EX-99.2

EX-99.2 3 d156747dex992.htm EX-99.2 EX-99.2

2nd Quarter 2017 Earnings Call August 3, 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 Partners, LP (“Enable Midstream”), our acquisition of Atmos Energy Marketing, including statements about future financial performance and operating income, and growth, guidance, including earnings and dividend growth, future financing plans and expectation for liquidity and capital resources and expenditures, effective tax rate, 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 and Forms 10-Q for the periods ended March 31, 2017 and June 30, 2017 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 Securities and Exchange Commission (“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. Slide 8 is extracted from Enable Midstream’s investor presentation as presented during its second quarter 2017 earnings call dated August 1, 2017. This slide is included for informational purposes only. The content has not been verified by CenterPoint Energy, and CenterPoint Energy assumes no liability for the same. You should consider Enable Midstream’s investor materials in the context of its SEC filings and its entire investor presentation, which is available on their website at http://investors.enablemidstream.com/. 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 and mark-to-market gains or losses resulting from the Company’s Energy Services business. A reconciliation of net income and diluted earnings per share to the basis used in providing 2017 guidance is provided in this presentation on slide 23. 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 and mark-to-market gains or losses resulting from the Company’s Energy Services business 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 22, 23, 24 and 25 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.

Agenda Scott Prochazka – President and CEO Second Quarter Results Business Segment Highlights Houston Electric Natural Gas Distribution Energy Services Midstream Investments Full-Year Outlook Midstream Investments Ownership Review Update Bill Rogers – Executive Vice President and CFO Business Segment Performance Utility Operations EPS Drivers Consolidated EPS Drivers Investment and Financing Appendix Regulatory Update Core Operating Income Reconciliation Net Income Reconciliation

Second Quarter 2017 Performance (1) Refer to slide 23 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures (2) Excluding ZENS and CES mark-to-market adjustments (3) Items related to the Texas Gulf rate order include recording of a regulatory asset (and a corresponding reduction in expense) to recover $16 million of prior postretirement expenses in future rates and a $6 million unfavorable adjustment to operation and maintenance expense, which is timing related (4) Primarily due to the annual true-up of transition charges correcting for over-collections that occurred during 2016 Q2 2017 vs Q2 2016 Drivers (2) h Favorable Variance i Unfavorable Variance Rate Relief Customer Growth Midstream Investments Interest Expense Enable Preferred Units Other (3) Depreciation Equity Return (4) Q2 GAAP EPS Q2 EPS on a Guidance (Non-GAAP) Basis (1) Second quarter 2017 EPS of $0.31, compared with EPS loss of $0.01 in second quarter 2016, which included a $0.17 per share charge associated with ZENS, primarily due to the merger of Time Warner Cable and Charter Communications

Electric Transmission and Distribution Highlights TDU core operating income was $144 million in Q2 2017 compared to $135 million in Q2 2016 Added more than 52,000 metered customers year-over-year, representing 2% customer growth Total throughput increased 2.5% from Q2 2016 to Q2 2017 DCRF Unanimous Stipulation and Settlement Agreement for a $41.8 million annual increase approved by the PUCT in July 2017; effective date of September 1, 2017 (1) Texas Legislature approved annual DCRF filings, eliminating the need to file full rate case after 4th DCRF filing (2) DCRF – Distribution Cost Recovery Factor; ERCOT – Electric Reliability Council of Texas; PUCT – Texas Public Utility Commission (1) The settlement agreement also included an estimated $28.7 million due to a refund of AMS revenue in excess of expenses (2) The legislation also requires the PUCT to create a rate case schedule; rate case schedule is subject to change if earned ROE is lower than a defined ROE Proposed $250 million transmission project submitted to ERCOT in April 2017 to address continued load growth from the petrochemical industry in the Freeport, Texas area Expected capital for the proposed project incremental to the previously disclosed five-year capital plan Anticipate decision from ERCOT later in 2017; if approved, Houston Electric will make the necessary filings with the PUCT CenterPoint crews restoring power after a May 2017 “microburst” weather event in Sealy, TX

