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Item 1.	Business

(1)	Houston Electric engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston.

(2)	Bond Companies are wholly-owned, bankruptcy remote entities formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds.

(3)	NGD operates natural gas distribution systems in six states.

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(4)	CES 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 over 30 states.

(5)

As of December 31, 2018, CNP Midstream owned approximately 54.0% of the common units representing limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets; CNP Midstream also owned 50% of the management rights and 40% of the incentive distribution rights in Enable GP. For additional information regarding CenterPoint Energy’s interest in Enable, including the 14,520,000 Enable Series A Preferred Units directly owned by CenterPoint Energy, see Note 11 to the consolidated financial statements.

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•	our Code of Ethics for our Chief Executive Officer and Senior Financial Officers;

•	our Ethics and Compliance Code;

•	our Corporate Governance Guidelines; and

•	the charters of the audit, compensation, finance and governance committees of our Board of Directors.

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•	the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and

•	the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.

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•	restricting the way the Registrants 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 and monitoring to mitigate environmental conditions caused by the Registrants’ 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 the Registrants’ 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

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

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Item 1A.	Risk Factors

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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 the markets in which we operate;

•	the future performance of our and Enable’s businesses;

•	integration of Vectren’s businesses into CenterPoint Energy;

•	maintenance of acceptable credit ratings;

•	market expectations regarding our future earnings and cash flows;

•	our ability to access capital markets on reasonable terms;

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•	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;

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•	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 Enable GP;

•	distributions paid on the Enable Series A Preferred Units;

•	any impact on cash levels should any sale of CenterPoint Energy’s investment in Enable occur, as discussed further below; and

•	other business risks affecting its cash levels.

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•	Contract Renewal: Enable’s contracts are subject to renewal risks. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions could be adversely affected;

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Customers: Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers or the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect Enable’s financial position, results of operations and ability to make cash distributions;

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Third-Party Drilling and Production Decisions: Enable’s businesses are dependent, in part, on the natural gas and crude oil drilling and production market conditions and decisions of others, over which Enable has no control. Further, sustained reductions in exploration or production activity in Enable’s areas of operation and fluctuations in energy prices could lead to further reductions in the utilization of Enable’s systems, which could adversely affect its financial position, results of operations and ability to make cash distributions. It may also become more difficult to maintain or increase the current volumes on Enable’s gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which it operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, Enable may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time;

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Competition: Enable competes with similar enterprises, some of which include large energy companies with greater financial resources and access to natural gas, NGL and crude oil supplies, in its respective areas of operation, primarily through rates, terms of service and flexibility and reliability of service. Increased competitive pressure in Enable’s industry, which is already highly competitive, could adversely affect Enable’s financial position, results of operations and ability to make cash distributions;

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Cost Recovery of Capital Improvements: Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates. In Enable’s Form 10-K for the fiscal year ended December 31, 2018, Enable stated that it expects that its expansion capital could range from approximately $325 million to $425 million and its maintenance capital could range from approximately $105 million to $125 million for the year ending December 31, 2019;

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Commodity Prices: Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. Factors affecting prices are beyond Enable’s control and include the following: (i) demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, (ii) the availability of imported natural gas, LNG, NGLs and crude oil, (iii) actions taken by foreign natural gas and oil producing nations, (iv) the availability of local, intrastate and interstate transportation systems, (v) the availability and marketing of competitive fuels, (vi) the impact of energy conservation efforts, technological advances affecting energy consumption and (vii) the extent of governmental regulation and taxation. Further, Enable’s natural gas processing arrangements expose it to commodity price fluctuations. In 2018, 6%, 27% and 67% of Enable’s processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which Enable purchases natural gas or NGLs under these arrangements, then Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected;

•	Credit Risk of Customers: Enable is exposed to credit risks of its customers, and any material nonpayment or nonperformance by its customers, whether through severe financial problems or otherwise, could adversely affect its financial position, results of operations and ability to make cash distributions;

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“Negotiated Rate” Contracts: Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts, which are authorized by the FERC, that are not subject to adjustment, even if its cost to perform these services exceeds the revenues received from these contracts. As of December 31, 2018, approximately 44% of Enable’s aggregate contracted firm transportation capacity on EGT and MRT and 45% of its aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such “negotiated rate” contracts. As a result, Enable’s costs could exceed its revenues received under these contracts, and if Enable’s costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution could also decrease;

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Unavailability of Interconnected Facilities: If third-party pipelines and other facilities interconnected to Enable’s gathering, processing or transportation facilities (including those providing transportation of natural gas and crude oil, transportation and fractionation of NGLs and electricity for compression, among others) become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected; and

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Land Ownership: Enable does not own all of the land on which its pipelines and facilities are located, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate, which could disrupt its operations or result in increased costs related to the construction and continuing operations elsewhere and adversely affect its financial position, results of operations and ability to make cash distributions.

•	Enable shares certain approval rights over major decisions and may not be able to control decisions, including control of cash distributions to Enable from the joint venture;

•	Enable may incur liabilities as a result of an action taken by its joint venture partners, including leaving Enable liable for the other joint venture partners’ shares of joint venture liabilities if those partners do not pay their share of the joint venture’s obligations;

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•	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 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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Rate Regulation: The rates charged by several of Enable’s pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. Enable’s pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas transportation services and crude oil gathering services. The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer.

