The Registrants are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. The following discussion is based on regulation in the Registrants’ businesses and CenterPoint Energy’s investment in Enable as of December 31, 2019.2021.
The FERC has jurisdiction under the NGA and the NGPA, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions, to conduct audits and investigations, and to impose significant civil penalties (up to approximately $1.29 million per day per violation, subject to periodic adjustment to account for inflation) for statutory violations and violations of the FERC’s rules or orders. CenterPoint Energy’s and CERC’s Energy Services reportable segment markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.
As a public utility holding company, under the Public Utility Holding Company Act of 2005, CenterPoint Energy and its consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.
For a discussion of the Registrants’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
State and Local Regulation – Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)
Houston Electric conducts its operations pursuant to a certificate of convenience and necessity issued by the PUCT that covers its present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by Houston Electric under cost-of-service rate regulation. Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 2030 to 40 years.
Houston Electric’s distribution rates charged to REPs for residential and small commercial customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of large commercial and industrial customers are primarily based on peak demand. All REPs in Houston Electric’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge includesmay include the transmission and distribution rate (which includes municipal franchise fees), a distribution recovery mechanism for recovery of incremental distribution-invested capital above that which is already reflected in the base distribution rate, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an EECREECRF charge, and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services.
With the IURC’s approval, Indiana Electric is a member of the MISO, a FERC-approved regional transmission organization. The MISO serves the electrical transmission needs of much of the midcontinentMidcontinent region and maintains operational control over Indiana Electric’s electric transmission and generation facilities as well as those of other utilities in the region.
Indiana Electric is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing as determined by the MISO market. Indiana Electric also receives transmission revenue that results from other members’ use of Indiana Electric’s transmission system. Generally, these transmission revenues, along with costs charged by the MISO, are considered components of base rates and any variance from that included in base rates is recovered from or refunded to retail customers through tracking mechanisms.
For a discussion of certain of Houston Electric’s and Indiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
Indiana Electric owns and operates 1,000 MW of coal-fired generation, 163 MW of gas-fired generation and 454 MW of solar generation. Indiana Electric’s newest in-service solar array, which was approved by the IURC in 2018, consists of approximately 150,000 solar panels distributed across 300 acres along Indiana State Road 545 between Troy and New Boston, Indiana. The 50 MW universal solar array was placed in service for southwestern Indiana electric customers in early 2021. On February 9, 2021, Indiana Electric entered into a BTA with a subsidiary of Capital Dynamics. Pursuant to the BTA, Capital Dynamics, with its partner Tenaska, contracted to build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, currently projected to be at the end of 2023, and subject to IURC approval, which was received on October 27, 2021, Indiana Electric will acquire Posey Solar and its solar array assets for a fixed purchase price. Due to rising cost for the project, caused in part by supply chain issues in the energy industry and the rising costs of commodities, we, along with Capital Dynamics, recently announced plans to downsize the project to approximately 200 MW. Indiana Electric collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval. Indiana Electric also received approval to purchase 100 MW of solar power in Warrick County, Indiana, under a 25 year PPA, with the related solar array expected to be completed in late 2023. Indiana Electric has also sought approval to purchase 185 MW of solar power in Vermillion County, Indiana, under a 15-year PPA, and 150 MW of solar power in Knox County, Indiana, under a 20-year PPA. Subject to necessary approvals, both solar arrays are expected to be in service by 2023. Indiana Electric also is party to two purchase power agreements,PPAs, entitling it to the delivery of up to 80 MW of electricity produced by wind turbines. The energy and capacity secured from Indiana Electric’s available generation resources are utilized primarily to serve the needs of retail electric customers residing within Indiana Electric’s franchised service territory. Costs of operating Indiana Electric’s generation facilities are recovered through IURC-approved base rates as well as periodic rate recovery mechanisms including the CECA, DSMA, ECA, FAC, MCRA, and RCRA Mechanism and TDSIC.Mechanism. Costs that are deemed unreasonable or imprudent by the IURC may not be recoverable through retail electric rates. Indiana Electric also receives revenues from the MISO to compensate it for benefits the generation facilities provide to the transmission system. Proceeds from the sales of energy from Indiana Electric’s generation facilities that exceed the requirements of retail customers are shared by Indiana Electric and retail electric customers.
The generation facilities owned and operated by Indiana Electric are subject to various environmental regulations enforced by the EPA and the IDEM. OperationOperations of Indiana Electric’s generation facilities are subject to regulation by the EPA and the IDEM as it pertains to the discharge of constituents from the generation facilities. For further discussion, see “Our Business — Environmental Matters” below.
CenterPoint Energy and CERC anticipate that compliance with PHMSA’s regulations, performance of the remediation activities by CenterPoint Energy’s and CERC’s NGDNatural Gas and intrastate pipelines and verification of records on maximum allowable operating pressure will continue to require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. In particular, the cost of compliance with the DOT’s integrity management rules will depend on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas, may also affect the costs incurred. Implementation by PHMSA of the 2011 and 2016 Acts,Pipes Act, in particular Section 113, acts reauthorizing PHMSA or implementation ofother future acts by PHMSA may result in other regulations or the reinterpretation of existing regulations that could impact compliance costs. In addition, CenterPoint Energy and CERC may be subject to the DOT’s enforcement actions and penalties if they fail to comply with pipeline regulations.
The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2019.2021. The Registrants’ operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric transmission and distribution systems, steam electric and renewable generation systems and the facilities that support these systems, the Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact the Registrants’ business activities in many ways, including, but not limited to:
To comply with these requirements, the Registrants may need to spend substantial amounts and devote other resources from time to time to, among other activities:
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions and monitoring and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and
several liability for costs required to assess, clean up and restore sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and/or property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
Based on current regulatory requirements and interpretations, the Registrants do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on their business, financial position, results of operations or cash flows. In addition, the Registrants believe that their current environmental remediation activities will not materially interrupt or diminish their operational ability. The Registrants cannot assure youprovide assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause them to incur significant costs. The following is a discussion of material current environmental and safety issues, laws and regulations that relate to the Registrants’ operations. The Registrants believe that they are in substantial compliance with these environmental laws and regulations.
There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or
regulations addressing the emissions of GHG on the state, federal, or international level. SomeOn 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 proposalsrule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states that seek review of the lower court’s decision vacating the ACE rule. CenterPoint Energy is currently unable to predict what a replacement rule for either the ACE rule or CPP would require.
To the extent climate changes may occur and such climate changes result in warmer temperatures in the Registrants’ or Enable’s service territories, financial results from the Registrants’ and Enable’s businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s NGDNatural Gas could be adversely affected through lower natural gas sales and Enable’s natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues.sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, or tornadoes.tornadoes and flooding. Since many of the Registrants’ facilities are located along or near the Gulf Coast,Texas gulf coast, increased or more severe hurricanes or tornadoes could increase costs to repair damaged facilities and restore service to customers. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted.
The Registrants’ operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating facilities and natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions. The Registrants may be required to obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. The Registrants may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
The Registrants’ operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material into wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from the Registrants’ pipelines or facilities could result in fines or penalties as well as significant remedial obligations.
Under the Obama administration, the EPA promulgated a set of rules that included a comprehensive regulatory overhaul of defining “waters of the United States” for the purposes of determining federal jurisdiction. The Trump administration signaled its intent to repeal and replace the Obama-era rules. In accordance with this intent, the EPA promulgated a rule in early 2018 that postponed the effectiveness of the Obama-era rules until 2020. Thereafter, the EPA proposed a new set of rules that would narrow the Clean Water Act’s jurisdiction, which were finalized on April 21, 2020. That set of rules was vacated by recent decisions in the U.S. federal district courts in New Mexico and Arizona, and on November 18, 2021, the EPA released in January 2020 anda proposal to reestablish the pre-2015 definition of “waters of the United States” which will become finaleffective upon publication in the Federal Register. Environmental stakeholdersfinalization and certain states have indicated their intent to challenge the new rule and further litigation is likely.publication. The potential impact of any newfurther revisions to the “waters of the United States” regulations on the Registrants’ business, liabilities, compliance obligations or profits and revenues is uncertain at this time.
In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. These new standards are applied at the time of permit renewal and an affected facility must comply with the wastewater discharge limitations no later than December 31, 2023.2023, and the prohibition of wet sluicing of bottom ash no later than December 31, 2025. In February 2019, the IURC approved Indiana Electric’s ELG compliance plan for its F.B. Culley Generating Station, and Indiana Electric is currently finalizing its ELG compliance plan for the remainder of its affected units as part of its ongoing IRP process.
Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of BTA“best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. Indiana Electric is currently completing the required ecological studies and anticipates timely compliance in 2021-2022.2022-2023.
The Registrants’ operations generate wastes, including some hazardous wastes, that are subject to the federal RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.
Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. In 2015, the EPA finalized its CCR Rule, which regulates coal ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s generating plants will continue to be beneficially reused. UnderThe EPA continues to propose amendments to the existingCCR Rule; however, under the CCR Rule as it is currently in effect, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies are necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. In March 2018, Indiana Electric began posting ground water dataPreliminary groundwater monitoring reports annually to its public website in accordance with the requirements of the CCR Rule. This data preliminarily indicates potential groundwater impacts very close to Indiana Electric’s ash impoundments, and further analysis is ongoing.Theongoing. The CCR Rule required companies to complete location restriction determinations by October 18,
2018. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, Indiana Electric iswas required to cease disposal of new ash in the ponds and commence closure of the ponds by August 2020.April 11, 2021. Indiana Electric plans to seekfiled timely requests for extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through December 31,October 15, 2023. The inability to take these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact Indiana Electric’s future operations. Failure to comply with these requirements could also result in an enforcement proceeding, including the imposition of fines and penalties. On January 22, 2021, Indiana Electric received letters from the EPA for both the F.B. Culley and A.B. Brown facilities that determined Indiana Electric’s extension submittals complete and extended the compliance deadline of April 11, 2021 until the EPA issues a final decision on the extension requests. The Culley West pond was closed under CCR provisions applicable to inactive ponds, and closure activities were completed in December 2020. For further discussion about Indiana Electric’s ash ponds, please see Note 16(e) to the consolidated financial statements.
CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of “hazardous substances” into the environment. Classes of PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of the Registrants’ ordinary operations they do, from time to time, generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to recover the costs they incur from the responsible classes of persons. Under CERCLA, the Registrants could potentially be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for associated response and assessment costs, including for the costs of certain health studies.
For information about preexisting environmental matters, please see Note 16(e) to the consolidated financial statements.
CenterPoint Energy is a holding company that conducts all of its business operations through subsidiaries, primarily Houston Electric, CERC, SIGECO, Indiana Gas and VEDO. CenterPoint Energy also owns interests in Enable. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this combined report on Form 10-K, summarizes the principal risk factors associated with the holding company and the businesses conducted by its subsidiaries and its interests in Enable.subsidiaries. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect CenterPoint Energy’s businesses. For other factors that may cause actual results to differ from those indicated in any forward-lookingforward-
Our businesses are capital intensive, and we rely on various sources to finance our capital expenditures. For example, we depend on (i) long-term debt, (ii) borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs (iii) distributions from CenterPoint Energy’s interests in Enable and (iv)(iii) if market conditions permit, issuances of additional shares of common and/or preferred stock by CenterPoint Energy. We may also use such sources to refinance any outstanding indebtedness as it matures. As of December 31, 2019,2021, CenterPoint Energy had $15.1$16 billion of outstanding indebtedness on a consolidated basis, which includes $977$537 million of non-recourse Securitization Bonds. For information on outstanding indebtedness of Houston Electric and CERC as well as future maturities, through 2024, see Note 14 to the consolidated financial statements. Our future financing activities may be significantly affected by, among other things:
has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. As of December 31, 2019, SIGECO had approximately $293 million aggregate principal amount of first mortgage bonds outstanding. SIGECO may issue additional bonds under its Mortgage Indenture up to 60% of currently unfunded property additions. As of December 31, 2019, approximately $1.1 billion of additional first mortgage bonds could be issued on this basis. However, under certain circumstances Indiana Electric is limited in its ability to issue additional bonds under the Mortgage Indenture due to a provision in its parent’s, VUHI, indentures.
The Registrants’ current credit ratings and any changes in credit ratings in 20192021 and to date in 20202022 are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Other Matters — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be loweredreduced or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are not recommendations to buy, sell or hold their securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on their ability to access capital on acceptable terms.
The imposition of certain ring-fencing measures at Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations.
As part of its most recent base rate proceeding, Houston Electric has agreed, as part of a settlement, to certain “ring-fencing” measures to increase its financial separateness from CenterPoint Energy. As part of the Stipulation and Settlement Agreement, Houston Electric and CenterPoint Energy are subject to various ring-fencing measures. For further information about the Stipulation and Settlement Agreement, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report. Additionally, further ring-fencing measures could be imposed on Houston Electric in the future through legislation or PUCT rules or orders. As a result of such ring-fencing measures, CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations could be materially adversely affected.
Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect the cost of capital related to outstanding debt and other financial instruments.
The LIBOR is the basic rate of interest widely used as a global reference for setting interest rates on variable rate loans and other securities. Each of the Registrants’ credit and term loan facilities, including certain facilities or financial instruments entered into by their subsidiaries, use LIBOR as a reference rate. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. If LIBOR reference rates become unavailable, any LIBOR borrowings under the Registrants’ credit and term loan facilities would convert at the end of the applicable interest period to alternate base rate loans and any future borrowings thereunder would be made as alternate base rate loans. Alternate base rate loans generally constitute a higher cost of capital.
Certain of CenterPoint Energy’s credit and term loan facilities provide for a mechanism to amend such facility to reflect the establishment of an alternative reference rate upon the inability to determine the LIBOR-based Eurodollar rate or occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement or unavailability of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial markets could have a material adverse effect on our financial condition, results of operations and cash flows.
An impairment of goodwill, long-lived assets, including intangible assets, equity method investments and an impairment or fair value adjustment to CenterPoint Energy’s Enable Series A Preferred Unit investment could reduce our earnings.
Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States of America require CenterPoint Energy to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amountvalue may not be recoverable. As a result ofGoodwill is tested for impairment at least annually, as well as when events or changes in circumstances indicates that the Merger, CenterPoint Energy has increased the amount of goodwill and other intangible assets on its consolidated financial statements that are subject to impairment based on future adverse changes to the acquired businesses or general market conditions.
In connection with its preparation of financial statements forcarrying value may not be recoverable. During the year ended December 31, 2019, CenterPoint Energy and CERC, as applicable, identified triggering events for interim goodwill impairment tests at their Infrastructure Services and Energy Services reporting units. Early stage bids received from market participants during the exploration of strategic alternatives for these businesses at year-end indicated that the carrying value of each reporting unit was more likely than not below the fair value. As a result, CenterPoint Energy and CERC evaluated long-lived assets, including property, plant and equipment, and specifically identifiable intangibles subject to amortization, for recoverability and the goodwill within the reporting units was tested for impairment as of December 31, 2019. The long-lived assets within the Infrastructure Services and Energy Services reporting units were determined to be recoverable based on undiscounted cash flows, considering the likelihood of possible outcomes existing as of December 31, 2019, including the assessment of the likelihood of a future sale of these assets.
CenterPoint Energy and CERC recognized an impairment loss of $48 million, the amount by which the carrying value (inclusive of deferred income tax liabilities of $25 million) of their respective Energy Services reporting unit exceeded fair value as of December 31, 2019. Following the impairment, the carrying value of the goodwill remaining in the Energy Services reporting unit is $62 million as of December 31, 2019. CenterPoint Energy did not recognize any impairments on its Infrastructure Services reporting unit in 2019.
On February 3, 2020, CenterPoint Energy through its subsidiary VUSI, entered intoidentified and recorded a goodwill impairment charge of $185 million in the Securities Purchase Agreement to sell the businesses within its Infrastructure ServicesIndiana Electric reporting unit. As a result, certain assets and liabilities representing a business within this reporting unit that will be transferred under the Securities Purchase Agreement (the “Disposal Group”) met the held for sale criteria during the first quarter of 2020. Because the transaction is structured as an asset sale for income tax purposes, the Disposal Group will exclude the deferred tax liabilities. CenterPoint Energy anticipates recording an impairment loss on assets held for sale of approximately $85 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount.
Additionally, on February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase AgreementNo impairments to sell CES, which represents substantially all of the businesses within the Energy Services reporting unit. Certain assets and liabilities representing a business within this reporting unit that will be transferred under the Equity Purchase Agreement (the “Disposal Group”) met the held for sale criteria during the first quarter of 2020. Because the transaction is structured as an asset sale for income tax purposes, the Disposal Group will exclude the deferred tax liabilities and certain assets and liabilities within the reporting unit that will be retained by CenterPoint Energy and CERC upon closing. CenterPoint Energy and CERC anticipate recording an impairment loss, consisting of both goodwill and long-lived asset impairments, on assets held for sale of approximately $80 million, plus an additional loss for transaction costs, in the first quarter of 2020. The actual amount of the impairment or loss may be materially different from the preliminary amount.
For investments CenterPoint Energy accounts for under the equity method, the impairment test considers whether the fair value of such investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if Enable’s common unit price, distributions or earnings were to decline, and that decline is deemed to be other than temporary, CenterPoint Energy could determine that it is unable to recover the carrying value of its equity investment in Enable. Considerable judgment is used in determining if an impairment loss is other than temporary and the amount of any impairment. Such an impairment occurredrecorded during the year ended December 31, 2015 due2021. See Note 6 to the sustained low Enable common unit price andconsolidated financial statements for further declines in such price that year, among other factors impacting the midstream oil and gas industry. As of December 31, 2019, CenterPoint Energy’s total investment in Enable is $10.29 per unit and Enable’s common unit price closed at $10.03 per unit (approximately $61 million below carrying value). Based on an analysis of its investment in Enable as of December 31, 2019, CenterPoint Energy believes that the decline in the value of its investment is temporary, and that the carrying value of its investment of $2.4 billion will be recovered. On February 24, 2020, Enable’s common unit price closed at $7.63 (approximately $622 million below carrying value). A sustained low Enable common unit price could result in CenterPoint Energy again recording impairment charges in the future.
For investments CenterPoint Energy accounts for as investments without a readily determinable fair value, such as the Enable Series A Preferred Unit investment, the carrying value of the asset may be adjusted to fair value, resulting in a gain or loss in the period, if a transaction on an identical or similar investment in Enable is observed. Additionally, CenterPoint Energy considers qualitative impairment triggers, such as significant deterioration in earnings performance, significant decline in market condition and other factors that raise significant concerns about Enable’s ability to continue as a going concern, to determine if an impairment analysis should be performed on its investment.
information. Should the annual goodwill impairment test or another periodic impairment test or an observable transaction as described above, indicate the fair value of our assets is less than the carrying value, we would be required to take a non-cash charge to earnings with a correlative effect on equity, andincreasing balance sheet leverage as measured by debt to total capitalization. A non-cash impairment charge or fair value adjustment could materially adversely impact our financial condition and results of operations and financial condition.operations.
Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our results of operations, liquidity and financial position.
CenterPoint Energy and its subsidiaries maintain qualified defined benefit pension plans covering certain of its employees. Costs associated with these plans are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, contributions to the plan, the number of plan participants and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and CenterPoint Energy may be required to make unplanned contributions in the event of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations, or government regulations that increase minimum funding requirements or the pension liability. In addition to affecting CenterPoint Energy’s funding requirements, each of these factors could adversely affect our results of operations, liquidity and financial position.
CenterPoint Energy, through Infrastructure Services, also contributes to several multi-employer pension plans. If Infrastructure Services withdraws from these plans, CenterPoint Energy may be required to pay an amount based on the allocable share of the plans’ unfunded vested benefits, referred to as the withdrawal liability. This could adversely affect our results of operations, liquidity and financial position.
The costs of providing health care benefits to our employees and retirees may increase substantially and adversely affect our results of operations and financial condition.
We provide health care benefits to eligible employees and retirees through self-insured and insured plans. In recent years, the costs of providing these benefits per beneficiary increased due to higher health care costs and higher levels of large individual health care claims and overall health care claims. We anticipate that such costs will continue to rise. Further, the effects of health care reform or any future legislative changes could also materially affect our health care benefit programs and costs. Any potential changes and resulting cost impacts, which are likely to be passed on to us, cannot be determined with certainty at this time. Our costs of providing these benefits could also increase materially in the future should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our results of operations and liquidity.
The use of derivative contracts in the normal course of business by the Registrants or Enable could result in financial losses that could negatively impact the Registrants’ results of operations and those of Enable.
The Registrants use derivative instruments, such as swaps, options, futures and forwards, to manage commodity, weather and financial market risks. Enable may also use such instruments from time to time to manage its commodity and financial market risks. The Registrants or Enable could recognize financial losses as a result of volatility in the market values or ineffectiveness of these contracts or should a counterparty fail to perform. Additionally, in the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments would result in significant cash payments, which would adversely impact its cash flows. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows.
CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2019.2021. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. CenterPoint Energy may redeem all of the ZENS at any time at a redemption amount per ZENS equal to the higher of the contingent principal amount per ZENS ($7538 million in the aggregate, or $5.28$2.65 per ZENS, as of December 31, 2019)2021) or the sum of the current market value of the reference shares attributable to one ZENS at the time of redemption. In the event CenterPoint Energy redeems the ZENS, in addition to the redemption amount, it would be required to pay deferred taxes related to the ZENS. CenterPoint Energy’s ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2019,2021, deferred taxes of approximately $429$539 million would have been payable in 2019,2021, based on 20192021 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 20192021 to fund the aggregate redemption amount, capital gains taxes of approximately $149$146 million would have been payable in 2019.2021. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. This could happen if CenterPoint Energy’s creditworthiness were to drop or the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns
or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and ZENS-Related Securities shares would typically ceasebe disposed when ZENS are exchanged and ZENS-Related Securities shares are sold.
Dividend requirements associated with theCenterPoint Energy’s Series A Preferred Stock and the Series B Preferred Stock that CenterPoint Energy issued to fund a portion of the Merger subject it to certain risks.
CenterPoint Energy has issued 800,000 shares of Series A Preferred Stock and 19,550,000 depositary shares, each representing a 1/20th interest in a share of CenterPoint Energy’s Series B Preferred Stock.outstanding. Any future payments of cash dividends, and the amount of any cash dividends CenterPoint Energy pays, on theits Series A Preferred Stock and the Series B Preferred Stock will depend on, among other things, its financial condition, capital requirements and results of operations and the ability of our subsidiaries and Enable to distribute cash to CenterPoint Energy, as well as other factors that CenterPoint Energy’s Board of Directors (or an authorized committee thereof) may consider relevant. Any failure to pay scheduled dividends on the Series A Preferred Stock and the Series B Preferred Stock when due could materially adversely impact our ability to access capital on acceptable terms and would likely have a material adverse impact on the market price of the Series A Preferred Stock, the Series B Preferred Stock, Common Stock and CenterPoint Energy’s debt securities and would prohibit CenterPoint Energy, under the terms of the Series A Preferred Stock and Series B Preferred Stock, from paying cash dividends on or repurchasing shares of Common Stock (subject to limited exceptions) until such time as CenterPoint Energy has paid all accumulated and unpaid dividends on the Series A Preferred Stock and the Series B Preferred Stock.
TheFurther, the terms of the Series A Preferred Stock and the Series B Preferred Stock further provide that if dividends on any of the respective shares have not been declared and paid for the equivalent of three or more semi-annual or six or more quarterly dividend periods, whether or not for
consecutive dividend periods, the holders of such shares, voting together as a single class with holders of any and all other series of CenterPoint Energy’s capital stock on parity with its Series A Preferred Stock or its Series B Preferred Stock (as to the payment of dividends and amounts payable on liquidation, dissolution or winding up of CenterPoint Energy’s affairs) upon which like voting rights have been conferred and are exercisable, will be entitled to vote for the election of a total of two additional members of CenterPoint Energy’s Board of Directors, subject to certain terms and limitations.
Changes in the method of determining LIBOR, or the replacement of LIBOR with an alternative reference rate, may adversely affect the cost of capital related to outstanding debt and other financial instruments.
LIBOR is currently the basic rate of interest widely used as a global reference for setting interest rates on variable rate loans and other securities. Each of the Registrants’ credit and term loan facilities, including certain facilities or financial instruments entered into by their subsidiaries, use LIBOR as a reference rate. The Financial Conduct Authority in the United Kingdom previously announced that it would phase out LIBOR as a benchmark by 2021, but later expressed support for the extension of certain tenors of U.S. dollar LIBOR until June 2023, as well as the replacement of LIBOR by the SOFR. Accordingly, beginning January 1, 2022, the Financial Conduct Authority ceased publishing one week and two-month U.S. dollar LIBOR and is expected to cease publishing all remaining U.S. dollar LIBOR tenors in June 2023. The Federal Reserve has also advised banks to cease entering into new contracts that use U.S. dollar LIBOR as a reference rate.
Because SOFR is a broad U.S. Treasury repo financing rate that represents overnight secured funding transactions, it differs fundamentally from LIBOR. Any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist. Changes in the method of calculating LIBOR, or the replacement of LIBOR with an alternative rate or benchmark such as SOFR, may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect our results of operations, cash flow and liquidity. Each of the Registrants’ credit facilities provide for a mechanism to replace LIBOR with possible alternative benchmarks upon certain benchmark replacement events. We are still currently evaluating the impact of any such potential benchmark replacements or unavailability of LIBOR. Also, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to such potential phase-out and alternative benchmark rates or disruption in the financial markets could materially and adversely affect our financial condition, results of operations and cash flows.
Risk Factors Affecting Electric Generation, Transmission and Distribution Businesses (CenterPoint Energy and Houston Electric)
Rate regulation of Houston Electric’s and Indiana Electric’s businesses may delay or deny their ability to earn an expected return and fully recover their costs.
Houston Electric’s rates are regulated by certain municipalities and the PUCT and Indiana Electric’s rates are regulated by the IURC. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year.year (often either fully or partially historic). Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of Houston Electric’s and Indiana Electric’s control. For Houston Electric, a general base rate proceeding is required 48 months from the date of the order setting rates in its most recent comprehensive rate proceeding, unless the PUCT issues an order extending the deadline to file that general base rate proceeding. For Indiana Electric, a general base rate proceeding is required prior to the expiration of its TDSIC plan, which expires on December 31, 2023. Houston Electric and Indiana Electric can make no assurance that their respective base rate proceedings will result in favorable adjustments to their rates, in full cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings have caused in certain instances, and in the future could cause, Houston Electric and Indiana Electric to recover their investments below their requested levels (such as in the most recent Houston Electric general rate case), below the national average for utilities or below recently approved levels for other utilities in their respective jurisdictions.
For instance, on April 5, 2019, Houston Electric filed its base rate application with the PUCT and the cities in its service area to change its rates, seeking approval for revenue increases of approximately $194 million, excluding a rider to refund approximately $40 million annually over three years. This rate filing was based on a rate base of $6.4 billion, a 50% debt/50% equity capital structure and a 10.4% ROE. Houston Electric also requested a prudency determination on all capital investments made since January 1, 2010; the establishment of a rider to refund approximately $119 million to its customers over three years resulting from the TCJA; updated depreciation rates; and approval to clarify and update various non-rate tariff provisions. After a five-day hearing in June 2019, and following the issuance of a PFD by the administrative law judges who heard the case, the parties entered into a Stipulation and Settlement Agreement. On February 14, 2020, the PUCT approved the Stipulation and Settlement Agreement, which established rates based on a $13 million increase in annual revenues, a capital structure of 42.5% equity/57.5% debt and a 9.4% ROE. The Stipulation and Settlement Agreement requires Houston Electric to file another case within 48 months of the final order and removes the possibility that the deadline would be extended. For more information on Houston Electric’s base rate case, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
The rates that Houston Electric and Indiana Electric are allowed to charge may not match their costs at any given time, a situation referred to as “regulatory lag.” For Houston Electric and Indiana Electric, several interim rate adjustment mechanisms have been implemented to reduce the effects of regulatory lag.lag (for example, DCRF, TCOS, TDSIC, DSMA and RCRA Mechanism), although certain of these mechanisms do not provide for recovery of operations and maintenance expenses. These adjustment mechanisms are subject to the applicable regulatory body’s approval and are subject to limitations that may reduce Houston Electric’s and Indiana Electric’s ability to adjust rates. For Houston Electric, the DCRF mechanism adjusts an electric utility’s ratesfurther information on rate case proceedings and interim rate adjustment mechanisms, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report. See also “—The February 2021 Winter Storm...” below for increases in net distribution-invested capital (e.g., distribution plant and distribution-related intangible plant and communication equipment) since its last comprehensive base rate proceeding, but Houston Electric may only make a DCRF filing once per calendar year and not during a comprehensive base rate proceeding. In connection with the Stipulation and Settlement Agreement, Houston Electric agreed not to file its DCRF in 2020. The TCOS mechanism allows a transmission service provider to update its wholesale transmission rates to reflect changes in transmission-related invested capital, but is only available to Houston Electric twice per calendar year. However, neither of these mechanisms provides for recovery of operations and maintenance expenses.further information.
Similarly, for Indiana Electric, the TDSIC rate mechanism allows electric utilities (that have an IURC-approved seven-year infrastructure improvement plan) to request incremental rate increases every six months to pay for the projects included in that plan, subject to IURC approval. However, the TDSIC allows the utility to recover 80% of the costs as they are incurred, with the remaining costs to be deferred as regulatory assets to be recovered in the next base rate case. TDSIC rate increases are limited to no more than 2% of the utility’s total retail revenues from the prior year. Indiana Electric recovers transmission costs through a FERC-approved formula rate and reflects charges and costs associated with participation in MISO through the MCRA mechanism, which is filed annually. Other non-fuel purchased power costs are recovered annually via the RCRA Mechanism. Electricity suppliers are required to submit energy efficiency plans to the IURC at least once every three years. Indiana Electric recovers program and administrative costs of these plans, including lost revenues and financial incentives, via its annual DSMA mechanism. The DSMA is subject to IURC approval.
Houston Electric and Indiana Electric can make no assurance that filings for such mechanisms will result in favorable adjustments to rates or in full cost recovery. Notwithstanding the application of thesuch rate adjustment mechanisms, discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of Houston Electric’s and Indiana Electric’s costs or enable them to earn an expectedtheir authorized return. In addition, changesChanges to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact Houston Electric’s and Indiana Electric’s ability to recover their costs in a timely manner. Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by Houston Electric or Indiana Electric and deny the full recovery of their cost of service in rates. To the extent the regulatory process does not allow Houston Electric and Indiana Electric to make a full and timely recovery of appropriate costs, their results of operations, financial condition and cash flows could be materially adversely affected.
Unlike Houston Electric, Indiana Electric must seek approval by the IURC for long-term financing authority and by the FERC for its short-term financing authority. This authority allows Indiana Electric the flexibility to enter into various financing arrangements. In the event that the IURC or the FERC do not approve Indiana Electric’s financing authority, Indiana Electric may not be able to fully execute its financing plans and its financial condition, results of operations and cash flows could be materially adversely affected.
Disruptions at power generation facilities owned by third parties or Indiana Electric or directives issued by regulatory authorities could interruptcause interruptions in Houston Electric’s sales ofand Indiana Electric’s ability to provide transmission and distribution services.services and adversely affect their reputation, financial condition, results of operations and cash flows.
Houston Electric transmitsowns the transmission and distributes to customers of REPsdistribution infrastructure that delivers electric power that the REPs obtain from power generation facilities owned by third parties. Houston Electricto its customers, but it does not own or operate any power generation facilities. IfAs allowed by a new law enacted by the Texas legislature after the February 2021 Winter Storm Event, Houston Electric is now leasing mobile generation units that can provide temporary emergency electric energy and aid in restoring power to some customers during certain widespread power outages that are impacting its distribution system. In February 2021, the ERCOT regulated Texas electric system experienced extreme winter weather conditions and an unprecedented power generation is disrupted or ifshortage. The amount of electricity generated by the state’s power generation companies was insufficient to meet the amount demanded by customers. This resulted in ERCOT directing TDUs to significantly Load Shed, which caused outages across the ERCOT electric grid of Texas, including in Houston Electric’s service territory. See Note 7 to the consolidated financial statements for further information. If power generation capacity is severely disrupted again or is inadequate for any reason, or if ERCOT needs to issue directives to TDUs (such as Houston Electric) to Load Shed, Houston Electric’s sales of transmission and distribution services may be diminished or interrupted,interrupted; it could have claims and litigation filed against it; and its reputation, financial condition, results of operations and cash flows could be adversely affected. For more information, see “— Houston Electric’s use of temporary ...” and “— The February 2021 Winter Storm ...”
Similarly, while Indiana Electric generates power, it is also party to a number of PPAs with third parties. Indiana Electric’s power generation may be disrupted or otherwise insufficient, if third parties do not deliver required power under our PPAs, power generation capacity is inadequate or MISO issues directives to its members (such as Indiana Electric) to implement controlled outages as a result of an emergency or due to reliability issues. If such disruptions were to occur, Indiana Electric’s transmission and distribution services may be diminished or interrupted; it could have claims and litigation filed against it; and its reputation, financial condition, results of operations and cash flows could be adversely affected.
