4th quarter 2018 earnings call February 28, 2019 Exhibit 99.2

Cautionary statement This presentation and the oral statements made in connection herewith contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this presentation and the oral statements made in connection herewith are forward-looking statements made in good faith by CenterPoint Energy, Inc. (“CenterPoint Energy” or the “Company”) and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995, including statements concerning CenterPoint Energy’s 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. 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 the acquisition of Vectren Corporation (the “Merger”) (including anticipated utility and non-utility cost savings related to the Merger and expected segments for Securities and Exchange Commission (“SEC”) reporting and investor reporting purposes), our growth and guidance (including earnings, rate base growth and customer growth expectations), capital resources and expenditures (including our anticipated five-year capital plans), our anticipated regulatory filings and projections (including the Bailey to Jones Creek project in Texas and the 50 megawatt solar facility and combined-cycle gas turbine generation facility in Indiana), the projected consolidated effective tax rate, expectations for equity issuances and estimated diluted common share count, 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 Partners, LP’s (“Enable”) performance and ability to pay distributions and other factors described in CenterPoint Energy’s Form 10-K for the year ended December 31, 2018 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 the Company, which can be found at www.centerpointenergy.com on the Investor Relations page or on the SEC’s website at www.sec.gov. A portion of slide 21 is derived from Enable’s investor presentation as presented during its Q4 and full-year 2018 earnings presentation dated February 19, 2019. The information in this slide is included for informational purposes only. The content has not been verified by us, and we assume no liability for the same. You should consider Enable’s investor materials in the context of its SEC filings and its entire investor presentation, which is available at http://investors.enablemidstream.com. This presentation contains time sensitive information that is accurate as of the date hereof (unless otherwise specified as accurate as of another date). 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.

Additional information Use of Non-GAAP Financial Measures In addition to presenting its financial results in accordance with generally accepted accounting principles (“GAAP”), including presentation of income available to common shareholders and diluted earnings per share, the Company also provides guidance based on adjusted income and adjusted diluted earnings per share used in providing earnings guidance, which are non-GAAP financial measures. Additional non-GAAP financial measures used by the Company include core operating income. 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. The Company’s adjusted income and adjusted diluted earnings per share used in providing earnings guidance calculation excludes from income available to common shareholders and diluted earnings per share, respectively, the impact of ZENS and related securities and mark-to-market gains or losses resulting from the Company’s Energy Services business. The Company’s guidance for 2019 does not reflect certain impacts associated with the Vectren Corporation merger, which are integration and transaction-related fees and expenses, including severance and other costs to achieve anticipated cost savings as a result of the merger and merger financing impacts in January, before the completion of the merger due to the issuance of debt and equity securities to fund the merger that resulted in higher net interest expense and higher common stock share count. The Company’s core operating income calculation excludes the transition and system restoration bonds from the Electric Transmission and Distribution business segment, the mark-to-market gains or losses resulting from the Company’s Energy Services business and income from the Other Operations business segment. A reconciliation of income available to common shareholders and diluted earnings per share to the basis used in providing guidance is provided in this presentation on slides 31–33. The Company is unable to present a quantitative reconciliation of forward-looking adjusted income and adjusted diluted earnings per share used in providing earnings guidance because changes in the value of ZENS and related securities and mark-to-market gains or losses resulting from the Company’s Energy Services business are not estimable as they are highly variable and difficult to predict due to various factors outside of management’s control. These excluded items, along with the excluded impacts associated with the merger, could have a material impact on GAAP-reported results for the applicable guidance period. Management evaluates the Company’s financial performance in part based on adjusted income, adjusted diluted earnings per share and core operating income. We believe that presenting these non-GAAP financial measures enhances an investor’s understanding of the Company’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 does not most accurately reflect the Company’s fundamental business performance. These excluded items are reflected in the reconciliation tables on slides 30–33. The Company’s adjusted income, adjusted diluted earnings per share and core operating income non-GAAP financial measures should be considered as a supplement to, and not as a substitute for, or superior to, income available to common shareholders, diluted earnings per share and operating income, 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. 2019 and 2020 Earnings Per Share Guidance Assumptions Both CenterPoint Energy’s 2019 and 2020 earnings per share guidance ranges consider operations performance to date and assumptions for certain significant variables that may impact earnings, such as customer growth (approximately 2% for electric operations and 1% for natural gas distribution) and usage including normal weather, throughput, commodity prices, recovery of capital invested through rate cases and other rate filings, effective tax rates, financing activities and related interest rates, and regulatory and judicial proceedings, as well as the volume of work contracted in our infrastructure services business. The ranges also consider anticipated cost savings as a result of the merger and the estimated cost and timing of technology integration projects. The 2019 guidance range assumes Enable Midstream Partners’ (Enable) 2019 guidance range for net income attributable to common units of $435–$505 million, provided on Enable’s Q4 and full-year 2018 earnings call on February 19, 2019. The 2020 guidance range utilizes a range of CenterPoint Energy’s scenarios for Enable’s 2020 net income attributable to common units. In providing this guidance, CenterPoint Energy uses a non-GAAP measure of adjusted diluted earnings per share that does not consider other potential impacts, such as changes in accounting standards or unusual items, including those from Enable, earnings or losses from the change in the value of the ZENS securities and the related stocks, or the timing effects of mark-to-market accounting in the Company’s Energy Services business, which, along with the certain excluded impacts associated with the merger, could have a material impact on GAAP reported results for the applicable guidance period. Refer to the information above in “Use of Non-GAAP Financial Measures” for reconciliation information.

