CenterPoint Energy (CNP) 10-K risk factor changes: FY2016 vs FY2015

We are a holding company that conducts all of our business operations through subsidiaries, primarily [removed: CenterPoint] Houston [added: Electric] and CERC.

As a result, we depend on distributions from our [removed: subsidiaries, including Enable, in order] [added: subsidiaries and Enable] to meet our payment obligations and to pay dividends on our common stock.

[removed: For a discussion] of risks that may impact the amount of cash distributions we receive with respect to our interests in Enable, please read [removed: “—] [added: “ —] Additional Risk Factors Affecting Our Interests in Enable Midstream Partners, LP — Our cash flows will be adversely impacted if we receive less cash distributions from Enable than we currently expect.”

As of December 31, [removed: 2015,] [added: 2016,] we had [removed: $8.8] [added: $8.6] billion of outstanding indebtedness on a consolidated basis, which includes [removed: $2.7] [added: $2.3] billion of non-recourse [removed: transition and system restoration bonds.][added: Securitization Bonds.]

As of December 31, [removed: 2015,] [added: 2016,] approximately [removed: $1.5 billion] [added: $850 million] principal amount of this debt is required to be paid through [removed: 2018.][added: 2019.]

This amount excludes principal repayments of approximately [removed: $1.2] [added: $1.3] billion on [removed: transition and system restoration bonds,] [added: Securitization Bonds,] for which dedicated revenue streams exist.

| • | [removed: market perceptions of] our ability to access capital markets on reasonable terms; |

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

As of December 31, [removed: 2015, CenterPoint] [added: 2016,] Houston [added: Electric] had approximately [removed: $2.1] [added: $2.6] billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including [removed: (a)] approximately [removed: $56 million held in trust to secure pollution control bonds that are not reflected on our financial statements because CenterPoint Houston is both the obligor on the bonds and the current owner of the bonds, and (b) approximately] $118 million held in trust to secure pollution control bonds for which we are obligated.

Additionally, as of December 31, [removed: 2015, CenterPoint] [added: 2016,] Houston [added: Electric] had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage.

[removed: CenterPoint] Houston [added: Electric] may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee.

Approximately [removed: $4.2] [added: $4.1] billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, [removed: 2015.][added: 2016.]

However, [removed: CenterPoint] Houston [added: Electric] has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

An impairment of goodwill, long-lived assets, including intangible assets, and [removed: equity-method] [added: equity and cost method] investments could reduce our earnings.

For investments we account for under the equity [added: or cost] method, the impairment test considers whether the fair value of [removed: the equity] [added: such] investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary.

[removed: For example,] [added: This determination was] based on the sustained low Enable common unit price and further declines in such price during the [removed: three months ended September 30, 2015 and December 31, 2015, respectively,] [added: year,] as well as the market outlook for continued depressed crude oil and natural gas prices impacting the midstream oil and gas [removed: industry, we determined in connection with our preparation of financial statements for the three months ended September 30, 2015 and December 31, 2015, that an other than temporary decrease in the value of our investment in Enable had occurred.][added: industry.]

We wrote down the value of our investment in Enable to its estimated fair value which resulted in impairment charges of [removed: $250 million as of September 30, 2015 and $975] [added: $1,225] million [removed: as of] [added: for the year ended] December 31, 2015.

[removed: Our total impairment loss included impairment charges totaling $1,846 million composed of the impairments of our investment in Enable of $1,225 million and] [added: Additionally, we recorded] our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived [removed: assets.][added: assets, for a total impairment charge of $1,846 million.]

If Enable’s unit price, distributions or earnings [removed: further] [added: were to] decline [removed: for reasons including, but not limited to, continued declines] [added: to levels below those used] in [removed: commodity prices and producer activity,] [added: our impairment tests in 2015,] and that decline is deemed to be other than temporary, we could determine that we are unable to recover the carrying value of our equity investment in Enable.

A sustained low Enable common unit price [removed: or further declines in such price] could result in our recording further impairment charges in the future.

Poor investment performance of the pension [removed: plan and] [added: plan,] factors adversely affecting the calculation of pension liabilities [added: and increasing health care costs] could unfavorably impact our [removed: liquidity and] results of [removed: operations.][added: operations, liquidity and financial position.]

Funding requirements may increase [removed: as a result] [added: and we may be required to make unplanned contributions in the event] of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations or government regulations that increase minimum funding requirements or the pension liability.

In addition to affecting our funding requirements, each of these factors could adversely affect our results of [removed: operations] [added: operations, liquidity] and financial position.

We, our subsidiaries or Enable could recognize financial losses as a result of volatility in the market values [added: or ineffectiveness] of these contracts or should a counterparty fail to perform.

Rate regulation of [removed: CenterPoint Houston’s] [added: Houston Electric’s] business may delay or deny [removed: CenterPoint Houston’s] [added: Houston Electric’s] ability to earn a reasonable return and fully recover its costs.

[removed: CenterPoint Houston’s] [added: Houston Electric’s] rates are regulated by certain municipalities and the [removed: Texas Utility Commission] [added: PUCT] based on an analysis of its invested [removed: capital and] [added: capital,] its expenses [added: and other factors] in a test [removed: year.][added: year in comprehensive base rate proceedings, subject to periodic review and adjustment using]

[removed: Thus,] [added: Notwithstanding] the [removed: rates that CenterPoint Houston is allowed to charge may not match its costs at any given time, which is referred to as “regulatory lag.” The] [added: application of the rate mechanisms discussed above, the] regulatory process [removed: by] [added: in] which rates are determined may not always result in rates that will produce full recovery of [removed: CenterPoint Houston’s] [added: NGD’s] costs and enable [removed: CenterPoint Houston] [added: NGD] to earn a reasonable return on its invested capital.

Disruptions at power generation facilities owned by third parties could interrupt [removed: CenterPoint Houston’s] [added: Houston Electric’s] sales of transmission and distribution services.

[removed: CenterPoint] Houston [added: Electric] transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties.

[removed: CenterPoint] Houston [added: Electric] does not own or operate any power generation facilities.

If power generation is disrupted or if power generation capacity is inadequate, [removed: CenterPoint Houston’s] [added: Houston Electric’s] sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows could be adversely affected.

[removed: CenterPoint Houston’s] [added: Houston Electric’s] revenues and results of operations are seasonal.

A significant portion of [removed: CenterPoint Houston’s] [added: Houston Electric’s] revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP.

Thus, [removed: CenterPoint Houston’s] [added: Houston Electric’s] revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months.

The AMS deployed throughout [removed: CenterPoint Houston’s] [added: Houston Electric’s] service territory may experience unexpected problems with respect to the timely receipt of accurate metering data.

[removed: CenterPoint] Houston [added: Electric] has deployed an AMS throughout its service territory.

The deployment consisted, among other elements, of replacing existing meters with new electronic meters that record metering data at 15-minute intervals and wirelessly communicate that information to [removed: CenterPoint] Houston [added: Electric] over a bi-directional communications system installed for that purpose.

The AMS integrates equipment and computer software from various vendors [removed: in order] to eliminate the need for physical meter readings to be taken at consumers’ premises, such as monthly readings for billing purposes and special readings associated with a customer’s change in REPs or the connection or disconnection of electric service.

[added: Unanticipated difficulties could be encountered during the operation] of the AMS, [added: including failures or inadequacy of equipment or software, difficulties in integrating the various components of the AMS,] changes in technology, cyber-security issues and factors outside the control of [removed: CenterPoint Houston,] [added: Houston Electric,] which could result in delayed or inaccurate metering data that might lead to delays or inaccuracies in the calculation and imposition of delivery or other charges, which could have a material adverse effect on [removed: CenterPoint Houston’s] [added: Houston Electric’s] results of operations, financial condition and cash flows.

[removed: CenterPoint] Houston [added: Electric] could be subject to higher costs and fines or other sanctions as a result of mandatory reliability standards.

We also own interests in Enable.

For a discussion

Our businesses are capital intensive in nature.

We depend on long-term debt to finance a portion of our capital expenditures and refinance our existing debt and on short-term borrowings through our revolving credit facilities and commercial paper programs to satisfy liquidity needs to the extent not satisfied by cash flow from our business operations.

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

For example, during the year ended December 31, 2015, we determined that an other than temporary decrease in the value of our equity investment in Enable had occurred.

Further, increasing health care costs and the effects of health care reform or any future legislative changes could also materially affect our benefit programs and costs.

Our costs of providing employee benefits and related funding requirements could also increase materially in the future should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our financial results.

mechanisms like those discussed below.

Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of Houston Electric’s control.

The rates that Houston Electric is allowed to charge may not match its costs at any given time, which is referred to as “regulatory lag.”

Though several interim adjustment mechanisms have been implemented to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s ability to adjust rates.

For example, the DCRF mechanism adjusts an electric utility’s rates for increases in net distribution-invested capital (e.g., distribution plant and intangible plant and communication equipment) since its last comprehensive base rate proceeding, but Houston Electric may make a DCRF filing only once per year and up to four times between comprehensive rate proceedings.

The TCOS mechanism allows a transmission service provider to update its wholesale transmission rates to reflect changes in transmission-related invested capital, but is only available twice a year.

Houston Electric can make no assurance that filings for such mechanisms will result in favorable adjustments to rates.

Further, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of Houston Electric’s costs or enable Houston Electric to earn a reasonable return.

In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Houston Electric’s ability to recover its costs in a timely manner.

To the extent the regulatory process does not allow Houston Electric to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected.

A general rate case is also a very complex and resource intensive proceeding with a relatively long timeline for completion.

Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by NGD to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to certain limitations that may reduce NGD’s ability to adjust its rates.

Arkansas enacted legislation in 2015 allowing public utilities to elect to have their rates regulated pursuant to a FRP, but such legislation provides for a utility’s base rates to be adjusted once a year.

In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions.

Additionally, in Minnesota, the MPUC implemented a full revenue decoupling pilot program in 2015, which separates approved revenues from the amount of natural gas used by its customers.

The effectiveness of these filings and programs depends on the approval of the applicable state regulatory body.

In Texas, NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submit annual GRIP filings to recover the incremental capital investments made in the preceding year.

NGD must file a general rate case no later than five years after the initial GRIP implementation date.

NGD can make no assurances that such filings will result in favorable adjustments to its rates.

Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by NGD and deny the full recovery of NGD’s cost of service or the full recovery of incurred natural gas costs in rates.

To the extent the regulatory process does not allow NGD to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected.

As of December 31, 2016, we owned an aggregate of 14,520,000 Series A Preferred Units in Enable.

For its Series A Preferred Units, Enable is expected to pay $0.625 per Series A Preferred Unit, or $2.50 per Series A Preferred Unit on an annualized basis.

However, distributions on each Series A Preferred Unit are not mandatory and are non-cumulative in the event distributions are not declared on the Series A Preferred Units.

Additionally, distributions on the Series A Preferred Units reduce the amount of available cash Enable has to pay distributions on its common and subordinated units.

| • | distributions paid on its Series A Preferred Units; and |

Enable’s Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the NYSE, and Enable may not have sufficient funds to redeem its Series A Preferred Units if required to do so.