Houston Electric’s and Indiana Electric’s revenues and results of operations are seasonal.
A significant portion of Houston Electric’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Similarly, Indiana Electric’s revenues are derived from rates it charges its customers to provide electricity. Houston Electric’s and Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage. Houston Electric’s revenues are generally higher during the warmer months. As in certain past years, unusually mild weather in the warmer months could diminish Houston Electric’s results of operations and harm its financial condition. Conversely, as in certain past years, extreme warm weather conditions could increase Houston Electric’s results of operations in a manner that would not likely be annually recurring.
A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, as in certain past years, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while more extreme seasonal weather conditions could increase Indiana Electric’s results of operations in a manner that would not likely be annually recurring.
Indiana Electric’s execution of its IRP and its regulated power supply operations are subject to various risks, including timely recovery of capital investments, increased costs and facility outages or shutdowns.
Indiana requires each electric utility to perform and submit an IRP every three years, unless extended, to the IURC that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next 20-year period on a periodic basis. Indiana Electric’s 2016 IRP modeling projects that the lowest cost and least risk generation portfolio to serve customers over the next 20 years involves retirement of a significant portion of its current generating fleet and replacing that generation capacity with other resources. Implementation of Indiana Electric’s IRP will likely require recovery of new capital investments, as well as costs of retiring the current generation fleet, including any remaining unrecovered costs of retired assets. In February 2018, as part of its electric generation transition plan, Indiana Electric filed a petition seeking authorization from the IURC to construct a new 700-850 MW natural gas combined cycle generating facility to replace certain existing generation capacity at an approximate cost of $900 million, which included the cost of a new natural gas pipeline to serve the facility, among other things. While the IURC approved the construction of a 50 MW universal solar array and the plan to retrofit its largest, most efficient coal-fired generation unit (Culley Unit 3), the IURC denied Indiana Electric’s request to construct a 700-850 MW natural gas combined cycle generating facility. The IURC urged Indiana Electric to utilize its next IRP planning cycle to evaluate the merits of a more diverse generation portfolio.
During the 2019 Indiana legislative session, certain proposed legislation would have prohibited the construction of new generation assets 250 MW or larger until 2021, among other prohibitions, by directing the IURC to not issue any final orders in proceedings requesting such construction. Although this proposed legislation was ultimately defeated, a similar moratorium on the construction of new generation assets in Indiana could be reintroduced in a subsequent legislative session. Legislation has been proposed in 2020 that would require IURC approval to retire coal-fired generation. This legislation, by its terms, would sunset in early 2021 and is not expected to impact Indiana Electric as currently drafted.
With respect to its upcoming IRP, Indiana Electric has conducted a request for proposals targeting 10 to 700 MW of capacity and unit-contingent energy and anticipates filing its 2019/2020 IRP in mid-2020. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. Depending on comments received on the IRP, the filing of any future requests for generating facilities could be delayed. Further, certain legislative activities such as the proposed moratorium in 2019 or other legislation restricting or delaying new generation could negatively affect Indiana Electric’s ability to construct new generation facilities and execution of its capital plan. Even if a generation project is approved, risks associated with the construction of any new generation exist, including the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays and cost overruns and the ability to meet capacity requirements. Further, there is no guarantee that the IURC will approve the requests included in any of Indiana Electric’s future filed petitions relating to its IRP.
Additionally, Indiana Electric’s generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, increased purchase power costs and inadvertent releases of coal ash and/or other contaminants with a significant environmental impact. These operational risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; or natural disasters, all of which could adversely affect Indiana Electric’s business. Further, Indiana Electric currently relies on coal for substantially all of its generation capacity. Currently, Indiana Electric purchases substantially all of its coal supply is purchased largely from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier or transportation interruptions could adversely affect Indiana Electric’s financial condition, results of operations and cash flows. In 2021, Indiana Electric experienced coal supply shortages due to labor shortages that the coal industry is experiencing. While the coal supply shortage that Indiana Electric experienced did not impact its ability to deliver electricity to its customers, labor shortages as well as supply shortages in the future, whether caused by insufficient supply or supplier bankruptcy or other regulatory and supply issues in the mining industry, may lead to increased cost and have a material adverse impact on our operations, which could have a material adverse effect on our financial condition, results of operations and cash flows. See “— Continued disruptions to the supply...”
Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in such payments could adversely affect Houston Electric’s financial condition, results of operations and cash flows.
Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity. As of December 31, 2021, Houston Electric provided electric delivery service to approximately 59 REPs. Adverse economic
conditions, such as the impact of COVID-19, the February 2021 Winter Storm Event, structural problems in the market served by ERCOT, inflation 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. Houston Electric’s PUCT-approved tariff outlines the remedies available to Houston Electric in the event that a REP defaults on amounts owed. Among the remedies available to Houston Electric are seeking recourse against any cash deposit, letter of credit, or surety bond provided by the REP or implementing mutually agreeable terms with the REP. Another remedy is to require that customers be shifted to another REP or a provider of last resort. Houston Electric thus remains at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are from affiliates of NRG and Vistra Energy Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2021 was $207 million. Approximately 40% and 18% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s financial condition, results of operations and cash flows. If a REP was 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 regarding prior payments Houston Electric had received from such REP. For example, following the February 2021 Winter Storm Event, multiple REPs filed for bankruptcy. We are currently capturing the amounts owed by the REPs as a permitted regulatory asset for bad debt expenses, which will be subject to a reasonableness review by the PUCT when we seek recovery in our next base rate case.
Indiana Electric’s execution of its generation transition plan, including its IRP, are subject to various risks, including timely recovery of capital investments and increased costs and risks related to the timing and cost of development and/or construction of new generation facilities.
Indiana requires each electric utility to perform and submit an IRP every three years, unless extended, to the IURC that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next 20-year period on a periodic basis. In February 2018, as part of its electric generation transition plan, Indiana Electric received approval from the IURC to construct a 50 MW universal solar array and a plan to retrofit its largest, most efficient coal-fired generation unit (Culley Unit 3). With respect to its 2019/2020 IRP submitted to the IURC in June 2020, Indiana Electric identified a preferred generation resource that includes the replacement of 730 MW of coal-fired generation facilities with a significant portion composed of renewables, including solar and wind, supported by dispatchable natural gas combustion turbines, including a pipeline to serve such natural gas generation, as well as storage. While the IURC does not approve or reject the IRP, the process involves the issuance of a staff report that provides comments on the IRP. On November 17, 2021, Indiana Electric received the staff report on the IRP. Further, there is no guarantee that the IURC will approve the requests included in any of Indiana Electric’s future filed petitions relating to its IRP.
Even if a generation project is approved, risks associated with the development or construction of any new generation exist, including new legislation restricting or delaying new generation, moratorium legislation, the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays, project scope changes, and cost overruns and the ability to meet capacity requirements. For example, we, along with our developers of the Posey solar project, have recently announced plans to downsize the Posey solar project from 300 MW to 200 MW due to supply chain issues experienced in the energy industry, the rising cost of commodities and community feedback. For additional information, see “— Continued disruptions to the supply...” Furthermore, we have announced our intent to acquire and/or develop additional solar and wind facilities as part of our capital plan. However, we have not yet entered into definitive agreements with developers for the acquisition and/or development of such additional projects, and we face significant competition with other bidders for a limited number of such generation facilities that developers plan to construct, including those that are in an acceptable position on the MISO interconnection queue. As a result, suitable generation facility project candidates may not be available on terms and conditions we find acceptable, or the expected benefits of a completed facility may not be realized fully or at all, or may not be realized in the anticipated timeframe. If we are unable to complete or acquire such generation facilities, or if they do not perform as anticipated, our future growth, financial condition, results of operations and cash flows may be adversely affected.
Houston Electric and Indiana Electric, as a member of ERCOT and MISO, respectively, could be subject to higher costs for system improvements, as well as fines or other sanctions as a result of FERC mandatory reliability standards.
Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, the FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. The FERC has designated the NERC as the
ERO to promulgate standards,
under FERC oversight, for all owners, operators and users of the bulk power system. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation and for reliability in the portion of MISO that includes Indiana Electric to ReliabilityFirst Corporation, a Delaware non-profit corporation. Compliance with mandatory reliability standards may subject Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures, which may not be fully recoverable in rates. In addition,While Houston Electric and Indiana Electric have received minor fines in the past for noncompliance, if Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards again, they couldwould be subject to sanctions, including substantial monetary penalties.penalties, which could range as high as over a million dollars per violation per day, and non-monetary penalties, such as having to file a mitigation plan to prevent recurrence of a similar violation and having certain milestones in such plan tracked.
In connection with the February 2021 Winter Storm Event, there have been calls for reform of the Texas electric market, some measure of which, if implemented, could have material adverse impacts on Houston Electric.
Various governmental and regulatory agencies and other entities have called for or are conducting inquiries and investigations into the February 2021 Winter Storm Event and the efforts made by various entities to prepare for, and respond to, this event, including the electricity generation shortfall issues. Such agencies and entities include the United States Congress, FERC, NERC, Texas RE, ERCOT, Texas government entities and officials such as the Texas Governor’s office, the Texas Legislature, the Texas Attorney General, the PUCT, the City of Houston and other municipal and county entities in Houston Electric’s receivablesservice area, among other entities. In addition to questions around preparation and response, some federal and other officials, as well as members of the public and media, have called for reviews and reforms of the Texas electric market, including whether it should continue to be governed by ERCOT or instead be subject to FERC jurisdiction and regulation by joining an ISO such as MISO, as well as the division of the market between power generators, TDUs (such as Houston Electric) and REPs. There are primarily concentratedsignificant uncertainties around these discussions and whether any market structure or governance changes will result therefrom, but if any such reviews and reform efforts ultimately result in changes to how the Texas electric market is structured or regulated, such changes could have a small number of REPs, and any delay or default in such payments could adversely affectmaterial adverse impact on Houston Electric’s cash flows,business, financial condition and results of operations. See “—The February 2021 Winter Storm...” below and Note 7 to the consolidated financial statements for further information.
Houston Electric’s receivables fromuse of temporary mobile generation resources is subject to various risks, including related failure to obtain and deploy sufficient mobile generation units, potential performance issues and allegations about Houston Electric’s deployment of the distributionresources (including the planning, execution, and effectiveness of electricity are collected from REPsthe same), regulatory and environmental requirements, and timely recovery of capital.
Following the February 2021 Winter Storm Event, the Texas legislature passed a new law, effective September 1, 2021, that supply the electricityallows TDUs, like Houston Electric, distributes to their customers. As of December 31, 2019,lease and operate temporary back-up generation resources during widespread power outages where ERCOT has ordered a TDU to shed load or the TDU’s distribution facilities are not being fully served by the bulk power system under normal operations. In response to this legislation, Houston Electric did businesshas entered into short-term and long-term leases with approximately 68 REPs. Adverse economic conditions, structural problemsa third party provider to obtain mobile generation units.
However, if Houston Electric is otherwise unable to deploy a sufficient number of mobile generation units in time to respond to a particular event; if the market served by ERCOTmobile generation units fail to perform as intended; if Houston Electric is otherwise unable to provide back-up generation resources and restore power as intended; or financial difficultiesif the use of onemobile generation units or more REPstheir failure to perform causes or is alleged to cause any personal injury, property damage, or other damage or loss due to allegations that it failed to deploy such units reasonably or effectively and failed to respond to particular power outages, Houston Electric could impairbe subject to claims, demands, litigation, liability, regulatory scrutiny, and loss of reputation. As noted above, the ability of these REPs to paylegislation prescribes specific and limited use for the mobile generation units, and Houston Electric’s services ormobile generation units have limited generation capacity, such that in future events customers could cause them to delay such payments.still be without power despite deployment of the mobile units.
While Houston Electric depends on these REPshas insurance coverage and indemnity rights for its use of mobile generation units, if its insurers or indemnitors fail to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. Applicable PUCT regulations significantly limit the extent to whichmeet their indemnity obligations, Houston Electric can apply normal commercial termscould be liable for personal injury, property damage, or otherwiseother damage or loss. Further, the mobile generation units are subject to various environmental regulations and permitting requirements, which could have an impact on Houston Electric’s ability to use these units, and noncompliance with which could subject Houston Electric to further potential liability. The use of mobile generation units is also subject to various requirements of the new legislation, and failure to comply with them could subject Houston Electric to additional liability as well as challenges to its use of mobile generation in general. While Houston Electric will seek credit protection from firms desiring to provide retail electric service in its service territory,recover the costs of the lease and use of mobile generation units, such recovery is not certain, and Houston Electric thus remains at risk for payments relatedElectric’s inability to services provided prior to the shift to another REP or the providerrecover its costs could have a material adverse impact on its financial condition, results of last resort. A significant portionoperations and cash flows. For further information, see “— Rate Regulation of Houston Electric’s billed receivables from REPsElectric’s...”, “— Our insurance coverage may not...” and “— We are from affiliates of NRG and Vistra Energy Corp., formerly known as TCEH Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2019 was $192 million. Approximately 32% and 12% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows, financial condition and results of operations. If a REP were unablesubject to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made by creditors involving payments Houston Electric had received from such REP.operational...”
Risk Factors Affecting Natural Gas Distribution and Competitive Energy Services BusinessesGas’ Business (CenterPoint Energy and CERC)
On February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to sell CES, which represents substantially all of the businesses within the Energy Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.
Rate regulation of NGDNatural Gas may delay or deny its ability to earn an expected return and fully recover its costs.
NGD’sNatural Gas’ rates are regulated by certain municipalities (in Texas only) and state commissions based on an analysis of NGD’sNatural Gas’ invested capital, expenses and other factors in a test year (often either fully or partially historic) in comprehensive base rate proceedings, subject to periodic review and adjustment. Each of these proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of NGD’sNatural Gas’ control. NGDDuring 2022, Natural Gas has a pending or anticipatesrate case and a proceeding considering recovery of extraordinary natural gas costs during the filing of, rate casesFebruary 2021 Winter Storm Event in Indiana,Minnesota. In the Minnesota extraordinary natural gas cost proceeding, various parties have proposed significant disallowances for all natural gas utilities ranging from $45 million to $409 million for CenterPoint Energy and Texas during 2020. NGDCERC. Natural Gas can make no assurance that these respective base rate and cost recovery proceedings will result in favorable adjustments to its rates, full or adequate cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, theseThese base rate proceedings could cause NGDNatural Gas to recover its investments at rates below its requested level, below the national average for utilities or below recently approved levels for other utilities in those jurisdictions.
The rates that NGDNatural Gas is allowed to charge may not match its costs at any given time, resulting in what is referred to as “regulatory lag.” For example, the MPUC has ordered that the amortization period for extraordinary gas costs resulting from the February 2021 Winter Storm Event be increased from 27-months to 63-months beginning on January 1, 2022, and that CERC forego recovery of the associated carrying costs. Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by NGDNatural Gas to reduce the effects of regulatory lag (for example, CSIA, DRR,GRIP, RRA and RSP), such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be approved, and are subject to certain limitations that may reduce or otherwise impede NGD’sNatural Gas’ ability to adjust its rates or result in rates below those requested by NGD.Natural Gas.
Arkansas allows public utilities to elect to have their rates regulated pursuant to a FRP, providing for a utility’s base rates to be adjusted once a year. In each of Louisiana, Mississippi and Oklahoma, NGD makes annual filings utilizing various formula rate mechanisms that adjust rates based on a comparison of authorized return to actual return to achieve the allowed return rates in those jurisdictions. Additionally, in Minnesota, the MPUC implemented a full revenue decoupling program, which separates approved revenues from the amount of natural gas used by its customers. Further, in Indiana, NGD may file a CSIA every six months to seek rate increases to recover certain federally mandated project costs (e.g., pipeline safety). The TDSIC (recovered
through the CSIA), allows the utility to recover 80% of its project costs associated with an IURC-approved seven-year infrastructure improvement plan as they are incurred, with the remaining costs to be deferred until the next base rate case, and rate increases are limited to no more than 2% of the utility’s total retail revenues. In Ohio, the DRR is an annual mechanism that allows a utility to recover its investments in utility plant and operating expenses associated with replacing bare steel and cast-iron pipelines, as well as certain other infrastructure investments. The effectiveness of these filings and programs depends on the approval of the applicable state regulatory body.
In Texas, NGD’s Houston, South Texas, Beaumont/East Texas and Texas Coast divisions each submit annual GRIP filings to recover the incremental capital investments made in the preceding year until a general rate case is filed. NGD must file a general rate case no later than five and a half years after the initial GRIP implementation date.
NGDNatural Gas can make no assurance that filings for such mechanisms will result in favorable adjustments to rates. Notwithstanding the application of the rate mechanisms discussed above, the regulatory process by which rates are determined is subject to change as a result of the legislative process or rulemaking, as the case may be, and may not always be available or result in rates that will produce recovery of NGD’sNatural Gas’ costs or enable NGDNatural Gas to earn an expected return. In addition, changesChanges to the interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact NGD’sNatural Gas’ ability to recover its costs in a timely manner. Additionally, inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may initiate investigations of the prudence of operating expenses incurred or capital investments made by NGDNatural Gas and deny the full recovery of NGD’sNatural Gas’ cost of service or the full recovery of incurred natural gas costs in rates. To the extent the regulatory process does not allow NGDNatural Gas to make a full and timely recovery of appropriate costs, its financial condition, results of operations financial condition and cash flows could be adversely affected. For further information on rate case proceedings and interim rate adjustment mechanisms, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report.
Unlike CERC, Indiana Gas, SIGECO’s natural gas distribution business and VEDO must seek approval by the IURC and PUCO, as applicable, for long-term financing authority. This authority allows these utilities the flexibility to enter into various financing arrangements. In the event that the IURC or PUCO do not approve these utilities’ respective financing authorities, they may not be able to fully execute their financing plans and their respective financial conditions, results of operations and cash flows could be adversely affected. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulatory Matters.”
Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for NGD’sNatural Gas’ customers.
NGDNatural Gas depends on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy its customers’ needs, all of which are critical to system reliability. Substantially all of NGD’sNatural Gas’ natural gas supply is purchased from intrastate and interstate pipelines. If NGDNatural Gas is unable to secure an independent natural gas supply of its own or through its affiliates or if third-party service providers fail to timely deliver natural gas to meet NGD’sNatural Gas’ requirements, the resulting decrease in natural gas supply in NGD’sNatural Gas’ service territories could have a material adverse effect on its financial condition, results of operations and cash flows and financial condition.flows. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, severe winter weather conditions, acts of terrorism or cyber-attackscyberattacks or changes in legislative or regulatory requirements,
could also adversely affect NGD’sNatural Gas’ businesses. Further, to the extent that NGD’sNatural Gas’ natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then NGD’sNatural Gas’ operations could be negatively affected. For additional risks related to the February 2021 Winter Storm Event, see “—The February 2021 Winter Storm...” below and Note 7 to the consolidated condensed financial statements for further information.
NGD and CES areNatural Gas is subject to fluctuations in notional natural gas prices, as well as geographic and seasonal natural gas price differentials, which could affect the ability of theirits suppliers and customers to meet their obligations or otherwisemay impact our operations which could adversely affect their liquidity,CERC’s financial condition, results of operations and financial condition.cash flows.
NGD and CES areNatural Gas is subject to risk associated with changes in the notional price of natural gas as well as geographic and seasonal natural gas price differentials that impact their businesses, including transportation and storage, whether through the use of AMAs or other arrangements.gas. Increases in natural gas prices might affect NGD’s and CES’sNatural Gas’ ability to collect balances due from their customers and for NGD, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which NGD and CES operate,Natural Gas operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that NGD’s and CES’sNatural Gas’ suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels. Additionally, a decrease in natural gas prices could increaseFor additional risks related to the amount of collateral required under hedging arrangements. AMAs may be subjectFebruary 2021 Winter Storm Event, see “—The February 2021 Winter Storm...” below and Note 7 to regulatory approval, and such agreements may not be renewed or may be renewed with less favorable terms.the consolidated condensed financial statements for further information.
A decline in CERC’s credit rating could result in CERC having to provide collateral under its shipping or hedging arrangements or to purchase natural gas, which consequently would increase its cash requirements and adversely affect its financial condition.
If CERC’s credit rating were to decline, it might be required to post cash collateral under its shipping or hedging arrangements or to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s financial condition, results of operations financial condition and cash flows could be adversely affected.
NGD’s and CES’s revenues and results of operations are seasonal.
NGD’s and CES’s revenues are primarily derived from natural gas sales. Thus, their revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish our results of operations and harm our financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase our results of operations in a manner that would not likely be annually recurring.
The states in which NGD provides service may, either through legislation or rules, adopt restrictions regarding organization, financing and affiliate transactions that could have significant adverse impacts on NGD’s ability to operate.
From time to time, proposals have been put forth in some of the states in which NGD does business to give state regulatory authorities increased jurisdiction and scrutiny over organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their affiliates that operate in those states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility business that can be conducted within the holding company structure. Additionally, they may impose record-keeping, record access, employee training and reporting requirements For additional risks related to affiliate transactionsthe February 2021 Winter Storm Event, see “—The February 2021 Winter Storm...” below and reporting inNote 7 to the event of certain downgrading of the utility’s credit rating.consolidated condensed financial statements for further information.
These regulatory frameworks could have adverse effects on NGD’s ability to conduct its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for NGD and us to comply with competing regulatory requirements.
NGD and CESNatural Gas must compete with alternate energy sources, which could result in less natural gas marketeddelivered and have an adverse impact on ourCERC’s financial condition, results of operations financial condition and cash flows.
NGD and CES competeNatural Gas competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with NGD and CESNatural Gas for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass NGD’sNatural Gas’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transporteddelivered by NGD and CESNatural Gas as a result of competition with alternate energy sources may have an adverse impact on ourCERC’s financial condition, results of operations financial condition and cash flows.
Infrastructure Services’ and ESG’sRisk Factors Affecting Energy Systems Group’s Business (CenterPoint Energy)
Energy Systems Group’s operations could be adversely affected by a number of factors.
Infrastructure Services’ and ESG’sEnergy Systems Group’s business results are dependent on a number of factors. The industries areindustry in which Energy Systems Group operates is competitive and many of the contracts are subject to a bidding process. Should Infrastructure Services and ESGEnergy Systems Group be unsuccessful in bidding contracts (e.g.,(for example, federal Indefinite Delivery/Indefinite Quantity contracts for ESG)contracts), results of operations could be impacted. Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work or issues arise where amounts due for work performed may not be collected, the profit margin realized on any single project could be reduced. Changes in legislation and regulations impacting the sectors in which the customers served by Infrastructure Services or ESGEnergy Systems Group operate could adversely impact operating results.
Infrastructure Services enters into a variety of contracts, some of which are fixed price. Other Additionally, Energy Systems Group’s business is subject to other risks that could adversely affect Infrastructure Services include,including, but are not limited to: failure to, properly construct pipeline infrastructure; loss of significant customers or a significant decline in related customer revenues; cancellation of projects by customers and/or reductions in the scope offollowing: the projects; changes in the timing of projects; the inability to obtain materials and equipment required to perform services from suppliers and manufacturers; and changes in the market prices of oil and natural gas and state regulatory requirements that mandate pipeline replacement programs that would affect the demand for infrastructure construction and/or the project margin realized on projects. For ESG, other risks include, but are not limited to: discontinuation of the federal ESPC and UESC programs;
the inability of customers to finance projects; failure to appropriately design, construct or operate projects; increased project delays and backlogs, particularly in the federal sector, increases in costs and shortages in supply materials due to the COVID-19 pandemic and other factors; cancellation of projects by customers and/or reductions in the scope of the projects.projects; and obligations related to warranties, guarantees and other contractual and legal obligations.
In addition, Infrastructure Services has supported CenterPoint Energy’s utilities pursuant to service contracts. In most instances, the ability to maintain these service contracts depends upon regulatory discretion, and there can be no assurance it will be able to obtain future service contracts, or that existing arrangements will not be revisited.
On February 3, 2020, CenterPoint Energy through its subsidiary VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements.
ESG’sSystems Group’s business has performance and warranty obligations, some of which are guaranteed by CenterPoint Energy.
In the normal course of business, ESGEnergy Systems Group issues performance bonds and other forms of assurance that commit it to operate facilities, pay vendors or subcontractors and support warranty obligations. As the parent company, CenterPoint Energy or Vectren has, and will, from time to time guarantee its subsidiaries’ commitments. These guarantiesguarantees do not represent incremental consolidated obligations; rather, they represent parental guarantiesguarantees of subsidiary obligations to allow the subsidiary the flexibility to conduct business without posting other forms of collateral. Neither CenterPoint Energy nor Vectren has been called upon to satisfy any obligations pursuant to these parental guaranties.guarantees to date.
Risk Factors Affecting CenterPoint Energy’s Interests in Enable Midstream Partners, LP (CenterPoint Energy)
CenterPoint Energy holds a substantial limited partner interest in Enable (53.7% of the outstanding common units representing limited partner interests in Enable as of December 31, 2019), as well as 50% of the management rights in Enable GP and a 40% interest in the incentive distribution rights held by Enable GP. As of December 31, 2019, CenterPoint Energy owned an aggregate of 14,520,000 Enable Series A Preferred Units representing limited partner interests in Enable. Accordingly, CenterPoint Energy’s future earnings, results of operations, cash flows and financial condition will be affected by the performance of Enable, the amount of cash distributions it receives from Enable and the value of its interests in Enable. Factors that may have a material impact on Enable’s performance and cash distributions, and, hence, the value of CenterPoint Energy’s interests in Enable, include the risk factors outlined below, as well as the risks described elsewhere under “Risk Factors” that are applicable to Enable.
CenterPoint Energy’s cash flows will be adversely impacted if it receives less cash distributions from Enable than it currently expects or if it reduces its ownership in Enable.
Both CenterPoint Energy and OGE hold their limited partner interests in Enable in the form of common units. CenterPoint Energy also holds Enable Series A Preferred Units. For the Enable Series A Preferred Units, Enable is expected to pay $0.625 per Enable Series A Preferred Unit, or $2.50 per Enable Series A Preferred Unit on an annualized basis. However, distributions on each Enable Series A Preferred Unit are not mandatory and are non-cumulative in the event distributions are not declared on the Enable Series A Preferred Units. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis, on its outstanding common units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Enable GP and its affiliates (referred to as “available cash”). Enable may not have sufficient available cash each quarter to enable it (i) to pay distributions on the Enable Series A Preferred Units or (ii) maintain or increase the distributions on its common units. Additionally, distributions on the Enable Series A Preferred Units reduce the amount of available cash Enable has to pay distributions on its common units. The amount of cash Enable can distribute on its common units and the Enable Series A Preferred Units will principally depend upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:
the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;
the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;
the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;
the relationship among prices for natural gas, NGLs and crude oil;
cash calls and settlements of hedging positions;
margin requirements on open price risk management assets and liabilities;
the level of competition from other companies offering midstream services;
adverse effects of governmental and environmental regulation;
the level of its operation and maintenance expenses and general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including:
the level and timing of its capital expenditures;
the cost of acquisitions;
its debt service requirements and other liabilities;
fluctuations in its working capital needs;
its ability to borrow funds and access capital markets;
restrictions contained in its debt agreements;
the amount of cash reserves established by Enable GP;
distributions paid on the Enable Series A Preferred Units;
any impact on cash levels should any sale of CenterPoint Energy’s investment in Enable occur, as discussed further below; and
other business risks affecting its cash levels.
Additionally, although it has no current plan to do so, CenterPoint Energy may also reduce its ownership in Enable over time through sales in the public equity markets, or otherwise, of the Enable common units it holds, subject to market conditions. CenterPoint Energy’s ability to execute any sale of Enable common units is subject to a number of uncertainties, including the timing, pricing and terms of any such sale. Any sales of Enable common units CenterPoint Energy owns could have an adverse impact on the price of Enable common units or on any trading market for Enable common units. Further, CenterPoint Energy’s sales of Enable common units may have an adverse impact on Enable’s ability to issue equity on satisfactory terms, or at all, which may limit its ability to expand operations or make future acquisitions. Any reduction in CenterPoint Energy’s interest in Enable would result in decreased distributions from Enable and decrease income, which may adversely impact CenterPoint Energy’s ability to meet its payment obligations and pay dividends on its Common Stock. Further, any sales of Enable common units would result in a significant amount of taxes due, which could also significantly impact CenterPoint Energy’s determination to execute any sale. There can be no assurances that any sale of Enable common units in the public equity markets or otherwise will be completed. Any sale of Enable common units in the public equity markets or otherwise may involve significant costs and expenses, including, in connection with any public offering, a significant underwriting discount. CenterPoint Energy may not realize any or all of the anticipated strategic, financial, operational or other benefits from any completed sale or reduction in its investment in Enable. Furthermore, under certain circumstances, including following certain changes in the methodology employed by rating agencies whereby the Enable Series A Preferred Units are no longer eligible for the same or a higher amount of “equity credit” attributed to the Enable Series A Preferred Units on their original issue date (referred to as a “rating event”), Enable has the option to redeem the Enable Series A Preferred Units. There can be no assurances that CenterPoint Energy will be able to reinvest any proceeds from such redemption in a manner that provides for a similar rate of return as the Enable Series A Preferred Units.
The amount of cash Enable has available for distribution to CenterPoint Energy on its common units and the Enable Series A Preferred Units depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which Enable records net income.
The amount of cash Enable has available for distribution on its common units and the Enable Series A Preferred Units, depends primarily upon its cash flows and not solely on profitability, which will be affected by non-cash items. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.
Enable is required to, or may at its option, redeem the Enable Series A Preferred Units in certain circumstances, and Enable may not have sufficient funds to redeem the Enable Series A Preferred Units if required to do so.
As a holder of the Enable Series A Preferred Units, CenterPoint Energy may request that Enable list those units for trading on the NYSE. If Enable is unable to list the Enable Series A Preferred Units in certain circumstances, it will be required to redeem the Enable Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its obligation to redeem the Enable Series A Preferred Units. In addition, mandatory redemption of the Enable Series A Preferred Units could have a material adverse effect on Enable’s business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders.
Additionally, Enable may redeem the Enable Series A Preferred Units under certain circumstances, including following a rating event. Upon a rating event, the Enable Series A Preferred Units may be considered by Enable to be an expensive form of indebtedness. If Enable does not have sufficient funds to exercise its option to redeem the Enable Series A Preferred Units upon a rating event, then such inability could have a material adverse effect on Enable’s business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders.
CenterPoint Energy is not able to exercise control over Enable, which entails certain risks.
Enable is controlled jointly by CenterPoint Energy and OGE, who each own 50% of the management rights in Enable GP. The board of directors of Enable GP is composed of an equal number of directors appointed by OGE and by CenterPoint Energy, the president and chief executive officer of Enable GP and three directors who are independent as defined under the independence standards established by the NYSE. Accordingly, CenterPoint Energy is not able to exercise control over Enable.
Although CenterPoint Energy jointly controls Enable with OGE, CenterPoint Energy may have conflicts of interest with Enable that could subject it to claims that CenterPoint Energy has breached its fiduciary duty to Enable and its unitholders.
CenterPoint Energy and OGE each own 50% of the management rights in Enable GP, as well as limited partner interests in Enable, and interests in the incentive distribution rights held by Enable GP. CenterPoint Energy also holds Enable Series A Preferred Units. Conflicts of interest may arise between CenterPoint Energy and Enable and its unitholders. CenterPoint Energy’s joint control of Enable GP may increase the possibility of claims of breach of fiduciary or contractual duties including claims of conflicts of interest related to Enable. In resolving these conflicts, CenterPoint Energy may favor its own interests and the interests of its affiliates over the interests of Enable and its unitholders as long as the resolution does not conflict with Enable’s partnership agreement. These circumstances could subject CenterPoint Energy to claims that, in favoring its own interests and those of its affiliates, CenterPoint Energy breached a fiduciary or contractual duty to Enable or its unitholders.
Enable is subject to various operational risks, all of which could affect Enable’s ability to make cash distributions to CenterPoint Energy.
