Company reiterates 2017 EPS guidance of $1.25 – $1.33 Company targets upper end of 4-6% earnings growth range for 2018 Full Year 2016 Earnings Call February 28, 2017 Exhibit 99.2

Cautionary Statement This presentation and the oral statements made in connection herewith contain statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future operations, events, financial position, earnings, growth, costs, prospects, capital investments or performance or underlying assumptions (including future regulatory filings and recovery, liquidity, capital resources, balance sheet, cash flow, capital investments and management, financing costs, and rate base or customer growth) and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You should not place undue reliance on forward-looking statements. Actual results may differ materially from those expressed or implied by these statements. 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,” “target,” “will,” or other similar words. The absence of these words, however, does not mean that the statements are not forward-looking. Examples of forward-looking statements in this presentation include statements about our review of our ownership interest in Enable Midstream, our acquisition of the retail energy services business of Continuum and Atmos Energy Marketing, including statements about future financial performance, margin, number of customers and operating income and growth, guidance, including earnings and dividend growth, future financing plans and expectation for liquidity and capital resources and expenditures, average rate base, tax reform and rates and interest rates, among other statements. We have based our forward-looking statements on our management’s beliefs and assumptions based on information currently available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions, and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements include but are not limited to the timing and impact of future regulatory, legislative and IRS decisions, financial market conditions, future market conditions, economic and employment conditions, customer growth, Enable Midstream’s performance and ability to pay distributions, and other factors described in CenterPoint Energy, Inc.’s Form 10-K for the period ended December 31, 2016 under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Future Earnings” and in other filings with the SEC by CenterPoint Energy, which can be found at www.centerpointenergy.com on the Investor Relations page or on the SEC’s website at www.sec.gov. This presentation contains time sensitive information that is accurate as of the date hereof. Some of the information in this presentation is unaudited and may be subject to change. We undertake no obligation to update the information presented herein except as required by law. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the Investor Relations page of our website. In the future, we will continue to use these channels to distribute material information about the Company and to communicate important information about the Company, key personnel, corporate initiatives, regulatory updates and other matters. Information that we post on our website could be deemed material; therefore, we encourage investors, the media, our customers, business partners and others interested in our Company to review the information we post on our website. Use of Non-GAAP Financial Measures In addition to presenting its financial results in accordance with generally accepted accounting principles (GAAP), including presentation of net income and diluted earnings per share, CenterPoint Energy also provides guidance based on adjusted net income and adjusted diluted earnings per share, which are non-GAAP financial measures. Generally, a non-GAAP financial measure is a numerical measure of a company’s historical or future financial performance that excludes or includes amounts that are not normally excluded or included in the most directly comparable GAAP financial measure.  CenterPoint Energy’s adjusted net income and adjusted diluted earnings per share calculation excludes from net income and diluted earnings per share, respectively, the impact of ZENS and related securities, mark-to-market gains or losses resulting from the company’s Energy Services business and adjustments for impairment charges. A reconciliation of net income and diluted earnings per share to the basis used in providing 2016 guidance is provided in this presentation on slide 18. CenterPoint Energy is unable to present a quantitative reconciliation of forward-looking adjusted net income and adjusted diluted earnings per share because changes in the value of ZENS and related securities, mark-to-market gains or losses resulting from the company’s Energy Services business and impairment charges are not estimable.  Management evaluates the company’s financial performance in part based on adjusted net income and adjusted diluted earnings per share. We believe that presenting these non-GAAP financial measures enhances an investor’s understanding of CenterPoint Energy’s overall financial performance by providing them with an additional meaningful and relevant comparison of current and anticipated future results across periods. The adjustments made in these non-GAAP financial measures exclude items that Management believes do not most accurately reflect the company’s fundamental business performance. These excluded items are reflected in the reconciliation tables on slides 18, 33, 34 and 35 of this presentation.  CenterPoint Energy’s adjusted net income and adjusted diluted earnings per share non-GAAP financial measures should be considered as a supplement to, and not as a substitute for, or superior to, net income and diluted earnings per share, which respectively are the most directly comparable GAAP financial measures. These non-GAAP financial measures also may be different than non-GAAP financial measures used by other companies.