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FERC Revised Policy Statement and NOPR: In a series of related issuances on March 15, 2018, the FERC issued a Revised Policy Statement stating that it will no longer permit pipelines organized as MLPs to recover an income tax allowance in their cost-of-service rates. On July 18, 2018, FERC issued a Final Rule adopting procedures that are generally the same as proposed in a March 15, 2018 NOPR implementing the Revised Policy Statement and the corporate income tax rate reduction with certain clarifications and modifications. For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. If FERC requires Enable to establish new tariff rates for either its natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions to its unitholders. With regard to FERC-jurisdictional rates on Enable’s crude oil pipelines, the FERC plans to address the Revised Policy Statement and corporate tax rate reduction in its next five-year review of the oil pipeline rate index, which will occur in 2020 and become effective July 1, 2021. The potential rate impacts from the revision are currently uncertain.

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Permits, Licenses and Approvals: Enable may be unable to obtain or renew federal or state permits, licenses or approvals necessary for its operations, which could inhibit its ability to do business. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable’s compliance status may result in the imposition of fines, penalties and injunctive relief. Further, to obtain new permits or renew permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to potential adverse impact of a proposed project. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable’s project construction schedules;

•	Hydraulic Fracturing Regulation: Increased regulation of hydraulic fracturing and waste water injection wells could result in reductions or delays in natural gas or crude oil production by Enable’s customers, which could adversely affect its financial position, results of operations and ability to make cash distributions; and

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Jurisdictional Characterization of Assets: Enable’s natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the NGA, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of the FERC under ICA. FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, Enable’s operations could be adversely affected should they become subject to the application of state regulation of rates and services. A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

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•	unanticipated delays, disruptions, issues or costs in integrating operations, financial and accounting, information technology, communications and other systems;

•	potential inconsistencies in procedures, practices, policies, controls, and standards;

•	possible differences in compensation arrangements, management perspectives and corporate culture; and

•	loss of or difficulties retaining talented employees or valuable third-party relationships.

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•	restricting the way we manage hazardous and non-hazardous wastes;

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

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

•	limiting airborne emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), nitrogen oxides (NOx) and mercury, and the disposal non-hazardous substances such as coal combustion residuals, among others;

•	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 or replace existing and proposed equipment; and

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

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•	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 and farm and utility equipment;

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•	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.

•	merchant energy, energy trading and REP 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.

•	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;

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•	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, which may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.

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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.

•	The collective bargaining agreement with IBEW Local 66 related to employees of Houston Electric is scheduled to expire in May 2020;

•	The collective bargaining agreements with USW Locals 13-227 and 13-1 related to NGD’s employees in Texas are scheduled to expire in June 2022 and July 2022, respectively;

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•	The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 and Mankato related to NGD employees in Minnesota are scheduled to expire in April 2020, December 2020, May 2021 and March 2021, respectively;

•	The collective bargaining agreements with IBEW Local 1393, USW Locals 12213 and 7441 related to employees of NGD in Indiana are scheduled to expire in December 2020;

•	The collective bargaining agreements with the Teamsters, Chauffeurs, Warehousemen and Helpers Union Local 135 and Utility Workers Union Local 175 related to employees of Indiana Electric were recently renegotiated and are scheduled to expire in September 2021 and October 2021, respectively; and

•	The collective bargaining agreement with IBEW Local 702 related to employees of Indiana Electric was scheduled to expire in June 2019 but was renegotiated in January 2019 with the ratification of a new three-year labor agreement.

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

•	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 our or Enable’s ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures.

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Item 1B.	Unresolved Staff Comments

Item 2.	Properties

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Item 3.	Legal Proceedings

Item 4.	Mine Safety Disclosures

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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(1)	Net income for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 to the consolidated financial statements for further discussion of the impacts of the TCJA implementation.

(2)	This amount includes $1,846 million of non-cash impairment charges related to Enable.

(3)	Amounts for 2014 and 2015 have been recast to reflect adoption of ASU 2015-03.

(4)	Total assets as of December 31, 2018 include cash and cash equivalents of $4.2 billion.

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

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•	Houston Electric engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and

•	CERC Corp. (i) owns and operates natural gas distribution systems in six states and (ii) 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 over 30 states through its wholly-owned subsidiary, CES.

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Electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution reportable segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. For further information about the Electric Transmission & Distribution reportable segment, see “Business — Our Business — Electric Transmission & Distribution” in Item 1 of Part I of this report.

•	Natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution reportable segment. For further information about the Natural Gas Distribution reportable segment, see “Business — Our Business — Natural Gas Distribution” in Item 1 of Part I of this report.

•	The Energy Services reportable segment includes non-rate regulated natural gas sales to, and transportation and storage services, for commercial and industrial customers. For further information about the Energy Services reportable segment, see “Business — Our Business — Energy Services” in Item 1 of Part I of this report.

•	The results of the Midstream Investments reportable segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Midstream Investments.”