Natural Gas Distribution Highlights Natural Gas Distribution operating income was $37 million in Q2 2017 compared to $20 million in Q2 2016 Added more than 32,000 customers year-over-year, representing 1% customer growth Texas Gulf rate order approved by the RRC in May 2017 establishes parameters for future GRIP filings; includes annual increase of $16.5 million Minnesota rate case filed in August 2017 proposes an annual increase of $56.5 million for growth and infrastructure investment; interim rates expected to be effective October 1, 2017 Arkansas FRP Unanimous Settlement Agreement filed in July 2017 for $7.6 million; subject to approval by the APSC RRC – Texas Railroad Commission; GRIP – Gas Reliability Infrastructure Program; FRP – Formula Rate Plan; APSC – Arkansas Public Service Commission

Energy Services Highlights and Outlook Q2 2017 Operating Income Operating income was $10 million in Q2 2017 compared to $7 million in Q2 2016, excluding a mark-to-market gain of $6 million and loss of $7 million, respectively Business Outlook Energy Services projected to contribute $45 - $55 million in operating income in 2017 Atmos Energy Marketing (AEM) acquisition has been accretive to earnings year-to-date Energy Services is the 12th largest natural gas marketer in North America as of Q1 2017 according to Platts (1) (1) Platts ranking for natural gas marketed volumes (Bcf/d) for Q1 2017

Midstream Investments Highlights $0.09 EPS Contribution in Q2 2017 vs $0.03 in Q2 2016 Source: Enable Midstream Partners, August 1, 2017, Q2 Earnings Call. Please refer to these materials for an overview of Enable’s Q2 2017 performance 44 Active Rigs on Enable’s Footprint (4) 50,000 New acres dedicated (1) Continued Commercial Momentum Underpinned by Significant Rig Activity Previously announced Wildcat and CaSE projects provide critical Anadarko Basin takeaway solutions totaling over 600 MMcf/d Year-to-date approximate additions to Enable’s total acreage dedications as of June 30, 2017 Active rigs on Enable’s footprint per Drillinginfo as of July 31, 2017, compared to April 17, 2017 Per quarter processed volumes since Enable’s formation Per Drillinginfo as of July 31, 2017 38 Increase in active rigs (2) 1.91 All-time high processed volumes TBtu/d % (3)

2017 Full-Year Outlook Utility rate relief and continued customer growth Increased contribution from Energy Services, partly due to recent acquisitions Increased earnings per Enable Midstream Partners’ forecast (2) Anticipate 2017 EPS growth will be driven by: (1) Refer to slide 25 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures (2) As provided on Enable Midstream Partners’ second quarter 2017 earnings call on August 1, 2017 Targeting upper end of 4-6% year-over-year earnings growth range for 2018 * 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 $1.16 $1.25 – $1.33 * EPS on a Guidance (Non-GAAP) Basis (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 Maintain current credit ratings of CenterPoint Activity Update Sale – Multiple parties are conducting their due diligence; we will not comment on the status of those activities, nor can we represent that any parties will make a binding offer Spin – Concluded that with a reasonable level of debt at SpinCo, we would not maintain the desired credit metrics for CenterPoint; therefore, we are no longer pursuing this option If Outright Sale is not Viable Support Enable’s efforts for growth and contract design that reduces commodity and volume exposure Pursue opportunities to incrementally reduce investment in Enable via sale in public markets, subject to market conditions We recognize current capital market limitations due to Enable’s public float Separate from capital market considerations, sales of more than 5% of the common units CenterPoint Energy owns to any one party are subject to rights of first offer and first refusal, except for transactions through a securities exchange

Scott Prochazka – President and CEO Second Quarter Results Business Segment Highlights Houston Electric Natural Gas Distribution Energy Services Midstream Investments Full-Year Outlook Midstream Investments Ownership Review Update Bill Rogers – Executive Vice President and CFO Business Segment Performance Utility Operations EPS Drivers Consolidated EPS Drivers Investment and Financing Appendix Regulatory Update Core Operating Income Reconciliation Net Income Reconciliation Agenda

Electric Transmission and Distribution Operating Income Drivers Q2 2016 vs Q2 2017 (1) Houston Electric’s customer count increased by 52,051 from 2,377,352 as of June 30, 2016 to 2,429,403 as of June 30, 2017 (2) Q2 2016 TDU core operating income represents total segment operating income of $158 million, excluding operating income from transition and system restoration bonds of $23 million (3) Includes rate increases of $11 million related to distribution capital investments (4) Includes lower equity return of $7 million, primarily due to the annual true-up of transition charges correcting for over-collections that occurred during 2016 and higher operation and maintenance expenses of $4 million, partially offset by higher usage of $2 million, primarily due to a return to more normal weather (5) Q2 2017 TDU core operating income represents total segment operating income of $164 million, excluding operating income from transition and system restoration bonds of $20 million 2% YoY Customer Growth (1) $135 $144 (2) (3) (4) (5) +$16 million year-over-year

