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Item 1.	Business

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

•	CERC Corp., which owns and operates natural gas distribution systems in six states; and

•	CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 31 states.

•	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 we can handle or dispose of wastes;

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

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

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

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

•	construct or acquire new facilities and equipment;

•	acquire permits for facility operations;

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

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

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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;

•	maintenance of acceptable credit ratings;

•	market expectations regarding our future earnings and cash flows;

•	our ability to access capital markets on reasonable terms;

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

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

•	provisions of relevant tax and securities laws.

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

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

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

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

•	cash calls and settlements of hedging positions;

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

•	the level of competition from other midstream energy companies;

•	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;

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•	its debt service requirements and other liabilities;

•	fluctuations in its working capital needs;

•	its ability to borrow funds and access capital markets;

•	restrictions contained in its debt agreements;

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

•	distributions paid on its Series A Preferred Units; and

•	other business risks affecting its cash levels.

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•	the availability and cost of capital;

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

•	demand for natural gas, NGLs and crude oil;

•	levels of reserves;

•	geological considerations;

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

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

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

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

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

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

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

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

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

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

•	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;

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

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

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

•	permit its subsidiaries to incur or guarantee additional debt;

•	incur or permit to exist certain liens on assets;

•	dispose of assets;

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

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

•	change the nature of its business.

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

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

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

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

•	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;

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•	modify or replace existing and proposed equipment; and

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

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

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

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

•	ruptures, fires and explosions; and

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

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•	merchant energy, energy trading and 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.

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•	operator error or failure of equipment or processes;

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

•	labor disputes;

•	information technology or financial system failures that impair our information technology infrastructure, reporting systems or disrupt normal business operations;

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

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

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•	perform ongoing assessments of pipeline integrity;

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

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

•	improve data collection, integration, and analysis;

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

•	repair and remediate pipelines as necessary; and

•	implement preventive and mitigating action.

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

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

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

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

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

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

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•	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 valuable employees or third-party relationships.

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Item 1B.	Unresolved Staff Comments

Item 2.	Properties

Item 3.	Legal Proceedings

Item 4.	Mine Safety Disclosures

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

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

(2)	Amounts for 2012 to 2015 have been restated to reflect adoption of ASU 2015-03.

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

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

•	CERC Corp., which owns and operates natural gas distribution systems in six states; and

•	CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 31 states.

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•	the performance of Enable, the amount of cash distributions we receive from Enable, Enable’s ability to redeem the Series A Preferred Units in certain circumstances and the value of our interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:

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

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

◦	changes in tax status;

◦	access to debt and equity capital; and

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

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

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

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

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

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

•	tax reform and legislation;

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

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

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

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

•	the impact of unplanned facility outages;

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

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

•	our ability to control operation and maintenance costs;

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•	actions by credit rating agencies;

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

•	the investment performance of our pension and postretirement benefit plans;

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

•	changes in interest rates or 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;

•	effectiveness of our risk management activities;

•	timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;

•	our potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses, which we cannot assure you will be completed or will have the anticipated benefits to us;

•	acquisition and merger activities involving us or our competitors;

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

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

•	the outcome of litigation;

•	the ability of REPs, including REP affiliates of NRG and Energy Future Holdings, to satisfy their obligations to us and our subsidiaries;

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

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•	a $1,841 million increase in equity earnings from our investment in Enable, as 2015 results included impairment charges of $1,846 million, discussed further in Note 10 to our consolidated financial statements;

•	a $419 million increase in the gain on our marketable securities;

•	a $26 million increase in operating income discussed below by segment;

•	a $22 million increase in cash distributions on Series A Preferred Units included in Other Income, net shown above;

•	a $14 million decrease in interest expense due to lower weighted average interest rates on outstanding debt; and

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

•	a $692 million increase in income tax expense due to higher income before tax;

•	a $487 million increase in the loss on indexed debt securities related to the ZENS resulting from a loss of $117 million from the Charter merger in 2016 compared to a loss of $7 million from Verizon’s acquisition of AOL in 2015 and increased losses of $377 million in the underlying value of the indexed debt securities;

•	a $22 million loss on early redemption of our $300 million 6.5% senior notes otherwise due 2018 included in Other Income, net shown above;

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•	a $6 million decrease in interest income due primarily to Enable’s repayment of $363 million note payable to us included in Other Income, net shown above; and

•	a $5 million decrease in miscellaneous other non-operating income include in Other Income, net shown above.

•	a $1,941 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $1,846 million, discussed further in Note 10 to our consolidated financial statements; and

•	a $256 million increase in the loss on our marketable securities.