•	CenterPoint Energy’s Other Operations reportable segment includes office buildings and other real estate used for business operations, home repair protection plans through a third party and other corporate support operations that support

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•	the performance of Enable, the amount of cash distributions CenterPoint Energy receives from Enable, Enable’s ability to redeem the Enable Series A Preferred Units in certain circumstances and the value of CenterPoint Energy’s 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;

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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 goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;

◦	changes in tax status; and

◦	access to debt and equity capital;

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CenterPoint Energy’s expected benefits of the Merger and integration, including the outcome of shareholder litigation filed against Vectren that could reduce anticipated benefits of the Merger, as well as the ability to successfully integrate the Vectren businesses and realize anticipated benefits and the risk that the credit ratings of the combined company or its subsidiaries may be different from what CenterPoint Energy expects;

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

•	timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment, including Houston Electric’s anticipated rate case in 2019, the outcome of which may not result in expected rates or recovery of costs;

•	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 legislation, including the effects of the TCJA (which includes any potential changes to interest deductibility) and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

•	CenterPoint Energy’s and CERC’s 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 on CERC and Enable;

•	actions by credit rating agencies, including any potential downgrades to credit ratings;

•	changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;

•	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;

•	the availability and prices of raw materials and services and changes in labor for current and future construction projects;

•	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 investments;

•	our ability to control operation and maintenance costs;

•	the sufficiency of our insurance coverage, including availability, cost, coverage and terms and ability to recover claims;

•	the investment performance of CenterPoint Energy’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 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 and Enable’s risk management and hedging activities, including, but not limited to financial and weather hedges and commodity risk management activities;

•	timely and appropriate regulatory actions, which include actions allowing securitization, for any future hurricanes or natural disasters or other recovery of costs, including costs associated with Hurricane Harvey;

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CenterPoint Energy’s 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 CenterPoint Energy’s interest in Enable, if any, whether through its decision to sell a portion of the Enable common units it owns in the public equity markets or otherwise, subject to certain limitations), which CenterPoint Energy and Enable cannot assure will be completed or will have the anticipated benefits to CenterPoint Energy or Enable;

•	acquisition and merger activities involving us or our competitors, including the ability to successfully complete merger, acquisition and divestiture plans;

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

•	the outcome of litigation;

•	the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;

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•	changes in technology, particularly with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation;

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

•	the effective tax rates;

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

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

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an $875 million increase in income tax expense, resulting from a reduction in income tax expense of $1,113 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $238 million decrease in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018 and lower income before income taxes year over year;

•	a $305 million decrease in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment;

•	a $281 million increase in losses on indexed debt securities related to the ZENS, resulting from a loss of $11 million from Meredith’s acquisition of Time in March 2018, a loss of $242 million from AT&T’s acquisition of TW in June 2018 and reduced gains of $28 million in the underlying value of the indexed debt securities;

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•	a $48 million increase in interest expense primarily due to higher outstanding other long-term debt and the amortization of Bridge Facility fees of $24 million;

•	a $35 million increase in preferred stock dividend requirements; and

•	a $29 million increase in losses on marketable securities.

•	an $17 million decrease in the non-service cost components of net periodic pension and post-retirement costs included in Other Income (Expense), net shown above;

•	a $4 million increase in dividend income on CenterPoint Energy’s ZENS-Related Securities included in Other Income (Expense), net shown above; and

•	a $983 million decrease in income tax expense, resulting from a reduction in income tax expense of $1,113 million due to tax reform, discussed further in Note 15 to the consolidated financial statements, offset by a $130 million increase in income tax expense primarily due to higher net income year over year;

•	a $462 million increase in gains on indexed debt securities related to the ZENS, resulting from increased gains of $345 million in the underlying value of the indexed debt securities and a loss of $117 million from the Charter merger in 2016;

•	a $113 million increase in operating income discussed below by reportable segment in Results of Operations by Reportable Segment;

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

•	a $25 million decrease in interest expense due to lower weighted average interest rates on outstanding debt;

•	a $17 million decrease in losses on early debt redemption;

•	a $14 million increase in cash distributions on the Enable Series A Preferred Units included in Other Income (Expense), net shown above; and

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•	a $14 million decrease in interest expense related to lower outstanding balances of the Securitization Bonds.

•	a $98 million increase in income tax expense, resulting from a reduction in income tax expense of $158 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $60 million decrease in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018; and

•	an $10 million increase in interest expense due to higher outstanding other long-term debt.

•	a $5 million decrease in non-service cost components of net periodic pension and post-retirement costs included in Other expense, net shown above; and

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•	an $8 million increase in TDU operating income resulting from a $7 million increase discussed below in Results of Operations by Reportable Segment and increased usage of $1 million, primarily due to a return to more normal weather, which was not offset by the weather hedge loss recorded on CenterPoint Energy.

•	a $158 million decrease in income tax expense due to a reduction in the corporate income tax rate resulting from the TCJA; and

•	a $1 million increase in TDU operating income resulting from a $1 million decrease discussed below in Results of Operations by Reportable Segment, which was more than offset by increased usage of $2 million, primarily due to a return to more normal weather, which was not offset by the weather hedge loss recorded on CenterPoint Energy.

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a $287 million increase in income tax expense, resulting from a reduction in income tax expense of $396 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $109 million decrease in income tax expense primarily due to lower income from continuing operations and a reduction in the corporate income tax rate resulting from the TCJA in 2018;

•	a $245 million decrease in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment; and

•	a $23 million decrease in income from discontinued operations, net of tax, due to the Internal Spin discussed further in Note 11 to the consolidated financial statements.

•	a $12 million decrease in the non-service cost components of net periodic pension and post-retirement costs included in Other expense, net shown above;

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

•	a $1 million decrease in interest expense due to lower outstanding long-term debt.

•	a $346 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 15 to the consolidated financial statements, offset by a $50 million increase in income tax expense primarily due to higher income from continuing operations year-over-year;

•	a $126 million increase in operating income discussed below in Results of Operations by Reportable Segment; and

•	a $34 million increase in income from discontinued operations, net of tax, discussed further in Notes 11 and 15 to the consolidated financial statements.