The execution of Enable’s businesses is subject to a number of operational risks, which include, but are not limited to, the following:
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• | Contract Renewal: Enable’s contracts are subject to renewal risks. To the extent Enable is unable to renew or replace its expiring contracts on terms that are favorable, if at all, or successfully manage its overall contract mix over time, its financial position, results of operations and ability to make cash distributions could be adversely affected;
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• | Customers: Enable depends on a small number of customers for a significant portion of its gathering and processing revenues and its transportation and storage revenues. The loss of, or reduction in volumes from, these customers or the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could result in a decline in sales of its gathering and processing or transportation
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and storage services and adversely affect Enable’s financial position, results of operations and ability to make cash distributions;
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• | Third-Party Drilling and Production Decisions: Enable’s businesses are dependent, in part, on the natural gas and crude oil drilling and production market conditions and decisions of others, over which Enable has no control. Further, sustained reductions in exploration or production activity in Enable’s areas of operation and fluctuations in energy prices could lead to further reductions in the utilization of Enable’s systems, which could adversely affect its financial position, results of operations and ability to make cash distributions. It may also become more difficult to maintain or increase the current volumes on Enable’s gathering systems and in its processing plants, as several of the formations in the unconventional resource plays in which it operates generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should Enable determine that the economics of its gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, Enable may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time;
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• | Competition: Enable competes with similar enterprises, some of which include public and private energy companies with greater financial resources and access to natural gas, NGL and crude oil supplies, in its respective areas of operation, primarily through rates, terms of service and flexibility and reliability of service. Increased competitive pressure in Enable’s industry, which is already highly competitive, could adversely affect Enable’s financial position, results of operations and ability to make cash distributions;
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• | Cost Recovery of Capital Improvements: Enable may not be able to recover the costs of its substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than it anticipates. In Enable’s Form 10-K for the fiscal year ended December 31, 2019, Enable stated that it expects that its expansion capital could range from approximately $160 million to $240 million and its maintenance capital could range from approximately $110 million to $130 million for the year ending December 31, 2020;
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• | Commodity Prices: Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. Factors affecting prices are beyond Enable’s control and include the following: (i) demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, (ii) the availability of imported natural gas, LNG, NGLs and crude oil, (iii) actions taken by foreign natural gas and oil producing nations, (iv) the availability of local, intrastate and interstate transportation systems, (v) the availability and marketing of competitive fuels, (vi) the impact of energy conservation efforts, technological advances affecting energy consumption and (vii) the extent of governmental regulation and taxation. Further, Enable’s natural gas processing arrangements expose it to commodity price fluctuations. In 2019, 4%, 26% and 70% of Enable’s processing plant inlet volumes consisted of keep-whole arrangements, percent-of-proceeds or percent-of-liquids and fee-based, respectively. If the price at which Enable sells natural gas or NGLs is less than the cost at which Enable purchases natural gas or NGLs under these arrangements, then Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected;
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• | Credit Risk of Customers: Enable is exposed to credit risks of its customers, and any material nonpayment or nonperformance by its customers, whether through severe financial problems or otherwise, could adversely affect its financial position, results of operations and ability to make cash distributions;
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• | “Negotiated Rate” Contracts: Enable provides certain transportation and storage services under fixed-price “negotiated rate” contracts, which are authorized by the FERC, that are not subject to adjustment, even if its cost to perform these services exceeds the revenues received from these contracts. As of December 31, 2019, approximately 37% of Enable’s aggregate contracted firm transportation capacity on EGT and MRT and 93% of its aggregate contracted firm storage capacity on EGT and MRT, was subscribed under such “negotiated rate” contracts. The majority of Enable’s aggregate contracted firm transportation capacity and all of its aggregate contracted firm storage capacity under negotiated rate contracts on MRT are subject to the FERC’s rate case approval. As a result, Enable’s costs could exceed its revenues received under these contracts, and if Enable’s costs increase and it is not able to recover any shortfall of revenue associated with its negotiated rate contracts, the cash flow realized by its systems could decrease and, therefore, the cash Enable has available for distribution could also decrease;
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• | Unavailability of Interconnected Facilities: If third-party pipelines and other facilities interconnected to Enable’s gathering, processing or transportation facilities (including those providing transportation of natural gas and crude oil, transportation and fractionation of NGLs and electricity for compression, among other things) become partially or fully unavailable for any reason, Enable’s financial position, results of operations and ability to make cash distributions could be adversely affected; and
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• | Land Ownership: Enable does not own all of the land on which its pipelines and facilities are located, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate, which could disrupt its operations or result in increased costs related to the construction and continuing operations elsewhere and adversely affect its financial position, results of operations and ability to make cash distributions.
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Enable conducts a portion of its operations through joint ventures, which subject it to additional risks that could adversely affect the success of these operations and Enable’s financial position, results of operations and ability to make cash distributions.
Enable conducts a portion of its operations through joint ventures with third parties, including Enbridge Inc., DCP Midstream, LP, CVR Energy, Inc., Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. Enable may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture.
Enable’s joint venture arrangements may involve risks not otherwise present when operating assets directly, including, for example:
Enable shares certain approval rights over major decisions and may not be able to control decisions, including control of cash distributions to Enable from the joint venture;
Enable may incur liabilities as a result of an action taken by its joint venture partners, including leaving Enable liable for the other joint venture partners’ shares of joint venture liabilities if those partners do not pay their share of the joint venture’s obligations;
Enable may be required to devote significant management time to the requirements of and matters relating to the joint ventures;
Enable’s insurance policies may not fully cover loss or damage incurred by both Enable and its joint venture partners in certain circumstances;
Enable’s joint venture partners may take actions contrary to its instructions or requests or contrary to its policies or objectives; and
disputes between Enable and its joint venture partners may result in delays, litigation or operational impasses.
The risks described above or the failure to continue Enable’s joint ventures or to resolve disagreements with its joint venture partners could adversely affect its ability to transact the business that is the subject of such joint venture, which would in turn adversely affect Enable’s financial position, results of operations and ability to make cash distributions. The agreements under which Enable formed certain joint ventures may subject it to various risks, limit the actions it may take with respect to the assets subject to the joint venture and require Enable to grant rights to its joint venture partners that could limit its ability to benefit fully from future positive developments. Some joint ventures require Enable to make significant capital expenditures. If Enable does not timely meet its financial commitments or otherwise does not comply with its joint venture agreements, its rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of Enable’s joint venture partners may have substantially greater financial resources than Enable has and Enable may not be able to secure the funding necessary to participate in operations its joint venture partners propose, thereby reducing its ability to benefit from the joint venture.
Under certain circumstances, Enbridge Inc. could have the right to purchase Enable’s ownership interest in SESH at fair market value.
Enable owns a 50% ownership interest in SESH. The remaining 50% ownership interest is held by Enbridge Inc. CenterPoint Energy owns 53.7% of Enable’s common units, 100% of the Enable Series A Preferred Units and a 40% economic interest in Enable GP. Pursuant to the terms of the limited liability company agreement of SESH, as amended, if, at any time, CenterPoint
Energy has a right to receive less than 50% of Enable’s distributions through its interests in Enable and Enable GP, or do not have the ability to exercise certain control rights, Enbridge Inc. could have the right to purchase Enable’s interest in SESH at fair market value, subject to certain exceptions.
Enable’s ability to grow is dependent in part on its ability to access external financing sources on acceptable terms.
Enable expects that it will distribute all of its “available cash” to its unitholders. As a result, Enable is expected to rely significantly upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. To the extent Enable is unable to finance growth externally or through internally generated cash flows, Enable’s cash distribution policy may significantly impair its ability to grow. In addition, because Enable is expected to distribute all of its available cash, its growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.
To the extent Enable issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that Enable will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that it has to distribute on each unit. There are no limitations in Enable’s partnership agreement on its ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by Enable to finance its growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that Enable has to distribute to its unitholders.
Enable depends, in part, on access to the capital markets and other external financing sources to fund its expansion capital expenditures, although it has also increasingly relied on cash flow generated from operations. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of its common units to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.
Enable’s debt levels may limit its flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2019, Enable had approximately $4.0 billion of long-term debt outstanding, excluding the premiums, discounts and unamortized debt expense on their senior notes, $155 million outstanding under its commercial paper program and $250 million outstanding under the Enable Oklahoma Intrastate Transmission, LLC 6.25% senior notes due 2020, excluding unamortized premium. Enable has a $1.75 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, with no borrowings outstanding, of which approximately $1.59 billion in borrowing capacity was available as of December 31, 2019. As of January 31, 2020, Enable had $119 million outstanding under its commercial paper program and $1.63 billion of available borrowing capacity under its revolving credit facility. Enable has the ability to incur additional debt, subject to limitations in its credit facilities. The levels of Enable’s debt could have important consequences, including the following:
the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;
a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;
Enable’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and
Enable’s debt level may limit its flexibility in responding to changing business and economic conditions.
Enable’s ability to service its debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions, commodity prices and financial, business, regulatory and other factors, some of which are beyond Enable’s control. If operating results are not sufficient to service current or future indebtedness, Enable may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all.
Further, any reductions in Enable’s credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships. Enable cannot assure that its credit ratings will remain in effect for any given period of time or that a
rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant. If any of Enable’s credit ratings are below investment grade, it may have higher future borrowing costs, and Enable or its subsidiaries may be required to post cash collateral or letters of credit under certain contractual agreements. If cash collateral requirements were to occur at a time when Enable was experiencing significant working capital requirements or otherwise lacked liquidity, its financial position, results of operations and ability to make cash distributions could be adversely affected.
Enable’s credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond Enable’s control, which could adversely affect its financial condition, results of operations and ability to make distributions.
Enable’s credit facilities contain customary covenants that, among other things, limit its ability to:
permit its subsidiaries to incur or guarantee additional debt;
incur or permit to exist certain liens on assets;
dispose of assets;
merge or consolidate with another company or engage in a change of control;
enter into transactions with affiliates on non-arm’s length terms; and
change the nature of its business.
Enable’s credit facilities also require it to maintain certain financial ratios. Enable’s ability to meet those financial ratios can be affected by events beyond its control, and we cannot assure you that it will meet those ratios. In addition, Enable’s credit facilities contain events of default customary for agreements of this nature.
Enable’s ability to comply with the covenants and restrictions contained in its credit facilities may be affected by events beyond its control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Enable’s ability to comply with these covenants may be impaired. If Enable violates any of the restrictions, covenants, ratios or tests in its credit facilities, a significant portion of its indebtedness may become immediately due and payable. In addition, Enable’s lenders’ commitments to make further loans to it under the revolving credit facility may be suspended or terminated. Enable might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Enable’s businesses are exposed to various regulatory risks.
Enable’s operations are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect Enable’s financial position, results of operations and ability to make cash distributions. This regulation includes, but is not limited to, the following:
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• | Rate Regulation: The rates charged by several of Enable’s pipeline systems, including for interstate gas transportation service provided by its intrastate pipelines, are regulated by the FERC. Enable’s pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural gas transportation services and crude oil gathering services. The FERC and state regulatory agencies also regulate other terms and conditions of the services Enable may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower its tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service Enable might propose or offer, the profitability of Enable’s pipeline businesses could suffer.
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• | FERC Revised Policy Statement and NOPR: In a series of related issuances on March 15, 2018, the FERC issued a Revised Policy Statement stating that it will no longer permit pipelines organized as MLPs to recover an income tax allowance in their cost-of-service rates. On July 18, 2018, FERC issued a Final Rule adopting procedures that are generally the same as proposed in a March 15, 2018 NOPR implementing the Revised Policy Statement and the corporate income tax rate reduction with certain clarifications and modifications. For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. If FERC requires Enable to establish new tariff rates for either its natural gas or crude oil pipelines that reflect a lower federal corporate income tax rate, it is possible the rates would be reduced, which could adversely affect Enable’s financial position, results of operations and ability to make cash distributions to its unitholders. With regard to FERC-jurisdictional
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rates on Enable’s crude oil pipelines, the FERC plans to address the Revised Policy Statement and corporate tax rate reduction in its next five-year review of the oil pipeline rate index, which will occur in 2020 and become effective July 1, 2021. The potential rate impacts from the revision are currently uncertain.
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• | Permits, Licenses and Approvals: Enable may be unable to obtain or renew federal or state permits, licenses or approvals necessary for its operations, which could inhibit its ability to do business. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of Enable’s compliance status may result in the imposition of fines, penalties and injunctive relief. Further, to obtain new permits or renew permits and other approvals in the future, Enable may be required to prepare and present data to governmental authorities pertaining to potential adverse impact of a proposed project. Compliance with these regulatory requirements may be expensive and may significantly lengthen the time required to prepare applications and to receive authorizations and consequently could disrupt Enable’s project construction schedules;
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• | Hydraulic Fracturing Regulation: Increased regulation of hydraulic fracturing and waste water injection wells could result in reductions or delays in natural gas or crude oil production by Enable’s customers, which could adversely affect its financial position, results of operations and ability to make cash distributions; and
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• | Jurisdictional Characterization of Assets: Enable’s natural gas gathering and intrastate transportation systems are generally exempt from the jurisdiction of the FERC under the NGA, and its crude oil gathering system in the Anadarko Basin is generally exempt from the jurisdiction of the FERC under ICA. FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. Natural gas gathering and intrastate crude oil gathering may receive greater regulatory scrutiny at the state level; therefore, Enable’s operations could be adversely affected should they become subject to the application of state regulation of rates and services. A change in the jurisdictional characterization of some of Enable’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.
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Other Risk Factors Affecting Our Businesses and/or CenterPoint Energy’s Interests in Enable Midstream Partners, LP
The success of the Merger depends, in part, on CenterPoint Energy’s ability to realize anticipated benefits and conduct an effective integration process.
The success of the Merger will depend, in part, on CenterPoint Energy’s ability to realize the expected benefits in the anticipated timeframe, including operating efficiencies, growth opportunities, cost savings and customer retention, from integrating CenterPoint Energy’s and Vectren’s businesses, while at the same time continuing to provide consistent, high quality services. The integration process could be complex, costly and time consuming, including the diversion of significant management time and resources thereto, and may result in the following challenges, among other things:
unanticipated delays, disruptions, issues or costs in integrating operations, financial and accounting, information technology, communications and other systems;
inconsistencies in procedures, practices, policies, controls, and standards;
differences in compensation arrangements, management perspectives and corporate culture; and
loss of or difficulties retaining talented employees or valuable third-party relationships.
CenterPoint Energy must also successfully adapt its systems of internal controls to continue to accurately provide reliable financial reports, including reporting of its financial condition, results of operations or cash flows, effectively prevent fraud and operate successfully as a public company. If CenterPoint Energy’s efforts to maintain an effective system of internal controls throughout integration are not successful, it is unable to maintain adequate controls over its financial reporting and processes in the future or it is unable to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002, CenterPoint Energy’s operating results could be harmed or it may fail to meet its reporting obligations. Ineffective internal controls also could cause investors to lose confidence in CenterPoint Energy’s reported financial information, which would likely have a negative effect on the trading prices of its securities.
Even with the successful integration of the businesses, CenterPoint Energy may not achieve the expected results or economic benefits, including any expected revenue or synergy opportunities. Failure to fully realize the anticipated benefits could adversely affect CenterPoint Energy’s results of operations, financial condition and cash flows.
Cyber-attacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our or Enable’s reputation, results of operations, financial condition and/or cash flows.
We and Enable are subject to cyber and physical security risks related to adversaries attacking information technology systems, network infrastructure, technology and facilities used to conduct almost all of our and Enable’s business, which includes, among other things, (i) managing operations and other business processes and (ii) protecting sensitive information maintained in the normal course of business. For example, the operation of our electric generation, transmission and distribution systems are dependent on not only physical interconnection of our facilities but also on communications among the various components of our systems and third-party systems. This reliance on information and communication between and among those components has increased since deployment of the intelligent grid, smart devices and operational technologies across our businesses. Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyber-attack or unauthorized access in any one of these systems could potentially impact the other systems.
Similarly, our and Enable’s business operations are interconnected with external networks and facilities. The distribution of natural gas to our customers requires communications with Enable’s pipeline facilities and third-party systems. The gathering, processing and transportation of natural gas from Enable’s gathering, processing and pipeline facilities and crude oil gathering pipeline systems also rely on communications among its facilities and with third-party systems that may be delivering natural gas or crude oil into or receiving natural gas or crude oil and other products from Enable’s facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our or Enable’s ability to conduct operations and control assets.
Cyber-attacks, including phishing attacks and threats from the use of malicious code such as malware, ransomware and viruses, and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, increase costs and subject us or Enable to possible legal claims and liability. Further, third parties, including vendors, suppliers and contractors, who perform certain services for us or administer and maintain our sensitive information, could also be targets of cyber-attacks and unauthorized access. Neither we nor Enable are fully insured against all cyber-security risks, any of which could adversely affect our reputation and could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.
As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our and Enable’s critical energy infrastructure may be targets of state-sponsored attacks, terrorist activities or otherwise that could disrupt our respective business operations. Any such disruptions could result in significant costs to repair damaged facilities, restore service and implement increased security measures, which could have a material adverse effect on either our or Enable’s results of operations, financial condition and/or cash flows.
Failure to maintain the security of personally identifiable information could adversely affect us.
In connection with our businesses, we and our vendors, suppliers and contractors collect and retain personally identifiable information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The regulatory environment surrounding information security and data privacy is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant costs, fines and penalties and liabilities for us. A significant theft, loss or fraudulent use of the personally identifiable information we maintain or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions and other legal requirements could adversely impact our reputation and could result in significant costs, fines and penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.regulations, including regulation of CCR and climate change legislation. We could also experience reduced demand for our services, including certain local initiatives to prohibit new natural gas service and increase electrification initiatives in jurisdictions served by Natural Gas.
Our operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, steam electric generating facilities
and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
restricting the way we manage hazardous and non-hazardous wastes, including wastewater discharges and air emissions;
limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
requiring remedial action and monitoring to mitigate environmental conditions caused by our operations, or attributable to former operations;
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• | limiting airborne emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2) and mercury, and the disposal non-hazardous substances such as CCRs, among other things;
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among others, restricting the use of fossil fuels through future climate legislation or regulation;
imposing requirements on orregulation, restricting the use of natural gas-fired appliances in new homes, limiting airborne emissions from generating facilities, restricting the way we manage wastes, including wastewater discharges and air emissions and requiring remedial action or monitoring to mitigate environmental actions caused by our operations of facilities under the terms of permits issued pursuantor attributable to such environmental laws and regulations; and
impacting the demand for our services by directly or indirectly affecting the use or price of fossil fuels, including, but not limited to, natural gas.
To comply with these requirements, weformer operations. We may need to spend substantial amounts and devote other resources from time to time to:
construct or acquire new facilities and equipment;
acquire permits for facility operations or purchase emissions allowances;
modify or replace existing and proposed equipment; and
decommission or remediate waste management areas, fuel storage facilities and other locations.
to comply with these requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean, restore and monitor sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
In April 2015, the EPA finalized its CCR Rule, which regulates ash as non‑hazardousnon-hazardous material under the RCRA. UnderThe final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s generating plants will continue to be beneficially reused. In July 2018, the EPA released its final CCR Rule Phase I Reconsideration which extended the deadline to October 31, 2020 for ceasing placement of ash in ponds that exceed groundwater protections standards or that fail to meet location restrictions. In August 2019, the EPA proposed additional “Part A” amendments to its CCR Rule with respect to beneficial reuse of ash and other materials. Further “Part B” amendments, which related to alternate liners for CCR surface impoundments and the surface impoundment closure process, were published in March 2020. The Part A amendments were finalized in August 2020, and the Part B amendments were finalized in November 2020 and extended the deadline to cease placement of ash in ponds to April 11, 2021. The EPA published an advanced notice of proposed rulemaking on legacy CCR surface impoundments in October 2020, and in December 2020 provided new data and requested public comment as part of the Agency’s reconsideration of its definition of beneficial reuse. The Part A amendments do not restrict Indiana Electric’s current beneficial reuse of its fly ash. The potential effects of future amendments to the CCR Rule Indiana Electric is requiredare uncertain at this time.
Regulatory agencies have also adopted, and from time to complete integrity assessmentstime consider adopting, new legislation and/or modifying existing laws and groundwater monitoring studies. In January 2018, Indiana Electric completedregulations to reduce GHGs. There continues to be a wide-ranging policy and regulatory debate, both nationally and internationally, regarding the potential impact of GHGs and possible means for their regulation. The EPA has expanded its first annual groundwater monitoring and corrective action report. This report identified localized impacts to groundwater near Indiana Electric’s coal impoundments. Further analysis is ongoing. In October 2018, Indiana Electric completed the CCR Rule’s required evaluation of the placement of Indiana Electric’s coal ash ponds. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond fail the aquifer placement location restriction. As a result of this failure, Indiana Electric must cease disposal of new ash in the ponds and commence closure of the ponds by August 31, 2020. Indiana Electric plans to seek extensions available under the CCR Rule that would allow it to continue to use the ponds through December 31, 2023. The inability to obtain these extensions may result in increased and potentially significant operational costs in connection with the accelerated implementation of an alternative ash disposal system or adversely impact Indiana Electric’s future operations. Failure to comply with theseexisting GHG emissions reporting requirements, which could also result in an enforcement proceeding including impositionlead to further regulation of fines and penalties. Further, a release of coal ash that presents an imminent and substantial endangerment to health ofGHGs by the environment could result in remediation costs, civil and/or criminal penalties, claims, litigation, increased regulation and compliance costs and reputational damage, all of which could adversely affect the financial condition of Indiana Electric.
EPA. The recent trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment, which is expected to continue under the Biden administration. For example, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change, as well as an executive order requiring agencies to review environmental actions taken by the Trump administration. The Biden administration also issued a memorandum to departments and thusagencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. President Biden also recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions and
100% carbon-free electricity by 2035, which formed the basis of the United States’ commitments announced in Glasgow. Reentry into the Paris Agreement, revised climate commitments coming out of the 2021 United Nations Climate Change Conference held in Glasgow, Scotland and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. Potential future restrictions include, among other things, the United States enacting additional GHG regulations and mandated financial, emissions and other disclosures. As a distributor and transporter of natural gas, Natural Gas’ revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or that would have the effect of reducing the consumption of natural gas. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be greater than the amounts we currently anticipate.
Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.
We currently have insurance in place, such as general liability and property insurance, to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to fully cover or restore the loss or damage without negative impact on our results of operations, financial condition and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses.
In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and believes insurance capacity to be limited. Historically, Houston Electric has been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise. In the future, any such recovery may not be granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.
Our operations and Enable’s operations are subject to all of the risks and hazards inherent in their respective businesses of gathering, processing, transportation and storage of natural gas and crude oil and the generation, transmission and distribution of electricity, including:
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, earthquakes and other natural disasters, acts of terrorism and actions by third parties;
inadvertent damage from construction, vehicles and farm and utility equipment;
leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas, NGLs and crude oil as a result of the malfunction of equipment or facilities;
ruptures, fires and explosions; and
other safety hazards affecting our operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our or Enable’s operations. A natural disaster or other hazard affecting the areas in which we or Enable operate could have a material adverse effect on our or Enable’s operations.
Enable is not fully insured against all risks inherent in its business. Enable currently has general liability and property insurance in place to cover certain of its facilities in amounts that Enable considers appropriate. Such policies are subject to certain limits and deductibles. Enable does not have business interruption insurance coverage for all of its operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of Enable’s facilities may not be sufficient to restore the loss or damage without negative impact on its results of operations and its ability to make cash distributions.
Our results of operations, financial condition and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.
Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including:
operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;
the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;
operating limitations that may be imposed by environmental or other regulatory requirements;
labor disputes;
information technology or financial and billing system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;
information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and
catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, ice storms, terrorism, wildfires, pandemic health events or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.
Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows.
Our and Enable’s success depends upon our and Enable’s ability to attract, effectively transition, motivate and retain key employees and identify and develop talent to succeed senior management.
We and Enable depend on senior executive officers and other key personnel. Our and Enable’s success depends on our and Enable’s ability to attract, effectively transition and retain key personnel. On February 19, 2020, our president and chief executive officer resigned from CenterPoint Energy. As a result of this departure, our board of directors is currently conducting a search to fill the role of chief executive officer. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our and Enable’s operations. In addition, because of the reliance on our and Enable’s management team, our and Enable’s future success depends in part on our and Enable’s ability to identify and develop talent to succeed senior management. The retention of key personnel and appropriate senior management succession planning will continue to be critically important to the successful implementation of our and Enable’s strategies.
Failure to attract and retain an appropriately qualified workforce could adversely impact our and Enable’s results of operations.
Our and Enable’s businesses are dependent on recruiting, retaining and motivating employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our and Enable’s costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our and Enable’s businesses. If we and Enable are unable to successfully attract and retain an appropriately qualified workforce, our and Enable’s results of operations could be negatively affected.
Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our or Enable’s services, including certain local initiatives to prohibit new NGD service and increase electrification initiatives.
Regulatory agencies have adopted, and from time to time consider adopting, new legislation and/or modifying existing laws and regulations, to reduce GHGs, and there continues to be a wide-ranging policy and regulatory debate, both nationally and
internationally, regarding the potential impact of GHGs and possible means for their regulation. Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues.
In August 2018, the EPA proposed a CPP replacement rule, the ACE Rule, which was finalized in July 2019 and requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units. States have three years to develop state plans to implement the ACE Rule, and we do not expect a state ACE plan to be finalized and approved by the EPA until 2024. We are currently unable to predict the effect of a state plan to implement the ACE Rule but do not anticipate that such a plan would have a material effect on our results of operations, financial condition or cash flows. Additionally, the ACE Rule is currently subject to legal challenges. At this time, we are unable to determine what effect, if any, the legal challenges will have on the ACE Rule.
Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements. These permitting and reporting requirements could lead to further regulation of GHGs by the EPA. As a distributor and transporter of natural gas, or a consumer of natural gas in its pipeline and gathering businesses, NGD’s or Enable’s revenues, operating costs and capital requirements, as applicable, could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Additionally, Houston Electric’s and Indiana Electric’s transmission and distribution businesses’ revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. For further discussion, see “— Risk Factors Affecting Natural“Business—Environmental Matters” in Item 1 and “ —Natural Gas Distribution and Competitive Energy Services Businesses —NGD and CES must compete with alternate energy sources, which could result in less natural gas marketed and have an adverse impact on our results of operations, financial condition and cash flows.with...”
Moreover, evolvingEvolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels may have substantial impacts on CenterPoint Energy’s electric generation and NGDnatural gas businesses. For example, because Indiana Electric’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Further, some investors may choose to not invest in CenterPoint Energy due to CenterPoint Energy’s use of fossil fuels. Also, certain cities in CenterPoint Energy’s NGDNatural Gas operational footprint have adopted initiatives to prohibit the construction of new NGDnatural gas facilities that would provide service and focus on electrification. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil gas. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. Certain state and local governments in states such as New York and California have also passed, or are considering, legislation banning the use of natural gas-fired appliances in new homes, which could affect consumer use of natural gas. Should such bans be enacted within Natural Gas’ operational footprint, they could adversely affect consumer demand for natural gas. Any such initiatives and legislation could adversely affect CenterPoint Energy’s results of operations.
CenterPoint Energy is subject to operational and financial risks and liabilities associated with the implementation of and efforts to achieve its carbon emission reduction goals.
In September 2021, CenterPoint Energy announced its new net zero emission goals for Scope 1 and 2 emissions by 2035 and a 20-30% reduction in Scope 3 emissions by 2035 as compared to 2021 levels. CenterPoint Energy’s analysis and plan for execution requires it to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees. Should one or more of CenterPoint Energy’s underlying assumptions prove incorrect, its actual results and ability to achieve net zero emissions by 2035 could differ materially from its expectations. Certain of the assumptions that could impact CenterPoint Energy’s ability to meet its net zero emissions goals include, but are not limited to: emission levels, service territory size and capacity needs remaining in line with expectations; regulatory approval of Indiana Electric’s generation transition plan; impacts of future environmental regulations or legislation; impact of future carbon pricing regulations or legislation, including a future carbon tax; price, availability and regulation of carbon offsets; price of fuel, such as natural gas; cost of energy generation technologies, such as wind and solar, natural gas and storage solutions; adoption of alternative energy by the public, including adoption of electric vehicles; rate of technology innovation with regards to alternative energy resources; CenterPoint Energy’s ability to implement its modernization plans for its pipelines and facilities; the ability to complete and implement generation alternatives to Indiana Electric’s coal generation and retirement dates of Indiana Electric’s coal facilities by 2035; the ability to construct and/or permit new natural gas pipelines; the ability to procure resources needed to build at a reasonable cost, the lack of or scarcity of resources and labor, any project cancellations, construction delays or overruns and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; changes in applicable standards or methodologies; and enhancement of energy efficiencies. Our businesses may face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets, and objectives that we announce, and our methodologies and timelines for pursuing them. If our sustainability practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation.
Developing and implementing plans for compliance with voluntary climate commitments can lead to additional capital, personnel and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. To the extent that we believe any of these costs are recoverable in rates, cost recovery could be resisted
by our regulators and our regulators might attempt to deny or defer timely recovery of these costs. Moreover, we cannot predict the ultimate impact of achieving our emissions reduction goals, or the various implementation aspects, on our system reliability or our financial condition and results of operations.
Continued disruptions to the global supply chain may lead to higher prices for goods and services and impact our operations, which could have a material adverse impact on our ability to execute our capital plan and on our financial condition, results of operations and cash flows.
The global supply chain has experienced and is expected to continue to experience disruptions due to a multitude of factors, such as the COVID-19 pandemic, labor shortages, resource availability, long lead time, inflation and weather, and these disruptions have adversely impacted the utility industry. We have experienced disruptions to our supply chain, as well as increased prices, and we may continue to experience this in the future. For example, we, along with the developer of the project, recently announced plans to downsize the previously announced solar array to be built in Posey County, Indiana from 300 MW to 200 MW due to supply chain issues experienced in the energy industry, the rising cost of commodities and community feedback. Additionally, we, as well as other companies in our industry, have experienced difficulties in procuring certain materials necessary for the transmission and distribution of power, such as transformers, wires, cables and meters. We may continue to experience difficulties in procuring these resources and others necessary to operate our businesses in the future, and if we were to experience other significant supply chain disruptions in the future, we may not be able to procure the resources, including labor, needed to fully execute on our ten-year capital plan or achieve our net zero emission goals. Even if we are able to procure the necessary resources, we might not be able to do so at a reasonable cost or in a timely manner which could result in project cancellations or scope changes, delays, cost overruns and under-recovery of costs. If we are unable to fully execute on capital plans as a result of supply chain disruptions, our financial condition, results of operations and cash flows may be materially and adversely affected.
The February 2021 Winter Storm Event caused severe disruptions in certain of our jurisdictions and could have a material adverse impact to our financial condition, results of operations, cash flows and liquidity.
In February 2021, certain of our jurisdictions experienced an extreme and unprecedented winter weather event with prolonged freezing temperatures that resulted in an electricity generation shortage in our Houston Electric service area, which impacted our businesses. The electricity generation shortages necessitated ERCOT to direct TDUs, including Houston Electric, to implement controlled outages in their respective service areas. In compliance with ERCOT’s directives and emergency procedures, Houston Electric implemented controlled electricity outages across its service territory, resulting in a substantial number of its customers (on certain days over a million residents) being without power, many for extended periods of time. ERCOT has stated that the electric outages were necessary to avoid prolonged large-scale, state-wide blackouts and long-term damage to the electric system in Texas. As a result, Houston Electric’s sales of transmission and distribution services were diminished or interrupted for several days. Additionally, the electricity generation shortage resulted in wholesale electricity prices increasing to their maximum allowed limit.
During and in the aftermath of the February 2021 Winter Storm Event, the Texas legislature revised applicable statutes and granted the PUCT and ERCOT additional regulatory authority, both oversight and enforcement, that focuses on ensuring that ERCOT market participants, including power generation facilities and TDUs (like Houston Electric), have sufficient winterization standards and protection. Houston Electric is in compliance with the requirements applicable to it. If any additional protections are required in the future, complying with these new protections may increase the cost of electricity and reduce consumption of electricity by ultimate consumers in Houston Electric’s service territory, which could adversely affect Houston Electric’s results of operations. Any potential decreases in customer usage due to higher electricity prices charged by REPs may not result in increased base rates charged by Houston Electric for its services until its next general base rate proceeding. For further information on Houston Electric’s regulatory proceedings, see “— Rate regulation of Houston Electric’s...”
Furthermore, the February 2021 Winter Storm Event also impacted the wholesale prices CenterPoint Energy and CERC paid for natural gas and their ability to service customers in their Natural Gas service territories, including due to the reduction in available natural gas capacity, impacts to CenterPoint Energy’s and CERC’s natural gas supply portfolio activities, and their ability to transport natural gas, among other things. In particular, the February 2021 Winter Storm Event also caused severe disruptions in the markets from which CenterPoint Energy and CERC sourced a significant portion of their natural gas for their utility operations, resulting in extraordinary increases in the price of natural gas to CenterPoint Energy and CERC. From February 12, 2021 to February 22, 2021, CenterPoint Energy spent approximately an incremental $2.2 billion more on natural gas supplies compared to plan. These amounts are based on final settlements of supplier and pipeline invoices from February 2021, including amounts negotiated to resolve disputes with various suppliers as of January 2022.
In addition to the risks discussed in this risk factor, for further information on risks related to:
•the arranging of future financings on acceptable terms, see “— If we are unable to...”;
•the ability to receive payment from a REP, see “— Houston Electric’s receivables are primarily...”
•the ability to seek recovery of the additional costs of natural gas, see “— Rate regulation of Natural Gas...”;
•access to natural gas supplies, see “— Access to natural gas supplies...”;
•various regulatory, investigations, litigation or other proceedings, see “— In connection with the February...” and Note 16 to the consolidated condensed financial statements;
•the fluctuations in notional natural gas prices, see “— Natural Gas is subject to...”; and
•the impact of a decline in CERC’s credit rating, see “— A decline in CERC’s credit ...”