Scott Prochazka President and CEO Full Year 2018 Performance 2018 Financial and Operational Highlights 2019 Key Regulatory Activities Electric Operations Capital Investment Outlook Natural Gas Distribution Capital Investment Outlook Rate Base Growth Outlook Guidance Basis EPS Outlook Bill Rogers Chief Financial Officer Business Segment Performance Utility Operations EPS Drivers Consolidated EPS Drivers 2019 and 2020 EPS Considerations Business Segment Review Appendix Regulatory Update Core Operating Income Reconciliation Income and EPS Reconciliation Credit Ratings and Outlook Equity Amortization Agenda

Full-Year 2018 Performance (1) Refer to slides 31-32 for reconciliation to GAAP measures and slide 3 for information on non-GAAP measures (2) Excluding ZENS, CES mark-to-market adjustments and, in 2018, impacts associated with the Vectren merger and, in 2017, $2.56 per share of deferred tax re-measurement associated with the TCJA (3) Primarily due to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months Note: In these slides, we will refer to public law number 115-97, initially introduced as the Tax Cuts and Jobs Act, as TCJA or simply “tax reform”. Additionally, we will refer to the accounting standard for compensation-retirement benefits as ASU 2017-07 2018 vs. 2017 Drivers(2) h Favorable Variance i Unfavorable Variance Rate Relief Income Tax Rate (TCJA) Midstream Investments Customer Growth Equity Return(3) O&M Depreciation and Amortization Non-TCJA income tax adjustments GAAP Diluted EPS Guidance Basis (Non-GAAP) Diluted EPS(1,2) Excluding gain from tax reform (2017) and impacts associated with the Vectren merger (2018) Full-year 2018 diluted EPS of $0.74, compared with diluted EPS of $4.13 in 2017, inclusive of $2.56 per share of deferred tax re-measurement benefit

2018 financial Highlights Delivered guidance-basis EPS, excluding impacts associated with the merger, of $1.60(1); finished at the top end of our guidance basis EPS range Invested nearly $1.6 billion in capital in our regulated utilities Increased regulated utilities’ incremental annual revenue through rate filings by $110 million, exclusive of tax reform impacts Increased the dividend by ~4% for the 5th year in a row Raised capital for merger: a mix of common stock, convertible preferred, preferred, senior notes and commercial paper Executed internal spin of our Midstream assets(2), improving CERC credit ratings Note: Please see slides 26-29 for full detail on regulatory filings (1) Refer to slide 31 for reconciliation to GAAP measures and slide 3 for information on non-GAAP measures (2) Excludes investment in Enable Series A Preferred Units

2018 Operational Highlights Added more than 77,000 new gas and electric utility customers Completed Brazos Valley Connection electric transmission line project Substantially completed cast iron replacements(1) Higher Energy Services core operating income(2) due to increased volumes and margins Assisted utilities in Puerto Rico, Florida and California in their recovery efforts (1) In 2019 cast iron replacement programs continue in Indiana and Ohio jurisdictions (2) Please see slide 30 for core operating income reconciliation and slide 3 for information on non-GAAP measures