Natural Gas Distribution Operating Income Drivers Q2 2016 vs Q2 2017 (1) Natural Gas Distribution’s customer count increased by 32,685 from 3,397,827 as of June 30, 2016 to 3,430,512 as of June 30, 2017 (2) Includes rate relief increases of $6 million, primarily from the Arkansas rate case filing of $3 million and Texas jurisdictions of $3 million (3) Items related to the Texas Gulf rate order include recording of a regulatory asset (and a corresponding reduction in expense) to recover $16 million of prior postretirement expenses in future rates and a $6 million unfavorable adjustment to operation and maintenance expense, which is timing related; remaining $7 million favorable variance includes $8 million favorable usage primarily due to the timing of a decoupling normalization adjustment, partially offset by $1 million other (4) Increased depreciation and amortization expense, primarily due to ongoing additions to plant-in-service, and other taxes of $7 million (2) (3) 1% YoY Customer Growth (1) (4) $37 $17 +$7 million year-over-year

Utility Operations Adjusted Diluted EPS Drivers Q2 2016 vs Q2 2017 (Guidance Basis) (1) Excludes equity return; please refer to slide 22 for more detail on core operating income (2) Includes a $9 million decrease in interest expense due to lower weighted average interest rates on outstanding debt and a $5 million increase in cash distributions on Series A Preferred Units included in Other Income; excludes transition and system restoration bonds (3) Lower equity return of $7 million, primarily related to the annual true-up of transition charges correcting for over-collections that occurred during 2016 (4) Taxes, equity AFUDC, other income and Other Operations segment Note: Refer to slide 23 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures (1) (2) (3) (4)

Consolidated Adjusted Diluted EPS Drivers Q2 2016 vs Q2 2017 (Guidance Basis) Utility Operations Midstream Investments $0.17 $0.29 Midstream Investments Utility Operations (1) See previous slide (2) Uses an ownership percentage of 55.4% for Q2 2016 and 54.1% for Q2 2017 (3) Midstream Investments components adjusted for the effective tax rate Note: Refer to slide 23 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures (1) (2) Midstream Investments Impact (3)

Update on 2017 Investment and Financing 2017 Investment and Financing Planned capital investment of approximately $1.5 billion (1) Net incremental borrowing anticipated of $200 – $400 million (2) Equity issuance not anticipated Increased size of Credit Facilities by $400 million to an aggregate of $2.9 billion; maturity extended through March 3, 2022 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) (3) 2017 Income Tax Q2 2017 effective tax rate: 36% Expected full-year 2017 effective tax rate: 36% (1) 2017 – 2021 consolidated capital plan includes planned capital investment of approximately $7.0 billion; expected $250 million capital investment related to the proposed transmission project in the Freeport, Texas area would be incremental to the previously disclosed five-year capital plan (2) Inclusive of funding for Atmos Energy Marketing (AEM) acquisition (3) Refer to slide 2 for information on non-GAAP measures

Consolidated Adjusted Diluted EPS Drivers Six Months Ended June 30, 2016 vs YTD 2017 (Guidance Basis) Utility Operations Midstream Investments $0.49 $0.66 Midstream Investments Utility Operations (1) Includes Utility Operations improvement of $0.04 in Q1 2017 vs Q1 2016 and $0.06 in Q2 2017 vs Q2 2016 (2) Uses an ownership percentage of 55.4% for six months ended June 30, 2016 and 54.1% for six months ended June 30, 2017 (3) Midstream Investments components adjusted for the effective tax rate Note: Refer to slide 24 for reconciliation to GAAP measures and slide 2 for information on non-GAAP measures (1) (2) Midstream Investments Impact (3)