Our financial condition, results of operations and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.
Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks inherent in the generation, transmission and distribution of electricity and in the delivery of natural gas that could result in substantial losses or other damages. These risks include, but are not limited to, the following:
•operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;
•the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;
•operating limitations that may be imposed by environmental or other regulatory requirements;
•labor disputes;
•information technology or financial and billing system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;
•failure to obtain in a timely manner and at reasonable prices the necessary fuel, such as coal and natural gas, building materials or other items needed to operate our facilities;
•information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and
•catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, ice storms, flooding, terrorism, wildfires, pandemic health events or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.
Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our financial condition, results of operations and cash flows.
Our revenues and results of operations are seasonal.
A significant portion of Houston Electric’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Similarly, Indiana Electric’s revenues are derived from rates it charges its customers to provide electricity. Natural Gas’ revenues are primarily derived from natural gas sales. Consequently, Houston Electric’s, Indiana Electric’s and Natural Gas’ revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity and natural gas usage, as applicable. Houston Electric’s revenues are generally higher during the warmer months. As in certain past years, unusually mild weather in the warmer months could diminish Houston Electric’s results of operations and harm its financial condition. Conversely, as in certain past years, extreme warm weather conditions could increase Houston Electric’s results of operations in a manner that would not likely be annually recurring. A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, as in certain past years, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while more extreme seasonal weather conditions could increase Indiana Electric’s results of operations in a manner that would not likely be annually recurring. Natural Gas’ revenues are customarily higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish Natural Gas’ results of operations and harm its financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase its results of operations in a manner that would not likely be annually recurring. For information related to our weather hedges, see Note 9(a) to the consolidated financial statements. For additional risks related to the February 2021 Winter Storm Event, see “—The February 2021 Winter Storm...” below and Note 7 to the consolidated condensed financial statements for further information.
Climate changeschange could adversely impact financial results from our and Enable’s businesses and result in more frequent and more severe weather events that could adversely affect theour results of operations of our businesses.operations.
A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories.territories and our business. If climate changes occur that result in warmer temperatures than normal in our service territories, financial results from our and Enable’s businesses could be adversely impacted. For example, NGD could be adversely affected through lowerwhere natural gas salesis used to heat homes and Enable’sbusinesses, warmer weather might result in less natural gas gathering, processing and transportation and crude oil gathering businesses could experience lower revenues.being used, adversely affecting us. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and severe winter weather conditions, including ice storms, all of which may impact our operations and ability to serve our customers. To the extent the frequency and severity of extreme weather events increases, our costs of providing service may increase, including the costs and availability of procuring insurance related to such impacts, and those costs may not be recoverable. Further, events of extreme weather could make it unsafe or ice storms.hinder the effectiveness of our employees to fix, maintain and restore power to affected areas and could harm our reputation. Since manycertain of our facilities are located along or near the Gulf Coast,Texas gulf coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers. Our electric and Natural Gas operations in our service territories were both also impacted by the February 2021 Winter Storm Event. In the long term, climate change could also cause shifts in population, including customers moving away from our service territories. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can beare impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs resultresults in higher rates and reduced demand for our services, our future financial results may be adversely impacted. Any such decreased energy use may also require us to retire current infrastructure that is no longer needed. Further,Similarly, public and private efforts to address climate change, such as by legislation, regulation, actions by private interest groups, and litigation, could impact our ability to continue operating our businesses as we do today, significant aspects of which rely on fossil fuels. These initiatives could have a significant impact on us and our operations as well as on our third party suppliers, vendors and partners, which could impact us by among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to us. In September 2021, CenterPoint Energy announced its new net zero emission goals for Scope 1 and 2 emissions by 2035 and a 20-30% reduction in Scope 3 emissions by 2035 as compared to 2021 levels. Finally, we may be subject to climate change lawsuits,litigation, which could result in substantial fines, penalties or damages.
NGDdamages and Enable may incur significant costsrestrictions on our operations. The oil and liabilitiesgas industry has already faced such litigation, challenging its marketing and use of fossil fuels and attributing climate change to emissions resulting from pipeline integritythe use of fossil fuels, and other similar programsindustries, including ours, could face such litigation in the future. For more information, see Note 7 to the consolidated financial statements, “— The February 2021 Winter Storm...” and related repairs.
Certain of NGD’s and Enable’s pipeline operations are“— CenterPoint Energy is subject to pipeline safety lawsoperational and regulations. The DOT’s PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs, including more frequent inspections and other measures, for transportation pipelines located in “high consequence areas,financial risks...” which are those areas where a
leak or rupture could do the most harm. The regulations require pipeline operators, including NGD and Enable, to, among other things:
perform ongoing assessments of pipeline integrity;
develop a baseline plan to prioritize the assessment of a covered pipeline segment;
identify and characterize applicable threats that could impact a high consequence area;
improve data collection, integration, and analysis;
develop processes for performance management, record keeping, management of change and communication;
repair and remediate pipelines as necessary; and
implement preventive and mitigating action.
Failure to comply with PHMSA or analogous state pipeline safety regulations could result in a number of consequences that may have an adverse effect on NGD’s and Enable’s operations. Both NGD and Enable incur significant costs associated with their compliance with existing PHMSA and comparable state regulations, which may not be recoverable in rates.
Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on NGD and Enable. Changes to pipeline safety regulations occur frequently. For example, PHMSA published a final rule in October 2019 that extends and expands the reach of certain PHMSA integrity management requirements (e.g., period assessments, leak detection and repairs) regardless of proximity to a high consequence area. The adoption of new regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us and Enable to incur increased and potentially significant operational costs.
Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results.
We have risks associated with aging infrastructure assets, including the failure of equipment or processes and potential breakdowns due to such aging. The age of certain of our assets may result in a need for replacement or higher level of maintenance costs because of our risk based federal and state compliant integrity management programs. Failure to achieve timely and full recovery of these expenses could adversely impact revenues and could result in increased capital expenditures or expenses. In addition, the nature of information available on aging infrastructure assets may make inspections, maintenance, upgrading and replacement of the assets particularly challenging. Also, our ability to successfully maintain or replace our aging infrastructure may be delayed or be at a greater cost than anticipated due to supply chain disruptions. Further, with respect to NGD’sNatural Gas’ operations, if certain pipeline replacements (for example, cast-iron or bare steel pipe) are not completed timely or successfully, government agencies and private parties might allege the uncompleted replacements caused events such as fires, explosions or leaks. Although we maintain insurance for certain of our facilities, our insurance coverage may not be sufficient in the event that a catastrophic loss is alleged to have been caused by a failure to timely complete equipment replacements. Insufficient insurance coverage and increased insurance costs could adversely impact our financial condition, results of operations financial condition and cash flows. Finally, aging infrastructure may complicate our utility operations ability to address climate change concerns and efforts to enhance resiliency and reliability. See “— Continued disruptions to the supply...”
The operation of our facilities depends on good labor relations with our employees.
Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. We have several separate bargaining units, each with a unique collective bargaining agreement described below:
The collective bargaining agreement with IBEW Local 66 related to employees of Houston Electric is scheduled to expire in May 2020, for which negotiations are anticipated to begin in March 2020;
The collective bargaining agreements with USW Locals 13-227 and 13-1 related to NGD’s employees in Texas are scheduled to expire in June 2022 and July 2022, respectively;
The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 and Mankato related to NGD employees in Minnesota are scheduled to expire in April 2020, December 2020, May 2021 and March 2021, respectively, and negotiations with Gas Workers Union Local 340 are currently in progress and expected to be completed before the April 2020 expiration;
The collective bargaining agreements with IBEW Local 1393, USW Locals 12213 and 7441 related to employees of NGD in Indiana are scheduled to expire in December 2020;
The collective bargaining agreements with the Teamsters, Chauffeurs, Warehousemen and Helpers Union Local 135 and Utility Workers Union Local 175 related to employees of Indiana Electric were recently renegotiated and are scheduled to expire in September 2021 and October 2021, respectively; and
The collective bargaining agreement with IBEW Local 702 related to employees of Indiana Electric is scheduled to expire in June 2022.
Additionally, Infrastructure Services negotiates various trade agreements through contractor associations. The two primary associations are the DCA and the PLCA. These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements have varying expiration dates in 2020, 2021 and 2022. In addition, these subsidiaries have various project agreements and small local agreements. These agreements expire upon completion of a specific project or on various dates throughout the year.
Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have a material adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.
Our businesses will continue to have to adapt to technological change and may not be successful or may have to incur significant expenditures to adapt to technological change.
We operate in businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly and increasing in complexity. New technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant investments and expenditures so that we can continue to provide cost-effective and reliable methods for energy production and delivery. Among such technological advances are distributed generation resources (e.g., private solar,
microturbines, fuel cells), energy storage devices and more energy-efficient buildings and products designed to reduce energy consumption and waste. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services, including Indiana Electric’s generating facilities becoming less competitive and economical. Further, certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain dates. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric and natural gas devices or other improvements in or applications of technology could lead to declines in per capita energy consumption.
Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a cost-effective manner, to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards, and to recover all, or a significant portion of, any unrecovered investment in obsolete assets. If we fail to adapt successfully to any technological change or obsolescence, fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our businesses, operatingfinancial condition, results financial conditionof operations and cash flows could be materially and adversely affected.
Our or Enable’s potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected.expected, adversely affecting our financial condition, results of operations and cash flows.
Our financial condition, results of operations and cash flows depend, in part, on our management’s ability to implement our business strategies successfully and realize the anticipated benefits therefrom. From time to time we and Enable have made, and may continue to make, acquisitions or divestitures of businesses and assets, such as our recently completed sale of our Natural Gas businesses in Arkansas and Oklahoma and the recently completed Enable Merger and subsequent sale of Energy Transfer Common Units and Energy Transfer Series G Preferred Units, form joint ventures or undertake restructurings. However, suitable acquisition candidates or potential buyers may not continue to be available on terms and conditions we or Enable, as the case may be, find acceptable, or the expected benefits of completed acquisitions or dispositions may not be realized fully or at all, or may not be realized in the anticipated timeframe. If we or Enable are unable to make acquisitions, or if those acquisitions do not perform as anticipated, our and Enable’s future growth may be adversely affected.
On February 3, 2020, CenterPoint Energy, through VUSI, entered into the Securities Purchase Agreement to sell the businesses within its Infrastructure Services reportable segment. The transaction is expected to close in the second quarter of 2020. For
further information, see Notes 6 and 23 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated.
Additionally, on February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equity Purchase Agreement to sell CES, which represents substantially all of the businesses within the Energy Services reportable segment. The transaction is expected to close in the second quarter of 2020. For further information, see Notes 6 and 23 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated. As discussed in Note 16(d) to the consolidated financial statements, the existing CERC Corp. guarantees supporting CES’s obligations under natural gas supply, transportation and storage contracts will not terminate upon closing of the transaction. While the buyer has an obligation to use its reasonable best efforts to cause CERC Corp. to be released from the guarantees as of and following closing, if the buyer is unable to do so, CERC Corp. would continue to have significant exposure under the guarantees. Following closing, if CES were to default on the payment obligations still guaranteed by CERC Corp., CERC Corp. could be obligated for such amounts.
Further, any completed or future acquisitions involve substantial risks, including the following:
•acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
•we or Enable may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;
•we or Enable may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and
•acquisitions, or the pursuit of acquisitions, could disrupt our or Enable’s ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures.
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results.
The Registrants are subject to numerous legal proceedings, the most significant of which are summarized in Note 16 to the Registrants’ respective consolidated financial statements. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of all matters with assurance. Final resolution of these matters may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have a material adverse effect on the Registrants’ financial results.
The Registrants could incur liabilities associated with businesses and assets that they have transferred to others.
Under some circumstances, the Registrants could incur liabilities associated with assets and businesses no longer owned by them. These assets and businesses were previously owned by Reliant Energy, a predecessor of Houston Electric, directly or through subsidiaries and include:
merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001 and now owned by affiliates of NRG; and
Texas electric generating facilities transferred to a subsidiary of Texas Genco in 2002, later sold to a third party and now owned by an affiliate of NRG.
In connection with the organization and capitalization of RRI (now GenOn) and Texas Genco (now an affiliate of NRG), those companies and/or their subsidiaries assumed liabilities associated with various assets and businesses transferred to them and agreed to certain indemnity agreements of the Registrants. Such indemnities have applied in various asbestos and other environmental matters that arise from time to time and cases such as the litigation arising out of sales of natural gas in California and other markets, including in the gas market manipulation cases described in Note 16(e) to the Registrants’ respective consolidated financial statements. However, because of the settlement and discharge of certain of GenOn’s indemnity obligations in 2019 in
its Chapter 11 bankruptcy proceedings, the Registrants will no longer have the benefit of any settled or discharged indemnities and could incur liabilities in matters that previously would have been indemnified.
In connection with our sale of Texas Genco, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and CenterPoint Energy would assume and agree to indemnify Texas Genco against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies held by CenterPoint Energy, and in certain of the asbestos lawsuits CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense by an NRG affiliate.
We are exposed to risks related to reduction in energy consumption due to factors such as unfavorable economic conditions in our service territories and changes in customers’ perceptions from recent incidents of other utilities involving natural gas pipelines.
Our businesses are affected by reduction in energy consumption due to factors including economic, climate and market conditions in our service territories, energy efficiency initiatives, use of alternative technologies and changes in our customers’ perceptions regarding natural gas usage as a result of recent incidents of other utilities involving natural gas pipelines, which could impact our ability to grow our customer base and our rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas and the need for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as mandated energy efficiency measures, demand-side management goals, distributed generation resources and economic and demographic conditions, such asincluding population changes, job and income growth, housing starts, new business formation and the overall level of economic activity.
Declines in demand for electricity and natural gas in NGD’sour service territories due to recent pipeline incidents of other utilities, increased electricity and for electricitynatural gas prices as a result ofexperienced during the February 2021 Winter Storm Event and economic downturns, in Houston Electric’s and Indiana Electric’s regulated electric service territories willamong other factors, could reduce overall salesusage and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity.electricity and natural gas. Although Houston Electric’s and Indiana Electric’s transmission and distribution businesses are subject to regulated allowable rates of return and recovery of certain costs under periodic adjustment clauses, overall declines in electricity solddelivered and used as a result of economic downturn or recession
could reduce revenues and cash flows, thereby diminishing results of operations. Additionally, prolongedA reduction in the rate of economic, downturns that negatively impact results of operations and cash flowsemployment and/or population growth could result in future material impairment charges to write-down the carrying valuelower growth and reduced demand for and usage of certain assets, including goodwill, to their respective fair values.
For example, Houston Electric’s business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although Houston, Texas has a diverse economy, employment in the energy industry remains important with overall Houston employment growing at a moderate rate in 2019 among various sectors. Further, the operations of Vectren’s utility businesses are concentrated in centralelectricity and southern Indiana and west-central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest. These industries include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings, plastic products; gypsum products; electrical equipment, metal specialties, glass and steel finishing; pharmaceutical and nutritional products; gasoline and oil products; ethanol; and coal mining.
In the event economic conditions further decline, the respective rates of growth in Houston, Indiana and the other areas in which we operate may also deteriorate. Changing market conditions, including changing regulation, changes in market prices of oil or other commodities, or changes in government regulation and assistance, may cause certain industrial customers to reduce or cease production and thereby decrease consumption of natural gas and/or electricity. Increases in customer defaults or delays in payment due to liquidity constraints could negatively impact our cash flows and financial condition.such service territories. Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or natural gas or number of customers and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on theirour financial position,condition, results of operations and cash flows.
General Risk Factors Affecting Our Businesses
Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our reputation, financial condition, results of operations and cash flows.
We are subject to cyber and physical security risks related to adversaries attacking information technology systems, network infrastructure, technology and facilities used to conduct almost all of our businesses, which includes, among other things, (i) managing operations and other business processes and (ii) protecting sensitive information maintained in the normal course of business. For example, the operation of our electric generation, transmission and distribution systems are dependent on not only physical interconnection of our facilities but also on communications among the various components of our systems and third-party systems. This reliance on information and communication between and among those components has increased since deployment of the intelligent grid, smart devices and operational technologies across our businesses. Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyberattack or unauthorized access in any one of these systems could potentially impact the other systems. Similarly, our business operations are interconnected with external networks and facilities. For example, the operation of an efficient deregulated wholesale and retail electric market in Texas mandates communication with ERCOT, and competitive retailers; and our Indiana Electric organization has a similar relationship with MISO. Also, the distribution of natural gas to our customers requires communications with third-party systems. Disruption of those communications, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by manmade events, such as cyberattacks or acts of terrorism, may disrupt our ability to conduct operations and control assets.
Cyberattacks, including phishing attacks and threats from the use of malicious code such as malware, ransomware and viruses, and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, increase costs and subject us to possible legal claims and liability. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from such attacks, our cybersecurity program does not prevent all breaches or cyberattack incidents. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. We have experienced, and expect to continue to experience, cyber intrusions and attacks to our information systems and those of third parties, including vendors, suppliers, contractors and quasi government entities, like ERCOT and MISO, who perform certain services for us or administer and maintain our sensitive information. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, through cybersecurity breach or ransomware attack has increased as attempted attacks have advanced in sophistication and number around the world. We are not fully insured against all cybersecurity risks, any of which could adversely affect our reputation and could have a material adverse effect on our financial condition, results of operations and cash flows.
We depend on the secure operations of our physical assets to transport the energy we deliver and our information technology to process, transmit and store electronic information, including information and operational technology we use to safely operate our energy transportation systems. Security breaches or acts of terrorism could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect our operations, as well as potential data privacy breaches and loss of protected personal information. Such losses could result in operational impacts, damage to our assets, public or personal safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential material adverse effect on our operations, financial condition, results of operations and cash flows. There is no certainty that costs incurred related to securing against security threats will be completely recoverable through rates.
Compliance with and changes in cybersecurity laws and regulations have a cost and operational impact on our business, and failure to comply with such requirements could adversely impact our reputation, financial condition, results of operations and cash flows.
Cyberattacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines and electric generation and infrastructure, may be specifically targeted by certain groups. In the second and third quarters of 2021, the TSA announced two new security directives in response to a ransomware attack on the Colonial Pipeline that occurred in 2021. These directives require critical pipeline owners to comply with mandatory reporting measures, designate a cybersecurity coordinator, provide vulnerability assessments, and ensure compliance with certain cybersecurity requirements. We may be required to expend significant additional resources and costs to respond to cyberattacks, to continue to modify or enhance our protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. There is no certainty that such costs incurred will be recovered through rates. Any failure to remain in compliance with these government regulations or failure in our cybersecurity protective measures may result in enforcement actions which may have a material adverse effect on our reputation, financial condition, results of operations and cash flows.
Failure to maintain the security of personally identifiable information could adversely affect us.
In connection with our businesses, we and our vendors, suppliers and contractors collect and retain personally identifiable information (for example, information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The regulatory environment surrounding information security and data privacy is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant costs, fines and penalties and liabilities for us. While we have implemented and maintain a data privacy program designed to protect personal information from any attacks, our data privacy programs does not prevent all security or privacy breaches. Some of our third party vendors who maintain personally identifiable information have experienced a breach of their data privacy. A significant theft, loss or fraudulent use of the personally identifiable information we maintain or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions and other legal requirements could adversely impact our reputation and could result in significant costs, fines and penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our financial condition, results of operations and cash flows.
We currently have insurance in place, such as general liability and property insurance, to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to fully cover or restore the loss or damage without negative impact on our financial condition, results of operations and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires, winter storms and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage to utility companies may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Insurance premiums for any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses.
In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and insurance capacity to be limited. Historically, Houston Electric has been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise. In the future, any such recovery may not be granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its financial condition, results of operations and cash flows.
We face risks related to COVID-19 and other health epidemics and outbreaks, including economic, regulatory, legal, workforce and cyber security risks, which could adversely impact our financial condition, results of operations, cash flows and liquidity.
The COVID-19 pandemic continues to evolve and adversely affect current global economic activities and conditions. An extended slowdown of economic growth, decreased demand for commodities and/or material changes in governmental or regulatory policy in the United States has resulted in, and could continue to result in, lower growth and reduced demand for and usage of electricity and natural gas in our service territories, particularly among our commercial and industrial customers, as customer facilities close, remain closed or potentially close again. The ability of our customers, contractors and suppliers to meet their obligations to us, including payment obligations, has also been negatively affected under the current economic conditions and previously resulted in an increase to allowance for credit losses. To the extent these conditions in our service territories persist, our bad debt expense from uncollectible accounts could continue to increase, negatively impacting our financial condition, results of operations and cash flows. REPs have and could continue to encounter financial difficulties, including bankruptcies, which could impair their ability to pay for Houston Electric’s services or could cause them to delay such payments, adversely affecting Houston Electric’s cash flows and liquidity. Additionally, our state and local regulatory agencies, in response to a federal mandate or otherwise, could impose restrictions on the rates we charge to provide our services, including the inability to implement approved rates, or delay actions with respect to our rate cases and filings. The COVID-19 pandemic may affect our ability to timely satisfy regulatory requirements such as recordkeeping and/or timely reporting requirements. For further information on COVID-19 regulatory matters, please see Note 7 to the consolidated financial statements, which information is incorporated herein by reference.
Additionally, various federal, state, and local governmental entities continue to pass legislation, issue orders, and take other measures to respond to the COVID-19 pandemic, including vaccination, testing and masking requirements. Some of these governmental requirements conflict with others presenting challenges to businesses like ours in interpreting, implementing, and complying with them. Governmental requirements have also been subject to challenges in litigation, such as OSHA’s Emergency Temporary Standard, mandating vaccination for certain employers, which was recently withdrawn by OSHA after being stayed by the Supreme Court of the United States.
With respect to our supply chain, to the extent we experience such disruptions in our supply chain that limit our ability to obtain materials and equipment necessary for our businesses, whether through delayed order fulfillment, limited production or unavailability due to COVID-19, we may be unable to perform our operations timely or as anticipated, which could result in service or construction delays, project cancellations or increased costs. Furthermore, in the event key officers or a substantial portion of our workforce were to be impacted by COVID-19 for an extended period of time, we may face challenges with respect to our services or operations and we may not be able to execute our capital plan as anticipated. There is considerable uncertainty regarding the extent to which COVID-19 and its variants will continue to spread, even with the availability of a vaccine therefor, and the extent and duration of governmental and other measures implemented to try to slow the spread of COVID-19 and variants, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. Restrictions of this nature have caused, and may continue to cause, us, our suppliers and other business counterparties to experience operational delays, shortages of employees, materials and equipment, facility shutdowns or business closures. As appropriate, based on conditions, we have modified certain business and workforce practices (including those related to employee travel, employee work locations and participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. However, the quarantine of personnel or the inability to access our facilities or customer sites could adversely affect our operations. While certain of our personnel have been, and may continue to be, quarantined, our operations and corporate functions have not been significantly adversely affected to date. As of the date of this Form 10-K, the vast majority of our workforce works from their regular work locations. As appropriate, we have adjusted our operational protocols to minimize exposure and risk to our field personnel, customers and the communities we serve, while continuing to maintain the work activities necessary for safe and reliable service to our customers. Even with increased safety precautions, we cannot assure that such adjustments and precautions will be sufficient to minimize exposure to and risk from COVID-19. Also, we have a limited number of highly skilled employees for some of our operations. If a large proportion of our employees in those critical positions were to contract COVID-19 at the same time, we would rely upon our business continuity plans in an effort to continue operations at our facilities, but there is no certainty that such measures will be sufficient to mitigate the adverse impact to our operations that could result from shortages of highly skilled employees. Additionally, in the event that customers, contractors, employees or others were to allege that they contracted COVID-19 because of actions we took or failed to take, we could face claims, lawsuits and potential legal liability. In addition to the reasonableness of our actions and efforts to comply with applicable COVID-19 guidance, our exposure and ultimate liability would depend upon the applicability of workers’ compensation, the availability of insurance coverage and limitations on liability being considered or enacted at the state and federal level. For more information, see “— Continued disruptions to the supply...”
Experts have observed an increase in the volume and the sophistication of cyberattacks since the beginning of the COVID-19 pandemic. Any technology system breaches and/or data privacy incidents could disrupt our operations or result in the loss or exposure of confidential or sensitive customer, employee or company information and adversely affect our business, financial condition and results of operations. For those employees and third-party service providers who continue to work remotely, we face heightened cyber security and privacy risks related to unauthorized system access, aggressive social engineering tactics and adversaries attacking the information technology systems, network infrastructure, technology and facilities used to conduct our business. The increase in the remote working arrangements of our employees initially as a result of the COVID-19 pandemic required enhancements and modifications to our information technology infrastructure (for example, virtual private network, or VPN, and remote collaboration systems), and any failures of these technologies, including third-party service providers, that facilitate working remotely could limit our ability to conduct our ordinary operations and expose us to increased risk or impact of a cyberattack. See “— Cyberattacks, physical security breaches, acts...”
We will continue to monitor developments affecting our employees, customers and operations. At this time, however, we cannot predict the extent or duration of the COVID-19 pandemic or its future effects on national, state and local economies, including the impact on our ability to access capital markets, our supply chain, our business strategies and plans and our workforce, nor can we estimate the potential adverse impact from COVID-19 on our financial condition, results of operations, cash flows and liquidity. Other future epidemics and outbreaks may result in potential adverse impacts similar to, or worse than, those from COVID-19.
Our success depends upon our ability to attract, effectively transition, motivate and retain key employees and identify and develop talent to succeed senior management.
We depend on senior executive officers and other key personnel. Our success depends on our ability to attract, effectively transition and retain key personnel. Further tightening of the labor market and increasing wages to attract and retain key personnel may adversely affect our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify and develop talent to succeed senior management. The retention of key personnel and appropriate senior management succession planning will continue to be critically important to the successful implementation of our strategies.
Failure to attract and retain an appropriately qualified workforce and maintain good labor relations could adversely impact the operations of our facilities and our results of operations.
Our businesses are dependent on recruiting, retaining and motivating employees. Like many companies in the utilities industry and other industries, we have experienced higher than normal turnover of employees as a result of a number of factors, including the COVID-19 pandemic, a tightening labor market, increasing remote working opportunities, employees shifting industries, individuals deciding not to work and a maturing workforce. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our businesses, particularly the specialized skills and knowledge required to construct and operate generation facilities, a technology-enabled power grid and transmission and distribution facilities, among other facilities. If we are unable to successfully attract and retain an appropriately qualified workforce, our ability to execute on our 10-year capital plan and our results of operations could be negatively affected.
Furthermore, the operations of our facilities depends on good labor relations with our employees, and several of our businesses have in place collective bargaining agreements with different labor unions, comprising approximately 37% of our workforce. We have several separate bargaining units, each with a unique collective bargaining agreement described further in Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with USW Locals 13-227, USW Locals 13-1 and IBEW Local 702 related to Natural Gas and CenterPoint Energy employees are scheduled to expire in June 2022, July 2022 and June 2022, respectively, and negotiations of these agreements are expected to be completed before the respective expirations. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have a material adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and cash flows.
Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our financial condition, results of operations and liquidity.
CenterPoint Energy and its subsidiaries maintain qualified defined benefit pension plans covering certain of its employees. Costs associated with these plans are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, contributions to the plan, the number of plan participants and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and CenterPoint Energy may be required to make unplanned contributions in the event of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations, or government regulations that increase minimum funding requirements or the pension liability. In addition to affecting CenterPoint Energy’s funding requirements, these factors could adversely affect our financial condition, results of operations and liquidity.
We may be significantly affected by changes in federal income tax laws and regulations, including any comprehensive federal tax reform legislation.
Our businesses are impacted by U.S. federal income tax policy. Under the current administration with the Senate and House of Representatives controlled by the Democratic Party, comprehensive federal tax reform legislation could be enacted that may significantly change the federal income tax laws applicable to domestic businesses, including changes that may increase the federal income tax rate and impact investment incentives and deductions for depreciation and interest, among other deductions. While CenterPoint Energy and its subsidiaries cannot assess the overall impact of any such potential legislation on our businesses, it is possible that our financial condition, results of operations or cash flows could be negatively impacted. Furthermore, with any enacted federal tax reform legislation, it is uncertain how state commissions and local municipalities may require us to respond to the effects of such tax legislation, including determining the treatment of EDIT and other increases and decreases in our revenue requirements. As such, potential regulatory actions in response to any enacted tax legislation could adversely affect our financial condition, results of operations and cash flows.
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results.
The Registrants are subject to numerous legal proceedings, the most significant of which are summarized in Note 16 to the consolidated financial statements to the Registrants’ respective consolidated financial statements. Litigation is subject to many uncertainties, and recent trends suggest that jury verdicts and other liability have been increasing, and the Registrants cannot predict the outcome of all matters with assurance. Additionally, under some circumstances, the Registrants could potentially have claims filed against them or incur liabilities associated with assets and businesses no longer owned by them as a result of sales, divestitures or other transfers to third parties who may be unable to fulfill their indemnity obligations to the Registrants. Final resolution of these matters, or any potential future claims or liabilities, may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have a material adverse effect on the Registrants’ financial results.
Our businesses may be adversely affected by the intentional misconduct of our employees.
We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and our efforts to prevent misconduct, it is possible for employees to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of our Ethics and Compliance Code and Standards of Conduct/Business Ethics policy, among other policies. If such intentional misconduct by employees should occur, it could result in substantial liability, higher costs, increased regulatory scrutiny and
negative public perceptions, any of which could have a material adverse effect on our financial condition, results of operations financial condition and cash flows. From time to time, including as part of our Ethics and Compliance program’s efforts to detect misconduct, we become aware of and expect to continue to become aware of instances of employee misconduct, which we investigate, remediate and disclose as appropriate and proportionate to the incident.
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Item 1B. | Unresolved Staff Comments |
Item 1B.Unresolved Staff Comments
None.
Item 2.Properties
The following discussion is based on the Registrants’ businesses and equity method investment as of December 31, 2019.2021.
Character of Ownership
We lease or own our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and natural gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.
Houston Electric T&D (CenterPoint Energy and Houston Electric)
Properties
All of Houston Electric’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires, telecommunications network and meters. Most of Houston Electric’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law.
All real and tangible properties of Houston Electric, subject to certain exclusions, are currently subject to:
•the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and
•the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.
No first mortgage bonds are outstanding under the Mortgage and Houston Electric is contractually obligated to not issue any additional first mortgage bonds under the Mortgage and is undertaking actions to release the lien of the Mortgage. For information regardingrelated to debt outstanding under the General Mortgage, see Note 14 to the consolidated financial statements.
Indiana Electric’s properties are primarily located in Indiana. They consist of transmission lines in Indiana and Kentucky, distribution lines, substations, service centers, coal-fired generating facilities, gas-fired turbine peaking units, a landfill gas electric generation project and solar generation facilities.
All real and tangible properties of Indiana Electric, subject to certain exclusions, are currently subject to:
•the lien of the First Mortgage Indenture dated as of April 1, 1932, between SIGECO (Indiana Electric) and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures.
Electric Lines - Transmission and Distribution. As of December 31, 2021, Houston Electric T & D reportable segment, please read “Business — Ourand Indiana Electric owned and operated the following electric transmission and distribution lines:
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| | Houston Electric | | Indiana Electric |
Description | | Overhead Lines | | Underground Lines | | Indiana | | Kentucky (1) |
Transmission lines: | | (in Circuit Miles) |
69 kV | | 216 | | | 2 | | | 564 | | | — | |
138 kV | | 2,260 | | | 24 | | | 411 | | | 9 | |
345 kV | | 1,445 | | | — | | | 63 | | | 15 | |
Total | | 3,921 | | | 26 | | | 1,038 | | | 24 | |
| | | | | | | | |
| | (in Circuit Miles) |
Distribution lines | | 29,753 | | | 27,172 | | | 4,614 | | | 2,546 | |
(1)These assets interconnect with Louisville Gas and Electric Company’s transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky.
Generating Capacity. As of December 31, 2021, Indiana Electric had 1,217 MW of installed generating capacity, as set forth in the following table.
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Generation Source | | Unit No. | | Location | | Date in Service | | Capacity (MW) |
Coal | | | | | | | | |
A.B. Brown | | 1 | | Posey County | | 1979 | | 245 | |
A.B. Brown | | 2 | | Posey County | | 1986 | | 245 | |
F.B. Culley | | 2 | | Warrick County | | 1966 | | 90 | |
F.B. Culley | | 3 | | Warrick County | | 1973 | | 270 | |
Warrick (1) | | 4 | | Warrick County | | 1970 | | 150 | |
Total Coal Capacity | | | | | | | | 1,000 | |
Gas | | | | | | | | |
Brown (2) | | 3 | | Posey County | | 1991 | | 80 | |
Brown | | 4 | | Posey County | | 2002 | | 80 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Renewable Landfill Gas | | | | Pike County | | 2009 | | 3 | |
Total Gas Capacity | | | | | | | | 163 | |
Solar | | | | | | | | |
Oak Hill | | | | Evansville, Indiana | | 2018 | | 2 | |
Volkman | | | | Evansville, Indiana | | 2018 | | 2 | |
Troy | | | | Spencer County | | 2021 | | 50 | |
Total Solar Capacity | | | | | | | | 54 | |
Total Generating Capacity (3) | | | | | | | | 1,217 | |
(1)SIGECO and AGC own a 300 MW unit at the Warrick Power Plant as tenants in common.