As a holder of Enable’s Series A Preferred Units, we may request that Enable list those units for trading on the NYSE.

If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units.

There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Series A Preferred Units.

In addition, mandatory redemption of the Series A Preferred Units could have a material adverse effect on Enable’s business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders.

We also hold Series A Preferred Units in Enable.

We also own interests in Enable, a publicly traded midstream master limited partnership jointly controlled by CERC Corp. and OGE.

As of December 31, 2015, the carrying value of CenterPoint Energy’s investment in Enable is $11.09 per unit, which includes the common and subordinated units representing limited partner interests, general partner interest and incentive distribution rights we hold.

As of December 31, 2015, Enable’s common unit price closed at $9.20.

The lowest close price for Enable’s common units through February 12, 2016 was $5.80.

Unanticipated difficulties could be encountered during the operation of the AMS, including failures or inadequacy of equipment or software, difficulties in integrating the various components

CERC operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations.

Enable generates a substantial portion of its gross margins under long-term, fee-based agreements.

It also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of its contract portfolio.

Enable provides firm transportation and storage services to certain key customers on its system.

Its major transportation customers are affiliates of CenterPoint Energy, Laclede, OGE, American Electric Power Company, Inc. and XTO Energy Inc., an affiliate of Exxon Mobil Corporation.

systems or the rate at which production from a well declines.

In addition, Enable’s cash flows associated with wells currently connected to its systems will decline over time.

Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years from a high of $13.31 per MMBtu in July 2008 to $1.63 per MMBtu at December 23, 2015 and $145.31 per barrel in July 2008 to $26.19 per barrel at February 11, 2016, respectively.

Some of

For example, Enable is currently constructing two cryogenic processing facilities that it plans to connect to its super-header system in Grady and Garvin County, Oklahoma, which Enable expects will add 400 MMcf per day of combined natural gas processing capacity.

Enable expects that the first of the two new plants (the Bradley II Plant) will be completed in the second quarter of 2016.

Enable expects that the second plant (the Wildhorse Plant), a 200 MMcf per day plant, will be completed in late 2017.

producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

Enable’s keep-whole natural gas processing arrangements, which accounted for 5% of its natural gas processed volumes in 2015, expose it to fluctuations in the pricing spreads between NGL prices and natural gas prices.

Under these arrangements, the processor processes raw natural gas to extract NGLs and delivers to the producer the natural gas equivalent Btu value of raw natural gas received from the producer in the form of processed natural gas.

Accordingly, the processor’s cost of natural gas and NGLs is a function of the difference between the value of the NGLs produced and the cost of the processed natural gas used to replace the natural gas equivalent Btu value of those NGLs.

Therefore, if natural gas prices increase and NGL prices do not increase by a corresponding amount, the processor has to replace the Btu of natural gas at higher prices and cost of natural gas and NGLs sold are negatively affected.

Enable’s percent-of-proceeds and percent-of-liquids natural gas processing agreements accounted for 47% of its natural gas processed volumes in 2015.

Under percent-of-proceeds processing arrangements, the processor generally purchases unprocessed natural gas from the producer for a purchase price that is based on published natural gas and NGL index prices.

The purchase price for unprocessed natural gas is calculated based on a percentage of the quantity of natural gas and NGLs that would result from processing the gas purchased.

Accordingly, the processor’s cost of goods sold is a percentage of the index price value of the natural gas and NGLs contained in the unprocessed natural gas.

Additionally, if the amount of processed natural gas or NGLs recovered during processing is less than the amount upon which the purchase price was based, Enable’s margins from sale of goods may be negatively affected.

The purchase price for NGLs is based on published NGL index prices and is calculated based on a percentage of the quantity of NGLs that would result from processing the gas.

Accordingly, the processor’s cost of goods sold is a percentage of the index price value of NGLs contained in the unprocessed natural gas.

If Enable is unable to sell the NGLs recovered during processing at a higher price than it pays, Enable’s margins from sale of goods are negatively affected.

Additionally, if the amount of NGLs recovered during processing is less than the amount upon which the purchase price was based, Enable’s margins from sale of goods may be negatively affected.

Enable has limited experience in the crude oil gathering business.

In November 2013, Enable commenced operations on its initial crude oil gathering pipeline system, located in Dunn and McKenzie Counties in North Dakota within the Bakken Shale formation.

Additionally in February 2014, Enable executed a crude oil gathering agreement to gather crude oil production through a new system in Williams and Mountrail Counties in North Dakota that commenced operations in the second quarter of 2015.

These facilities, which will have a combined capacity of 49,500 barrels per day, are the first crude oil gathering systems that Enable has built and operated.

Other operators of gathering systems in the Bakken Shale formation may have more experience in the construction, operation and maintenance of crude oil gathering systems than Enable.

This relative lack of experience may hinder Enable’s ability to fully implement its business plan in a timely and cost efficient manner, which, in turn, may adversely affect its results of operations and its ability to make cash distributions to unitholders.

own operating and regulatory risks, which increases the risk that they may default on their obligations to Enable.

Enable’s growth strategy includes, in part, the ability to make acquisitions that result in an increase in its cash generated from operations.

If Enable is unable to make these accretive acquisitions either because: (i) it is unable to identify attractive acquisition targets or it is unable to negotiate purchase contracts on acceptable terms, (ii) it is unable to obtain acquisition financing on economically acceptable terms, or (iii) it is outbid by competitors, then its future growth and ability to increase distributions will be adversely affected.

Our operating subsidiaries own and operate electric transmission and distribution [removed: facilities] and natural gas distribution [removed: facilities] [added: facilities, supply natural gas to commercial] and [added: industrial customers and electric and natural gas utilities and] own interests in Enable [removed: Midstream Partners, LP (Enable)] as described below.

Our [removed: indirect] [added: indirect,] wholly-owned subsidiaries include:

| • | [removed: CenterPoint Energy] Houston Electric, [removed: LLC (CenterPoint Houston),] which engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; [removed: and] |

The results of our Midstream Investments [added: business] segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, [removed: natural gas liquids (NGLs)] [added: NGLs] and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Our Midstream Investments Segment.” [removed: A summary of] [added: Our Other Operations business segment includes office buildings and other real estate used in] our [removed: reportable] business [removed: segments as] [added: operations and other corporate operations which support all] of [removed: December 31, 2015 is set forth below:][added: our business operations.]

[added: |] Electric Transmission & Distribution [added: | $ | 628 | | | $ | 607 | | | $ | 595 | |]

[added: |] Natural Gas Distribution [added: | 510 | | | | 534 | | | | 534 | | | | 534 | | | | 534 | | | | 534 | | |]

[added: |] Energy Services [added: | 20 | | | | 42 | | | | 52 | | |]

[removed: CERC’s operations also include] [added: Our Energy Services business segment includes] non-rate regulated natural gas sales to, and transportation and storage [removed: services for,] [added: services, for] commercial and industrial [removed: customers in 23 states in the central United States.][added: customers.]

[added: |] Other Operations [added: | 8 | | | | 11 | | | | 1 | | |]

Within these broader financial measures, we monitor margins, operation and maintenance expense, [removed: interest expense, capital spending and working capital requirements.]

In addition to these financial [removed: measures] [added: measures,] we also monitor a number of variables that management considers important to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days.

For example, our [added: electric] business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country.

[removed: Reduced demand and] [added: To the extent population growth is affected by] lower energy prices [removed: could lead to] [added: and there is] financial pressure on some of our customers who operate within the energy [removed: industry and] [added: industry, there may be an] impact [added: on] the growth rate of our customer [removed: base.][added: base and overall demand.]

Every state in which we distribute natural gas had a warmer than normal winter in [added: 2016 and] 2015.

[removed: Historically,] [added: Both the TDU and] NGD [removed: has] [added: have] utilized weather hedges [added: in the past] to help reduce the impact of mild weather on its financial results.

[removed: However,] NGD did not enter a weather hedge for the [removed: 2015–2016] [added: last two] winter [removed: season] [added: seasons] as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015.

In addition, in many of our service areas, particularly in the Houston area and [removed: in] Minnesota, we have benefited from [removed: a] growth in the number of [removed: customers that also tends to mitigate the effects of reduced consumption.][added: customers.]

The profitability of our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and [added: natural] gas distribution rates.

Its operations serve customers [added: primarily] in the central United States.

While this business utilizes financial derivatives to [removed: hedge its exposure to] [added: mitigate the effects of] price movements, it does not [removed: engage in] [added: enter into risk management contracts for] speculative [removed: or proprietary trading] [added: purposes] and maintains a low [removed: value at risk level, or VaR,] [added: VaR] to avoid significant financial exposures.

We strive to maintain investment grade ratings for our securities [removed: in order] to access the capital markets on terms we consider reasonable.

We expect to make contributions to our pension plans aggregating approximately [removed: $8] [added: $46] million in [removed: 2016] [added: 2017] but may need to make larger contributions in subsequent years.

The results of our Midstream Investments segment are [removed: primarily] 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 [removed: systems, which depends significantly on the level of production from natural gas wells connected to its systems across a number of U.S. mid-continent markets.][added: systems.]

[removed: Aggregate production volumes are affected by the overall amount of oil and gas drilling and completion activities, as production] [added: Production] must be maintained or increased by new drilling or other activity, because the production rate of oil and gas wells declines over time.

Enable has attempted to mitigate the impact of commodity prices on its business by entering into hedges, focusing on contracting fee-based [removed: business,] [added: business] and converting existing commodity-based contracts to fee-based contracts.

[removed: Should lower] [added: If current] commodity prices [added: levels] persist, or [removed: should] [added: if] commodity [removed: prices decline further,] [added: price levels decline,] Enable’s future volumes and cash flows may be negatively impacted.

[removed: The emergence of these plays and advancements] [added: Advancements] in technology have [removed: been crucial factors that have] allowed producers to efficiently extract [removed: significant volumes of] natural gas and crude [removed: oil.][added: oil from these formations and plays.]

[added: Natural gas continues to be a critical component of energy demand in the U.S.] Over the long term, Enable’s management believes that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired [removed: electricity generation] [added: power plants] by natural gas-fired [removed: electricity generation] [added: power plants] due to the [removed: low prices] [added: price] of natural gas and stricter government environmental regulations on the mining and burning of coal.

Enable’s management believes that increasing consumption of natural gas over the long term [added: in these sectors] will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Enable may access the capital markets to fund [added: its] expansion capital expenditures.

Volatility in energy and commodity prices, as well as other [removed: macro economic] [added: macro-economic] factors could impact the relative [removed: attractiveness of Enable’s debt securities to investors.]

As a result of capital market volatility, Enable may be unable to issue equity [added: securities] or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

The regulation of gathering and transmission pipelines, storage and related facilities by [removed: the] FERC and other federal and state regulatory agencies, including the DOT, has a significant impact on Enable’s business.

For example, [added: the DOT’s] PHMSA has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase [added: its] compliance costs and increase the time it takes to obtain required permits.

[removed: This loss included] [added: | (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 [removed: assets.][added: assets for the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015. |]

For further [removed: discussion of the impairment,] [added: information,] see Note [removed: 9] [added: 8(a)] to our consolidated financial statements.