Electric Transmission and Distribution Q2 2017 Regulatory Update Mechanism Docket # Annual Increase (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information AMS 47364 N/A June 2017 TBD TBD Final reconciliation of AMS surcharge proposing a $28.7 million refund for AMS revenue in excess of expenses, for which a reserve has been recorded. EECRF (2) 47232 $11.0 June 2017 TBD TBD Annual reconciliation filing for program year 2016 and includes proposed performance bonus of $11 million. Anticipated effective date of March 2018. DCRF 47032 $41.8 April 2017 September 2017 July 2017 Based on an increase in eligible distribution-invested capital for 2016 of $479 million. Unanimous Stipulation and Settlement Agreement was filed in June 2017 for $86.8 million (a $41.8 million annual increase). The settlement agreement also included the AMS refund referenced above. TCOS 46703 $7.8 December 2016 February 2017 February 2017 Based on an incremental increase in total rate base of $109.6 million. AMS – Advanced Metering System; EECRF – Energy Efficiency Cost Recovery Factor; DCRF – Distribution Cost Recovery Factor; TCOS – Transmission Cost of Service; TBD – to be determined (1) Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates (2) Amounts are recorded when approved

Natural Gas Distribution Q2 2017 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information South Texas and Beaumont/East Texas (RRC) GRIP 10618, 10619 $7.6 March 2017 July 2017 June 2017 Based on net change in invested capital of $46.5 million. Houston and Texas Coast (RRC) Rate Case 10567 $16.5 November 2016 May 2017 May 2017 The Railroad Commission approved a unanimous settlement agreement establishing parameters for future GRIP filings, including a 9.6% ROE on a 55.15% equity ratio. Texarkana, Texas Service Area (Multiple City Jurisdictions) Rate Case $1.1 July 2017 September 2017 TBD Proposed rates are consistent with Arkansas rates approved in 2016. Arkansas (APSC) EECR (2) 07-081-TF $0.5 May 2017 January 2018 TBD Recovers $11.5 million, including an incentive of $0.5 million based on 2016 program performance. Arkansas (APSC) FRP 17-010-FR $9.3 April 2017 October 2017 TBD Based on ROE of 9.5% as approved in the last rate case. Unanimous Settlement Agreement was filed in July 2017 for $7.6 million and is subject to approval. Arkansas (APSC) BDA 06-161-U $3.9 March 2017 June 2017 June 2017 For the evaluation period between January 2016 and August 2016. Amounts are recorded during the evaluation period. GRIP – Gas Reliability Infrastructure Program; EECR – Energy Efficiency Cost Recovery; FRP – Formula Rate Plan; BDA – Billing Determinant Rate Adjustment; TBD – to be determined (1) Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates (2) Amounts are recorded when approved

Natural Gas Distribution Q2 2017 Regulatory Update Jurisdiction Mechanism Docket # Annual Increase (1) ($ in millions) Filing Date Effective Date Approval Date Additional Information Minnesota (MPUC) Rate Case G008/GR-17-285 $56.5 August 2017 TBD TBD Reflects a proposed 10.0% ROE on a 52.18% equity ratio. Includes a proposal to extend decoupling beyond current expiration date of June 2018. Interim rates expected to be effective October 1, 2017. Minnesota (MPUC) CIP (2) G008/M-17-339 $13.8 May 2017 TBD TBD Annual reconciliation filing for program year 2016 and includes proposed performance bonus of $13.8 million. Minnesota (MPUC) Decoupling G008/GR-13-316 $26.2 September 2016 February 2017 March 2017 Reflects revenue under recovery for the period July 1, 2015 through June 30, 2016, adjusting for final rates from the 2015 rate case. $24.6 million was recognized in 2016. Mississippi (MPSC) RRA 12-UN-139 $2.3 May 2017 July 2017 July 2017 Authorized ROE of 9.59% and a capital structure of 50% debt and 50% equity. Louisiana (LPSC) RSP U-34251, U-34249 $1.0 September 2016 December 2016 April 2017 Authorized ROE of 9.95% and a capital structure of 48% debt and 52% equity. Oklahoma (OCC) EECR (2) PUD201700078 $0.4 March 2017 TBD TBD Recovers $2.6 million, including an incentive of $0.4 million based on 2016 program performance. Oklahoma (OCC) PBRC PUD201700078 $2.2 March 2017 TBD TBD Based on ROE of 10%. CIP – Conservation Improvement Program; RRA – Rate Regulation Adjustment; RSP – Rate Stabilization Plan; EECR – Energy Efficiency Cost Recovery; PBRC – Performance Based Rate Change Plan; TBD – to be determined (1) Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates (2) Amounts are recorded when approved

Reconciliation: Operating Income to Core Operating Income on a Guidance (Non-GAAP) Basis

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