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

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

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•	restricting the way we can handle or dispose of wastes;

•	limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;

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•	requiring remedial action to mitigate environmental conditions caused by our operations or attributable to former operations;

•	enjoining the operations of facilities with permits issued pursuant to such environmental laws and regulations; and

•	impacting the demand for our services by directly or indirectly affecting the use or price of natural gas.

•	construct or acquire new facilities and equipment;

•	acquire permits for facility operations;

•	modify, upgrade or replace existing and proposed equipment; and

•	clean or decommission waste management areas, fuel storage facilities and other locations.

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•	our payment of dividends;

•	our financings and our capital raising activities;

•	mergers or other business combinations; and

•	our acquisition or disposition of assets.

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•	general economic and capital market conditions;

•	credit availability from financial institutions and other lenders;

•	volatility or fluctuations in distributions from Enable’s units or volatility in Enable’s unit price;

•	investor confidence in us and CenterPoint Energy and the markets in which we operate;

•	maintenance of acceptable credit ratings by us and CenterPoint Energy;

•	market expectations regarding our and CenterPoint Energy’s future earnings and cash flows;

•	our and CenterPoint Energy’s ability to access capital markets on reasonable terms;

•	our exposure to GenOn (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG and currently the subject of bankruptcy proceedings, in connection with certain indemnification obligations;

•	incremental collateral that may be required due to regulation of derivatives; and

•	provisions of relevant tax and securities laws.

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•	the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;

•	the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;

•	the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;

•	the relationship among prices for natural gas, NGLs and crude oil;

•	cash calls and settlements of hedging positions;

•	margin requirements on open price risk management assets and liabilities;

•	the level of competition from other companies offering midstream services;

•	adverse effects of governmental and environmental regulation;

•	the level of its operation and maintenance expenses and general and administrative costs; and

•	prevailing economic conditions.

•	the level and timing of its capital expenditures;

•	the cost of acquisitions;

•	its debt service requirements and other liabilities;

•	fluctuations in its working capital needs;

•	its ability to borrow funds and access capital markets;

•	restrictions contained in its debt agreements;

•	the amount of cash reserves established by its general partner;

•	distributions paid on its Series A Preferred Units;

•	any impact on cash levels should any sale of our investment in Enable occur; and

•	other business risks affecting its cash levels.

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•	the availability and cost of capital;

•	prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

•	demand for natural gas, NGLs and crude oil;

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•	levels of reserves;

•	geological considerations;

•	environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

•	the availability of drilling rigs and other costs of production and equipment.

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•	Enable’s joint venture partners may share certain approval rights over major decisions;

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•	Enable’s joint venture partners may not pay their share of the joint venture’s obligations, leaving Enable liable for their shares of joint venture liabilities;

•	Enable may be unable to control the amount of cash it will receive from the joint venture;

•	Enable may incur liabilities as a result of an action taken by its joint venture partners;

•	Enable may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

•	Enable’s insurance policies may not fully cover loss or damage incurred by both Enable and its joint venture partners in certain circumstances;

•	Enable’s joint venture partners may be in a position to take actions contrary to its instructions or requests or contrary to its policies or objectives; and

•	disputes between Enable and its joint venture partners may result in delays, litigation or operational impasses.

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•	the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;

•	a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;

•	Enable’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and

•	Enable’s debt level may limit its flexibility in responding to changing business and economic conditions.

•	permit its subsidiaries to incur or guarantee additional debt;

•	incur or permit to exist certain liens on assets;

•	dispose of assets;

•	merge or consolidate with another company or engage in a change of control;

•	enter into transactions with affiliates on non-arm’s length terms; and

•	change the nature of its business.

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•	restricting the way we can handle or dispose of wastes;

•	limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

•	requiring remedial action to mitigate environmental conditions caused by our operations, or attributable to former operations;

•	enjoining the operations of facilities with permits issued pursuant to such environmental laws and regulations; and

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•	impacting the demand for our services by directly or indirectly affecting the use or price of natural gas.

•	construct or acquire new facilities and equipment;

•	acquire permits for facility operations;

•	modify or replace existing and proposed equipment; and

•	clean or decommission waste management areas, fuel storage facilities and other locations.