(2)Brown Unit 3 is also equipped to burn oil.
(3)Excludes 1.5% participation in OVEC. See Item 1. Business —for more details.
Mobile Generation. As allowed by a new law enacted by the Texas legislature after the February 2021 Winter Storm Event, Houston Electric Transmission & Distribution — Properties”is now leasing mobile generation facilities that can provide temporary emergency electric energy that can aid in Item 1restoring power to customers during certain widespread power outages that are impacting its distribution system. In 2021, Houston Electric entered into two leases for mobile generation: (1) a temporary short-term basis lease initially for 125 MW and that expanded to 220 MW by December 31, 2021 and (2) a 7.5 year lease for up to 505 MW of this report,mobile generation, of which information is incorporated herein by reference.125 MW was delivered as of December 31, 2021.
Substations. As of December 31, 2021, Houston Electric owned 239 major substation sites having a total installed rated transformer capacity of 71,241 Mva. As of December 31, 2021, Indiana Electric’s transmission system also includes 33 substations with an installed capacity of approximately 4,555 Mva. In addition, Indiana Electric’s distribution system includes 77 distribution substations with an installed capacity of approximately 2,137 Mva and 56,973 distribution transformers with an installed capacity of 2,580 Mva.
Service Centers. As of December 31, 2021, Houston Electric operated 13 regional service centers located on a total of 320 acres of land and Indiana Electric Integrated (CenterPoint Energy)operated 6 regional service centers located on a total of 50 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.
For information regarding the properties of the Indiana Electric Integrated reportable segment, please read “Business — Our Business — Indiana Electric Integrated — Properties” in Item 1 of this report, which information is incorporated herein by reference.
Natural Gas Distribution (CenterPoint Energy and CERC)
For information regarding the propertiesAs of December 31, 2021, CenterPoint Energy’s and CERC’s Natural Gas owned approximately 100,000 and 78,000 linear miles of natural gas distribution and transmission mains, respectively, varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s Natural Gas in Indiana and Ohio includes approximately 22,000 miles of distribution and transmission mains, all of which are located in Indiana and Ohio except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported to customers in Indiana. Generally, in each of the cities, towns and rural areas served by CenterPoint Energy’s and CERC’s Natural Gas, Distribution reportable segment, please read “Business — Our Business —they
own the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s Natural Gas Distribution — Assets” in Item 1 of this report, which information is incorporated hereinreceives gas are owned, operated and maintained by reference.
Energy Services (CenterPoint Energyothers, and CERC)
For information regardingtheir distribution facilities begin at the propertiesoutlet of the Energy Services reportable segment, please read “Business — Our Business — Energy Services — Assets”measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.
As of December 31, 2021, CEIP owned and operated over 285 miles of intrastate pipeline in Louisiana, Texas and Oklahoma.
Item 1 of this report, which information is incorporated herein by reference.3.Legal Proceedings
Infrastructure Services (CenterPoint Energy)
For information regarding the properties of the Infrastructure Services reportable segment, please read “Business — Our Business — Infrastructure Services” in Item 1 of this report, which information is incorporated herein by reference.
Midstream Investments (CenterPoint Energy)
For information regarding the properties of the Midstream Investments reportable segment, please read “Business — Our Business — Midstream Investments” in Item 1 of this report, which information is incorporated herein by reference.
Corporate and Other (CenterPoint Energy and CERC)
For information regarding the properties of the CenterPoint Energy Corporate and Other reportable segment, please read “Business — Our Business — Corporate and Other Operations” in Item 1 of this report, which information is incorporated herein by reference.
For a discussion of material legal and regulatory proceedings affecting the Registrants as of December 31, 2019,2021, please read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of this report and Note 16(e) to the consolidated financial statements, which information is incorporated herein by reference.
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Item 4. | Mine Safety Disclosures |
Item 4.Mine Safety Disclosures
Not applicable.
PART II
This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Houston Electric and CERC.
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Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
CenterPoint Energy
As of February 19, 2020,15, 2022, CenterPoint Energy’s common stock was held by approximately 27,52424,985 shareholders of record. CenterPoint Energy’s common stock is listed on the NYSE and Chicago Stock Exchange and is traded under the symbol “CNP.”
The amount of future cash dividends will be subject to determination based upon CenterPoint Energy’s financial condition and results of operations, and financial condition, future business prospects, any applicable contractual restrictions and other factors that CenterPoint Energy’s Board of Directors considers relevant and will be declared at the discretion of CenterPoint Energy’s Board of Directors. For further information on CenterPoint Energy’s dividends, see Note 13 to the consolidated financial statements.
Repurchases of Equity Securities
During the quarter ended December 31, 2019,2021, none of CenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of CenterPoint Energy or any “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.
Houston Electric
As of February 19, 2020,15, 2022, all of Houston Electric’s 1,000 outstanding common shares were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.
CERC
As of February 19, 2020,15, 2022, all of CERC Corp.’s 1,000 outstanding shares of common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.
Item 6. Selected Financial Data (CenterPoint Energy)
The following table presents selected financial data with respect to CenterPoint Energy’s consolidated financial condition and consolidated results of operations and should be read in conjunction with CenterPoint Energy’s consolidated financial statements and the related notes in Item 8 of this report.Not applicable.
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| Year Ended December 31, | |
| 2019 | | 2018 | | 2017 | | 2016 | | 2015 | |
| (in millions, except per share amounts) | |
Revenues | $ | 12,301 |
| | $ | 10,589 |
| | $ | 9,614 |
| | $ | 7,528 |
| | $ | 7,386 |
| |
Equity in earnings (losses) of unconsolidated affiliates, net | 230 |
| | 307 |
| | 265 |
| | 208 |
| | (1,663 | ) | (2) |
Income (loss) available to common shareholders | 674 |
| | 333 |
| | 1,792 |
| (1) | 432 |
|
| (692 | ) | |
Basic earnings (loss) per common share | 1.34 |
| | 0.74 |
| | 4.16 |
| | 1.00 |
|
| (1.61 | ) | |
Diluted earnings (loss) per common share | 1.33 |
| | 0.74 |
| | 4.13 |
| | 1.00 |
|
| (1.61 | ) | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | |
| 2019 | | 2018 | | 2017 | | 2016 | | 2015 | |
| (in millions, except per share amounts) | |
Cash dividends paid per common share | $ | 1.15 |
| | $ | 1.11 |
| | $ | 1.07 |
| | $ | 1.03 |
| | $ | 0.99 |
| |
Dividend payout ratio | 86 | % | | 150 | % | | 26 | % |
| 103 | % |
| n/a |
| |
Return on average common equity | 8 | % | | 5 | % | | 44 | % | | 12 | % | | (17 | )% | |
At year-end: | | | | | | | | | | |
Book value per common share | $ | 16.64 |
| | $ | 16.08 |
| | $ | 10.88 |
| | $ | 8.04 |
| | $ | 8.05 |
| |
Market price per common share | 27.27 |
| | 28.23 |
| | 28.36 |
| | 24.64 |
| | 18.36 |
| |
Market price as a percent of book value | 164 | % | | 176 | % | | 261 | % | | 306 | % | | 228 | % | |
Percentage of common units owned representing limited partner interests in Enable | 53.7 | % | | 54.0 | % | | 54.1 | % | | 54.1 | % | | 55.4 | % | |
Total assets (3) (4) | $ | 35,439 |
| | $ | 27,009 |
| | $ | 22,736 |
| | $ | 21,829 |
| | $ | 21,290 |
| |
Short-term borrowings | — |
| | — |
| | 39 |
| | 35 |
| | 40 |
| |
Securitization Bonds, including current maturities | 977 |
| | 1,435 |
| | 1,868 |
| | 2,278 |
| | 2,667 |
| |
Other long-term debt, including current maturities (5) | 14,135 |
| | 7,729 |
| | 6,933 |
| | 6,279 |
| | 6,063 |
| |
Capitalization: | | | | | | | | | | |
Common stock equity | 36 | % | | 47 | % | | 35 | % | | 29 | % | | 28 | % | |
Long-term debt, including current maturities | 64 | % | | 53 | % | | 65 | % | | 71 | % | | 72 | % | |
Capitalization, excluding Securitization Bonds: | | | | | | | | | | |
Common stock equity | 37 | % | | 51 | % | | 40 | % | | 36 | % | | 36 | % | |
Long-term debt, excluding Securitization Bonds, and including current maturities | 63 | % | | 49 | % | | 60 | % | | 64 | % | | 64 | % | |
Capital expenditures | $ | 2,587 |
| | $ | 1,720 |
| | $ | 1,494 |
| | $ | 1,406 |
| | $ | 1,575 |
| |
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
| |
(1) | Income (loss) available to common shareholders for the year ended December 31, 2017 includes a reduction in income tax expense of $1,113 million due to tax reform. See Note 15 to the consolidated financial statements for further discussion of the impacts of the TCJA implementation. |
| |
(2) | This amount includes $1,846 million of non-cash impairment charges related to Enable. |
| |
(3) | The increase in Total assets as of December 31, 2019, as compared to December 31, 2018, was primarily driven by the assets acquired in the Merger. |
| |
(4) | Total assets as of December 31, 2018 include cash and cash equivalents of $4.2 billion. |
| |
(5) | The increase in Other long-term debt, including current maturities as of December 31, 2019, as compared to December 31, 2018, was primarily driven by debt incurred to finance the Merger and debt acquired in the Merger. |
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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.company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, and distribution electricand 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 and discontinued operations, please read Note 1 to the consolidated financial statements.
Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that provides electric transmission service to transmission service customers in the ERCOT region and distribution servicesservice to REPs serving the Texas Gulf Coastgulf coast area that includes the city of Houston.
CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy that owns and operates natural gas distribution facilities in several states, with operating subsidiaries that own and operate natural gas distribution facilities in six statespermanent pipeline connections through interconnects with various interstate and supply natural gas to commercial and industrial customers and electric and natural gas utilities in over 30 states.intrastate pipeline companies.
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, 2019,2021, CenterPoint Energy’s reportable segments by Registrant are as follows:were Electric and Natural Gas.
|
| | | | | | | | | | | | | | |
Registrants | | Houston•The 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 in Houston Electric’s and Indiana Electric’s service territories, as well as the 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 includesutility and energy delivery services to electric customers and electric generation assets to serve its electric customers and optimize those assets in the wholesale power market.market in Indiana Electric’s service territory. For further information about the Indiana Electric Integrated reportable segment, see “Business — Our Business — Indiana Electric Integrated”Electric” in Item 1 of Part I of this report.
•The 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.Minnesota and home repair protection plans to natural gas customers in Arkansas, Indiana, Mississippi, Ohio, Oklahoma and Texas through a third party as of December 31, 2021. For further information about the Natural Gas Distribution reportable segment, see “Business — Our Business — Natural Gas Distribution”Gas” in Item 1 of Part I of this report.
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• | 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.
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 Corporateoperations.
Houston Electric and OtherCERC each consist of a single reportable segment includes unallocated corporate costs and inter-segment eliminations.segment.
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
As announced in cash. Through its subsidiaries, Vectren’s operations consist of utilityDecember 2020, our business strategy incorporated the Business Review and non-utility businesses. The utility operations include three public utilities, Indiana Gas, SIGECOEvaluation Committee’s recommendations to increase our planned capital expenditures in our electric and VEDO, which, in the aggregate, provide natural gas distributionbusinesses to support rate base growth and transportation servicessell certain of our Natural Gas businesses located in Arkansas and Oklahoma as a means to nearly 67%efficiently finance a portion of Indianasuch increased capital expenditures. The sale of our Natural Gas businesses in Arkansas 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 customersOklahoma was completed 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 23January 2022. See Note 4 to the consolidated financial statements.statements for further details.
In February 2021, we announced our support for the Enable Merger, which closed in December 2021. At our September 2021 analyst day, we announced our plans to exit the midstream sector by the end of 2022 and become a pure-play utility focusing on growth in our existing service territories. In September 2021, we entered into a Forward Sale Agreement to sell 50 million Energy Transfer Common Units immediately following the closing of the Enable Merger. In December 2021, we completed sales of 150 million Energy Transfer Common Units (inclusive of the Energy Transfer Common Units sold pursuant to the Forward Sale Agreement) and 192,390 Energy Transfer Series G Preferred Units for net proceeds of $1,320 million. See Note 12 to the consolidated financial statements for further details.
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.
To assess our financial performance, our management primarily monitors operatingrecovery of costs and return on investments by the evaluation of net income and cash flows, among other things, from our regulated service territories within our reportable segments. Within these broader financial measures, we monitor margins, natural gas and fuel costs, interest expense, capital spending and working capital requirements.requirements, and operation and maintenance expense. In addition to these financial measures, we also monitor a number of variables that management considers important to gauge the performance of 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,days, environmental impacts, safety factors, system reliability and customer satisfaction to gauge our performance.satisfaction.
The nature of our businesses requires significant amounts of capital investment, particularly in light of our new 10-year capital plan, 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. Proceeds from future dispositions of Energy Transfer Common Units or Energy Transfer Series G Preferred Units could reduce borrowings or provide additional support for our capital investment needs. With respect to CERC, we intend to use proceeds from the completed dispositions of our Natural Gas businesses in Arkansas and Oklahoma and any potential further asset sales to satisfy a portion of its 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, including supply chain disruptions, 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. For example, Houston Electric is largely concentrated in Houston, Texas, a diverse economy where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although the Houston area represents a large part of our customer base, we have
a diverse customer base throughout the various states our utility businesses serve. In Minnesota, for instance, education and health services are the state’s largest sectors, whereas Arkansas has a large food manufacturing industry.sectors. Indiana and Ohio are impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest such as automotive, feed and grain processing. 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 operationsglobal supply chain has experienced significant disruptions due to a multitude of Vectren’sfactors, such as labor shortages, resource availability, long lead times, inflation and weather. These disruptions have adversely impacted the utility businesses are concentrated in centralindustry. Like many of our peers, we have experienced disruptions to our supply chain and southern Indiana and west-central Ohio and are therefore impacted by changesmay continue to experience such disruptions in the Midwest economyfuture. For example, we, along with the developer of the project, recently announced plans to downsize the solar array to be built in general and changes in particular industries concentratedPosey County, Indiana from 300 MW to 200 MW due to supply chain issues experienced in the Midwest. These industries include automotive assembly, partsenergy industry, rising cost of commodities 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.community feedback. For more information, see Note 16 to the consolidated financial statements.
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.Toslowed. 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. Lower interest rates have helped single family housing starts in the Houston and Minneapolis to exceed growth in previous years. Multifamily residential customer growth is affected by the cyclical nature of apartment construction. Beginning in 2019, aA new construction cycle in Houston helped overall residential customer growth to return tosurpass the long-term trend of 2%. for the last two years. 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 customerManagement expects residential meter growth was 1.3% for 2019, which is slightly higher thanCERC to remain 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 tandemline 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.trends at approximately 1%.
Significant Events
Proposed DivestitureSale of Infrastructure Services.Natural Gas Businesses. 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,April 29, 2021, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Equityan Asset Purchase Agreement to sell CES, which represents substantially allits Arkansas and Oklahoma Natural Gas businesses for $2.15 billion in cash, including recovery of the businesses within the Energy Services reportable segment. The transaction is expected to closeapproximately $425 million in gas cost, including storm-related incremental natural gas costs incurred in the second quarterFebruary 2021 Winter Storm Event, subject to certain adjustments set forth in the Asset Purchase Agreement. The sale closed on January 10, 2022. On August 31, 2021, CenterPoint Energy, through its subsidiary CERC Corp., completed the sale of 2020.MES to Last Mile Energy. For further information, see Notes 6 and 23Note 4 to the consolidated financial statements.
Net Zero Emission Goals. In September 2021, CenterPoint Energy announced new net zero emission goals for both Scope 1 and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035. For more information regarding CenterPoint Energy’s new net zero emission goals and the risks associated with them, see “Risk Factors — Risk Factors Affecting Our Businesses — CenterPoint Energy is subject to operational and financial risks...” and “Management’s Discussion and Analysis — Liquidity and Capital Resources” in this Form 10-K.
February 2021 Winter Storm Event. In February 2021, portions of the United States experienced an extreme and unprecedented winter weather event that resulted in corresponding electricity generation shortages, including in Texas, natural gas shortages and increased wholesale prices of natural gas in the United States. Many customers of Houston Electric’s REPs and, to a lesser extent, of CERC, were severely impacted by outages in electricity and natural gas delivery during the February 2021 Winter Storm Event. As a result of this weather event, the governors of Texas, Oklahoma and Louisiana declared states of either disaster or emergencies in their respective states. Subsequently, President Biden also approved major disaster declarations for all or parts of Texas, Oklahoma and Louisiana.
The February 2021 Winter Storm Event resulted in financial impacts to CenterPoint Energy, Houston Electric and CERC, including substantial increases in prices for natural gas, decreased revenues at Houston Electric due to ERCOT-mandated outages, additional interest expense related to external financing to pay for natural gas working capital, significant impacts to the REPs, including the REPs’ ability to pay invoices from Houston Electric, increases in bad debt expense, issues with counterparties and customers, litigation and investigations or inquiries from government or regulatory agencies and entities, and other financial impacts. CenterPoint Energy does not, at this time, anticipate long-term financial impacts associated with the February 2021 Winter Storm Event, including changes to its credit profile, credit ratings or liquidity, given the regulatory mechanisms that are in place in our jurisdictions to recover the extraordinary expenses. CenterPoint Energy is, however,
continuing to work with individual regulatory agencies to reach a successful final resolution on the recovery of the extraordinary costs. For more information regarding regulatory impacts, debt transactions and litigation, see Notes 7, 14 and 16 to the consolidated financial statements and “—Liquidity and Capital Resources —Future Sources and Uses of Cash” and “—Regulatory Matters” below.
Enable Merger Agreement. On February 16, 2021, Enable entered into the Enable Merger Agreement. On December 2, 2021, the Enable Merger closed pursuant to the Enable Merger Agreement. At the closing of the Enable Merger, CenterPoint Energy transferred 100% of the Enable Common Units and Enable Series A Preferred Units it owned in exchange for Energy Transfer Common Units and Energy Transfer Series G Preferred Units, respectively. In December 2021, we completed sales of approximately 75% of the acquired Energy Transfer Common Units and 50% of Energy Transfer Series G Preferred Units for net proceeds of $1,320 million. For more information, see Notes 4, 11 and 12 to the consolidated financial statements.
Debt Transactions. In 2021, CenterPoint Energy, Houston Electric and CERC issued a combined $4.5 billion in new debt and repaid or redeemed a combined $2.7 billion of debt, excluding scheduled principal payments on Securitization Bonds. Additionally, on January 31, 2022, CERC Corp. redeemed $425 million aggregate principal amount of CERC’s outstanding senior notes due 2023. For further information about debt transactions in 2021 and to date in 2022, see Note 12 to the consolidated financial statements.
Preferred Stock Conversions. For information regarding preferred stock conversions in 2021, see Note 19 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 detailsinformation related to our pending and completed regulatory proceedings and orders related to the TCJA in 20192021 and to date in 2020,2022, see “—Liquidity and Capital Resources —Regulatory Matters” in Item 7below.
Board of Part II of this report, which discussion is incorporated herein by reference.
Merger with Vectren. Directors Governance Structure. On February 1, 2019, pursuant to the Merger Agreement,July 22, 2021, CenterPoint Energy consummatedannounced the previously announced Mergerdecision of the independent directors of the Board to implement a new independent Board leadership and acquired Vectren for approximately $6 billion in cash.governance structure and appointed a new independent chair of the Board. To implement this new governance structure, the independent directors of the Board eliminated the Executive Chairman position. For morefurther information, about the Merger, see Notes 1 and 4Note 8 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,business strategies and factors that may have a material impact on such performance, cash distributionsstrategic initiatives, restructurings, joint ventures 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 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 benefitsacquisitions or dispositions of the Merger and integration,assets or businesses, including the outcomecompleted sale of shareholder litigation filed against Vectren that could reduceour Natural Gas businesses in Arkansas and Oklahoma, which we cannot assure will have the anticipated benefits to us, our planned sales of the Merger, as well as the ability to successfully integrate the Vectren businessesour remaining Energy Transfer common and to realizepreferred equity securities, which we cannot assure will be completed or will have the anticipated benefits and commercial opportunities;to us;
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;
•our ability to fund and invest planned capital and the timely recovery of our investments, including those related to Indiana Electric’s generation transition plan as part of its most recent IRP;
•our ability to successfully construct and operate electric generating facilities, including complying with applicable environmental standards and the outcomeimplementation of a well-balanced energy and resource mix, as appropriate;
•the pending Houston Electric rate case;development of new opportunities and the performance of projects undertaken by Energy Systems Group, which are subject to, among other factors, the level of success in bidding contracts and cancellation and/or reductions in the scope of projects by customers, and obligations related to warranties, guarantees and other contractual and legal obligations;
•the recording of impairment charges;
•timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;investment, including the timing and amount of the recovery of Houston Electric’s mobile generation leases;
•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;capital, such as impacts from the February 2021 Winter Storm Event;
•the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric, including the negative impact on such ability related to COVID-19;
•the COVID-19 pandemic and its effect on our operations, business and financial condition, our industries and the communities we serve, U.S. and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behaviors relating thereto;
•volatility in the markets for oil and natural gas as a result of, among other factors, the actions of certain crude-oil exporting countries and the Organization of Petroleum Exporting Countries, increasing exports of LNG to Europe and climate change concerns, including the increasing adoption and use of alternative energy sources;
•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;
•direct or indirect effects on our facilities, resources, operations and financial condition resulting from terrorism, cyber attacks or intrusions, 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 and other severe weather events, pandemic health events or other occurrences;
•tax legislation, including the effects of the CARES Act and of the TCJA (which includes but is not limited to any potential changes to tax rates, tax credits and/or interest deductibility), as well as any changes in tax laws under the current administration, 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•our 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•matters affecting 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;
•local, state and federal legislative and regulatory actions or developments relating to the environment, including, among others, those related to global climate change, air emissions, carbon, waste water discharges and the handling and disposal of CCR that could impact operations, cost recovery of generation plant costs and related assets, and CenterPoint Energy’s net zero emission goals;
•the impact of unplanned facility outages or other closures;
•the sufficiency of our insurance coverage, including availability, cost, coverage and terms and ability to recover claims;
•the availability and prices of raw materials and services and changes in labor for current and future construction projects;
local, stateprojects 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;
our ability to invest planned capital and the timely recovery of our existing and future investments,maintenance costs, 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 maintenancesuch 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;
•changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;
•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;hedges;
•timely and appropriate regulatory actions, which include actions allowing securitization, for any future hurricanes or other severe weather events, or natural disasters or other recovery of costs, including costs associated with Hurricane Harvey;costs;
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;
•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;generation, and their adoption by consumers;
•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;
•political and economic developments, including energy and environmental policies under the Biden administration;
•the transition to a replacement for the LIBOR benchmark interest rate;
•CenterPoint Energy’s ability to execute on its initiatives, targets and goals, including its net zero emission goals and its operations and maintenance expenditure goals;
•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event;
•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 |
|
CenterPoint Energy’s results of operations are affected by seasonal fluctuations in the demand for electricity and natural gas. CenterPoint Energy’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, its subsidiaries ability to collect receivables from REPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of our consolidated operations, please read “Risk Factors” in Item 1A of Part I of this report.
Income (loss) available to common shareholders for the years ended December 31, 2021, 2020 and 2019 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Favorable (Unfavorable) |
| | 2021 | | 2020 | | 2019 (1) | | 2021 to 2020 | | 2020 to 2019 |
| | (in millions) |
Electric | | $ | 475 | | | $ | 230 | | | $ | 419 | | | $ | 245 | | | $ | (189) | |
Natural Gas | | 403 | | | 278 | | | 251 | | | 125 | | | 27 | |
Total Utility Operations | | 878 | | | 508 | | | 670 | | | 370 | | | (162) | |
| | | | | | | | | | |
Corporate & Other (2) | | (305) | | | (201) | | | (272) | | | (104) | | | 71 | |
Discontinued Operations | | 818 | | | (1,256) | | | 276 | | | 2,074 | | | (1,532) | |
Total CenterPoint Energy | | $ | 1,391 | | | $ | (949) | | | $ | 674 | | | $ | 2,340 | | | $ | (1,623) | |
(1)Includes only February 1, 2019 through December 31, 2019 results of acquired electric and natural gas businesses due to the Merger.
(2)Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to preferred shareholders.
2021 Compared to 20182020
Net Income. CenterPoint Energy reported income available to common shareholders of $674$1,391 million ($1.33 per diluted common share) for 20192021 compared to $333a loss available to common shareholders of $949 million ($0.74 per diluted common share) for 2018.2020.
The increase in income available to common shareholders of $341$2,340 million was primarily due to the following key factors:
a $395 million•an 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 expenseearnings from discontinued operations primarily related to lower outstanding balancesthe Enable Merger discussed further in Note 4 to the consolidated financial statements and the 2020 impairment in Enable discussed further in Notes 10 and 11 to the consolidated financial statements;
•goodwill impairment at Indiana Electric in 2020;
•the dividend requirement and amortization of the Securitization Bonds;beneficial conversion feature associated with Series C Preferred Stock in 2020; and
an $8 million decrease in•favorable income tax expense primarily due to the lower effective tax rate, as explained below,impacts in 2021, partially offset by higher income before income taxes.the CARES Act in 2020.
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 valuesale of the indexedEnergy Transfer Common Units and Energy Transfer Series G Preferred Units in 2021;
•make-whole premiums on debt securities related to the ZENS includedredeemed in Other Income (Expense), net shown above.
2021; and
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 reductionBoard-implemented governance changes announced in valuation allowances on certain stateJuly 2021.
Excluding those items, income available to common shareholders increased $191 million primarily due to the following key factors:
•rate relief, net operating losses that are now expected to be realized.of increases in depreciation and amortization and taxes other than income taxes;
•reduced impact of COVID-19;
2018•continued customer growth; and
•reduced interest expense.
2020 Compared to 20172019
Net Income. CenterPoint Energy reported a loss available to common shareholders of $949 million for 2020 compared to income available to common shareholders of $333$674 million ($0.74 per diluted common share) for 2018 compared to $1,792 million ($4.13 per diluted common share) for 2017.2019.
The decrease in income available to common shareholders of $1,459$1,623 million was primarily due to the following key factors:
an $875•a decrease in earnings from discontinued operations as a result of the 2020 impairment in Enable discussed further in Note 10 and 11 to the consolidated financial statements;
•goodwill impairment at Indiana Electric in 2020; and
•the dividend requirement and amortization of beneficial conversion feature associated with Series C Preferred Stock in 2020
These decreases were partially offset by the CARES Act in 2020.
Excluding those items, income available to common shareholders increased $115 million increase in income tax expense, resulting from a reduction in income tax expense of $1,113 millionprimarily due to the following key factors:
•rate relief, net of increases in depreciation and amortization and taxes other than income taxes;
•continued customer growth;
•operation and maintenance expense discipline; and
•the impact of twelve months in 2020 versus eleven months in 2019 for businesses acquired in the Merger.
These increases were partially offset by the impact of COVID-19.
Discontinued Operations. In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria. On December 2, 2021, Enable completed the previously announced Enable Merger pursuant to the Enable Merger Agreement entered into on February 16, 2021. CenterPoint Energy’s plan to exit its Midstream Investment reportable segment in 2022 represents a strategic shift to CenterPoint Energy. Therefore, the assets and liabilities associated with the equity investment in Enable are reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income, and the December 31, 2020 Consolidated Balance Sheet was required to be recast for assets held for sale. For further information, see 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 Infrastructure Services Disposal Group. Accordingly, the previously reported Infrastructure Services reportable segment has been eliminated. The transaction closed on April 9, 2020. For further information, see Note 4 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 the Energy Services Disposal Group. Accordingly, the previously reported Energy Services reportable segment has been eliminated. The transaction closed on June 1, 2020. For further information, see Note 4 to the consolidated financial statements.
Income Tax Expense. For a discussion of effective tax reform in 2017, discussed further inrate per period, see Note 15 to the consolidated financial statements, offset by a $238 million decreasestatements.
CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT
CenterPoint Energy’s CODM views net income as the measure of profit or loss for the reportable segments. Segment results include inter-segment interest income and expense, which may result in income tax expense primarily due to a reduction in the corporate income tax rate resulting from the TCJA in 2018inter-segment profit and lower income before income taxes year over year;loss.
a $305 million decrease in operating income, discussed belowThe following discussion of results of operations by reportable segment concentrates on CenterPoint Energy’s Utility Operations, conducted through two reportable segments, Electric and Natural Gas. CenterPoint Energy’s formerly reported Midstream Investments reportable segment results are now included in Results of Operations by Reportable Segment;
a $281 million increase in losses on indexed debt securities related todiscontinued operations. For additional information regarding 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 2018Midstream Investments reportable segment, see Notes 4, 10, 11 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 1118 to the consolidated financial statements;
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;
ELECTRIC
•
The following table provides summary data of CenterPoint Energy’s Electric reportable segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Favorable (Unfavorable) |
| 2021 | | 2020 | | 2019 (1) | | 2021 to 2020 | | 2020 to 2019 |
| (in millions, except throughput, weather and customer data) |
Revenues | $ | 3,763 | | | $ | 3,470 | | | $ | 3,519 | | | $ | 293 | | | $ | (49) | |
Cost of revenues (2) | 186 | | | 147 | | | 149 | | | (39) | | | 2 | |
Revenues less cost of revenues | 3,577 | | | 3,323 | | | 3,370 | | | 254 | | | (47) | |
Expenses: | | | | | | | | | |
Operation and maintenance | 1,780 | | | 1,697 | | | 1,649 | | | (83) | | | (48) | |
Depreciation and amortization | 756 | | | 670 | | | 746 | | | (86) | | | 76 | |
Taxes other than income taxes | 268 | | | 268 | | | 261 | | | — | | | (7) | |
Goodwill Impairment (3) | — | | | 185 | | | — | | | 185 | | | (185) | |
Total expenses | 2,804 | | | 2,820 | | | 2,656 | | | 16 | | | (164) | |
Operating Income | 773 | | | 503 | | | 714 | | | 270 | | | (211) | |
Other Income (Expense): | | | | | | | | | |
Interest and other finance charges | (226) | | | (220) | | | (225) | | | (6) | | | 5 | |
| | | | | | | | | |
Other income (expense), net | 23 | | | 19 | | | 26 | | | 4 | | | (7) | |
Income before income taxes | 570 | | | 302 | | | 515 | | | 268 | | | (213) | |
Income tax expense | 95 | | | 72 | | | 96 | | | (23) | | | 24 | |
Net income | $ | 475 | | | $ | 230 | | | $ | 419 | | | $ | 245 | | | $ | (189) | |
Throughput (in GWh): | | | | | | | | | |
Residential | 32,067 | | | 32,630 | | | 31,605 | | | (2) | % | | 3 | % |
Total | 103,000 | | | 98,647 | | | 96,866 | | | 4 | % | | 2 | % |
Weather (percentage of normal weather for service area): | | | | | | | | | |
Cooling degree days | 108 | % | | 109 | % | | 109 | % | | (1) | % | | — | % |
Heating degree days | 82 | % | | 76 | % | | 96 | % | | 6 | % | | (20) | % |
Number of metered customers at end of period: | | | | | | | | | |
Residential | 2,493,832 | | | 2,433,474 | | | 2,372,135 | | | 2 | % | | 3 | % |
Total | 2,814,859 | | | 2,749,116 | | | 2,682,228 | | | 2 | % | | 2 | % |
(1)an $18 million decrease in interest expenseIncludes only February 1, 2019 through December 31, 2019 results of acquired electric businesses due to the Merger.
(2)Includes Utility natural gas, fuel and purchased power.
(3)For information related to lower outstanding balances of the Securitization Bonds;2020 goodwill impairment at the Indiana Electric reporting unit, see Note 6 to the consolidated financial statements.