2019 Key regulatory Activities Electric Operations Expect a ruling from the PUCT in late 2019 for the Bailey to Jones Creek 345kV transmission line(1) Anticipate filing Houston Electric general rate case on or before April 30th Expect final order from IURC in the first half of the year approving the 50 MW solar facility in Indiana Anticipate final order from IURC in the second half of the year for Indiana Electric’s combined-cycle gas turbine generation facility Natural Gas Distribution Expect final order from PUCO in the second or third quarter for the Ohio general rate case Intend to file general rate case in Minnesota in November Note: Please see slides 26-29 for full detail on regulatory filings PUCT – Texas Public Utility Commission; IURC – Indiana Utility Regulatory Commission; PUCO – Public Utilities Commission of Ohio (1) For more information on the Bailey to Jones Creek project, please visit: https://www.centerpointenergy.com/en-us/corporate/about-us/bailey-jones-creek

Electric Operations Capital Investment Outlook(1) (1) Includes AFUDC (2) Includes 11 months of capital for Indiana Electric $1,194 $1,304 $1,515 $1,457 $1,361 Houston Electric and Indiana Electric: $6.8 Billion Five Year Capital Plan (2)

(1) Includes AFUDC (2) Includes 11 months of capital for Indiana and Ohio Natural Gas Distribution Capital Investment Outlook(1) $992 $1,015 $1,107 $1,127 $1,098 Regulated Gas Utility Operations in AR, IN, LA, MN, MS, OH, OK and TX $5.3 Billion Five Year Capital Plan (2)

Rate Base Growth outlook (1) The projected year-end rate base is subject to change depending on actual capital investment and deferred taxes, the time frame over which excess deferred taxes are returned to customers, and the actual rate base authorized (2) Projected year-end rate base is the total rate base for the year and not just the amount that has been reflected in rates; Amounts shown may differ from regulatory filings (3) Includes Vectren year-end rate base in 2018, prior to the completion of the merger Rate Base Growth: 8.2% CAGR 2018 - 2023 (1)(2) $13,484 $15,950 $18,728 $17,109 $14,693 $19,951 (3) (Includes AR, IN, LA, MN, MS, OH, OK and TX) (Includes IN and TX)

Guidance basis EPS Outlook(1) 2019 Guidance Basis EPS of $1.60 - $1.70(2) Includes both utility and non-utility anticipated cost savings resulting from the merger, exclusive of costs to achieve those savings Excludes certain integration and transaction-related fees and expenses Excludes merger financing impacts in January, prior to the completion of the merger 2020 Guidance Basis EPS of $1.75 - $1.90 Includes both utility and non-utility anticipated cost savings resulting from the merger as well as costs to achieve those savings 5 - 7% CAGR growth rate through 2023 Based off 2018 guidance basis EPS, excluding impacts associated with the merger, of $1.60(3) Utility operations rate base investment provides the majority of growth Utility and non-utility anticipated cost savings resulting from the merger (1) Refer to slide 3 for information on non-GAAP measures and 2019 and 2020 earnings per share guidance assumptions (2) Excluding certain impacts associated with the merger. Refer to slide 3 for information on non-GAAP measures and 2019 and 2020 earnings per share guidance assumptions (3) Refer to slide 31 for reconciliation to GAAP measures and slide 3 for information on non-GAAP measures

2015 – 2020 guidance basis eps ranges(1) $1.00 $1.10 $1.20 $1.12 $1.25 $1.33 $1.50 $1.60 $1.70 $1.60 $1.75 $1.90 Low-end of guidance basis EPS High-end of guidance basis EPS Actual EPS on a Guidance Basis 2015: Excluding midstream impairment charges. 2017: Excluding the gain from tax reform. 2018: Excluding impacts associated with the merger. 2019: Target range excludes certain impacts associated with the merger. $1.10 $1.16 $1.37 $1.60 5 – 7% Growth (1) Refer to slides 31-33 for reconciliation to GAAP measures and slide 3 for information on non-GAAP measures and 2019 and 2020 earnings per share guidance assumptions

Closing comments Thank you to the various employees directly and indirectly involved in completing the transaction related financing and the integration planning Overall safety performance exceeded targets Leveraged technology in our systems and operations (advanced leak detection, drones, smart meters, data analytics, etc.) Received multiple industry awards for our emergency assistance, customer satisfaction and innovation Continued focus on safety, execution, customer loyalty and innovation will drive our long-term growth potential

