Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

No Registrant makes any representations as to the information related solely to CenterPoint Energy or the subsidiaries of CenterPoint Energy other than itself.

The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. When discussing CenterPoint Energy’s consolidated financial information, it includes the results of Houston Electric and CERC, which, along with CenterPoint Energy, are collectively referred to as the Registrants. Where appropriate, information relating to a specific registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries.

OVERVIEW

Background

CenterPoint Energy, Inc. is a public utility holding company and owns interests in Enable. CenterPoint Energy’s operating subsidiaries own and operate electric transmission and distribution, electric generation and natural gas distribution facilities, supply natural gas to commercial and industrial customers and electric and natural gas utilities and provide underground pipeline

construction and repair services, energy performance contracting and sustainable infrastructure services. For a detailed description of CenterPoint Energy’s operating subsidiaries, please read Note 1 to the consolidated financial statements.

Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that provides electric transmission and distribution services to REPs serving the Texas Gulf Coast area that includes the city of Houston.

CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy with operating subsidiaries that own and operate natural gas distribution facilities in six states and supply natural gas to commercial and industrial customers and electric and natural gas utilities in over 30 states.

Reportable Segments

In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our reportable segments, which are listed below. We also discuss our liquidity, capital resources and critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on these segments of the energy business. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject, among other factors.

As of December 31, 2019, reportable segments by Registrant are as follows:



Registrants	Houston Electric T&D	Indiana Electric Integrated	Natural Gas Distribution	Energy Services	Infrastructure Services	Midstream Investments	Corporate and Other
CenterPoint Energy	X	X	X	X	X	X	X
Houston Electric	X
CERC			X	X			X


•	Houston Electric T&D reportable segment includes electric transmission and distribution services that are subject to rate regulation and impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. For further information about the Houston Electric T&D reportable segment, see “Business — Our Business — Houston Electric T&D” in Item 1 of Part I of this report.

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Houston Electric T&D reportable segment includes electric transmission and distribution services that are subject to rate regulation and impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. For further information about the Houston Electric T&D reportable segment, see “Business — Our Business — Houston Electric T&D” in Item 1 of Part I of this report.


•	Indiana Electric Integrated reportable segment includes energy delivery services to electric customers and electric generation assets to serve its electric customers and optimize those assets in the wholesale power market. For further information about the Indiana Electric Integrated reportable segment, see “Business — Our Business — Indiana Electric Integrated” in Item 1 of Part I of this report.

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Indiana Electric Integrated reportable segment includes energy delivery services to electric customers and electric generation assets to serve its electric customers and optimize those assets in the wholesale power market. For further information about the Indiana Electric Integrated reportable segment, see “Business — Our Business — Indiana Electric Integrated” in Item 1 of Part I of this report.


•	Natural Gas Distribution reportable segment includes natural gas distribution services that are subject to rate regulation in CenterPoint Energy’s and CERC’s service territories, as well as home appliance maintenance and repair services to customers in Minnesota. For further information about the Natural Gas Distribution reportable segment, see “Business — Our Business — Natural Gas Distribution” in Item 1 of Part I of this report.

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Natural Gas Distribution reportable segment includes natural gas distribution services that are subject to rate regulation in CenterPoint Energy’s and CERC’s service territories, as well as home appliance maintenance and repair services to customers in Minnesota. For further information about the Natural Gas Distribution reportable segment, see “Business — Our Business — Natural Gas Distribution” in Item 1 of Part I of this report.


•	Energy Services reportable segment includes non-rate regulated natural gas sales to, and transportation and storage services, for commercial and industrial customers. For further information about the Energy Services reportable segment, see “Business — Our Business — Energy Services” in Item 1 of Part I of this report.


•	Infrastructure Services reportable segment includes underground pipeline construction and repair services. For further information about the Infrastructure Services reportable segment, see “Business — Our Business — Infrastructure Services” in Item 1 of Part I of this report.


•	Midstream Investments reportable segment includes CenterPoint Energy’s equity investment in Enable and is dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Midstream Investments.” For further information about the Midstream Investments reportable segment, see “Business — Our Business — Midstream Investments” in Item 1 of Part I of this report.

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Midstream Investments reportable segment includes CenterPoint Energy’s equity investment in Enable and is dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Midstream Investments.” For further information about the Midstream Investments reportable segment, see “Business — Our Business — Midstream Investments” in Item 1 of Part I of this report.


•	CenterPoint Energy’s Corporate and Other reportable segment includes office buildings and other real estate used for business operations, home repair protection plans to natural gas customers in Texas and Louisiana through a third party, energy performance contracting and sustainable infrastructure services and other corporate support operations CERC’s Corporate and Other reportable segment includes unallocated corporate costs and inter-segment eliminations.

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CenterPoint Energy’s Corporate and Other reportable segment includes office buildings and other real estate used for business operations, home repair protection plans to natural gas customers in Texas and Louisiana through a third party, energy performance contracting and sustainable infrastructure services and other corporate support operations CERC’s Corporate and Other reportable segment includes unallocated corporate costs and inter-segment eliminations.

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.

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.

EXECUTIVE SUMMARY

We expect our and Enable’s businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company. The majority of our revenues are generated from the transmission and delivery of electricity and the sale of natural gas by our subsidiaries. On February 1, 2019, we acquired Vectren for approximately $6 billion in cash. Through its subsidiaries, Vectren’s operations consist of utility and non-utility businesses. The utility operations include three public utilities, Indiana Gas, SIGECO and VEDO, which, in the aggregate, provide natural gas distribution and transportation services to nearly 67% of Indiana and about 20% of Ohio and electric transmission and distribution services to southwestern Indiana, including power generating and wholesale power operations. In total, these utility operations supply natural gas and electricity to over one million customers in Indiana and Ohio. The non-utility operations include Infrastructure Services and ESG. Infrastructure Services, through its wholly-owned subsidiaries, provides underground pipeline and repair services to many utilities, including our utilities, as well as other industries. ESG provides energy services through performance-based energy contracting operations and sustainable infrastructure services, such as renewables, distributed generation and combined heat and power projects. ESG assists schools, hospitals, governmental facilities and other private institutions with reducing energy and maintenance costs by upgrading their facilities with energy-efficient equipment. ESG operates throughout the United States. Concurrent with the completion of the Merger, we added two new reportable segments, Indiana Electric Integrated and Infrastructure Services. 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.

To assess our financial performance, our management primarily monitors operating income and cash flows, among other things, from our reportable segments. Within these broader financial measures, we monitor margins, interest expense, capital spending and working capital requirements. In addition to these financial measures, we also monitor a number of variables that management considers important to our reportable segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. From an operational standpoint, we monitor operation and maintenance expense, safety factors, system reliability and customer satisfaction to gauge our performance.

The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities, proceeds from commercial paper and issuances of debt and equity in the capital markets to satisfy these capital needs. We strive to maintain investment grade ratings for our securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets can also affect the availability of new capital on terms we consider attractive. In those circumstances, we may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. For example, Houston Electric 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. Despite Houston, Texas having a diverse economy, employment

in the energy industry remains important with overall Houston employment growing at a moderate rate in 2019 among various sectors. Although the Houston area represents a large part of our customer base, we have a diverse customer base throughout the eight states we serve. Each state has a unique economy and is driven by different industrial sectors. Our largest customers reflect the diversity in industries in the states across our footprint. In Minnesota, for instance, education and health services are the state’s largest sectors, whereas Arkansas has a large food manufacturing industry. Some industries are driven by population growth like education and health care, while others may be influenced by strength in the national or international economy. 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.

Also, adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for our services. Long-term national trends indicate customers have reduced their energy consumption, which could adversely affect our results. However, due to more affordable energy prices and continued economic improvement in the areas we serve, the trend toward lower usage has slowed.To the extent population growth is affected by lower energy prices and there is financial pressure on some of our customers who operate within the energy industry, there may be an impact on the growth rate of our customer base and overall demand. Multifamily residential customer growth is affected by the cyclical nature of apartment construction. Beginning in 2019, a new construction cycle in Houston helped overall residential customer growth to return to the long-term trend of 2%. Management expects residential meter growth for Houston Electric to remain in line with long term trends at approximately 2%. Typical customer growth in the jurisdictions served by the Natural Gas Distribution reportable segment is approximately 1%. CERC’s NGD customer growth was 1.3% for 2019, which is slightly higher than in previous years.

Performance of the Houston Electric T&D reportable segment and the Natural Gas Distribution reportable segment is significantly influenced by energy usage per customer, which is significantly impacted by weather conditions. For Houston Electric, revenues are generally higher during the warmer months when more electricity is used for cooling purposes. For CERC’s NGD, demand for natural gas for heating purposes is generally higher in the colder months. Therefore, we compare our results on a weather-adjusted basis.

In 2019, the Houston area experienced weather that was closer to normal compared to 2018. Although the summer months, particularly August and September, were hotter than normal, this was offset during the remaining months of the year due to milder than normal weather. While overall rainfall was higher than normal in 2019 largely due to Tropical Storm Imelda, it did not rise to the record rainfall levels experienced in 2017 that occurred largely due to Hurricane Harvey. After a return to more normal weather in 2018, our NGD service territories experienced warmer weather in 2019 in all areas except Minnesota.

Historically, both CenterPoint Energy’s TDU and CERC’s NGD have utilized weather hedges to help reduce the impact of mild weather on their financial results. CenterPoint Energy’s TDU and CERC’s NGD entered into a weather hedge for the 2018–2019 and 2019–2020 winter heating seasons in Texas where no weather normalization mechanisms exist. In CERC’s non-Texas jurisdictions, weather normalization mechanisms or decoupling in the Minnesota division help to mitigate the impact of abnormal weather on our financial results.

In Minnesota and Arkansas for CERC’s NGD, there are rate adjustment mechanisms to counter the impact of declining usage from energy efficiency improvements. In addition, in many of our service areas, particularly in the Houston area and Minnesota, as applicable to each registrant, we have benefited from growth in the number of customers, which could mitigate the effects of reduced consumption. We anticipate that this trend will continue as the regions’ economies continue to grow. The profitability of our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and natural gas distribution rates.

Sales of natural gas and electricity to residential and commercial customers by Indiana Gas, SIGECO and VEDO are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed, and as these utilities have implemented conservation programs.

In our NGD Indiana and Ohio service territories, normal temperature adjustment and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. Our NGD operations in Ohio has a straight fixed variable rate design for its residential customers. This rate design mitigates approximately 90% of the Ohio service territory’s weather risk and risk of decreasing consumption specific to its small

customer classes. While Indiana Electric has neither a normal temperature adjustment mechanism nor a decoupling mechanism, rate designs provide for a lost margin recovery mechanism that operates in tandem with conservation initiatives.

On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates. A settlement has been reached and a final order from the PUCT is expected during the first quarter of 2020. For details related to our pending and completed regulatory proceedings and orders related to the TCJA in 2019 and to date in 2020, see “—Liquidity and Capital Resources —Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

We believe the long-term outlook for ESG’s performance contracting and sustainable infrastructure opportunities remains strong with continued national focus expected on energy conservation and sustainability, renewable energy and security as power prices across the country rise and customer focus on new, efficient and clean sources of energy grows.

The regulation of natural gas pipelines and related facilities by federal and state regulatory agencies affects CenterPoint Energy’s and CERC’s businesses. In accordance with natural gas pipeline safety and integrity regulations, CenterPoint Energy and CERC are making, and will continue to make, significant capital investments in their service territories, which are necessary to help operate and maintain a safe, reliable and growing natural gas system. CenterPoint Energy’s and CERC’s compliance expenses may also increase as a result of preventative measures required under these regulations. Consequently, new rates in the areas they serve are necessary to recover these increasing costs.

Consistent with the regulatory treatment of pension costs, the Registrants defer the amount of pension expense that differs from the level of pension expense included in the Registrants’ base rates for the Electric T&D reportable segment and Natural Gas Distribution reportable segment in their Texas jurisdictions. CenterPoint Energy expects to contribute a minimum of approximately $83 million to its pension plans in 2020.

Factors Influencing Our Businesses Proposed for Divestiture

The Energy Services reportable segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis. Its operations serve customers throughout the United States. The segment is impacted by price differentials on both a regional and seasonal basis, as well as fluctuations in regional daily natural gas prices driven by weather and other market factors. While this business utilizes financial derivatives to mitigate the effects of price movements, it does not enter into risk management contracts for speculative purposes and evaluates VaR daily to monitor significant financial exposures to realized income. Energy Services experienced instances of decreased margin in 2019 due to fewer opportunities to optimize natural gas supply costs as compared to 2018. Specifically, weather-facilitated market impacts in various regions of the continental United States during the three months ended March 31, 2018 allowed Energy Services to increase its margins in the first quarter of 2018. 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.

Demand for Infrastructure Services remains high due to the aging infrastructure and evolving safety and reliability regulations across the United States. The long-term focus for Infrastructure Services is recurring work in both the distribution and transmission businesses. The timing and recurrence of large transmission projects is less predictable and may create volatility in its year-over-year results. 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.

Factors Influencing Midstream Investments (CenterPoint Energy)

The results of CenterPoint Energy’s Midstream Investments reportable segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems. These volumes depend significantly on the level of production from natural gas wells connected to Enable’s systems across a number of U.S. mid-continent markets. Aggregate production volumes are affected by the overall amount of oil and gas drilling and completion activities. Production must be maintained or increased by new drilling or other activity, because the production rate of oil and gas wells declines over time.

Enable expects its business to continue to be impacted by the trends affecting the midstream industry. Enable’s outlook is based on its management’s assumptions regarding the impact of these trends that it has developed by interpreting the information currently available to it. If Enable management’s assumptions or interpretation of available information prove to be incorrect, Enable’s future financial condition and results of operations may differ materially from its expectations.

Enable’s business is impacted by commodity prices, which have declined and otherwise experienced significant volatility in recent years. Commodity prices impact the drilling and production of natural gas and crude oil in the areas served by Enable’s systems. In addition, Enable’s processing arrangements expose it to commodity price fluctuations. Enable has attempted to mitigate the impact of commodity prices on its business by entering into hedges, focusing on contracting fee-based business and converting existing commodity-based contracts to fee-based contracts.