Brazos Valley Connection [removed: Project.][added: Project]

[removed: CenterPoint] Houston [added: Electric] expects to complete construction [removed: of] [added: and energize] the Brazos Valley Connection by [removed: mid-2018.][added: June 2018.]

| • | the performance of Enable, the amount of cash distributions we receive from Enable, [added: 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: |

| ◦ | access to debt and [removed: growth] [added: equity] capital; and |

| • | 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. |

As of December 31, 2016, we also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the limited partner interests in Enable.

For further information about our Electric Transmission & Distribution business segment, see “Business — Our Business — Electric Transmission & Distribution” in Item 1 of Part I of this report.

For further information about our Natural Gas Distribution business segment, see “Business — Our Business — Natural Gas Distribution” in Item 1 of Part I of this report.

For further information about our Energy Services business segment, see “Business — Our Business — Energy Services” in Item 1 of Part I of this report.

interest expense, capital spending and working capital requirements.

Reviewing recent years, year-over-year meter growth for Houston Electric hit a high in 2014 at 2.4%.

This growth slowed to 2.1% for 2015, largely as a result of the performance of the energy sector.

With some stabilization of the energy section in 2016, Houston Electric meter growth experienced an uptick to 2.3%.

We anticipate that this growth will continue at roughly 2%, in line with recent years.

In 2016, our Houston service area experienced above normal warmth with episodes of flooding.

Houston’s average temperature of 71.4 degrees Fahrenheit was the seventh highest (record 2012) going back to 1889.

However, only the TDU entered a weather hedge for the 2015-2016 and 2016-2017 heating seasons.

In Minnesota and Arkansas, rate adjustment mechanisms counter the impact of declining usage from energy efficiency improvements.

This growth also tends to mitigate the effects of reduced consumption.

In 2016, CES acquired Continuum, which included approximately 13,000 customers and 175 Bcf of gas sales.

The customer base was comprised of a mix similar to our existing business.

This acquisition helped drive the overall operating income increase for Energy Services in 2016 as compared to 2015, excluding mark-to-market accounting for derivatives.

In January 2017, CES acquired AEM.

These volumes depend significantly on the level of production from natural gas wells connected to Enable’s systems across a number of U.S. mid-continent markets.

Aggregate production volumes are affected by the overall amount of oil and gas drilling and completion activities.

Enable expects its business to continue to be impacted by the trends affecting the midstream industry, discussed below.

Enable’s outlook is based on its management’s assumptions regarding the impact of these trends that it has developed by interpreting the information currently available to them.

If Enable management’s assumptions or interpretation of available information prove to be incorrect, Enable’s future financial condition and results of operations may differ materially from its expectations.

Enable’s business is impacted by commodity prices, which have declined and otherwise experienced significant volatility in recent years.

In early 2016, natural gas and crude oil prices dropped to their lowest levels in over 10 years.

Both natural gas and crude oil prices increased moderately in the second half of 2016.

Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable’s systems, and the volumes on Enable’s systems are negatively impacted if producers decrease drilling and production in those areas served.

Both Enable’s gathering and processing segment and its transportation and storage segment can be impacted by drilling and production.

Enable’s gathering and processing segment primarily serves producers, and many producers utilize the services provided by its transportation and storage segment.

A decrease in volumes will decrease cash flows from Enable’s systems.

In addition, Enable’s processing arrangements expose it to commodity price fluctuations.

Despite recent low commodity prices, Enable’s long-term view is that natural gas and crude oil production in the U.S. will increase.

As a result, the proven reserves of natural gas and crude oil in the U.S. have significantly increased and the price of natural gas and crude oil has decreased compared to historical periods.

The EIA projects that the majority of domestic consumption growth will be in the electric power, industrial and liquefaction for export sectors where the aggregate natural gas demand of these sectors is expected to grow from approximately 17.8 trillion cubic feet of natural gas in 2016 to approximately 21.0 trillion cubic feet of natural in 2040.

attractiveness of Enable’s debt securities to investors.

Enable relies on certain key natural gas producer customers for a significant portion of its natural gas and NGLs supply.

For the year ended December 31, 2016, Enable’s top ten natural gas producer customers accounted for approximately 66% of its gathered volumes.

These customers include affiliates of Continental, Vine, GeoSouthern, XTO Energy, Apache, Tapstone, Chesapeake, BP Energy Company, Covey Park and Marathon.

| • | CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems. A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. As of December 31, 2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets. |

Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving over 2.3 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately six million people and includes the city of Houston.

On behalf of REPs, CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout CenterPoint Houston’s certificated service territory.

The Electric Reliability Council of Texas, Inc. (ERCOT) serves as the regional reliability coordinating council for member electric power systems in Texas.

ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs.

The ERCOT market represents approximately 90% of the

demand for power in Texas and is one of the nation’s largest power markets.

Transmission and distribution services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

CERC owns and operates our regulated natural gas distribution business (NGD), which engages in intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.4 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

Midstream Investments

We have a significant equity investment in Enable, an unconsolidated subsidiary that owns, operates and develops natural gas and crude oil assets.

Our Midstream Investments segment includes equity earnings associated with the operations of Enable.

Our other operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.

In 2014, we experienced a colder than normal January and February and milder

temperatures for the rest of the year, including the summer months, in the Houston area.

In 2013, we experienced a colder than normal spring and very cold weather in November and December in Houston and all of the states in which we have gas customers.

Oil and gas producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas, NGLs and crude oil, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations.

Commodity price changes impact the commodity-based portion of Enable’s gross margin, its producer customers’ decisions to drill and complete wells and its transportation and storage customers decisions to contract capacity on Enable’s system.

Prices of natural gas, crude oil, and NGLs have historically experienced periods of significant volatility.

Enable’s results are also impacted by the price differentials between receipt and delivery points on its systems.

The prices of crude oil, NGLs and natural gas have continued to decline significantly.

Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years from a high of $13.31 per MMBtu in July 2008 to $1.63 per MMBtu at December 23, 2015 and $145.31 per barrel in July 2008 to $26.19 per barrel at February 11, 2016, respectively.

The level of drilling is expected to positively correlate with long-term trends in commodity prices.

Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

Recently, declining crude oil, natural gas and NGL prices have resulted in decreases in current and anticipated crude oil and natural gas drilling activity.

Should lower prices and producer activity persist for a sustained period or should prices and producer activity decline further, Enable’s future volumes and cash flows may be negatively impacted.

To maintain and increase throughput volumes on its systems, Enable must continue to contract its capacity to shippers, including producers and marketers.

Enable’s transportation and storage systems compete for customers based on the type of service a customer needs, operating flexibility, receipt and delivery points and geographic flexibility and available capacity and price.

To maintain and increase Enable’s transportation and storage volumes, it must continue to contract its capacity to shippers, including producers, marketers, local distribution companies, power generators and industrial end users.

Natural gas continues to be a critical component of energy supply and demand in the United States.

According to the U.S. Energy Information Administration (EIA), demand for natural gas in the electric power sector is projected to increase from approximately 8.2 Tcf in 2013 to approximately 9.4 Tcf in 2040, with a portion of the growth attributable to the retirement of 37 gigawatts of coal-fired capacity by 2020.

The EIA also predicts that low natural gas prices will lead to the increase of natural gas consumption in the industrial sector and to the United States becoming a new exporter of natural gas by mid-2017.

However, the EIA expects growth in natural gas consumption for power generation, exploration and in the industrial sector to be partially offset by decreased usage in the residential sector.

Impairment of Equity Investment.

We recognized a loss of $1,633 million from our investment in Enable for the year ended December 31, 2015.

In April 2015, CenterPoint Houston filed a Certificate of Convenience and Necessity (CCN) application with the Texas Utility Commission seeking approval to construct the Brazos Valley Connection (CenterPoint Houston’s portion of the Houston region transmission project).

CenterPoint Houston proposed 32 alternative routes for the project in the application, including one route (the Recommended Route) that CenterPoint Houston identified in the application as best meeting the routing criteria used by the Texas Utility Commission in the route selection portion of CCN proceedings.

The hearing on CenterPoint Houston’s CCN application was divided into two phases, a route-selection phase and a need phase.

The route selection hearing was held on August 17 and 18, 2015.

The hearing on the need for the line was held on September 2 and 3, 2015.

| • | Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, [removed: natural gas liquids] [added: NGLs] and other energy commodities. |

As of December 31, [removed: 2015,] [added: 2016,] we had outstanding long-term debt, lease obligations and obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.

Our floating rate obligations aggregated [removed: $1.1] [added: $1.4] billion and [removed: $532 million] [added: $1.1 billion] as of December 31, [removed: 2015] [added: 2016] and [removed: 2014,] [added: 2015,] respectively.

If the floating interest rates were to increase by 10% from December 31, [removed: 2015] [added: 2016] rates, our combined interest expense would increase by $1 million annually.

As of December 31, [removed: 2015] [added: 2016] and [removed: 2014,] [added: 2015,] we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating [removed: $7.5] [added: $7.1] billion and [removed: $8.2] [added: $7.5] billion, respectively, in principal amount and having a fair value of [removed: $8.0] [added: $7.5] billion and [removed: $8.9] [added: $8.0] billion, respectively.

Because these instruments are fixed-rate, they do not expose us to the risk of loss in earnings due to changes in market interest rates (see Note [removed: 12] [added: 13] to our consolidated financial statements).

However, the fair value of these instruments would increase by approximately [removed: $216] [added: $207] million if interest rates were to decline by 10% from their levels at December 31, [removed: 2015.][added: 2016.]

As discussed in Note [removed: 10] [added: 11] to our consolidated financial statements, the ZENS obligation is bifurcated into a debt component and a derivative component.

The debt component of [removed: $154] [added: $114] million at December 31, [removed: 2015] [added: 2016] was a fixed-rate obligation and, therefore, did not expose us to the risk of loss in earnings due to changes in market interest rates.

However, the fair value of the debt component would increase by approximately [removed: $24] [added: $18] million if interest rates were to decline by 10% from levels at December 31, [removed: 2015.][added: 2016.]

[added: Changes] in the fair value of the derivative component, a [removed: $442] [added: $717] million recorded liability at December 31, [removed: 2015,] [added: 2016,] are recorded in our Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate.

If the risk-free interest rate were to increase by 10% from December 31, [removed: 2015] [added: 2016] levels, the fair value of the derivative component liability would increase by approximately [removed: $8] [added: $4] million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

We are exposed to equity market value risk through our ownership of 7.1 million shares of TW Common, [removed: 1.8] [added: 0.9] million shares of [removed: TWC] [added: Time] Common and 0.9 million shares of [removed: Time] [added: Charter] Common, which we hold to facilitate our ability to meet our obligations under the ZENS.

See Note [removed: 10] [added: 11] to our consolidated financial statements for a discussion of our ZENS obligation.

A decrease of 10% from the December 31, [removed: 2015] [added: 2016] aggregate market value of these shares would result in a net loss of approximately [removed: $14] [added: $2] million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

At December 31, [removed: 2015,] [added: 2016,] the recorded fair value of our non-trading energy derivatives was a net asset of [removed: $53] [added: $38] million (before collateral), all of which is related to our Energy Services business segment.