Earnings Call Highlights Earnings Summary & Outlook 2016 Highlights Enable Midstream Highlights Midstream Investments Ownership Review Update Scott Prochazka – President and CEO

2016 Guidance-Basis EPS Growth in Excess of 5% with Higher Growth Projected for 2017 (2) 2016 EPS 2015 - 2016 EPS on a Guidance (Non-GAAP) Basis + 2017 Guidance We anticipate 2017 EPS growth will be driven by: (1) As provided on Enable’s 4th quarter 2016 earnings call (2) Refer to slide 34 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures * 2017 Guidance of $1.25 - $1.33 assumes that earnings from Utility Operations and Midstream Investments will not both be at the top or bottom end of their respective ranges Utility rate relief and continued customer growth Increased contribution from CenterPoint Energy Services, partly attributable to recent acquisitions Increased earnings per Enable Midstream Partners’ forecast (1) $1.00 $1.10 $1.16 $1.25 – 1.33 *

Utility Operations Strong customer growth – over 90,000 new utility customers Total electric throughput up over 3% compared to 2015 Capital expenditures of ~$1.4 billion invested on behalf of our customers and total rate base growth of 5.4% Increased rate relief by $95 million Earned ROEs near authorized levels at both electric and gas utilities Held O&M growth under 2%, excluding items with revenue offsets and acquisitions Acquired the retail energy services business of Continuum and in early 2017 Atmos Energy Marketing (AEM), expanding the scale, geographic reach, and capabilities of Energy Services Midstream Investments Net income attributable to common and subordinated units and distributable cash flow above the midpoint of 2016 guidance from Enable Midstream 2016 Highlights

Highlights from Enable Midstream’s Earnings Call on Feb. 21, 2017 #1 in Processing Capacity Enable is well-positioned to benefit from operational leverage associated with leading processing capacity investments Recent Commercial Success Benefits Increase Fee-based Margin P Reduce Commodity Exposure P Extend Average Contract Life P Support Continued Capital Deployment P Gathering and Processing Signed a new 10-year, fee-based G&P contract in the STACK play that replaces a contract with a percent-of-proceeds (POP) processing arrangement Transportation and Storage Signed a new 20-year, 228,000 dekatherm per day (Dth/d) intrastate firm service agreement Extended a 126,000 Dth/d interstate firm service agreement for 4 additional years Extended a 305,000 Dth/d intrastate firm service agreement for 1 additional year Recent Commercial Activity Market-Leading SCOOP/STACK Processing Capacity(2) Source: Enable Midstream Partners, February 21, 2017, Press Release and Q4 Earnings Call. Please refer to these materials for an overview of Enable’s Q4 and full year 2016 performance (1) Contractually dedicated rigs to Enable per Enable’s quarterly earnings press releases (2) Per Bentek as of February 1, 2017; represents processing capacity in designated SCOOP and STACK counties Q4-15 Q1-16 Q2-16 Q3-16 Q4-16 Rig Activity Remains Strong Dedicated Rig Count (1)

Midstream Investments Ownership Review Update Criteria for Consideration of a Sale or Spin – sustainable value for our long-term shareholders Comparable earnings per share and dividends Improve visibility of future earnings Seek to maintain current credit ratings Ongoing Activities Evaluating OGE’s ROFO offer for sale option Continuing discussions with third parties for sale option Working to understand tax characteristics and market implications of a spin, including understanding tax leakage

Earnings Call Highlights Operating Income Drivers Capital Investment Outlook Rate Base Outlook Tracy Bridge – EVP & President, Houston Electric

2% YoY Customer Growth (1) (2) (4) (5) (3) Electric Transmission and Distribution Operating Income Drivers 2015 vs 2016 (1) Houston Electric’s customer count increased by 54,823 from 2,348,517 as of December 31, 2015 to 2,403,340 as of December 31, 2016 (2) 2015 TDU core operating income represents total segment operating income of $607 million, excluding operating income from transition and system restoration bonds of $105 million (3) Includes higher DCRF revenues of $13 million and higher net transmission-related revenues of $27 million (4) Includes higher equity return of $17 million, primarily due to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months primarily offset by higher O&M expenses of $3 million and lower right-of-way revenues of $3 million (5) 2016 TDU core operating income represents total segment operating income of $628 million, excluding operating income from transition and system restoration bonds of $91 million $502 $537