Agenda Scott Prochazka President and CEO Full Year 2018 Performance 2018 Financial and Operational Highlights 2019 Key Regulatory Activities Electric Operations Capital Investment Outlook Natural Gas Distribution Capital Investment Outlook Rate Base Growth Outlook Guidance Basis EPS Outlook Bill Rogers Chief Financial Officer Business Segment Performance Utility Operations EPS Drivers Consolidated EPS Drivers 2019 and 2020 EPS Considerations Business Segment Review Appendix Regulatory Update Core Operating Income Reconciliation Income and EPS Reconciliation Credit Ratings and Outlook Equity Amortization

Electric Transmission and Distribution Core Operating Income Drivers 2017 v. 2018 (1) Excludes transition and system restoration bonds; please refer to slide 30 for core operating income reconciliation measures and to slide 3 for information on non-GAAP measures (2) The retrospective adoption of ASU 2017-07 resulted in an increase to 2017 operating income of $26 million and a corresponding decrease to other income (3) Includes rate changes, exclusive of the TCJA impact (4) Includes increased operation and maintenance expenses of $79 million primarily due to the following: higher contract services of $24 million, largely due to resiliency spend and services related to fiber and wireless; higher support services of $23 million, primarily related to technology projects; higher labor and benefits costs of $14 million; higher other miscellaneous O&M expenses of $12 million and higher damage claims from third parties of $6 million. These were partially offset by higher equity return of $32 million, primarily related to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months; higher miscellaneous revenues of $9 million largely due to right-of-way and fiber and wireless revenues; and higher usage of $8 million, primarily due to a return to more normal weather (1)(2) (1) (3) (4) $561 $568 Federal income tax expense is also decreased

Natural Gas Distribution Operating Income Drivers 2017 v. 2018 (1) The retrospective adoption of ASU 2017-07 resulted in an increase to 2017 operating income of $20 million and a corresponding decrease to other income (2) Includes rate increases, exclusive of the TCJA impact (3) Includes increased operating and maintenance expenses of $41 million, primarily consisting of: higher materials and supplies, contracts and services and bad debt expenses of $15 million; higher support services expense of $16 million, primarily related to technology projects; higher other miscellaneous operation and maintenance expenses of $10 million; higher labor and benefits costs of $30 million, resulting from the recording in 2017 of regulatory assets (and a corresponding reduction in expense) to recover $16 million of prior post-retirement expenses in future rates established in the Texas Gulf rate order and additional maintenance activities; decreased revenue of $10 million, primarily driven by timing of weather normalization adjustments; partially offset by an increase in non-volumetric revenues of $10 million (1) (2) (3) Federal income tax expense is also decreased

Utility operations adjusted diluted eps drivers 2017 v. 2018 (Guidance basis)(5) (1) Excludes equity return; please refer to slide 30 for core operating income reconciliation measures and to slide 3 for information on non-GAAP measures. Utilizes the 2017 tax rate (benefit of 2018 tax rate captured in Other) and the share count prior to merger financing (2) Excludes transition and system restoration bonds. Utilizes the 2017 tax rate (benefit of 2018 tax rate captured in Other) and the share count prior to merger financing (3) Higher equity return of $32 million, primarily related to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months. Utilizes the 2017 tax rate (benefit of 2018 tax rate captured in Other) and the share count prior to merger financing (4) Taxes, including the benefits of TCJA, TCJA revenue reductions, equity AFUDC, other income and Other Operations segment. Utilizes the share count prior to merger financing (5) Excluding $58 million of pre-tax costs ($46 million of operating income and $12 million of net interest) plus $35 million of preferred stock dividend requirements and the increase in share count associated with the merger; Utility Operations EPS includes all earnings except those related to Midstream Investments (Utility Operations EPS includes the Enable Series A Preferred Units) Note: Refer to slides 31-32 for reconciliation to GAAP measures and slide 3 for information on non-GAAP measures (1) (2)(5) Net of TCJA revenue reductions shown on slides 16 and 17 (3) (4) (5)

Consolidated adjusted diluted eps drivers 2017 v. 2018 (Guidance basis)(1) (1) Excluding $58 million of pre-tax costs ($46 million of operating income and $12 million of net interest) plus $35 million of preferred stock dividend requirements and the increase in share count associated with the merger; Utility Operations EPS includes all earnings except those related to Midstream Investments (Utility Operations EPS includes the Enable Series A Preferred Units). (2) See previous slide (3) Utilizes the share count prior to merger financing Note: Refer to slides 31-32 for reconciliation to GAAP measures and slide 3 for information on non-GAAP measures (2) $0.09 EPS improvement as a result of tax reform Utility Operations Utility Operations Midstream Investments Midstream Investments $1.37 $1.60 (1) (3)