An increase of 10% in the market prices of energy commodities from their December 31, [removed: 2015] [added: 2016] levels would have decreased the fair value of our non-trading energy derivatives net asset by [removed: $6] [added: $7] million.

Changes in the fair value of the TW Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS.

Changes

Our operating subsidiaries own and operate electric transmission and distribution [removed: facilities] and natural gas distribution [removed: facilities] [added: facilities, supply natural gas to commercial] and [added: industrial customers and electric and natural gas utilities and] own interests in Enable [removed: Midstream Partners, LP (Enable)] as described below.

Our [removed: indirect] [added: indirect,] wholly-owned subsidiaries include:

| • | [removed: CenterPoint Energy] Houston Electric, [removed: LLC (CenterPoint Houston),] which engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; [removed: and] |

We make available free of charge on our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the [removed: Securities and Exchange Commission (SEC).][added: SEC.]

| • | the charters of the audit, [removed: compensation] [added: compensation, finance] and governance committees of our [removed: Board] [added: board] of [removed: Directors.] [added: directors.] |

[removed: CenterPoint] Houston [added: Electric] is a transmission and distribution electric utility that operates wholly within the state of Texas.

Neither [removed: CenterPoint] Houston [added: Electric] nor any other subsidiary of CenterPoint Energy makes direct retail or wholesale sales of electric energy or owns or operates any electric generating facilities.

On behalf of [removed: retail electric providers (REPs), CenterPoint] [added: REPs,] Houston [added: Electric] delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kilovolts [removed: (kV)] in locations throughout [removed: CenterPoint Houston’s] [added: Houston Electric’s] certificated service territory.

[removed: CenterPoint] Houston [added: Electric] constructs and maintains transmission facilities and provides transmission services under tariffs approved by the [removed: Public Utility Commission of Texas (Texas Utility Commission).][added: PUCT.]

In [removed: the Electric Reliability Council of Texas, Inc. (ERCOT),] [added: ERCOT,] end users purchase their electricity directly from certificated REPs.

[removed: CenterPoint] Houston [added: Electric] delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer.

[removed: CenterPoint Houston’s] [added: Houston Electric’s] distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders.

[removed: CenterPoint Houston’s] [added: Houston Electric’s] operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations.

[removed: CenterPoint] Houston [added: Electric] provides distribution services under tariffs approved by the [removed: Texas Utility Commission.][added: PUCT.]

[removed: Texas Utility Commission] [added: PUCT] rules and market protocols govern the commercial operations of distribution companies and other market participants.

Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the [removed: Texas Utility Commission.][added: PUCT.]

[removed: CenterPoint] Houston [added: Electric] is a member of ERCOT.

Within ERCOT, prices for wholesale generation and retail electric sales are unregulated, but services provided by transmission and distribution companies, such as [removed: CenterPoint Houston,] [added: Houston Electric,] are regulated by the [removed: Texas Utility Commission.][added: PUCT.]

The ERCOT market included available generating capacity of over [removed: 77,000] [added: 78,000] megawatts [removed: (MW)] as of December 31, [removed: 2015.][added: 2016.]

The ERCOT market operates under the reliability standards set by the [removed: North American Electric Reliability Corporation (NERC)] [added: NERC] and approved by the [removed: Federal Energy Regulatory Commission (FERC).][added: FERC.]

Within ERCOT, these reliability standards are administered by the [removed: Texas Reliability Entity (TRE).][added: TRE.]

The [removed: Texas Utility Commission] [added: PUCT] has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid.

The ERCOT [removed: independent system operator (ERCOT ISO)] [added: ISO] is responsible for operating the bulk electric power supply system in the ERCOT market.

[removed: CenterPoint Houston’s] [added: Houston Electric’s] electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO.

[removed: CenterPoint] Houston [added: Electric] participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

Those costs were recoverable after approval by the [removed: Texas Utility Commission] [added: PUCT] either through the issuance of securitization bonds or through the implementation of a competition transition charge as a rider to the utility’s tariff.

[removed: CenterPoint Houston’s] [added: Houston Electric’s] integrated utility business was restructured in accordance with the Texas electric restructuring law and its generating stations were sold to third parties.

Ultimately [removed: CenterPoint] Houston [added: Electric] was authorized to recover a total of approximately $5 billion in stranded costs, other charges and related interest.

Most of that amount was recovered through the issuance of transition bonds by special purpose subsidiaries of [removed: CenterPoint Houston.][added: Houston Electric.]

[added: The transition bonds] are repaid through charges imposed on customers in [removed: CenterPoint Houston’s] [added: Houston Electric’s] service territory.

As of December 31, [removed: 2015,] [added: 2016,] approximately [removed: $2.3] [added: $1.9] billion aggregate principal amount of transition bonds were outstanding.

[removed: CenterPoint] Houston [added: Electric] serves nearly all of the Houston/Galveston metropolitan area.

At December 31, [removed: 2015, CenterPoint Houston’s] [added: 2016, Houston Electric’s] customers consisted of approximately [removed: 69] [added: 64] REPs, which sell electricity to [removed: over 2.3] [added: more than 2.4] million metered customers in [removed: CenterPoint Houston’s] [added: Houston Electric’s] certificated service area, and municipalities, electric cooperatives and other distribution companies located outside [removed: CenterPoint Houston’s] [added: Houston Electric’s] certificated service area.

Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the [removed: Texas Utility Commission.][added: PUCT.]

Sales to REPs that are affiliates of NRG [removed: Energy, Inc. (NRG)] represented approximately [removed: 35%, 37%] [added: 34%, 35%] and [removed: 38%] [added: 37%] of [removed: CenterPoint Houston’s] [added: Houston Electric’s] transmission and distribution revenues in [removed: 2015, 2014] [added: 2016, 2015] and [removed: 2013,] [added: 2014,] respectively.

Sales to REPs that are affiliates of Energy Future Holdings [removed: Corp. (Energy Future Holdings)] represented approximately [added: 11%,] 10% [added: and 10%] of [removed: CenterPoint Houston’s] [added: Houston Electric’s] transmission and distribution revenues in [removed: each of 2015, 2014] [added: 2016, 2015] and [removed: 2013.][added: 2014, respectively.]

[removed: CenterPoint Houston’s] [added: Houston Electric’s] aggregate billed receivables balance from REPs as of December 31, [removed: 2015] [added: 2016] was [removed: $195] [added: $193] million.

Approximately [removed: 34%] [added: 33%] and [removed: 11%] [added: 12%] of this amount was owed by affiliates of NRG and Energy Future Holdings, respectively.

[removed: CenterPoint] Houston [added: Electric] does not have long-term contracts with any of its customers.

In May 2012, [removed: CenterPoint] Houston [added: Electric] substantially completed the deployment of an [removed: advanced metering system (AMS),] [added: AMS,] having installed approximately 2.2 million smart meters.

| • | 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. |

As of December 31, 2016, we also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the limited partner interests in Enable.

AMS

Houston Electric may issue additional general

| Arkansas | 379,117 | | | 48,161 | | | 427,278 | |

| Louisiana | 230,475 | | | 16,842 | | | 247,317 | |

| Minnesota | 778,731 | | | 69,856 | | | 848,587 | |

| Mississippi | 112,992 | | | 12,548 | | | 125,540 | |

| Oklahoma | 89,419 | | | 10,785 | | | 100,204 | |

| Texas | 1,592,804 | | | 97,614 | | | 1,690,418 | |

| Total NGD | 3,183,538 | | | 255,806 | | | 3,439,344 | |

Major suppliers in 2016 included the following:

| | | |

| --- | --- | --- |

| | | |

| Supplier | | Percent of Supply Volumes |

| BP Energy Company/BP Canada Energy Marketing | | 17.7% |

| Macquarie Energy | | 16.3% |

| Tenaska Marketing Ventures | | 14.0% |

| Sequent Energy Management | | 8.0% |

| Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline | | 7.1% |

| One Nation Energy Solutions | | 3.3% |

| Laclede Energy Resources | | 2.9% |

| Mieco | | 2.6% |

| CES | | 2.5% |

| Twin Eagle Resource Management | | 2.2% |

NGD may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.

NGD has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs.

NGD currently has AMAs in Arkansas, north Louisiana and Oklahoma that extend through 2020.

These totals include approximately 13,000 customers and 175 Bcf of natural gas related to the acquisition of Continuum, which closed in April 2016, and was fully integrated into CES by the end of 2016.

Not included in the 2016 customer count are approximately 60,000 natural gas customers that are served under residential and small commercial choice programs invoiced by their host utility.

These customers are not included in customer count so as not to distort the significant margin impact from the remaining customer base.

In January 2017, CES completed the acquisition of AEM.

For information related to this acquisition, see Note 19 to our consolidated financial statements.

CES optimizes its use of these

Our Midstream Investments business segment consists of CERC Corp.’s equity method investment in Enable.

Enable is a publicly traded MLP, jointly controlled by CERC Corp. and OGE.

For information related to CERC Corp.’s equity method investment in Enable, see Notes 2(b), 10 and 19 to our consolidated financial statements.

In December 2011, Congress passed the 2011 Act.

| • | CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems (NGD). A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. As of December 31, 2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets. |

Substantially all of our former Interstate Pipelines business segment and Field Services business segment were contributed to Enable in May 2013.

As a result, these business segments did not report operating results during 2014 or 2015.

The transition bonds

Advanced Metering System and Distribution Grid Automation (Intelligent Grid)

CenterPoint Houston is also pursuing deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” (IG) which would provide on-demand data and information about the status of facilities on its system.

We expect to include the costs of the deployment in future rate proceedings before the Texas Utility Commission.

In October 2009, the DOE selected CenterPoint Houston for a $200 million grant to help fund its AMS and IG projects.

CenterPoint Houston received substantially all of the $200 million of grant funding from the DOE by 2011 and used $150 million of it to accelerate completion of its deployment of advanced meters to 2012.

CenterPoint Houston used the other $50 million from the grant for an initial deployment of an IG that covers approximately 12% of its service territory.

The DOE-funded portion of the IG project was substantially completed in 2015, and the capital portion of the IG project subject to partial funding by the DOE cost approximately $140 million.

| Arkansas | 379,319 | | | 48,128 | | | 427,447 | |

| Louisiana | 229,873 | | | 16,917 | | | 246,790 | |

| Minnesota | 770,891 | | | 69,381 | | | 840,272 | |

| Mississippi | 112,140 | | | 12,536 | | | 124,676 | |

| Oklahoma | 89,756 | | | 10,789 | | | 100,545 | |

| Texas | 1,567,866 | | | 96,170 | | | 1,664,036 | |

| Total NGD | 3,149,845 | | | 253,921 | | | 3,403,766 | |

Major suppliers in 2015 included BP Energy Company/BP Canada Energy Marketing (18.4% of supply volumes), Tenaska Marketing Ventures (14.5%), Sequent Energy Management (9.0%), ConocoPhillips Company (7.0%), Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline (6.3%), Twin Eagle Resource Management (3.4%), CenterPoint Energy Services (3.2%), Mieco (3.1%), Oneok Energy Services (2.9%), and Trailstone NA Logistics (2.3%).

