CNP, §1A diff (2018 → 2019)

Item 1A. Risk Factors CenterPoint Energy is a holding company that conducts all of its business operations through subsidiaries, primarily Houston Electric, CERC, SIGECO, Indiana Gas and VEDO. CenterPoint Energy also owns interests in Enable. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this combined report on Form 10-K, summarizes the principal risk factors associated with the holding company, the businesses conducted by its subsidiaries and its interests in Enable. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect CenterPoint Energy’s businesses. For other factors that may cause actual results to differ from those indicated in any forward-looking statement or projection contained in this combined report on Form 10-K, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Future Earnings” in Item 7, which should be read in conjunction with the risk factors contained in this Item 1A. Carefully consider each of the risks described below, including those relating to Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Unless the context indicates otherwise, where appropriate, information relating to a specific registrant has been segregated and labeled as such and specific references to Houston Electric and CERC in this section also pertain to CenterPoint Energy. In this combined report on Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its subsidiaries. Risk Factors Associated with Our Consolidated Financial Condition CenterPoint Energy is a holding company with no operations or operating assets of its own. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries and from Enable to meet its payment obligations and to pay dividends on its common and preferred stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions. CenterPoint Energy derives all of its operating income from, and holds all of its assets through, its subsidiaries, including its interests in Enable. As a result, CenterPoint Energy depends on distributions from its subsidiaries and Enable to meet its payment obligations and to pay dividends on its common and preferred stock. In general, CenterPoint Energy’s subsidiaries are separate and distinct legal entities and have no obligation to provide it with funds for its payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit CenterPoint Energy’s subsidiaries’ and Enable’s ability to make payments or other distributions to CenterPoint Energy, and its subsidiaries or Enable could agree to contractual restrictions on their ability to make payments or other distributions. For a description of these restrictions and further information on ring-fencing measures that may adversely affect CenterPoint Energy’s ability to receive dividends from Houston Electric as well as other financial impacts, please read “-The imposition of certain ring-fencing measures at Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations.” Additionally, CenterPoint Energy’s results of operations, future growth and earnings and dividend goals depend on the performance of its utility and non-utility (such as CES, Infrastructure Services and ESG) subsidiaries which contribute to a portion of its consolidated earnings and which may not perform at expected or forecasted levels or do not achieve the projected growth in these businesses as anticipated. As part of their non-utility businesses, CenterPoint Energy and CERC also offer home repair protection plans to natural gas customers in Texas and Louisiana (through a third-party provider) and provide home appliance maintenance and repair services to customers in Minnesota. For a discussion of risks that may impact the amount of cash distributions CenterPoint Energy receives with respect to its interests in Enable, please read “- Additional Risk Factors Affecting CenterPoint Energy’s Interests in Enable Midstream Partners, LP - CenterPoint Energy’s cash flows will be adversely impacted if it receives less cash distributions from Enable than it currently expects.” CenterPoint Energy’s right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if CenterPoint Energy were a creditor of any subsidiary, its rights as a creditor would be effectively subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by CenterPoint Energy. If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures or refinance outstanding indebtedness could be limited. Our businesses are capital intensive, and we rely on various sources to finance our capital expenditures. For example, we depend on (i) long-term debt, (ii) borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs, (iii) distributions from CenterPoint Energy’s interests in Enable and (iv) if market conditions permit, issuances of additional shares of common and/or preferred stock by CenterPoint Energy. We may also use such sources to refinance any outstanding indebtedness as it matures. As of December 31, 2019, CenterPoint Energy had $15.1 billion of outstanding indebtedness on a consolidated basis, which includes $977 million of non-recourse Securitization Bonds. For information on maturities through 2024, see Note 14 to the consolidated financial statements. Our future financing activities may be significantly affected by, among other things: • general economic and capital market conditions; • credit availability from financial institutions and other lenders; • volatility or fluctuations in distributions from Enable’s units or volatility in Enable’s unit price; • investor confidence in us and the markets in which we operate; • the future performance of our and Enable’s businesses; • integration of Vectren’s businesses into CenterPoint Energy; • maintenance of acceptable credit ratings; • market expectations regarding our future earnings and cash flows; • our ability to access capital markets on reasonable terms; • incremental collateral that may be required due to regulation of derivatives; and • provisions of relevant tax and securities laws. As of December 31, 2019, Houston Electric had approximately $4.0 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including approximately $68 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated. Additionally, as of December 31, 2019, Houston Electric had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, up to 70% of property additions or cash deposited with the trustee. As of December 31, 2019, approximately $3.7 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2019. However, Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. As of December 31, 2019, SIGECO had approximately $293 million aggregate principal amount of first mortgage bonds outstanding. SIGECO may issue additional bonds under its Mortgage Indenture up to 60% of currently unfunded property additions. As of December 31, 2019, approximately $1.1 billion of additional first mortgage bonds could be issued on this basis. However, under certain circumstances Indiana Electric is limited in its ability to issue additional bonds under the Mortgage Indenture due to a provision in its parent’s, VUHI, indentures. The Registrants’ current credit ratings and any changes in credit ratings in 2019 and to date in 2020 are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Other Matters - Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are not recommendations to buy, sell or hold their securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on their ability to access capital on acceptable terms. The imposition of certain ring-fencing measures at Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations. As part of its most recent base rate proceeding, Houston Electric has agreed, as part of a settlement, to certain “ring-fencing” measures to increase its financial separateness from CenterPoint Energy. As part of the Stipulation and Settlement Agreement, Houston Electric and CenterPoint Energy are subject to various ring-fencing measures. For further information about the Stipulation and Settlement Agreement, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report. Additionally, further ring-fencing measures could be imposed on Houston Electric in the future through legislation or PUCT rules or orders. As a result of such ring-fencing measures, CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations could be materially adversely affected. Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect the cost of capital related to outstanding debt and other financial instruments. The LIBOR is the basic rate of interest widely used as a global reference for setting interest rates on variable rate loans and other securities. Each of the Registrants’ credit and term loan facilities, including certain facilities or financial instruments entered into by their subsidiaries, use LIBOR as a reference rate. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR reference rates become unavailable, any LIBOR borrowings under the Registrants’ credit and term loan facilities would convert at the end of the applicable interest period to alternate base rate loans and any future borrowings thereunder would be made as alternate base rate loans. Alternate base rate loans generally constitute a higher cost of capital. Certain of CenterPoint Energy’s credit and term loan facilities provide for a mechanism to amend such facility to reflect the establishment of an alternative reference rate upon the inability to determine the LIBOR-based Eurodollar rate or occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement or unavailability of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial markets could have a material adverse effect on our financial condition, results of operations and cash flows. An impairment of goodwill, long-lived assets, including intangible assets, equity method investments and an impairment or fair value adjustment to CenterPoint Energy’s Enable Series A Preferred Unit investment could reduce our earnings. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States of America require CenterPoint Energy to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. As a result of the Merger, CenterPoint Energy has increased the amount of goodwill and other intangible assets on its consolidated financial statements that are subject to impairment based on future adverse changes to the acquired businesses or general market conditions. In connection with its preparation of financial statements for the year ended December 31, 2019, CenterPoint Energy and CERC, as applicable, identified triggering events for interim goodwill impairment tests at their Infrastructure Services and Energy Services reporting units. Early stage bids received from market participants during the exploration of strategic alternatives for these businesses at year-end indicated that the carrying value of each reporting unit was more likely than not below the fair value. As a result, CenterPoint Energy and CERC evaluated long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, for recoverability and the goodwill within the reporting units was tested for impairment as of December 31, 2019. The long-lived assets within the Infrastructure Services and Energy Services reporting units were determined to be recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of December 31, 2019, including the assessment of the likelihood of a future sale of these assets. CenterPoint Energy and CERC recognized an impairment loss of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) of their respective Energy Services reporting unit exceeded fair value as of December 31, 2019. Following the impairment, the carrying value of the goodwill remaining in the Energy Services reporting unit is $62 million as of December 31, 2019. CenterPoint Energy did not recognize any impairments on its Infrastructure Services reporting unit in 2019. On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reporting unit. As a result, certain assets and liabilities representing a business within this reporting unit that will be transferred under the Securities Purchase Agreement (the “Disposal Group”) met the held for sale criteria during the first quarter of 2020. Because the transaction is structured as an asset sale for income tax purposes, the Disposal Group will exclude the deferred tax liabilities. CenterPoint Energy anticipates recording an impairment loss on assets held for sale of approximately $85 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount. Additionally, on February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to sell CES, which represents substantially all of the businesses within the Energy Services reporting unit. Certain assets and liabilities representing a business within this reporting unit that will be transferred under the Equity Purchase Agreement (the “Disposal Group”) met the held for sale criteria during the first quarter of 2020. Because the transaction is structured as an asset sale for income tax purposes, the Disposal Group will exclude the deferred tax liabilities and certain assets and liabilities within the reporting unit that will be retained by CenterPoint Energy and CERC upon closing. CenterPoint Energy and CERC anticipate recording an impairment loss, consisting of both goodwill and long-lived asset impairments, on assets held for sale of approximately $80 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount. For investments CenterPoint Energy accounts for under the equity method, the impairment test considers whether the fair value of such investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if Enable’s common unit price, distributions or earnings were to decline, and that decline is deemed to be other than temporary, CenterPoint Energy could determine that it is unable to recover the carrying value of its equity investment in Enable. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Such an impairment occurred during the year ended December 31, 2015 due to the sustained low Enable common unit price and further declines in such price that year, among other factors impacting the midstream oil and gas industry. As of December 31, 2019, CenterPoint Energy’s total investment in Enable is $10.29 per unit and Enable’s common unit price closed at $10.03 per unit (approximately $61 million below carrying value). Based on an analysis of its investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.4 billion will be recovered. On February 24, 2020, Enable’s common unit price closed at $7.63 (approximately $622 million below carrying value). A sustained low Enable common unit price could result in CenterPoint Energy again recording impairment charges in the future. For investments CenterPoint Energy accounts for as investments without a readily determinable fair value, such as the Enable Series A Preferred Unit investment, the carrying value of the asset may be adjusted to fair value, resulting in a gain or loss in the period, if a transaction on an identical or similar investment in Enable is observed. Additionally, CenterPoint Energy considers qualitative impairment triggers, such as significant deterioration in earnings performance, significant decline in market condition and other factors that raise significant concerns about Enable’s ability to continue as a going concern, to determine if an impairment analysis should be performed on its investment. Should the annual impairment test or another periodic impairment test or an observable transaction, as described above, indicate the fair value of our assets is less than the carrying value, we would be required to take a non-cash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. A non-cash impairment charge or fair value adjustment could materially adversely impact our results of operations and financial condition. Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our results of operations, liquidity and financial position. CenterPoint Energy and its subsidiaries maintain qualified defined benefit pension plans covering certain of its employees. Costs associated with these plans are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, contributions to the plan, the number of plan participants and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and CenterPoint Energy may be required to make unplanned contributions in the event of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations, or government regulations that increase minimum funding requirements or the pension liability. In addition to affecting CenterPoint Energy’s funding requirements, each of these factors could adversely affect our results of operations, liquidity and financial position. CenterPoint Energy, through Infrastructure Services, also contributes to several multi-employer pension plans. If Infrastructure Services withdraws from these plans, CenterPoint Energy may be required to pay an amount based on the allocable share of the plans’ unfunded vested benefits, referred to as the withdrawal liability. This could adversely affect our results of operations, liquidity and financial position. The costs of providing health care benefits to our employees and retirees may increase substantially and adversely affect our results of operations and financial condition. We provide health care benefits to eligible employees and retirees through self-insured and insured plans. In recent years, the costs of providing these benefits per beneficiary increased due to higher health care costs and higher levels of large individual health care claims and overall health care claims. We anticipate that such costs will continue to rise. Further, the effects of health care reform or any future legislative changes could also materially affect our health care benefit programs and costs. Any potential changes and resulting cost impacts, which are likely to be passed on to us, cannot be determined with certainty at this time. Our costs of providing these benefits could also increase materially in the future should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our results of operations and liquidity. The use of derivative contracts in the normal course of business by the Registrants or Enable could result in financial losses that could negatively impact the Registrants’ results of operations and those of Enable. The Registrants use derivative instruments, such as swaps, options, futures and forwards, to manage commodity, weather and financial market risks. Enable may also use such instruments from time to time to manage its commodity and financial market risks. The Registrants or Enable could recognize financial losses as a result of volatility in the market values or ineffectiveness of these contracts or should a counterparty fail to perform. Additionally, in the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments would result in significant cash payments, which would adversely impact its cash flows. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2019. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. CenterPoint Energy may redeem all of the ZENS at any time at a redemption amount per ZENS equal to the higher of the contingent principal amount per ZENS ($75 million in the aggregate, or $5.28 per ZENS, as of December 31, 2019) or the sum of the current market value of the reference shares attributable to one ZENS at the time of redemption. In the event CenterPoint Energy redeems the ZENS, in addition to the redemption amount, it would be required to pay deferred taxes related to the ZENS. CenterPoint Energy’s ultimate tax liability related to the ZENS continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2019, deferred taxes of approximately $429 million would have been payable in 2019, based on 2019 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2019 to fund the aggregate redemption amount, capital gains taxes of approximately $149 million would have been payable in 2019. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. This could happen if CenterPoint Energy’s creditworthiness were to drop or the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and ZENS-Related Securities shares would typically cease when ZENS are exchanged and ZENS-Related Securities shares are sold. Dividend requirements associated with the Series A Preferred Stock and the Series B Preferred Stock that CenterPoint Energy issued to fund a portion of the Merger subject it to certain risks. CenterPoint Energy has issued 800,000 shares of Series A Preferred Stock and 19,550,000 depositary shares, each representing a 1/20th interest in a share of CenterPoint Energy’s Series B Preferred Stock. Any future payments of cash dividends, and the amount of any cash dividends CenterPoint Energy pays, on the Series A Preferred Stock and the Series B Preferred Stock will depend on, among other things, its financial condition, capital requirements and results of operations and the ability of our subsidiaries and Enable to distribute cash to CenterPoint Energy, as well as other factors that CenterPoint Energy’s Board of Directors (or an authorized committee thereof) may consider relevant. Any failure to pay scheduled dividends on the Series A Preferred Stock and the Series B Preferred Stock when due would likely have a material adverse impact on the market price of the Series A Preferred Stock, the Series B Preferred Stock, Common Stock and CenterPoint Energy’s debt securities and would prohibit CenterPoint Energy, under the terms of the Series A Preferred Stock and Series B Preferred Stock, from paying cash dividends on or repurchasing shares of Common Stock (subject to limited exceptions) until such time as CenterPoint Energy has paid all accumulated and unpaid dividends on the Series A Preferred Stock and the Series B Preferred Stock. The terms of the Series A Preferred Stock and the Series B Preferred Stock further provide that if dividends on any of the respective shares have not been declared and paid for the equivalent of three or more semi-annual or six or more quarterly dividend periods, whether or not for consecutive dividend periods, the holders of such shares, voting together as a single class with holders of any and all other series of CenterPoint Energy’s capital stock on parity with its Series A Preferred Stock or its Series B Preferred Stock (as to the payment of dividends and amounts payable on liquidation, dissolution or winding up of CenterPoint Energy’s affairs) upon which like voting rights have been conferred and are exercisable, will be entitled to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain terms and limitations. Risk Factors Affecting Electric Generation, Transmission and Distribution Businesses (CenterPoint Energy and Houston Electric) Rate regulation of Houston Electric’s and Indiana Electric’s businesses may delay or deny their ability to earn an expected return and fully recover their costs. Houston Electric’s rates are regulated by certain municipalities and the PUCT and Indiana Electric’s rates are regulated by the IURC. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of Houston Electric’s and Indiana Electric’s control. For Houston Electric, a general base rate proceeding is required 48 months from the date of the order setting rates in its most recent comprehensive rate proceeding, unless the PUCT issues an order extending the deadline to file that general base rate proceeding. For Indiana Electric, a general base rate proceeding is required prior to the expiration of its TDSIC plan, which expires on December 31, 2023. Houston Electric and Indiana Electric can make no assurance that their respective base rate proceedings will result in favorable adjustments to their rates, in full cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings have caused in certain instances, and in the future could cause, Houston Electric and Indiana Electric to recover their investments below their requested levels, below the national average for utilities or below recently approved levels for other utilities in their respective jurisdictions. For instance, on April 5, 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates, seeking approval for revenue increases of approximately $194 million, excluding a rider to refund approximately $40 million annually over three years. This rate filing was based on a rate base of $6.4 billion, a 50% debt/50% equity capital structure and a 10.4% ROE. Houston Electric also requested a prudency determination on all capital investments made since January 1, 2010; the establishment of a rider to refund approximately $119 million to its customers over three years resulting from the TCJA; updated depreciation rates; and approval to clarify and update various non-rate tariff provisions. After a five-day hearing in June 2019, and following the issuance of a PFD by the administrative law judges who heard the case, the parties entered into a Stipulation and Settlement Agreement. On February 14, 2020, the PUCT approved the Stipulation and Settlement Agreement, which established rates based on a $13 million increase in annual revenues, a capital structure of 42.5% equity/57.5% debt and a 9.4% ROE. The Stipulation and Settlement Agreement requires Houston Electric to file another case within 48 months of the final order and removes the possibility that the deadline would be extended. For more information on Houston Electric’s base rate case, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. The rates that Houston Electric and Indiana Electric are allowed to charge may not match their costs at any given time, a situation referred to as “regulatory lag.” For Houston Electric and Indiana Electric, several interim rate adjustment mechanisms have been implemented to reduce the effects of regulatory lag. These adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s and Indiana Electric’s ability to adjust rates. For Houston Electric, the DCRF mechanism adjusts an electric utility’s rates for increases in net distribution-invested capital (e.g., distribution plant and distribution-related intangible plant and communication equipment) since its last comprehensive base rate proceeding, but Houston Electric may only make a DCRF filing once per calendar year and not during a comprehensive base rate proceeding. In connection with the Stipulation and Settlement Agreement, Houston Electric agreed not to file its DCRF in 2020. The TCOS mechanism allows a transmission service provider to update its wholesale transmission rates to reflect changes in transmission-related invested capital, but is only available to Houston Electric twice per calendar year. However, neither of these mechanisms provides for recovery of operations and maintenance expenses. Similarly, for Indiana Electric, the TDSIC rate mechanism allows electric utilities (that have an IURC-approved seven-year infrastructure improvement plan) to request incremental rate increases every six months to pay for the projects included in that plan, subject to IURC approval. However, the TDSIC allows the utility to recover 80% of the costs as they are incurred, with the remaining costs to be deferred as regulatory assets to be recovered in the next base rate case. TDSIC rate increases are limited to no more than 2% of the utility’s total retail revenues from the prior year. Indiana Electric recovers transmission costs through a FERC-approved formula rate and reflects charges and costs associated with participation in MISO through the MCRA mechanism, which is filed annually. Other non-fuel purchased power costs are recovered annually via the RCRA Mechanism. Electricity suppliers are required to submit energy efficiency plans to the IURC at least once every three years. Indiana Electric recovers program and administrative costs of these plans, including lost revenues and financial incentives, via its annual DSMA mechanism. The DSMA is subject to IURC approval. Houston Electric and Indiana Electric can make no assurance that filings for such mechanisms will result in favorable adjustments to rates or in full cost recovery. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of Houston Electric’s and Indiana Electric’s costs or enable them to earn an expected return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Houston Electric’s and Indiana Electric’s ability to recover their costs in a timely manner. Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by Houston Electric or Indiana Electric and deny the full recovery of their cost of service in rates. To the extent the regulatory process does not allow Houston Electric and Indiana Electric to make a full and timely recovery of appropriate costs, their results of operations, financial condition and cash flows could be materially adversely affected. Unlike Houston Electric, Indiana Electric must seek approval by the IURC for long-term financing authority and by the FERC for its short-term financing authority. This authority allows Indiana Electric the flexibility to enter into various financing arrangements. In the event that the IURC or the FERC do not approve Indiana Electric’s financing authority, Indiana Electric may not be able to fully execute its financing plans and its financial condition, results of operations and cash flows could be materially adversely affected. Disruptions at power generation facilities owned by third parties could interrupt Houston Electric’s sales of transmission and distribution services. Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. Houston Electric does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, Houston Electric’s sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows could be adversely affected. Houston Electric’s and Indiana Electric’s revenues and results of operations are seasonal. A significant portion of Houston Electric’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Similarly, Indiana Electric’s revenues are derived from rates it charges its customers to provide electricity. Houston Electric’s and Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage. Houston Electric’s revenues are generally higher during the warmer months. As in certain past years, unusually mild weather in the warmer months could diminish Houston Electric’s results of operations and harm its financial condition. Conversely, as in certain past years, extreme warm weather conditions could increase Houston Electric’s results of operations in a manner that would not likely be annually recurring. A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, as in certain past years, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while more extreme seasonal weather conditions could increase Indiana Electric’s results of operations in a manner that would not likely be annually recurring. Indiana Electric’s execution of its IRP and its regulated power supply operations are subject to various risks, including timely recovery of capital investments, increased costs and facility outages or shutdowns. Indiana requires each electric utility to perform and submit an IRP every three years, unless extended, to the IURC that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next 20-year period on a periodic basis. Indiana Electric’s 2016 IRP modeling projects that the lowest cost and least risk generation portfolio to serve customers over the next 20 years involves retirement of a significant portion of its current generating fleet and replacing that generation capacity with other resources. Implementation of Indiana Electric’s IRP will likely require recovery of new capital investments, as well as costs of retiring the current generation fleet, including any remaining unrecovered costs of retired assets. In February 2018, as part of its electric generation transition plan, Indiana Electric filed a petition seeking authorization from the IURC to construct a new 700-850 MW natural gas combined cycle generating facility to replace certain existing generation capacity at an approximate cost of $900 million, which included the cost of a new natural gas pipeline to serve the facility, among other things. While the IURC approved the construction of a 50 MW universal solar array and the plan to retrofit its largest, most efficient coal-fired generation unit (Culley Unit 3), the IURC denied Indiana Electric’s request to construct a 700-850 MW natural gas combined cycle generating facility. The IURC urged Indiana Electric to utilize its next IRP planning cycle to evaluate the merits of a more diverse generation portfolio. During the 2019 Indiana legislative session, certain proposed legislation would have prohibited the construction of new generation assets 250 MW or larger until 2021, among other prohibitions, by directing the IURC to not issue any final orders in proceedings requesting such construction. Although this proposed legislation was ultimately defeated, a similar moratorium on the construction of new generation assets in Indiana could be reintroduced in a subsequent legislative session. Legislation has been proposed in 2020 that would require IURC approval to retire coal-fired generation. This legislation, by its terms, would sunset in early 2021 and is not expected to impact Indiana Electric as currently drafted. With respect to its upcoming IRP, Indiana Electric has conducted a request for proposals targeting 10 to 700 MW of capacity and unit-contingent energy and anticipates filing its 2019/2020 IRP in mid-2020. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. Depending on comments received on the IRP, the filing of any future requests for generating facilities could be delayed. Further, certain legislative activities such as the proposed moratorium in 2019 or other legislation restricting or delaying new generation could negatively affect Indiana Electric’s ability to construct new generation facilities and execution of its capital plan. Even if a generation project is approved, risks associated with the construction of any new generation exist, including the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays and cost overruns and the ability to meet capacity requirements. Further, there is no guarantee that the IURC will approve the requests included in any of Indiana Electric’s future filed petitions relating to its IRP. Additionally, Indiana Electric’s generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased purchase power costs and inadvertent releases of coal ash and/or other contaminants with a significant environmental impact. These operational risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; or natural disasters, all of which could adversely affect Indiana Electric’s business. Further, Indiana Electric relies on coal for substantially all of its generation capacity. Currently, its coal supply is purchased largely from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier or transportation interruptions could adversely affect Indiana Electric’s results of operations, financial condition and cash flows. Houston Electric and Indiana Electric, as a member of ERCOT and MISO, respectively, could be subject to higher costs for system improvements, as well as fines or other sanctions as a result of mandatory reliability standards. Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, the FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. The FERC has designated the NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation and for reliability in the portion of MISO that includes Indiana Electric to ReliabilityFirst Corporation, a Delaware non-profit corporation. Compliance with mandatory reliability standards may subject Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures, which may not be fully recoverable in rates. In addition, if Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards, they could be subject to sanctions, including substantial monetary penalties. Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in such payments could adversely affect Houston Electric’s cash flows, financial condition and results of operations. Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. As of December 31, 2019, Houston Electric did business with approximately 68 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2019 was $192 million. Approximately 32% and 12% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments Houston Electric had received from such REP. Risk Factors Affecting Natural Gas Distribution and Competitive Energy Services Businesses (CenterPoint Energy and CERC) On February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to sell CES, which represents substantially all of the businesses within the Energy Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements. Rate regulation of NGD may delay or deny its ability to earn an expected return and fully recover its costs. NGD’s rates are regulated by certain municipalities (in Texas only) and state commissions based on an analysis of NGD’s invested capital, expenses and other factors in a test year (often either fully or partially historic) in comprehensive base rate proceedings, subject to periodic review and adjustment. Each of these proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of NGD’s control. NGD has pending, or anticipates the filing of, rate cases in Indiana, Minnesota and Texas during 2020. NGD can make no assurance that these respective base rate proceedings will result in favorable adjustments to its rates, full cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings could cause NGD to recover its investments at rates below its requested level, below the national average for utilities or below recently approved levels for other utilities in those jurisdictions. The rates that NGD is allowed to charge may not match its costs at any given time, resulting in what is referred to as “regulatory lag.” Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by NGD to reduce the effects of regulatory lag, such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be approved, and are subject to certain limitations that may reduce or otherwise impede NGD’s ability to adjust its rates or result in rates below those requested by NGD. Arkansas allows public utilities to elect to have their rates regulated pursuant to a FRP, providing for a utility’s base rates to be adjusted once a year. In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions. Additionally, in Minnesota, the MPUC implemented a full revenue decoupling program, which separates approved revenues from the amount of natural gas used by its customers. Further, in Indiana, NGD may file a CSIA every six months to seek rate increases to recover certain federally mandated project costs (e.g., pipeline safety). The TDSIC (recovered through the CSIA), allows the utility to recover 80% of its project costs associated with an IURC-approved seven-year infrastructure improvement plan as they are incurred, with the remaining costs to be deferred until the next base rate case, and rate increases are limited to no more than 2% of the utility’s total retail revenues. In Ohio, the DRR is an annual mechanism that allows a utility to recover its investments in utility plant and operating expenses associated with replacing bare steel and cast-iron pipelines, as well as certain other infrastructure investments. The effectiveness of these filings and programs depends on the approval of the applicable state regulatory body. In Texas, NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submit annual GRIP filings to recover the incremental capital investments made in the preceding year until a general rate case is filed. NGD must file a general rate case no later than five and a half years after the initial GRIP implementation date. NGD can make no assurance that filings for such mechanisms will result in favorable adjustments to rates. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of NGD’s costs or enable NGD to earn an expected return. In addition, changes to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact NGD’s ability to recover its costs in a timely manner. Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by NGD and deny the full recovery of NGD’s cost of service or the full recovery of incurred natural gas costs in rates. To the extent the regulatory process does not allow NGD to make a full and timely recovery of appropriate costs, its results of operations, financial condition and cash flows could be adversely affected. Unlike CERC, Indiana Gas, SIGECO’s natural gas distribution business and VEDO must seek approval by the IURC and PUCO, as applicable, for long-term financing authority. This authority allows these utilities the flexibility to enter into various financing arrangements. In the event that the IURC or PUCO do not approve these utilities’ respective financing authorities, they may not be able to fully execute their financing plans and their respective financial conditions, results of operations and cash flows could be adversely affected. Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for NGD’s customers. NGD depends on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy its customers’ needs, all of which are critical to system reliability. Substantially all of NGD’s natural gas supply is purchased from intrastate and interstate pipelines. If NGD is unable to secure an independent natural gas supply of its own or through its affiliates or if third-party service providers fail to timely deliver natural gas to meet NGD’s requirements, the resulting decrease in natural gas supply in NGD’s service territories could have a material adverse effect on its results of operations, cash flows and financial condition. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, acts of terrorism or cyber-attacks or changes in legislative or regulatory requirements, could also adversely affect NGD’s businesses. Further, to the extent that NGD’s natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then NGD’s operations could be negatively affected. NGD and CES are subject to fluctuations in notional natural gas prices as well as geographic and seasonal natural gas price differentials, which could affect the ability of their suppliers and customers to meet their obligations or otherwise adversely affect their liquidity, results of operations and financial condition. NGD and CES are subject to risk associated with changes in the notional price of natural gas as well as geographic and seasonal natural gas price differentials that impact their businesses, including transportation and storage, whether through the use of AMAs or other arrangements. Increases in natural gas prices might affect NGD’s and CES’s ability to collect balances due from their customers and, for NGD, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which NGD and CES operate, thereby resulting in decreased sales and revenues and (ii) increase the risk that NGD’s and CES’s suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increase the amount of collateral required under hedging arrangements. AMAs may be subject to regulatory approval, and such agreements may not be renewed or may be renewed with less favorable terms. A decline in CERC’s credit rating could result in CERC having to provide collateral under its shipping or hedging arrangements or to purchase natural gas, which consequently would increase its cash requirements and adversely affect its financial condition. If CERC’s credit rating were to decline, it might be required to post cash collateral under its shipping or hedging arrangements or to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s results of operations, financial condition and cash flows could be adversely affected. NGD’s and CES’s revenues and results of operations are seasonal. NGD’s and CES’s revenues are primarily derived from natural gas sales. Thus, their revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish our results of operations and harm our financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase our results of operations in a manner that would not likely be annually recurring. The states in which NGD provides service may, either through legislation or rules, adopt restrictions regarding organization, financing and affiliate transactions that could have significant adverse impacts on NGD’s ability to operate. From time to time, proposals have been put forth in some of the states in which NGD does business to give state regulatory authorities increased jurisdiction and scrutiny over organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their affiliates that operate in those states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility business that can be conducted within the holding company structure. Additionally, they may impose record-keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s credit rating. These regulatory frameworks could have adverse effects on NGD’s ability to conduct its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for NGD and us to comply with competing regulatory requirements. NGD and CES must compete with alternate energy sources, which could result in less natural gas marketed and have an adverse impact on our results of operations, financial condition and cash flows. NGD and CES compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with NGD and CES for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass NGD’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by NGD and CES as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows. Infrastructure Services’ and ESG’s operations could be adversely affected by a number of factors. Infrastructure Services’ and ESG’s business results are dependent on a number of factors. The industries are competitive and many of the contracts are subject to a bidding process. Should Infrastructure Services and ESG be unsuccessful in bidding contracts (e.g., federal Indefinite Delivery/Indefinite Quantity contracts for ESG), results of operations could be impacted. Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work or issues arise where amounts due for work performed may not be collected, the profit margin realized on any single project could be reduced. Changes in legislation and regulations impacting the sectors in which the customers served by Infrastructure Services or ESG operate could adversely impact operating results. Infrastructure Services enters into a variety of contracts, some of which are fixed price. Other risks that could adversely affect Infrastructure Services include, but are not limited to: failure to properly construct pipeline infrastructure; loss of significant customers or a significant decline in related customer revenues; cancellation of projects by customers and/or reductions in the scope of the projects; changes in the timing of projects; the inability to obtain materials and equipment required to perform services from suppliers and manufacturers; and changes in the market prices of oil and natural gas and state regulatory requirements that mandate pipeline replacement programs that would affect the demand for infrastructure construction and/or the project margin realized on projects. For ESG, other risks include, but are not limited to: discontinuation of the federal ESPC and UESC programs; the inability of customers to finance projects; failure to appropriately design, construct or operate projects; and cancellation of projects by customers and/or reductions in the scope of the projects. In addition, Infrastructure Services has supported CenterPoint Energy’s utilities pursuant to service contracts. In most instances, the ability to maintain these service contracts depends upon regulatory discretion, and there can be no assurance it will be able to obtain future service contracts, or that existing arrangements will not be revisited. On February 3, 2020, CenterPoint Energy, through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements. ESG’s business has performance and warranty obligations, some of which are guaranteed by CenterPoint Energy. In the normal course of business, ESG issues performance bonds and other forms of assurance that commit it to operate facilities, pay vendors or subcontractors and support warranty obligations. As the parent company, CenterPoint Energy has and will from time to time guarantee its subsidiaries’ commitments. These guaranties do not represent incremental consolidated obligations; rather, they represent parental guaranties of subsidiary obligations to allow the subsidiary the flexibility to conduct business without posting other forms of collateral. Neither CenterPoint Energy nor Vectren has been called upon to satisfy any obligations pursuant to these parental guaranties. Risk Factors Affecting CenterPoint Energy’s Interests in Enable Midstream Partners, LP (CenterPoint Energy) CenterPoint Energy holds a substantial limited partner interest in Enable (53.7% of the outstanding common units representing limited partner interests in Enable as of December 31, 2019), as well as 50% of the management rights in Enable GP and a 40% interest in the incentive distribution rights held by Enable GP. As of December 31, 2019, CenterPoint Energy owned an aggregate of 14,520,000 Enable Series A Preferred Units representing limited partner interests in Enable. Accordingly, CenterPoint Energy’s future earnings, results of operations, cash flows and financial condition will be affected by the performance of Enable, the amount of cash distributions it receives from Enable and the value of its interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of CenterPoint Energy’s interests in Enable, include the risk factors outlined below, as well as the risks described elsewhere under “Risk Factors” that are applicable to Enable. CenterPoint Energy’s cash flows will be adversely impacted if it receives less cash distributions from Enable than it currently expects or if it reduces its ownership in Enable. Both CenterPoint Energy and OGE hold their limited partner interests in Enable in the form of common units. CenterPoint Energy also holds Enable Series A Preferred Units. For the Enable Series A Preferred Units, Enable is expected to pay $0.625 per Enable Series A Preferred Unit, or $2.50 per Enable Series A Preferred Unit on an annualized basis. However, distributions on each Enable Series A Preferred Unit are not mandatory and are non-cumulative in the event distributions are not declared on the Enable Series A Preferred Units. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis, on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates (referred to as “available cash”). Enable may not have sufficient available cash each quarter to enable it (i) to pay distributions on the Enable Series A Preferred Units or (ii) maintain or increase the distributions on its common units. Additionally, distributions on the Enable Series A Preferred Units reduce the amount of available cash Enable has to pay distributions on its common units. The amount of cash Enable can distribute on its common units and the Enable Series A Preferred Units will principally depend upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things: • the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles; • the prices of, levels of production of, and demand for natural gas, NGLs and crude oil; • the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores; • the relationship among prices for natural gas, NGLs and crude oil; • cash calls and settlements of hedging positions; • margin requirements on open price risk management assets and liabilities; • the level of competition from other companies offering midstream services; • adverse effects of governmental and environmental regulation; • the level of its operation and maintenance expenses and general and administrative costs; and • prevailing economic conditions. In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including: • the level and timing of its capital expenditures; • the cost of acquisitions; • its debt service requirements and other liabilities; • fluctuations in its working capital needs; • its ability to borrow funds and access capital markets; • restrictions contained in its debt agreements; • the amount of cash reserves established by Enable GP; • distributions paid on the Enable Series A Preferred Units; • any impact on cash levels should any sale of CenterPoint Energy’s investment in Enable occur, as discussed further below; and • other business risks affecting its cash levels. Additionally, although it has no current plan to do so, CenterPoint Energy may also reduce its ownership in Enable over time through sales in the public equity markets, or otherwise, of the Enable common units it holds, subject to market conditions. CenterPoint Energy’s ability to execute any sale of Enable common units is subject to a number of uncertainties, including the timing, pricing and terms of any such sale. Any sales of Enable common units CenterPoint Energy owns could have an adverse impact on the price of Enable common units or on any trading market for Enable common units. Further, CenterPoint Energy’s sales of Enable common units may have an adverse impact on Enable’s ability to issue equity on satisfactory terms, or at all, which may limit its ability to expand operations or make future acquisitions. Any reduction in CenterPoint Energy’s interest in Enable would result in decreased distributions from Enable and decrease income, which may adversely impact CenterPoint Energy’s ability to meet its payment obligations and pay dividends on its Common Stock. Further, any sales of Enable common units would result in a significant amount of taxes due, which could also significantly impact CenterPoint Energy’s determination to execute any sale. There can be no assurances that any sale of Enable common units in the public equity markets or otherwise will be completed. Any sale of Enable common units in the public equity markets or otherwise may involve significant costs and expenses, including, in connection with any public offering, a significant underwriting discount. CenterPoint Energy may not realize any or all of the anticipated strategic, financial, operational or other benefits from any completed sale or reduction in its investment in Enable. Furthermore, under certain circumstances, including following certain changes in the methodology employed by rating agencies whereby the Enable Series A Preferred Units are no longer eligible for the same or a higher amount of “equity credit” attributed to the Enable Series A Preferred Units on their original issue date (referred to as a “rating event”), Enable has the option to redeem the Enable Series A Preferred Units. There can be no assurances that CenterPoint Energy will be able to reinvest any proceeds from such redemption in a manner that provides for a similar rate of return as the Enable Series A Preferred Units. The amount of cash Enable has available for distribution to CenterPoint Energy on its common units and the Enable Series A Preferred Units depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which Enable records net income. The amount of cash Enable has available for distribution on its common units and the Enable Series A Preferred Units, depends primarily upon its cash flows and not solely on profitability, which will be affected by non-cash items. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes. Enable is required to, or may at its option, redeem the Enable Series A Preferred Units in certain circumstances, and Enable may not have sufficient funds to redeem the Enable Series A Preferred Units if required to do so. As a holder of the Enable Series A Preferred Units, CenterPoint Energy may request that Enable list those units for trading on the NYSE. If Enable is unable to list the Enable Series A Preferred Units in certain circumstances, it will be required to redeem the Enable Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Enable Series A Preferred Units. In addition, mandatory redemption of the Enable Series A Preferred Units could have a material adverse effect on Enable’s business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders. Additionally, Enable may redeem the Enable Series A Preferred Units under certain circumstances, including following a rating event. Upon a rating event, the Enable Series A Preferred Units may be considered by Enable to be an expensive form of indebtedness. If Enable does not have sufficient funds to exercise its option to redeem the Enable Series A Preferred Units upon a rating event, then such inability could have a material adverse effect on Enable’s business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders. CenterPoint Energy is not able to exercise control over Enable, which entails certain risks. Enable is controlled jointly by CenterPoint Energy and OGE, who each own 50% of the management rights in Enable GP. The board of directors of Enable GP is composed of an equal number of directors appointed by OGE and by CenterPoint Energy, the president and chief executive officer of Enable GP and three directors who are independent as defined under the independence standards established by the NYSE. Accordingly, CenterPoint Energy is not able to exercise control over Enable. Although CenterPoint Energy jointly controls Enable with OGE, CenterPoint Energy may have conflicts of interest with Enable that could subject it to claims that CenterPoint Energy has breached its fiduciary duty to Enable and its unitholders. CenterPoint Energy and OGE each own 50% of the management rights in Enable GP, as well as limited partner interests in Enable, and interests in the incentive distribution rights held by Enable GP. CenterPoint Energy also holds Enable Series A Preferred Units. Conflicts of interest may arise between CenterPoint Energy and Enable and its unitholders. CenterPoint Energy’s joint control of Enable GP may increase the possibility of claims of breach of fiduciary or contractual duties including claims of conflicts of interest related to Enable. In resolving these conflicts, CenterPoint Energy may favor its own interests and the interests of its affiliates over the interests of Enable and its unitholders as long as the resolution does not conflict with Enable’s partnership agreement. These circumstances could subject CenterPoint Energy to claims that, in favoring its own interests and those of its affiliates, CenterPoint Energy breached a fiduciary or contractual duty to Enable or its unitholders. Enable is subject to various operational risks, all of which could affect Enable’s ability to make cash distributions to CenterPoint Energy. The execution of Enable’s businesses is subject to a number of operational risks, which include, but are not limited to, the following: • Contract Renewal: Enable’s contracts are subject to renewal risks. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions could be adversely affected; • Customers: Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers or the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could result in a decline in sales of its gathering and processing or transportation and storage services and adversely affect Enable’s financial position, results of operations and ability to make cash distributions; • Third-Party Drilling and Production Decisions: Enable’s businesses are dependent, in part, on the natural gas and crude oil drilling and production market conditions and decisions of others, over which Enable has no control. Further, sustained reductions in exploration or production activity in Enable’s areas of operation and fluctuations in energy prices could lead to further reductions in the utilization of Enable’s systems, which could adversely affect its financial position, results of operations and ability to make cash distributions. It may also become more difficult to maintain or increase the current volumes on Enable’s gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which it operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, Enable may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time; • Competition: Enable competes with similar enterprises, some of which include public and private energy companies with greater financial resources and access to natural gas, NGL and crude oil supplies, in its respective areas of operation, primarily through rates, terms of service and flexibility and reliability of service. Increased competitive pressure in Enable’s industry, which is already highly competitive, could adversely affect Enable’s financial position, results of operations and ability to make cash distributions; • Cost Recovery of Capital Improvements: Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates. In Enable’s Form 10-K for the fiscal year ended December 31, 2019, Enable stated that it expects that its expansion capital could range from approximately $160 million to $240 million and its maintenance capital could range from approximately $110 million to $130 million for the year ending December 31, 2020; • Commodity Prices: Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. Factors affecting prices are beyond Enable’s control and include the following: (i) demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, (ii) the availability of imported natural gas, LNG, NGLs and crude oil, (iii) actions taken by foreign natural gas and oil producing nations, (iv) the availability of local, intrastate and interstate transportation systems, (v) the availability and marketing of competitive fuels, (vi) the impact of energy conservation efforts, technological advances affecting energy consumption and (vii) the extent of governmental regulation and taxation. Further, Enable’s natural gas processing arrangements expose it to commodity price fluctuations. In 2019, 4%, 26% and 70% of Enable’s processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which Enable purchases natural gas or NGLs under these arrangements, then Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected; • Credit Risk of Customers: Enable is exposed to credit risks of its customers, and any material nonpayment or nonperformance by its customers, whether through severe financial problems or otherwise, could adversely affect its financial position, results of operations and ability to make cash distributions; • “Negotiated Rate” Contracts: Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts, which are authorized by the FERC, that are not subject to adjustment, even if its cost to perform these services exceeds the revenues received from these contracts. As of December 31, 2019, approximately 37% of Enable’s aggregate contracted firm transportation capacity on EGT and MRT and 93% of its aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such “negotiated rate” contracts. The majority of Enable’s aggregate contracted firm transportation capacity and all of its aggregate contracted firm storage capacity under negotiated rate contracts on MRT are subject to the FERC’s rate case approval. As a result, Enable’s costs could exceed its revenues received under these contracts, and if Enable’s costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution could also decrease; • Unavailability of Interconnected Facilities: If third-party pipelines and other facilities interconnected to Enable’s gathering, processing or transportation facilities (including those providing transportation of natural gas and crude oil, transportation and fractionation of NGLs and electricity for compression, among other things) become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected; and • Land Ownership: Enable does not own all of the land on which its pipelines and facilities are located, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate, which could disrupt its operations or result in increased costs related to the construction and continuing operations elsewhere and adversely affect its financial position, results of operations and ability to make cash distributions. Enable conducts a portion of its operations through joint ventures, which subject it to additional risks that could adversely affect the success of these operations and Enable’s financial position, results of operations and ability to make cash distributions. Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. Enable may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. Enable’s joint venture arrangements may involve risks not otherwise present when operating assets directly, including, for example: • Enable shares certain approval rights over major decisions and may not be able to control decisions, including control of cash distributions to Enable from the joint venture; • Enable may incur liabilities as a result of an action taken by its joint venture partners, including leaving Enable liable for the other joint venture partners’ shares of joint venture liabilities if those partners do not pay their share of the joint venture’s obligations; • Enable may be required to devote significant management time to the requirements of and matters relating to the joint ventures; • Enable’s insurance policies may not fully cover loss or damage incurred by both Enable and its joint venture partners in certain circumstances; • Enable’s joint venture partners may take actions contrary to its instructions or requests or contrary to its policies or objectives; and • disputes between Enable and its joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue Enable’s joint ventures or to resolve disagreements with its joint venture partners could adversely affect its ability to transact the business that is the subject of such joint venture, which would in turn adversely affect Enable’s financial position, results of operations and ability to make cash distributions. The agreements under which Enable formed certain joint ventures may subject it to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require Enable to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If Enable does not timely meet its financial commitments or otherwise does not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of Enable’s joint venture partners may have substantially greater financial resources than Enable has and Enable may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture. Under certain circumstances, Enbridge Inc. could have the right to purchase Enable’s ownership interest in SESH at fair market value. Enable owns a 50% ownership interest in SESH. The remaining 50% ownership interest is held by Enbridge Inc. CenterPoint Energy owns 53.7% of Enable’s common units, 100% of the Enable Series A Preferred Units and a 40% economic interest in Enable GP. Pursuant to the terms of the limited liability company agreement of SESH, as amended, if, at any time, CenterPoint Energy has a right to receive less than 50% of Enable’s distributions through its interests in Enable and Enable GP, or do not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase Enable’s interest in SESH at fair market value, subject to certain exceptions. Enable’s ability to grow is dependent in part on its ability to access external financing sources on acceptable terms. Enable expects that it will distribute all of its “available cash” to its unitholders. As a result, Enable is expected to rely significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. To the extent Enable is unable to finance growth externally or through internally generated cash flows, Enable’s cash distribution policy may significantly impair its ability to grow. In addition, because Enable is expected to distribute all of its available cash, its growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that Enable will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that it has to distribute on each unit. There are no limitations in Enable’s partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that Enable has to distribute to its unitholders. Enable depends, in part, on access to the capital markets and other external financing sources to fund its expansion capital expenditures, although it has also increasingly relied on cash flow generated from operations. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions. Enable’s debt levels may limit its flexibility in obtaining additional financing and in pursuing other business opportunities. As of December 31, 2019, Enable had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on their senior notes, $155 million outstanding under its commercial paper program and $250 million outstanding under the Enable Oklahoma Intrastate Transmission, LLC 6.25% senior notes due 2020, excluding unamortized premium. Enable has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.59 billion in borrowing capacity was available as of December 31, 2019. As of January 31, 2020, Enable had $119 million outstanding under its commercial paper program and $1.63 billion of available borrowing capacity under its revolving credit facility. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of Enable’s debt could have important consequences, including the following: • the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all; • a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions; • Enable’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and • Enable’s debt level may limit its flexibility in responding to changing business and economic conditions. Enable’s ability to service its debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond Enable’s control. If operating results are not sufficient to service current or future indebtedness, Enable may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all. Further, any reductions in Enable’s credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships. Enable cannot assure that its credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of Enable’s credit ratings are below investment grade, it may have higher future borrowing costs, and Enable or its subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when Enable was experiencing significant working capital requirements or otherwise lacked liquidity, its financial position, results of operations and ability to make cash distributions could be adversely affected. Enable’s credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond Enable’s control, which could adversely affect its financial condition, results of operations and ability to make distributions. Enable’s credit facilities contain customary covenants that, among other things, limit its ability to: • permit its subsidiaries to incur or guarantee additional debt; • incur or permit to exist certain liens on assets; • dispose of assets; • merge or consolidate with another company or engage in a change of control; • enter into transactions with affiliates on non-arm’s length terms; and • change the nature of its business. Enable’s credit facilities also require it to maintain certain financial ratios. Enable’s ability to meet those financial ratios can be affected by events beyond its control, and we cannot assure you that it will meet those ratios. In addition, Enable’s credit facilities contain events of default customary for agreements of this nature. Enable’s ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Enable’s ability to comply with these covenants may be impaired. If Enable violates any of the restrictions, covenants, ratios or tests in its credit facilities, a significant portion of its indebtedness may become immediately due and payable. In addition, Enable’s lenders’ commitments to make further loans to it under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments. Enable’s businesses are exposed to various regulatory risks. Enable’s operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. This regulation includes, but is not limited to, the following: • Rate Regulation: The rates charged by several of Enable’s pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. Enable’s pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas transportation services and crude oil gathering services. The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer. • FERC Revised Policy Statement and NOPR: In a series of related issuances on March 15, 2018, the FERC issued a Revised Policy Statement stating that it will no longer permit pipelines organized as MLPs to recover an income tax allowance in their cost-of-service rates. On July 18, 2018, FERC issued a Final Rule adopting procedures that are generally the same as proposed in a March 15, 2018 NOPR implementing the Revised Policy Statement and the corporate income tax rate reduction with certain clarifications and modifications. For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. If FERC requires Enable to establish new tariff rates for either its natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions to its unitholders. With regard to FERC-jurisdictional rates on Enable’s crude oil pipelines, the FERC plans to address the Revised Policy Statement and corporate tax rate reduction in its next five-year review of the oil pipeline rate index, which will occur in 2020 and become effective July 1, 2021. The potential rate impacts from the revision are currently uncertain. • Permits, Licenses and Approvals: Enable may be unable to obtain or renew federal or state permits, licenses or approvals necessary for its operations, which could inhibit its ability to do business. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable’s compliance status may result in the imposition of fines, penalties and injunctive relief. Further, to obtain new permits or renew permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to potential adverse impact of a proposed project. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable’s project construction schedules; • Hydraulic Fracturing Regulation: Increased regulation of hydraulic fracturing and waste water injection wells could result in reductions or delays in natural gas or crude oil production by Enable’s customers, which could adversely affect its financial position, results of operations and ability to make cash distributions; and • Jurisdictional Characterization of Assets: Enable’s natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the NGA, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of the FERC under ICA. FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, Enable’s operations could be adversely affected should they become subject to the application of state regulation of rates and services. A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase. Other Risk Factors Affecting Our Businesses and/or CenterPoint Energy’s Interests in Enable Midstream Partners, LP The success of the Merger depends, in part, on CenterPoint Energy’s ability to realize anticipated benefits and conduct an effective integration process. The success of the Merger will depend, in part, on CenterPoint Energy’s ability to realize the expected benefits in the anticipated timeframe, including operating efficiencies, growth opportunities, cost savings and customer retention, from integrating CenterPoint Energy’s and Vectren’s businesses, while at the same time continuing to provide consistent, high quality services. The integration process could be complex, costly and time consuming, including the diversion of significant management time and resources thereto, and may result in the following challenges, among other things: • unanticipated delays, disruptions, issues or costs in integrating operations, financial and accounting, information technology, communications and other systems; • inconsistencies in procedures, practices, policies, controls, and standards; • differences in compensation arrangements, management perspectives and corporate culture; and • loss of or difficulties retaining talented employees or valuable third-party relationships. CenterPoint Energy must also successfully adapt its systems of internal controls to continue to accurately provide reliable financial reports, including reporting of its financial condition, results of operations or cash flows, effectively prevent fraud and operate successfully as a public company. If CenterPoint Energy’s efforts to maintain an effective system of internal controls throughout integration are not successful, it is unable to maintain adequate controls over its financial reporting and processes in the future or it is unable to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, CenterPoint Energy’s operating results could be harmed or it may fail to meet its reporting obligations. Ineffective internal controls also could cause investors to lose confidence in CenterPoint Energy’s reported financial information, which would likely have a negative effect on the trading prices of its securities. Even with the successful integration of the businesses, CenterPoint Energy may not achieve the expected results or economic benefits, including any expected revenue or synergy opportunities. Failure to fully realize the anticipated benefits could adversely affect CenterPoint Energy’s results of operations, financial condition and cash flows. Cyber-attacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our or Enable’s reputation, results of operations, financial condition and/or cash flows. We and Enable are subject to cyber and physical security risks related to adversaries attacking information technology systems, network infrastructure, technology and facilities used to conduct almost all of our and Enable’s business, which includes, among other things, (i) managing operations and other business processes and (ii) protecting sensitive information maintained in the normal course of business. For example, the operation of our electric generation, transmission and distribution systems are dependent on not only physical interconnection of our facilities but also on communications among the various components of our systems and third-party systems. This reliance on information and communication between and among those components has increased since deployment of the intelligent grid, smart devices and operational technologies across our businesses. Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyber-attack or unauthorized access in any one of these systems could potentially impact the other systems. Similarly, our and Enable’s business operations are interconnected with external networks and facilities. The distribution of natural gas to our customers requires communications with Enable’s pipeline facilities and third-party systems. The gathering, processing and transportation of natural gas from Enable’s gathering, processing and pipeline facilities and crude oil gathering pipeline systems also rely on communications among its facilities and with third-party systems that may be delivering natural gas or crude oil into or receiving natural gas or crude oil and other products from Enable’s facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our or Enable’s ability to conduct operations and control assets. Cyber-attacks, including phishing attacks and threats from the use of malicious code such as malware, ransomware and viruses, and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, increase costs and subject us or Enable to possible legal claims and liability. Further, third parties, including vendors, suppliers and contractors, who perform certain services for us or administer and maintain our sensitive information, could also be targets of cyber-attacks and unauthorized access. Neither we nor Enable are fully insured against all cyber-security risks, any of which could adversely affect our reputation and could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows. As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our and Enable’s critical energy infrastructure may be targets of state-sponsored attacks, terrorist activities or otherwise that could disrupt our respective business operations. Any such disruptions could result in significant costs to repair damaged facilities, restore service and implement increased security measures, which could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows. Failure to maintain the security of personally identifiable information could adversely affect us. In connection with our businesses, we and our vendors, suppliers and contractors collect and retain personally identifiable information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The regulatory environment surrounding information security and data privacy is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant costs, fines and penalties and liabilities for us. A significant theft, loss or fraudulent use of the personally identifiable information we maintain or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions and other legal requirements could adversely impact our reputation and could result in significant costs, fines and penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result. We are subject to operational and financial risks and liabilities arising from environmental laws and regulations. Our operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, steam electric generating facilities and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as: • restricting the way we manage hazardous and non-hazardous wastes, including wastewater discharges and air emissions; • limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species; • requiring remedial action and monitoring to mitigate environmental conditions caused by our operations, or attributable to former operations; • limiting airborne emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and mercury, and the disposal non-hazardous substances such as CCRs, among other things; • restricting the use of fossil fuels through future climate legislation or regulation; • imposing requirements on or restricting the operations of facilities under the terms of permits issued pursuant to such environmental laws and regulations; and • impacting the demand for our services by directly or indirectly affecting the use or price of fossil fuels, including, but not limited to, natural gas. To comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to: • construct or acquire new facilities and equipment; • acquire permits for facility operations or purchase emissions allowances; • modify or replace existing and proposed equipment; and • decommission or remediate waste management areas, fuel storage facilities and other locations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean, restore and monitor sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. In April 2015, the EPA finalized its CCR Rule, which regulates ash as non­-hazardous material under the RCRA. Under the CCR Rule, Indiana Electric is required to complete integrity assessments and groundwater monitoring studies. In January 2018, Indiana Electric completed its first annual groundwater monitoring and corrective action report. This report identified localized impacts to groundwater near Indiana Electric’s coal impoundments. Further analysis is ongoing. In October 2018, Indiana Electric completed the CCR Rule’s required evaluation of the placement of Indiana Electric’s coal ash ponds. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, Indiana Electric must cease disposal of new ash in the ponds and commence closure of the ponds by August 31, 2020. Indiana Electric plans to seek extensions available under the CCR Rule that would allow it to continue to use the ponds through December 31, 2023. The inability to obtain these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact Indiana Electric’s future operations. Failure to comply with these requirements could also result in an enforcement proceeding including imposition of fines and penalties. Further, a release of coal ash that presents an imminent and substantial endangerment to health of the environment could result in remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs and reputational damage, all of which could adversely affect the financial condition of Indiana Electric. The recent trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be greater than the amounts we currently anticipate. Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows. We currently have insurance in place, such as general liability and property insurance, to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to fully cover or restore the loss or damage without negative impact on our results of operations, financial condition and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses. In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and believes insurance capacity to be limited. Historically, Houston Electric has been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise. In the future, any such recovery may not be granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows. Our operations and Enable’s operations are subject to all of the risks and hazards inherent in their respective businesses of gathering, processing, transportation and storage of natural gas and crude oil and the generation, transmission and distribution of electricity, including: • damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties; • inadvertent damage from construction, vehicles and farm and utility equipment; • leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities; • ruptures, fires and explosions; and • other safety hazards affecting our operations. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our or Enable’s operations. A natural disaster or other hazard affecting the areas in which we or Enable operate could have a material adverse effect on our or Enable’s operations. Enable is not fully insured against all risks inherent in its business. Enable currently has general liability and property insurance in place to cover certain of its facilities in amounts that Enable considers appropriate. Such policies are subject to certain limits and deductibles. Enable does not have business interruption insurance coverage for all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable’s facilities may not be sufficient to restore the loss or damage without negative impact on its results of operations and its ability to make cash distributions. Our results of operations, financial condition and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions. Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including: • operator error or failure of equipment or processes, including failure to follow appropriate safety protocols; • the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage; • operating limitations that may be imposed by environmental or other regulatory requirements; • labor disputes; • information technology or financial and billing system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations; • information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and • catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, ice storms, terrorism, wildfires, pandemic health events or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts. Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows. Our and Enable’s success depends upon our and Enable’s ability to attract, effectively transition, motivate and retain key employees and identify and develop talent to succeed senior management. We and Enable depend on senior executive officers and other key personnel. Our and Enable’s success depends on our and Enable’s ability to attract, effectively transition and retain key personnel. On February 19, 2020, our president and chief executive officer resigned from CenterPoint Energy. As a result of this departure, our board of directors is currently conducting a search to fill the role of chief executive officer. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our and Enable’s operations. In addition, because of the reliance on our and Enable’s management team, our and Enable’s future success depends in part on our and Enable’s ability to identify and develop talent to succeed senior management. The retention of key personnel and appropriate senior management succession planning will continue to be critically important to the successful implementation of our and Enable’s strategies. Failure to attract and retain an appropriately qualified workforce could adversely impact our and Enable’s results of operations. Our and Enable’s businesses are dependent on recruiting, retaining and motivating employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our and Enable’s costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our and Enable’s businesses. If we and Enable are unable to successfully attract and retain an appropriately qualified workforce, our and Enable’s results of operations could be negatively affected. Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our or Enable’s services, including certain local initiatives to prohibit new NGD service and increase electrification initiatives. Regulatory agencies have adopted, and from time to time consider adopting, new legislation and/or modifying existing laws and regulations, to reduce GHGs, and there continues to be a wide-ranging policy and regulatory debate, both nationally and internationally, regarding the potential impact of GHGs and possible means for their regulation. Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In August 2018, the EPA proposed a CPP replacement rule, the ACE Rule, which was finalized in July 2019 and requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units. States have three years to develop state plans to implement the ACE Rule, and we do not expect a state ACE plan to be finalized and approved by the EPA until 2024. We are currently unable to predict the effect of a state plan to implement the ACE Rule but do not anticipate that such a plan would have a material effect on our results of operations, financial condition or cash flows. Additionally, the ACE Rule is currently subject to legal challenges. At this time, we are unable to determine what effect, if any, the legal challenges will have on the ACE Rule. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, NGD’s or Enable’s revenues, operating costs and capital requirements, as applicable, could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Additionally, Houston Electric’s and Indiana Electric’s transmission and distribution businesses’ revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. For further discussion, see “- Risk Factors Affecting Natural Gas Distribution and Competitive Energy Services Businesses -NGD and CES must compete with alternate energy sources, which could result in less natural gas marketed and have an adverse impact on our results of operations, financial condition and cash flows.” Moreover, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels may have substantial impacts on CenterPoint Energy’s electric generation and NGD businesses. For example, because Indiana Electric’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Also, certain cities in CenterPoint Energy’s NGD operational footprint have adopted initiatives to prohibit the construction of new NGD facilities that would provide service and focus on electrification. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil gas. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. Any such initiatives and legislation could adversely affect CenterPoint Energy’s results of operations. Climate changes could adversely impact financial results from our and Enable’s businesses and result in more frequent and more severe weather events that could adversely affect the results of operations of our businesses. A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories. If climate changes occur that result in warmer temperatures in our service territories, financial results from our and Enable’s businesses could be adversely impacted. For example, NGD could be adversely affected through lower natural gas sales and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes or ice storms. Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted. Any such decreased energy use may also require us to retire current infrastructure that is no longer needed. Further, we may be subject to climate change lawsuits, which could result in substantial penalties or damages. NGD and Enable may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs. Certain of NGD’s and Enable’s pipeline operations are subject to pipeline safety laws and regulations. The DOT’s PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for transportation pipelines located in “high consequence areas,” which are those areas where a leak or rupture could do the most harm. The regulations require pipeline operators, including NGD and Enable, to, among other things: • perform ongoing assessments of pipeline integrity; • develop a baseline plan to prioritize the assessment of a covered pipeline segment; • identify and characterize applicable threats that could impact a high consequence area; • improve data collection, integration, and analysis; • develop processes for performance management, record keeping, management of change and communication; • repair and remediate pipelines as necessary; and • implement preventive and mitigating action. Failure to comply with PHMSA or analogous state pipeline safety regulations could result in a number of consequences that may have an adverse effect on NGD’s and Enable’s operations. Both NGD and Enable incur significant costs associated with their compliance with existing PHMSA and comparable state regulations, which may not be recoverable in rates. Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on NGD and Enable. Changes to pipeline safety regulations occur frequently. For example, PHMSA published a final rule in October 2019 that extends and expands the reach of certain PHMSA integrity management requirements (e.g., period assessments, leak detection and repairs) regardless of proximity to a high consequence area. The adoption of new regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us and Enable to incur increased and potentially significant operational costs. Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results. We have risks associated with aging infrastructure assets, including the failure of equipment or processes and potential breakdowns due to such aging. The age of certain of our assets may result in a need for replacement or higher level of maintenance costs because of our risk based federal and state compliant integrity management programs. Failure to achieve timely and full recovery of these expenses could adversely impact revenues and could result in increased capital expenditures or expenses. In addition, the nature of information available on aging infrastructure assets may make inspections, maintenance, upgrading and replacement of the assets particularly challenging. Further, with respect to NGD’s operations, if certain pipeline replacements (for example, cast-iron or bare steel pipe) are not completed timely or successfully, government agencies and private parties might allege the uncompleted replacements caused events such as fires, explosions or leaks. Although we maintain insurance for certain of our facilities, our insurance coverage may not be sufficient in the event that a catastrophic loss is alleged to have been caused by a failure to timely complete equipment replacements. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows. The operation of our facilities depends on good labor relations with our employees. Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. We have several separate bargaining units, each with a unique collective bargaining agreement described below: • The collective bargaining agreement with IBEW Local 66 related to employees of Houston Electric is scheduled to expire in May 2020, for which negotiations are anticipated to begin in March 2020; • The collective bargaining agreements with USW Locals 13-227 and 13-1 related to NGD’s employees in Texas are scheduled to expire in June 2022 and July 2022, respectively; • The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 and Mankato related to NGD employees in Minnesota are scheduled to expire in April 2020, December 2020, May 2021 and March 2021, respectively, and negotiations with Gas Workers Union Local 340 are currently in progress and expected to be completed before the April 2020 expiration; • The collective bargaining agreements with IBEW Local 1393, USW Locals 12213 and 7441 related to employees of NGD in Indiana are scheduled to expire in December 2020; • The collective bargaining agreements with the Teamsters, Chauffeurs, Warehousemen and Helpers Union Local 135 and Utility Workers Union Local 175 related to employees of Indiana Electric were recently renegotiated and are scheduled to expire in September 2021 and October 2021, respectively; and • The collective bargaining agreement with IBEW Local 702 related to employees of Indiana Electric is scheduled to expire in June 2022. Additionally, Infrastructure Services negotiates various trade agreements through contractor associations. The two primary associations are the DCA and the PLCA. These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements. These agreements expire upon completion of a specific project or on various dates throughout the year. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have a material adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows. Our businesses will continue to have to adapt to technological change and may not be successful or may have to incur significant expenditures to adapt to technological change. We operate in businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly and increasing in complexity. New technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant investments and expenditures so that we can continue to provide cost-effective and reliable methods for energy production and delivery. Among such technological advances are distributed generation resources (e.g., private solar, microturbines, fuel cells), energy storage devices and more energy-efficient buildings and products designed to reduce energy consumption and waste. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services, including Indiana Electric’s generating facilities becoming less competitive and economical. Further, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric and natural gas devices or other improvements in or applications of technology could lead to declines in per capita energy consumption. Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a cost-effective manner, to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards, and to recover all, or a significant portion of, any unrecovered investment in obsolete assets. If we fail to adapt successfully to any technological change or obsolescence, fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our businesses, operating results, financial condition and cash flows could be materially and adversely affected. Our or Enable’s potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected. From time to time, we and Enable have made and may continue to make acquisitions or divestitures of businesses and assets, form joint ventures or undertake restructurings. However, suitable acquisition candidates or potential buyers may not continue to be available on terms and conditions we or Enable, as the case may be, find acceptable, or the expected benefits of completed acquisitions may not be realized fully or at all, or may not be realized in the anticipated timeframe. If we or Enable are unable to make acquisitions or if those acquisitions do not perform as anticipated, our and Enable’s future growth may be adversely affected. On February 3, 2020, CenterPoint Energy, through VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated. Additionally, on February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to sell CES, which represents substantially all of the businesses within the Energy Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated. As discussed in Note 16(d) to the consolidated financial statements, the existing CERC Corp. guarantees supporting CES’s obligations under natural gas supply, transportation and storage contracts will not terminate upon closing of the transaction. While the buyer has an obligation to use its reasonable best efforts to cause CERC Corp. to be released from the guarantees as of and following closing, if the buyer is unable to do so, CERC Corp. would continue to have significant exposure under the guarantees. Following closing, if CES were to default on the payment obligations still guaranteed by CERC Corp., CERC Corp. could be obligated for such amounts. Further, any completed or future acquisitions involve substantial risks, including the following: • acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels; • acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate; • we or Enable may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited; • we or Enable may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and • acquisitions, or the pursuit of acquisitions, could disrupt our or Enable’s ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures. We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results. The Registrants are subject to numerous legal proceedings, the most significant of which are summarized in Note 16 to the Registrants’ respective consolidated financial statements. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of all matters with assurance. Final resolution of these matters may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have a material adverse effect on the Registrants’ financial results. The Registrants could incur liabilities associated with businesses and assets that they have transferred to others. Under some circumstances, the Registrants could incur liabilities associated with assets and businesses no longer owned by them. These assets and businesses were previously owned by Reliant Energy, a predecessor of Houston Electric, directly or through subsidiaries and include: • merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001 and now owned by affiliates of NRG; and • Texas electric generating facilities transferred to a subsidiary of Texas Genco in 2002, later sold to a third party and now owned by an affiliate of NRG. In connection with the organization and capitalization of RRI (now GenOn) and Texas Genco (now an affiliate of NRG), those companies and/or their subsidiaries assumed liabilities associated with various assets and businesses transferred to them and agreed to certain indemnity agreements of the Registrants. Such indemnities have applied in various asbestos and other environmental matters that arise from time to time and cases such as the litigation arising out of sales of natural gas in California and other markets, including in the gas market manipulation cases described in Note 16(e) to the Registrants’ respective consolidated financial statements. However, because of the settlement and discharge of certain of GenOn’s indemnity obligations in 2019 in its Chapter 11 bankruptcy proceedings, the Registrants will no longer have the benefit of any settled or discharged indemnities and could incur liabilities in matters that previously would have been indemnified. In connection with our sale of Texas Genco, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and CenterPoint Energy would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by CenterPoint Energy, and in certain of the asbestos lawsuits CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense by an NRG affiliate. We are exposed to risks related to reduction in energy consumption due to factors such as unfavorable economic conditions in our service territories and changes in customers’ perceptions from recent incidents of other utilities involving natural gas pipelines. Our businesses are affected by reduction in energy consumption due to factors including economic climate in our service territories, energy efficiency initiatives, use of alternative technologies and changes in our customers’ perceptions regarding natural gas usage as a result of recent incidents of other utilities involving natural gas pipelines, which could impact our ability to grow our customer base and our rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas and the need for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such as population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. Declines in demand for natural gas in NGD’s territories due to recent pipeline incidents of other utilities and for electricity as a result of economic downturns in Houston Electric’s and Indiana Electric’s regulated electric service territories will reduce overall sales and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity. Although Houston Electric’s and Indiana Electric’s transmission and distribution businesses are subject to regulated allowable rates of return and recovery of certain costs under periodic adjustment clauses, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thereby diminishing results of operations. Additionally, prolonged economic downturns that negatively impact results of operations and cash flows could result in future material impairment charges to write-down the carrying value of certain assets, including goodwill, to their respective fair values. For example, Houston Electric’s business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although Houston, Texas has a diverse economy, employment in the energy industry remains important with overall Houston employment growing at a moderate rate in 2019 among various sectors. Further, the operations of Vectren’s utility businesses are concentrated in central and southern Indiana and west-central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest. These industries include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings, plastic products; gypsum products; electrical equipment, metal specialties, glass and steel finishing; pharmaceutical and nutritional products; gasoline and oil products; ethanol; and coal mining. In the event economic conditions further decline, the respective rates of growth in Houston, Indiana and the other areas in which we operate may also deteriorate. Changing market conditions, including changing regulation, changes in market prices of oil or other commodities, or changes in government regulation and assistance, may cause certain industrial customers to reduce or cease production and thereby decrease consumption of natural gas and/or electricity. Increases in customer defaults or delays in payment due to liquidity constraints could negatively impact our cash flows and financial condition. Some or all of these factors, could result in a lack of growth or decline in customer demand for electricity or number of customers, and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on their financial position, results of operations and cash flows. Our businesses may be adversely affected by the intentional misconduct of our employees. We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and our efforts to prevent misconduct, it is possible for employees to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of our Ethics and Compliance Code and Standards of Conduct/Business Ethics policy, among other policies. If such intentional misconduct by employees should occur, it could result in substantial liability, higher costs, increased regulatory scrutiny and negative public perceptions, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. Item 1B.