2019 EPS Considerations Houston Electric Impacts DCRF provided $36 million in annual incremental revenue in 2018; no filing applicable in 2019 TCOS filings provided $51 million in annual incremental revenue in 2018; not anticipated in 2019 Equity amortization provided $74 million in pre-tax earnings in 2018; anticipated to be $43 million in 2019 Anticipated utility and non-utility cost savings resulting from the merger Anticipated consolidated effective tax rate of approximately 22%, excluding EDIT amortization which has a corresponding offset in operating income EPS is after the dividend requirement for Series A and Series B preferred No anticipated issuance of equity in 2019 Midstream (see slide 21)

2019 EPS Considerations – Midstream investments (1) All figures in 2019 column are anticipated as of the date of this presentation (2) Source: Enable’s 4th quarter and full-year earnings presentation dated February 19, 2019 (3) Assumes no change in Enable ownership position (4) Does not include $2 million loss on dilution, net of proportional basis difference recognition (in millions, except for percentages) (pre-tax amounts) 2018 2019(1) Enable Net Income attributable to common units $485 $435 - $505(2) CNP common unit ownership percentage 54.0% 54.0%(3) Basis Difference Amortization $47(4) $47 Interest (CNP Midstream internal note) 3.5% on $900 million for 4 months 4.5% on $1.2 billion for 12 months Marginal Effective Tax Rate 25% 25%

2020 EPS Considerations Regulatory Filings Anticipate TCOS filing(s) incorporating 2019 and part of 2020 capital investment Expect DCRF filing reflecting 2019 capital investment Minnesota interim rates in effect post filing of general rate case application Anticipated merger O&M savings of $75 - $100 million Includes pre-tax utility and non-utility savings This estimate is prior to some benefits shared with customers and does not include costs to achieve Commodity prices and volumes (Midstream) Anticipated consolidated effective tax rate of approximately 22%, excluding EDIT amortization which has a corresponding offset in operating income EPS is after the dividend requirement for Series A and Series B preferred No anticipated issuance of equity in 2020

CenterPoint Businesses Historical Prior to the merger, CenterPoint had five segments for SEC reporting. For Investor Relations reporting, we grouped four segments together: Houston Electric – T&D(1) Natural Gas Distribution CenterPoint Energy Services Corporate and Other Operations(2) Midstream Investments Utility Operations (1) Includes equity amortization associated with Transition and System Restoration Bonds (2) Includes corporate level debt and distributions on the Enable Series A Preferred Units Included certain non-utility activities

CenterPoint Businesses Post Merger Going forward, we expect we will have seven segments for SEC reporting. We expect to group them as follows for investor reporting: Houston Electric – T&D(1) Indiana Electric – Integrated Natural Gas Distribution CenterPoint Energy Services Infrastructure Services(2) Midstream Investments(3) Corporate and Other(4) Electric Operations Utility Operations (1) Includes equity amortization associated with Transition and System Restoration Bonds (2) Includes Minnesota Limited and Miller Pipeline (3) Includes interest expense at CNP Midstream, see slide 21 (4) Includes corporate level debt and distributions on the Enable Series A Preferred Units

Agenda Scott Prochazka President and CEO Full Year 2018 Performance 2018 Financial and Operational Highlights 2019 Key Regulatory Activities Electric Operations Capital Investment Outlook Natural Gas Distribution Capital Investment Outlook Rate Base Growth Outlook Guidance Basis EPS Outlook Bill Rogers Chief Financial Officer Business Segment Performance Utility Operations EPS Drivers Consolidated EPS Drivers 2019 and 2020 EPS Considerations Business Segment Review Appendix Regulatory Update Core Operating Income Reconciliation Income and EPS Reconciliation Credit Ratings and Outlook Equity Amortization