•
a $6 million increase in miscellaneous other non-operating
The following table provides variance explanations by major income included in Other Income (Expense), net shown above;statement caption for the Electric reportable segment:
| | | | | | | | | | | | | | |
| | Favorable (Unfavorable) |
| | 2021 to 2020 | | 2020 to 2019 |
| | (in millions) |
Revenues less Cost of revenues | | | | |
Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below | | $ | 254 | | | $ | 363 | |
Bond Companies, offset in other line items below | | 52 | | | (124) | |
Customer growth | | 32 | | | 37 | |
Impacts on usage from COVID-19 | | 28 | | | (40) | |
Energy efficiency, partially offset in operation and maintenance below | | 12 | | | 5 | |
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods | | 9 | | | (14) | |
Impacts from increased peak demand in the prior year, collected in rates in the current year | | 6 | | | 19 | |
Miscellaneous revenues, primarily related to service connections and off-system sales | | 4 | | | 11 | |
Pass-through revenues, offset in operation and maintenance below | | 2 | | | 2 | |
AMS, offset in depreciation and amortization below | | — | | | (3) | |
Twelve months in 2020 versus eleven months in 2019 for Indiana Electric due to Merger | | — | | | 34 | |
Refund of protected and unprotected EDIT, offset in income tax expense | | (8) | | | (31) | |
Weather, efficiency improvements and other usage impacts, excluding impact of COVID-19 | | (57) | | | (17) | |
Customer rates and impact of the change in rate design | | (80) | | | (289) | |
Total | | $ | 254 | | | $ | (47) | |
Operation and maintenance | | | | |
Transmission costs billed by transmission providers, offset in revenues less cost of revenues above | | $ | (90) | | | $ | (61) | |
All other operation and maintenance expense, including materials and supplies and insurance | | (8) | | | 14 | |
Pass through expenses, offset in revenues less cost of revenues above | | (3) | | | (2) | |
Bond Companies, offset in other line items | | (1) | | | 1 | |
Energy efficiency program costs | | (1) | | | — | |
Contract services | | — | | | 12 | |
Twelve months in 2020 versus eleven months in 2019 for Indiana Electric due to Merger | | — | | | (17) | |
| | | | |
Support services | | 1 | | | (13) | |
Labor and benefits | | 9 | | | (2) | |
Merger related expenses, primarily severance and technology | | 10 | | | 20 | |
Total | | $ | (83) | | | $ | (48) | |
Depreciation and amortization | | | | |
Bond Companies, offset in other line items | | $ | (58) | | | $ | 116 | |
Ongoing additions to plant-in-service | | (28) | | | (31) | |
AMS, offset by revenues less cost of revenues above | | — | | | (1) | |
Twelve months in 2020 versus eleven months in 2019 for Indiana Electric due to Merger | | — | | | (8) | |
Total | | $ | (86) | | | $ | 76 | |
Taxes other than income taxes | | | | |
Incremental capital projects placed in service | | $ | (2) | | | $ | (4) | |
Twelve months in 2020 versus eleven months in 2019 for Indiana Electric | | — | | | (1) | |
Franchise fees and other taxes | | 2 | | | (2) | |
Total | | $ | — | | | $ | (7) | |
Goodwill impairment | | | | |
See Note 6 for further information | | $ | 185 | | | $ | (185) | |
Total | | $ | 185 | | | $ | (185) | |
Interest expense and other finance charges | | | | |
Debt to fund incremental capital projects, and refinance maturing debt | | $ | (13) | | | $ | (5) | |
Twelve months in 2020 versus eleven months in 2019 for Indiana Electric due to Merger | | — | | | (2) | |
Bond Companies, offset in other line items above | | 7 | | | 12 | |
Total | | $ | (6) | | | $ | 5 | |
Other income (expense), net | | | | |
Reduction to non-service benefit cost | | $ | 5 | | | $ | 17 | |
Bond Companies, offset in other line items above | | — | | | (4) | |
Investments in CenterPoint Energy Money Pool interest income | | (1) | | | (20) | |
Total | | $ | 4 | | | $ | (7) | |
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 anFor a discussion of effective tax rate per period by Registrant, see Note 15 to the consolidated financial statements.
NATURAL GAS
The following table provides summary data of 28%CenterPoint Energy’s Natural Gas reportable segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Favorable (Unfavorable) |
| 2021 | | 2020 | | 2019 (1) | | 2021 to 2020 | | 2020 to 2019 |
| (in millions, except throughput, weather and customer data) |
Revenues | $ | 4,336 | | | $ | 3,631 | | | $ | 3,750 | | | $ | 705 | | | $ | (119) | |
Cost of revenues (2) | 1,959 | | | 1,358 | | | 1,652 | | | (601) | | | 294 | |
Revenues less Cost of revenues | 2,377 | | | 2,273 | | | 2,098 | | | 104 | | | 175 | |
Expenses: | | | | | | | | | |
Operation and maintenance | 1,004 | | | 1,013 | | | 1,051 | | | 9 | | | 38 | |
Depreciation and amortization | 502 | | | 473 | | | 439 | | | (29) | | | (34) | |
Taxes other than income taxes | 253 | | | 237 | | | 206 | | | (16) | | | (31) | |
Total expenses | 1,759 | | | 1,723 | | | 1,696 | | | (36) | | | (27) | |
Operating Income | 618 | | | 550 | | | 402 | | | 68 | | | 148 | |
Other Income (Expense) | | | | | | | | | |
Gain on sale | 8 | | | — | | | — | | | 8 | | | — | |
Interest expense and other finance charges | (141) | | | (153) | | | (144) | | | 12 | | | (9) | |
| | | | | | | | | |
Other income (expense), net | (2) | | | 6 | | | (5) | | | (8) | | | 11 | |
Income from Continuing Operations Before Income Taxes | 483 | | | 403 | | | 253 | | | 80 | | | 150 | |
Income tax expense | 80 | | | 125 | | | 2 | | | 45 | | | (123) | |
Net Income | $ | 403 | | | $ | 278 | | | $ | 251 | | | $ | 125 | | | $ | 27 | |
Throughput (in Bcf): | | | | | | | | | |
Residential | 241 | | | 237 | | | 246 | | | 2 | % | | (4) | % |
Commercial and industrial | 428 | | | 439 | | | 458 | | | (3) | % | | (4) | % |
Total Throughput | 669 | | | 676 | | | 704 | | | (1) | % | | (4) | % |
Weather (percentage of 10-year average for service area): | | | | | | | | | |
Heating degree days | 91 | % | | 91 | % | | 101 | % | | — | % | | (10) | % |
Number of customers at end of period: | | | | | | | | | |
Residential | 4,372,428 | | | 4,328,607 | | | 4,252,361 | | | 1 | % | | 2 | % |
Commercial and industrial | 354,602 | | | 349,725 | | | 349,749 | | | 1 | % | | — | % |
Total | 4,727,030 | | | 4,678,332 | | | 4,602,110 | | | 1 | % | | 2 | % |
(1)Includes only February 1, 2019 through December 31, 2019 results of acquired natural gas businesses due to the Merger.
(2)Includes Utility natural gas, fuel and (69)%purchased power and Non-utility cost of revenues, including natural gas.
The following table provides variance explanations by major income statement caption for the years ended December 31, 2018 and 2017, respectively. TheNatural Gas reportable segment:
| | | | | | | | | | | | | | |
| | Favorable (Unfavorable) |
| | 2021 to 2020 | | 2020 to 2019 |
| | (in millions) |
Revenues less Cost of revenues | | | | |
Customer rates and impact of the change in rate design, exclusive of the TCJA impact below | | $ | 65 | | | $ | 108 | |
Impacts of COVID-19, including usage and other miscellaneous charges | | 16 | | | (25) | |
Customer growth | | 13 | | | 20 | |
Gross receipts tax, offset in taxes other than income taxes below | | 13 | | | (6) | |
Weather and usage, excluding impacts from COVID-19 | | 12 | | | 4 | |
Twelve months in 2020 versus eleven months in 2019 in Indiana and Ohio jurisdictions | | — | | | 65 | |
Non-volumetric and miscellaneous revenue, excluding impacts from COVID-19 | | — | | | 15 | |
Energy efficiency, offset in operation and maintenance below | | (7) | | | (1) | |
Refund of protected and unprotected EDIT, offset in income tax expense | | (8) | | | (5) | |
Total | | $ | 104 | | | $ | 175 | |
Operation and maintenance | | | | |
Support services and miscellaneous operations and maintenance expenses | | $ | 16 | | | $ | (8) | |
Merger related expenses, primarily severance and technology | | 8 | | | 40 | |
Energy efficiency, offset in revenues less cost of revenues above | | 7 | | | 1 | |
| | | | |
Twelve months in 2020 versus eleven months in 2019 in Indiana and Ohio jurisdictions | | — | | | (14) | |
Contract services | | (3) | | | 20 | |
Labor and benefits, primarily due to headcount | | (19) | | | (1) | |
Total | | $ | 9 | | | $ | 38 | |
Depreciation and amortization | | | | |
Incremental capital projects placed in service | | $ | (29) | | | $ | (23) | |
Twelve months in 2020 versus eleven months in 2019 in Indiana and Ohio jurisdictions | | — | | | (11) | |
Total | | $ | (29) | | | $ | (34) | |
Taxes other than income taxes | | | | |
Gross receipts tax, offset in revenues less cost of revenues above | | $ | (13) | | | $ | 6 | |
Incremental capital projects placed in service | | (3) | | | (31) | |
Twelve months in 2020 versus eleven months in 2019 in Indiana and Ohio jurisdictions | | — | | | (6) | |
Total | | $ | (16) | | | $ | (31) | |
Gain on Sale | | | | |
Net gain on sale of MES | | $ | 8 | | | $ | — | |
Total | | $ | 8 | | | $ | — | |
Interest expense and other finance charges | | | | |
Reduced interest rates on outstanding borrowings, partially offset by incremental borrowings for capital expenditures and make-whole premium | | $ | 12 | | | $ | (9) | |
| | | | |
Total | | $ | 12 | | | $ | (9) | |
Other income (expense), net | | | | |
| | | | |
| | | | |
Other miscellaneous non-operating expenses, primarily due to non-service benefit cost | | $ | (10) | | | $ | 9 | |
Money pool investments with CenterPoint Energy interest income | | 2 | | | 2 | |
Total | | (8) | | | 11 | |
Income Tax Expense. For a discussion of effective tax rate of 28% is primarily dueper period by Registrant, see Note 15 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.consolidated financial statements.
HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS
Houston Electric’s CODM views net income as the measure of profit or loss for its reportable segment. Houston Electric consists of a single reportable segment. 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. For information regarding factors that may affect the future results of Houston Electric’s consolidated operations, please read “Risk Factors” in Item 1A of Part I of this report.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Favorable (Unfavorable) |
| 2021 | | 2020 | | 2019 | | 2021 to 2020 | | 2020 to 2019 |
| (in millions, except throughput, weather and customer data) |
Revenues: | | | | | | | | | |
TDU | $ | 2,894 | | | $ | 2,723 | | | $ | 2,678 | | | $ | 171 | | | $ | 45 | |
Bond Companies | 240 | | | 188 | | | 312 | | | 52 | | | (124) | |
Total revenues | 3,134 | | | 2,911 | | | 2,990 | | | 223 | | | (79) | |
Expenses: | | | | | | | | | |
Operation and maintenance, excluding Bond Companies | 1,591 | | | 1,517 | | | 1,470 | | | (74) | | | (47) | |
Depreciation and amortization, excluding Bond Companies | 429 | | | 405 | | | 377 | | | (24) | | | (28) | |
Taxes other than income taxes | 251 | | | 252 | | | 247 | | | 1 | | | (5) | |
Bond Companies | 219 | | | 161 | | | 278 | | | (58) | | | 117 | |
Total | 2,490 | | | 2,335 | | | 2,372 | | | (155) | | | 37 | |
Operating Income | 644 | | | 576 | | | 618 | | | 68 | | | (42) | |
Interest expense and other finance charges | (183) | | | (171) | | | (164) | | | (12) | | | (7) | |
Interest expense on Securitization Bonds | (21) | | | (28) | | | (39) | | | 7 | | | 11 | |
Other income, net | 17 | | | 10 | | | 21 | | | 7 | | | (11) | |
Income before income taxes | 457 | | | 387 | | | 436 | | | 70 | | | (49) | |
Income tax expense | 76 | | | 53 | | | 80 | | | (23) | | | 27 | |
Net income | $ | 381 | | | $ | 334 | | | $ | 356 | | | $ | 47 | | | $ | (22) | |
Throughput (in GWh): | | | | | | | | | |
Residential | 30,650 | | | 31,244 | | | 30,334 | | | (2) | % | | 3 | % |
Total | 96,898 | | | 93,768 | | | 92,180 | | | 3 | % | | 2 | % |
Weather (percentage of 10-year average for service area): | | | | | | | | | |
Cooling degree days | 109 | % | | 110 | % | | 106 | % | | (1) | % | | 4 | % |
Heating degree days | 80 | % | | 72 | % | | 96 | % | | 8 | % | | (24) | % |
Number of metered customers at end of period: | | | | | | | | | |
Residential | 2,359,168 | | | 2,303,315 | | | 2,243,188 | | | 2 | % | | 3 | % |
Total | 2,660,938 | | | 2,599,827 | | | 2,534,286 | | | 2 | % | | 3 | % |
|
| | | | | | | | | | | |
| 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.The following table provides variance explanations by major income statement caption for the Houston Electric reported net income of $356 million for 2019 compared to $336 million for 2018.T&D reportable segment:
| | | | | | | | | | | | | | |
| | Favorable (Unfavorable) |
| | 2021 to 2020 | | 2020 to 2019 |
| | (in millions) |
Revenues | | | | |
Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers | | $ | 254 | | | $ | 364 | |
Bond Companies, offset in other line items below | | 52 | | | (124) | |
Customer growth | | 31 | | | 35 | |
Impacts on usage from COVID-19 | | 19 | | | (31) | |
Energy efficiency, partially offset in operation and maintenance below | | 12 | | | 5 | |
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods | | 9 | | | (14) | |
Impacts from increased peak demand in the prior year, collected in rates in the current year | | 6 | | | 19 | |
AMS, offset in depreciation and amortization below | | — | | | (3) | |
Miscellaneous revenues | | (1) | | | 7 | |
Refund of protected and unprotected EDIT, offset in income tax expense | | (8) | | | (32) | |
Weather impacts and other usage | | (51) | | | (7) | |
Customer rates and impact of the change in rate design | | (100) | | | (298) | |
Total | | $ | 223 | | | $ | (79) | |
Operation and maintenance, excluding Bond Companies | | | | |
Transmission costs billed by transmission providers, offset in revenues above | | $ | (90) | | | $ | (61) | |
Contract services | | (3) | | | 6 | |
All other operation and maintenance expense, including materials and supplies and insurance | | (2) | | | 14 | |
Energy efficiency program costs, offset in revenues above | | (1) | | | — | |
Support services | | 2 | | | (6) | |
Merger related expenses, primarily severance and technology | | 9 | | | 2 | |
Labor and benefits | | 11 | | | (2) | |
| | | | |
| | | | |
Total | | $ | (74) | | | $ | (47) | |
Depreciation and amortization, excluding Bond Companies | | | | |
Ongoing additions to plant-in-service | | $ | (24) | | | $ | (31) | |
AMS, offset by revenues | | — | | | 3 | |
| | | | |
Total | | $ | (24) | | | $ | (28) | |
Taxes other than income taxes | | | | |
Franchise fees and other taxes | | $ | 4 | | | $ | (1) | |
Incremental capital projects placed in service | | (3) | | | (4) | |
Total | | $ | 1 | | | $ | (5) | |
Bond Companies expense | | | | |
Operations and maintenance and depreciation expense, offset by revenues above | | $ | (58) | | | $ | 117 | |
Total | | $ | (58) | | | $ | 117 | |
Interest expense and other finance charges | | | | |
Debt to fund incremental capital projects, and refinance maturing debt | | $ | (12) | | | $ | (7) | |
| | | | |
Total | | $ | (12) | | | $ | (7) | |
Interest expense on Securitization Bonds | | | | |
Lower outstanding principal balance, offset by revenues above | | $ | 7 | | | $ | 11 | |
Total | | $ | 7 | | | $ | 11 | |
Other income (expense), net | | | | |
Reduction to non-service benefit cost | | $ | 8 | | | $ | 13 | |
Bond Companies, offset by revenues above | | — | | | (4) | |
Investments in CenterPoint Energy Money Pool interest income | | (1) | | | (20) | |
Total | | $ | 7 | | | $ | (11) | |
| | | | |
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 anFor a discussion of 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 inper period, see 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.
statements.
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 CODM views net income as the measure of profit or loss for its reportable segment. CERC consists of a single reportable segment. 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.gas. 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.expense, CERC’s ability to collect receivables from customers and CERC’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of CERC’s consolidated operations, please read “Risk Factors” in Item 1A of Part I of this report.
|
| | | | | | | | | | | |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Favorable (Unfavorable) |
| 2021 | | 2020 | | 2019 | | 2021 to 2020 | | 2020 to 2019 |
| (in millions, except throughput, weather and customer data) |
Revenues | $ | 3,248 | | | $ | 2,763 | | | $ | 3,018 | | | $ | 485 | | | $ | (255) | |
Cost of Revenues (1) | 1,532 | | | 1,117 | | | 1,430 | | | (415) | | | 313 | |
Revenues less Cost of Revenues | 1,716 | | | 1,646 | | | 1,588 | | | 70 | | | 58 | |
Expenses: | | | | | | | | | |
Operation and maintenance | 790 | | | 798 | | | 824 | | | 8 | | | 26 | |
Depreciation and amortization | 326 | | | 304 | | | 293 | | | (22) | | | (11) | |
Taxes other than income taxes | 193 | | | 182 | | | 161 | | | (11) | | | (21) | |
Total expenses | 1,309 | | | 1,284 | | | 1,278 | | | (25) | | | (6) | |
Operating Income | 407 | | | 362 | | | 310 | | | 45 | | | 52 | |
Other Income (Expense) | | | | | | | | | |
Gain on sale | 11 | | | — | | | — | | | 11 | | | — | |
Interest expense and other finance charges | (103) | | | (111) | | | (116) | | | 8 | | | 5 | |
| | | | | | | | | |
Other income (expense), net | (10) | | | (7) | | | (8) | | | (3) | | | 1 | |
Income from Continuing Operations Before Income Taxes | 305 | | | 244 | | | 186 | | | 61 | | | 58 | |
Income tax expense (benefit) | 51 | | | 97 | | | (3) | | | 46 | | | (100) | |
Income From Continuing Operations | 254 | | | 147 | | | 189 | | | 107 | | | (42) | |
Income (Loss) from Discontinued Operations (net of tax expense (benefit) of $—, $(2), and $17, respectively) | — | | | (66) | | | 23 | | | 66 | | | (89) | |
Net Income | $ | 254 | | | $ | 81 | | | $ | 212 | | | $ | 173 | | | $ | (131) | |
Throughput (in BCF): | | | | | | | | | |
Residential | 173 | | | 167 | | | 188 | | | 4 | % | | (11) | % |
Commercial and industrial | 264 | | | 260 | | | 292 | | | 2 | % | | (11) | % |
Total Throughput | 437 | | | 427 | | | 480 | | | 2 | % | | (11) | % |
Weather (percentage of 10-year average for service area): | | | | | | | | | |
Heating degree days | 92 | % | | 91 | % | | 101 | % | | 1 | % | | (10) | % |
Number of customers at end of period: | | | | | | | | | |
Residential | 3,383,819 | | | 3,349,828 | | | 3,287,343 | | | 1 | % | | 2 | % |
Commercial and industrial | 264,843 | | | 260,400 | | | 260,872 | | | 2 | % | | — | % |
Total | 3,648,662 | | | 3,610,228 | | | 3,548,215 | | | 1 | % | | 2 | % |
2019 Compared to 2018(1)
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) | 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) | 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 theIncludes Utility 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 additionNon-utility cost 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.
including natural gas.
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.
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, respectively.
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:
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;
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.
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.
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.Discontinued Operations. 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 Disposal Group. Accordingly, the previously reported Energy Services reportable segment.segment has been eliminated. The transaction is expected to close in the second quarter ofclosed on June 1, 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 ServicesThe following table provides variance explanations by major income statement caption for CERC’s Natural Gas reportable segment. The transaction is expected to close in the second quartersegment:
| | | | | | | | | | | | | | |
| | Favorable (Unfavorable) |
| | 2021 to 2020 | | 2020 to 2019 |
| | (in millions) |
Revenues less Cost of revenues | | | | |
Customer rates and impact of the change in rate design, exclusive of the TCJA impact below | | $ | 31 | | | $ | 62 | |
Impacts on usage from COVID-19 | | 16 | | | (22) | |
Gross receipts tax, offset in taxes other than income taxes below | | 13 | | | (4) | |
Customer growth | | 9 | | | 14 | |
Weather and usage, excluding impacts from COVID-19 | | 8 | | | 2 | |
Energy efficiency, offset in operation and maintenance below | | 1 | | | (8) | |
Non-volumetric and miscellaneous revenue, excluding impacts from COVID-19 | | (1) | | | 18 | |
Refund of protected and unprotected EDIT, offset in income tax expense | | (7) | | | (4) | |
Total | | $ | 70 | | | $ | 58 | |
Operation and maintenance | | | | |
Merger related expenses, primarily severance and technology | | $ | 8 | | | $ | — | |
Support services and miscellaneous operations and maintenance expenses | | 8 | | | (2) | |
Contracted services | | 1 | | | 24 | |
Energy efficiency, offset in revenues less cost of revenues above | | (1) | | | 8 | |
| | | | |
Labor and benefits, primarily due to headcount | | (8) | | | (4) | |
Total | | $ | 8 | | | $ | 26 | |
Depreciation and amortization | | | | |
Incremental capital projects placed in service | | $ | (22) | | | $ | (11) | |
Total | | $ | (22) | | | $ | (11) | |
Taxes other than income taxes | | | | |
Gross receipts tax, offset in revenues less cost of revenues above | | $ | (13) | | | $ | 4 | |
Incremental capital projects placed in service | | 2 | | | (25) | |
Total | | $ | (11) | | | $ | (21) | |
Gain on Sale | | | | |
Net gain on sale of MES | | $ | 11 | | | $ | — | |
Total | | $ | 11 | | | $ | — | |
Interest expense and other finance charges | | | | |
Reduced interest rates on outstanding borrowings, partially offset by incremental borrowings for capital expenditures and make-whole premium | | $ | 8 | | | $ | 5 | |
Total | | $ | 8 | | | $ | 5 | |
Other income (expense), net | | | | |
| | | | |
| | | | |
Other miscellaneous non-operating expenses, primarily due to non-service benefit cost | | $ | (4) | | | $ | 6 | |
Money pool investments with CenterPoint Energy interest income | | 1 | | | (5) | |
Total | | $ | (3) | | | $ | 1 | |
Income Tax Expense. For a discussion of 2020. For further information,effective tax rate per period, see Notes 6 and 23Note 15 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, 20182021, 2020 and 20172019 is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC |
| (in millions) |
Cash provided by (used in): | | | | | | | | | | | | | | | | | |
Operating activities | $ | 22 | | | $ | 770 | | | $ | (1,440) | | | $ | 1,995 | | | $ | 899 | | | $ | 729 | | | $ | 1,638 | | | $ | 918 | | | $ | 466 | |
Investing activities | (1,851) | | | (1,617) | | | (859) | | | (1,265) | | | (564) | | | (452) | | | (8,421) | | | (1,495) | | | (662) | |
Financing activities | 1,916 | | | 926 | | | 2,306 | | | (834) | | | (416) | | | (278) | | | 2,776 | | | 442 | | | 173 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, |
| 2021 compared to 2020 | | 2020 compared to 2019 |
| CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC |
| (in millions) |
Changes in net income after adjusting for non-cash items | $ | 2,098 | | | $ | 203 | | | $ | 88 | | | $ | (1,785) | | | $ | (128) | | | $ | 9 | |
Changes in working capital | (155) | | | (101) | | | (274) | | | 811 | | | 61 | | | 355 | |
Increase in regulatory assets (1) | (2,188) | | | (226) | | | (1,927) | | | (85) | | | 37 | | | (128) | |
Change in equity in earnings of unconsolidated affiliates | (1,767) | | | — | | | — | | | 1,658 | | | — | | | — | |
Change in distributions from unconsolidated affiliates (2) (3) | 42 | | | — | | | — | | | (148) | | | — | | | — | |
| | | | | | | | | | | |
Higher pension contribution | 25 | | | — | | | — | | | 23 | | | — | | | — | |
Other | (28) | | | (5) | | | (56) | | | (117) | | | 11 | | | 27 | |
| $ | (1,973) | | | $ | (129) | | | $ | (2,169) | | | $ | 357 | | | $ | (19) | | | $ | 263 | |
(1)The increase in regulatory assets is primarily due to the incurred natural gas costs associated with the February 2021 Winter Storm Event. See Note 7 to the consolidated financial statements for more information on the February 2021 Winter Storm Event.
(2)In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria and is reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income. For further information, see Notes 4 and 11 to the consolidated financial statements.
(3)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.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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, |
| 2021 compared to 2020 | | 2020 compared to 2019 |
| CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC |
| (in millions) |
Proceeds from the sale of equity securities | $ | 1,320 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Acquisitions, net of cash acquired | — | | | — | | | — | | | 5,991 | | | — | | | — | |
Net change in capital expenditures | (568) | | | (561) | | | (80) | | | (90) | | | (33) | | | (39) | |
| | | | | | | | | | | |
Transaction costs related to the Enable Merger | (49) | | | — | | | — | | | — | | | — | | | — | |
Cash received related to Enable Merger | 5 | | | — | | | — | | | — | | | — | | | — | |
Net change in notes receivable from unconsolidated affiliates | — | | | (481) | | | 9 | | | — | | | 962 | | | (123) | |
Change in distributions from Enable in excess of cumulative earnings (1) | (80) | | | — | | | — | | | 38 | | | — | | | — | |
Proceeds from divestitures | (1,193) | | | — | | | (343) | | | 1,215 | | | — | | | 365 | |
| | | | | | | | | | | |
Other | (21) | | | (11) | | | 7 | | | 2 | | | 2 | | | 7 | |
| $ | (586) | | | $ | (1,053) | | | $ | (407) | | | $ | 7,156 | | | $ | 931 | | | $ | 210 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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)In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria and is reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income. For further information, see Notes 4 and 11 to the consolidated financial statements.
| |
(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, |
| 2021 compared to 2020 | | 2020 compared to 2019 |
| CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC |
| (in millions) |
Net changes in commercial paper outstanding | $ | 1,893 | | | $ | — | | | $ | 582 | | | $ | (2,652) | | | $ | — | | | $ | (197) | |
Proceeds from issuances of preferred stock, net | (723) | | | — | | | — | | | 723 | | | — | | | — | |
Proceeds from issuance of Common Stock, net | (672) | | | — | | | — | | | 672 | | | — | | | — | |
Net changes in long-term debt outstanding, excluding commercial paper | 2,450 | | | 415 | | | 1,481 | | | (2,539) | | | (170) | | | (93) | |
| | | | | | | | | | | |
Net changes in debt and equity issuance costs | (30) | | | (9) | | | (6) | | | 12 | | | 5 | | | (4) | |
Net changes in short-term borrowings | (27) | | | — | | | (27) | | | — | | | — | | | — | |
| | | | | | | | | | | |
Decreased payment of Common Stock dividends | 7 | | | — | | | — | | | 185 | | | — | | | — | |
Decreased (increased) payment of Preferred Stock dividends | 30 | | | — | | | — | | | (19) | | | — | | | — | |
Payment of obligation for finance lease | (179) | | | (179) | | | — | | | — | | | — | | | — | |
Net change in notes payable from affiliated companies | — | | | 496 | | | 224 | | | — | | | 9 | | | — | |
Contribution from parent | — | | | 68 | | | (37) | | | — | | | (528) | | | 88 | |
Dividend to parent | — | | | 551 | | | 80 | | | — | | | (175) | | | 40 | |
Capital contribution to parent associated with the sale of CES | — | | | — | | | 286 | | | — | | | — | | | (286) | |
Other | 1 | | | — | | | 1 | | | 8 | | | 1 | | | 1 | |
| $ | 2,750 | | | $ | 1,342 | | | $ | 2,584 | | | $ | (3,610) | | | $ | (858) | | | $ | (451) | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 Registrants expect that anticipated 2022 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 Energy Transfer or proceeds from future dispositions of Energy Transfer Common Units or Energy Transfer Series G Preferred Units, and, with respect to CERC, proceeds from any potential asset sales. 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.
Material Current and Long-term Cash Requirements. 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 20202022 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.
| | | | | | | | | | | | | | | | | | | | |
| | CenterPoint Energy | | Houston Electric | | CERC |
| | (in millions) |
Estimated capital expenditures | | $ | 3,490 | | | $ | 1,780 | | | $ | 1,233 | |
| | | | | | |
Scheduled principal payments on Securitization Bonds | | 220 | | | 220 | | | — | |
| | | | | | |
Maturing Houston Electric general mortgage bonds | | 300 | | | 300 | | | — | |
Finance lease for mobile generation | | 496 | | | 496 | | | — | |
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 20202022 through 2024: 2026. See Note 18 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 |
CenterPoint Energy | | | (in millions) |
| | | | | | | | | | | |
| | | | | | | | | | | |
Electric | | | $ | 2,052 | | | $ | 2,879 | | | $ | 2,281 | | | $ | 1,724 | | | $ | 2,683 | |
Natural Gas | | | 1,427 | | | 1,804 | | | 1,439 | | | 1,490 | | | 1,887 | |
Corporate and Other | | | 11 | | | 31 | | | 18 | | | 14 | | | 14 | |
| | | | | | | | | | | |
Total | | | $ | 3,490 | | | $ | 4,714 | | | $ | 3,738 | | | $ | 3,228 | | | $ | 4,584 | |
Houston Electric (1) | | | $ | 1,780 | | | $ | 2,172 | | | $ | 1,479 | | | $ | 1,429 | | | $ | 2,205 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
CERC (1) | | | $ | 1,233 | | | $ | 1,725 | | | $ | 1,360 | | | $ | 1,422 | | | $ | 1,807 | |
(1)Houston Electric and CERC each consist of a single reportable segment..
Capital Expenditures for Climate-Related Projects. On September 23, 2021, CenterPoint Energy announced a new 10-year capital expenditure plan. As part of its 10-year plan to spend over $40 billion on capital expenditures, CenterPoint Energy anticipates spending over $3 billion in clean energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 ofsummarizes the Registrants’ contractual obligationsmaterial current and long-term cash requirements as of December 31, 2019,2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total | | 2022 | | 2023-2024 | | 2025-2026 | | 2027 and thereafter |
| | (in millions) |
CenterPoint Energy | | | | | | | | | | |
Securitization Bonds | | $ | 537 | | | $ | 220 | | | $ | 317 | | | $ | — | | | $ | — | |
Other long-term debt (1) | | 15,549 | | | 308 | | | 6,082 | | | 911 | | | 8,248 | |
Interest payments — Securitization Bonds (2) | | 27 | | | 15 | | | 12 | | | — | | | — | |
Interest payments — other long-term debt (2) | | 6,386 | | | 445 | | | 834 | | | 761 | | | 4,346 | |
Short-term borrowings | | 7 | | | 7 | | | — | | | — | | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Finance lease for mobile generation | | 496 | | | 496 | | | — | | | — | | | — | |
Commodity and other commitments (3) | | 4,939 | | | 626 | | | 1,500 | | | 631 | | | 2,182 | |
| | | | | | | | | | |
Total cash requirements | | $ | 27,941 | | | $ | 2,117 | | | $ | 8,745 | | | $ | 2,303 | | | $ | 14,776 | |
| | | | | | | | | | |
Houston Electric | | | | | | | | | | |
Securitization Bonds | | $ | 537 | | | $ | 220 | | | $ | 317 | | | $ | — | | | $ | — | |
Other long-term debt (1) | | 4,958 | | | 300 | | | 200 | | | 300 | | | 4,158 | |
Interest payments — Securitization Bonds (2) | | 27 | | | 15 | | | 12 | | | — | | | — | |
Interest payments — other long-term debt (2) | | 3,615 | | | 188 | | | 351 | | | 340 | | | 2,736 | |
Finance lease for mobile generation | | 496 | | | 496 | | | — | | | — | | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Total cash requirements | | $ | 9,633 | | | $ | 1,219 | | | $ | 880 | | | $ | 640 | | | $ | 6,894 | |
| | | | | | | | | | |
| | | | | | | | | | |
CERC | | | | | | | | | | |
Long-term debt | | $ | 4,380 | | | $ | — | | | $ | 2,599 | | | $ | — | | | $ | 1,781 | |
Interest payments — long-term debt (1) | | 1,250 | | | 91 | | | 160 | | | 153 | | | 846 | |
Short-term borrowings | | 7 | | | 7 | | | — | | | — | | | — | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Commodity and other commitments (3) | | 2,486 | | | 322 | | | 500 | | | 382 | | | 1,282 | |
Total cash requirements | | $ | 8,123 | | | $ | 420 | | | $ | 3,259 | | | $ | 535 | | | $ | 3,909 | |
(1)ZENS obligations are included in the 2027 and thereafter column at their contingent principal amount of $38 million as of December 31, 2021. 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 ($820 million as of December 31, 2021), 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, 2021. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.
(3)For a discussion of commodity and other commitments, see Note 16(a) to the consolidated financial statements.
The table above does not include the following:
•estimated future payments for expected future AROs primarily estimated to be incurred after 2026. See Note 3(c) to the consolidated financial statements for further information.
•expected contributions to pension plans and other postretirement plans in 2022. See Note 8(g) to the consolidated financial statements for further information.