The agreements have varying terms, the longest of which expires in 2019.

In May 2013, we, OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), formed Enable, initially a private limited partnership.

On April 16, 2014, Enable completed its initial public offering (IPO) of 28,750,000 common units at a price of $20.00 per unit, which included 3,750,000 common units sold by ArcLight pursuant to an over-allotment option that was fully exercised by the underwriters.

Enable received $464 million in net proceeds from the sale of the units, after deducting underwriting fees, structuring fees and other offering costs.

In connection with Enable’s IPO, a portion of our common units were converted into subordinated units.

As of December 31, 2015, CERC Corp. held an approximate 55.4% limited partner interest in Enable (consisting of 94,151,707 common units and 139,704,916 subordinated units) and OGE held an approximate 26.3% limited partner interest in Enable (consisting of 42,832,291 common units and 68,150,514 subordinated units).

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

Enable is controlled jointly by CERC Corp. and OGE as each own 50% of the management rights in the general partner of Enable.

Sale of our ownership interests in Enable’s general partner to anyone other than an affiliate prior to May 1, 2016 is prohibited by Enable’s general partner’s limited liability company agreement.

Sale of our or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and we are not permitted to dispose of less than all of our interest in Enable’s general partner.

As of December 31, 2015, CERC Corp. and OGE also own a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner of Enable.

Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 45 days after the end of each quarter.

If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount.

In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

On January 28, 2016, we entered into a purchase agreement with Enable pursuant to which we agreed to purchase in a private placement (Private Placement) an aggregate of 14,520,000 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable (Series A Preferred Units) for a cash purchase price of $25.00 per Series A Preferred Unit.

The Private Placement closed on February 18, 2016.

In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. We used the proceeds from this redemption for our investment in the Series A Preferred Units.

Our investment in Enable is accounted for on an equity basis.

Equity earnings associated with our interest in Enable are reported under the Midstream Investments segment.

As of December 31, 2015, Enable’s portfolio of energy infrastructure assets included approximately 12,400 miles of gathering pipelines, 13 major processing plants with approximately 2.3 Bcf per day of processing capacity and 2.3 Bcf per day of treating capacity, approximately 7,900 miles of interstate pipelines (including Southeast Supply Header, LLC (SESH)), approximately 2,200 miles of intrastate pipelines and eight storage facilities providing approximately 85.0 Bcf of storage capacity.

Eight of Enable’s processing plants in the Anadarko basin are interconnected through its super-header system.

For a discussion of material legal and regulatory proceedings affecting us, please read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of this report and Note [removed: 14(d)] [added: 15(d)] to our consolidated financial statements, which information is incorporated herein by reference.

| | FOR THE FISCAL YEAR ENDED DECEMBER 31, [removed: 2015] [added: 2016] |

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [removed: o]

The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (CenterPoint Energy) was [removed: $8,146,639,191] [added: $10,273,144,728] as of June 30, [removed: 2015,] [added: 2016,] using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers.

As of February [removed: 12, 2016,] [added: 10, 2017,] CenterPoint Energy had [removed: 430,271,749] [added: 430,688,867] shares of Common Stock outstanding.

Portions of the definitive proxy statement relating to the [removed: 2016] [added: 2017] Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, [removed: 2015,] [added: 2016,] are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.

| Item 1. | | Business | | [removed: [1](#s3E2D2A61D3B25BB6A7161B2F7F899DB4)] [added: [1](#s76A4225A73E9534EB8BF83C23B96F598)] |

| Item 1A. | | Risk Factors | | [removed: [18](#s31F770E8A2FF56E9A62B0145AF886B11)] [added: [15](#s5E48B42655885BD7B748A10AD1B8E4BC)] |

| Item 1B. | | Unresolved Staff Comments | | [removed: [39](#s00D4EFDD65525997A21355BDCEDE062E)] [added: [40](#s541B273F0E7D5CFF9F9DFC19644B4A5B)] |

| Item 2. | | Properties | | [removed: [39](#sFF3344AFEA085DD898A96E1192F7B894)] [added: [40](#s2CCBE7E488725FCCA9C47500276B6C77)] |

| Item 3. | | Legal Proceedings | | [removed: [40](#s24D07045000354AB88D3162C0D4E6DA5)] [added: [40](#s5FD9A574751D5BEBA594A1052F04F902)] |

| Item 4. | | Mine Safety Disclosures | | [removed: [40](#s49BA1C10FD2452929E478889D5222EA6)] [added: [40](#sB9D948E82FB65D53842683DA7FD1BD38)] |

| Item 5. | | Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | | [removed: [41](#s41B5D85C70F555AEB066CA95749B6253)] [added: [41](#sC0A98C9E0EA25B7BB0318B58AE8F3DD7)] |

| Item 6. | | Selected Financial Data | | [removed: [42](#sE6B91CF8AAFC5933B28D427685AEBF37)] [added: [42](#s93E41C9CF5155DD0A282CE5D6471439A)] |

| Item 7. | | Management’s Discussion and Analysis of Financial Condition and Results of Operations | | [removed: [43](#s5736FEF2B0775E30BE1233C330843D3C)] [added: [43](#s27CD8846DFB25B71A310EBD2E1B43524)] |

| Item 7A. | | Quantitative and Qualitative Disclosures About Market Risk | | [removed: [73](#s2100426ADE775F2A933C379E81503D2C)] [added: [67](#sA9666E40D94B529BAED8890F19AB9758)] |

| Item 8. | | Financial Statements and Supplementary Data | | [removed: [75](#s36A5D5F3B0105070A62D96F7B39CE1C2)] [added: [70](#s980AD0DA03F65CDB95285BA77A665AD1)] |

| Item 9. | | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | | [removed: [122](#sA423884BCB875F77831962C691B1CFD1)] [added: [119](#sDA42C0FF74ED5CB3BD8F1D2F4E12D354)] |

| Item 9A. | | Controls and Procedures | | [removed: [122](#sE1F5EE0ADBE95A7991C1FF7319DA754E)] [added: [119](#s63137967247758469FA0C67FF5A133A2)] |

| Item 9B. | | Other Information | | [removed: [124](#s68D39E9DC76A5FC1AA2C60EBEE8AB823)] [added: [122](#s3696559B113056F7BCCDD423BCC3C7C7)] |

| Item 10. | | Directors, Executive Officers and Corporate Governance | | [removed: [124](#s3618DA2068AE5DCCA7979CB398E46125)] [added: [122](#sCF55A08340895018A9955C542F075FCE)] |

| Item 11. | | Executive Compensation | | [removed: [124](#s578B786A3CDA50FCAB81FA14CD2B9B67)] [added: [122](#sEF1BDFE26ABE585E9DE3E23E3AA240DB)] |

| Item 12. | | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | | [removed: [125](#s7DD1D5510F3D5688AA2FD0FAC9B73551)] [added: [122](#s25E2F84BAE8757EFA42527B412B1AFF6)] |

| Item 13. | | Certain Relationships and Related Transactions, and Director Independence | | [removed: [125](#s6BAE51472D7E5D72887ABB1257529E00)] [added: [122](#sB416B8CB64FE5921A0DED94EBC2B1763)] |

| Item 14. | | Principal Accounting Fees and Services | | [removed: [125](#s6DF3016D0F665853A1F475C7AB6ADEB1)] [added: [122](#s45F8B96AC17B5B9D9278E2B177FA05E9)] |

| Item 15. | | Exhibits and Financial Statement Schedules | | [removed: [125](#sF208CFEC1F185963960E1E11EF4F205A)] [added: [123](#s3515366ECF3B574987F94E8B0352277B)] |

You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” [added: “target,”] “will” or other similar words.

10-K 1 cnp_10kx12312016.htm 10-K

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| | | |

| GLOSSARY | | |

| AEM | | Atmos Energy Marketing, LLC, a wholly-owned subsidiary of Atmos Energy Holdings, Inc., a wholly-owned subsidiary of Atmos Energy Corporation |

| AFUDC | | Allowance for funds used during construction |

| AMAs | | Asset Management Agreements |

| AMS | | Advanced Metering System |

| AOL | | AOL Inc. |

| APSC | | Arkansas Public Service Commission |

| ArcLight | | ArcLight Capital Partners, LLC |

| ARO | | Asset retirement obligation |

| ASC | | Accounting Standards Codification |

| ASU | | Accounting Standards Update |

| AT&T | | AT&T Inc. |

| AT&T Common | | AT&T common stock |

| Btu | | British thermal units |

| Bcf | | Billion cubic feet |

| Bond Companies | | Transition and system restoration bond companies |

| Brazos Valley Connection | | A portion of the Houston region transmission project between Houston Electric’s Zenith substation and the Gibbons Creek substation owned by the Texas Municipal Power Agency |

| CEA | | Commodities Exchange Act |

| CEIP | | CenterPoint Energy Intrastate Pipelines, LLC |

| CenterPoint Energy | | CenterPoint Energy, Inc., and its subsidiaries |

| CERC Corp. | | CenterPoint Energy Resources Corp. |

| CERC | | CERC Corp., together with its subsidiaries |

| CERCLA | | Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended |

| CES | | CenterPoint Energy Services, Inc., a wholly-owned subsidiary of CERC Corp. |

| CFTC | | Commodity Futures Trading Commission |

| Charter | | Charter Communications, Inc. |

| Charter Common | | Charter common stock |

| CIP | | Conservation Improvement Program |

| Continuum | | The retail energy services business of Continuum Retail Energy Services, LLC, including its wholly-owned subsidiary Lakeshore Energy Services, LLC and the natural gas wholesale assets of Continuum Energy Services, LLC |

| DCRF | | Distribution Cost Recovery Factor |

| DOE | | U.S. Department of Energy |

| DOT | | U.S. Department of Transportation |

| Dth | | Dekatherms |

| EECR | | Energy Efficiency Cost Recovery |

| EECRF | | Energy Efficiency Cost Recovery Factor |

| EGT | | Enable Gas Transmission, LLC |

10-K 1 cnp_10kx12312015.htm 10-K

Most of our electric lines and [added: natural] gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.

As of February [removed: 12, 2016,] [added: 10, 2017,] our common stock was held by approximately [removed: 34,130] [added: 32,130] shareholders of record.

Our common stock is listed on the [removed: New York] [added: NYSE] and Chicago Stock [removed: Exchanges] [added: Exchange] and is traded under the symbol “CNP.”

The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the [removed: New York Stock Exchange] [added: NYSE] composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods.

| First Quarter | | | | | | | | | $ | [removed: 0.2375] [added: 0.2575] | |

| Second Quarter | | | | | | | | | $ | [removed: 0.2375] [added: 0.2575] | |

| Third Quarter | | | | | | | | | $ | [removed: 0.2375] [added: 0.2575] | |

| Fourth Quarter | | | | | | | | | $ | [removed: 0.2375] [added: 0.2575] | |

The closing market price of our common stock on December 31, [removed: 2015] [added: 2016] was [removed: $18.36] [added: $24.64] per share.

