and its remaining 0.1% interest in SESH to Enable on June 30, 2015.

Limited Partner Interest in Enable:



	As of December 31,
	2016			2015		2014
CenterPoint Energy	54.1	%	(1)	55.4	%	55.4	%
OGE	25.7	%		26.3	%	26.3	%


(1)	In November 2016, Enable closed a public offering of 10,000,000 common units. In connection with the offering, Enable and an affiliate of ArcLight sold an additional combined 1,500,000 common units to the underwriters.

Enable Common and Subordinated Units Held:

Summarized consolidated income (loss) information for Enable is as follows:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Operating revenues	$	2,272	$	2,418		$	3,367
Cost of sales, excluding depreciation and amortization	1,017		1,097			1,914
Impairment of goodwill and other long-lived assets	9		1,134			8
Operating income (loss)	385		(712		)	586
Net income (loss) attributable to Enable	290		(752		)	530

Reconciliation of Equity in Earnings (Losses), net:
CERC’s interest	$	160	$	(416	)	$	298
Basis difference amortization (1)	48		8			5
Impairment of CERC’s equity method investment in Enable	—		(1,225		)	—
CERC’s equity in earnings (losses), net (2)	$	208	$	(1,633	)	$	303


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


(2)	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Summarized consolidated balance sheet information for Enable is as follows:



	December 31,
	2016			2015
	(in millions)
Current assets	$	396		$	381
Non-current assets	10,816			10,845
Current liabilities	362			615
Non-current liabilities	3,056			3,080
Non-controlling interest	12			12
Preferred equity	362			—
Enable partners’ capital	7,420			7,519

Reconciliation of Investment in Enable:
CERC’s ownership interest in Enable partners’ capital	$	4,067		$	4,163
CERC’s basis difference	(1,562		)	(1,569		)
CERC’s investment in Enable	$	2,505		$	2,594

Distributions Received from Unconsolidated Affiliates:



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Investment in Enable’s common and subordinated units	$	297	$	294	$	298
Interest in SESH (1)	—		—		7
Total	$	297	$	294	$	305


(1)	CERC contributed a 24.95% interest in SESH to Enable on May 30, 2014 and its remaining 0.1% interest in SESH to Enable on June 30, 2015.

Transactions with Enable:



	Year Ended December 31,
	2016		2015		2014
	(in millions)
Reimbursement of transition services (1)	$	7	$	16	$	163
Natural gas expenses, including transportation and storage costs	110		117		130
Interest income related to notes receivable from Enable	1		8		8


(1)	Represents amounts billed under the Transition Agreements, including the costs of seconded employees. Actual transition services costs are recorded net of reimbursement.



	Year Ended December 31,
	2016		2015
	(in millions)
Accounts receivable for amounts billed for transition services	$	1	$	3
Interest receivable related to notes receivable from Enable	—		4
Accounts payable for natural gas purchases from Enable	10		11

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

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]



	December 31, 2016					December 31, 2015
	Long-Term			Current (1)		Long-Term (2)			Current (1)
	(in millions)
Short-term borrowings:
Inventory financing (3)	$	—		$	35	$	—		$	40
Total short-term borrowings	—			35		—			40
Long-term debt:
Senior notes 4.50% to 6.625% due 2017 to 2041	1,593			250		1,843			325
Commercial paper (4)	569			—		219			—
Unamortized debt issuance costs	(10		)	—		(12		)	—
Unamortized discount and premium	(27		)	—		(34		)	—
Total long-term debt	2,125			250		2,016			325
Total debt	$	2,125		$	285	$	2,016		$	365


(1)	Includes amounts due or exchangeable within one year of the date noted.


(2)	Includes $12 million of unamortized debt issuance costs to reflect adoption of ASU 2015-03.

(3)


(4)	Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.

Schedule of Line of Credit Facilities [Table Text Block]

As of December 31, 2016 and 2015, CERC had the following revolving credit facility and utilization of such facility:



		December 31, 2016							December 31, 2015
Size of Facility		Loans		Letters of Credit		Commercial Paper			Loans		Letters of Credit		Commercial Paper
(in millions)
$	600	$	—	$	4	$	569	(1)	$	—	$	2	$	219	(1)


(1)	Weighted average interest rate was approximately 1.03% and 0.81% as of December 31, 2016 and 2015, respectively.

Execution Date

Size of

Facility

Draw Rate of LIBOR plus (1)

Financial Covenant Limit on Debt to Capital Ratio

Debt to Capital

Ratio as of December 31, 2016

Termination Date

(in millions)

March 3, 2016

600

1.25%

65%

35.8%

March 3, 2021


(1)	Based on current credit ratings.

Schedule of Maturities of Long-term Debt [Table Text Block]

CERC Corp. has the following long-term debt maturities:



	(in millions)
2017	$	250
2018	300
2019	—
2020	—
2021	1,162

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Taxes [Abstract]

Income Tax Expense Disclosure [Table Text Block]

The components of CERC’s income tax expense (benefit) were as follows:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Current income tax expense:
State	$	6	$	3		$	10
Total current expense	6		3			10
Deferred income tax expense (benefit):
Federal	130		(488		)	171
State	26		(54		)	7
Total deferred expense (benefit)	156		(542		)	178
Total income tax expense (benefit)	$	162	$	(539	)	$	188

Reconciliation Of Expected Federal Income Tax Expense To Actual [Table Text Block]

A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate is as follows:



	Year Ended December 31,
	2016			2015			2014
	(in millions)
Income (loss) before income taxes	$	407		$	(1,451	)	$	511
Federal statutory income tax rate	35		%	35		%	35		%
Expected federal income tax expense (benefit)	142			(508		)	179
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	17			(33		)	11
State valuation allowance, net of federal income tax	3			—			—
Other, net	—			2			(2		)
Total	20			(31		)	9
Total income tax expense (benefit)	$	162		$	(539	)	$	188
Effective tax rate	40		%	37		%	37		%

Income Tax Asset Liability Disclosure [Table Text Block]

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:



	December 31,
	2016			2015
	(in millions)
Deferred tax assets:
Benefits and compensation	$	45		$	39
Loss and credit carryforwards	451			388
AROs	64			59
Other	18			39
Valuation allowance	(5		)	(2		)
Total deferred tax assets	573			523
Deferred tax liabilities:
Property, plant, and equipment	1,017			929
Investment in unconsolidated affiliates	1,383			1,277
Regulatory assets/liabilities, net	8			—
Other	90			91
Total deferred tax liabilities	2,498			2,297
Net deferred tax liabilities	$	1,925		$	1,774

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]



	(in millions)
2017	$	461
2018	467
2019	268
2020	125
2021	127
2022 and beyond	8

Operating Leases of Lessee Disclosure [Table Text Block]



	(in millions)
2017	$	5
2018	4
2019	4
2020	3
2021	2
2022 and beyond	7
Total	$	25

Unaudited Quarterly Information [Abstract]

Tabular disclosure of a lessee's leasing arrangements including: (1) the basis on which contingent rental payments are determined, (2) the existence and terms of renewal or purchase options and escalation clauses, (3) restrictions imposed by lease arrangements, such as those concerning dividends, additional debt, and further leasing, (4) rent holidays, rent concessions, or leasehold improvement incentives and unusual provisions or conditions. Disclosure may also include the specific period used to amortize material leasehold improvements made at the inception of the lease or during the lease term. Additionally, for operating leases having initial or remaining noncancelable lease terms in excess of one year: (a) future minimum rental payments required as of the date of the latest balance sheet presented, in the aggregate and for each of the five succeeding fiscal years, (b) the total of minimum rentals to be received in the future under noncancelable subleases as of the date of the latest balance sheet presented, and (c) for all operating leases, rental expense for each period for which an income statement is presented, with separate amounts for minimum rentals, contingent rentals, and sublease rentals. Rental payments under leases with terms of a month or less that were not renewed need not be included.

+ References + Details

Unaudited Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly financial data [Table Text Block]

Summarized quarterly financial data is as follows:



	Year Ended December 31, 2016
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in millions)
Revenues	$	1,320	$	807	$	978	$	1,349
Operating income	166		18		26		108
Net income	120		6		43		76



	Year Ended December 31, 2015
	First Quarter		Second Quarter		Third Quarter (1)			Fourth Quarter (2)
	(in millions)
Revenues	$	1,817	$	824	$	799		$	1,087
Operating income	160		27		18			108
Net income (loss)	109		22		(508		)	(535		)


(1)	CERC recognized $862 million ($537 million after tax) in impairment charges related to Enable during the three months ended September 30, 2015.


(2)	CERC recognized $984 million ($620 million after tax) in impairment charges related to Enable during the three months ended December 31, 2015.

Reportable Business Segments (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

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

Financial data for business segments and products and services are as follows:



	Revenues from External Customers		Intersegment Revenues			Depreciation and Amortization		Operating Income (Loss)			Total Assets (1)			Expenditures for Long- Lived Assets
	(in millions)
As of and for the year ended December 31, 2016:
Natural Gas Distribution	$	2,380	$	29		$	242	$	303		$	6,099		$	510
Energy Services	2,073		26			7		20			1,102			5
Midstream Investments (2)	—		—			—		—			2,505			—
Other	1		—			—		(5		)	75			—
Reconciling Eliminations	—		(55		)	—		—			(563		)	—
Consolidated	$	4,454	$	—		$	249	$	318		$	9,218		$	515
As of and for the year ended December 31, 2015:
Natural Gas Distribution	$	2,603	$	29		$	222	$	273		$	5,657		$	601
Energy Services	1,924		33			5		42			857			5
Midstream Investments (2)	—		—			—		—			2,594			—
Other	—		—			—		(2		)	777			—
Reconciling Eliminations	—		(62		)	—		—			(744		)	—
Consolidated	$	4,527	$	—		$	227	$	313		$	9,141		$	606
As of and for the year ended December 31, 2014:
Natural Gas Distribution	$	3,271	$	30		$	201	$	287		$	5,464		$	525
Energy Services	3,095		84			5		52			978			3
Midstream Investments (2)	—		—			—		—			4,521			—
Other	1		—			—		(4		)	1,031			—
Reconciling Eliminations	—		(114		)	—		—			(964		)	—
Consolidated	$	6,367	$	—		$	206	$	335		$	11,030		$	528


(1)	Amounts for 2015 and 2014 have been restated to reflect the adoption of ASU 2015-03.


(2)	Midstream Investments’ equity earnings (losses) are as follows:



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Enable (a)	$	208	$	(1,633	)	$	303
SESH	—		—			5
Total	$	208	$	(1,633	)	$	308


(a)	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Revenue from External Customers by Products and Services [Table Text Block]



	Year Ended December 31,
Revenues by Products and Services:	2016		2015		2014
	(in millions)
Retail gas sales	$	3,329	$	3,725	$	5,049
Wholesale gas sales	977		657		1,159
Gas transportation and processing	23		26		38
Energy products and services	125		119		121
Total	$	4,454	$	4,527	$	6,367

Midstream Investments [Table Text Block]

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



	Year Ended December 31,
	2016		2015			2014
	(in millions)
Enable (a)	$	208	$	(1,633	)	$	303
SESH	—		—			5
Total	$	208	$	(1,633	)	$	308


(a)	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

Background (Details)

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Natural Gas Distribution [Member]

54.10%

^[1]

55.40%

Number of States in which Entity Operates

Energy Services [Member]

Number of States in which Entity Operates

[1]	In November 2016, Enable closed a public offering of 10,000,000 common units. In connection with the offering, Enable and an affiliate of ArcLight sold an additional combined 1,500,000 common units to the underwriters.