Enable’s long-term view is that natural gas and crude oil production in the U.S. will increase. Advancements in technology have allowed producers to efficiently extract natural gas and crude oil from tight gas formations and shale plays. As a result, the proven reserves of natural gas and crude oil in the United States have significantly increased. As proven reserves of natural gas and crude oil have continued to increase, the supply growth has outpaced demand growth, resulting in oversupply. The oversupply of natural gas and crude oil has resulted in price declines over the last year. Natural gas continues to be a critical component of energy demand in the U.S. Enable’s management believes that, although oversupply will continue in the near term, the prospects for continued natural gas demand are favorable over the long term and will be driven by population and economic growth, the continued displacement of coal-fired power plants by natural gas-fired power plants due to the price of natural gas and stricter government environmental regulations on the mining and burning of coal and the continued development of a global export market for LNG. Enable’s management believes that increasing consumption of natural gas over the long term, both within the United States and in the global export market for LNG, will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Significant Events

Proposed Divestiture of Infrastructure Services. 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.

Proposed Divestiture of CES. 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.

Regulatory Proceedings. On April 5, 2019, and subsequently adjusted in errata filings in May and June 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates. A settlement has been reached and a final order from the PUCT in the proceeding is expected during the first quarter of 2020. For details related to our pending and completed regulatory proceedings and orders related to the TCJA in 2019 and to date in 2020, see “—Liquidity and Capital Resources —Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

Merger with Vectren. On February 1, 2019, pursuant to the Merger Agreement, CenterPoint Energy consummated the previously announced Merger and acquired Vectren for approximately $6 billion in cash. For more information about the Merger, see Notes 1 and 4 to the consolidated financial statements.

Debt Transactions. In January 2019, Houston Electric issued $700 million aggregate principal amount of general mortgage bonds, in May 2019, CenterPoint Energy entered into a $1.0 billion variable rate term loan and in August 2019, CenterPoint Energy issued $1.2 billion aggregate principal amount of senior notes. For more information about the 2019 debt transactions, see Note 14 to the consolidated financial statements.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our and Enable’s future earnings and results of our and Enable’s operations will depend on or be affected by numerous factors that apply to all Registrants unless otherwise indicated including:


•	the performance of Enable, the amount of cash distributions CenterPoint Energy receives from Enable, Enable’s ability to redeem the Enable Series A Preferred Units in certain circumstances and the value of CenterPoint Energy’s interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:


◦	competitive conditions in the midstream industry, and actions taken by Enable’s customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Enable;


◦	the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;

◦

the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;


◦	the demand for crude oil, natural gas, NGLs and transportation and storage services;


◦	environmental and other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing;


◦	recording of goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;


◦	the timing of payments from Enable’s customers under existing contracts, including minimum volume commitment payments;


◦	changes in tax status; and


◦	access to debt and equity capital;


•	the expected benefits of the Merger and integration, including the outcome of shareholder litigation filed against Vectren that could reduce anticipated benefits of the Merger, as well as the ability to successfully integrate the Vectren businesses and to realize anticipated benefits and commercial opportunities;


•	the recording of impairment charges, including any impairment associated with Infrastructure Services and CES;


•	industrial, commercial and residential growth in our service territories and changes in market demand, including the demand for our non-utility products and services and effects of energy efficiency measures and demographic patterns;


•	the outcome of the pending Houston Electric rate case;


•	timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;


•	future economic conditions in regional and national markets and their effect on sales, prices and costs;


•	weather variations and other natural phenomena, including the impact of severe weather events on operations and capital;


•	state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;


•	tax legislation, including the effects of the TCJA (which includes any potential changes to interest deductibility) and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;


•	CenterPoint Energy’s and CERC’s ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;


•	the timing and extent of changes in commodity prices, particularly natural gas and coal, and the effects of geographic and seasonal commodity price differentials on CERC and Enable;


•	the ability of CenterPoint Energy’s and CERC’s non-utility business operating in the Energy Services reportable segment to effectively optimize opportunities related to natural gas price volatility and storage activities, including weather-related impacts;


•	actions by credit rating agencies, including any potential downgrades to credit ratings;


•	changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;


•	problems with regulatory approval, legislative actions, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or cancellation or in cost overruns that cannot be recouped in rates;


•	the availability and prices of raw materials and services and changes in labor for current and future construction projects;


•	local, state and federal legislative and regulatory actions or developments relating to the environment, including, among other things, those related to global climate change, air emissions, carbon, waste water discharges and the handling and

disposal of CCR that could impact the continued operation, and/or cost recovery of generation plant costs and related assets;


•	the impact of unplanned facility outages or other closures;


•	any direct or indirect effects on our or Enable’s facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, ice, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, pandemic health events or other occurrences;

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any direct or indirect effects on our or Enable’s facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, ice, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, pandemic health events or other occurrences;


•	our ability to invest planned capital and the timely recovery of our existing and future investments, including those related to Indiana Electric’s anticipated IRP;


•	our ability to successfully construct and operate electric generating facilities, including complying with applicable environmental standards and the implementation of a well-balanced energy and resource mix, as appropriate;


•	our ability to control operation and maintenance costs;


•	the sufficiency of our insurance coverage, including availability, cost, coverage and terms and ability to recover claims;


•	the investment performance of CenterPoint Energy’s pension and postretirement benefit plans;


•	commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;


•	changes in rates of inflation;


•	inability of various counterparties to meet their obligations to us;


•	non-payment for our services due to financial distress of our customers;


•	the extent and effectiveness of our and Enable’s risk management and hedging activities, including, but not limited to financial and weather hedges and commodity risk management activities;


•	timely and appropriate regulatory actions, which include actions allowing securitization, for any future hurricanes or natural disasters or other recovery of costs, including costs associated with Hurricane Harvey;


•	CenterPoint Energy’s or Enable’s potential business strategies and strategic initiatives, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses, including the proposed sales of Infrastructure Services and CES, which CenterPoint Energy and Enable cannot assure will be completed or will have the anticipated benefits to CenterPoint Energy or Enable;


•	the performance of projects undertaken by our non-utility businesses and the success of efforts to realize value from, invest in and develop new opportunities and other factors affecting those non-utility businesses, including, but not limited to, the level of success in bidding contracts, fluctuations in volume and mix of contracted work, mix of projects received under blanket contracts, failure to properly estimate cost to construct projects or unanticipated cost increases in completion of the contracted work, changes in energy prices that affect demand for construction services and projects and cancellation and/or reductions in the scope of projects by customers and obligations related to warranties and guarantees;

•

the performance of projects undertaken by our non-utility businesses and the success of efforts to realize value from, invest in and develop new opportunities and other factors affecting those non-utility businesses, including, but not limited to, the level of success in bidding contracts, fluctuations in volume and mix of contracted work, mix of projects received under blanket contracts, failure to properly estimate cost to construct projects or unanticipated cost increases in completion of the contracted work, changes in energy prices that affect demand for construction services and projects and cancellation and/or reductions in the scope of projects by customers and obligations related to warranties and guarantees;


•	acquisition and merger activities involving us or our competitors, including the ability to successfully complete merger, acquisition and divestiture plans;


•	our or Enable’s ability to recruit, effectively transition and retain management and key employees and maintain good labor relations;


•	the outcome of litigation;


•	the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;


•	changes in technology, particularly with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation;


•	the impact of alternate energy sources on the demand for natural gas;


•	the timing and outcome of any audits, disputes and other proceedings related to taxes;


•	the effective tax rates;


•	the transition to a replacement for the LIBOR benchmark interest rate;


•	the effect of changes in and application of accounting standards and pronouncements; and


•	other factors discussed in “Risk Factors” in Item 1A of this report and in other reports that the Registrants file from time to time with the SEC.

CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS



	Year Ended December 31,
	2019			2018			2017
	(in millions, except per share amounts)
Revenues	$	12,301		$	10,589		$	9,614
Expenses	11,075			9,758			8,478
Operating Income	1,226			831			1,136
Gain (Loss) on Marketable Securities	282			(22		)	7
Gain (Loss) on Indexed Debt Securities	(292		)	(232		)	49
Interest and Other Finance Charges	(528		)	(361		)	(313		)
Interest on Securitization Bonds	(39		)	(59		)	(77		)
Equity in Earnings of Unconsolidated Affiliates, net	230			307			265
Other Income (Expense), net	50			50			(4		)
Income Before Income Taxes	929			514			1,063
Income Tax Expense (Benefit)	138			146			(729		)
Net Income	791			368			1,792
Preferred Stock Dividend Requirement	117			35			—
Income Available to Common Shareholders	$	674		$	333		$	1,792

Basic Earnings Per Common Share	$	1.34		$	0.74		$	4.16

Diluted Earnings Per Common Share	$	1.33		$	0.74		$	4.13

2019 Compared to 2018

Net Income. CenterPoint Energy reported income available to common shareholders of $674 million ($1.33 per diluted common share) for 2019 compared to $333 million ($0.74 per diluted common share) for 2018.

The increase in income available to common shareholders of $341 million was primarily due to the following key factors:


•	a $395 million increase in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment;


•	a $304 million increase in gain on marketable securities, included in Other Income (Expense), net shown above;


•	a $20 million decrease in interest expense related to lower outstanding balances of the Securitization Bonds; and


•	an $8 million decrease in income tax expense primarily due to the lower effective tax rate, as explained below, partially offset by higher income before income taxes.

These increases were partially offset by:


•	a $167 million increase in interest expense, primarily as a result of higher outstanding long-term debt used to finance the Merger and additional long-term debt acquired in the Merger, discussed further in Notes 4 and 14 to the consolidated financial statements;


•	an $82 million increase in preferred stock dividend requirements primarily as a result of the Merger;


•	a $77 million decrease to equity in earnings from the investment in Enable, which includes CenterPoint Energy’s share ($46 million) of Enable’s goodwill impairment charge recorded in the fourth quarter of 2019 discussed further in Note 11 to the consolidated financial statements; and


•	a $60 million increase in losses on the underlying value of the indexed debt securities related to the ZENS included in Other Income (Expense), net shown above.

Income Tax Expense. CenterPoint Energy reported an effective tax rate of 15% and 28% for the years ended December 31, 2019 and 2018, respectively. The lower effective tax rate of 15% is due to an increase in the amount of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, the effect of state law changes that resulted in the remeasurement of state deferred taxes, and the impact of the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

2018 Compared to 2017

Net Income. CenterPoint Energy reported income available to common shareholders of $333 million ($0.74 per diluted common share) for 2018 compared to $1,792 million ($4.13 per diluted common share) for 2017.

The decrease in income available to common shareholders of $1,459 million was primarily due to the following key factors:

•

an $875 million increase in income tax expense, resulting from a reduction in income tax expense of $1,113 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $238 million decrease in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018 and lower income before income taxes year over year;


•	a $305 million decrease in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment;


•	a $281 million increase in losses on indexed debt securities related to the ZENS, resulting from a loss of $11 million from Meredith’s acquisition of Time in March 2018, a loss of $242 million from AT&T’s acquisition of TW in June 2018 and reduced gains of $28 million in the underlying value of the indexed debt securities;


•	a $48 million increase in interest expense primarily due to higher outstanding other long-term debt and the amortization of Bridge Facility fees of $24 million;


•	a $35 million increase in preferred stock dividend requirements; and


•	a $29 million increase in losses on marketable securities.

These decreases were partially offset by:


•	a $42 million increase in equity earnings from the investment in Enable, discussed further in Note 11 to the consolidated financial statements;

a $25 million increase in interest income on investments included in Other Income (Expense), net shown above;


•	a $17 million decrease in the non-service cost components of net periodic pension and post-retirement costs included in Other Income (Expense), net shown above;

an $18 million decrease in interest expense related to lower outstanding balances of the Securitization Bonds;
a $6 million increase in miscellaneous other non-operating income included in Other Income (Expense), net shown above;


•	a $4 million increase in dividend income on CenterPoint Energy’s ZENS-Related Securities included in Other Income (Expense), net shown above; and

a $2 million increase in gains on interest rate economic hedges included in Other Income (Expense), net shown above.

Income Tax Expense. CenterPoint Energy reported an effective tax rate of 28% and (69)% for the years ended December 31, 2018 and 2017, respectively. The effective tax rate of 28% is primarily due to the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018 as prescribed by the TCJA and the amortization of EDIT. These decreases were partially offset by an increase to the effective tax rate as a result of the establishment of a valuation allowance on certain state net operating loss deferred tax assets that are no longer expected to be utilized prior to expiration after the Internal Spin. The effective tax rate was also increased for state law changes that resulted in remeasurement of state deferred taxes in those jurisdictions.

HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS

Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets.



	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	2,990		$	3,234		$	2,998
Expenses	2,372			2,609			2,361
Operating Income	618			625			637
Interest and other finance charges	(164		)	(138		)	(128		)
Interest on Securitization Bonds	(39		)	(59		)	(77		)
Other income (expense), net	21			(3		)	(8		)
Income before income taxes	436			425			424
Income tax expense (benefit)	80			89			(9		)
Net income	$	356		$	336		$	433

2019 Compared to 2018

Net Income. Houston Electric reported net income of $356 million for 2019 compared to $336 million for 2018.

The increase of $20 million in net income was primarily due to the following key factors:


•	a $24 million increase in Other income (expense), net primarily due to increased interest income of $22 million mainly from investments in the CenterPoint Energy money pool;


•	a $14 million increase in TDU operating income discussed below in Results of Operations by Reportable Segment, exclusive of an $8 million gain from weather hedges recorded at CenterPoint Energy; and


•	a $9 million decrease in income tax expense primarily due to the lower effective tax rate, as explained below, partially offset by higher income before income taxes.

These increases to net income were partially offset by a $26 million increase in interest expense due to higher outstanding other long-term debt.

Income Tax Expense. Houston Electric reported an effective tax rate of 18% and 21% for the years ended December 31, 2019 and 2018, respectively. The lower effective tax rate of 18% is due to an increase in the amount of amortization of the net regulatory EDIT liability as decreed by regulators.

2018 Compared to 2017

Net Income. Houston Electric reported net income of $336 million for 2018 compared to net income of $433 million for 2017.