On January [removed: 20, 2016,] [added: 5, 2017,] our board of directors declared a regular quarterly cash dividend of [removed: $0.2575] [added: $0.2675] per share, payable on March 10, [removed: 2016] [added: 2017] to shareholders of record on February 16, [removed: 2016.][added: 2017.]

During the quarter ended December 31, [removed: 2015,] [added: 2016,] none of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.

| 2016 | | | | | | | | | | | |

| January 20 | | | | | $ | 16.90 | | | | | |

| March 29 | $ | 21.25 | | | | | | | | | |

| April 5 | | | | | $ | 20.51 | | | | | |

| June 29 | $ | 24.00 | | | | | | | | | |

| July 22 | $ | 24.69 | | | | | | | | | |

| August 16 | | | | | $ | 22.13 | | | | | |

| October 11 | | | | | $ | 21.84 | | | | | |

| December 22 | $ | 24.84 | | | | | | | | | |

| 2014 | | | | | | | | | | | |

| January 3 | | | | | $ | 22.81 | | | | | |

| February 21 | $ | 24.48 | | | | | | | | | |

| April 7 | | | | | $ | 23.39 | | | | | |

| June 30 | $ | 25.54 | | | | | | | | | |

| July 1 | $ | 25.38 | | | | | | | | | |

| August 6 | | | | | $ | 23.56 | | | | | |

| November 10 | $ | 25.38 | | | | | | | | | |

| December 15 | | | | | $ | 21.54 | | | | | |

| | Year Ended December 31, | | | | | | | | | | | | | | | | | | | [removed: |]

| | [removed: 2015 |] [added: 2016] | | | [removed: 2014] | [added: 2015] | | | [removed: 2013] | [added: 2014] | | | [removed: 2012] | [added: 2013] | | | [removed: 2011 (4)] | [added: 2012] | | |

| | (in millions, except per share amounts) | | | | | | | | | | | | | | | | | | | [removed: |]

| Revenues | $ | [removed: 7,386] [added: 7,528] | | | $ | [removed: 9,226] [added: 7,386] | | | $ | [removed: 8,106] [added: 9,226] | | | $ | [removed: 7,452] [added: 8,106] | | | $ | [removed: 8,450 |] [added: 7,452] | |

| Equity in [removed: Earnings (Losses)] [added: earnings (losses)] of [removed: Unconsolidated Affiliates] [added: unconsolidated affiliates] | [removed: (1,633] [added: 208] | | [added: | | (1,663 | |] ) | (1) | 308 | | | [removed: (2)] | 188 | | | [removed: (3)] | 31 | | | [removed: | 30 | | | |]

| [removed: Income (Loss) before Extraordinary Item | (692] [added: Net income (loss)] | [added: $] | [removed: )] [added: 432] | | [removed: 611] | [added: $] | [added: (692] | [added: )] | [removed: 311] | [added: $] | [added: 611] | | [removed: 417] | [added: $] | [added: 311] | | [removed: 770] | [added: $] | [added: 417] | |

| Basic earnings (loss) per common [removed: share: |] [added: share] | [added: $] | [added: 1.00] | | | [added: $] | [added: (1.61] | [added: )] | | [added: $] | [added: 1.42] | | | [added: $] | [added: 0.73] | | | [added: $] | [added: 0.98] | |

| [removed: Basic] [added: Diluted] earnings (loss) per common share | $ | [removed: (1.61] [added: 1.00] | [removed: )] | | $ | [removed: 1.42] [added: (1.61] | [added: )] | | $ | [removed: 0.73] [added: 1.42] | | | $ | [removed: 0.98] [added: 0.72] | | | $ | [removed: 3.19 |] [added: 0.97] | |

| Cash dividends declared per common share | $ | [removed: 0.99] [added: 1.03] | | | $ | [removed: 0.95] [added: 0.99] | | | $ | [removed: 0.83] [added: 0.95] | | | $ | [removed: 0.81] [added: 0.83] | | | $ | [removed: 0.79 |] [added: 0.81] | |

| Dividend payout ratio | [removed: n/a] [added: 103] | | [added: %] | | [removed: 67] [added: n/a] | | [removed: %] | | [removed: 114] [added: 67] | | % | | [removed: 83] [added: 114] | | % | | [removed: 44] [added: 83] | | % | [removed: (5) |]

| Return on average common equity | [added: 12 | | % | |] (17 | | )% | | 14 | | % | | 7 | | % | | 10 | | % | [removed: | 21 | | % | (5) |]

| Ratio of earnings to fixed charges | [removed: 2.67 |] [added: 2.74] | | | [removed: 2.79] | [added: 2.67] | | | [removed: 2.42] | [added: 2.79] | | | [removed: 2.29] | [added: 2.42] | | | [removed: 2.96] | [added: 2.29] | | [removed: (5)] |

| At year-end: | | | | | | | | | | | | | | | | | | | | [removed: |]

| Book value per common share | $ | [removed: 8.05] [added: 8.04] | | | $ | [removed: 10.58] [added: 8.05] | | | $ | [removed: 10.09] [added: 10.58] | | | $ | 10.09 | | | $ | [removed: 9.91 |] [added: 10.09] | |

| Market price per common share | [removed: 18.36 |] [added: 24.64] | | | [removed: 23.43] | [added: 18.36] | | | [removed: 23.18] | [added: 23.43] | | | [removed: 19.25] | [added: 23.18] | | | [removed: 20.09] | [added: 19.25] | | |

| Market price as a percent of book value | [removed: 228] [added: 306] | | % | | [removed: 221] [added: 228] | | % | | [removed: 230] [added: 221] | | % | | [removed: 191] [added: 230] | | % | | [removed: 203] [added: 191] | | % | [removed: |]

| Short-term borrowings | [removed: 40 |] [added: 35] | | | [removed: 53] | [added: 40] | | | [removed: 43] | [added: 53] | | | [removed: 38] | [added: 43] | | | [removed: 62] | [added: 38] | | |

| [removed: Other long-term] [added: Long-term] debt, including current maturities | [removed: 6,100 |] [added: 71] | | [added: %] | [removed: 5,758] | [added: 72] | | [added: %] | [removed: 4,914] | [added: 66] | | [added: %] | [removed: 5,910] | [added: 66] | | [added: %] | [removed: 6,603] | [added: 69] | | [added: %] |

| Capitalization: | | | | | | | | | | | | | | | | | | | | [removed: |]

| Common stock equity | [removed: 28] [added: 29] | | % | | [removed: 34] [added: 28] | | % | | 34 | | % | | [removed: 31] [added: 34] | | % | | [removed: 32] [added: 31] | | % | [removed: |]

| Long-term debt, [added: excluding securitization bonds, and] including current maturities | [removed: 72] [added: 64] | | % | | [removed: 66] [added: 64] | | % | | [removed: 66] [added: 56] | | % | | [removed: 69] [added: 53] | | % | | [removed: 68] [added: 58] | | % | [removed: |]

| Common stock equity | 36 | | % | | [removed: 44] [added: 36] | | % | | [removed: 47] [added: 44] | | % | | [removed: 42] [added: 47] | | % | | [removed: 39] [added: 42] | | % | [removed: |]

| Capital expenditures | $ | [removed: 1,575] [added: 1,406] | | | $ | [removed: 1,402] [added: 1,575] | | | $ | [removed: 1,272] [added: 1,402] | | | $ | [removed: 1,188] [added: 1,272] | | | $ | [removed: 1,191 |] [added: 1,188] | |

| | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

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| | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | |

| Limited partner interests owned in Enable | 54.1 | | % | | 55.4 | | % | | 55.4 | | % | | 58.3 | | % | | n/a | | |

| Total assets (2) | $ | 21,829 | | | $ | 21,290 | | | $ | 23,150 | | | $ | 21,816 | | | $ | 22,806 | |

| Securitization bonds, including current maturities (2) | 2,278 | | | | 2,667 | | | | 3,037 | | | | 3,388 | | | | 3,832 | | |

| Other long-term debt, including current maturities (2) | 6,279 | | | | 6,063 | | | | 5,717 | | | | 4,873 | | | | 5,861 | | |

| Capitalization, excluding securitization bonds: | | | | | | | | | | | | | | | | | | | |

| (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. |

| | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Extraordinary Item, net of tax | — | | | | — | | | | — | | | | — | | | | 587 | | | |

| Net income (loss) | $ | (692 | ) | | $ | 611 | | | $ | 311 | | | $ | 417 | | | $ | 1,357 | | |

| Income (Loss) before Extraordinary Item | $ | (1.61 | ) | | $ | 1.42 | | | $ | 0.73 | | | $ | 0.98 | | | $ | 1.81 | | |

| Extraordinary Item, net of tax | — | | | | — | | | | — | | | | — | | | | 1.38 | | | |

| Diluted earnings (loss) per common share: | | | | | | | | | | | | | | | | | | | | |

| Income (Loss) before Extraordinary Item | $ | (1.61 | ) | | $ | 1.42 | | | $ | 0.72 | | | $ | 0.97 | | | $ | 1.80 | | |

| Extraordinary Item, net of tax | — | | | | — | | | | — | | | | — | | | | 1.37 | | | |

| Diluted earnings (loss) per common share | $ | (1.61 | ) | | $ | 1.42 | | | $ | 0.72 | | | $ | 0.97 | | | $ | 3.17 | | |

| Total assets | $ | 21,334 | | | $ | 23,200 | | | $ | 21,870 | | | $ | 22,871 | | | $ | 21,703 | | |

| Transition and system restoration bonds, including current maturities | 2,674 | | | | 3,046 | | | | 3,400 | | | | 3,847 | | | | 2,522 | | | |

| Capitalization, excluding transition and system restoration bonds: | | | | | | | | | | | | | | | | | | | | |

| Long-term debt, excluding transition and system restoration bonds, and including current maturities | 64 | | % | | 56 | | % | | 53 | | % | | 58 | | % | | 61 | | % | |

| | |

| --- | --- |

| (1) | As of December 31, 2015, we owned approximately 55.4% of the limited partner interests in Enable Midstream Partners, LP (Enable), an unconsolidated subsidiary that we account for on an equity basis. This amount includes $1,846 million of non-cash impairment charges related to Enable. |

| (2) | As of December 31, 2014, we owned approximately 55.4% of the limited partner interests in Enable and 0.1% of Southeast Supply Header (SESH), each an unconsolidated subsidiary, that we accounted for on an equity basis. |

| (3) | Following the formation of Enable on May 1, 2013, Enable owned substantially all of our former Interstate Pipelines and Field Services business segments, except for our retained 25.05% interest in SESH. As of December 31, 2013, we owned approximately 58.3% of the limited partner interests in Enable. |

| (4) | 2011 Income before Extraordinary Item includes a $224 million after-tax ($0.53 and $0.52 per basic and diluted share, respectively) return on true-up balance related to a portion of interest on the appealed true-up amount. |

| (5) | Calculated using Income before Extraordinary Item. |

We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, [removed: 2015] [added: 2016] and [removed: 2014,] [added: 2015,] and the related statements of consolidated income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, [removed: 2015.][added: 2016.]