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of Accounting Policies [Line Items]
Regulatory liabilities, noncurrent	$ 769	$ 734
Capitalized interest costs, including AFUDC	2	2	$ 1
Provision for doubtful accounts	7	19	20
Write-down of natural gas inventory	1	4	$ 8
Unamortized debt issuance expense	10	12
Removal Costs [Member]
Summary of Accounting Policies [Line Items]
Regulatory liabilities, noncurrent	665	632
Prepaid Expenses and Other Current Assets [Member]
Summary of Accounting Policies [Line Items]
Regulatory assets, current	70	21
Margin deposits	1	31
Under recovered gas costs	40	12
Other Current Liabilities [Member]
Summary of Accounting Policies [Line Items]
Regulatory liabilities, current	11	55
Over recovered gas costs	$ 10	$ 55

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 6,351	$ 5,898
Accumulated depreciation and amortization	1,782	1,640
Property, Plant and Equipment, Net	4,569	4,258
Depreciation expense	230	211	$ 195
Amortization expense	19	16	11
Total depreciation and amortization expense	249	227	206
Beginning balance	156	139
Accretion expense	8	5
Revisions in estimates of cash flows	5	12
Ending balance	169	156	$ 139
Natural Gas Distribution [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	6,219	5,762
Accumulated depreciation and amortization	$ 1,722	1,575
Natural Gas Distribution [Member] \| Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	32 years
Energy Services [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 83	86
Accumulated depreciation and amortization	$ 29	34
Energy Services [Member] \| Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	25 years
Other property [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 49	50
Accumulated depreciation and amortization	$ 31	$ 31
Other property [Member] \| Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	9 years

Acquisition (Details) - USD ($) $ in Millions		12 Months Ended
Acquisition (Details) - USD ($) $ in Millions	Apr. 01, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Total purchase price consideration		$ 102.0	$ 0.0	$ 0.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Total purchase price consideration		102.0	0.0	$ 0.0
Goodwill		862.0	$ 840.0
Continuum Energy Services [Member]
Total purchase price consideration	$ 102.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Total purchase price consideration	102.0
Receivables	76.0
Derivative assets	38.0
Property and equipment	1.0
Identifiable intangibles	38.0
Total assets acquired	153.0
Accounts payable	49.0
Derivative liabilities	24.0
Total liabilities assumed	73.0
Identifiable net assets acquired	80.0
Goodwill	22.0
Net assets acquired	102.0
Amortization of Intangible Assets		3.0
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		466.0
Business Combination, Operating Income Of Acquiree Since Acquisition Date		$ 1.0
Continuum Energy Services [Member] \| Customer Relationships [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Finite-lived Intangible Assets Acquired	$ 34.0
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	15 years
Continuum Energy Services [Member] \| Noncompete Agreements [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Finite-lived Intangible Assets Acquired	$ 4.0
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	4 years

Goodwill (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

$ 862

$ 840

Natural Gas Distribution [Member]

^[1]

746

^[1]

Energy Services [Member]

^[2]

105

Accumulated Goodwill Impairment Charge

^[1]

252

Corporate and Other [Member]

$ 11

Schedule Of Regulatory Assets And Liabilities [Line Items]

^[1]

$ 0

[1]	See Note 4.
[2]	Amount presented is net of the accumulated goodwill impairment charge of $252 million.

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

Dec. 31, 2016

Dec. 31, 2015

Regulatory assets in other long-term assets (1)

^[1]

$ 125

$ 105

Regulatory liabilities

(769)

(734)

Net Regulatory Assets (Liabilities)

(644)

(629)

Pension and Other Postretirement Plans Costs [Member]

Schedule Of Regulatory Assets And Liabilities [Line Items]

Remaining amounts of regulatory assets for which no return on investment during recovery period is provided

$ 6

$ 5

[1]

Employee Benefit Plans Pension and Postretirement Benefits (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2016

Dec. 31, 2015

Pension and Savings Plan

Percentage of eligible earnings used to determine retirement benefits

5.00%

Pension Expense

$ 35

$ 24

$ 27

Non Qualified Pension Plan Benefit Expense

$ 3

Maximum Percentage Of Employee Compensation Eligible For Contribution To Savings Plan

50.00%

Description Of Company Match Under Savings Plan

100.00%

Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay

6.00%

Defined Contribution Plan, Cost Recognized

$ 16

Other liabilities-benefit obligations

$ (104)

$ (89)

Amounts reclassified from accumulated other comprehensive income: [Abstract]

Tax benefit (expense)

(6)

Net current period other comprehensive income (loss)

(6)

(4)

Effect of a one-percentage point change in assumed healthcare cost trend rates

Deferred Compensation Arrangement with Individual, Compensation Expense

Other Pension Plan, Postretirement or Supplemental Plans [Member]

Amounts reclassified from accumulated other comprehensive income: [Abstract]

Other comprehensive income (loss) before reclassifications (1)

^[1]

(10)

Actuarial gains (2)

^[2]

Tax benefit (expense)

(6)

Net current period other comprehensive income (loss)

(6)

Ending Balance

$ 3

$ 9

Amounts recognized in accumulated other comprehensive loss

Unrecognized actuarial loss

Unrecognized prior service cost (credit)

(1)

Total recognized in accumulated other comprehensive loss

Less: deferred tax benefit (1)

^[3]

(15)

(11)

Net amount recognized in accumulated other comprehensive income

$ (3)

$ (9)

(3)

(9)

(1)

(3)

(9)

Effect of a one-percentage point change in assumed healthcare cost trend rates

Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gains (Losses), after Tax

Other Postretirement Benefit Plans, Defined Benefit [Member]

Components of net periodic benefit cost

Service cost — benefits earned during the period

Interest cost on accumulated benefit obligation

Expected return on plan assets

(1)

Amortization of prior service cost

Amortization of net loss

Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments

^[4]

(1)

Net postretirement benefit cost

$ 4

$ 7

Assumptions used to determine net postretirement benefit costs

Discount rate

4.35%

3.90%

4.75%

Expected return on plan assets

3.60%

3.95%

4.05%

3.10%

Change in Benefit Obligation [Roll Forward]

Accumulated benefit obligation, beginning of year

$ 101

$ 126

Service cost — benefits earned during the period

$ 1

Interest cost on accumulated benefit obligation

Benefits paid

(13)

(12)

Participant contributions

Medicare reimbursement

Plan amendment (1)

^[5]

(5)

Actuarial (gain) loss

(19)

Accumulated benefit obligation, end of year

$ 115

$ 101

115

101

126

Change in Plan Assets [Roll Forward]

Plan assets, beginning of year

Benefits paid

(13)

(12)

Employer contributions

Participant contributions

Actual investment return

Plan assets, end of year

$ 25

$ 26

Current liabilities-other

(4)

(6)

Other liabilities-benefit obligations

(86)

(70)

Net liability, end of year

$ (90)

$ (76)