The decrease of $97 million in net income was primarily due to the following key factors:


•	a $98 million increase in income tax expense, resulting from a reduction in income tax expense of $158 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $60 million decrease in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018; and


•	a $10 million increase in interest expense due to higher outstanding other long-term debt.

These decrease in net income were partially offset by the following:


•	a $5 million decrease in non-service cost components of net periodic pension and post-retirement costs included in Other expense, net shown above; and


•	an $8 million increase in TDU operating income resulting from a $7 million increase discussed below in Results of Operations by Reportable Segment and increased usage of $1 million, primarily due to a return to more normal weather, which was not offset by the weather hedge loss recorded on CenterPoint Energy.

Income Tax Expense. Houston Electric reported an effective tax rate of 21% and (2)% for the years ended December 31, 2018 and 2017, respectively. The effective tax rate of 21% is primarily due to the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018 as prescribed by the TCJA and the amortization of EDIT. See Note 15 to the consolidated financial statements for a more in-depth discussion of the 2018 impacts of the TCJA.

CERC CONSOLIDATED RESULTS OF OPERATIONS

CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities as well as natural gas basis differentials. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, competition in CERC’s various business operations, the effectiveness of CERC’s risk management activities, debt service costs and income tax expense.



	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	6,570		$	7,343		$	6,603
Expenses	6,220			7,121			6,136
Operating Income	350			222			467
Interest and other finance charges	(116		)	(122		)	(123		)
Other expense, net	(8		)	(8		)	(25		)
Income from continuing operations before income taxes	226			92			319
Income tax expense (benefit)	14			22			(265		)
Income from continuing operations	212			70			584
Income from discontinued operations, net of tax	—			138			161
Net Income	$	212		$	208		$	745

2019 Compared to 2018

Net Income. CERC reported net income of $212 million for 2019 compared to $208 million for 2018.

The increase in net income of $4 million was primarily due to the following key factors:


•	a $128 million increase in operating income discussed below in Results of Operations by Reportable Segment;


•	an $8 million decrease in income tax expense due to the lower effective tax rate, as explained below, partially offset by higher income from continuing operations ; and


•	a $6 million decrease in interest and other finance charges.

These increases were partially offset by a $138 million decrease in income from discontinued operations, net of tax, discussed further in Notes 11 and 15 to the consolidated financial statements.

Income Tax Expense. CERC’s effective tax rate reported on income from continuing operations was 6% and 24% for the years ended December 31, 2019 and 2018, respectively. The lower effective tax rate of 6% on income from continuing operations is due to an increase in the amount of amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, the effect of state law changes that resulted in the remeasurement of state deferred taxes, and the impact of the reduction in valuation allowances on certain state net operating losses that are now expected to be realized.

2018 Compared to 2017

Net Income. CERC reported net income of $208 million for 2018 compared to net income of $745 million for 2017.

The decrease in net income of $537 million was primarily due to the following key factors:

•

a $287 million increase in income tax expense, resulting from a reduction in income tax expense of $396 million due to tax reform in 2017, discussed further in Note 15 to the consolidated financial statements, offset by a $109 million decrease in income tax expense primarily due to lower income from continuing operations and a reduction in the corporate income tax rate resulting from the TCJA in 2018;


•	a $245 million decrease in operating income, discussed below by reportable segment in Results of Operations by Reportable Segment; and


•	a $23 million decrease in income from discontinued operations, net of tax, due to the Internal Spin discussed further in Note 11 to the consolidated financial statements.

These decreases were partially offset by:


•	a $12 million decrease in the non-service cost components of net periodic pension and post-retirement costs included in Other expense, net shown above;


•	a $5 million increase in miscellaneous other non-operating income included in Other expense, net shown above; and


•	a $1 million decrease in interest expense due to lower outstanding long-term debt.

Income Tax Expense. CERC’s effective tax rate reported on income from continuing operations was 24% and (83)% for the years ended December 31, 2018 and 2017, respectively. The effective tax rate of 24% on income from continuing operations is primarily due to the reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018 as prescribed by the TCJA and the amortization of EDIT. See Note 15 to the consolidated financial statements for a more in-depth discussion of the 2018 impacts of the TCJA.

RESULTS OF OPERATIONS BY REPORTABLE SEGMENT

The following table presents operating income (loss) for each reportable segment for 2019, 2018 and 2017. Included in revenues by reportable segment below are intersegment sales, which are accounted for as if the sales were to third parties at current market prices. These revenues are eliminated during consolidation. See Note 19 to the consolidated financial statements for details of reportable segments by registrant.

Operating Income (Loss) by Reportable Segment



	Year Ended December 31,
	2019			2018			2017
	(in millions)
CenterPoint Energy
Houston Electric T&D (1)	$	624		$	623		$	636
Indiana Electric Integrated	90			—			—
Natural Gas Distribution	408			266			348
Energy Services (2)	32			(47		)	126
Infrastructure Services (3)	95			—			—
Corporate and Other	(23		)	(11		)	26
Total CenterPoint Energy Consolidated Operating Income	$	1,226		$	831		$	1,136
Houston Electric
Houston Electric T&D (1)	$	618		$	625		$	637
CERC
Natural Gas Distribution	$	316		$	266		$	348
Energy Services (2)	32			(47		)	126
Other Operations	2			3			(7		)
Total CERC Consolidated Operating Income	$	350		$	222		$	467

(1)

Operating income for CenterPoint Energy’s Houston Electric T&D reportable segment differs from operating income for Houston Electric due to weather hedge gains (losses) recorded at CenterPoint Energy that are not recorded at Houston Electric. Weather hedge gains (losses) of $6 million, $(2) million and $(1) million were recorded at CenterPoint Energy’s Houston Electric T&D reportable segment for the years ended December 31, 2019, 2018 and 2017, respectively. See Note 9(a) to the consolidated financial statements for more information on the weather hedge.


(2)	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.


(3)	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.

Houston Electric T&D (CenterPoint Energy and Houston Electric)

The following table provides summary data of the Houston Electric T&D reportable segment:



	Year Ended December 31,
	2019		2018		2017
Revenues:	(in millions, except throughput and customer data)
TDU	$	2,684	$	2,638	$	2,588
Bond Companies	312		594		409
Total revenues	2,996		3,232		2,997
Expenses:
Operation and maintenance, excluding Bond Companies	1,470		1,444		1,397
Depreciation and amortization, excluding Bond Companies	377		386		395
Taxes other than income taxes	247		240		235
Bond Companies	278		539		334
Total expenses	2,372		2,609		2,361
Operating Income (1)	$	624	$	623	$	636
Operating Income:
TDU	$	590	$	568	$	561
Bond Companies (2)	34		55		75
Total segment operating income	$	624	$	623	$	636
Throughput (in GWh):
Residential	30,334		30,405		29,703
Total	92,180		90,409		88,636
Number of metered customers at end of period:
Residential	2,243,188		2,198,225		2,164,073
Total	2,534,286		2,485,370		2,444,299

(1)


(2)	Operating income from the Bond Companies, together with $5 million, $4 million and $2 million of interest income for the years ended December 31, 2019, 2018 and 2017, respectively, are necessary to pay interest on the Securitization Bonds.

2019 Compared to 2018*.* The Houston Electric T&D reportable segment reported operating income of $624 million for 2019, consisting of $590 million from the TDU and $34 million related to the Bond Companies. For 2018, operating income totaled $623 million, consisting of $568 million from the TDU and $55 million related to the Bond Companies.

TDU operating income increased $22 million primarily due to the following key factors:


•	higher transmission-related revenues of $74 million, exclusive of the TCJA impact mentioned below, partially offset by higher transmission costs billed by transmission providers of $57 million;


•	decreased operation and maintenance expenses of $34 million, net of $10 million of Merger-related severance costs and $12 million of write offs for rate case expenses associated with the settlement of Houston Electric’s rate case, primarily due to lower labor and benefits costs and lower support services costs;


•	customer growth of $28 million from the addition of over 48,000 customers;


•	rate increases of $20 million related to distribution capital investments, exclusive of the TCJA impact mentioned below; and


•	higher miscellaneous revenues of $14 million primarily related to right-of-way revenues.

The increase in operating income was partially offset by the following:


•	lower equity return of $29 million, primarily related to the annual true-up of transition charges to correct over-collections that occurred during the preceding 12 months and due to the winding up of Transition Bond Company II;


•	higher depreciation and amortization expense, primarily because of ongoing additions to plant in service, and other taxes of $26 million;


•	lower usage of $20 million due to lower residential use per customer and lower demand in our large commercial and small industrial classes in part due to less favorable weather in early 2019; and


•	lower revenue of $15 million related to the impact of the TCJA.

Lower depreciation and amortization expenses related to AMS of $28 million were offset by a corresponding decrease in related revenues.

2018 Compared to 2017*.* The Houston Electric T&D reportable segment reported operating income of $623 million for 2018, consisting of $568 million from the TDU and $55 million related to the Bond Companies. For 2017, operating income totaled $636 million, consisting of $561 million from the TDU and $75 million related to the Bond Companies.

TDU operating income increased $7 million primarily due to the following key factors:


•	higher transmission-related revenues of $37 million, exclusive of the TCJA impact, and lower transmission costs billed by transmission providers of $32 million;


•	customer growth of $31 million from the addition of over 41,000 customers;


•	rate increases of $36 million related to distribution capital investments, exclusive of the TCJA;


•	higher equity return of $32 million, primarily related to the annual true-up of transition charges correcting for under-collections that occurred during the preceding 12 months;


•	higher miscellaneous revenues of $9 million largely due to right-of-way and fiber and wireless revenues; and


•	higher usage of $8 million, primarily due to a return to more normal weather.

The increase to operating income was partially offset by the following:


•	increased operation and maintenance expenses of $79 million, excluding transmission costs billed by transmission providers, primarily due to the following:


◦	contract services of $24 million, largely due to increased resiliency spend and services related to fiber and wireless;


◦	support services of $23 million, primarily related to technology projects;


◦	labor and benefits costs of $14 million;


◦	other miscellaneous operation and maintenance expenses of $12 million; and


◦	damage claims from third parties of $6 million;


•	lower revenues of $79 million due to the recording of a regulatory liability and a corresponding decrease to revenue of $31 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rate and the revenues

that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower revenues of $48 million due to lower transmission and distribution rate filings as a result of the TCJA; and


•	higher depreciation and amortization expense, primarily because of ongoing additions to plant in service, and other taxes of $17 million.

Lower depreciation and amortization expenses related to AMS of $21 million were offset by a corresponding decrease in related revenues.

Indiana Electric Integrated (CenterPoint Energy)

The following table provides summary data of CenterPoint Energy’s Indiana Electric Integrated reportable segment:



	Year Ended December 31, 2019 (1)
	(in millions, except throughput and customer data)
Revenues	$	523
Expenses:
Utility natural gas, fuel and purchased power	149
Operation and maintenance	179
Depreciation and amortization	91
Taxes other than income taxes	14
Total expenses	433
Operating Income	$	90
Throughput (in GWh):
Retail	4,310
Wholesale	376
Total	4,686
Number of metered customers at end of period:
Residential	128,947
Total	147,942


(1)	Represents February 1, 2019 through December 31, 2019 results only due to the Merger.

2019 Compared to 2018*.* The Indiana Electric Integrated reportable segment reported operating income of $90 million for 2019, which includes operation and maintenance expenses of $21 million for Merger-related severance and incentive compensation costs. These results are not comparable to 2018 as this reportable segment was acquired in the Merger as discussed in Note 4 to the consolidated financial statements.

Natural Gas Distribution (CenterPoint Energy)

The following table provides summary data of CenterPoint Energy’s Natural Gas Distribution reportable segment:



	Year Ended December 31,
	2019		2018		2017
	(in millions, except throughput and customer data)
Revenues	$	3,683	$	2,967	$	2,639
Expenses:
Utility natural gas, fuel and purchased power	1,617		1,467		1,164
Operation and maintenance	1,036		803		722
Depreciation and amortization	417		277		260
Taxes other than income taxes	205		154		145
Total expenses	3,275		2,701		2,291
Operating Income	$	408	$	266	$	348
Throughput (in Bcf):
Residential	246		186		151
Commercial and industrial	458		285		261
Total Throughput	704		471		412
Number of customers at end of period:
Residential	4,252,361		3,246,277		3,213,140
Commercial and industrial	349,749		260,033		256,651
Total	4,602,110		3,506,310		3,469,791

2019 Compared to 2018*.* CenterPoint Energy’s Natural Gas Distribution reportable segment reported operating income of $408 million for 2019 compared to $266 million for 2018.

Operating income increased $142 million primarily as a result of the following key factors:


•	a $91 million increase in operating income associated with the natural gas businesses acquired in the Merger for the period from February 1, 2019 through December 31, 2019, which includes $45 million in Merger-related severance and incentive compensation costs, as well as the addition of over 1 million customers in Indiana and Ohio;


•	a $30 million increase in revenues for weather and usage, partially driven by the timing of a decoupling mechanism in Minnesota in CERC’s NGD service territory;


•	a $14 million increase in revenues associated with customer growth from the addition of over 42,000 new customers in CERC’s NGD service territories;


•	a $12 million increase in rates, exclusive of the TCJA impacts discussed below, from rate filings in CERC’s NGD service territories; and


•	a $6 million increase in revenue due to a reduction in TCJA-related revenue offsets that were recorded in 2018 in CERC’s NGD service territories.

The increase in operating income was partially offset by the following:


•	increased depreciation and amortization expense of $13 million, due to ongoing additions to plant-in-service in CERC’s NGD service territories; and


•	higher operation and maintenance expenses of $1 million, consisting of $10 million of Merger-related severance and incentive compensation costs associated with CERC’s NGD, which were offset by a $9 million decline in materials and supplies, contracts and services and bad debt expenses.

Decreased operation and maintenance expense related to energy efficiency programs of $14 million and increased other taxes expense related to gross receipt taxes of $2 million were offset by a corresponding decrease and increase in the related revenues in CERC’s NGD service territories, respectively.

2018 Compared to 2017*.* CenterPoint Energy’s Natural Gas Distribution reportable segment reported operating income of $266 million for 2018 compared to $348 million for 2017.