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy, Inc. and subsidiaries as of December 31, [removed: 2015] [added: 2016] and [removed: 2014,] [added: 2015,] and the results of their operations and their cash flows for each of the three years in the period ended December 31, [removed: 2015,] [added: 2016,] in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, [removed: 2015,] [added: 2016,] based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February [removed: 26, 2016] [added: 28, 2017] expressed an unqualified opinion on the Company’s internal control over financial reporting.

| | [removed: 2015] [added: 2016] | | | | [removed: 2014] [added: 2015] | | | | [removed: 2013] [added: 2014] | | |

| Operation and maintenance | [removed: 2,007] [added: 2,093] | | | | [removed: 1,969] [added: 2,007] | | | | [removed: 1,847] [added: 1,969] | | |

| Depreciation and amortization | [removed: 970] [added: 1,126] | | | | [removed: 1,013] [added: 970] | | | | [removed: 954] [added: 1,013] | | |

| Taxes other than income taxes | [removed: 374] [added: 384] | | | | [removed: 388] [added: 374] | | | | [removed: 387] [added: 388] | | |

| Total | [removed: 6,453] [added: 6,569] | | | | [removed: 8,291] [added: 6,453] | | | | [removed: 7,096] [added: 8,291] | | |

| Operating Income | [removed: 933] [added: 959] | | | | [removed: 935] [added: 933] | | | | [removed: 1,010] [added: 935] | | |

| Gain [removed: (Loss)] [added: (loss)] on marketable securities | [removed: (93] [added: 326] | | [removed: )] | | [removed: 163] [added: (93] | | [added: )] | | [removed: 236] [added: 163] | | |

| Gain [removed: (Loss)] [added: (loss)] on indexed debt securities | [removed: 74] [added: (413] | | [added: )] | | [removed: (86] [added: 74] | | [removed: )] | | [removed: (193] [added: (86] | | ) |

| Interest and other finance charges | [removed: (352] [added: (338] | | ) | | [removed: (353] [added: (352] | | ) | | [removed: (351] [added: (353] | | ) |

| Interest on [removed: transition and system restoration bonds] [added: Securitization Bonds] | [removed: (105] [added: (91] | | ) | | [removed: (118] [added: (105] | | ) | | [removed: (133] [added: (118] | | ) |

| Equity in earnings (losses) of unconsolidated affiliates | [removed: (1,633] [added: 208] | | [removed: )] | | [removed: 308] [added: (1,633] | | [added: )] | | [removed: 188] [added: 308] | | |

| Other, net | [removed: 46] [added: 35] | | | | [removed: 36] [added: 46] | | | | [removed: 24] [added: 36] | | |

| Total | [removed: (2,063] [added: (273] | | ) | | [removed: (50] [added: (2,063] | | ) | | [removed: (229] [added: (50] | | ) |

| Income (Loss) Before Income Taxes | [removed: (1,130] [added: 686] | | [removed: )] | | [removed: 885] [added: (1,130] | | [added: )] | | [removed: 781] [added: 885] | | |

| Income tax expense (benefit) | [removed: (438] [added: 254] | | [removed: )] | | [removed: 274] [added: (438] | | [added: )] | | [removed: 470] [added: 274] | | |

| Net Income (Loss) | $ | [removed: (692] [added: 432] | [removed: )] | | $ | [removed: 611] [added: (692] | [added: )] | | $ | [removed: 311] [added: 611] | |

| Basic Earnings (Loss) Per Share | $ | [removed: (1.61] [added: 1.00] | [removed: )] | | $ | [removed: 1.42] [added: (1.61] | [added: )] | | $ | [removed: 0.73] [added: 1.42] | |

| Diluted Earnings (Loss) Per Share | $ | [removed: (1.61] [added: 1.00] | [removed: )] | | $ | [removed: 1.42] [added: (1.61] | [added: )] | | $ | [removed: 0.72] [added: 1.42] | |

| Weighted Average Shares Outstanding, Basic | [removed: 430] [added: 431] | | | | 430 | | | | [removed: 428] [added: 430] | | |

| Weighted Average Shares Outstanding, Diluted | [removed: 430] [added: 434] | | | | [removed: 432] [added: 430] | | | | [removed: 431] [added: 432] | | |

| | [removed: (in millions)] | | [removed: | |] [added: (in millions)] | | | | | | |

| Other comprehensive [removed: income:] [added: income (loss):] | | | | | | | | | | | |

| Adjustment to pension and other postretirement plans (net of tax of [removed: $12, $5] [added: $4, $12] and [removed: $25,] [added: $5,] respectively) | [removed: 20] [added: (7] | | [added: )] | | [removed: 3] [added: 20] | | | | [removed: 44] [added: 3] | | |

| Reclassification of deferred loss from cash flow hedges realized in net income (net of [removed: tax)] [added: tax of $1, $-0-, and $-0-, respectively)] | [removed: —] [added: 1] | | | | [removed: 1] [added: —] | | | | 1 | | |

| Other comprehensive income [added: (loss)] | [removed: 20] [added: (5] | | [added: )] | | [removed: 4] [added: 20] | | | | [removed: 45] [added: 4] | | |

| Comprehensive income (loss) | $ | [removed: (672] [added: 427] | [removed: )] | | $ | [removed: 615] [added: (672] | [added: )] | | $ | [removed: 356] [added: 615] | |

| | December 31, [removed: 2015] [added: 2016] | | | | December 31, [removed: 2014] [added: 2015] | | |

| Cash and cash equivalents [removed: ($264] [added: ($340] and [removed: $290] [added: $264] related to VIEs, respectively) | $ | [removed: 264] [added: 341] | | | $ | [removed: 298] [added: 264] | |

| Investment in marketable securities | [removed: 805] [added: 953] | | | | [removed: 930] [added: 805] | | |

| Accounts receivable [removed: ($64] [added: ($52] and [removed: $58] [added: $64] related to VIEs, respectively), less bad debt reserve of [removed: $20] [added: $15] and [removed: $26,] [added: $20,] respectively | [removed: 593] [added: 740] | | | | [removed: 837] [added: 593] | | |

| Accrued unbilled revenues | [removed: 279] [added: 335] | | | | [removed: 357] [added: 279] | | |

| Non-trading derivative assets | [removed: 89] [added: 51] | | | | [removed: 99] [added: 89] | | |

| Taxes receivable | [removed: 172] [added: 30] | | | | [removed: 190] [added: 172] | | |

| Prepaid expense and other current assets [removed: ($35] [added: ($40] and [removed: $47] [added: $35] related to VIEs, respectively) | [removed: 140] [added: 161] | | | | [removed: 178] [added: 140] | | |

| Total current assets | [removed: 2,689] [added: 2,923] | | | | [removed: 3,268] [added: 2,689] | | |

| Property, Plant and Equipment, net | [removed: 11,537] [added: 12,307] | | | | [removed: 10,502] [added: 11,537] | | |

| Goodwill | [removed: 840] [added: 862] | | | | 840 | | |

| Revenues: | | | | | | | | | | | |

| Utility revenues | $ | 5,440 | | | $ | 5,448 | | | $ | 6,116 | |

| Non-utility revenues | 2,088 | | | | 1,938 | | | | 3,110 | | |

| Utility natural gas | 983 | | | | 1,264 | | | | 1,878 | | |

| Non-utility natural gas | 1,983 | | | | 1,838 | | | | 3,043 | | |

| Net deferred gain from cash flow hedges (net of tax of $-0-, $-0-, and $-0-, respectively) | 1 | | | | — | | | | — | | |

| Preferred units - unconsolidated affiliate | 363 | | | | — | | |

| Other | 173 | | | | 102 | | |

| Total Assets | $ | 21,829 | | | $ | 21,290 | |

CONSOLIDATED BALANCE SHEETS, cont.

| | (in millions, except par value and shares) | | | | | | |

| Indexed debt | 114 | | | | 145 | | |

| Other | 325 | | | | 343 | | |

| VIE Securitization Bonds, net | 1,867 | | | | 2,276 | | |

| Shareholders’ Equity: | | | | | | | |

| Common stock, $0.01 par value, 1,000,000,000 shares authorized, 430,682,504 shares and 430,262,703 shares outstanding, respectively | 4 | | | | 4 | | |

| Additional paid-in capital | 4,195 | | | | 4,180 | | |

| Accumulated deficit | (668 | | ) | | (657 | | ) |

| Accumulated other comprehensive loss | (71 | | ) | | (66 | | ) |

| Net income (loss) | $ | 432 | | | $ | (692 | ) | | $ | 611 | |

| Depreciation and amortization | 1,126 | | | | 970 | | | | 1,013 | | |

| Acquisitions, net of cash acquired | (102 | | ) | | — | | | | — | | |

| Decrease in notes receivable - unconsolidated affiliate | 363 | | | | — | | | | — | | |

| Investment in preferred units - unconsolidated affiliate | (363 | | ) | | — | | | | — | | |

| Loss on reacquired debt | (22 | | ) | | — | | | | — | | |

| Distribution to ZENS holders | (178 | | ) | | (32 | | ) | | — | | |

| Net income (loss) | | | | 432 | | | | | | | (692 | | ) | | | | | 611 | | |

See Notes to Consolidated Financial Statements

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

| • | 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. |

As of December 31, 2016, CenterPoint Energy also owned an aggregate of 14,520,000 Series A Preferred Units in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets, and CERC Corp. owned approximately 54.1% of the limited partner interests in Enable.

CenterPoint Energy had current regulatory assets of $70 million and $21 million as of December 31, 2016 and 2015, respectively, included in other current assets in its Consolidated Balance Sheets.

CenterPoint Energy had current regulatory liabilities of $18 million and $57 million as of December 31, 2016 and 2015, respectively, included in other current liabilities in its Consolidated Balance Sheets.

(g) Capitalization of Interest and AFUDC

Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates.

CenterPoint Energy reports the income tax provision associated with its interest in Enable in Income tax expense (benefit) in its Statements of Consolidated Income.

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07).

ASU 2015-07 removes the requirement to categorize within the fair value hierarchy investments for which fair values are measured at NAV using the practical expedient.

Entities will be required to disclose the fair value of investments measured using the NAV practical expedient so that financial statement users can reconcile amounts reported in the fair value hierarchy table to amounts reported on the balance sheet.

February 26, 2016

| | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Revenues | $ | 7,386 | | | $ | 9,226 | | | $ | 8,106 | |

| Natural gas | 3,102 | | | | 4,921 | | | | 3,908 | | |

| Inventory | 347 | | | | 379 | | |

| Other | 146 | | | | 147 | | |

| Total Assets | $ | 21,334 | | | $ | 23,200 | |

| VIE transition and system restoration bonds | 2,283 | | | | 2,674 | | |

| Cash contribution to Enable | — | | | | — | | | | (38 | | ) |

| Long-term revolving credit facility | 200 | | | | — | | | | — | | |

| Cash paid for debt exchange and debt retirement | — | | | | (1 | | ) | | (7 | | ) |

| Proceeds from issuance of common stock, net | — | | | | 1 | | | | 4 | | |

| Formation of Enable | — | | | | — | | | | 4,252 | | |

| • | CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems (NGD). A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. As of December 31, 2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets. |

As of December 31, 2015, CERC Corp. and OGE also own 40% and 60%, respectively, of the incentive distribution rights held by the general partner of Enable.