•operating leases. See Note 21 to the consolidated financial statements for further information.
February 2021 Winter Storm Event. In February 2021, portions of the United States experienced an extreme and unprecedented winter weather event resulting in corresponding electricity generation shortages, including payments due by period:in Texas, and natural gas shortages and increased prices of natural gas in the United States. Although CenterPoint Energy’s and CERC’s extraordinary costs from the increase in natural gas prices are subject to available natural gas cost recovery mechanisms in their jurisdictions (although timing of recovery is uncertain), until such amounts are ultimately recovered from customers, CenterPoint Energy and CERC will continue to incur increased finance-related costs, resulting in a significant use of cash. See “— Regulatory Matters — February 2021 Winter Storm Event” below and Note 7 to the consolidated financial statements.
|
| | | | | | | | | | | | | | | | | | | | |
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 ArrangementsArrangements.
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 operatingshort-term leases, the Registrants have no off-balance sheet arrangements.
Regulatory Matters
HoustonCOVID-19 Regulatory Matters
For information about COVID-19 regulatory matters, see Note 7 to the consolidated financial statements.
February 2021 Winter Storm Event
For information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements, and for additional information on the Texas electric market, see “Risk Factors — Risk Factors Affecting Electric Generation, Transmission and Distribution Business — In connection with the February...”
The table below presents the incremental natural gas costs included in regulatory assets as of December 31, 2021 by state as a result of the February 2021 Winter Storm Event and CenterPoint Energy’s and CERC’s requested recovery status as of February 2022.
| | | | | | | | | | | | | | | | | | | | |
State | | Recovery Status | | Legislative Activity | | Incremental Gas Cost in Regulatory Assets (in millions) |
Arkansas and Oklahoma | | On January 10, 2022, CERC Corp., completed the sale of its Arkansas and Oklahoma Natural Gas businesses For additional information, see Note 4 to the consolidated financial statements. | | | | $ | 398 | |
Louisiana | | Filed application on April 16, 2021 for North Louisiana to recover over a three-year period beginning May 1, 2021. LPSC approved on April 22, 2021. | | None. | | 67 |
Minnesota | | Filed application on March 15, 2021 requesting to recover over a two-year period beginning May 1, 2021. Modified request and worked with other utilities to propose common definition of extraordinary gas costs to be recovered over a 27-month period starting September 1, 2021 using volumetric, seasonally adjusted, and stepped surcharge rates. MPUC issued order approving modified cost recovery subject to a prudence review. The prudence review schedule has testimonies being filed by parties October 2021 through February 2022, a hearing scheduled in February 2022, an administrative law judge report in May 2022 and MPUC final order issued by August 2022. On December 30, 2021, as part of CERC’s alternative request filed in tandem with its general rate case initial filing, the MPUC ordered the amortization period for extraordinary gas cost recovery be extended from a 27-month period to a 63-month period beginning on January 1, 2022. | | None. | | 379 |
Mississippi | | Recovery began in September 2021 through normal gas cost recovery. | | None. | | 2 |
| | | | | | | | | | | | | | | | | | | | |
State | | Recovery Status | | Legislative Activity | | Incremental Gas Cost in Regulatory Assets (in millions) |
Texas | | Securitization application was filed on July 30, 2021. Intervenor and staff testimony was received in September and October and CERC filed rebuttal testimony on October 25, 2021. A joint notice of settlement was filed by the Texas utilities that are requesting securitization, intervenors, and Railroad Commission staff on October 29, 2021. The settlement resolves all contested issues and includes an agreement by all signatories that the costs incurred by the utilities to purchase natural gas volumes during February 2021 are reasonable and necessary and were prudently incurred. As part of the settlement, CERC agreed to limit the interim carrying cost rate to its actual interim financing rate of 0.7%. A merits hearing was held on November 2, 2021. On November 10, 2021, the RRC approved the settlement and the regulatory asset amount to be securitized. On February 8, 2022, the RRC issued a financing order. The Texas Public Finance Authority will have approximately 180 days to issue customer rate relief bonds to recover natural gas costs from the February 2021 Winter Storm Event. | | A securitization bill has been signed by the Texas governor which authorizes the Railroad Commission to use securitization financing and issuance of customer rate relief bonds for recovery of extraordinary gas costs. | | 1,073 | |
| | | | Total CERC | | $ | 1,919 | |
Indiana North | | IURC issued order August 25, 2021. Recovery began September 2021 with 50% of the February 2021 variance recovered evenly over the 12‐month period September 2021 to August 2022, with the remainder of the variance recovered through a volumetric per‐therm allocation over the same 12-month period. | | None. | | 63 |
Indiana South | | IURC issued order July 28, 2021. Recovery began August 2021 with 50% of the February 2021 variance recovered evenly over the 12‐month period August 2021 to July 2022, with the remainder of the variance recovered through a volumetric per‐therm allocation over the same 12-month period. | | None. | | 11 |
| | | | Total CenterPoint Energy | | $ | 1,993 | |
| | | | | | |
Indiana Electric CPCN (CenterPoint Energy)
On February 9, 2021, Indiana Electric entered into a BTA with a subsidiary of Capital Dynamics. Under the agreement, Capital Dynamics, with its partner Tenaska, contracted to build a 300 MW solar array in Posey County, Indiana through a special purpose entity, Posey Solar. Upon completion of construction, which is projected to be at the end of 2023. Indiana Electric will acquire Posey Solar and its solar array assets for a fixed purchase price. On February 23, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to purchase the project. Indiana Electric also sought approval for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. A hearing was conducted on June 21, 2021. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing Indiana Electric to purchase the Posey solar project through a BTA and approved recovery of costs via a levelized rate over the anticipated 35-year life. The IURC also approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. The Posey solar project is expected to be in service by 2023. Due to rising cost for the project, caused in part by supply chain issues in the energy industry and the rising costs of commodities, we, along with Capital Dynamics, recently announced plans to downsize the project to approximately 200 MW. Indiana Electric collaboratively agreed to the scope change and is currently working through contract negotiations, contingent on further IURC review and approval.
On June 17, 2021 Indiana Electric filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. Indiana Electric has also requested depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana South’s base rates include a return on and recovery of depreciation expense on the facility. A hearing was conducted on January 26 through 28, 2022. The estimated $334 million turbine facility would be constructed at the current site of the A.B. Brown power plant in Posey County, Indiana and would provide a combined output of 460 MW. Construction of the turbines will begin following receipt of necessary regulatory approvals by the IURC and FERC, which are anticipated in the second half of 2022 and first quarter 2023, respectively. The turbines are targeted to be operational in first quarter of 2025. Subject to IURC approval, recovery of the
proposed natural gas combustion turbines and regulatory asset will be requested in the next Indiana Electric rate case expected in 2023.
On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden LLC, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis Energy USA Inc., which is developing a solar project in Knox County, Indiana. Subject to necessary approvals, both solar arrays are expected to be in service by 2023.
Indiana Electric Securitization of Planned Generation Retirements (CenterPoint Energy)
The State of Indiana has enacted legislation, Senate Bill 386, that would enable CenterPoint Energy to request approval from the IURC to securitize the remaining book value and removal costs associated with generating facilities to be retired in the next twenty-four months. The Governor of Indiana signed the legislation on April 19, 2021. CenterPoint Energy intends to seek securitization in the future associated with planned retirements of coal generation facilities in 2022.
Subsidiary Restructuring
In July 2021, Indiana North and SIGECO filed petitions with the IURC for the approval of a new financial services agreement and the confirmation of Indiana North’s financing authority, and final orders were issued by the IURC on December 28, 2021. VEDO filed a similar application with the PUCO in September 2021 and the PUCO issued an order on January 26, 2022 adopting recommendations by PUCO staff. CenterPoint Energy is evaluating the transfer of Indiana North and VEDO from VUHI to CERC in order to better align its organizational structure with management and financial reporting. Both the IURC and PUCO have approved the transaction. As a part of the restructuring, VUHI may approach certain of its debt holders with an offer to exchange existing VUHI debt for CERC debt. The orders allow the reissuance of existing debt of Indiana North and VEDO to CERC, to continue to amortize existing issuance expenses and discounts, and to treat any potential exchange fees as discounts to be amortized over the life of the debt. If CenterPoint Energy moves forward with the restructuring, including any VUHI debt exchanges, it is expected to be completed in 2022.
Indiana South Base Rate Case (CenterPoint Energy and Houston Electric)Energy)
On April 5, 2019,October 30, 2020, and as subsequently adjusted in errata filings in May and June 2019, Houston Electricamended, Indiana South filed its base rate applicationcase with the PUCT and the cities in its service area to change its rates,IURC seeking approval for a revenue increasesincrease of approximately $194 million, excluding a rider to refund approximately $40 million annually over three years discussed below.$29 million. This rate case filing is required under Indiana TDSIC statutory requirements before the completion of Indiana South’s capital expenditure program, approved in 2014 for investments starting in 2014 through 2020. The revenue increase is based upon a requested ROE of 10.15% and an overall after-tax rate of return of 5.99% on atotal rate base of $6.4 billion,approximately $469 million. Indiana South has utilized 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 aprojected test year, ending December 31, 2009. Houston Electric alsoreflecting its 2021 budget as the basis for the revenue increase requested a prudency determination on all capital investments made since January 1, 2010, the establishment of a riderand proposes to refund over three years to its customers approximately $119 million of unprotected EDIT resulting from the TCJA, updated depreciationimplement 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.
in two phases. 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 JanuaryApril 23, 2020, Houston Electric filed2021, a Stipulation and Settlement Agreement was filed resolving all issues in the case. The settlement recommended a revenue increase of $21 million based on a 9.7% ROE and an overall after-tax rate of return of 5.78% on total rate base of approximately $469 million. A settlement hearing was held on June 24, 2021. On October 6, 2021, the IURC issued an order approving the settlement. Phase one rates, reflecting actual plant-in-service and cost of capital through June 2021, became effective in October 2021 and phase two rates, reflecting actual plant-in-service and cost of capital through December 2021 with certain adjustments, will become effective in March 2022.
Indiana North Base Rate Case (CenterPoint Energy)
On December 18, 2020, Indiana North filed its base rate case with the PUCT that providesIURC seeking approval for the following, among other things:
an overalla revenue requirement increase of approximately $13 million;
an$21 million. This rate case filing is required under Indiana TDSIC statutory requirements before the completion of Indiana North’s capital expenditure program, approved in 2014 for investments starting in 2014 through 2020. The revenue increase is based upon a requested ROE of 9.4%;
a capital structure10.15% and an overall after-tax rate of 57.5% debt/42.5% equity;
a refundreturn 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. No6.32% on total rate base items are requiredof approximately $1,611 million. Indiana North has utilized a projected test year, reflecting its 2021 budget as the basis for the revenue increase requested and proposes to be written off; however, approximately $12 millionimplement rates 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 filetwo phases. On June 25, 2021, 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 withwas filed resolving 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 resultissues in the case. The settlement recommended a revenue decrease of $6 million based on a 9.8% ROE and an overall after-tax rate of return of 6.16% on total rate base of approximately $1,611 million. A settlement hearing was held August 6, 2021. On November 17, 2021, the IURC issued an order being issued afterapproving the first quarter of 2020. Thesettlement.Phase one rates, are expected to be implemented 45 days after the final order is issued.
CenterPoint Energyreflecting actual plant-in-service and Houston Electric record pre-tax expense for (i) probable disallowancescost of capital investmentsthrough June 2021, became effective in November 2021 and (ii) customer refund obligationsphase two rates, reflecting actual plant-in-service and costs deferred in regulatory assets when the amounts are no longer considered probablecost of recovery.
Brazos Valley Connection Project (CenterPoint Energy and Houston Electric)
Houston Electric completed construction on and energized the Brazos Valley Connectioncapital through December 2021 with certain adjustments, will become effective 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.2022.
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 Freeport Area Master Plan, which included the Bailey to Jones Creek Project. On December 12, 2017,November 21, 2019, the PUCT issued its final approval of Houston Electric received approval from ERCOT. In September 2018, Houston Electric filed aElectric’s 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 dependbased 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. Anan 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 beginningin 2019, began construction in early 2021, and energizingcompleted construction and energized the line ahead of schedule in earlyNovember 2021.Certain residual clean-up activities will continue in 2022.
Indiana Electric GenerationSpace City Solar Transmission Interconnection Project (CenterPoint Energy)Energy and Houston Electric)
Indiana Electric must make substantial investments in its generation resources in the near term to comply with environmental regulations. On February 20, 2018, IndianaDecember 17, 2020, Houston Electric filed a petition seeking authorizationCCN application with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. Depending on the route ultimately approved by the PUCT, the estimated capital cost of the transmission line project ranges from approximately $23 million to $71 million. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors in addition to route selection. In January 2021, Houston Electric executed a Standard Generation Interconnection Agreement for the Space City Solar Generation facility with EDF Renewables, which also provided security for the transmission line project in the form of a $23 million letter of credit, the amount of which is subject to change depending on the route approved. A hearing at the PUCT was held on June 28, 2021. On September 1, 2021, the administrative law judge issued a proposal for decision recommending a route that costs $25 million. The PUCT approved the proposal for decision at the November 18, 2021 open meeting and issued a final order on January 12, 2022. Houston Electric expects to complete construction and energization of the transmission line by the end of 2022.
Texas Legislation (CenterPoint Energy and Houston Electric)
In addition to the legislative activity discussed above, the Texas legislature enacted the following in 2021:
•Senate Bill 2 reforms the ERCOT board to be comprised of a total of eleven directors: three ex officio representatives, and eight members who are unaffiliated with any market participants. The three ex officio directors—the ERCOT CEO, the Public Counsel of the Office of Public Utility Counsel, and the PUCT Chair—serve on the board by virtue of their official position for as long as they hold that position. Two members are non-voting directors: the ERCOT CEO and the PUCT Chair. The other nine members are voting directors. The ERCOT board is currently comprised of the following members: Mr. Paul Foster (Chairman of ERCOT board), Mr. William Flores (Vice Chairman of ERCOT board), Mr. Carlos Aguilar, Mr. Zin Smati, Mr. John Swainson, Mr. Robert Flexon, Ms. Julie England, Ms. Peggy Heeg, Mr. Peter Lake (PUCT Chairman), Mr. Brad Jones (ERCOT Interim President & CEO), and Mr. Chris Ekoh (Public Counsel of the Office of Public Utility Counsel).
•Senate Bill 3 establishes weatherization and other power grid requirements including the design and operation of a load management program for nonresidential customers during an energy emergency activation level 2 or higher event and the ability to recover the reasonable and necessary costs of the program.
•Senate Bill 415 allows a TDU to seek prior PUCT approval to contract with a power generation company for a PUCT assigned proportional share of electric energy storage system at the distribution level and recover certain costs and a reasonable return on contract payments if contract terms satisfy relevant accounting standards for a capital lease or finance lease.
•House Bill 2483 allows a TDU to procure, own and operate, or jointly own with another TDU, transmission and distribution facilities with a lead time of at least six months that would aid in restoring power to the utility's distribution customers following a widespread outage, excluding storage equipment or facilities. Reasonable and necessary costs can be recovered using the rate of return on investment from the IURCmost recent base rate proceeding. Recovery of incremental operation and maintenance expenses and any return not recovered in a rate proceeding can be deferred until a future ratemaking proceeding. Additionally, a TDU may lease and operate facilities that provide temporary emergency electric energy to aid in restoring power to the utility’s distribution customers during a widespread power outage. Leasing and operating costs can be recovered using the utility’s rate of return from the most recent base rate proceeding and incremental operation and maintenance expenses can be deferred. The lease must be treated as a capital lease or finance lease for ratemaking purposes.
•Senate Bill 1281 removes the requirement for an electric utility to amend its CCN to construct a new 700-850transmission line that connects existing transmission facilities to a substation or metering point if certain conditions are met and adds a customer benefit test into consideration. The bill also requires ERCOT to conduct biennial assessments of grid reliability in extreme weather scenarios.
Houston Electric continues to review the effects of the legislation and is working with the PUCT regarding proposed rulemakings and pursuing implementation of these items where applicable. For example, in 2021 Houston Electric entered into two leases for mobile generation: (1) a temporary short-term lease initially for 125 MW that expanded to 220 MW by December 31, 2021 and (2) a 7.5 year lease for up to 505 MW of mobile generation of which 125 MW was delivered as of December 31, 2021. As of December 31, 2021, CenterPoint Energy and Houston Electric intends to seek recovery in its DCRF of deferred costs and the applicable return under these lease agreements, approximating $200 million. These mobile generation leases will support resiliency in major weather events and were deployed during the restoration process for Hurricane Nicholas. See Note 21 to the consolidated financial statements.
In addition to these measures taken by Houston Electric to support system preparedness and reliability, the City of Houston recently launched the first-of-its-kind long-term strategic power resilience initiative called “Resilient Now.” In a joint effort, Houston Electric is working with the City of Houston to develop the Master Energy Plan for the city to help the community thrive through economic changes, digital transformation, and advancing environmental goals for the benefit of its communities. The Master Energy Plan could develop into capital opportunities for Houston Electric, including relating to infrastructure modernization, residential weatherization, and investments around electric vehicles infrastructure.
Minnesota Base Rate Cases (CenterPoint Energy and CERC)
On October 28, 2019, CERC filed a general rate case with the MPUC seeking approval for a revenue increase of approximately $62 million with a projected test year ended December 31, 2020. The revenue increase is based upon a requested ROE of 10.15% and an overall after-tax rate of return of 7.41% on a total rate base of approximately $1,307 million. CERC implemented interim rates reflecting $53 million for natural gas combined cycle generating facility to replaceused on and after January 1, 2020. In September 2020, a settlement that addressed all issues except the baseload capacityInclusive Financing/TOB Financing proposal by the City of its existing generation fleet atMinneapolis was signed by a majority of all parties and was filed with the Office of Administrative Hearings. A stipulation between the City of Minneapolis and CERC addressing the TOB proposal was filed on September 2, 2020. The settlement reflects a $39 million increase and was based on an approximateoverall after-tax rate of return of 6.86% and does not specify individual cost of $900 million, which includescapital components. On March 1, 2021, the cost ofMPUC issued 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 anwritten final order approving the environmental investments proposed for$39 million increase and rejected the F.B. Culley generating facility, along with recovery of prior pollution control investments made in 2014.TOB stipulation. The order deniedalso required CERC and the proposed gas combined cycle generating facility. Indiana Electric is conductingCity of Minneapolis to submit a new IRP, expectedfuture filing to be completedallow for further development of a potential TOB pilot program and additional or expanded low-income conservation improvement programs. A compliance filing was submitted on March 12, 2021 proposing a final rate implementation on June 1, 2021 and the interim refund occurring in mid-2020,June 2021, contingent on final MPUC approval. Pursuant to identify an appropriate investment of capital in its generation fleetMPUC approval, final rates were implemented on June 1, 2021 and the interim rate refunds were applied to satisfy the needs of its customers and comply with environmental regulations.customer accounts starting on June 12, 2021.
Indiana Electric Solar Project (CenterPoint Energy)
On February 20, 2018, Indiana Electric announced it was finalizing details to install an additional 50 MWNovember 1, 2021, CERC filed a general rate case with the MPUC seeking approval for a revenue increase of universal solar energy, consistent with its IRP,approximately $67 million with a petition seeking authority to recover costs associated withprojected test year ended December 31, 2022. The revenue increase is based upon a requested ROE of 10.2% and an overall rate of return of 7.06% on a total rate base of approximately $1.8 billion. CERC requested that an interim rate increase of approximately $52 million be implemented January 1, 2022 while the project pursuant to Indiana Senate Bill 29. Indiana Electricrate case is litigated. An alternative request was also filed on November 1, 2021. The alternative request proposed a settlement agreement with the intervening parties whereby the energy produced by the solar farmfinal rate increase of $40 million that would be set at a fixed marketimplemented in the 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, andcase on January 29, 20201, 2022, and offered: an increase in rates for plant investment only using the IURCoverall rate of return approved in 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, forprior rate case, an asymmetrical capital true-up, extension of the recovery of gas costs associatedincurred to serve customers in February 2021 from the then current 27 month mechanism to 63 months, an income tax rider, continuation of the existing property tax rider and continued deferral of COVID-19 incremental costs along with additional adjustments. On December 30, 2021, the MPUC issued a written order denying the alternative request but extended the amortization period for extraordinary gas costs to 63-months beginning on January 1, 2022. The MPUC also issued written orders on the general rate case filing which (1) accepted CERC’s rate-increase application with a time for final determination of September 1, 2022, (2) authorized the implementation of interim rates on January 1, 2022, of $42 million based on an overall rate of return of 6.46%, and (3) referred the case to the Office of Administrative Hearings for a contested case proceeding. A procedural schedule has been set with intervenor testimony that was due on February 7, 2022, rebuttal testimony due on March 7, 2022, surrebuttal testimony due March 30, 2022, a hearing scheduled April 6, 2022 through April 8, 2022, the administrative law judge to issue a report on July 12, 2022 and the MPUC to issue an order in October 2022.
Minnesota Legislation (CenterPoint Energy and CERC)
The Natural Gas Innovation Act was passed by the Minnesota legislature in June 2021 with bipartisan support. This law establishes a regulatory framework to enable the state’s investor-owned natural gas utilities to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing greenhouse gas emissions and advancing the
state’s clean closureenergy future. Specifically, the Natural Gas Innovation Act allows a natural gas utility to submit an innovation plan for approval by the MPUC which could propose the use of renewable energy resources and innovative technologies such as:
•renewable natural gas (produces energy from organic materials such as wastewater, agricultural manure, food waste, agricultural or forest waste);
•renewable hydrogen gas (produces energy from water through electrolysis with renewable electricity such as solar);
•energy efficiency measures (avoids energy consumption in excess of the A.B. Brown ash pond pursuantutility’s existing conservation programs); and
•innovative technologies (reduces or avoids greenhouse gas emissions using technologies such as carbon capture).
CERC expects to Indiana Senate Bill 251. This project, expectedsubmit its first innovation plan to last approximately 14 years, would resultthe MPUC in 2022. The maximum allowable cost for an innovation plan will start at 1.75% of the utility's revenue in the full excavationstate and recycling ofcould increase to 4% by 2033, subject to review and approval by 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 theMPUC.
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)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 insince the Registrants’ combined 2020 forForm 10-K was filed with the Registrants.SEC.
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Mechanism | | Annual Increase (Decrease) (1) (in millions) | | Filing Date
| | Effective Date | | Approval Date | | Additional Information |
CenterPoint Energy and Houston Electric (PUCT) |
Rate Case TCOS(1)
| | $15564 | | April
2019 February 2022 | | TBD | | TBD | | See discussion above under Based on net change of invested capital of $574 million.Houston Electric Base Rate Case.
|
EECRFTCOS | | 719 | | May
2019 August 2021 | | March
2020 October 2021 | | October 20192021 | | Based on net change of invested capital of $166 million. |
EECRF | | 22 | | June 2021 | | March 2022 | | November 2021 | | The PUCT issued a final order in October 2019 approving recoveryrequested $63 million is comprised of the following: 2022 Program and Evaluation, Measurement and Verification costs of $38 million, 2020 EECRFunder-recovery of $35$3 million including a $7interest, and 2020 earned bonus of $22 million. A settlement was filed in September 2021 reducing the amount requested by $315 thousand and recommending 2022 Program and Evaluation, Measurement and Verification costs of $38 million, performance bonus.2020 under-recovery of $3 million including interest, and 2020 earned bonus of $22 million. |
TCOS | | 9 | | March 2021 | | April 2021 | | April 2021 | | Based on net change in invested capital of $80 million. |
CenterPoint Energy and CERC - Arkansas (APSC) |
FRP | | (10) | | April 2021 | | October 2021 | | September 2021 | | Based on ROE of 9.50% with 50 basis point (+/-) earnings band. Revenue decrease of $10.4 million based on prior test year true-up earned return on equity of 11.53%. The initial term of Rider FRP was terminated in September 2021. A petition for rehearing was filed on October 8, 2021. On October 14, 2021, as part of the settlement filed in the asset sale docket, CERC filed a motion to hold the petition for rehearing in abeyance pending closing of the asset sale. The APSC issued an order on October 15, 2021 granting the motion. Additionally, a request to extend the Rider FRP term for an additional five years was filed on May 5, 2021. On October 19, 2021, as part of the settlement filed in the asset sale docket, CERC filed a motion to hold this proceeding in abeyance and the APSC granted the motion on October 21, 2021. |
CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission) |
GRIP | | 2028 | | March 2019 2021 | | July
2019 June 2021 | | June 2019
2021 | | Based on net change in invested capital of $123$197 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%. |
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Mechanism | | Annual Increase (Decrease) (1) (in millions) | | Filing Date
| | Effective Date | | Approval Date | | Additional Information |
CenterPoint Energy and CERC - Louisiana (LPSC) |
RSP | | 7 | | September 2021 | | December 2021 | | December 2021 | | Based on authorized ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana decrease, with certain non-recurring true-up adjustments outside the earnings band, is a decrease of $1 million based on a test year ended June 2021 and adjusted earned ROE of 15.17%. The South Louisiana increase, with certain non-recurring true-up adjustments outside the earnings band, is an increase of $8 million based on a test year ended June 2021 and adjusted earned ROE of 1.93%. Per the 2020 RSP order, a request to extend the RSP for an additional three year term was filed in July 2021 and a hearing is scheduled for May 2022. |
CenterPoint Energy and CERC - Minnesota (MPUC) |
Rate Case (1) | | 67 | | November 2021 | | TBD | | TBD | | See discussion above under Minnesota Base Rate Case. |
Decoupling (1) | | N/A | | September 2021 | | September 2021 | | TBD | | Represents under-recovery of approximately $19 million recorded for and during the period July 1, 2020 through June 30, 2021, including an approximately $5 million adjustment related to the implementation of final rates from the general rate case filed in 2019. |
CIP Financial Incentive | | 10 | | May 2021 | | December 2021 | | October 2021 | | CIP Financial Incentive based on 2020 activity. |
Decoupling | | N/A | | September 2020 | | September 2020 | | March 2021 | | Represents under-recovery of approximately $2 million recorded for and during the period July 1, 2019 through June 30, 2020, including approximately $1 million related to the period July 1, 2018 through June 30, 2019. |
Rate Case | | 39 | | October 2019 | | June 2021 | | March 2021 | | See discussion above under Minnesota Base Rate Case. |
CenterPoint Energy and CERC - Mississippi (MPSC) |
RRA | | 3 | | April 2021 | | September 2021 | | September 2021 | | Based on ROE of 9.81% with 100 basis point (+/-) earnings band. Revenue increase of approximately $3 million based on 2020 test year adjusted earned ROE of 7.49%. |
CenterPoint Energy and CERC - Oklahoma (OCC) |
PBRC | | 2(1) | | March 2019 2021 | | September 2019August 2021 | | August 20192021 | | Based on ROE of 10% with 50 basis point (+/-) earnings band. Revenue credit of approximately $1 million based on 2020 test year adjusted earned ROE of 12.42%. OnA settlement was filed in June 2021 with a hearing held on July 26, 2019, the ALJ recommended that the OCC approve an increase of $2 million. On August 29, 2019, the1, 2021. OCC approved the ALJ-recommended revenue increasecredit of $2 million.approximately $1 million on August 6, 2021. |
CenterPoint Energy - Indiana South - Gas (IURC) |
CSIA | | 3(1) | | October
2018 April 2021 | | January
2019 July 2021 | | January
2019 July 2021 | | Requested an increase of $16$11 million to rate base, which reflects a $3 million$(1 million) annual increasedecrease 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 ano change of $(1) million,to the previous credit provided, and a change in the total (over)/under-recovery variance of $(3)less than $1 million annually. |
CSIARate Case | | 521 | | October 2020 | | October 2021 | | October 2021 | | AprilSee discussion above under Indiana South Base Rate Case.
|
CenterPoint Energy - Indiana North - Gas (IURC) |
2019CSIA
| | July
2019 5 | | July
2019 April 2021 | | July 2021 | | July 2021 | | Requested an increase of $22$37 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$6 million annually. |
CSIARate Case | | 321 | | October 2019December 2020 | | JanuaryNovember 2021 | | November 2021 | | See discussion above under Indiana North Base Rate Case. |
CenterPoint Energy - Ohio (PUCO) |
| | | | | | | | | | |
DRR | | 9 | | April 2021 | | September 2021 | | September 2021 | | Requested an increase of $71 million to rate base for investments made in 2020, which reflects a $9 million annual increase in current revenues. A change in (over)/under-recovery variance of $5 million annually is also included in rates. |
| | January 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mechanism | | Annual Increase (Decrease) (1) (in millions) | | Filing Date | | Effective Date | | Approval Date | | Additional Information |
CenterPoint Energy - Indiana Electric (IURC) |
TDSIC (1) | | 3 | | February 2022 | | TBD | | TBD | | Requested an increase of $18$42 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. |
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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.less than $1 million. |
TDSIC CECA(1)
| | 4(2) | | February 20202022 | | May
2020 TBD | | TBD | | Requested an increasea decrease of $34less than $1 million to rate base, which reflects a $4$3 million annual decrease in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. This mechanism includes a non-traditional rate making approach related to a 50 MW universal solar array placed in service in January 2021. |
TDSIC | | 3 | | August 2021 | | November 2021 | | November 2021 | | Requested an increase of $35 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the 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.less than $1 million. |
ECA - MATS | | 132 | | February
2018 May 2021 | | January
2019 September 2021 | | April
2019 September 2021 | | Requested an increase of $58$39 million to rate base, which reflects a $13$2 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism includes recoveryalso included a change in (over)/under-recovery variance of prior accounting deferrals associated with investments (depreciation, carrying costs, operating expenses).less than $1 million annually. |
CECATDSIC | | 23 | | February 2019 2021 | | June
2019 May 2021 | | May 2019
2021 | | Requested an increase of $13$28 million to rate base, related to solar pilot investments, which reflects a $2$3 million annual increase in current revenues. |
CECA (1)
| | 0.1 | | February 2020 | | June
2020
| | TBD | | Requested an 80% of the revenue requirement is included in requested rate increase of $0.1 million toand 20% is deferred until next rate base related to solar pilot investments, which reflects an immaterial change to current revenues.case. The mechanism also includes a change in (over)/under-recovery variance of $0.1less than $1 million. |
CECA | | 8 | | February 2021 | | June 2021 | | May 2021 | | Reflects an $8 million annually. Additional solar investmentannual increase in current revenues through a non-traditional rate making approach related to supplya 50 MW ofuniversal solar capacity is approved and will be included for recovery once completedarray placed in service in January 2021. |
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(1) | Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates. | | | | | | | | | |
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Tax Reform
(1)Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.
TCJA-related 2018 tax expense refunds are currently included in the Registrants’ existing rates
Greenhouse Gas Regulation 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.
ELGCompliance (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,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,July 8, 2019, the EPA published its proposed CPP replacement rule, the ACE Rule,rule, which was finalized on July 8, 2019 and(i) repealed the CPP rule; (ii) replaced the CPP rule with a program that 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 implementunits; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and CenterPoint Energy does not expect a state ACEthe timing-related portions of the Section 111(d) implementing rule to be finalized and approved— was struck down by the EPA until 2024.U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states that seek review of the lower court’s decision vacating the ACE rule. CenterPoint Energy is currently unable to predict what a replacement rule for either the ACE rule or CPP would require.
The Biden administration recommitted the United States to the Paris Agreement, which can be expected to drive a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the US commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035 as well as a goal to reduce Scope 3 emissions by 20% to 30% by 2035. Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 estimates do not take into account the emissions of transport customers and emissions related to upstream extraction. These emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from the current and future administrations to further reduce GHG
emissions. CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of a state planreducing the consumption of natural gas. For more information regarding CenterPoint Energy’s new net zero emission goals and the risks associated with them, see “Risk Factors — Risk Factors Affecting Our Businesses — CenterPoint Energy is subject to operational and financial risks...” In addition, the EPA has indicated that it intends to implement the ACE rule butnew regulations targeting reductions in methane emissions, which are likely to increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not anticipategenerate electricity, other than leasing facilities that suchprovide temporary emergency electric energy to aid in restoring power to distribution customers during certain widespread power outages as allowed by a new law enacted after the February 2021 Winter Storm Event, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. CenterPoint Energy’s new net zero emissions goals are aligned with Indiana Electric’s generation transition plan wouldand are expected to position Indiana Electric to comply with anticipated future regulatory requirements related to GHG emissions reductions. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. For example, Minnesota has enacted the Natural Gas Innovation Act that seeks to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions.Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil gas. Additionally, cities in Minnesota within CenterPoint Energy’s Natural Gas operational footprint are considering initiatives to eliminate natural gas use in buildings and focus on electrification. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. These initiatives could have a material effect.
Impactsignificant impact on CenterPoint Energy and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. Further, our third party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact CenterPoint Energy’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to CenterPoint Energy. Conversely, regulatory actions that effectively promote the consumption of Legislative Actions & Other Initiatives (CenterPoint Energy)
natural gas because of its lower emissions characteristics would be expected to benefit CenterPoint Energy and CERC and their natural gas-related businesses. At this time, compliancehowever, we cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses.