Electric Transmission and Distribution Q4 2018 Regulatory Update Mechanism Docket # Annual Increase (Decrease) (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information TCOS N/A February 2018 April 2018 April 2018 Revised TCOS annual revenue application approved in November 2017 by a reduction of $41.6 million to recognize a decrease in the federal income tax rate, amortize certain EDIT balances and adjust rate base by EDIT attributable to new plant since the last rate case, all of which are related to the TCJA. TCOS 48389 40.8 May 2018 July 2018 July 2018 Requested an increase of $285 million to rate base and reflects a $40.8 million annual increase in current revenues. Also reflects a one-time refund of $6.6 million in excess federal income tax collected from January to April 2018. TCOS 48708 2.4 September 2018 November 2018 November 2018 Requested an increase of $15.4 million to rate base and reflects a $2.4 million annual increase in current revenues. EECRF 48420 8.4 June 2018 March 2019 December 2018 The PUCT issued a final order in December 2018 approving recovery of 2019 EECRF of $39.5 million, including an $8.4 million performance bonus. DCRF 48226 30.9 April 2018 September 2018 August 2018 Unanimous settlement agreement approved by the PUCT in August 2018 results in incremental annual revenue of $30.9 million. It results in a $120.6 million annual revenue requirement effective September 1, 2018. The settlement agreement also reflects an approximately $39 million decrease resulting from the 21% federal income tax rate, a $20 million decrease to return to customers the reserve recorded recognizing this decrease in the federal income tax rate from January 25, 2018 through August 31, 2018 and a $19.2 million decrease related to the unprotected EDIT. Effective September 1, 2019, the reserve amount returned to customers ends. In December 2018, Houston Electric filed an updated DCRF tariff to adjust the interim DCRF rates to reflect the difference between the $20 million estimated tax-expense regulatory liability and the $23.4 million actual tax-expense regulatory liability recorded by Houston Electric. DCRF – Distribution Cost Recovery Factor; TCOS – Transmission Cost of Service; TBD – To Be Determined; EDIT – Excess Deferred Income Taxes; EECRF – Energy Efficiency Cost Recovery Factor; PUCT – Public Utilities Commission of Texas Note: In September 2018, Houston Electric filed a certificate of convenience and necessity application with the PUCT that included capital cost estimates for the Freeport Master Plan Project (1) Represents proposed increases (decreases) when effective date and/or approval date is not yet available. Approved rates could differ materially

Natural Gas Distribution Q4 2018 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase (Decrease) (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information South Texas (RRC) Rate Case 10669 (1.0) November 2017 May 2018 May 2018 Unanimous settlement agreement approved by the Railroad Commission in May 2018 that provides for a $1 million annual decrease in current revenues. The settlement agreement also reflects an approximately $2 million decrease in the federal income tax rate and amortization of certain EDIT balances and establishes a 9.8% ROE for future GRIP filings for the South Texas jurisdiction. Beaumont/East Texas and Texas Gulf (RRC) GRIP 10716 10717 14.7 March 2018 July 2018 June 2018 Based on net change in invested capital of $70.0 million and reflects a $14.7 million annual increase in current revenues, net of an approximate $1.0 million decrease from the federal income tax rate reduction as a result of the TCJA. Administrative 104.111 10748 10749 10750 N/A July 2018 September 2018 August 2018 Beaumont/East Texas, Houston and Texas Coast proposed to decrease base rates by $12.9 million to reflect the change in the federal income tax rate. In addition, Beaumont/East Texas proposed to decrease the GRIP charge to reflect the change in the federal income tax rate. The impact of deferred taxes is expected to be reflected in the next rate case. Arkansas (APSC) FRP 17-010-FR 13.2 August 2018 October 2018 September 2018 Based on ROE of 9.5% as approved in the last rate case and reflects a $13.2 million annual increase in current revenues, excluding the effects of the recently enacted TCJA. The annual increase is reduced from TCJA impacts by approximately $8.1 million, which include the effects of a lower federal income tax rate and amortization of EDIT balances. GRIP – Gas Reliability Infrastructure Program; FRP – Formula Rate Plan; EDIT – Excess Deferred Income Taxes; RRC – Railroad Commission; APSC – Arkansas Public Service Commission (1) Represents proposed increases (decreases) when effective date and/or approval date is not yet available. Approved rates could differ materially