2016A 2017E 2018E 2019E 2020E 2021E Transmission 48% 50% 45% 47% 40% 31% Distribution 49% 46% 50% 49% 56% 64% Electric Transmission and Distribution Capital Investment Outlook $4.1 Billion 2017 – 2021 Capital Plan (1) Includes AFUDC (2) Capital expenditures related to the Brazos Valley Connection include $72 million in 2016 and an estimated $192 million and $39 million in 2017 and 2018, respectively (2) (2) (2) (1)

Electric Transmission and Distribution $6.2 Billion Projected 2021 Average Rate Base Capital Structure: 45% equity / 55% debt Rate Base Growth: 5.0% CAGR 2016-2021 Note: The estimated average annual rate base is subject to change due to actual capital investment, effects of bonus depreciation, deferred taxes, and actual rate base authorized.

Earnings Call Highlights Natural Gas Distribution Operating Income Drivers Capital Investment Outlook Rate Base Outlook Energy Services Results & Outlook Joe McGoldrick – EVP & President, Gas Division

1% YoY Customer Growth (1) (3) Natural Gas Distribution Operating Income Drivers 2015 vs 2016 (1) Natural Gas Distribution’s customer count increased by 35,578 from 3,403,766 as of December 31, 2015 to 3,439,344 as of December 31, 2016 (2) Rate increases of $55 million, primarily from the 2015 Minnesota rate case, including the decoupling rider, and the Texas GRIP filings (3) Includes customer growth of $5 million and an increase of $26 million from weather normalization adjustments, including decoupling and hedging activities, partially offset by $19 million of milder weather effects (4) Includes higher labor and benefits expense of $11 million primarily driven by increased pension costs, increased contract services expenses of $10 million primarily for pipeline integrity, leak surveying and repair activities, and increased other O&M expenses of $8 million related to higher support services costs and other miscellaneous expenses partially offset by lower bad debt expense of $12 million resulting from lower customer bills due to warmer than normal weather and credit and collections process improvements that have reduced write-offs (4) (2)

Capital Recovery Method 2016A 2017E 2018E 2019E 2020E 2021E Annual Mechanisms 27% 57% 63% 57% 63% 63% Rate Cases 73% 43% 37% 43% 37% 37% Natural Gas Distribution Capital Investment Outlook $2.7 Billion 2017 – 2021 Capital Plan (1) Includes AFUDC (1)

Natural Gas Distribution $3.7 Billion Projected 2021 Average Rate Base Rate Base Growth: 6.6% CAGR 2016-2021 Rate Base Capital Structure: 50.9% equity / 49.1% debt Note: The estimated average annual rate base is subject to change due to actual capital investment, effects of bonus depreciation, deferred taxes, and actual rate base authorized.

Energy Services Results and Outlook 2016 Operating Income Operating income was $41 million in 2016 compared to $38 million last year, excluding a mark-to-market loss of $21 million and a gain of $4 million, respectively 2017 Outlook Energy Services projected to contribute $45 – $55 million in operating income Acquisition of Continuum’s retail energy services business expected to be accretive to earnings Recent AEM acquisition expected to be modestly accretive to earnings Customer count does not include natural gas customers that are under residential and small commercial choice programs invoiced by their host utility. - 200 400 600 800 1,000 1,200 1,400 - 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2013 2014 2015 2016 2017E Billion Cubic Feet (Bcf) Number of Customers Number of customers at year end Throughput (in Bcf)

Bill Rogers – EVP & CFO Earnings Call Highlights 2016 Earnings Drivers Liquidity & Capital Resources 2017 Guidance Outlook Tax Discussion