Discount rate

4.15%

4.35%

Expected return on plan assets

3.60%

3.95%

4.05%

3.10%

Prescription cost trend rate assumed for the next year

10.75%

11.00%

Rate to which the cost trend rate is assumed to decline (ultimate trend rate)

4.50%

5.00%

Annualized individual discount rates based on time period, minimum

6 months

Annualized individual discount rates based on time period, maximum

99 years

Changes in plan assets and benefit obligations recognized in other comprehensive income

Net loss

$ 2

Amortization of prior service cost

Total recognized in other comprehensive loss

Total expense (benefit) recognized in net periodic cost and other comprehensive income

(14)

Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)

Effect of a one-percentage point change in assumed healthcare cost trend rates

Effect of One Percentage Point Increase on Postretirement Benefit Obligation

Effect of One Percentage Point Increase on Total of Service and Interest Cost

Effect of One Percentage Point Decrease on Postretirement Benefit Obligation

Effect of One Percentage Point Decrease on Total of Service and Interest Cost

$ 0

Minimum [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Healthcare cost trend rate assumed for the next year

5.75%

6.00%

Maximum [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Healthcare cost trend rate assumed for the next year

10.65%

5.50%

Health Care [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Year that the healthcare rate reaches the ultimate trend rate

2024

Prescription Drug [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Year that the healthcare rate reaches the ultimate trend rate

2024

Benefit Obligation [Member]

Defined Benefit Plan Disclosure [Line Items]

Deferred Compensation Liability, Classified, Noncurrent

$ 3

Effect of a one-percentage point change in assumed healthcare cost trend rates

Postemployment Benefits Liability, Noncurrent

$ 14

CenterPoint Energy [Member] | Common Stock [Member]

Pension and Savings Plan

Defined contribution plan, Maximum percentage allowed in company stock

25.00%

Number Of Shares In Common Stock Held By Savings Plan

14,216,986

Percentage of investment in common stocks

17.00%

[1]	Total other comprehensive income (loss) related to the remeasurement of pension, postretirement and other postemployment plans.
[2]	These accumulated other comprehensive components are included in the computation of net periodic cost.
[3]	CERC’s postretirement benefit obligation is reduced by the impact of previously non-taxable government subsidies under the Medicare Prescription Drug Act. Because the subsidies were non-taxable, the temporary difference used in measuring the deferred tax impact was determined on the unrecognized losses excluding such subsidies.
[4]	Effective January 1, 2017, a change in retiree medical coverage for Medicare eligible post-65 retirees from self-insured to a Medicare Advantage Program, an insured benefit, was implemented. A curtailment gain was recognized in October 2016 related to this implementation.
[5]	The postretirement plan was amended in 2016 to change the retiree medical coverage for Medicare eligible post-65 retirees from self-insured to a Medicare Advantage Program, an insured benefit which became effective January 1, 2017.

Employee Benefit Plans Plan Assets (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Estimated contributions next fiscal year

$ 5

Postemployment Benefits

Postemployment benefit expense

$ 4

$ 2

Benefit expense related to deferred compensation plans

Other Postretirement Benefit Plans, Defined Benefit [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Expected Future Benefit Payments, Fiscal Year Maturity

$ 26

Benefit Payments - 2017

Benefit Payments - 2018

Benefit Payments - 2019

Benefit Payments - 2020

Benefit Payments - 2021

Benefit Payments - 2022-2026

$ 43

Other Postretirement Benefit Plans, Defined Benefit [Member] | U.S. Equity [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

15.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

25.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | International Equity [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

2.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

12.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fixed Income [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

68.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

78.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Cash and Cash Equivalents [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations Range Minimum

0.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

2.00%

Other Postretirement Benefit Plans, Defined Benefit [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]

$ 25

^[1]

^[2]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]

^[1]

^[2]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]

^[1]

^[2]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

International Equity [Member] | Equity Funds [Member]

$ 0

^[1]

$ 0

^[2]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Actual Plan Asset Allocations

7.00%

Fixed Income Funds [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Actual Plan Asset Allocations

73.00%

70.00%

U.S. Equity [Member] | Equity Funds [Member]

Schedule Of Fair Value Of Financial Assets For Pension And Postretirement Benefits [Line Items]

Defined Benefit Plan, Actual Plan Asset Allocations

20.00%

23.00%

Benefit Obligation [Member]

Postemployment Benefits

Postemployment Benefits Liability, Noncurrent

$ 14

Deferred Compensation Liability, Classified, Noncurrent

$ 3

[1]	73% of the amount invested in mutual funds was in fixed income securities; 20% was in U.S. equities and 7% was in international equities.
[2]	70% of the amount invested in mutual funds was in fixed income securities; 23% was in U.S. equities and 7% was in international equities.

Employee Benefit Plans Other Employee Matters (Details) - Employees Subject To Collective Bargaining Agreements [Member] - Labor Force Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2016
Number of Employees, Total [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	34.00%
Workforce Subject to Collective Bargaining Arrangements Expiring within One Year [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	12.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in May 2021 [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	3.00%
Workforce Subject to Collective Bargaining Arrangements Expiring in April and December 2020 [Member] [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Investments in money pool	$ 0	$ 0
Related Party Transaction, Amounts of Transaction	133	130	$ 127
Dividends paid to parent	643	43	405
Operation And Maintenance Expense [Member] \| CenterPoint Energy [Member]
Related Party Transaction [Line Items]
Corporate services charge	125	118	115
Operation And Maintenance Expense [Member] \| CenterPoint Houston [Member]
Related Party Transaction [Line Items]
Corporate services charge	15	18	17
Related Party Transaction, Other Revenues from Transactions with Related Party	$ (7)	$ (6)	$ (5)

Derivative Instruments (Details)

12 Months Ended

Dec. 31, 2016

USD ($)

Bcf

Dec. 31, 2015

USD ($)

Bcf

Dec. 31, 2014

USD ($)

Weather Hedges Term

10 years

$ 105,000,000

$ 140,000,000

67,000,000

87,000,000

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

(14,000,000)

56,000,000

52,000,000

29,000,000

$ 46,000,000

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

1,000,000

3,000,000

Aggregate fair value of assets already posted as collateral

Credit risk contingent feature assets

2,000,000

Weather Hedge Swap | Gains (Losses) in Revenue [Member]

84,000,000

^[1]