•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;

•	inadvertent damage from construction, vehicles, farm and utility equipment;

•	leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;

•	ruptures, fires and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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•	merchant energy, energy trading and retail electric provider businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001 and now owned by affiliates of NRG; and

•	Texas electric generating facilities transferred to a subsidiary of Texas Genco in 2002, later sold to a third party and now owned by an affiliate of NRG.

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•	operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;

•	the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;

•	operating limitations that may be imposed by environmental or other regulatory requirements;

•	labor disputes;

•	information technology or financial system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;

•	information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and

•	catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, terrorism, pandemic health events or other similar occurrences.

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•	perform ongoing assessments of pipeline integrity;

•	develop a baseline plan to prioritize the assessment of a covered pipeline segment;

•	identify and characterize applicable threats that could impact a high consequence area;

•	improve data collection, integration, and analysis;

•	develop processes for performance management, record keeping, management of change and communication;

•	repair and remediate pipelines as necessary; and

•	implement preventive and mitigating action.

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•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

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•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•	we or Enable may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;

•	we or Enable may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

•	acquisitions, or the pursuit of acquisitions, could disrupt ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures.

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

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

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•	the performance of Enable, the amount of cash distributions we receive from Enable, and the value of our interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:

◦	competitive conditions in the midstream industry, and actions taken by Enable’s customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Enable;

◦

the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;

◦	the demand for crude oil, natural gas, NGLs and transportation and storage services;

◦	environmental and other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing;

◦	recording of non-cash goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;

◦	changes in tax status;

◦	access to debt and equity capital; and

◦	the availability and prices of raw materials and services for current and future construction projects;

•	industrial, commercial and residential growth in our service territories and changes in market demand, including the effects of energy efficiency measures and demographic patterns;

•	timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;

•	future economic conditions in regional and national markets and their effect on sales, prices and costs;

•	weather variations and other natural phenomena, including the impact of severe weather events on operations and capital;

•	state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;

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•	tax reform and legislation, including the effects of the TCJA and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

•	our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;

•	the timing and extent of changes in commodity prices, particularly natural gas, and the effects of geographic and seasonal commodity price differentials;

•	problems with regulatory approval, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;

•	local, state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;

•	the impact of unplanned facility outages;

•	any direct or indirect effects on our or Enable’s facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, pandemic health events or other occurrences;

•	our ability to invest planned capital and the timely recovery of our investment in capital;

•	our ability to control operation and maintenance costs;

•	actions by credit rating agencies;

•	the sufficiency of our insurance coverage, including availability, cost, coverage and terms;

•	the investment performance of CenterPoint Energy, Inc.’s pension and postretirement benefit plans;

•	commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

•	changes in interest rates and their impact on our costs of borrowing;

•	changes in rates of inflation;

•	inability of various counterparties to meet their obligations to us;

•	non-payment for our services due to financial distress of our customers;

•	the extent and effectiveness of our risk management and hedging activities, including, but not limited to our financial and weather hedges;

•	timely and appropriate regulatory actions allowing the recovery of costs associated any future hurricanes or natural disasters, including costs associated with Hurricane Harvey;

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our or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses (including a reduction of our interests in Enable, if any, whether through our decision to sell all or a portion of the Enable common units we own in the public equity markets or otherwise, subject to certain limitations), which we cannot assure you will be completed or will have the anticipated benefits to us or Enable;

•	acquisition and merger activities involving us or our competitors;

•	our or Enable’s ability to recruit, effectively transition and retain management and key employees and maintain good labor relations;

•	the ability of GenOn (formerly known as RRI Energy, Inc., Reliant Energy and RRI), a wholly-owned subsidiary of NRG, and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations to us, including indemnity obligations;

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•	the outcome of litigation;

•	the timing and outcome of any audits, disputes and other proceedings related to taxes;

•	the effect of changes in and application of accounting standards and pronouncements; and

•	other factors we discuss under “Risk Factors” in Item 1A of this report and in other reports we file from time to time with the SEC.

•	a $323 million decrease in income tax expense, resulting from a reduction in income tax expense of $396 million due to tax reform, discussed further in Note 13 to our consolidated financial statements, offset by a $73 million increase in income tax expense primarily due to higher net income year over year;

•	a $126 million increase in operating income discussed below by segment; and

•	a $57 million increase in equity earnings from our investment in Enable, discussed further in Note 11 to our consolidated financial statements.