Natural Gas Distribution Q4 2018 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase (Decrease) (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information Louisiana (LPSC) RSP 6.1 December 2018 December 2018 February 2019 Based on ROE of 9.95% and the 21% federal income tax rate and reflects a $6.1 million annual increase in current revenues. Other impacts of the TCJA, which were calculated outside the band, reduced the annual increase by approximately $4 million. Interim rates were implemented in December 2018. Final rates were implemented February 2019 upon receipt of the LPSC’s final order. The LPSC also approved the refund of $5.6 million of other TCJA impacts over a three month period, beginning January 31, 2019. Minnesota (MPUC) Rate Case G008/GR-17-285 3.9 August 2017 November 2018 July 2018 Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates reflecting an annual increase of $47.8 million were effective October 1, 2017. A unanimous settlement agreement was filed in March 2018, subject to MPUC approval. The settlement agreement increases base rates by $3.9 million, makes decoupling a permanent part of the tariff, incorporates the impact of the decrease in the federal income tax rate and amortization of EDIT balances (approximately $20 million) and establishes or continues tracker recovery mechanisms that account for approximately $13.3 million in the initial filing. The MPUC voted to approve the settlement and a formal order was issued on July 20, 2018. Final rates (and the refund of interim rates that exceed final rates) were implemented beginning November 1, 2018. Minnesota (MPUC) Decoupling (13.8) September 2018 September 2018 January 2019 Represents revenue over-recovery of $21.9 million recorded for and during the period July 1, 2017 through June 30, 2018 offset by the rate and prior period adjustments totaling $8.1 million recorded in 2018. RSP – Rate Stabilization Plan; EDIT – Excess Deferred Income Taxes; LPSC – Louisiana Public Service Commission; MPUC – Minnesota Public Utilities Commission (1) Represents proposed increases (decreases) when effective date and/or approval date is not yet available. Approved rates could differ materially

Natural Gas Distribution Q4 2018 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase (Decrease) (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information Minnesota (MPUC) CIP 12.5 May 2018 September 2018 September 2018 Annual reconciliation filing for program year 2017 and includes performance bonus of $12.5 million which was recorded in September 2018. Mississippi (MPSC) RRA 12-UN-139 3.2 May 2018 November 2018 November 2018 Based on authorized ROE of 9.144% and a capital structure of 50% debt and 50% equity and reflects a $3.2 million annual increase in revenues. Oklahoma (OCC) PBRC PUD201800029 5.4 March 2018 October 2018 October 2018 Based on ROE of 10% and reflects a $5.4 million annual increase in revenues. As a result of the final order, all EDIT was removed from the PBRC calculation. Protected EDIT amortization will begin to be refunded in April 2019 via one-time annual bill credits. Unprotected EDIT will be refunded over a five-year period via annual bill credits which began in October 2018. CIP – Conservation Improvement Plan; PBRC – Performance Based Rate Change; EDIT – Excess Deferred Income Taxes; RRA – Rate Rider Adjustment; MPSC – Mississippi Public Service Commission; OCC – Oklahoma Corporation Commission (1) Represents proposed increases (decreases) when effective date and/or approval date is not yet available. Approved rates could differ materially

Reconciliation: Operating Income to Core Operating Income

Reconciliation: Income and Diluted EPS to Adjusted Income and Adjusted Diluted EPS Used in Providing Annual Earnings Guidance

Reconciliation: Net Income and Diluted EPS to Adjusted net Income and Adjusted Diluted EPS Used in Providing Annual Earnings Guidance

Reconciliation: net Income and Diluted EPS to Adjusted net Income and Adjusted Diluted EPS Used in Providing Annual Earnings Guidance

Credit ratings and outlook (1) A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term (2) A S&P credit watch assesses the potential direction of a short-term or long-term credit rating (3) A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period Company/Instrument Moody’s S&P Fitch Rating Outlook(1) Rating CreditWatch(2) Rating Outlook(3) CNP Inc. Senior Unsecured Debt Baa2 Stable BBB Stable BBB Stable Houston Electric Senior Secured Debt A1 Stable A Stable A+ Stable CERC Corp. Senior Unsecured Debt Baa1 Positive BBB+ Stable BBB+ Stable Vectren Corp Issuer Credit Rating Not rated BBB+ Stable Not rated Vectren Utility Holdings, Inc. Senior Unsecured Debt A2 Negative BBB+ Stable Not rated Indiana Gas Company Senior Unsecured Debt A2 Negative BBB+ Stable Not rated Southern Indiana Gas & Electric Company Senior Secured Debt Aa3 Negative A Stable Not rated

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 Dec. 31, 2018 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 2019 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 Jan. 1, 2019, through 2024 are based on CenterPoint Energy’s estimates as of Dec. 31, 2018. 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 Dec 31, 2018