125,000,000

Derivative, Gain (Loss) on Derivative, Net

$ 0

$ (4,000,000)

(10,000,000)

Natural gas derivative

Derivative, Nonmonetary Notional Amount, Volume | Bcf

1,035

767

Derivative Assets (Liabilities), at Fair Value, Net

^[2]

$ 24,000,000

$ 109,000,000

Derivative, Fair Value, Net

^[3]

38,000,000

53,000,000

Natural gas derivative | Current Assets [Member]

(14,000,000)

56,000,000

Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement

^[3]

81,000,000

100,000,000

Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset

(30,000,000)

(11,000,000)

Derivative Asset

^[2]

51,000,000

89,000,000

Natural gas derivative | Other Noncurrent Assets [Member]

Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement

^[3]

24,000,000

40,000,000

Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset

(5,000,000)

(4,000,000)

Derivative Asset

^[2]

19,000,000

36,000,000

Natural gas derivative | Current Liabilities [Member]

Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement

^[3]

(57,000,000)

(62,000,000)

Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset

16,000,000

51,000,000

Derivative Liability

^[2]

(41,000,000)

(11,000,000)

Natural gas derivative | Other Noncurrent Liabilities [Member]

Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement

^[3]

(10,000,000)

(25,000,000)

Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset

5,000,000

20,000,000

Derivative Liability

^[2]

(5,000,000)

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

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

(18,000,000)

134,000,000

35,000,000

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

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

70,000,000

(105,000,000)

$ 11,000,000

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

^[4]

79,000,000

^[5],[6]

90,000,000

^[7],[8]

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

^[4]

14,000,000

^[5],[6]

2,000,000

^[7],[8]

^[4]

24,000,000

^[5],[6]

36,000,000

^[7],[8]

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

^[4]

5,000,000

^[5],[6]

^[7],[8]

^[4]

2,000,000

^[5],[6]

10,000,000

^[7],[8]

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

^[4]

43,000,000

^[5],[6]

60,000,000

^[7],[8]

^[4]

^[5],[6]

4,000,000

^[7],[8]

Natural gas derivative | Long [Member]

^[4]

$ 5,000,000

^[5],[6]

$ 25,000,000

^[7],[8]

Derivative, Nonmonetary Notional Amount, Volume | Bcf

112

Credit Risk Contract [Member]

Derivative Assets (Liabilities), at Fair Value, Net

$ 70,000,000

$ 125,000,000

Retail End Users [Member]

(14,000,000)

Financial Institutions [Member]

^[9]

47,000,000

115,000,000

Energy Marketers [Member]

33,000,000

Weather Hedge, Bilateral Cap Amount

4,000,000

10,000,000

2014To2015 [Member]

16,000,000

External Credit Rating, Investment Grade [Member]

External Credit Rating, Investment Grade [Member] | Retail End Users [Member]

^[10]

36,000,000

6,000,000

External Credit Rating, Investment Grade [Member] | Financial Institutions [Member]

^[9],[10]

2,000,000

External Credit Rating, Investment Grade [Member] | Energy Marketers [Member]

^[10]

33,000,000

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

^[10]

$ 1,000,000

$ 4,000,000

Derivative, Nonmonetary Notional Amount, Volume | Bcf

126

133

[1]	The net of total non-trading natural gas derivative assets was $70 million and $125 million as of December 31, 2016 and 2015, respectively, as shown on CERC’s Consolidated Balance Sheets, and was comprised of the natural gas contracts derivatives assets separately shown above, impacted by collateral netting of $14 million and $-0- as of December 31, 2016 and 2015, respectively.
[2]	The derivative assets and liabilities on the 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.
[3]	Gross amounts recognized include some derivative assets and liabilities that are not subject to master netting arrangements.
[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 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 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 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.
[6]	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.
[7]	Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts 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 Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $109 million asset as shown on CERC’s 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 $56 million.
[8]	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 767 Bcf or a net 112 Bcf long position. Of the net long position, basis swaps constitute 133 Bcf.
[9]	End users are comprised primarily of customers who have contracted to fix the price of a portion of their physical gas requirements for future periods.
[10]	“Investment grade” is primarily determined using publicly available credit ratings, and considers credit support (including parent company guarantees) and collateral (including cash and standby letters of credit). For unrated counterparties, CERC determines a synthetic credit rating by performing financial statement analysis, and considers contractual rights and restrictions and collateral.

Fair Value Measurements (Details)

12 Months Ended

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

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

Fair Value, Assets, Level 1 to Level 2 Transfers, Amount

$ 0

Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount

Fair Value, Assets, Level 2 to Level 1 Transfers, Amount

Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount

Assets

Derivative Asset, Fair Value, Gross Liability

(35,000,000)

^[1]

$ (15,000,000)

^[2]

83,000,000

138,000,000

Derivative Liability, Fair Value, Gross Asset

(21,000,000)

^[1]

(71,000,000)

^[2]

46,000,000

16,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation Roll Forward

(14,000,000)

56,000,000

Beginning balance

12,000,000

^[3]

17,000,000

^[3]

$ 3,000,000

Purchases

12,000,000

Total gains

12,000,000

7,000,000

14,000,000

Total settlements

(27,000,000)

(12,000,000)

1,000,000

Transfers out of Level 3

(1,000,000)

Transfers into Level 3

5,000,000

1,000,000

(1,000,000)

Ending balance (1)

^[3]

13,000,000

12,000,000

17,000,000

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

11,000,000

6,000,000

16,000,000

Carrying Amount [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation Roll Forward

Notes receivable - affiliated companies

363,000,000

Long-term debt

2,375,000,000

2,341,000,000

Fair Value [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation Roll Forward

Notes receivable - affiliated companies

356,000,000

Long-term debt

2,551,000,000

2,539,000,000

Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]

Assets

24,000,000

17,000,000

Significant Other Observable Inputs (Level 2) [Member]

4,000,000

13,000,000

Assets

74,000,000

115,000,000

Significant Unobservable Inputs (Level 3) [Member]

56,000,000

65,000,000

Assets

20,000,000

21,000,000

Fair Value, Measurements, Recurring [Member]

7,000,000

9,000,000

Assets

3,000,000

2,000,000

Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]

^[4]

10,000,000

11,000,000

Assets

3,000,000

2,000,000

Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]

^[4]