Reconciliation: Diluted EPS to Adjusted Diluted EPS Used in Providing Annual Earnings Guidance Q4 2016 Q4 2015 FY 2016 FY 2015 Diluted EPS as reported $0.23 $(1.18) $1.00 $(1.61) Loss on impairment of Midstream Investments - $1.44 - $2.69 Timing effects impacting CES $0.01 - $0.03 $(0.01) ZENS-related mark-to-market losses $0.02 $0.01 $0.13 $0.03 Consolidated EPS on a guidance basis $0.26 $0.27 $1.16 $1.10 Note: Refer to slide 34 and 35 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures

Utility Operations Adjusted Diluted EPS Drivers 2015 vs 2016 (Guidance Basis) (1) Excludes equity return; please refer to slide 33 for more detail on core operating income (2) The Equity Amortization schedule on page 38 details the increase between the 2015 and 2016 equity returns (3) 2016 income from investment in Enable Midstream series A preferred units of $22 million (4) Interest expense reductions of $14 million; excludes transition and system restoration bonds (5) 4th quarter 2016 charge of $22 million for early redemption of bonds otherwise due in 2018 (6) Taxes, AFUDC, other income, and Other Operations segment Note: Refer to slide 2 for information on non-GAAP measures (1) (2) (3) (4) (5) (6)

Consolidated Adjusted Diluted EPS Drivers 2015 vs 2016 (Guidance Basis) (1) See previous slide (2) Increased to $48 million in 2016 versus $8 million in 2015. Basis difference is being amortized over approximately 33 years. (3) Includes impact of Louisiana state tax law change; uses an average 2016 ownership of 55.3% (4) Fair value adjustments for commodity derivatives provided a $0.04 benefit in 2015 and reduced earnings by $0.03 in 2016; uses an average 2016 ownership of 55.3% (5) Midstream Investments components adjusted for the effective tax rate Note: Refer to slide 2 for information on non-GAAP measures (2) Utility Operations Midstream Investments (3) (4) $1.10 $1.16 Midstream Investments Impact (5) Midstream Investments Utility Operations (1)

2016 Adjusted FFO/Total Debt – 24% (1) Equity / Total Capital – 36% (1) Interest expense savings of $14 million with over $600 million of 6% plus debt retired in 2016 (1) 2017 Planned capital investment of approximately $1.5 billion Net incremental borrowings anticipated of $200 - $500 million; dependent on factors including bonus depreciation, capital investment plans and working capital Equity issuance not anticipated Anticipate competitive dividend growth of 4% Guidance EPS growth of 8% to 15% projected to reduce the 2017 payout ratio to be in the range of 80% to 86% (from $1.07 / $1.33 to $1.07 / $1.25) Liquidity and Capital Resources (1) Excludes transition and system restoration bonds Note: Refer to slides 36 and 37 for Adjusted FFO/Total Debt calculation and slide 2 for information on non-GAAP measures

2017 Guidance Outlook Reiterate 2017 full-year guidance of $1.25 - $1.33 per diluted share $0.93 - $0.97 expected from utility operations $0.31 - $0.37 expected from midstream investments 2017 earnings growth expected to be driven by: Utility growth primarily driven by rate relief and continued customer additions Increased contribution from Energy Services 2017 operating income estimate of $45 to $55 million Full year of income from investment in Enable’s preferred units Estimated net income increase of approximately $9 million Increased earnings per Enable Midstream Partners’ forecast Enable forecasted 2017 net income attributable to common and subordinated units of $315 to $385 million Lower interest expense Estimated net income improvement of $10 to $20 million Lower tax rate 37% 2016 effective tax rate versus 36% anticipated 2017 effective tax rate Note: Refer to slide 2 for information on non-GAAP measures

Tax Discussion

CenterPoint’s Current Tax Position Effective Tax Rates CenterPoint’s 2016 Effective Tax Rate was 37% (projected rate of 36% plus the income tax expense recognized due to the Louisiana state tax law change) Cash Tax Rates CenterPoint’s 2016 cash tax rate was approximately 4% All remaining federal tax carry forwards (NOLs, etc.) were utilized as of Dec. 31, 2016 Lower than the statutory rate primarily due to 50% bonus depreciation and taxable loss allocated from Enable Midstream Investment Impact Taxable income or loss at the Enable level is based on their operations and tax elections at the partnership level CenterPoint reports taxable income or loss on the consolidated tax return based on the Schedule K-1 that is received from Enable