Operating income decreased $82 million primarily as a result of the following key factors:

•

lower revenue of $47 million, associated with the recording of a regulatory liability and a corresponding decrease to revenue in certain jurisdictions of $14 million reflecting the difference in revenues collected under customer rates at the pre-TCJA tax rates and the revenues that would have been collected had rates been adjusted to the lower corporate tax rate upon TCJA enactment and lower filing amounts of $33 million associated with the lower corporate tax rate as a result of the TCJA in CERC’s NGD service territories;


•	higher operation and maintenance expenses of $41 million in CERC’s NGD service territories, primarily consisting of:


◦	materials and supplies, contracts and services and bad debt expenses of $15 million;


◦	support services expenses of $16 million, primarily related to technology projects;


◦	and other miscellaneous operation and maintenance expenses of $10 million;


•	higher labor and benefits costs of $30 million, resulting from the recording in 2017 of regulatory assets (and a corresponding reduction in expense) to recover $16 million of prior post-retirement expenses in future rates established in the Texas Gulf rate order and additional maintenance activities in CERC’s NGD service territories;


•	increased depreciation and amortization expense of $17 million, primarily due to ongoing additions to plant-in-service in CERC’s NGD service territories;


•	decreased revenue of $10 million, primarily driven by timing of weather normalization adjustments in CERC’s NGD service territories; and


•	higher other taxes of $2 million, primarily due to higher property taxes in CERC’s NGD service territories.

The decrease in operating income was partially offset by:


•	rate increases of $46 million, primarily in the Texas, Minnesota and Arkansas jurisdictions, exclusive of the TCJA impact discussed above in CERC’s NGD service territories;


•	an increase in non-volumetric revenues of $10 million in CERC’s NGD service territories; and


•	a $10 million increase associated with customer growth from the addition of over 36,000 customers in CERC’s NGD service territories.

Increased operation and maintenance expense related to energy efficiency programs of $10 million and increased other taxes expense related to gross receipt taxes of $7 million were offset by a corresponding increase in the related revenues in CERC’s NGD service territories.

Natural Gas Distribution (CERC)

The following table provides summary data of CERC’s Natural Gas Distribution reportable segment:



	Year Ended December 31,
	2019		2018		2017
	(in millions, except throughput and customer data)
Revenues	$	2,951	$	2,967	$	2,639
Expenses:
Natural gas	1,395		1,467		1,164
Operation and maintenance	790		803		722
Depreciation and amortization	289		277		260
Taxes other than income taxes	161		154		145
Total expenses	2,635		2,701		2,291
Operating Income	$	316	$	266	$	348
Throughput (in Bcf):
Residential	188		186		151
Commercial and industrial	292		285		261
Total Throughput	480		471		412
Number of customers at end of period:
Residential	3,287,343		3,246,277		3,213,140
Commercial and industrial	260,872		260,033		256,651
Total	3,548,215		3,506,310		3,469,791

2019 Compared to 2018*.* CERC’s Natural Gas Distribution reportable segment reported operating income of $316 million for 2019 compared to $266 million for 2018.

Operating income increased $50 million primarily as a result of the following key factors:


•	a $30 million increase in revenues for weather and usage, partially driven by the timing of a decoupling mechanism in Minnesota;


•	a $14 million increase in revenues associated with customer growth from the addition of over 42,000 new customers;


•	a $12 million increase in rates, exclusive of the TCJA impacts discussed below; and


•	a $6 million increase in revenue due to a reduction in TCJA-related revenue offsets that were recorded in 2018.

The increase in operating income was partially offset by the following:


•	increased depreciation and amortization expense of $13 million, due to ongoing additions to plant-in-service in CERC’s NGD service territories; and


•	higher operation and maintenance expenses of $1 million, consisting of $10 million of Merger-related severance and incentive compensation costs, which were offset by a $9 million decline in materials and supplies, contracts and services and bad debt expenses.

2018 Compared to 2017*.* The CERC’s Natural Gas Distribution reportable segment reported operating income of $266 million for 2018 compared to $348 million for 2017.

Operating income decreased $82 million primarily as a result of the following key factors:

•


•	higher operation and maintenance expenses of $41 million, primarily consisting of:


◦	materials and supplies, contracts and services and bad debt expenses of $15 million;


◦	support services expenses of $16 million, primarily related to technology projects;


◦	and other miscellaneous operation and maintenance expenses of $10 million;


•	higher labor and benefits costs of $30 million, resulting from the recording in 2017 of regulatory assets (and a corresponding reduction in expense) to recover $16 million of prior post-retirement expenses in future rates established in the Texas Gulf rate order and additional maintenance activities;


•	increased depreciation and amortization expense of $17 million, primarily due to ongoing additions to plant-in-service;


•	decreased revenue of $10 million, primarily driven by timing of weather normalization adjustments; and


•	higher other taxes of $2 million, primarily due to higher property taxes.

The decrease in operating income was partially offset by:


•	rate increases of $46 million, primarily in the Texas, Minnesota and Arkansas jurisdictions, exclusive of the TCJA impact discussed above;


•	an increase in non-volumetric revenues of $10 million; and


•	a $10 million increase associated with customer growth from the addition of over 36,000 customers.

Energy Services (CenterPoint Energy and CERC)

The following table provides summary data of the Energy Services reportable segment:



	Year Ended December 31,
	2019		2018			2017
	(in millions, except throughput and customer data)
Revenues	$	3,782	$	4,521		$	4,049
Expenses:
Natural gas	3,588		4,453			3,816
Operation and maintenance	96		96			86
Depreciation and amortization	16		16			19
Taxes other than income taxes	2		3			2
Goodwill impairment	48		—			—
Total expenses	3,750		4,568			3,923
Operating Income (Loss)	$	32	$	(47	)	$	126

Timing impacts related to mark-to-market gain (loss) (1)	$	39	$	(110	)	$	79

Throughput (in Bcf)	1,305		1,355			1,200

Number of customers at end of period (2)	31,000		30,000			31,000


(1)	Includes the change in unrealized mark-to-market value and the impact from derivative assets and liabilities acquired through the purchase of Continuum and AEM.


(2)	These numbers do not include approximately 66,000, 65,000 and 72,000 natural gas customers as of December 31, 2019, 2018 and 2017, respectively, that are under residential and small commercial choice programs invoiced by their host utility.

2019 Compared to 2018*.* The Energy Services reportable segment reported operating income of $32 million for 2019 compared to an operating loss of $47 million for 2018.

Operating income increased $79 million as a result of the following:


•	a $149 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins.

The increase in operating income was partially offset by the following:


•	a $48 million goodwill impairment charge. See Note 6 to the consolidated financial statements for further information; and


•	a $22 million decrease in margin due to fewer opportunities to optimize natural gas costs relative to 2018, primarily in the first quarter of 2019. Weather-driven market impacts in various regions of the continental United States provided increased margins during the first quarter of 2018 which were not repeated in 2019.

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.

2018 Compared to 2017*.* The Energy Services reportable segment reported an operating loss of $47 million for 2018 compared to operating income of $126 million for 2017.

Operating income decreased $173 million as a result of the following key factors:


•	a $189 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins; and


•	a $10 million increase in operation and maintenance expenses, attributable to increased technology expenses, higher contract and services expense related to pipeline integrity testing, higher support services and legal expenses.

The decrease in operating income was partially offset by the following:

•

a $22 million increase in margin due to increased opportunities to optimize natural gas supply costs through storage and transportation capacity, primarily in the first quarter of 2018, and incremental volumes from customers. Realized commercial opportunities attributable to the Continuum and AEM acquisitions and colder than normal weather in several regions of the United States, primarily in the first quarter of 2018, drove incremental sales volumes; and


•	a $5 million increase in margin due to increased revenues from energy delivery to customers through CEIP interconnect projects and MES’ portable natural gas supply services.

Infrastructure Services (CenterPoint Energy)

The following table provides summary data of the Infrastructure Services reportable segment:



	Year Ended December 31, 2019 (1)
	(in millions, except throughput and customer data)
Revenues	$	1,190
Expenses:
Non-utility cost of revenues, including natural gas	309
Operation and maintenance	734
Depreciation and amortization	50
Taxes other than income taxes	2
Total expenses	1,095
Operating Income	$	95
Backlog at period end (2):
Blanket contracts (3)	$	628
Bid contracts (4)	254
Total	$	882


(1)	Represents February 1, 2019 through December 31, 2019 results only due to the Merger.


(2)	Backlog represents the amount of revenue Infrastructure Services expects to realize from work to be performed on uncompleted contracts in the next twelve months, including new contractual agreements on which work has not begun. Infrastructure Services operates primarily under two types of contracts, blanket contracts and bid contracts.

(3)

Under blanket contracts, customers are not contractually committed to specific volumes of services; however, Infrastructure Services expects to be chosen to perform work needed by a customer in a given time frame. These contracts are typically awarded on an annual or multi-year basis. For blanket work, backlog represents an estimate of the amount of revenue that Infrastructure Services expects to realize from work to be performed in the next twelve months on existing contracts or contracts management expects to be renewed or awarded.


(4)	Using bid contracts, customers are contractually committed to a specific service to be performed for a specific price, whether in total for a project or on a per unit basis.

2019 Compared to 2018*.* The Infrastructure Services reportable segment reported operating income of $95 million for 2019, which includes $13 million for Merger-related severance and incentive compensation costs, $19 million of Merger-related

amortization of intangibles for construction backlog recorded in Non-utility cost of revenues, including natural gas, and $11 million of Merger-related intangibles amortization recorded in depreciation and amortization. These results are not comparable to 2018 as this reportable segment was acquired in the Merger as discussed in Note 4 to the consolidated financial statements.

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.

Midstream Investments (CenterPoint Energy)

The following table provides pre-tax equity income of the Midstream Investments reportable segment:



	Year Ended December 31,
	2019		2018		2017
	(in millions)
Equity earnings from Enable, net (1)	$	229	$	307	$	265


(1)	Equity earnings from Enable, net for the year ended December 31, 2019 were reduced by CenterPoint Energy’s share, $46 million, of Enable’s goodwill impairment charge of $86 million recorded in the fourth quarter of 2019.

Corporate and Other (CenterPoint Energy)

The following table shows the operating income (loss) of CenterPoint Energy’s Corporate and Other reportable segment:



	Year Ended December 31,
	2019			2018			2017
	(in millions)
Revenues	$	300		$	15		$	14
Expenses:
Non-utility cost of revenues, including natural gas	218			—			—
Operation and maintenance	32			(16		)	(54		)
Depreciation and amortization	66			33			33
Taxes other than income taxes	7			9			9
Total expenses	323			26			(12		)
Operating Income (Loss)	$	(23	)	$	(11	)	$	26

2019 Compared to 2018*.* CenterPoint Energy’s Corporate and Other reportable segment reported an operating loss of $23 million for 2019 compared to an operating loss of $11 million for 2018.

Operating loss increased $12 million primarily due to a $20 million increase in operation and maintenance expenses for Merger-related transaction and integration costs incurred by CenterPoint Energy corporate.

The increase in operating loss was partially offset by:

operating income of $4 million associated with ESG, which was acquired in the Merger, for the period February 1, 2019 through December 31, 2019, including $2 million for Merger-related severance and incentive compensation costs, $5 million of Merger-related amortization of intangibles recorded in non-utility cost of revenues, including natural gas and $5 million of Merger-related intangibles amortization recorded in depreciation and amortization; and
a $3 million property tax refund.

2018 Compared to 2017*.* CenterPoint Energy’s Corporate and Other reportable segment reported an operating loss of $11 million for 2018 compared to operating income of $26 million for 2017. Operating income decreased $37 million primarily due to costs related to the Merger.

Corporate and Other (CERC)

The following table shows the operating income (loss) of CERC’s Corporate and Other reportable segment:



	Year Ended December 31,
	2019		2018			2017
	(in millions)
Revenues	$	5	$	1		$	—
Expenses	3		(2		)	7
Operating Income (Loss)	$	2	$	3		$	(7	)

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2019, 2018 and 2017 is as follows:



	Year Ended December 31,
	2019									2018									2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Cash provided by (used in):
Operating activities	$	1,638		$	918		$	466		$	2,136		$	1,115		$	814		$	1,417		$	905		$	278
Investing activities	(8,421		)	(1,495		)	(662		)	(1,207		)	(911		)	(697		)	(1,257		)	(776		)	(346		)
Financing activities	2,776			442			173			3,053			(108		)	(104		)	(245		)	(236		)	79

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities:



	Year Ended December 31,
	2019 compared to 2018									2018 compared to 2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Changes in net income after adjusting for non-cash items	$	299		$	(234	)	$	180		$	(63	)	$	154		$	(243	)
Changes in working capital	(856		)	60			(307		)	604			57			595
Change in equity in earnings of unconsolidated affiliates	77			—			—			(42		)	—			—
Change in distributions from unconsolidated affiliates (1)	(6		)	—			—			267			—			—
Changes related to discontinued operations (2)	—			—			(176		)	—			—			176
Higher pension contribution	(40		)	—			—			(21		)	—			—
Other	28			(23		)	(45		)	(26		)	(1		)	8
	$	(498	)	$	(197	)	$	(348	)	$	719		$	210		$	536


(1)	This change is partially offset by the change in distributions from Enable in excess of cumulative earnings in investing activities noted in the table below.


(2)	See Notes 2(c) and 11 to the consolidated financial statements for a discussion of CERC’s discontinued operations.

Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities:



	Year Ended December 31,
	2019 compared to 2018									2018 compared to 2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Proceeds from the sale of marketable securities	$	(398	)	$	—		$	—		$	398		$	—		$	—
Proceeds from the sale of assets	5			—			—			—			—			—
Purchase of investments	(6		)	—			—			—			—			—
Acquisitions, net of cash acquired	(5,991		)	—			—			132			—			132
Net change in capital expenditures (1)	(855		)	(103		)	(143		)	(225		)	(47		)	(120		)
Net change in notes receivable from unconsolidated affiliates	—			(481		)	228			—			(96		)	(114		)
Change in distributions from Enable in excess of cumulative earnings	12			—			—			(267		)	—			—
Changes related to discontinued operations (2)	—			—			(47		)	—			—			(250		)
Other	19			—			(3		)	12			8			1
	$	(7,214	)	$	(584	)	$	35		$	50		$	(135	)	$	(351	)


(1)	The increase in capital expenditures in 2019 primarily resulted from businesses acquired in the Merger.