10,000,000

11,000,000

Assets

Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]

^[4]

Assets

^[4]

Natural gas derivative

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

(14,000,000)

56,000,000

Assets

Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset

^[5]

(35,000,000)

^[1]

(15,000,000)

^[2]

Natural gas derivatives (3)

^[5]

70,000,000

125,000,000

Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset

^[5]

(21,000,000)

^[1]

(71,000,000)

^[2]

Natural gas derivatives (2)

^[5]

46,000,000

16,000,000

Natural gas derivative | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]

Assets

Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement

^[5]

11,000,000

4,000,000

Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement

^[5]

4,000,000

13,000,000

Natural gas derivative | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]

Assets

Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement

^[5]

74,000,000

115,000,000

Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement

^[5]

56,000,000

65,000,000

Natural gas derivative | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]

Assets

Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement

^[5]

20,000,000

21,000,000

Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement

^[5]

$ 7,000,000

9,000,000

Option Held | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member]

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

Option volatilities low range

86.00%

Option Held | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member]

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

Option volatilities low range

0.00%

Forward Contracts | Maximum [Member] | Significant Unobservable Inputs (Level 3) [Member]

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

Illiquid forward price low range

7.01

Forward Contracts | Minimum [Member] | Significant Unobservable Inputs (Level 3) [Member]

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

Illiquid forward price low range

2.24

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation Roll Forward

Equity Method Investment, Other than Temporary Impairment

$ 0

$ 1,225,000,000

$ 0

[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 represent the impact of legally enforceable master netting arrangements that allow CERC to settle positive and negative positions and also include cash collateral of $56 million posted with the same counterparties.
[3]	During 2016, 2015 and 2014, CERC did not have significant Level 3 sales.
[4]	Amounts are included in Other Assets in the Consolidated Balance Sheets.
[5]	Natural gas derivatives include no material amounts related to physical forward transactions with Enable.

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

3 Months Ended

12 Months Ended

Nov. 22, 2016

Dec. 31, 2015

Sep. 30, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Jun. 30, 2015

May 30, 2014

Dec. 31, 2013

Service Agreement Notice For Termination At Term End

90 days

Service Agreement Notice For Termination At Will Number Of Days

180 days

Interest receivable related to notes receivable from Enable

$ 8

$ 5

$ 8

Equity in earnings (losses) of unconsolidated affiliates

2,594

2,505

2,594

$ 208

(1,633)

$ 308

Sale of Units, Percentage, Trigger Right of First Refusal

5.00%

Summarized unaudited consolidated income from Enable [Abstract]

Basis Difference, Amortization Period

33 years

Summarized unaudited consolidated balance sheet from Enable [Abstract]

Distribution received from unconsolidated affiliates [Abstract]

$ 2,594

$ 2,505

2,594

Proceeds from Equity Method Investment, Dividends or Distributions

$ 297

294

305

OGE [Member]

Sale of Units, Percentage, Trigger Right of First Refusal

5.00%

Southeast Supply Header LLC [Member]

Share Price

$ 15.73

25.05%

Equity in earnings (losses) of unconsolidated affiliates

^[1]

$ 0

Equity Method Investment, Contributed Ownership Percentage

0.10%

24.95%

Distribution received from unconsolidated affiliates [Abstract]

25.05%

Proceeds from Equity Method Investment, Dividends or Distributions

^[1]

$ 0

$ 7

55.40%

54.10%

^[2]

55.40%

Equity Method Investment, Other than Temporary Impairment

$ 0

$ 1,225

$ 0

Equity Method Investment, Carrying Value Per Unit

$ 10.71

Equity in earnings (losses) of unconsolidated affiliates

$ 2,594

$ 2,505

2,594

^[3]

$ 208

$ (1,633)

$ 303

Partners' Capital Account, Units, Sold in Public Offering

55.40%

54.10%

^[2]

55.40%

10,000,000

Summarized unaudited consolidated income from Enable [Abstract]

Operating revenues

$ 2,272

$ 2,418

$ 3,367

Cost of sales, excluding depreciation and amortization

1,017

1,097

1,914

Impairment of goodwill and other long-lived assets

1,134

Operating income (loss)

385

(712)

586

Net income (loss) attributable to Enable

290

(752)

530

CERC’s interest

160

(416)

298

Basis difference amortization (1)

^[4]

Impairment of CERC’s equity method investment in Enable

(1,225)

Impairment Charges

$ 984

$ 862

1,846

Goodwill And Long-LIved Assets Impairment Charges, Entity's Share

621

Income (Loss) From Equity Method Investment, Excluding Impairment Charge

213

Summarized unaudited consolidated balance sheet from Enable [Abstract]

Current assets

381

396

381

Non-current assets

10,845

10,816

10,845

Current liabilities

615

362

615

Non-current liabilities

3,080

3,056

3,080

Non-controlling interest

Preferred equity

362

Enable partners’ capital

7,519

7,420

7,519

CERC’s ownership interest in Enable partners’ capital

4,163

4,067

4,163

CERC’s basis difference

(1,569)

(1,562)

(1,569)

Distribution received from unconsolidated affiliates [Abstract]

2,594

2,505

2,594

Proceeds from Equity Method Investment, Dividends or Distributions

297

294

298

Enable Midstream Partners [Member] | ArcLight [Member]

Partners' Capital Account, Units, Sold in Public Offering

1,500,000

Extinguishment of Debt, Amount

363

Interest income related to notes receivable from Enable

Interest receivable related to notes receivable from Enable

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

Reimbursement of transition services (1)

^[5]

163

Accounts receivable for amounts billed for transition services

$ 1

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

Equity Method Investment, Ownership, Shares

94,151,707

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

Equity Method Investment, Ownership, Shares

139,704,916

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

Natural gas expenses, including transportation and storage costs

$ 110

117

$ 130

Accounts payable for natural gas purchases from Enable

$ 10

$ 11

Management Rights Ownership Percentage

50.00%

Distribution received from unconsolidated affiliates [Abstract]

Incentive Distribution Right

40.00%

Incentive Distribution Right, Maximum

50.00%

Enable Midstream Partners [Member] | OGE [Member]

Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage

25.70%

26.30%

Management Rights Ownership Percentage

50.00%

Distribution received from unconsolidated affiliates [Abstract]