CenterPoint’s Deferred Tax Liability CenterPoint has a net deferred tax liability of $5.3 billion as of Dec. 31, 2016 which would be reduced if a lower federal income tax rate is enacted December 31, 2016 ($ in millions) Utility Related (1) Non-Utility Related Total Deferred Tax Assets Benefits and compensation $82 $234 $316 Loss and credit carryforwards $79 $79 Assets retirement obligations $76 $1 $77 Other $5 $16 $21 Valuation allowance   ($5) ($5) Total deferred tax assets $163 $325 $488 Deferred Tax Liabilities Property, plant, and equipment $2,545 $58 $2,603 Investment in unconsolidated affiliates $1,383 $1,383 Securitization $683 $683 Regulatory assets/liabilities, net ($65) $265 $200 Investment in marketable securities and indexed debt $772 $772 Indexed debt securities derivative $4 $4 Other $1 $105 $106 Total deferred tax liabilities $2,481 $3,270 $5,751 Net Deferred Tax Liabilities $2,318 $2,945 $5,263 Any reduction in regulated balances would be subject to regulatory review and likely get re-characterized as a regulatory liability and amortized to customers over time Any reduction in unregulated balances would likely be recognized as an income tax benefit on the income statement or through other comprehensive income increasing owner’s equity in the period of enactment (1) The “Utility Related” net deferred tax liabilities is largely comprised of regulated balances, but also includes amounts that are not incorporated in the setting of rates

Potential Tax Reform Implications Using only the following assumptions (and assuming the current business segments) (1) Lower corporate tax rate of 20% 100% expensing of capital investments Permanent disallowance of interest deductibility CenterPoint should have the following impacts Accretive to EPS Reduced future cash tax rates and effective tax rates A stronger balance sheet as a result of unregulated deferred tax reductions (1) These assumptions are not comprehensive and do not address other potential tax reforms being contemplated, including but not limited to, taxation of partnership interests, transition rules for regulated utilities and cross-border adjustability.  The impacts described above do not consider the effects of these other potential tax reform proposals or the specific implications to regulated utilities such as the re-characterization of deferred tax liability to a regulatory liability, amortized to customers over time.

Appendix

Consolidated Capital Investment Outlook (1) Includes AFUDC (1) (1) $7.0 Billion 2017 – 2021 Consolidated Capital Plan

DCRF – Distribution Cost Recovery Factor; TCOS – Transmission Cost of Service; EECRF – Energy Efficiency Cost Recovery Factor (1) Represents the new DCRF charge, not a year over year increase (2) Amounts are recorded when approved (3) Effective dates or approval dates not yet available and approved rates could differ materially Electric Transmission and Distribution 2016 Regulatory Update Mechanism Docket # Annual Increase ($ in millions) Filing Date Effective Date Approval Date Additional Information DCRF (1) 45747 $45.0 April 2016 September 2016 July 2016 Based on an increase in eligible distribution-invested capital from January 1, 2010 through December 31, 2015 of $689 million. Unless otherwise changed in a subsequent DCRF filing, an annualized DCRF charge of $49 million will be effective September 2017. TCOS 46230 $3.5 July 2016 September 2016 September 2016 Based on an incremental increase in total rate base of $95.6 million. EECRF (2) 46014 $10.6 June 2016 March 2017 October 2016 Recovers $45.5 million, including an incentive of $10.6 million based on 2015 program performance. TCOS 46703 $7.8 December 2016 (3) (3) Based on an incremental increase in total rate base of $109.6 million. Approval is expected in Q1 2017.