(2)	See Notes 2(c) and 11 to the consolidated financial statements for a discussion of CERC’s discontinued operations.

Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities:



	Year Ended December 31,
	2019 compared to 2018									2018 compared to 2017
	CenterPoint Energy			Houston Electric			CERC			CenterPoint Energy			Houston Electric			CERC
	(in millions)
Net changes in commercial paper outstanding	$	3,434		$	—		$	855		$	(1,892	)	$	—		$	(1,017	)
Proceeds from issuances of preferred stock	(1,740		)	—			—			1,740			—			—
Proceeds from issuance of Common Stock	(1,844		)	—			—			1,844			—			—
Net changes in long-term debt outstanding, excluding commercial paper	(397		)	274			(599		)	2,126			77			851
Net changes in reacquired debt	—			—			—			5			—			5
Net changes in debt issuance costs	27			(4		)	5			(34		)	(1		)	(1		)
Net changes in short-term borrowings	39			—			39			(43		)	—			(43		)
Distributions to ZENS note holders	398			—			—			(398		)	—			—
Increased payment of Common Stock dividends	(78		)	—			—			(38		)	—			—
Increased payment of preferred stock dividends	(107		)	—			—			(11		)	—			—
Net change in notes payable from affiliated companies	—			58			570			—			(119		)	(1,140		)
Contribution from parent	—			390			(831		)	—			200			922
Dividend to parent	—			(167		)	240			—			(29		)	241
Other	(9		)	(1		)	(2		)	(1		)	—			(1		)
	$	(277	)	$	550		$	277		$	3,298		$	128		$	(183	)

Future Sources and Uses of Cash

The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures are expected to be used for investment in infrastructure for electric and natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Series A Preferred Stock, Series B Preferred Stock and Common Stock, and in addition to interest payments on debt, the Registrants’ principal anticipated cash requirements for 2020 include the following:



	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Estimated capital expenditures	$	2,630	$	1,031	$	702
Scheduled principal payments on Securitization Bonds	231		231		—
Minimum contributions to pension plans and other post-retirement plans	100		9		3
Maturing Vectren term loans	600		—		—

The Registrants expect that anticipated 2020 cash needs will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, term loans or common stock, anticipated cash flows from operations, with respect to CenterPoint Energy and CERC, proceeds from commercial paper and with respect to CenterPoint Energy, distributions from Enable. Additionally, proceeds from the expected closing of the transactions underlying the Securities Purchase Agreement and Equity Purchase Agreement will be used to repay outstanding debt. Discretionary financing or refinancing may result in the issuance of equity securities of CenterPoint Energy or debt securities of the Registrants in the capital markets or the arrangement of additional credit facilities or term bank loans. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms.

The following table sets forth the Registrants’ actual capital expenditures by reportable segment for 2019 and estimates of the Registrants’ capital expenditures currently planned for projects for 2020 through 2024:



	2019		2020		2021		2022		2023		2024
CenterPoint Energy	(in millions)
Houston Electric T&D	$	1,033	$	1,031	$	1,082	$	934	$	934	$	876
Indiana Electric Integrated (1)	183		276		268		267		396		392
Natural Gas Distribution (1)	1,098		1,124		1,037		1,261		1,373		1,331
Energy Services (3)	12		4		—		—		—		—
Infrastructure Services (1) (4)	67		28		—		—		—		—
Corporate and Other (1)	194		167		136		123		92		92
Total	$	2,587	$	2,630	$	2,523	$	2,585	$	2,795	$	2,691
Houston Electric (2)	$	1,033	$	1,031	$	1,082	$	934	$	934	$	876
CERC
Natural Gas Distribution	$	773	$	698	$	648	$	850	$	917	$	891
Energy Services (3)	12		4		—		—		—		—
Total	$	785	$	702	$	648	$	850	$	917	$	891


(1)	Included in the 2019 column are capital expenditures from businesses acquired in the Merger, for the period February 1, 2019 to December 31, 2019.


(2)	Houston Electric consists of a single reportable segment, Houston Electric T&D.


(3)	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.


(4)	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.

The following table sets forth estimates of the Registrants’ contractual obligations as of December 31, 2019, including payments due by period:



Contractual Obligations	Total		2020		2021-2022		2023-2024		2025 and thereafter
	(in millions)
CenterPoint Energy
Securitization Bonds	$	977	$	231	$	430	$	316	$	—
Other long-term debt (1)	14,191		600		5,633		1,579		6,379
Interest payments — Securitization Bonds (2)	79		30		37		12		—
Interest payments — other long-term debt (2)	6,195		529		871		701		4,094
Operating leases (3)	69		22		25		10		12
Benefit obligations (4)	—		—		—		—		—
Non-trading derivative liabilities	80		51		26		3		—
Commodity and other commitments (5)	4,279		750		1,035		606		1,888
Total contractual cash obligations (6)	$	25,870	$	2,213	$	8,057	$	3,227	$	12,373
Houston Electric
Securitization Bonds	$	977	$	231	$	430	$	316	$	—
Other long-term debt (1)	3,973		—		702		200		3,071
Interest payments — Securitization Bonds (2)	79		30		37		12		—
Interest payments — other long-term debt (2)	2,896		161		300		267		2,168
Operating leases (3)	1		1		—		—		—
Benefit obligations (4)	—		—		—		—		—
Total contractual cash obligations (6)	$	7,926	$	423	$	1,469	$	795	$	5,239
CERC
Long-term debt	$	2,546	$	—	$	969	$	300	$	1,277
Interest payments — long-term debt (1)	1,379		112		179		141		947
Operating leases (3)	28		6		8		5		9
Benefit obligations (4)	—		—		—		—		—
Non-trading derivative liabilities	58		44		14		—		—
Commodity and other commitments (5)	3,089		533		674		356		1,526
Total contractual cash obligations (6)	$	7,100	$	695	$	1,844	$	802	$	3,759

(1)

ZENS obligations are included in the 2025 and thereafter column at their contingent principal amount of $75 million as of December 31, 2019 . These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($822 million as of December 31, 2019), as discussed in Note 12 to the consolidated financial statements.

(2)

The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2019. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.


(3)	For a discussion of operating leases, please read Note 22 to the consolidated financial statements.


(4)	See Note 8(g) to the consolidated financial statements for information on the Registrants’ expected contributions to pension plans and other postretirement plans in 2020.


(5)	For a discussion of commodity and other commitments, please read Note 16(a) to the consolidated financial statements.


(6)	This table does not include estimated future payments for expected future AROs. These payments are primarily estimated to be incurred after 2025. See Note 3(c) to the consolidated financial statements for further information.

Off-Balance Sheet Arrangements

Other than Houston Electric’s first mortgage bonds and general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy (see Note 14 to the consolidated financial statements) and operating leases, the Registrants have no off-balance sheet arrangements.

Regulatory Matters

Houston Electric Base Rate Case (CenterPoint Energy and Houston Electric)

On April 5, 2019, and subsequently adjusted in errata filings in May and June 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 discussed below. This rate filing is based on a rate base of $6.4 billion, a 50% debt/50% equity capital structure and a 10.4% ROE. Houston Electric last filed for a base rate increase on June 30, 2010, with a test year ending December 31, 2009. Houston Electric also requested a prudency determination on all capital investments made since January 1, 2010, the establishment of a rider to refund over three years to its customers approximately $119 million of unprotected EDIT resulting from the TCJA, updated depreciation rates and approval to clarify and update various non-rate tariff provisions. Recovery of all reasonable and necessary rate case expenses for this case and certain prior rate case proceedings were severed into a separate proceeding. A hearing was held June 24–28, 2019.

On September 16, 2019, the ALJs issued a PFD. The PUCT began deliberating on the PFD (which is prepared by ALJs at a different state agency) during its November 14, 2019 open meeting but delayed final determination for further consideration. The PUCT again discussed the Houston Electric rate case at its December 13, 2019 open meeting and concluded that the PUCT would consider settlement a reasonable approach to resolving the rate case and noted that Houston Electric had indicated settlement negotiations were already underway. Houston Electric updated the PUCT at its January 16, 2020 open meeting regarding the status of settlement discussions, indicating that the parties were working on a settlement and anticipated a final settlement in the near future. On January 23, 2020, Houston Electric filed a Stipulation and Settlement Agreement with the PUCT that provides for the following, among other things:


•	an overall revenue requirement increase of approximately $13 million;


•	an ROE of 9.4%;


•	a capital structure of 57.5% debt/42.5% equity;


•	a refund of unprotected EDIT of $105 million plus carrying costs over approximately 30-36 months; and


•	recovery of all retail transmission related costs through the TCRF.

Also, Houston Electric is not required to make a one-time refund of capital recovery from its TCOS and DCRF mechanisms. Future TCOS filings will take into account both ADFIT and EDIT until the final order from Houston Electric’s next base rate proceeding. No rate base items are required to be written off; however, approximately $12 million in rate case expenses were written off in 2019. A base rate application must be filed for Houston Electric no later than four years from the date of the PUCT’s final order in the proceeding. Additionally, Houston Electric will not file a DCRF in 2020, nor will a subsequent separate proceeding with the PUCT be instituted regarding EDIT on Houston Electric’s securitized assets.

Furthermore, under the terms of the Stipulation and Settlement Agreement, Houston Electric agreed to adopt certain ring-fencing measures to increase its financial separateness from CenterPoint Energy, which include the following:


•	Houston Electric’s credit agreements and indentures shall not contain cross-default provisions by which a default by CenterPoint Energy or its other affiliates would cause a default at Houston Electric;


•	The financial covenant in Houston Electric’s credit agreement shall not be related to any entity other than Houston Electric. Houston Electric shall not include in its debt or credit agreements any financial covenants or rating agency triggers related to any entity other than Houston Electric;


•	Houston Electric shall not pledge its assets in respect of or guarantee any debt or obligation of any of its affiliates. Houston Electric shall not pledge, mortgage, hypothecate, or grant a lien upon the property of Houston Electric except pursuant to an exception in effect in Houston Electric’s current credit agreement, such as Houston Electric’s first mortgage and general mortgage;


•	Houston Electric shall maintain its own stand-alone credit facility, and Houston Electric shall not share its credit facility with any regulated or unregulated affiliate;


•	Houston Electric shall maintain ratings with all three major credit ratings agencies;


•	Houston Electric shall maintain a stand-alone credit rating;


•	Houston Electric’s first mortgage bonds and general mortgage bonds shall be secured only with assets of Houston Electric;


•	No Houston Electric assets may be used to secure the debt of CenterPoint Energy or its other affiliates;

•

Houston Electric shall not hold out its credit as being available to pay the debt of any affiliates (provided that, for the avoidance of doubt, Houston Electric is not considered to be holding its credit out to pay the debt of affiliates, or in breach of any other ring-fencing measure, with respect to the $68 million of Houston Electric general mortgage bonds that currently serve as collateral for certain outstanding CenterPoint Energy pollution control bonds);


•	Without prior approval of the PUCT, neither CenterPoint Energy nor any affiliate of CenterPoint Energy (excluding Houston Electric) may incur, guarantee, or pledge assets in respect of any incremental new debt that is dependent on: (1) the revenues of Houston Electric in more than a proportionate degree than the other revenues of CenterPoint Energy; or (2) the equity of Houston Electric;


•	Houston Electric shall not transfer any material assets or facilities to any affiliates, other than a transfer that is on an arm’s length basis consistent with the PUCT’s affiliate standards applicable to Houston Electric;


•	Except for its participation in an affiliate money pool, Houston Electric shall not commingle its assets with those of other CenterPoint Energy affiliates;


•	Except for its participation in an affiliate money pool, Houston Electric shall not lend money to or borrow money from CenterPoint Energy; and


•	Houston Electric shall notify the PUCT if its issuer credit rating or corporate credit rating as rated by any of the three major rating agencies falls below investment grade.

The PUCT approved the Stipulation and Settlement Agreement at its February 14, 2020 open meeting. A final order from the PUCT is currently expected during the first quarter of 2020; however, motions for rehearing, if granted, could result in the order being issued after the first quarter of 2020. The rates are expected to be implemented 45 days after the final order is issued.

CenterPoint Energy and Houston Electric record pre-tax expense for (i) probable disallowances of capital investments and (ii) customer refund obligations and costs deferred in regulatory assets when the amounts are no longer considered probable of recovery.

Brazos Valley Connection Project (CenterPoint Energy and Houston Electric)

Houston Electric completed construction on and energized the Brazos Valley Connection in March 2018, ahead of the original June 1, 2018 energization date. The final capital costs of the project reported to the PUCT in December 2018 were $281 million, which was within the estimated range of approximately $270-$310 million in the PUCT’s original order. In a filing with the PUCT in September 2018, Houston Electric applied for interim recovery of project costs incurred through July 31, 2018, which were not previously included in rates. Houston Electric received approval for interim recovery in November 2018. Final approval of the project costs occurred in Houston Electric’s base rate case discussed above.

Bailey to Jones Creek Project (CenterPoint Energy and Houston Electric)

In April 2017, Houston Electric submitted a proposal to ERCOT requesting its endorsement of the Bailey to Jones Creek Project. On December 12, 2017, Houston Electric received approval from ERCOT. In September 2018, Houston Electric filed a certificate of convenience and necessity application with the PUCT that included capital cost estimates for the project that ranged from approximately $482-$695 million, which were higher than the initial cost estimates. The revised project cost estimates include additional costs associated with the routing of the line to mitigate environmental and other land use impacts and structure design to address soil and coastal wind conditions. The actual capital costs of the project will depend on those factors as well as other factors, including land acquisition costs, construction costs and the ultimate route approved by the PUCT. On the request of the PUCT, ERCOT intervened in the proceeding and performed a re-evaluation of the cost-effectiveness of the proposed project. Based on that re-evaluation, ERCOT reaffirmed the recommended transmission option for the project. An unopposed settlement agreement was filed on August 15, 2019, under which Houston Electric would construct the project at an estimated cost of approximately $483 million. The PUCT issued its final approval of the certificate of convenience and necessity application on November 21, 2019. Houston Electric has commenced pre-construction activities on the project, and anticipates beginning construction in early 2021 and energizing the line in early 2022.