Incentive Distribution Right

60.00%

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

Variable Interest Entity, Qualitative or Quantitative Information, Ownership, Shares

42,832,291

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

Variable Interest Entity, Qualitative or Quantitative Information, Ownership, Shares

68,150,514

Minimum [Member] | Enable Midstream Partners [Member]

Debt Instrument, Interest Rate, Stated Percentage Rate Range

2.10%

Minimum [Member] | Enable Midstream Partners [Member]

Distribution received from unconsolidated affiliates [Abstract]

Incentive Distribution, Distribution Per Unit

$ 0.2875

Maximum [Member] | Enable Midstream Partners [Member]

Debt Instrument, Interest Rate, Stated Percentage Rate Range

2.45%

Maximum [Member] | Enable Midstream Partners [Member]

Distribution received from unconsolidated affiliates [Abstract]

Incentive Distribution, Distribution Per Unit

$ 0.330625

Midstream Investments [Member]

Equity in earnings (losses) of unconsolidated affiliates

$ 208

$ (1,633)

$ 308

Midstream Investments [Member] | Southeast Supply Header LLC [Member]

Equity in earnings (losses) of unconsolidated affiliates

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

Equity in earnings (losses) of unconsolidated affiliates

2,594

2,505

2,594

^[6]

208

(1,633)

$ 303

Summarized unaudited consolidated balance sheet from Enable [Abstract]

$ 2,594

$ 2,505

$ 2,594

[1]	CERC contributed a 24.95% interest in SESH to Enable on May 30, 2014 and its remaining 0.1% interest in SESH to Enable on June 30, 2015.
[2]	In November 2016, Enable closed a public offering of 10,000,000 common units. In connection with the offering, Enable and an affiliate of ArcLight sold an additional combined 1,500,000 common units to the underwriters.
[3]	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.
[4]	Equity in earnings of unconsolidated affiliates includes CERC’s share of Enable earnings adjusted for the amortization of the basis difference of CERC’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized over approximately 33 years, the average life of the assets to which the basis difference is attributed.
[5]	Represents amounts billed under the Transition Agreements, including the costs of seconded employees. Actual transition services costs are recorded net of reimbursement.
[6]	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.

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

12 Months Ended

May 01, 2016

Dec. 31, 2016

Dec. 31, 2015

Unamortized issuance costs, net

Short-term Debt

^[1]

$ 35

$ 40

(10)

(12)

Unamortized discount (premium), net

(27)

(34)

^[2]

Long-term Debt, Excluding Current Maturities

2,125

2,016

^[2]

Long-term Debt, Current Maturities

^[1]

250

325

Debt, Current

^[1]

285

365

Size of Facility

600

Long-term Debt, Maturities in 2017

250

Long-term Debt, Maturities in 2018

300

Long-term Debt, Maturities in 2019

Long-term Debt, Maturities in 2020

Long-term Debt, Maturities in 2021

1,162

Inventory financing [Member]

Short-term Debt

^[1],[3]

Senior Notes [Member]

Extinguishment of Debt, Amount

$ 325

Debt Instrument, Interest Rate, Stated Percentage Rate Range

6.15%

Senior Notes 4.50% to 6.625% due 2016 to 2041

Long-term Debt, Gross, Noncurrent

1,593

1,843

^[2]

Long-term Debt, Gross, Current

^[1]

250

325

Commercial Paper [Member]

Long-term Debt, Gross, Noncurrent

^[4]

569

219

^[2]

Long-term Debt, Gross, Current

^[1],[4]

$ 0

Line of Credit [Member]

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

65.00%

Ratio of Indebtedness to Net Capital

0.358

Revolving Credit Facility [Member]

Letter of Credit [Member]

Loans

$ 0

Commercial Paper [Member]

Loans

Debt, Weighted Average Interest Rate

Loans

^[5]

$ 569

$ 219

1.03%

0.81%

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

Line of Credit Facility, Interest Rate Description

^[6]

1.25%

Minimum [Member] | Senior Notes 4.50% to 6.625% due 2016 to 2041

Debt Instrument, Interest Rate, Stated Percentage Rate Range

4.50%

Maximum [Member] | Senior Notes 4.50% to 6.625% due 2016 to 2041

Debt Instrument, Interest Rate, Stated Percentage Rate Range

6.625%

[1]	Includes amounts due or exchangeable within one year of the date noted.
[2]	Includes $12 million of unamortized debt issuance costs to reflect adoption of ASU 2015-03.
[3]	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.
[4]	Classified as long-term debt because the termination date of the facility that backstops the commercial paper is more than one year from the date noted.
[5]	Weighted average interest rate was approximately 1.03% and 0.81% as of December 31, 2016 and 2015, respectively.
[6]	Based on current credit ratings.

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income tax expense:
State	$ 6	$ 3	$ 10
Total current expense	6	3	10
Deferred income tax expense (benefit):
Federal	130	(488)	171
State	26	(54)	7
Total deferred expense (benefit)	156	(542)	178
Income Tax Expense (Benefit)	162	(539)	188
Income tax reconciliation
Income (loss) before income taxes	$ 407	$ (1,451)	$ 511
Federal statutory income tax rate	35.00%	35.00%	35.00%
Expected federal income tax expense (benefit)	$ 142	$ (508)	$ 179
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax	17	(33)	11
State valuation allowance, net of federal income tax	3	0	0
Other, net	0	2	(2)
Total	20	(31)	9
Income Tax Expense (Benefit)	$ 162	$ (539)	$ 188
Effective tax rate	40.00%	37.00%	37.00%
Deferred tax assets:
Benefits and compensation	$ 45	$ 39
Loss and credit carryforwards	451	388
AROs	64	59
Other	18	39
Valuation allowance	(5)	(2)
Total deferred tax assets	573	523
Deferred tax liabilities:
Deferred Tax Liabilities, Property, Plant and Equipment	1,017	929
Investment in unconsolidated affiliates	1,383	1,277
Regulatory assets/liabilities, net	8	0
Other	90	91
Total deferred tax liabilities	2,498	2,297
Net deferred tax liabilities	1,925	$ 1,774
Federal [Member]
Deferred tax assets:
Valuation allowance	(5)
Deferred tax liabilities:
Operating loss carryforwards	1,100
State and Local Jurisdiction [Member]
Deferred tax liabilities:
Operating loss carryforwards	958
Tax Credit Carryforward, Amount	11
Capital Loss Carryforward [Member] \| State and Local Jurisdiction [Member]
Deferred tax liabilities:
Tax Credit Carryforward, Amount	$ 244
Latest Tax Year [Member] \| State and Local Jurisdiction [Member]
Deferred tax liabilities:
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2036
Latest Tax Year [Member] \| Capital Loss Carryforward [Member] \| State and Local Jurisdiction [Member]
Deferred tax liabilities:
Other Tax Carryforward, Expiration Dates	Dec. 31, 2017
Earliest Tax Year [Member] \| Federal [Member]
Deferred tax liabilities:
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2031
Earliest Tax Year [Member] \| State and Local Jurisdiction [Member]
Deferred tax liabilities:
Operating Loss Carryforwards, Expiration Dates	Dec. 31, 2017

Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2017	$ 5
2018	4
2019	4
2020	3
2021	2
2022 and beyond	7
Total	25
Total lease expense for all operating leases	9	$ 8	$ 9
Minnesota Service Territory [Member]
Legal, Environmental and Other Regulatory Matters [Abstract]
Liability recorded for remediation of Minnesota sites	7
Minnesota Service Territory [Member] \| Minimum [Member]
Legal, Environmental and Other Regulatory Matters [Abstract]
Estimated remediation costs for the Minnesota sites	$ 5
Site Contingency, Years to Resolve Contingency	30 years
Minnesota Service Territory [Member] \| Maximum [Member]
Legal, Environmental and Other Regulatory Matters [Abstract]
Estimated remediation costs for the Minnesota sites	$ 30
Site Contingency, Years to Resolve Contingency	50 years
Natural Gas Supply Commitments [Member]
Long-term Purchase Commitment [Line Items]
2017	$ 461
2018	467
2019	268
2020	125
2021	127
2022 and beyond	$ 8

Unaudited Quarterly Information (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Revenues

$ 1,349

$ 978

$ 807

$ 1,320

$ 1,087

^[1]

$ 799

^[2]

$ 824

$ 1,817

$ 4,454

$ 4,527

$ 6,367

Operating income

108

166

108

^[1]

^[2]

160

318

313

335

Net income (loss)

$ 76

$ 43

$ 6

$ 120

(535)

^[1]

(508)

^[2]

$ 22

$ 109

$ 245

(912)

$ 323

Impairment Charge, net of tax

Impairment Charges

984

862

$ 1,846

$ 620

$ 537

[1]	CERC recognized $984 million ($620 million after tax) in impairment charges related to Enable during the three months ended December 31, 2015.
[2]	CERC recognized $862 million ($537 million after tax) in impairment charges related to Enable during the three months ended September 30, 2015.

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

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 1,349

$ 978

$ 807

$ 1,320

$ 1,087

^[1]

$ 799

^[2]

$ 824

$ 1,817

$ 4,454

$ 4,527

$ 6,367

249

227

206

108

$ 26

$ 18

$ 166

108

^[1]

^[2]

$ 27

$ 160

318

313

335

^[3]

9,218

9,141

9,218

9,141

11,030

515

606

528

Natural Gas Distribution [Member]

208

(1,633)

308

2,380

2,603

3,271

242

222

201

303

273

287

510

601

525

Energy Services [Member]

2,073

1,924

3,095

Midstream Investments [Member]

^[4]

^[4]

^[4]

^[4]

Corporate and Other [Member]

208

(1,633)

308

(5)

(2)

(4)

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

Operating Segments [Member] | Energy Services [Member]

^[3]

6,099

5,657

6,099

5,657

5,464

Operating Segments [Member] | Midstream Investments [Member]

^[3]

1,102

857

1,102

857

978

Operating Segments [Member] | Corporate and Other [Member]

^[3],[4]

2,505

2,594

2,505

2,594

4,521

Intersegment Eliminations [Member]

^[3]

777

1,031

(55)

(62)

(114)

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

^[3]

$ (563)

(744)

(563)

(744)

(964)

Intersegment Eliminations [Member] | Energy Services [Member]

(29)

(30)

Intersegment Eliminations [Member] | Midstream Investments [Member]

(26)

(33)

(84)

Intersegment Eliminations [Member] | Corporate and Other [Member]

^[4]

Equity Method Investment, Other than Temporary Impairment

^[5]

208

(1,633)

303

Impairment Charges

$ 984

$ 862

1,846

1,225

Goodwill And Long-LIved Assets Impairment Charges, Entity's Share

621

Income (Loss) From Equity Method Investment, Excluding Impairment Charge

213

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

Southeast Supply Header LLC [Member]

^[6]

208

(1,633)

303

Southeast Supply Header LLC [Member] | Midstream Investments [Member]

^[7]

$ 0

$ 5

[1]	CERC recognized $984 million ($620 million after tax) in impairment charges related to Enable during the three months ended December 31, 2015.
[2]	CERC recognized $862 million ($537 million after tax) in impairment charges related to Enable during the three months ended September 30, 2015.
[3]	Amounts for 2015 and 2014 have been restated to reflect the adoption of ASU 2015-03.
[4]	Midstream Investments’ equity earnings (losses) are as follows: Year Ended December 31, 2016 2015 2014 (in millions)Enable (a) $208 $(1,633) $303SESH — — 5 Total $208 $(1,633) $308(a)These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.
[5]	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.
[6]	These amounts include impairment charges totaling $1,846 million composed of CERC’s impairment of its equity method investment in Enable of $1,225 million and CERC’s share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.
[7]	CERC contributed a 24.95% interest in SESH to Enable on May 30, 2014 and its remaining 0.1% interest in SESH to Enable on June 30, 2015.

Reportable Business Segments Revenue by Products and Services (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

^[1]

Sep. 30, 2015

^[2]

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Retail Gas Sales [Member]

$ 1,349

$ 978

$ 807

$ 1,320

$ 1,087

$ 799

$ 824

$ 1,817

$ 4,454

$ 4,527

$ 6,367

Wholesale Gas Sales [Member]

3,329

3,725

5,049

Gas Transportation and Processing [Member]

977

657

1,159

Energy Products Or Services [Member]