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

•	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 14 to the consolidated financial statements.

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(1)	Excludes weather hedge gain (loss) of $(2) million, $(1) million and $1 million recorded on CenterPoint Energy. See Note 9(a) to the consolidated financial statements for more information on the weather hedge.

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(1)	Represents the amount necessary to pay interest on the Securitization Bonds.

•	higher transmission-related revenues of $37 million, exclusive of the TCJA, and lower transmission costs billed by transmission providers of $32 million;

•	customer growth of $31 million from the addition of over 41,000 customers;

•	rate increases of $36 million related to distribution capital investments, exclusive of the TCJA;

•	higher equity return of $32 million, primarily related to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months;

•	higher miscellaneous revenues of $9 million largely due to right-of-way and fiber and wireless revenues; and

•	higher usage of $8 million, primarily due to a return to more normal weather.

•	increased operation and maintenance expenses of $79 million, excluding transmission costs billed by transmission providers, primarily due to the following:

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◦	contract services of $24 million, largely due to increased resiliency spend and services related to fiber and wireless;

◦	support services of $23 million, primarily related to technology projects;

◦	labor and benefits costs of $14 million;

◦	other miscellaneous operation and maintenance expenses of $12 million; and

◦	damage claims from third parties of $6 million;

•

lower revenues of $79 million due to the recording of a regulatory liability and a corresponding decrease to revenue of $31 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rate and the revenues that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower revenues of $48 million due to lower transmission and distribution rate filings as a result of the TCJA; and

•	higher depreciation and amortization expense, primarily because of ongoing additions to plant in service, and other taxes of $17 million.

•	lower equity return of $22 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during the preceding 12 months;

•	higher depreciation, primarily because of ongoing additions to plant in service, and other taxes of $20 million;

•	higher operation and maintenance expenses of $18 million, primarily due to higher labor and benefits costs of $10 million and corporate support services expenses of $8 million;

•	lower usage of $15 million; and

•	rate increases of $47 million related to distribution capital investments;

•	higher transmission-related revenues of $61 million, partially offset by transmission costs billed by transmission providers of $56 million.

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lower revenue of $47 million, associated with the recording of a regulatory liability and a corresponding decrease to revenue in certain jurisdictions of $14 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rates and the revenues that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower filing amounts of $33 million associated with the lower corporate tax rate as a result of the TCJA;

•	higher operation and maintenance expenses of $41 million, primarily consisting of:

◦	materials and supplies, contracts and services and bad debt expenses of $15 million;

◦	support services expenses of $16 million, primarily related to technology projects; and

◦	other miscellaneous operation and maintenance expenses of $10 million;

•	higher labor and benefits costs of $30 million, resulting from the recording in 2017 of regulatory assets (and a corresponding reduction in expense) to recover $16 million of prior post-retirement expenses in future rates established in the Texas Gulf rate order and additional maintenance activities;

•	increased depreciation and amortization expense of $17 million, primarily due to ongoing additions to plant-in-service;

•	decreased revenue of $10 million, primarily driven by timing of weather normalization adjustments; and

•	higher other taxes of $2 million, primarily due to higher property taxes.

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•	rate increases of $46 million, primarily in the Texas, Minnesota and Arkansas jurisdictions, exclusive of the TCJA impact discussed above;

•	an increase in non-volumetric revenues of $10 million; and

•	a $10 million increase associated with customer growth from the addition of over 36,000 customers.

•	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 $18 million, primarily due to increased bad debt expenses of $7 million, increased contract services of $7 million and increased insurance costs of $3 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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(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.

(2)	These numbers do not include approximately 65,000, 72,000 and 60,100 natural gas customers as of December 31, 2018, 2017 and 2016, respectively, that are under residential and small commercial choice programs invoiced by their host utility.

•	a $189 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins; and

•	an $10 million increase in operation and maintenance expenses, attributable to increased technology expenses, higher contract and services expense related to pipeline integrity testing, higher support services and legal expenses.

•

a $22 million increase in margin due to increased opportunities to optimize natural gas supply costs through storage and transportation capacity, primarily in the first quarter of 2018, and incremental volumes from customers. Realized commercial opportunities attributable to the Continuum and AEM acquisitions and colder than normal weather in several regions of the United States, primarily in the first quarter of 2018, drove incremental sales volumes; and

•	a $5 million increase in margin due to increased revenues from energy delivery to customers through CEIP interconnect projects and MES’ portable natural gas supply services.

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(1)	This change is partially offset by the change in distributions from Enable in excess of cumulative earnings in investing activities noted in the table below.

(2)	See Notes 2(c) and 11 to the consolidated financial statements for a discussion of CERC’s discontinued operations.

(1)	See Notes 2(c) and 11 to the consolidated financial statements for a discussion of CERC’s discontinued operations.

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(1)	On February 1, 2019, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. In conjunction with the consummation of the Merger, $759 million of debt at Vectren was redeemed due to the change in control. For further discussion of the Merger, see Note 4 to the consolidated financial statements.

(2)	CenterPoint Energy’s estimated capital expenditures include estimated capital expenditures for Vectren and its subsidiaries as of the closing of the Merger.

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(1)	Vectren 2019 capital expenditures reflect capital expenditure estimates for the period February through December 2019 only.

(2)	Houston Electric consists of a single reportable segment, Electric Transmission & Distribution.