Natural Gas Distribution 2016 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase ($ in millions) Filing Date Effective Date Approval Date Additional Information Houston, South Texas, Beaumont/East Texas, Texas Coast (Railroad Commission) GRIP 10508, 10509, 10510, 10511 $18.2 March 2016 July 2016 July 2016 Based on net change in invested capital of $115.5 million. Houston and Texas Coast (1) (Railroad Commission) Rate Case 10567 $31.0 November 2016 (2) (2) Based on rate base of $669 million and a 10.25% ROE on a 55.1% equity ratio. Final order is expected in Q2 2017. Arkansas (APSC) Rate Case 15-098-U $14.2 November 2015 September 2016 September 2016 Based on an ROE of 9.5%. Also approved an FRP. Arkansas (APSC) EECR (3) 07-081-TF $0.5 August 2016 January 2017 (2) Recovers $11.0 million, including an incentive of $0.5 million based on 2015 program performance. Mississippi (MPSC) RRA 12-UN-139 $2.7 July 2016 October 2016 October 2016 Based on ROE of 9.47%. Oklahoma (OCC) EECR (3) PUD201600094 $0.4 March 2016 July 2016 July 2016 Recovers $2.4 million, including an incentive of $0.4 million based on 2015 program performance. GRIP – Gas Reliability Infrastructure Program; FRP – Formula Rate Plan; EECR – Energy Efficiency Cost Recovery; RRA – Rate Regulation Adjustment (1) In addition to requesting the change in rates, Natural Gas Distribution proposed consolidation of the Houston and Texas Coast divisions into a Texas Gulf division (2) Effective dates or approval dates not yet available and approved rates could differ materially (3) Amounts are recorded when approved

Natural Gas Distribution 2016 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase ($ in millions) Filing Date Effective Date Approval Date Additional Information Minnesota (MPUC) Rate Case 15-424 $27.5 August 2015 December 2016 June 2016 Interim increase of $47.8 million effective in October 2015. Final rates based on an ROE of 9.49% and interim rate refund implemented in December 2016. Minnesota (MPUC) CIP (1) G008/ M-16-366 $12.7 May 2016 September 2016 September 2016 Based on 2015 results. Minnesota (MPUC) Decoupling (2) G008/ GR-13-316 $24.6 September 2016 September 2016 December 2016 Reflects revenue under recovery for the period July 1, 2015 through June 30, 2016. Louisiana (LPSC) RSP U-34251, U-34249 $1.3 September 2016 December 2016 (3) Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. Louisiana (LPSC) RSP U-33818, U-33817 $2.3 October 2015 December 2016 (3) Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. CIP – Conservation Improvement Program; RSP – Rate Stabilization Plan (1) Amounts are recorded when approved (2) The amount was recorded during the under recovery period (3) Effective dates or approval dates not yet available and approved rates could differ materially

Estimated Rate Filing Timelines as of December 31, 2016 Houston Electric (1) Natural Gas Distribution (1) (1) Rate filings and timelines are subject to change and may be impacted by factors such as regulatory, legislative and economic factors (2)

Reconciliation: Operating Income to Core Operating Income on a Guidance (Non-GAAP) Basis Note: Refer to slide 2 for information on non-GAAP measures

Note: Refer to slide 2 for information on non-GAAP measures Reconciliation: Net Income (Loss) and Diluted EPS to Adjusted Net Income and Adjusted Diluted EPS Used in Providing Annual Earnings Guidance

Note: Refer to slide 2 for information on non-GAAP measures Reconciliation: Net Income (Loss) and Diluted EPS to Adjusted Net Income and Adjusted Diluted EPS Used in Providing Annual Earnings Guidance