•	a $712 million decrease in income tax expense;

•	a $160 million increase in the gain on our indexed debt securities related to the ZENS resulting from a loss of $7 million from Verizon’s acquisition of AOL in 2015 and increased gains of $167 million in the underlying value of the indexed debt securities;

•	a $13 million decrease in interest expense related to lower outstanding balances of our Securitization Bonds;

•	a $9 million increase in proceeds received from the settlement of corporate-owned life insurance policies included in Other Income, net shown above; and

•	a $1 million increase in miscellaneous other non-operating income included in Other Income, net shown above.

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(1)	Represents the amount necessary to pay interest on the securitization bonds.

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•	higher transmission-related revenues of $82 million, partially offset by transmission costs billed by transmission providers of $55 million;

•	higher equity return of $17 million, primarily due to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months; and

•	higher depreciation, primarily because of ongoing additions to plant in service, and other taxes of $45 million;

•	higher transmission-related revenues of $81 million, which were partially offset by increased transmission costs billed by transmission providers of $47 million;

•	lower equity return of $20 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during the preceding 12 months;

•	lower revenues from energy efficiency bonuses of $15 million, including a one-time energy efficiency remand bonus in 2014 of $8 million;

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

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

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

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

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

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

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

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

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•	decreased usage of $25 million as a result of warmer weather compared to the prior year, partially mitigated by weather hedges and weather normalization adjustments;

•	higher depreciation and amortization of $22 million; and

•	increase in taxes of $2 million.

•	rate increases of $23 million;

•	increased economic activity across our footprint of $7 million, including the addition of approximately 30,000 customers; and

•	increased other revenue of $5 million.

(1)	These numbers do not include approximately 60,100 and 9,700 natural gas customers as of December 31, 2016 and 2014, respectively, that are under residential and small commercial choice programs invoiced by their host utility.

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

(2)	We contributed our remaining 0.1% interest in SESH to Enable on June 30, 2015.

(3)	On April 16, 2014, Enable completed its initial public offering and, as a result, our limited partner interest in Enable was reduced from approximately 58.3% to approximately 54.7%. On May 30, 2014, we contributed to Enable our 24.95% interest in SESH, which increased our limited partner interest in Enable from approximately 54.7% to approximately 55.4% and reduced our interest in SESH to 0.1%.

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•	capital expenditures of approximately $1.5 billion;

•	maturing senior notes of $500 million;

•	scheduled principal payments on Securitization Bonds of $411 million;

•	acquisition of AEM for approximately $140 million, including estimated working capital of $100 million; and

•	dividend payments on our common stock and interest payments on debt.

(1)	ZENS obligations are included in the 2022 and thereafter column at their contingent principal amount as of December 31, 2016 of $514 million.  These obligations are exchangeable for cash at any time at the option of the holders for 95% of

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(2)	We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2016. We 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 15(c) to our consolidated financial statements.

(4)	In 2017, we are required to contribute approximately $39 million to our qualified pension plan. We expect to contribute approximately $7 million and $16 million, respectively, to our non-qualified pension and postretirement benefits plans in 2017.

(5)	For a discussion of other commodity commitments, please read Note 15(a) to our 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 2022. We record a separate liability for the fair value of AROs which totaled $205 million as of December 31, 2016. See Note 3(c) to our consolidated financial statements.

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(1)	Represents the new DCRF charge, not a year over year increase.

(2)	Amounts are recorded when approved.

(3)	Effective dates or approval dates not yet available, and approved rates could differ materially.

(4)	In addition to requesting the change in rates, NGD proposed consolidation of the Houston and Texas Coast divisions into a Texas Gulf division.

(5)	The amount was recorded during the under recovery period.

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(1)	Based on the consolidated debt to capitalization covenant in our revolving credit facility and the revolving credit facility of each of Houston Electric and CERC Corp., we would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated $2.5 billion at December 31, 2016.

(2)	Represents outstanding commercial paper of $929 million and outstanding letters of credit of $6 million.

(3)	Represents outstanding letters of credit of $4 million.

(4)	Represents outstanding commercial paper of $587 million and outstanding letters of credit of $4 million.

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

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

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

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

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

•	increased costs related to the acquisition of natural gas;

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

•	various legislative or regulatory actions;

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

•	the ability of GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries;

•	the ability of REPs, including REP affiliates of NRG and Energy Future Holdings, to satisfy their obligations to us and our subsidiaries;

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

•	the outcome of litigation brought by or against us;

•	contributions to pension and postretirement benefit plans;

•	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.