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(1)

ZENS obligations are included in the 2024 and thereafter column at their contingent principal amount as of December 31, 2018 of $93 million.  These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($540 million as of December 31, 2018), as discussed in Note 12 to the consolidated financial statements.

(2)

The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2018. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3)	For a discussion of operating leases, please read Note 16(c) to the consolidated financial statements.

(4)	See Note 8(g) to the consolidated financial statements for information on the Registrants’ expected contributions to pension plans and other postretirement plans in 2019.

(5)	For a discussion of commodity and other commitments, please read Note 16(a) to the consolidated financial statements.

(6)	This table does not include estimated future payments for expected future AROs. These payments are primarily estimated to be incurred after 2024. See Note 3(c) to the consolidated financial statements for further information.

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

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(1)	Pursuant to the amendment entered into in May 2018, the aggregate commitments under the CenterPoint Energy revolving credit facility increased to $3.3 billion on October 5, 2018 due to the satisfaction of certain conditions, including the termination of the Bridge Facility. For further information, see Note 4 to the consolidated financial statements.

(2)	Vectren’s outstanding short-term and long-term debt on the closing date of the Merger became debt of CenterPoint Energy.

(3)	Issued by CERC Corp.

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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 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.

(4)	Issued by CERC Corp.

(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 outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

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•	cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments;

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

•	increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC);

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

•	various legislative or regulatory actions;

•	incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy and CERC);

•	the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;

•	slower customer payments and increased write-offs of receivables due to higher natural gas prices or changing economic conditions (CenterPoint Energy and CERC);

•	the outcome of litigation;

•	contributions to pension and postretirement benefit plans (CenterPoint Energy);

•	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.

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•	Equity price risk results from exposures to changes in prices of individual equity securities (CenterPoint Energy).

•	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 (CenterPoint Energy and CERC).

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•	Houston Electric engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and

•	CERC Corp. (i) owns and operates natural gas distribution systems in six states and (ii) 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 over 30 states through its wholly-owned subsidiary, CES.

(a)	Use of Estimates

(b)	Principles of Consolidation

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(c)	Equity and Investments without a Readily Determinable Fair Value (CenterPoint Energy and CERC)

(d)	Revenues

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(1)	Included in Interest and other finance charges on the Registrants’ respective Statements of Consolidated Income.

(2)	Included in Other Income (Expense) on the Registrants’ respective Statements of Consolidated Income.

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(1)	Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.

(2)

In 2018, CenterPoint Energy and CERC reflected a decrease in their respective ARO liability which is primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation. In 2017, CenterPoint Energy and CERC reflected an increase in their respective ARO liability which is primarily attributable to decreases in the long-term interest rates used for discounting in the ARO calculation.

•	Indiana Gas provides energy delivery services to natural gas customers located in central and southern Indiana;

•	SIGECO provides energy delivery services to electric and natural gas customers located near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market; and

•	VEDO provides energy delivery services to natural gas customers located near Dayton in west-central Ohio.

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•	Infrastructure Services provides underground pipeline construction and repair services; and

•	ESG provides energy performance contracting and sustainable infrastructure, such as renewables, distributed generation and combined heat and power projects.

(1)	Net income for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million and $396 million due to the TCJA for CenterPoint Energy and CERC, respectively. See Note 15 for further discussion of the impacts of tax reform implementation.

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(1)	Reflected in Utility revenues in the Statements of Consolidated Income.

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(2)	Reflected in Non-utility revenues in the Statements of Consolidated Income.

(3)

Primarily consists of income from ARPs and leases. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.

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

(1)	Recorded in Depreciation and amortization expenses on CenterPoint Energy’s and CERC’s respective Statements of Consolidated Income.

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(1)	Current regulatory assets are included in Prepaid expenses and other current assets in the Registrants’ respective Consolidated Balance Sheets.

(2)

The unrecognized equity return will be recognized as it is recovered in rates through 2024. During the years ended December 31, 2018, 2017 and 2016, Houston Electric recognized approximately $74 million, $42 million and $64 million, respectively, of the allowed equity return. The timing of Houston Electric’s recognition of the equity return will vary each period based on amounts actually collected during the period. The actual amounts recognized are adjusted at least annually to correct any over-collections or under-collections during the preceding 12 months.

(3)	Includes a portion of Houston Electric’s and CERC’s NGD’s actuarially determined pension and other postemployment expense in excess of the amount being recovered through rates that is being deferred for rate making purposes, of which $33 million and $4 million as of December 31, 2018, respectively, and $31 million and $7 million as of December 31, 2017, respectively, were not earning a return.

(4)

The Registrants suffered damage as a result of Hurricane Harvey, a major storm classified as a Category 4 hurricane on the Saffir-Simpson Hurricane Wind Scale, that first struck the Texas coast on Friday, August 25, 2017 and remained over the Houston area for the next several days. The unprecedented flooding from torrential amounts of rainfall accompanying the storm caused significant damage to or destruction of residences and businesses served by the Registrants. The Registrants deferred the uninsured storm restoration costs as management believed it was probable that such costs will be recovered through traditional rate adjustment mechanisms for capital costs and through the next base rate proceeding for operation and maintenance expenses. As a result, storm restoration costs did not materially affect the Registrants’ reported net income for 2017. The Registrants are not earning a return on Hurricane Harvey restoration costs.

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(5)	The EDIT and deferred revenues will be recovered or refunded to customers as required by tax and regulatory authorities. See Note 15 for additional information.