•	a $5 million decrease in miscellaneous other non-operating income included in Other Income, net shown above; and

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•	a $1 million increase in interest expense due to the issuance of $300 million of unsecured senior notes and higher weighted average commercial paper interest rates discussed further in Note 12 to our consolidated financial statements.

•	a $1,841 million increase in equity earnings from our investment in Enable, as 2015 results included impairment charges of $1,846 million, discussed further in Note 11 to our consolidated financial statements;

•	a $15 million decrease in interest expense due to lower weighted average interest rates on outstanding debt; and

•	a $5 million increase in operating income discussed below by segment.

•	a $701 million increase in income tax expense due to higher income before tax; and

•	$3 million decrease in interest income included in Other income, net shown above.

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•	rate increases of $38 million, primarily from Texas rate filings of $14 million, Arkansas rate case and formula rate plan filings of $9 million, Minnesota interim rates of $7 million and Mississippi RRA of $4 million;

•	higher other revenues of $8 million, primarily driven by transportation revenues;

•	customer growth of $7 million from the addition of over 30,000 new customers;

•	labor and benefits were favorable by $5 million, resulting primarily from the recording of a regulatory asset (and a corresponding reduction in expense) to recover $16 million of prior postretirement expenses in future rates established in the Texas Gulf rate order; and

•	an increase of $7 million from weather normalization adjustments, partially offset by $4 million of milder weather effects.

•	higher operation and maintenance expenses of $20 million, primarily due to increased bad debt expenses of $7 million, increased contract services of $7 million, increased insurance costs of $3 million and increased corporate support services expenses of $2 million; and

•	increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $16 million.

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•	rate increases of $55 million, primarily from the 2015 Minnesota rate case, including the decoupling rider, and the Texas GRIP filing;

•	lower bad debt expense of $12 million resulting from lower customer bills due to warmer than normal weather as well as credit and collections process improvements that have reduced write-offs;

•	an increase of $26 million from weather normalization adjustments, including weather-related decoupling and hedging activities, partially offset by $19 million of milder weather effects; and

•	customer growth of $5 million from the addition of over 35,000 new customers.

•	increased depreciation and amortization of $20 million, primarily due to ongoing additions to plant in service;

•	higher labor and benefits expenses of $11 million, primarily driven by increased pension costs;

•	higher contract services expenses of $10 million, primarily for increased pipeline integrity, leak surveying and repair activities; and

•	increased operation and maintenance expenses of $8 million related to higher support services costs and other miscellaneous expenses.

(1)	Includes the change in unrealized mark-to-market value and the impact from derivative assets and liabilities acquired through the purchase of Continuum and AEM.

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(2)	These numbers do not include approximately 72,000 and 60,100 natural gas customers as of December 31, 2017 and 2016, respectively, that are under residential and small customer choice programs invoiced by their host utility.

(1)	These amounts include impairment charges totaling $1,846 million composed of the impairment of our investment in Enable of $1,225 million and our 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.

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(1)	We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2017. We typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(2)	For a discussion of operating leases, please read Note 14(c) to our consolidated financial statements.

(3)	We expect to contribute approximately $5 million to our postretirement benefits plan in 2018 to fund a portion of our obligations in accordance with rate orders or to fund pay-as-you-go costs associated with the plan.

(4)	For a discussion of other commodity commitments, please read Note 14(a) to our consolidated financial statements.

(5)	This table does not include estimated future payments for expected future AROs. These payments are primarily estimated to be incurred after 2023. We record a separate liability for the fair value of AROs, which totaled $243 million as of December 31, 2017. See Note 3(c) to our consolidated financial statements.

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(1)	Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.

(2)	Amounts are recorded when approved.

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(1)	Represents outstanding commercial paper of $898 million and outstanding letters of credit of $1 million.

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(1)	A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.

(2)	An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

(3)	A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.