Indiana Electric Generation Project (CenterPoint Energy)

Indiana Electric must make substantial investments in its generation resources in the near term to comply with environmental regulations. On February 20, 2018, 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 the baseload capacity of its existing generation fleet at an approximate cost of $900 million, which includes the cost of a new natural gas pipeline to serve the plant.

As a part of this same proceeding, Indiana Electric also sought recovery under Indiana Senate Bill 251 of costs to be incurred for environmental investments to be made at its F.B. Culley generating plant to comply with ELG and CCR rules. The F.B. Culley investments, estimated to be approximately $95 million, began in 2019 and will allow the F.B. Culley Unit 3 generating facility to comply with environmental requirements and continue to provide generating capacity to Indiana Electric’s customers. Under Indiana Senate Bill 251, Indiana Electric sought authority to recover 80% of the approved costs, including a return, using a tracking mechanism, with the remaining 20% of the costs deferred for recovery in Indiana Electric’s next base rate proceeding.

On April 24, 2019, the IURC issued an order approving the environmental investments proposed for the F.B. Culley generating facility, along with recovery of prior pollution control investments made in 2014. The order denied the proposed gas combined cycle generating facility. Indiana Electric is conducting a new IRP, expected to be completed in mid-2020, to identify an appropriate investment of capital in its generation fleet to satisfy the needs of its customers and comply with environmental regulations.

Indiana Electric Solar Project (CenterPoint Energy)

On February 20, 2018, Indiana Electric announced it was finalizing details to install an additional 50 MW of universal solar energy, consistent with its IRP, with a petition seeking authority to recover costs associated with the project pursuant to Indiana Senate Bill 29. Indiana Electric filed a settlement agreement with the intervening parties whereby the energy produced by the solar farm would be set at a fixed market rate over the life of the investment and recovered within Indiana Electric’s CECA mechanism. On March 20, 2019, the IURC approved the settlement. Indiana Electric reached an agreement with the other settling parties to amend the settlement agreement to ensure the project would not cause negative tax consequences. Indiana Electric filed the amended settlement agreement with the IURC on September 16, 2019, and on January 29, 2020 the IURC approved the amended settlement agreement.

Indiana Electric A.B. Brown Ash Pond Remediation (CenterPoint Energy)

On August 14, 2019, Indiana Electric filed a petition with the IURC, seeking approval, as a federally mandated project, for the recovery of costs associated with the clean closure of the A.B. Brown ash pond pursuant to Indiana Senate Bill 251. This project, expected to last approximately 14 years, would result in the full excavation and recycling of the ponded ash through agreements with a beneficial reuse entity, totaling approximately $160 million. Under Indiana Senate Bill 251, Indiana Electric seeks authority to recover via a tracking mechanism 80% of the approved costs, with a return on eligible capital investments needed to allow for the extraction of the ponded ash, with the remaining 20% of the costs deferred for recovery in Indiana Electric’s next base rate proceeding. On December 19, 2019 and subsequently on January 10, 2020, Indiana Electric filed a settlement agreement with the intervening parties whereby the costs would be recovered as requested, with an additional commitment by Indiana Electric to offset the federally mandated costs by at least $25 million, representing a combination of total cash proceeds received from the

ash reuser and total insurance proceeds to be received from Indiana Electric’s insurers in confidential settlement agreements in the pending Complaint for Damages and Declaratory Relief filing. The settlement agreement is pending before the IURC, with an order expected in the first half of 2020. If approved, Indiana Electric would expect recovery of the approved costs to commence in 2021.

Rate Change Applications

The Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, Houston Electric is periodically involved in proceedings to adjust its capital tracking mechanisms (TCOS and DCRF) and annually files to adjust its EECRF. CERC is periodically involved in proceedings to adjust its capital tracking mechanisms in Texas (GRIP), its cost of service adjustments in Arkansas, Louisiana, Mississippi and Oklahoma (FRP, RSP, RRA and PBRC, respectively), its decoupling mechanism in Minnesota, and its energy efficiency cost trackers in Arkansas, Minnesota, Mississippi and Oklahoma (EECR, CIP, EECR and EECR, respectively). CenterPoint Energy is periodically involved in proceedings to adjust its capital tracking mechanisms in Indiana (CSIA for gas and TDSIC for Electric) and Ohio (DRR), its decoupling mechanism in Indiana (SRC for gas), and its energy efficiency cost trackers in Indiana (EEFC for gas and DSMA for electric) and Ohio (EEFR).

The table below reflects significant applications pending or completed during 2019 and to date in 2020 for the Registrants.



Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and Houston Electric (PUCT)
Rate Case (1)	$155	April 2019	TBD	TBD	See discussion above under Houston Electric Base Rate Case.
EECRF	7	May 2019	March 2020	October 2019	The PUCT issued a final order in October 2019 approving recovery of 2020 EECRF of $35 million, including a $7 million performance bonus.
CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)
GRIP	20	March 2019	July 2019	June 2019	Based on net change in invested capital of $123 million.
Rate Case (1)	7	November 2019	TBD	TBD	Reflects a proposed 10.40% ROE on a 58% equity ratio. Additionally, the proposal includes a refund for an Unprotected EDIT Rider amortized over 3 years of which $2.2 million is refunded in Year 1 and a request of $0.2 million for a Hurricane Surcharge, resulting from Hurricane Harvey, over 1 year.
CenterPoint Energy and CERC - Houston and Texas Coast (Railroad Commission)
Administrative 104.111	N/A	August 2019	January 2020	October 2019	On August 1, 2019, and subsequent supplemental filings in August and October 2019, Houston and Texas Coast proposed a rider to refund over three years to its Houston and Texas Coast customers combined, approximately $18 million of unprotected EDIT related to the TCJA.
CenterPoint Energy and CERC - South Texas (Railroad Commission)
Administrative 104.111	N/A	November 2019	March 2020	January 2020	On November 14, 2019, South Texas proposed to refund protected EDIT, amortized over ARAM. The estimated refund for the first year is $0.6 million.
CenterPoint Energy and CERC - Arkansas (APSC)
FRP	7	April 2019	October 2019	August 2019	Based on ROE of 9.5% approved in the last rate case. On August 23, 2019, the APSC approved a unanimous comprehensive settlement that results in an FRP revenue increase of $7 million and includes additional non-monetary items.
CenterPoint Energy and CERC - Louisiana (LPSC)
RSP	3	September 2019	December 2019	December 2019	Based on ROE of 9.95%.
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive	11	May 2019	October 2019	September 2019	CIP Financial Incentive based on 2018 activity.
Decoupling	N/A	September 2019	September 2019	January 2020	Represents over-recovery of $21 million recorded for and during the period July 1, 2018 through June 30, 2019, partially offset by over-refund of $2 million related to the period July 1, 2017 through June 30, 2018.
Rate Case (1)	62	October 2019	TBD	TBD	Reflects a proposed 10.15% ROE on a 51.39% equity ratio. Interim rates were approved and reflect an annual increase of $53 million, effective January 1, 2020.
CenterPoint Energy and CERC - Mississippi (MPSC)
RRA	2	May 2019	November 2019	November 2019	Based on ROE of 9.26%.



Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy and CERC - Oklahoma (OCC)
PBRC	2	March 2019	September 2019	August 2019	Based on ROE of 10%. On July 26, 2019, the ALJ recommended that the OCC approve an increase of $2 million. On August 29, 2019, the OCC approved the ALJ-recommended revenue increase of $2 million.
CenterPoint Energy - Indiana South - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $16 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(1) million, and a change in the total (over)/under-recovery variance of $(3) million annually.
CSIA	5	April 2019	July 2019	July 2019	Requested an increase of $22 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $3 million annually.
CSIA	3	October 2019	January 2020	January 2020	Requested an increase of $18 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $(0.2) million annually.
CenterPoint Energy - Indiana North - Gas (IURC)
CSIA	3	October 2018	January 2019	January 2019	Requested an increase of $54 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $(11) million, and a change in the total (over)/under-recovery variance of $(19) million annually.
CSIA	12	April 2019	July 2019	July 2019	Requested an increase of $58 million to rate base, which reflects a $12 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $14 million annually.
CSIA	4	October 2019	January 2020	January 2020	Requested an increase of $29 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in no change to the previous credit provided, and a change in the total (over)/under-recovery variance of $(7) million annually.
CenterPoint Energy - Ohio (PUCO)
DRR	11	May 2019	September 2019	August 2019	Requested an increase of $78 million to rate base for investments made in 2018, which reflects a $11 million annual increase in current revenues. A change in (over)/under-recovery variance of $(3) million annually is also included in rates. All pre-2018 investments are included in rate case request.
Rate Case	23	March 2018	September 2019	August 2019	Settlement agreement approved by PUCO Order that provides for a $23 million annual increase in current revenues. Order based upon $622 million of total rate base, a 7.48% overall rate of return, and extension of conservation and DRR programs.
TSCR (1)	N/A	January 2019	TBD	TBD	Application to flow back to customers certain benefits from the TCJA. Initial impact reflects credits for 2018 of $(10) million and 2019 of $(8) million, with mechanism to begin subsequent to new base rates. Order is expected in early 2020.



Mechanism	Annual Increase (Decrease) (1) (in millions)	Filing Date	Effective Date	Approval Date	Additional Information
CenterPoint Energy - Indiana Electric (IURC)
TDSIC	3	February 2019	May 2019	May 2019	Requested an increase of $24 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes refunds associated with the TCJA, resulting in a change of $5 million, and a change in the total (over)/under-recovery variance of $5 million annually.
TDSIC	4	August 2019	November 2019	November 2019	Requested an increase of $35 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of $4 million annually.
TDSIC (1)	4	February 2020	May 2020	TBD	Requested an increase of $34 million to rate base, which reflects a $4 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of $2 million annually.
ECA - MATS	13	February 2018	January 2019	April 2019	Requested an increase of $58 million to rate base, which reflects a $13 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism includes recovery of prior accounting deferrals associated with investments (depreciation, carrying costs, operating expenses).
CECA	2	February 2019	June 2019	May 2019	Requested an increase of $13 million to rate base related to solar pilot investments, which reflects a $2 million annual increase in current revenues.
CECA (1)	0.1	February 2020	June 2020	TBD	Requested an increase of $0.1 million to rate base related to solar pilot investments, which reflects an immaterial change to current revenues. The mechanism also includes a change in (over)/under-recovery variance of $0.1 million annually. Additional solar investment to supply 50 MW of solar capacity is approved and will be included for recovery once completed in 2021.


(1)	Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.

Tax Reform

TCJA-related 2018 tax expense refunds are currently included in the Registrants’ existing rates and are therefore reducing the Registrants’ current annual revenue. The TCJA-related 2018 tax expense refunds for Houston Electric were completed in September 2019. However, in Houston Electric’s rate case filed in April 2019, and subsequently adjusted in errata filings in May and June 2019, pursuant to the Stipulation and Settlement Agreement, Houston Electric will return unprotected EDIT net regulatory liability balance to customers, through a separate rider and its wholesale transmission tariff over approximately three years. The balance of unprotected EDIT was $105 million as of December 31, 2018. In addition, Houston Electric’s TCJA-related protected EDIT balance as of December 31, 2018 is $563 million and must be returned to customers over ARAM.

CenterPoint Energy’s electric and natural gas utilities in Indiana and Ohio, which were acquired during the Merger, currently recover corporate income tax expense in approved rates charged to customers. The IURC and the PUCO both issued orders which initiated proceedings to investigate the impact of the TCJA on utility companies and customers within Indiana and Ohio, respectively. In addition, the IURC and PUCO have ordered each utility to establish regulatory liabilities to record all estimated impacts of tax reform starting January 1, 2018 until the date when rates are adjusted to capture these impacts. In Indiana, in response to Vectren’s pre-Merger filing for proposed changes to its rates and charges to consider the impact of the lower federal income tax rates, the IURC approved an initial reduction to current rates and charges, effective June 1, 2018, to capture the immediate impact of the lower corporate federal income tax rate. The refund of EDIT and regulatory liabilities commenced in November 2018 for Indiana electric customers and in January 2019 for Indiana gas customers. In Ohio, the initial rate reduction to current rates and charges became effective upon conclusion of its pending base rate case on August 28, 2019. In January 2019, an application was filed with PUCO in compliance with its October 2018 order requiring utilities to file for a request to adjust rates to reflect the impact of the TCJA, requesting authority to implement a rider to flow back to customers the tax benefits realized under the TCJA, including the refund of EDIT and regulatory liabilities. CenterPoint Energy expects this proceeding to be approved in 2020.

ELG (CenterPoint Energy)

Under the Clean Water Act, the EPA sets technology-based guidelines for water discharges from new and existing electric generation facilities. In September 2015, the EPA finalized revisions to the existing steam electric ELG setting stringent technology-based water discharge limits for the electric power industry. The EPA focused this rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations, specifically setting strict water discharge limits for arsenic, mercury and selenium for scrubber waste waters. The ELG will be implemented when existing water discharge permits for the plants are renewed. In the case of Indiana Electric’s water discharge permits, in 2017 the IDEM issued final renewals for the F.B. Culley and A.B. Brown power plants. IDEM agreed that units identified for retirement by December 2023 would not be required to install new treatment technology to meet ELG, and approved a 2020 compliance date for dry bottom ash and a 2023 compliance date for flue gas desulfurization wastewater treatment standards for the remaining coal-fired unit at F.B. Culley.

On April 13, 2017, as part of the U.S. President’s Administration’s regulatory reform initiative, which is focused on the number and nature of regulations, the EPA granted petitions to reconsider the ELG rule, and indicated it would stay the current implementation deadlines in the rule during the pendency of the reconsideration. On September 13, 2017, the EPA finalized a rule postponing certain interim compliance dates by two years, but did not postpone the final compliance deadline of December 31, 2023. In April 2018, the EPA published an effluent guidelines program plan that anticipated a December 2019 rule revising the effluent limitations and pre-treatment standards for existing sources in the 2015 rule. On April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit vacated and remanded portions of the ELG rule that selected impoundment as the best available technology for legacy wastewater and leachate. It is not clear what revisions to the ELG rule the EPA will implement, or what effect those revisions may have. As Indiana Electric does not currently have short-term ELG implementation deadlines in its recently renewed wastewater discharge permits, it does not anticipate immediate impacts from the EPA’s two-year extension of preliminary implementation deadlines due to the longer compliance time frames granted by IDEM and will continue to work with IDEM to evaluate further implementation plans. On November 4, 2019, the EPA released a pre-publication copy of proposed revisions to the CCR and ELG rules. CenterPoint Energy will evaluate the proposals to determine potential impacts to current compliance plans for its A.B. Brown and F.B. Culley generating stations.