(6)	Other long-term regulatory assets that are not earning a return were not material as of December 31, 2018 and 2017.

(7)	Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

(1)	Included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income and not capitalized as a part of Inventory or Property, Plant and Equipment.

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(1)	Reflects maximum performance achievement.

(2)	Reflects the impact of current expectations of achievement and stock price.

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(1)	Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized. See Note 2(r).

(2)	Amounts presented in the table above are included in Other, net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals. See Note 2(r).

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(1)	Significant sources of gain for 2018 include the increase in discount rate from 3.65% to 4.35% and the mortality projection scale change from MP2017 to MP2018. For 2017, the significant source of loss was the decrease in the discount rate from 4.15% to 3.65%.

(2)	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.

(3)	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.

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(1)	Amounts presented in the table above are included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals and amounts capitalized. See Note 2(r).

(2)	Amounts presented in the table above are included in Other, net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals. See Note 2(r).

(3)

A curtailment gain or loss is required when the expected future services of a significant number of current employees are reduced or eliminated for the accrual of benefits. During 2016, postretirement healthcare benefits were amended resulting in a net curtailment gain of $5 million. In May 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local Union 66 that provides that for Houston Electric bargaining unit employees covered under the agreement who retire on or after January 1, 2017, retiree medical and prescription drug coverage will be provided exclusively through the NECA/IBEW Family Medical Care Plan in exchange for the payment of monthly premiums as determined under the agreement. As a result, the accrued postretirement benefits related to such future CenterPoint Energy and Houston Electric union retirees were eliminated. Houston Electric recognized a curtailment gain of $3 million as an accelerated recognition of the prior service credit that would otherwise be recognized in future periods for the postretirement plan. CenterPoint Energy also recognized an additional curtailment gain of $2 million in October 2016 related to other amendments in the postretirement plan.

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(1)	Significant sources of gain for 2018 include the increase in the discount rate from 3.60% to 4.35%, favorable benefit claims experience and cost trend rates in addition to the change in mortality projection scale from MP2017 to MP2018.

(2)	The discount rate assumption was determined by matching the projected cash flows of the 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.

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(3)	The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.

(1)	CenterPoint Energy’s and 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)	Represents investments in common collective trust funds.

(2)	The amounts invested in mutual funds and common collective trust funds were allocated as follows:

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(1)	Weather hedge gains (losses) are recorded in Revenues in the Statements of Consolidated Income.

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(1)	The fair value shown for natural gas contracts is comprised of derivative gross volumes totaling 1,674 Bcf or a net 140 Bcf long position and 1,795 Bcf or a net 224 Bcf long position as of December 31, 2018 and 2017, respectively.  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 is detailed in the Offsetting of Natural Gas Derivative Assets and Liabilities table below.

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

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(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.

(1)

Upon adoption of ASU 2017-12 effective January 1, 2018 (see Note 2 for additional information), CenterPoint Energy and CERC elected to exclude from their assessment of hedge effectiveness the natural gas market price difference between locations of the hedged inventory and the delivery location specified in the hedge instruments. Prior to the adoption of this accounting guidance, the timing 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, was excluded from the assessment of effectiveness for CenterPoint Energy’s and CERC’s existing fair value hedges and will continue to be excluded from the assessment of hedge effectiveness. CenterPoint Energy and CERC elected to continue to immediately recognize amounts excluded from hedge effectiveness in their respective Statements of Consolidated Income.

(2)	Income statement impact associated with cash flow hedge activity is related to gains and losses reclassified from Accumulated other comprehensive income into income. Amounts are immaterial for the Registrants for the years ended December 31, 2018, 2017 and 2016, respectively.

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(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, CenterPoint Energy and CERC determine a synthetic credit rating by performing financial statement analysis and consider 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 amounts reflected in the table above were not impacted by collateral netting.

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(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy and CERC to settle positive and negative positions and also include cash collateral of $19 million as of both December 31, 2018 and 2017, respectively, posted with the same counterparties.

(2)	Amounts are included in Prepaid and Other Current Assets and Other Assets in the Consolidated Balance Sheets.

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

(4)

Level 1 natural gas derivatives include exchange-traded derivatives cleared by the CME, which deems that financial instruments cleared by the CME are settled daily in connection with posted cash payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes, and are presented in Level 1 net of posted cash; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

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

(2)	During 2016, CenterPoint Energy transferred its indexed debt securities from Level 2 to Level 3 to reflect changes in the significance of the unobservable inputs used in the valuation.

(3)	During 2018, CenterPoint Energy transferred its indexed debt securities derivative from Level 3 to Level 2 to reflect changes in the significance of the unobservable inputs used in the valuation.

(4)	CenterPoint Energy and CERC did not have significant Level 3 sales during any of the years ended December 31, 2018, 2017 or 2016.

(1)	Includes Securitization Bond debt.

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(1)	Excludes the Enable Series A Preferred Units owned by CenterPoint Energy.

(2)

The carrying amount of the Enable Series A Preferred Units, reflected as Preferred units - unconsolidated affiliate on CenterPoint Energy’s Consolidated Balance Sheets, was $363 million as of both December 31, 2018 and 2017. No impairment charges or adjustment to carrying value were made as no observable price changes were identified in the current or prior reporting periods. See Note 2(r) for further discussion.

(3)	Prior to the Internal Spin on September 4, 2018 described above, CenterPoint Energy’s investment in Enable’s common units, excluding the Enable Series A Preferred Units held directly by CenterPoint Energy, was held indirectly through CERC.