(g) Capitalization of Interest and Allowance for Funds Used During Construction

CenterPoint Energy recognizes interest and penalties as a component of income tax expense.

| | December 31, | | | | | | |

| Total inventory | $ | 347 | | | $ | 379 | |

In April 2015, the FASB issued Accounting Standards Update No. 2015-05, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40) (ASU 2015-05).

ASU 2015-05 provides guidance to customers about whether a cloud computing arrangement includes a software license.

If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses.

If a cloud

computing arrangement does not include a software license, the customer should account for the arrangement as a service contract.

The guidance will not change a customer’s accounting for service contracts.

CenterPoint Energy will adopt ASU 2015-05 prospectively on January 1, 2016.

In August 2015, the FASB issued Accounting Standard Update No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which delays the effective date of ASU 2014-09 by one year.

ASU 2015-11 changes the subsequent measurement guidance for inventory accounted for using methods other than the last in, first out (LIFO) and Retail Inventory methods.

Companies will subsequently measure inventory at the lower of cost and net realizable value.

Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.

Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method.

In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17).

ASU 2015-17 requires deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position.

CenterPoint Energy adopted ASU 2015-17 retrospectively starting with fiscal year 2015.

As such, certain prior period amounts have been classified to conform to the current presentation.

In the Consolidated Balance Sheet as of December 31, 2014, CenterPoint Energy reclassified $683 million from current deferred income tax liabilities to increase deferred income taxes within non-current liabilities.

| | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

(c) Asset Retirement Obligations

Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, [removed: 2015] [added: 2016] to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, [removed: 2015] [added: 2016] that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the [removed: Treadway Commission.]

Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management has concluded that our internal control over financial reporting was effective as of December 31, [removed: 2015.][added: 2016.]

Deloitte & Touche LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, [removed: 2015] [added: 2016] which is set forth below.

We have audited the internal control over financial reporting of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, [removed: 2015,] [added: 2016,] based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2015,] [added: 2016,] based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements [removed: and financial statement schedules] as of and for the year ended December 31, [removed: 2015] [added: 2016] of the Company and our report dated February [removed: 26, 2016] [added: 28, 2017] expressed an unqualified opinion on those financial statements.

Treadway Commission.

February 28, 2017

February 26, 2016

None.

Amendment to Bylaws

Effective February 25, 2016, the Board of Directors of CenterPoint Energy, Inc. (the Board) amended and restated its bylaws (the Bylaws).

The Bylaws include, among other things, the following changes:

- Provide the Board with explicit authority to cancel, postpone or reschedule a shareholder meeting.

- Provide the chairman of the meeting with explicit authority to adjourn or recess a shareholder meeting.

- Allow shareholder meetings to proceed by means of remote communication.

- Clarify the powers of the chairman of the meeting to conduct a shareholder meeting.

- Provide for additional disclosure requirements for notices of director nominations and shareholder proposals.

- Provide an explicit confidentiality obligation for directors.

The foregoing description of the terms of the Bylaws does not purport to be complete and is subject to, and qualified in its entirety by, reference to the complete text of the Bylaws, a copy of which is filed as Exhibit 3(b) to this Annual Report on Form 10-K and incorporated by reference herein.

Amendments to Forms of Award Agreements under Long Term Incentive Plan

On February 25, 2016, the Compensation Committee of the Board approved revisions to the forms of award agreements for qualified performance awards and restricted stock unit awards with service-based vesting under CenterPoint Energy’s long-term incentive plan.

The revised forms provide for pro rata vesting upon retirement for a “retirement eligible” participant (age 55 or greater with at least five years of service) and remove the requirement that such a participant be employed for at least the first six months of the calendar year in which the award is granted to qualify for such pro rata vesting.

The revised form of award agreement for executive chairman restricted stock unit awards with service-based vesting also provides for pro rata vesting upon termination without cause and removes the requirement that the executive chairman be employed for at least the first six months of the calendar year in which the award is granted to qualify for such pro rata vesting.

The foregoing description of the forms of award agreements does not purport to be complete and is subject to, and qualified in its entirety by, reference to the complete text of the following forms of agreements for qualified performance awards, qualified performance awards for the executive chairman, restricted stock unit awards with service-based vesting and executive chairman restricted stock unit awards with service-based vesting, copies of which are filed as Exhibits 10(ll)(2), 10(ll)(3), 10(ll)(5) and 10(ll)(7), respectively, to this Annual Report on Form 10-K and are incorporated by reference herein.

The information called for by Item 10, to the extent not set forth in “Executive Officers” in Item 1, will be set forth in the definitive proxy statement relating to CenterPoint Energy’s [removed: 2016] [added: 2017] annual meeting of shareholders pursuant to SEC Regulation 14A.

The information called for by Item 11 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s [removed: 2016] [added: 2017] annual meeting of shareholders pursuant to SEC Regulation 14A.

The information called for by Item 12 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s [removed: 2016] [added: 2017] annual meeting of shareholders pursuant to SEC Regulation 14A.

The information called for by Item 13 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s [removed: 2016] [added: 2017] annual meeting of shareholders pursuant to SEC Regulation 14A.

The information called for by Item 14 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s [removed: 2016] [added: 2017] annual meeting of shareholders pursuant to SEC Regulation 14A.

| Report of Independent Registered Public Accounting Firm | [removed: [75](#s36A5D5F3B0105070A62D96F7B39CE1C2)] [added: [70](#s980AD0DA03F65CDB95285BA77A665AD1)] |

| Statements of Consolidated Income for the Three Years Ended December 31, [removed: 2015] [added: 2016] | [removed: [76](#s9E40195702E05B13B8754DB8DB22BCF6)] [added: [71](#s5344AE52A7BB52A1A31D483BFA055AB7)] |

| Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, [removed: 2015] [added: 2016] | [removed: [77](#sB6B58A3F17F4588B91A7FFC81CC559EF)] [added: [72](#s27609E842D5658D0AD0E6711BB695E9D)] |

| Consolidated Balance Sheets as of December 31, [removed: 2015] [added: 2016] and [removed: 2014] [added: 2015] | [removed: [78](#sDEA5E6B5A2D25427A869A38B481DA426)] [added: [73](#s9FC52F3C319D5A71897506E152282BC7)] |

| Statements of Consolidated Cash Flows for the Three Years Ended December 31, [removed: 2015] [added: 2016] | [removed: [79](#s4363D1E14CF55FE6B821FCB50F40A340)] [added: [75](#sD8B707CFF50F5DFBB902F090D1155DAB)] |

| Statements of Consolidated Shareholders’ Equity for the Three Years Ended December 31, [removed: 2015] [added: 2016] | [removed: [81](#sA44DE1A4AB0B574C9A72C846AE89D882)] [added: [77](#s2311B35955275BF291E4DE1CB9AD4F0E)] |

| Notes to Consolidated Financial Statements | [removed: [82](#sE0A7B668BD48515A884C6BFDD44E5883)] [added: [78](#s98AB194E17545F729F6482DBF8BEB205)] |

(a)(2) Financial Statement Schedules for the Three Years Ended December 31, [removed: 2015][added: 2016.]

[added: I, II,] III, IV and V.

See Index of Exhibits beginning on page [removed: 135,] [added: 125,] which index also includes the management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

[removed: | |] For [removed: the] [added: Fiscal] Year Ended December 31, [removed: | | | | | | | | | | |][added: 2016]

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on the [removed: 26th] [added: 28th] day of February, [removed: 2016.][added: 2017.]

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February [removed: 26, 2016.][added: 28, 2017.]

| [removed: †3(b)] [added: 3(b)] | — | [removed: Second] [added: Third] Amended and Restated Bylaws of CenterPoint Energy | | [added: CenterPoint Energy’s Form 8-K dated February 21, 2017] | | [added: 1-31447] | | [added: 3.1] |

| 4(e)(1) | — | General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10-Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(1) |

| 4(e)(2) | — | Second Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10- Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(3) |

| 4(e)(3) | — | Third Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10-Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(4) |

| 4(e)(4) | — | Fourth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10- Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(5) |

| 4(e)(5) | — | Fifth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10-Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(6) |

| 4(e)(6) | — | Sixth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10-Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(7) |

| 4(e)(7) | — | Seventh Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10-Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(8) |

| 4(e)(8) | — | Eighth Supplemental Indenture to Exhibit 4(e)(1), dated as of October 10, 2002 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 10-Q for the quarter ended September 30, 2002 | | 1-3187 | | 4(j)(9) |

| 4(e)(30) | — | Twentieth Supplemental Indenture to Exhibit 4(e)(1), dated as of December 9, 2008 | | [removed: CenterPoint Houston’s] [added: Houston Electric’s] Form 8-K dated January 6, 2009 | | 1-3187 | | 4.2 |

| 4(e)(35) | — | Twenty-Third Supplemental Indenture, dated as of March 17, 2014, to the General Mortgage Indenture, dated as of October 10, 2002, between [removed: CenterPoint] Houston [added: Electric] and the Trustee | | CenterPoint Energy’s Form 10-Q for the quarter ended March 31, 2014 | | 1-31447 | | 4.10 |

| 4(i)(1) | — | [removed: $1,200,000,000] [added: $1,600,000,000] Credit Agreement dated as of [removed: September 9, 2011,] [added: March 3, 2016,] among CenterPoint Energy, as Borrower, and the banks named therein | | CenterPoint Energy’s Form 8-K dated [removed: September 9, 2011] [added: March 3, 2016] | | 1-31447 | | 4.1 |

| [removed: 4(i)(2)] [added: 4(j)(1)] | — | [removed: First Amendment to] [added: $300,000,000] Credit [removed: Agreement,] [added: Agreement] dated as of [removed: April 11, 2013,] [added: March 3, 2016,] among [removed: CenterPoint Energy,] [added: Houston Electric,] as Borrower, and the banks named therein | | CenterPoint Energy’s Form 8-K dated [removed: April 11, 2013] [added: March 3, 2016] | | 1-31447 | | [removed: 4.1] [added: 4.2] |

| [removed: 4(i)(3)] [added: 4(k)] | — | [removed: Second Amendment to] [added: $600,000,000] Credit [removed: Agreement,] [added: Agreement] dated as of [removed: September 9, 2013,] [added: March 3, 2016,] among [removed: CenterPoint Energy,] [added: CERC Corp.,] as Borrower, and the banks named therein | | CenterPoint Energy’s Form 8-K dated [removed: September 9, 2013] [added: March 3, 2016] | | 1-31447 | | [removed: 4.1] [added: 4.3] |

| [removed: *†10(ll)(2)] [added: *10(ll)(2)] | — | Form of Qualified Performance Award Agreement for 20XX — 20XX Performance Cycle under Exhibit 10(ll)(1) | | [added: CenterPoint Energy’s Form 10-K for the year ended December 31, 2015] | | [added: 1-31447] | | [added: 10(ll)(2)] |