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

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

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

•	CERC Corp., which owns and operates natural gas distribution systems in six states; and

•	CES, which obtains and offers competitive variable and fixed-price physical natural gas supplies and services primarily to commercial and industrial customers and electric and natural gas utilities in 31 states.

(a)	Use of Estimates

(b)	Principles of Consolidation

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(c)	Revenues

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(1)

The unrecognized allowed equity return will be recognized as it is recovered in rates through 2024. During the years ended December 31, 2016, 2015 and 2014, Houston Electric recognized approximately $64 million, $49 million and $68 million, respectively, of the allowed equity return. The timing of CenterPoint Energy’s recognition of the allowed equity return will vary each period based on amounts actually collected during the period. The actual amounts recovered for the allowed equity return are reviewed and adjusted at least annually by the PUCT to correct any over-collections or under-collections during the preceding 12 months and to provide for the full and timely recovery of the allowed equity return.

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

(3)	Other regulatory assets that are not earning a return were not material as of December 31, 2016 and 2015.

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(1)

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 the fourth quarter of 2014, CenterPoint Energy recognized a curtailment pension loss of $6 million related to employees seconded to Enable. Substantially all of the seconded employees became employees of Enable effective January 1, 2015. Also, postretirement healthcare benefits were amended during 2016 resulting in a net curtailment gain of $5 million. In May 2016, Houston Electric entered into a renegotiated

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(2)

A one-time, non-cash settlement charge is required when lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of net periodic cost for that year.  Due to the amount of lump sum payment distributions from the non-qualified pension plan during the year ended December 31, 2015, CenterPoint Energy recognized a non-cash settlement charge of $10 million.  This charge is an acceleration of costs that would otherwise be recognized in future periods.

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(1)

The Postretirement plan was amended during 2016 to change retiree medical coverage, effective January 1, 2017, as follows: (i) members of the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, will receive any retiree medical and prescription drug coverage exclusively through the NECA/IBEW Family Medical Care Plan pursuant to the terms of the renegotiated collective bargaining agreement entered into in May 2016; and (ii)  Medicare eligible post-65 retirees will receive coverage through a Medicare Advantage Program, an insured benefit, in lieu of the previous self-insured benefit.  These changes resulted in a reduction in our Postretirement Plan liability of $56 million as of December 31, 2016.

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(2)

In May 2016, Houston Electric entered into a renegotiated collective bargaining agreement with the IBEW Local Union 66 and amended the Houston Electric Union Postretirement Trust.  The amendment resulted in a split of the trust into two segregated and restricted accounts, one holds assets for the benefit of current, retired on or before December 31, 2016, union retirees and one holds assets for the benefit of post-2016 union retirees who are now covered exclusively by the NECA/IBEW Family Medical Care Plan. Accordingly, $20 million was transferred to the account for post-2016 union retirees.

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

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

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(1)	57% of the amount invested in mutual funds was in international equities, 28% was in emerging market equities and 15% was in U.S. equities.

(2)	This represents the common collective trust funds with 53% of the amount invested in fixed income securities, 12% in U.S. equities, 30% in international equities and 5% in emerging market equities.

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(1)	58% of the amount invested in mutual funds was in international equities, 28% was in emerging market equities and 14% was in U.S. equities.

(2)	This represents the common collective trust funds with 60% of the amount invested in fixed income securities, 11% in U.S. equities, 23% in international equities and 2% in emerging market equities.

(1)	74% of the amount invested in mutual funds was in fixed income securities, 18% was in U.S. equities and 8% was in international equities.

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(1)	72% of the amount invested in mutual funds was in fixed income securities, 20% was in U.S. equities and 8% was in international equities.

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

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(2)

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets as they are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading natural gas derivative assets and liabilities was a $24 million asset as shown on CenterPoint Energy’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $14 million.

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

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

(2)	The derivative assets and liabilities on the Consolidated Balance Sheets exclude accounts receivable or accounts payable that, should they exist, could be used as offsets to these balances in the event of a default.

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

(2)

Natural gas contracts are presented on a net basis in the Consolidated Balance Sheets. Natural gas contracts are subject to master netting arrangements. This netting applies to all undisputed amounts due or past due and causes derivative assets (liabilities) to be ultimately presented net in a liability (asset) account within the Consolidated Balance Sheets. The net of total non-trading derivative assets and liabilities was a $109 million asset as shown on CenterPoint Energy’s Consolidated Balance Sheets (and as detailed in the table below), and was comprised of the natural gas contracts derivative assets and liabilities separately shown above, impacted by collateral netting of $56 million.

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

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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.

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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 determines a synthetic credit rating by performing financial statement analysis and considers contractual rights and restrictions and collateral.