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(1)	As of December 31, 2018, Enable is controlled jointly by CenterPoint Energy and OGE. Sale of CenterPoint Energy’s or OGE’s ownership interests in Enable GP to a third party is subject to mutual rights of first offer and first refusal, and CenterPoint Energy is not permitted to dispose of less than all of its interest in Enable GP.

(2)

Enable is expected to pay a minimum quarterly distribution of $0.2875 per common unit on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates, within 60 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per common unit in any quarter, Enable GP will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances Enable GP 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.

(3)	CenterPoint Energy held the management rights and incentive distributions rights in Enable GP indirectly through CERC until the Internal Spin on September 4, 2018 described above.

(1)	Reflects CERC’s ownership of Enable common units up to September 4, 2018 when CERC completed the Internal Spin. After such date, distributions from Enable were received directly by CenterPoint Energy.

(2)	2016 amounts represent the period from February 18, 2016 to December 31, 2016.

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

(1)

Equity in earnings of unconsolidated affiliate includes CenterPoint Energy’s share of Enable earnings adjusted for the amortization of the basis difference of CenterPoint Energy’s original investment in Enable and its underlying equity in net assets of Enable. The basis difference is being amortized over approximately 30 years, the remaining average life of the assets to which the basis difference is attributed.

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•	senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made subordinated to the Series A Preferred Stock;

•	on a parity with any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is not expressly made senior or subordinated to the Series A Preferred Stock, including the Series B Preferred Stock;

•	junior to any class or series of capital stock established after the initial issue date of the Series A Preferred Stock that is expressly made senior to the Series A Preferred Stock;

•	junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

•	structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

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•	senior to Common Stock and to each other class or series of capital stock established after the initial issue date of the Series B Preferred Stock that is expressly made subordinated to the Series B Preferred Stock;

•	on a parity with the Series A Preferred Stock and any class or series of capital stock established after the initial issue date that is not expressly made senior or subordinated to the Series B Preferred Stock;

•	junior to any class or series of capital stock established after the initial issue date that is expressly made senior to the Series B Preferred Stock;

•	junior to all existing and future indebtedness (including indebtedness outstanding under CenterPoint Energy’s credit facilities, senior notes and commercial paper) and other liabilities with respect to assets available to satisfy claims against CenterPoint Energy; and

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•	structurally subordinated to any existing and future indebtedness and other liabilities of CenterPoint Energy’s subsidiaries and capital stock of CenterPoint Energy’s subsidiaries held by third parties.

(1)	Gains and losses are reclassified from Accumulated other comprehensive income into income when the hedged transactions affect earnings. The reclassification amounts are included in Interest and other finance charges in each of the Registrant’s respective Statements of Consolidated Income. Amounts are less than $1 million for each of the years ended December 31, 2018 and 2017, respectively.

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(2)	Amounts are included in the computation of net periodic cost and are reflected in Other, net in each of the Registrants’ respective Statements of Consolidated Income.

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

(2)	Issued by CERC Corp.

(3)	CenterPoint Energy’s and CERC’s NGD has AMAs associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas. In March 2018, NGD’s third-party AMAs in Arkansas, Louisiana and Oklahoma

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(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)	CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 12(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.

(6)	$68 million and $118 million of these series of debt were secured by general mortgage bonds of Houston Electric as of December 31, 2018 and 2017, respectively.

(1)	Secured by general mortgage bonds of Houston Electric.

(1)	Proceeds from these debt issuances were used for general limited liability company and corporate purposes, as applicable, including capital expenditures, repayment of portions of outstanding commercial paper and borrowings under CenterPoint Energy’s money pool.

(2)	Issued by CERC Corp.

(3)	Proceeds from these debt issuances were used to fund a portion of the Merger and to pay related fees and expenses.

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(1)	Issued by CERC Corp.

(1)	Proceeds from these commercial paper issuances were used to fund a portion of the Merger and to pay related fees and expenses and were contributed to Vectren for its payment of its stub period cash dividend, long-term incentive payments and to fund the repayment of indebtedness of Vectren subsidiaries redeemed at the option of the holder as a result of the closing of the Merger.

(2)	The commercial paper notes were issued at various times in January 2019 with maturities up to and including 90 days as of the time of issuance, and, prior to their use as described in connection with the closing of the Merger, the net proceeds of such issuances were invested in short-term investments.

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(1)	Based on credit ratings as of December 31, 2018.

(2)

For CenterPoint Energy and Houston Electric, the financial covenant limit will temporarily increase from 65% to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.

(3)	As defined in the revolving credit facility agreement, excluding Securitization Bonds.

(4)	Amended on June 16, 2017 to extend the termination date.

(5)	Pursuant to the amendment entered into in May 2018, the aggregate commitments under the CenterPoint Energy revolving credit facility increased to $3.3 billion on October 5, 2018 as a result of the satisfaction of certain conditions described above.

(6)	Issued by CERC Corp.

(1)	These maturities include Securitization Bonds principal repayments on scheduled payment dates.

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(1)

Recognized a $32 million deferred tax expense due to state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions. Also recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. These items are partially offset by $24 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(2)	Recognized a $1.1 billion deferred tax benefit from the remeasurement of CenterPoint Energy’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. For additional information on the 2017 impacts of the TCJA, please see the discussion following the deferred tax assets and liabilities table below.