CPP and ACE Rule (CenterPoint Energy)

On August 3, 2015, the EPA released its CPP Rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On August 31, 2018, the EPA published its proposed CPP replacement rule, the ACE Rule, which was finalized on July 8, 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 CenterPoint Energy does not expect a state ACE rule to be finalized and approved by the EPA until 2024. CenterPoint Energy is currently unable to predict the effect of a state plan to implement the ACE rule but does not anticipate that such a plan would have a material effect.

Impact of Legislative Actions & Other Initiatives (CenterPoint Energy)

At this time, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. While the requirements of a state ACE rule remain uncertain, Indiana Electric will continue to monitor regulatory activity regarding GHG emission standards that may affect its electric generating units.

FERC Revised Policy Statement (CenterPoint Energy)

The regulation of midstream energy infrastructure assets has a significant impact on Enable’s business. For example, Enable’s interstate natural gas transportation and storage assets are subject to regulation by the FERC under the NGA. In March 2018, the FERC announced a Revised Policy Statement stating that it would no longer allow pipelines organized as a master limited partnership to recover an income tax allowance in their cost-of-service rates. In July 2018, the FERC issued new regulations which required all FERC-regulated natural gas pipelines to make a one-time Form No. 501-G filing providing certain financial information. In October 2018, Enable Gas Transmission, LLC filed its Form No. 501-G and filed a statement that it intended to take no other action. On March 8, 2019, the FERC terminated the 501-G proceeding and required no other action. MRT did not file a FERC Form No. 501-G because it had filed a general rate case in June 2018. In July 2018, the FERC issued an order accepting MRT’s proposed rate increases subject to refund upon a final determination of MRT’s rates and ordering MRT to refile its rate case to reflect the elimination of an income tax allowance in its cost-of-service rates. On August 30, 2018, MRT submitted a supplemental filing to comply with the FERC’s order. MRT has appealed the FERC’s order to eliminate the income tax allowance in its cost-of-service rates. The FERC set MRT’s re-filed rate case for hearing. The procedural schedule has been suspended to afford MRT

time to file a settlement. If a settlement is not filed or all of the participants do not agree to a settlement, then the proceeding may advance to hearing. On November 5, 2019, as supplemented on December 13, 2019, MRT filed an uncontested proposed settlement for its 2018 rate case. On October 30, 2019, MRT filed a second general rate case with the FERC pursuant to Section 4 of the NGA. The 2019 rate case was necessary because at the time of filing the 2019 rate case, the proposed settlement of the 2018 rate case was still being contested, requiring that new maximum rates be established for the non-settling parties reflecting the turnback of capacity. On November 5, 2019, MRT filed an uncontested proposed settlement for the 2019 rate case. Subsequently, MRT reached agreement with 100% of the parties participating in the MRT rate cases, and these rate case settlements are pending at the FERC. The FERC may accept or reject the proposed settlements in the 2018 and 2019 rate cases as to all of the parties, or may reject one or both of the settlements and set one or both of the rate cases for hearing.

Other Matters

Credit Facilities

The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, please see Note 14 to the consolidated financial statements.

Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $5.1 billion as of December 31, 2019. As of February 19, 2020, the Registrants had the following revolving credit facilities and utilization of such facilities:



			Amount Utilized as of February 19, 2020
Registrant	Size of Facility		Loans		Letters of Credit		Commercial Paper		Weighted Average Interest Rate	Termination Date
	(in millions)
CenterPoint Energy	$	3,300	$	—	$	6	$	1,824	1.79%	March 3, 2022
CenterPoint Energy (1)	400		—		—		207		1.86%	July 14, 2022
CenterPoint Energy (2)	200		—		—		—		—	July 14, 2022
Houston Electric	300		—		—		—		—	March 3, 2022
CERC	900		—		1		205		1.73%	March 3, 2022
Total	$	5,100	$	—	$	7	$	2,236


(1)	The credit facility was issued by VUHI and is guaranteed by SIGECO, Indiana Gas and VEDO.


(2)	The credit facility was issued by VCC and is guaranteed by Vectren.

Borrowings under each of the revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makes representations prior to borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the revolving credit facilities, the spread to LIBOR and the commitment fees fluctuate based on the borrower’s credit rating. The borrowers are currently in compliance with the various business and financial covenants in the five revolving credit facilities.

Long-term Debt

For detailed information about the Registrants’ debt issuances in 2019, see Note 14 to the consolidated financial statements.

Securities Registered with the SEC

On January 31, 2017, the Registrants filed a joint shelf registration statement with the SEC, as amended on September 24, 2018, registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities

and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement expired on January 31, 2020. For information related to the Registrants’ debt and equity security issuances in 2019, see Notes 13 and 14 to the consolidated financial statements.

Temporary Investments

As of February 19, 2020, the Registrants had no temporary investments.

Money Pool

The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs.

The table below summarizes CenterPoint Energy money pool activity by Registrant as of February 19, 2020:



	Weighted Average Interest Rate	Houston Electric		CERC
		(in millions)
Money pool investments	1.81%	$	282	$	—

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under the Registrants’ credit facilities is based on their credit ratings. The interest on borrowings under the credit facilities is based on each respective borrower’s credit ratings. On October 25, 2019, Moody’s downgraded VUHI’s and Indiana Gas’ senior unsecured debt rating to A3 from A2 and SIGECO’s senior secured debt rating to A1 from Aa3. The outlooks of VUHI, Indiana Gas and SIGECO were revised to stable from negative. On November 18, 2019, Moody’s withdrew the ratings of Indiana Gas. On November 21, 2019, Moody’s placed the A3 senior unsecured rating, A3 Issuers rating, and A1 senior secured rating of Houston Electric on review for downgrade. On February 19, 2020, Fitch downgraded Houston Electric’s senior secured debt to A from A+ with a negative outlook and affirmed CenterPoint Energy’s BBB rating with a negative outlook. As of February 19, 2020, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of the Registrants:



		Moody’s		S&P		Fitch
Registrant	Borrower/Instrument	Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
CenterPoint Energy	CenterPoint Energy Senior Unsecured Debt	Baa2	Stable	BBB	Stable	BBB	Negative
CenterPoint Energy	Vectren Corp. Issuer Rating	n/a	n/a	BBB+	Stable	n/a	n/a
CenterPoint Energy	VUHI Senior Unsecured Debt	A3	Stable	BBB+	Stable	n/a	n/a
CenterPoint Energy	Indiana Gas Senior Unsecured Debt	n/a	n/a	BBB+	Stable	n/a	n/a
CenterPoint Energy	SIGECO Senior Secured Debt	A1	Stable	A	Stable	n/a	n/a
Houston Electric	Houston Electric Senior Secured Debt	A1	Under Review	A	Stable	A	Negative
CERC	CERC Corp. Senior Unsecured Debt	Baa1	Positive	BBB+	Stable	BBB+	Stable


(1)	A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.


(2)	An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.


(3)	A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.

The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings

are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. 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 the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies.

A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of December 31, 2019, the impact on the borrowing costs under the five revolving credit facilities would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments.

CES, a wholly-owned subsidiary of CERC operating in the Energy Services reportable segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and natural gas utilities throughout the United States. To economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. Similarly, mark-to-market exposure offsetting and exceeding the credit threshold may cause the counterparty to provide collateral to CES. As of December 31, 2019, the amount posted by CES as collateral aggregated approximately $92 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. CenterPoint Energy and CERC estimate that as of December 31, 2019, unsecured credit limits extended to CES by counterparties aggregated $467 million, and none of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC might need to provide cash or other collateral of as much as $181 million as of December 31, 2019. The amount of collateral will depend on seasonal variations in transportation levels.

ZENS and Securities Related to ZENS (CenterPoint Energy)

If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought its liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. 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. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on December 31, 2019, deferred taxes of approximately $429 million would have been payable in 2019. If all the ZENS-Related Securities had been sold on December 31, 2019, capital gains taxes of approximately $149 million would have been payable in 2019. For additional information about ZENS, see Note 12 to the consolidated financial statements.

Cross Defaults

Under each of CenterPoint Energy’s, Houston Electric’s and CERC’s respective revolving credit facilities, as well as under CenterPoint Energy’s term loan agreement, a payment default on, or a non-payment default that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by the borrower or any of their respective significant subsidiaries will cause a default under such borrower’s respective credit facility or term loan agreement. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities.

Under each of VUHI’s and VCC’s respective revolving credit facilities and term loan agreements, a payment default on, or a non-payment default that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $50 million by the borrower, any of their respective subsidiaries or any of the respective guarantors of a credit facility or term loan agreement will cause a default under such borrower’s respective credit facility or term loan agreement.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

CenterPoint Energy previously disclosed that it may 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 has no intention to reduce its ownership of Enable common units and currently plans to hold such Enable common units and to utilize any cash distributions received on such Enable common units to finance a portion of CenterPoint Energy’s capital expenditure program. CenterPoint Energy may consider or alter its plans or proposals in respect of any such plans in the future.

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.

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.

Enable Midstream Partners (CenterPoint Energy and CERC)

In September 2018, CERC completed the Internal Spin, after which CERC’s equity investment in Enable met the criteria for discontinued operations classification. As a result, the operations have been classified as Income from discontinued operations, net of tax, in CERC’s Statements of Consolidated Income for the periods presented. For further information, see Note 11 to the consolidated financial statements.

CenterPoint Energy receives quarterly cash distributions from Enable on its common units and Enable Series A Preferred Units. A reduction in the cash distributions CenterPoint Energy receives from Enable could significantly impact CenterPoint Energy’s liquidity. For additional information about cash distributions from Enable, see Notes 11 and 23 to the consolidated financial statements.

Hedging of Interest Expense for Future Debt Issuances

From time to time, the Registrants may enter into interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. For further information, see Note 9(a) to the consolidated financial statements.

Weather Hedge (CenterPoint Energy and CERC)

CenterPoint Energy and CERC have historically entered into partial weather hedges for certain NGD jurisdictions and electric operations’ Texas service territory to mitigate the impact of fluctuations from normal weather. CenterPoint Energy and CERC remain exposed to some weather risk as a result of the partial hedges. For more information about weather hedges, see Note 9(a) to the consolidated financial statements.

Collection of Receivables from REPs (CenterPoint Energy and Houston Electric)

Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, 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, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP’s default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. 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 against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, the Registrants’ liquidity and capital resources could be affected by:


•	cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas Distribution and Energy Services reportable segments;


•	acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices and concentration of natural gas suppliers (CenterPoint Energy and CERC);


•	increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC);


•	increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans;


•	various legislative or regulatory actions;


•	incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy and CERC);


•	the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;


•	slower customer payments and increased write-offs of receivables due to higher natural gas prices or changing economic conditions (CenterPoint Energy and CERC);


•	the satisfaction of any obligations pursuant to guarantees;


•	the outcome of litigation;


•	contributions to pension and postretirement benefit plans;


•	restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and


•	various other risks identified in “Risk Factors” in Item 1A of Part I of this report.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money

Houston Electric has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. For information about the total debt to capitalization financial covenants in the Registrants’ and certain of CenterPoint Energy’s subsidiaries’ revolving credit facilities, see Note 14 to the consolidated financial statements.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require the Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. The Registrants’ significant accounting policies are discussed in Note 2 to the consolidated financial statements. The Registrants believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors.

Accounting for Rate Regulation

Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. CenterPoint Energy’s and Houston Electric’s Electric T&D reportable segment, CenterPoint Energy’s Indiana Electric Integrated reportable segment, and CenterPoint Energy’s and CERC’s Natural Gas Distribution reportable segments apply this accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Registrants would be required to write off or write down these regulatory assets and liabilities. For further detail on the Registrants’ regulatory assets and liabilities, see Note 7 to the consolidated financial statements.

Acquisition Accounting

The Registrants evaluate acquisitions to determine when a set of acquired activities and assets represent a business. When control of a business is obtained, the Registrants apply the acquisition method of accounting and record the assets acquired, liabilities assumed and any non-controlling interest obtained based on fair value at the acquisition date.

The fair values of tangible and intangible assets and liabilities subject to rate-setting provisions and earning a regulated return generally approximate their carrying values. The fair value of assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, are determined using the income and market approach, which estimation methods may require the use of significant judgment and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. The results of operations of the acquired business are included in the Registrants’ respective Statements of Consolidated Income beginning on the date of the acquisition.

On the Merger Date, pursuant to the Merger Agreement, CenterPoint Energy consummated the Merger and acquired Vectren for approximately $6 billion in cash. The Merger is being accounted for in accordance with ASC 805, Business Combinations,

with CenterPoint Energy as the accounting acquirer of Vectren. Identifiable assets acquired and liabilities assumed have been recorded at their estimated fair values on the Merger Date.

Vectren’s regulated operations, comprised of electric generation and electric and natural gas delivery services, are subject to the rate-setting authority of the FERC, the IURC and the PUCO, and are accounted for pursuant to U.S. generally accepted accounting principles for regulated operations. The rate-setting and cost-recovery provisions currently in place for Vectren’s regulated operations provide revenues designed to recover the cost of providing utility service and a return on and recovery of investment in rate base assets and liabilities. Thus, the fair values of Vectren’s tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, neither the assets nor liabilities acquired reflect any adjustments related to these amounts. The fair value of regulatory assets not earning a return have been determined using the income approach and include the use of significant judgment and unobservable inputs.

The fair value of Vectren’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions, including identifiable intangibles, and the allocation of fair value to reporting units on the Merger Date was determined under the income approach using the multi-period excess earnings method, which is a specific discounted cash flow income approach, and for the measurement of certain assets and liabilities, the market approach was utilized.