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

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

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(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $14 million held by CES from the same counterparties.

(2)	Amounts are included in 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.

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(1)	Amounts represent the impact of legally enforceable master netting arrangements that allow CenterPoint Energy to settle positive and negative positions and also include cash collateral of $56 million 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.

(1)	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. As of December 31, 2016, the indexed debt securities liability was $717 million. During 2016, there was a loss of $413 million on the indexed debt securities.

(2)	During 2016, 2015 and 2014, CenterPoint Energy did not have significant Level 3 sales.

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

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

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

(1)

Equity in earnings of unconsolidated affiliates 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 33 years, the average life of the assets to which the basis difference is attributed.

(2)

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

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(1)	Represents the period from February 18, 2016 to December 31, 2016.

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

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(1)	To reflect adoption of ASU 2015-03, balances have been restated to include unamortized debt issuance costs of $9 million, $10 million and $11 million as of December 31, 2015, 2014 and 2013, respectively.

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

(2)	Includes $35 million of unamortized debt issuance costs to reflect adoption of ASU 2015-03.

(3)

NGD currently has AMAs associated with its utility distribution service in Arkansas, north Louisiana and Oklahoma that extend through 2020. Pursuant to the provisions of the agreements, NGD sells natural gas and agrees to repurchase an equivalent amount of natural gas during the winter heating seasons at the same cost, plus a financing charge. These transactions are accounted for as an inventory financing.

(4)	CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 11(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.

(5)	$118 million of these series of debt were secured by general mortgage bonds of Houston Electric as of both December 31, 2016 and 2015.

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

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(1)	Weighted average interest rate was approximately 1.04% and 0.79% as of December 31, 2016 and December 31, 2015, respectively.

(2)	Weighted average interest rate was approximately 1.64% as of December 31, 2015.

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

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(1)	Based on current credit ratings.

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

(3)

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 twelve-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.

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(1)	2,349,000 incremental shares from assumed conversions of restricted stock have not been included in the computation of diluted earnings (loss) per share for the year ended December 31, 2015, as their inclusion would be anti-dilutive.

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

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

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

(2)	Houston Electric’s transmission and distribution revenues from major customers are as follows:

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

(a)

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

(4)	Included in total assets of Other Operations as of December 31, 2016, 2015 and 2014, are pension and other postemployment related regulatory assets of $759 million, $814 million and $795 million, respectively.

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

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

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

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

Item 14.	Principal Accounting Fees and Services

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Item 15.	Exhibits and Financial Statement Schedules

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(8)	Not applicable.

(9)	Not applicable.

(10)	Not applicable.

(11)	Not applicable.

(12)	Not applicable.

(13)	See subsection (7) above.

(14)	Not applicable.

(15)	Not applicable.

(16)	Not applicable.

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(18)	Not applicable.

(19)	Not applicable.

(21)	Not applicable.

6.	To my knowledge, no Event of Default has occurred and is continuing.

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9.	The First Mortgage Collateralization Date has not occurred.

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•	Mr. Carroll's annual base salary is increased from $625,000 to $675,000 effective as of April 1, 2017 and continuing thereafter until the termination of Mr. Carroll's service as Executive Chairman of the Board or as otherwise modified by the Board; and

•	No changes were made to Mr. Carroll’s 300% long-term incentive compensation target.

(1)	the Vesting Date(s) on which the units are paid under Section 3 hereof for the number of units indicated in the Award Notice assuming continuous Employment by the Participant as of such Vesting Date(s); or

(2)	in the case of the Participant’s death or Separation from Service due to Disability or Retirement prior to the Vesting

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•	Annual retainer fee of $90,000 for Board membership, paid quarterly in arrears;

•	Supplemental annual retainer of $20,000 for serving as a chairman of the Audit Committee or Compensation Committee; and

•	Supplemental annual retainer of $15,000 for serving as a chairman of the Finance Committee or Governance Committee.

•	Mr. Prochazka’s short-term incentive target was increased from 110% to 115%; and

•	no changes to the 75% short-term incentive target for each of Messrs. Rogers, Bridge and McGoldrick.

•	Mr. Prochazka’s long-term incentive target was increased from 390% to 400%;

•	Mr. Rogers long-term incentive target was increased from 170% to 195%; and

•	no changes to the 160% long-term incentive target for each of Messrs. Bridge and McGoldrick.

(1)	Excluded from the computation of fixed charges for the years ended December 31, 2016, 2015, 2014, 2013, and 2012 is interest expense of $-0-, $-0- and $3 million and interest income of $6 million and $11 million respectively, which is included in income tax expense.

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

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

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

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

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

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

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

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

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

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

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

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