(3)	Recognized a $6 million deferred tax expense in 2016 due to Louisiana state law change and recorded an additional $3 million valuation allowance on certain state carryforwards.

(4)	Recognized $9 million of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions beginning in 2018.

(5)	Recognized a $158 million deferred tax benefit from the remeasurement of Houston Electric’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. For additional information on the 2017 impacts of the TCJA, please see the discussion following the deferred tax assets and liabilities table below.

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(6)	Recorded an additional $11 million valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. This item is partially offset by $15 million of amortization of the net regulatory EDIT liability in certain jurisdictions as decreed by regulators beginning in 2018.

(7)

Recognized a $396 million deferred tax benefit from the remeasurement of CERC’s ADFIT liability as a result of the enactment of the TCJA on December 22, 2017, which reduced the U.S. corporate income tax rate from 35% to 21%. ASC 740 requires tax impacts of changes in tax laws or rates be reported in continuing operations.  Therefore, CERC’s federal income tax benefit generated by the remeasurement of the ADFIT liability for Enable during 2017 and state law changes during 2016 associated with its investment in Enable are reported in continuing operations on CERC’s Statements of Consolidated Income. The ADFIT liability associated with CERC’s investment in Enable is reported as discontinued operations on CERC’s Consolidated Balance Sheets.

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(1)	Income available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 for further discussion of the impacts of the TCJA.

(2)	The potentially dilutive impact from restricted stock awards applies the treasury stock method. Under this method, an increase in the average fair market value of Common Stock can result in a greater dilutive impact from these securities.

(3)

The potentially dilutive impact from Series B Preferred Stock applies the if-converted method in calculating diluted earnings per common share. Under this method, diluted earnings per common share is adjusted for the more dilutive effect of the Series B Preferred Stock as a result of either its accumulated dividend for the period in the numerator or the assumed-converted common share equivalent in the denominator. The computation of diluted earnings per common share outstanding for the year ended December 31, 2018 excludes 8,885,000 potentially dilutive shares because to include them would be anti-dilutive. However, these shares could be potentially dilutive in the future.

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(1)	Quarterly earnings (loss) per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings (loss) per common share.

(2)	Recast to reflect the adoption of ASU 2017-07. See Note 2(r) for further information.

(3)	Income available to common shareholders and Net income for the fourth quarter 2017 include a reduction in income tax expense of $1,113 million, $158 million and $396 million for CenterPoint Energy, Houston Electric and CERC, respectively, due to the TCJA. See Note 15 for further discussion of the impacts of tax reform implementation.

(4)	Amounts have been recast to reflect discontinued operations in all periods presented.

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(1)

On September 4, 2018, CERC completed the Internal Spin. Previously, CERC’s equity method investment in Enable was included in CERC’s Midstream Investments reportable segment. CERC’s equity in earnings in Enable, net of basis difference amortization and income tax, have been classified as discontinued operations for all periods presented. See Note 11 for further discussion on the Internal Spin and the associated discontinued operations presentation.

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(1)	CenterPoint Energy’s and Houston Electric’s Electric Transmission & Distribution revenues from major customers are as follows:

(2)	CenterPoint Energy’s Midstream Investments’ equity earnings, net are as follows:

(3)	Total assets included pension and other postemployment-related regulatory assets of $665 million, $600 million and $759 million as of December 31, 2018, 2017 and 2016, respectively. Additionally, total assets as of December 31, 2018 included $3.9 billion of temporary investments included in Cash and cash equivalents on CenterPoint Energy’s Consolidated Balance Sheets.

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(1)	On September 4, 2018, CERC completed the Internal Spin. For further information regarding the Internal Spin, see Note 11.

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(1)

CenterPoint Energy’s Cash and cash equivalents as of December 31, 2018 included $3.9 billion of temporary investments resulting from the Merger financings. CenterPoint Energy recorded interest income of $28 million, $2 million and $1 million for the years ended December 31, 2018, 2017 and 2016, respectively, in Other, net on CenterPoint Energy’s Statements of Consolidated Income. See Notes 13 and 14 for further details related to the Merger financings.

(2)	Houston Electric’s Cash and cash equivalents as of December 31, 2018 and 2017 included $335 million and $230 million, respectively, of cash related to the Bond Companies. Houston Electric recorded interest income of $4 million, $2 million and $1 million for the years ended December 31, 2018, 2017 and 2016, respectively, in Other, net on Houston Electric’s Statement of Consolidated Income.

(1)	Included in Accounts and notes receivable (payable)–affiliated companies in Houston Electric’s and CERC’s Consolidated Balance Sheets.

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(1)	Interest income is included in Other, net and interest expense is included in Interest and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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Item 9A.	Controls and Procedures

•	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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Item 9B.	Other Information

•	Revised eligibility requirements to provide clarity with respect to participants employed for a portion of the applicable plan year;

•	Amended methodology for calculating payments upon retirement;

•	Removed manager discretion with respect to terminations after the plan year but before the payment date to conform to operational practice; and

•	Deleted provisions related to Section 162(m) of the Internal Revenue Code to reflect current legislative changes.

Item 10.	Directors, Executive Officers and Corporate Governance

Item 11.	Executive Compensation

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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Item 13.	Certain Relationships and Related Transactions, and Director Independence

Item 14.	Principal Accounting Fees and Services

(1)	For 2018 and 2017, 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 2018 and 2017, 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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Item 15.	Exhibits and Financial Statement Schedules

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