Adjusted Funds From Operations (FFO) ($ in millions) Year Ended December 31, 2016 Year Ended December 31, 2015 Amounts included in Cash Flows from Operating Activities: Net income (loss) $ 432 $ (692) Depreciation and amortization 1,126 970 Amortization of deferred financing costs 26 27 Deferred income taxes 213 (413) Unrealized loss (gain) on marketable securities (326) 93 Loss (gain) on indexed debt securities 413 (74) Write-down of natural gas inventory 1 4 Equity in (earnings) losses of unconsolidated affiliates, net of distributions (208) 1,779 Pension contributions (9) (66) Funds From Operations $ 1,668 $ 1,628 Amounts included in Cash Flows from Investing Activities: Distributions from unconsolidated affiliates in excess of cumulative earnings 297 148 Less: Amounts associated with Transition and System Restoration Bond Companies (456) (368) Adjusted Funds From Operations (FFO) $ 1,509 $ 1,408 This slide includes adjusted funds from operations (“FFO”) which is net cash provided by operating activities: excluding (I) changes in other assets and liabilities, (II) other, net and (III) amounts related to transition and system restoration bonds; and including distributions from unconsolidated affiliates in excess of cumulative earnings included in cash flow from investing activities

Ratio of Adjusted FFO/Total Debt Excluding Transition and System Restoration Bonds ($ in millions) December 31, 2016 December 31, 2015 Short-term Debt: Short-term borrowings $ 35 $ 40 Current portion of transition and system restoration bonds* 411 391 Indexed debt (ZENS)** 114 145 Current portion of other long-term debt 500 328 Long-term Debt: Transition and system restoration bonds* 1,867 2,276 Other 5,665 5,590 Total Debt $ 8,592 $ 8,770 Less: Transition and system restoration bonds (including current portion)* (2,278) (2,667) Total Debt, excluding transition and system restoration bonds $ 6,314 $ 6,103 Adjusted FFO/Total Debt, excluding transition and system restoration bonds 23.9% 23.1% * The transition and system restoration bonds are serviced with dedicated revenue streams, and the bonds are non-recourse to CenterPoint Energy and CenterPoint Energy Houston Electric. ** The debt component reflected on the financial statements was $114 million and $145 million, as of December 31, 2016 and December 31, 2015, respectively. The principal amount on which 2% interest is paid was $828 million on each of December 31, 2016 and December 31, 2015. The contingent principal amount was $514 million and $705 million as of December 31, 2016 and December 31, 2015, respectively. At maturity or upon redemption, holders of ZENS will receive cash at the higher of the contingent principal amount or the value of the reference shares of Time Warner Inc., Time Inc. and Charter Communications, Inc. This slide includes adjusted funds from operations (“FFO”) which is net cash provided by operating activities: •excluding (I) changes in other assets and liabilities, (II) other, net and (III) amounts related to transition and system restoration bonds; and •including distributions from unconsolidated affiliates in excess of cumulative earnings included in cash flow from investing activities

Estimated Amortization for Pre-Tax Equity Earnings Associated with the Recovery of Certain Qualified Cost and Storm Restoration Costs The table provides the pre-tax equity return recognized by CenterPoint Energy, Inc. (CenterPoint Energy) during each of the years 2005 through 2016 related to CenterPoint Energy Houston Electric, LLC’s (CEHE) recovery of certain qualified costs or storm restoration costs, as applicable, pursuant to the past issuance of transition bonds by CenterPoint Energy Transition Bond Company II, LLC (Transition BondCo II) and CenterPoint Energy Transition Bond Company III, LLC (Transition BondCo III) or CenterPoint Energy Transition Bond Company IV, LLC (Transition BondCo IV) or system restoration bonds by CenterPoint Energy Restoration Bond Company, LLC (System Restoration BondCo), as applicable and the estimated pre-tax equity return currently expected to be recognized in each of the years 2017 through 2024 related to CEHE’s recovery of certain qualified costs or storm restoration costs, as applicable, pursuant to the past issuance of transition bonds by Transition BondCo II, Transition BondCo III or Transition BondCo IV or system restoration bonds by System Restoration BondCo, as applicable. The amounts reflected for 2017 through 2024 are based on CenterPoint Energy’s estimates as of December 31, 2016. However, the equity returns to be recognized in future periods with respect to each series of transition or system restoration bonds, as applicable, will be periodically subject to adjustment based on tariff adjustments for any overcollections or undercollections of transition charges or system restoration charges, as applicable. The equity return amounts reflected in the table are reported in the financial statements of CenterPoint Energy and CenterPoint Energy Houston Electric as revenues from electric transmission and distribution utility. As of December 31, 2016