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•	cash collateral requirements that could exist in connection with certain contracts, including our weather hedging arrangements, and gas purchases, gas price and gas storage activities of our Natural Gas Distribution and Energy Services business segments;

•	acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;

•	increased costs related to the acquisition of natural gas;

•	increases in interest expense in connection with debt refinancings and borrowings under our credit facility;

•	various legislative or regulatory actions;

•	incremental collateral, if any, that may be required due to regulation of derivatives;

•	the ability of GenOn and its subsidiaries, currently the subject of bankruptcy proceedings, to satisfy their obligations in respect of GenOn’s indemnity obligations to CenterPoint Energy and its subsidiaries;

•	slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;

•	the outcome of litigation brought by or against us;

•	restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and

•	various other risks identified in “Risk Factors” in Item 1A of Part I of this report.

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•	Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.

•	Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, NGLs and other energy commodities.

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

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

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(1)	Net income for the year ended December 31, 2017 includes a reduction in income taxes of $396 million due to tax reform. See Note 13 for further discussion of the impacts of tax reform implementation.

(1)	See Note 4.

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

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(1)	Current regulatory assets are included in Other current assets in CERC’s Consolidated Balance Sheets.

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(2)	CERC is not earning a return on its Hurricane Harvey restoration costs.

(3)	EDIT will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 13 for additional information.

(4)	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 $7 million and $6 million as of December 31, 2017 and 2016, respectively, were not earning a return.

(5)	Current regulatory liabilities are included in Other current liabilities in CERC’s Consolidated Balance Sheets.

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(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.

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(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.

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

(2)	This accumulated other comprehensive component is included in the computation of net periodic cost.

(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.

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(1)	71% of the amount invested in mutual funds was in fixed income securities; 21% was in U.S. equities and 8% was in international equities.

(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.

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(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,795 Bcf or a net 224 Bcf long position.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(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 $130 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 $19 million.

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

(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.

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(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.  Certain natural gas contracts hedge basis risk only and lack a fixed price exposure.

(2)

Natural gas contracts are presented on a net basis in the 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 $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.

(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.

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(1)

Hedge ineffectiveness results from the basis ineffectiveness discussed above, and excludes the impact to natural gas expense from timing ineffectiveness.  Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.  As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on natural gas expense.

(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 $154 million and $70 million as of December 31, 2017 and 2016, respectively, as shown on CERC’s Consolidated Balance Sheets, and was comprised of the natural gas contracts

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(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 $19 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.

(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.

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

(2)	During 2017, 2016 and 2015, CERC did not have significant Level 3 sales.

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

(1)

The 139,704,916 subordinated units previously owned by CERC Corp. converted into common units of Enable on a one-for-one basis, on August 30, 2017, at the end of the subordination period, as set forth in Enable’s Fourth Amended and Restated Agreement of Limited Partnership. Upon conversion, holders of common units resulting from the conversion of subordinated units have all the rights and obligations of unitholders holding all other common units, including the right to receive distributions pro rata made with respect to common units.

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(1)	Represents amounts billed under the Transition Agreements, including the costs of seconded employees. Substantially all of the seconded employees became employees of Enable effective January 1, 2015. Actual transition services costs are recorded net of reimbursement.

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(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 31 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.

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

(2)

NGD has AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. The AMAs have varying terms, the longest of which expires in 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.

(3)	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.

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(1)	Weighted average interest rate was approximately 1.72% and 1.03% as of December 31, 2017 and December 31, 2016, respectively.

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

(2)	Based on current credit ratings.

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

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(1)	Net income for the fourth quarter 2017 includes a reduction in income taxes of $396 million due to tax reform. See Note 13 for further discussion of the impacts of tax reform implementation.

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

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

(a)	Includes 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.

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•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

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(1)	For 2017 and 2016, amounts include fees for services provided by the principal accounting firm relating to the integrated audit of financial statements and internal control over financial reporting, statutory audits, attest services, and regulatory filings.

(2)	For 2017 and 2016, includes fees for consultations concerning financial accounting and reporting standards and various agreed-upon or expanded procedures related to accounting records to comply with financial accounting or regulatory reporting matters.

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(1)	Excluded from the computation of fixed charges for the years ended December 31, 2013 is interest income of $3 million, which is included in income tax expense.

(2)	Net income for the year ended December 31, 2017 includes a reduction in income taxes of $396 million due to tax reform. See Note 13 for further discussion of the impacts of tax reform implementation.

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.