Fair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the non-rate regulated businesses required the estimation of the appropriate company specific risk premiums for those non-rate regulated businesses based on evaluation of industry and entity-specific risks, which included expectations about future market or economic conditions existing on the Merger Date. Changes in these assumptions could have a significant impact on the amount of the identified intangible assets and/or the resulting amount of goodwill assigned to each reporting unit. CenterPoint Energy utilized a third-party valuation specialist in determining the key assumptions used in the valuation of intangible assets acquired and the allocation of goodwill to each of its reporting units on the Merger Date.

Impairment of Long-Lived Assets, Including Identifiable Intangibles, Goodwill, Equity Method Investments, and Investments without a Readily Determinable Fair Value

The Registrants review the carrying value of long-lived assets, including identifiable intangibles, goodwill, equity method investments, and investments without a readily determinable fair value whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for impairment as required by accounting guidance for goodwill and other intangible assets. Unforeseen events, changes in market conditions, and probable regulatory disallowances, where applicable, could have a material effect on the value of long-lived assets, including intangibles, goodwill, equity method investments, and investments without a readily determinable fair value due to changes in observable or estimated market value, future cash flows, interest rate, and regulatory matters could result in an impairment charge. The Registrants recorded no impairments to long-lived assets, including intangibles, equity method investments, or readily determinable fair value during 2019, 2018 and 2017. CenterPoint Energy and CERC recognized goodwill impairment losses, discussed below, during 2019, and the Registrants recorded no impairments to goodwill in 2018 and 2017.

Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value could be different using different estimates and assumptions in these valuation techniques.

Fair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the non-rate regulated businesses requires the estimation of the appropriate company specific risk premiums for those non-rate regulated businesses based on evaluation of industry and entity-specific risks, which includes expectations about future market or economic conditions existing on the date of the impairment test. Changes in these assumptions could have a significant impact on results of the impairment tests. CenterPoint Energy and CERC utilized a third-party valuation specialist to determine the key assumptions used in the estimate of fair value for each of its reporting units on the date of its annual goodwill impairment test.

Annual goodwill impairment test

CenterPoint Energy and CERC completed their 2019 annual goodwill impairment test as of July 1, 2019 and determined, based on an income approach or a weighted combination of income and market approaches, that no goodwill impairment charge

was required for any reporting unit based on the annual test. The fair values of each reporting unit significantly exceeded the carrying value of the reporting unit, with the exception of CenterPoint Energy’s Indiana Electric Integrated, Infrastructure Services and ESG reporting units. Indiana Electric Integrated’s fair value exceed its carrying value by 13%, and it had total goodwill of $1,008 million as of the 2019 annual impairment test date. Infrastructure Services’ fair value exceeded its carrying values by 6%, and it had total goodwill of $355 million as of the 2019 annual impairment test date. ESG’s fair value exceeded its carrying value by 8%, and it had total goodwill of $127 million as of the 2019 annual impairment test date. These reporting units are comprised entirely of businesses acquired in the Merger in February 2019, when assets and liabilities were adjusted to fair value and as a result, carrying values approximate fair value at that time. The measurement period for the initial purchase price accounting for the reporting units acquired in the Merger, including CenterPoint Energy’s Indiana Electric Integrated, Infrastructure Services and ESG reporting units, remained open as of the date of the annual impairment test date. Upon conclusion of the measurement period in the fourth quarter of 2019, CenterPoint Energy retrospectively evaluated the impact that the measurement period adjustments had on its annual impairment test and identified no material differences to the results, except CenterPoint Energy’s Indiana Electric Integrated’s fair value exceeded its carrying value by 7%, and it had total goodwill of $1,121 million. The primary driver for the excess fair value in the businesses acquired in the Merger at the annual goodwill impairment test date is a decline in market discounts rates, a key valuation assumption, from February 1, 2019 to July 1, 2019.

Although no goodwill impairment resulted from the 2019 annual test, an interim goodwill impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, if CenterPoint Energy’s market capitalization falls below book value for an extended period of time, or events affecting a reporting unit such as a contemplated disposal of all or part of a reporting unit.

Assets Held for Sale and Discontinued Operations

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale (the “Disposal Group”) at the lower of their carrying value or their estimated fair value less cost to sell. If the Disposal Group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant, is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax.

December 31, 2019 goodwill impairment assessments

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 the 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 fair value of each reporting unit was more likely than not below the carrying 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 were 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.

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. Per the Securities Purchase Agreement, VISCO will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $123 million within the reporting unit as of December 31, 2019 to be recognized as a benefit to deferred income tax expense by CenterPoint Energy upon closing; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer.

The fair value of the Infrastructure Services reporting unit was estimated as of December 31, 2019 using a market approach utilizing the economic indicators of value received by market participants during the exploration of strategic alternatives to inform the fair value of substantially all of the businesses within this reporting unit as of December 31, 2019. As of December 31, 2019, the fair value of the Infrastructure Services reporting unit exceeded the carrying value (inclusive of deferred income tax liabilities

of $123 million) by approximately $21 million or 2%. As a result, CenterPoint Energy did not record a goodwill impairment on its Infrastructure Services reporting unit as of December 31, 2019.

In February 2020, certain assets and liabilities representing the businesses within the Infrastructure Services reporting unit that will be transferred under the Securities Purchase Agreement (the “Disposal Group”) met the held for sale criteria. Because the transaction is structured as an asset sale for income tax purposes, the disposal group will exclude the deferred tax liabilities included within the reporting unit. Upon classifying the Disposal Group as held for sale in the first quarter of 2020, CenterPoint Energy anticipates recording an impairment loss on assets held for sale of approximately $85 million, plus an additional loss for transaction costs, in 2020. The actual amount of the impairment or loss in 2020 may be materially different from the preliminary amount.

The fair value of the Energy Services reporting unit was estimated as of December 31, 2019 using a combination of the market approach and the income approach. CenterPoint Energy and CERC utilized the economic indicators of value received by market participants during the exploration of strategic alternatives to inform the fair value of substantially all of the businesses within this reporting unit as of December 31, 2019. Certain assets groups not constituting a business within the reporting unit were valued using an income approach, as there was limited indication of value from market participants as of December 31, 2019 for these assets and liabilities. As a result, Energy Services recognized a goodwill impairment loss of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) of the Energy Services reporting unit exceeded its 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.

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. This transaction does not include CEIP and its assets. Per the Equity Purchase Agreement, CES will be converted from a wholly-owned corporation to a limited liability company that is disregarded for federal income tax purposes immediately prior to the closing of the transaction resulting in the sale of membership units at closing. The sale will be considered an asset sale for tax purposes requiring the net deferred tax liabilities of approximately $25 million within the reporting unit as of December 31, 2019 to be recognized as a benefit to deferred income tax expense by CenterPoint Energy upon closing; therefore, any deferred tax assets and liabilities within the reporting unit are not included in the carrying amount of the assets and liabilities that will be transferred to the buyer.

In February 2020 certain assets and liabilities representing substantially all of the businesses within CenterPoint Energy’s and CERC’s Energy Services reporting unit met the criteria to be classified as held for sale. 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. Upon classifying the disposal group as held for sale in the first quarter of 2020, CenterPoint Energy anticipates recording an aggregate impairment loss 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 further information, see Notes 6 and 23 to the consolidated financial statements.

Equity Method Investments

Equity method investments are evaluated for impairment when factors indicate that a decrease in value of an investment has occurred and the carrying amount of the investment may not be recoverable. An impairment loss, based on the excess of the carrying value over the best estimate of fair value of the investment, is recognized in earnings when an impairment is deemed to be other than temporary. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment.

Based on an analysis of CenterPoint Energy’s investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of Enable is temporary, and that the carrying value of its investment of $2.4 billion will be recovered. CenterPoint Energy considers the severity and duration of the impairment, management’s intent and ability to hold the investment to recovery, significant events and conditions of Enable, including its investment grade credit rating and planned expansion projects, along with other factors, to conclude that the investment is not other than temporarily impaired as of December 31, 2019. A sustained low Enable common unit price or further declines in such price could result in CenterPoint Energy recording an impairment charge in future periods. If the decrease in value of CenterPoint Energy’s investment in Enable is determined to be other than temporary, an impairment will be recognized equal to the excess of the carrying value of the investment in Enable over its estimated fair value. Management would evaluate and likely weight both the income approach and market approach to estimate the fair value of the total investment in Enable, which includes CenterPoint Energy’s holdings of Enable common units, general partner interest and incentive distribution rights. The determination of fair value will consider a number of relevant factors including Enable’s

forecasted results, recent comparable transactions and the limited float of Enable’s publicly traded common units. As of December 31, 2019, the carrying value of CenterPoint Energy’s total investment in Enable was $10.29 per unit. On December 31, 2019, Enable’s common unit price closed at $10.03, based on its publicly traded common units which represent approximately 21% of total outstanding units, (an aggregate of approximately $61 million below carrying value). On February 24, 2020, Enable’s common unit price closed at $7.63 (approximately $622 million below carrying value).

Unbilled Revenues

Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through AMS meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Infrastructure Services provides underground pipeline construction and repair services. The contracts are generally less than one year in duration and consist of fixed price, unit, and time and material customer contracts. Under unit or time and material contracts, services are billed to customers monthly or more frequently for work completed based on units completed or the costs of time and material incurred and generally require payment within 30 days of billing. Infrastructure Services has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied, and therefore recognizes revenue at a point in time in the amount to which it has the right to invoice, which results in accrued unbilled revenues at the end of each accounting period. Under fixed price contracts, Infrastructure Services performs larger scale construction and repair services. Services performed under fixed price contracts are typically billed per the terms of the contract, which can range from completion of specific milestones to scheduled billing intervals. Billings occur monthly or more frequently for work completed and generally require payment within 30 days of billing. Revenue for fixed price contracts is recognized over time as control is transferred using the input method, considering costs incurred relative to total expected cost. Total expected cost is therefore a significant judgment affecting the amount and timing of revenue recognition.

Pension and Other Retirement Plans

CenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. CenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to its plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, CenterPoint Energy’s actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension and other retirement plans expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2(u) to the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect the Registrants.

OTHER SIGNIFICANT MATTERS

Pension Plans (CenterPoint Energy). As discussed in Note 8(b) to the consolidated financial statements, CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering eligible employees. Employer contributions for the qualified plan are based on actuarial computations that establish the minimum contribution required under ERISA and the maximum deductible contribution for income tax purposes.

Under the terms of CenterPoint Energy’s pension plan, it reserves the right to change, modify or terminate the plan. CenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.

Additionally, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans that allows participants to receive the benefits to which they would have been entitled under the non-contributory qualified pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.

CenterPoint Energy’s funding requirements and employer contributions for the years ended December 31, 2019, 2018 and 2017 were as follows:



	Year Ended December 31,
	2019		2018		2017
CenterPoint Energy	(in millions)
Minimum funding requirements for qualified pension plans	$	86	$	60	$	39
Employer contributions to the qualified pension plans	86		60		39
Employer contributions to the non-qualified benefit restoration plans	23		9		9

CenterPoint Energy expects to contribute a minimum of approximately $76 million to the qualified pension plans and contributions aggregating approximately $7 million to the non-qualified benefit restoration plans in 2020.

Changes in pension obligations and assets may not be immediately recognized as pension expense in CenterPoint Energy’s Statements of Consolidated Income, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.

As the sponsor of a plan, CenterPoint Energy is required to (a) recognize on its Consolidated Balance Sheet an asset for the plan’s over-funded status or a liability for the plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of the fiscal year and (c) recognize changes in the funded status of the plans in the year that changes occur through adjustments to other comprehensive income and, when related to its rate-regulated utilities with recoverability of cost, to regulatory assets.

The projected benefit obligation for all defined benefit pension plans was $2.5 billion and $2.0 billion as of December 31, 2019 and 2018, respectively.

As of December 31, 2019, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $448 million. Changes in interest rates or the market values of the securities held by the plan during 2020 could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions.

Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension cost and the impact to pre-tax earnings, after capitalization and regulatory impacts, by Registrant were as follows:



	Year Ended December 31,
	2019						2018						2017
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Pension cost	$	93	$	40	$	35	$	61	$	25	$	22	$	95	$	42	$	35
Impact to pre-tax earnings	72		23		31		64		27		23		71		23		29

The calculation of pension cost and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.

As of December 31, 2019, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 5.75%, which is 0.25% lower than the 6.00% rate assumed as of December 31, 2018. The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class. CenterPoint Energy regularly reviews its actual asset allocation and periodically rebalances plan assets to reduce volatility and better match plan assets and liabilities.

As of December 31, 2019, the projected benefit obligation was calculated assuming a discount rate of 3.20%, which is 1.15% lower than the 4.35% discount rate assumed as of December 31, 2018. The discount rate was determined by reviewing yields on

high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of CenterPoint Energy’s plans.

CenterPoint Energy’s actuarially determined pension and other postemployment expense for 2019 and 2018 that is greater or less than the amounts being recovered through rates in certain Texas jurisdictions is deferred as a regulatory asset or liability, respectively. Pension cost for 2020, including the nonqualified benefit restoration plan, is estimated to be $45 million, of which CenterPoint Energy expects approximately $52 million to impact pre-tax earnings after effecting such deferrals and capitalization, based on an expected return on plan assets of 5.75% and a discount rate of 3.20% as of December 31, 2019. If the expected return assumption were lowered by 0.50% from 5.75% to 5.25%, 2020 pension cost would increase by approximately $10 million.

As of December 31, 2019, the pension plans projected benefit obligation, including the unfunded nonqualified pension plans, exceeded plan assets by $448 million. If the discount rate were lowered by 0.50% from 3.20% to 2.70%, the assumption change would increase CenterPoint Energy’s projected benefit obligation by approximately $127 million and decrease its 2020 pension cost by approximately $5 million. The expected reduction in pension cost due to the decrease in discount rate is a result of the expected correlation between the reduced interest rate and appreciation of fixed income assets in pension plans with significantly more fixed income instruments than equity instruments. In addition, the assumption change would impact CenterPoint Energy’s Consolidated Balance Sheets by increasing the regulatory asset recorded as of December 31, 2019 by $110 million and would result in a charge to comprehensive income in 2019 of $13 million, net of tax of $4 million, due to the increase in the projected benefit obligation.

Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact CenterPoint Energy’s future pension expense and liabilities. CenterPoint Energy cannot predict with certainty what these factors will be in the future.

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