Compliance costs and other effects associated with climate change, reductions in GHG emissions orand obtaining renewable energy sources remain uncertain. Although the amount of compliance costs remains uncertain, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. While the requirements of a federal or state ACE rule remain uncertain, Indiana ElectricCenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its net zero emissions goals, CenterPoint Energy is expected to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material.
Climate Change Trends and Uncertainties
As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and services, which may result in, among other things, Indiana Electric’s generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on CenterPoint Energy’s electric generation and natural gas businesses. For example, because Indiana Electric’s current generating units.facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’ services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the
FERC Revised Policy Statement (CenterPoint Energy)challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.
The regulationTo address these developments, CenterPoint Energy announced its new net zero emissions goals for both Scope 1 and Scope 2 emissions by 2035. In June of midstream energy infrastructure assets has2020, Indiana Electric identified a preferred generation resource in its most recent IRP submitted to the IURC that aligns with its new net zero emission goals and includes the replacement of 730 MW of coal-fired generation facilities with a significant impact on Enable’s business.portion comprised of renewables, including solar and wind, supported by dispatchable natural gas combustion turbines, including a pipeline to serve such natural gas generation, as well as storage. Additionally, as reflected in its 10-year capital plan announced in September 2021, CenterPoint Energy anticipates spending over $3 billion in clean energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion. CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its newly adopted net zero emissions goals support global efforts to reduce the impacts of climate change. For more information regarding CenterPoint Energy’s new net zero emission goals and the risks associated with them, see “Risk Factors — Risk Factors Affecting Our Businesses — CenterPoint Energy is subject to operational and financial risks...”
To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, Enable’s interstateCenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas transportationsales. On the other hand, warmer temperatures in CenterPoint Energy’s and storage assetsHouston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. Since many of the Registrants’ facilities are subjectlocated along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes could increase costs to regulationrepair damaged facilities and restore service to customers. CenterPoint Energy’s recently announced 10-year capital plan includes capital expenditures to maintain reliability and safety and increase resiliency of its systems as climate change may result in more frequent significant weather events. Houston Electric does not own or operate any electric generation facilities other than, since September 2021, leasing facilities that provide temporary emergency electric energy to aid in restoring power to distribution customers during certain widespread power outages as allowed by a new law enacted after the FERC underFebruary 2021 Winter Storm Event. Houston Electric transmits and distributes to customers of REPs electric power that the NGA. In March 2018,REPs obtain from power generation facilities owned by third parties. To the FERC announcedextent adverse weather conditions affect the Registrants’ suppliers, results from their energy delivery businesses may suffer. For example, in Texas, the February 2021 Winter Storm Event caused an electricity generation shortage that was severely disruptive to Houston Electric’s service territory and the wholesale generation market and also caused a Revised Policy Statement stating that it would no longer allow pipelines organized as a master limited partnershipreduction in available natural gas capacity. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover an income tax allowancerestoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in their cost-of-service rates. In July 2018,reduced demand for services, the FERC issued new regulations which required all FERC-regulated natural gas pipelinesRegistrants’ future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact our ability 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 MRTsecure cost-efficient insurance.
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$4 billion as of December 31, 2019. 2021.
As of February 19, 2020,15, 2022, the Registrants had the following revolving credit facilities and utilization of such facilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Amount Utilized as of February 15, 2022 | | | | |
Registrant | | Size of Facility | | Loans | | Letters of Credit | | Commercial Paper | | Weighted Average Interest Rate | | Termination Date |
| | (in millions) | | | | |
CenterPoint Energy | | $ | 2,400 | | | $ | — | | | $ | 11 | | | $ | 710 | | | 0.23% | | February 4, 2024 |
CenterPoint Energy (1) | | 400 | | | — | | | — | | | 264 | | | 0.22% | | February 4, 2024 |
Houston Electric | | 300 | | | — | | | — | | | — | | | —% | | February 4, 2024 |
CERC | | 900 | | | — | | | — | | | 100 | | | 0.19% | | February 4, 2024 |
Total | | $ | 4,000 | | | $ | — | | | $ | 11 | | | $ | 1,074 | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | | 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.
| |
(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. Each of the Registrant’s credit facilities provide for a mechanism to replace LIBOR with possible alternative benchmarks upon certain benchmark replacement events. The borrowers are currently in compliance with the various business and financial covenants in the fivefour revolving credit facilities.
Long-term Debt
For detailed information about the Registrants’ debt issuances in 2019,2021, see Note 14 to the consolidated financial statements.
Securities Registered with the SEC
On January 31, 2017,May 29, 2020, 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 expiredwill expire on January 31, 2020.May 29, 2023. For information related to the Registrants’ debt and equity security issuances in 2019,2021, see Notes 13 and 14 to the consolidated financial statements.
Temporary Investments
As of February 19, 2020,15, 2022, 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, 2020:15, 2022:
| | | | | | | | | | | | | | | | | |
| Weighted Average Interest Rate | | Houston Electric | | CERC |
| | | (in millions) |
Money pool investments | 0.22% | | $ | (731) | | | $ | — | |
|
| | | | | | | | | |
| 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 rate on borrowings under the Registrants’ credit facilities is based on their respective 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, 2020,15, 2022, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of the Registrants:
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | NegativeStable |
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 | | A1A2 | | Under ReviewStable | | A | | Stable | | A | | NegativeStable |
CERC | | CERC Corp. Senior Unsecured Debt | | Baa1A3 | | PositiveStable | | BBB+ | | Stable | | BBB+A- | | Stable |
| |
(1) | A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. |
(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.
| |
(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, 2019,2021, the impact on the borrowing costs under the fivefour revolving credit facilities would have been immaterial.insignificant. 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$213 million as of December 31, 2019.2021. 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 and ZENS-Related Securities 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, 2019,2021, deferred taxes of approximately $429$539 million would have been payable in 2019.
2021. If all the ZENS-Related Securities had been sold on December 31, 2019,2021, capital gains taxes of approximately $149$146 million would have been payable in 2019.2021. For additional information about ZENS, see Note 12 to the consolidated financial statements.
Cross Defaults
Under each of CenterPoint Energy’s (including VUHI’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.
As announced in September 2021, CenterPoint Energy previously disclosed that itplans to increase its planned capital expenditures in its Electric and Natural Gas businesses to support rate base growth and may reduce its ownership in Enable over time throughexplore asset sales in addition to the public equity markets, or otherwise,recently completed sale of the Enable common units it holds, subjectits Natural Gas businesses located in Arkansas and Oklahoma as a means 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 toefficiently finance a portion of CenterPoint Energy’ssuch increased capital expenditure program. CenterPoint Energy may consider or alterexpenditures. On January 10, 2022, CERC Corp. completed the sale of 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.Arkansas and Oklahoma regulated natural gas LDC businesses. For further information, see Notes 64 and 2322 to the consolidated financial statements.
Additionally, on February 24, 2020,On December 2, 2021, the Enable Merger closed and, as a result, CenterPoint Energy throughreceived Energy Transfer Common Units and Energy Transfer Series G Preferred Units. Subsequent to the closing of the Enable Merger, in December 2021, CenterPoint Energy sold 150 million of the Energy Transfer Common Units (inclusive of the Energy Transfer Common Units sold pursuant to the Forward Sale Agreement) and half of the Energy Transfer Series G Preferred Units it received in the Enable Merger. CenterPoint Energy has announced plans to dispose of all of its subsidiary CERC Corp., entered intointerests in Energy Transfer by the Equity Purchase Agreement to sell CES, which represents substantiallyend of 2022.CenterPoint Energy may not realize any or all of the businesses withinanticipated strategic, financial, operational or other benefits from any disposition or reduction of its investment in Energy Transfer. There can be no assurances that any further disposal of Energy Transfer Common Units or Energy Transfer Series G Preferred Units will be completed. Any disposal of such securities may involve significant costs and expenses, including in connection with any public offering, a significant underwriting discount. For information regarding the Energy Services reportable segment. The transaction is expected to close in the second quarter of 2020.For further information,Enable Merger, see Notes 64, 11 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 1112 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 NGDNatural Gas 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. CenterPoint Energy and CERC did not enter into any weather hedges during the year ended December 31, 2021. 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 also be negatively 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 andreportable segment;
•reductions in the cash distributions we receive from Energy Services reportable segments; Transfer;
•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; loans or the use of alternative sources of financings due to the effects of COVID-19 on capital and other financial markets;
•various legislative or regulatory actions;
•incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy and CERC)Energy);
•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;Electric, including the negative impact on such ability related to COVID-19 and the February 2021 Winter Storm Event;
•slower customer payments and increased write-offs of receivables due to higher natural gas prices, or changing economic conditions, COVID-19 or the February 2021 Winter Storm Event (CenterPoint Energy and CERC);
•the satisfaction of any obligations pursuant to guarantees;
•the outcome of litigation; litigation, including litigation related to the February 2021 Winter Storm Event;
•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 issueCertain provisions in certain note purchase agreements relating to debt issued by VUHI have the effect of restricting the amount of additional first mortgage bonds subjectissued by SIGECO. Additionally, such note purchase agreements would restrict the securitization (as enabled by Senate Bill 386 as enacted by the State of Indiana) that CenterPoint Energy intends to certain exceptions.seek in 2022 of remaining book value and removal costs associated with generating facilities to be retired by Indiana Electric. 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’sEnergy, for its Electric 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, Houston Electric and CERC 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, and 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, goodwill, or equity method investments or readily determinable fair value during 2019, 20182021 and 2017.2019. During 2020, CenterPoint Energy recognized equity method investment impairment losses as discussed further in Note 11 to the consolidated financial statements and CERC recognized goodwill impairment losses as discussed below, during 2019,further in Notes 6 and 10 to the Registrants recorded no impairments to goodwill in 2018 and 2017.consolidated financial statements.
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 20192021 annual goodwill impairment test asduring the third quarter of July 1, 20192021 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.unit. 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.unit.
Although no goodwill impairment resulted from the 20192021 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”)or the disposal group, at the lower of their carrying value or their estimated fair value less cost to sell.If the Disposal Groupa 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 forDuring the year ended December 31, 2019,2021, as described further in Note 4 to the consolidated financial statements, certain assets and liabilities representing a business met the held for sale criteria. As a result, goodwill attributable to the natural gas reporting unit of $398 million and $144 million at CenterPoint Energy and CERC, respectively, was deemed attributable to assets held for sale as of December 31, 2021.Neither CenterPoint Energy nor CERC recognized any gains or losses upon classification of held for sale, including impairments of goodwill, during the year ended December 31, 2021.
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, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value could be different if different estimates and assumptions in these valuation techniques were applied.
Fair value measurements require significant judgment and often unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, identified triggering events for interim goodwill impairment tests atand (iii) discount rates reflecting risk inherent in the Infrastructure Services and Energy Services reporting units. Early stage bids received fromfuture market participants duringprices. Changes in these assumptions could have a significant impact on the exploration of strategic alternatives for these businesses at year-end indicated that theresulting 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, plantused a market approach consisting of the contractual sales price adjusted for estimated working capital and equipment, and specifically identifiable intangibles subjectother contractual purchase price adjustments to amortization,determine fair value of the businesses classified as held for recoverability andsale. The fair value of the goodwillretained businesses within the natural gas 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 recoverableunit was estimated based on undiscounted cash flows, consideringa weighted combination of income and market approaches, consistent with the likelihoodmethodology used in the 2021 and 2020 annual goodwill impairment tests. A third-party valuation specialist was utilized to determine the key assumptions used in the estimate of possible outcomes existing as of December 31, 2019, including the assessmentfair value 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 theretained natural gas 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.
2021. The fair value of the Infrastructure Servicesretained natural gas 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.at 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 unitsignificantly exceeded its fair value as of December 31, 2019. Following the impairment, the carrying value of the goodwill remaining in the Energy Servicesretained businesses within that reporting unit is $62 million as of December 31, 2019.
On February 24, 2020, CenterPoint Energy, through its subsidiary CERC Corp., entered intoimmediately after classifying the Equity Purchase Agreement to sell CES, which represents substantially all of theArkansas and Oklahoma Natural Gas 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 23Note 4 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 planplans covering eligible employees. Employer contributions for the qualified planplans 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,plans, 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, 20182021, 2020 and 20172019 were as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
CenterPoint Energy | (in millions) |
Minimum funding requirements for qualified pension plans | $ | — | | | $ | 76 | | | $ | 86 | |
Employer contributions to the qualified pension plans | 53 | | | 76 | | | 86 | |
Employer contributions to the non-qualified benefit restoration plans | 8 | | 10 | | | 23 | |
|
| | | | | | | | | | | |
| 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 |
|
Although CenterPoint Energy expects to contribute aEnergy’s minimum of approximately $76 millioncontribution requirement to the qualified pension plans andin 2022 is zero, it expects to make contributions aggregating up to $50 million. CenterPoint Energy expects to make contributions aggregating approximately $7 million to the non-qualified benefit restoration plans in 2020.2022.
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$2.3 billion and $2.0$2.5 billion as of December 31, 20192021 and 2018,2020, respectively.
As of December 31, 2019,2021, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $448$226 million. Changes in interest rates or the market values of the securities held by the plan during 20202022 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, |
| 2021 | | 2020 | | 2019 |
| CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC | | CenterPoint Energy | | Houston Electric | | CERC |
| (in millions) |
Pension cost | $ | 69 | | | $ | 34 | | | $ | 27 | | | $ | 49 | | | $ | 19 | | | $ | 20 | | | $ | 93 | | | $ | 40 | | | $ | 35 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2019,2021, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 5.75%,5.00% rate, which is 0.25% lower than the 6.00%same rate assumed as of December 31, 2018.2020. 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, 2019,2021, the projected benefit obligation was calculated assuming a discount rate of 3.20%2.80%, which is 1.15% lower0.35% higher than the 4.35%2.45% discount rate assumed as of December 31, 2018.2020. 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 expensecost for 20192021 and 20182020 that is greater or less than the amounts being recovered through rates in certainthe majority of Texas jurisdictions is deferred as a regulatory asset or liability, respectively. Pension cost for 2020,2022, including the nonqualified benefit restoration plan, is estimated to be $45$22 million of which CenterPoint Energy expects approximately $52 million to impact pre-tax earnings after effecting suchbefore applicable regulatory deferrals and capitalization, based on an expected return on plan assets of 5.75%5.00% and a discount rate of 3.20%2.80% as of December 31, 2019.2021. If the expected return assumption were lowered by 0.50% from 5.75%5.00% to 5.25%4.50%, 20202022 pension cost would increase by approximately $10 million.
As of December 31, 2019,2021, the pension plans projected benefit obligation, including the unfunded nonqualified pension plans, exceeded plan assets by $448$226 million. If the discount rate were lowered by 0.50% from 3.20%2.80% to 2.70%2.30%, the assumption change would increase CenterPoint Energy’s projected benefit obligation by approximately $127$118 million and decrease its 20202022 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, 20192021 by $110$100 million and would result in a charge to comprehensive income in 20192021 of $13$14 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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Impact of Changes in Interest Rates, Equity Prices and Energy Commodity Prices
The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in the Registrants’ consolidated financial statements. Most of the revenues and income from the Registrants’ business activities are affected by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below:
•Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.
•Equity price risk results from exposures to changes in prices of individual equity securities (CenterPoint Energy).
•Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas, NGLs and other energy commodities (CenterPoint Energy and CERC)Energy).
Management has established comprehensive risk management policies to monitor and manage these market risks.
Interest Rate Risk
As of December 31, 2019,2021, the Registrants had outstanding long-term debt and lease obligations and CenterPoint Energy had obligations under its ZENS that subject them to the risk of loss associated with movements in market interest rates.
CenterPoint Energy’s floating rate obligations aggregated $3.9$4.5 billion and $210 million$2.4 billion as of December 31, 20192021 and 2018,2020, respectively. If the floating interest rates were to increase by 10% from December 31, 20192021 rates, CenterPoint Energy’s combined interest expense would increase by approximately $9$2 million annually.
Houston Electric did not have any floating rate obligations as of either December 31, 20192021 or 2018.2020.
CERC’s floating rate obligations aggregated $376 million$1.9 billion and $210$347 million as of December 31, 20192021 and 2018,2020, respectively. If the floating interest rates were to increase by 10% from December 31, 20192021 rates, CERC’s combined interest expense would increase by approximately $1 million annually.
As of December 31, 20192021 and 2018,2020, CenterPoint Energy had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $11.2$11.7 billion and $9.0$11.1 billion, respectively, in principal amount and having a fair value of $12.2$13.0 billion and $9.2$12.9 billion,
respectively. Because these instruments are fixed-rate, they do not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $344$359 million if interest rates were to decline by 10% from their levels as of December 31, 2019.2021.
As of December 31, 20192021 and 2018,2020, Houston Electric had outstanding fixed-rate debt aggregating $5.0$5.5 billion and $4.8$5.1 billion, respectively, in principal amount and having a fair value of approximately $5.5$6.3 billion and $4.8$6.0 billion, respectively. Because these instruments are fixed-rate, they do not expose Houston Electric to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $179$214 million if interest rates were to decline by 10% from their levels as of December 31, 2019.2021.
As of December 31, 20192021 and 2018,2020, CERC had outstanding fixed-rate debt aggregating $2.2$2.5 billion and $2.2$2.1 billion, respectively, in principal amount and having a fair value of $2.5$2.8 billion and $2.3$2.5 billion, respectively. Because these instruments are fixed-rate, they do not expose CERC to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $77$71 million if interest rates were to decline by 10% from their levels at December 31, 2019.2021.
In general, such an increase in fair value would impact earnings and cash flows only if the Registrants were to reacquire all or a portion of these instruments in the open market prior to their maturity.
As discussed in Note 12 to the consolidated financial statements, the ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of $19$10 million at December 31, 20192021 was a fixed-rate obligation and, therefore, did not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $2$1 million if interest rates were to decline by 10% from levels at December 31, 2019.2021. Changes in the fair value of the derivative component, a $893$903 million recorded liability at December 31, 2019,2021, are recorded in CenterPoint Energy’s Statements of Consolidated Income and, therefore, it is exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-freerisk-
free interest rate were to increase by 10% from December 31, 20192021 levels, the fair value of the derivative component liability would decrease by approximately $1 million, which would be recorded as an unrealized gain in CenterPoint Energy’s Statements of Consolidated Income.
Equity Market Value Risk (CenterPoint Energy)
CenterPoint Energy is exposed to equity market value risk through its ownership of 10.2 million shares of AT&T Common and 0.9 million shares of Charter Common, which CenterPoint Energy holds to facilitate its ability to meet its obligations under the ZENS.ZENS and through its ownership of 51 million shares of Energy Transfer Common Units and 0.2 million shares of Energy Transfer Series G Preferred Units. See Note 12 to the consolidated financial statements for a discussion of CenterPoint Energy’s ZENS obligation.obligation and the Energy Transfer Common Units and Energy Transfer Series G Preferred Units that CenterPoint Energy holds. Changes in the fair value of the ZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS. A decrease of 10% from the December 31, 20192021 aggregate market value of these shares would result in a net loss of less than $1 million, which would be recorded as a loss on debt securities in CenterPoint Energy’s Statements of Consolidated Income.
Commodity Price Risk From Non-Trading Activities (CenterPoint Energy and CERC)Energy)
CenterPoint Energy and CERC use derivative instruments as economic hedges to offset the commodity price exposure inherent in their businesses. The commodity risk created by these instruments, including the offsetting impact on the market value of natural gas inventory, is described below. CenterPoint Energy and CERC measure this commodity risk using a sensitivity analysis. For purposes of this analysis, CenterPoint Energy and CERC estimate commodity price risk by applying a $0.50 change in the forward NYMEX price to their net open fixed price position (including forward fixed price physical contracts, natural gas inventory and fixed price financial contracts) at the end of each period. As of December 31, 2019, the recorded fair value of CenterPoint Energy’s and CERC’s non-trading energy derivatives was a net asset of $73 million (before collateral), all of which is related to CenterPoint Energy’s and CERC’s Energy Services reportable segment. A $0.50 change in the forward NYMEX price would have had a combined impact of $13 million on CenterPoint Energy’s and CERC’s non-trading energy derivatives net asset and the market value of natural gas inventory.
Commodity price risk is not limited to changes in forward NYMEX prices. Variation of commodity pricing between the different indices used to mark to market portions of CenterPoint Energy’s and CERC’s natural gas inventory (Gas Daily) and the related fair value hedge (NYMEX) can result in volatility to CenterPoint Energy’s and CERC’s net income. Over time, any gains or losses on the sale of storage gas inventory would be offset by gains or losses on the fair value hedges.
CenterPoint Energy’s regulated operations in Indiana have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal and purchased power for the benefit of retail customers due to current state regulations, which, subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. CenterPoint Energy’s utility natural gas operations in Indiana have regulatory authority to lock in pricing for up to 50% of annual natural gas purchases using arrangements with an original term of up to 10 years. This authority has been utilized to secure fixed price natural gas using both physical purchases and financial derivatives. As of December 31, 2019,2021, the recorded fair value of non-trading energy derivative liabilitiesassets was $22$14 million for CenterPoint Energy’s utility natural gas operations in Indiana, which is offset by a regulatory asset.
Although CenterPoint Energy’s regulated operations are exposed to limited commodity price risk, natural gas and coal prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered. Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs and recovery of unaccounted for natural gas and other natural gas-related expenses, also mitigate the effect natural gas costs may have on CenterPoint Energy’s financial condition. In 2008, the PUCO approved an exit of the merchant function in CenterPoint Energy’s Ohio natural gas service territory, allowing Ohio customers to purchase substantially all natural gas directly from retail marketers rather than from CenterPoint Energy.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the “Company”"Company") as of December 31, 20192021 and 2018,2020, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2019,2021, and the related notes (collectively referred to as the “financial statements”"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’sCompany's internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 202022, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the Company’sCompany's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit MattersMatter
The critical audit mattersmatter communicated below are mattersis a matter arising from the current-period audit of the financial statements that werewas communicated or required to be communicated to the audit committee and that (1) relaterelates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinionsopinion on the critical audit mattersmatter or on the accounts or disclosures to which they relate.it relates.
Acquisitions - Vectren Corporation - Intangible Assets - Refer to Note 4 to the financial statements
Critical Audit Matter Description
The Company completed the acquisition of Vectren Corporation (“Vectren”) for $6 billion in cash on February 1, 2019. The Company accounted for the acquisition under the acquisition method of accounting for business combinations. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair values, including intangible assets and goodwill of $4.6 billion. Of the intangible assets acquired, $297 million was allocated to identifiable intangible assets such as customer relationships and trade name with the remainder of $4.3 billion being recorded as goodwill. Management estimated the fair value of the identifiable intangible assets using the multi-period excess earnings method, which is a specific discounted cash flow method. In addition, the determination of the business fair value required management to make significant estimates and assumptions related to discount rates and future cash flows. Determining the discount rates for the nonregulated businesses acquired required management to estimate the appropriate entity specific risk premiums for those nonregulated businesses based on evaluation of industry and entity-specific risks which included expectations about future market or economic conditions.
Changes in these assumptions could have a significant impact on either the amount of the identified intangible assets, the resulting amount of goodwill, or both.
Given the fair value determination of intangible assets acquired required management to make significant estimates and assumptions related to the forecasts of future cash flows and the company specific risk premium affecting the discount rate, performing audit procedures to evaluate the reasonableness of these estimates and assumptions required a high degree of auditor judgment and an increased extent of effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the forecasts of future cash flows and company specific risk premium affecting the discount rate for the intangible assets of the nonregulated businesses acquired included the following, among others:
We tested the effectiveness of controls over acquisition valuation, including management’s controls over the forecasts of future cash flows and selection of the company specific risk premium assumption used in the determinations of the discount rates.
We considered the impact of changes to the discount rate and long-term growth rate on the fair value.
We evaluated the value at which acquired assets were recorded under the applicable accounting guidance based on the regulated nature of the entity.
We assessed the reasonableness of management’s forecasts by comparing the forecasts to:
| |
◦ | Historical revenues and operating margins. |
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◦ | Internal communications to management and the Board of Directors. |
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◦ | Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies. |
We evaluated whether the estimated future cash flows were consistent with evidence obtained in other areas of the audit.
We involved our fair value specialists who assisted in:
| |
◦ | Assessing the appropriateness of the valuation methodology used to determine the customer relationship intangible assets and the company specific risk premiums. |
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◦ | Testing the determined discount rates by independently estimating a discount rate for each business using a process consistent with generally accepted valuation practices. |
Goodwill - Refer to Note 6 to the financial statements
Critical Audit Matter Description
The Company’s evaluation of goodwill for impairment involves the comparison of the fair value of each reporting unit to its carrying value. In its annual goodwill impairment test on July 1, 2019 (“measurement date”) and as triggering events are identified, the Company used the discounted cash flow model and a market approach to estimate fair value of each reporting unit, which required management to make significant estimates and assumptions related to forecasts of future revenues and operating margins based on certain assumptions including (i) future capital expenditures and rate base growth, (ii) estimated future rate changes, (iii) discount rates, and (iv) long-term growth rates. Changes in these assumptions could have a significant impact on the fair value of a reporting unit, the amount of any goodwill impairment charge, or both. The Company’s goodwill is $5.2 billion as of December 31, 2019, of which $4.3 billion resulted from the acquisition of Vectren. The fair value of each reporting unit exceeded the carrying value as of the measurement date and, therefore, no impairment was recognized.
Given the significant assumptions used by management to estimate fair value including (i) future capital expenditures and rate base growth, (ii) estimated future rate changes, (iii) discount rates, and (iv) long-term growth rates, performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to forecasts of future revenue and operating margin, specifically for reporting units containing unregulated business units and Vectren rate regulated jurisdictions, required a high degree of auditor judgment and an increased extent of effort, including the need to involve fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the assumptions used to forecast future revenue and operating margin used by management within the discounted cash flow model included the following, among others:
We tested the effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of fair value, such as controls related to management’s forecasts of future capital expenditures, future rate base growth, estimated future rate changes, discount rates, and long-term growth rates.
We evaluated the reasonableness of management’s forecasts by comparing the forecasts to:
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◦ | Historical revenues, operating margins, capital expenditures, rate base growth, and rate changes. |
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◦ | Internal communications to management and the Board of Directors. |
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◦ | Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies. |
We compared future rate changes to the Company’s scheduled rate filings and the amount of capital expenditures for the regulated entities to communications with regulators including integrated resource plans.
We compared actual revenue growth and capital expenditures results for 2019 to the planned results as of the acquisition date.
We evaluated the impact of changes in management’s forecasts from the measurement date to December 31, 2019.
We involved our fair value specialists who assisted in:
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◦ | Assessing the appropriateness of the valuation methodology used to determine the company specific risk premiums in calculating the discount rate. |
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◦ | Testing the determined discount rates by independently estimating a discount rate for each business using a process consistent with generally accepted valuation practices. |
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◦ | Evaluating the reasonableness of the long-term growth rate through a comparison to industry reports and peer companies. |
Impact of Rate Regulation on the Financial Statements -— Refer to Notes 2 and 7 to the financial statements
Critical Audit Matter Description
The Company through its regulated electric and gas subsidiaries is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the relevant state public utility commissions“Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in Texas by the Railroad Commission, and the Federal Energy Regulatory Commission (collectively, “the Commissions”), and those municipalities (in Texas only) served by the Company.jurisdictions. Management has determined it meetsits regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; prepaid expenses and other current assets; regulatory assets and liabilities; utility revenues;revenues and expenses; operation and maintenance expense; and depreciation and amortization expense; and income tax expense.
The Company’s rates are subject to regulatory rate-setting processes by certain municipalities and the Commissions. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered by rates. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in
the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory actions on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due its inherent complexities.process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred and deferred as regulatory assets, and (2) refund or future reductions in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
For matters with a high degree of subjectivity, we•We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, in the states the Company operates in, regulatory statutes, interpretations, procedural memorandums, filings made by interveners,intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedenceprecedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the CommissionCommissions and the filings with the CommissionCommissions by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We evaluated management’s plans regardingassertion that no indicators of impairment were identified in connection with the Company's property, plant, and equipment for indications of potential impairment.equipment. We inspected the capital-projectscapital projects budget and inquired of management to identify projects that are designed to replace assets that may be retired prior to the end of the useful life. We inspected minutes of the board of directors and regulatory orders and other filings with the Commissions to identify any evidence that may contradict management’s assertion regarding probability of a disallowance of long-lived assets.
•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects and inquired of management to assess whether capitalized costs are probable of disallowance.
•We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 202022, 2022
We have served as the Company’s auditor since 1932.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in millions, except per share amounts) |
Revenues: | | | | | |
Utility revenues | $ | 8,042 | | | $ | 7,049 | | | $ | 7,202 | |
Non-utility revenues | 310 | | | 369 | | | 362 | |
Total | 8,352 | | | 7,418 | | | 7,564 | |
Expenses: | | | | | |
Utility natural gas, fuel and purchased power | 2,127 | | | 1,488 | | | 1,762 | |
Non-utility cost of revenues, including natural gas | 208 | | | 257 | | | 257 | |
Operation and maintenance | 2,810 | | | 2,744 | | | 2,775 | |
Depreciation and amortization | 1,316 | | | 1,189 | | | 1,225 | |
Taxes other than income taxes | 528 | | | 516 | | | 474 | |
Goodwill impairment | — | | | 185 | | | — | |
Total | 6,989 | | | 6,379 | | | 6,493 | |
Operating Income | 1,363 | | | 1,039 | | | 1,071 | |
Other Income (Expense): | | | | | |
Gain (loss) on equity securities | (172) | | | 49 | | | 282 | |
Gain (loss) on indexed debt securities | 50 | | | (60) | | | (292) | |
Gain on sale | 8 | | | — | | | — | |
Interest expense and other finance charges | (508) | | | (501) | | | (528) | |
Interest expense on Securitization Bonds | (21) | | | (28) | | | (39) | |
| | | | | |
| | | | | |
| | | | | |
Other income, net | 58 | | | 64 | | | 51 | |
Total | (585) | | | (476) | | | (526) | |
Income from Continuing Operations Before Income Taxes | 778 | | | 563 | | | 545 | |
Income tax expense | 110 | | | 80 | | | 30 | |
Income from Continuing Operations | 668 | | | 483 | | | 515 | |
Income (Loss) from Discontinued Operations (net of tax expense (benefit) of $201, $(333), and $108, respectively) | 818 | | | (1,256) | | | 276 | |
Net Income (Loss) | 1,486 | | | (773) | | | 791 | |
Income allocated to preferred shareholders | 95 | | | 176 | | | 117 | |
| | | | | |
Income (Loss) Available to Common Shareholders | $ | 1,391 | | | $ | (949) | | | $ | 674 | |
| | | | | |
Basic earnings per common share - continuing operations | $ | 0.97 | | | $ | 0.58 | | | $ | 0.79 | |
Basic earnings (loss) per common share - discontinued operations | 1.38 | | | (2.37) | | | 0.55 | |
Basic Earnings (Loss) Per Common Share | $ | 2.35 | | | $ | (1.79) | | | $ | 1.34 | |
Diluted earnings per common share - continuing operations | $ | 0.94 | | | $ | 0.58 | | | $ | 0.79 | |
Diluted earnings (loss) per common share - discontinued operations | 1.34 | | | (2.37) | | | 0.54 | |
Diluted Earnings (Loss) Per Common Share | $ | 2.28 | | | $ | (1.79) | | | $ | 1.33 | |
| | | | | |
Weighted Average Common Shares Outstanding, Basic | 593 | | | 531 | | | 502 | |
Weighted Average Common Shares Outstanding, Diluted | 610 | | | 531 | | | 505 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
| (in millions, except per share amounts) |
Revenues: | | | | | |
Utility revenues | $ | 7,162 |
| | $ | 6,163 |
| | $ | 5,603 |
|
Non-utility revenues | 5,139 |
| | 4,426 |
| | 4,011 |
|
Total | 12,301 |
| | 10,589 |
| | 9,614 |
|
Expenses: | |
| | | | |
|
Utility natural gas, fuel and purchased power | 1,683 |
| | 1,410 |
| | 1,109 |
|
Non-utility cost of revenues, including natural gas | 4,029 |
| | 4,364 |
| | 3,785 |
|
Operation and maintenance | 3,550 |
| | 2,335 |
| | 2,157 |
|
Depreciation and amortization | 1,287 |
| | 1,243 |
| | 1,036 |
|
Taxes other than income taxes | 478 |
| | 406 |
| | 391 |
|
Goodwill impairment | 48 |
| | — |
| | — |
|
Total | 11,075 |
| | 9,758 |
| | 8,478 |
|
Operating Income | 1,226 |
| | 831 |
| | 1,136 |
|
Other Income (Expense): | | | | | |
|
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, net | 50 |
| | 50 |
| | (4 | ) |
Total | (297 | ) | | (317 | ) | | (73 | ) |
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 |
|
| | | | | |
Weighted Average Common Shares Outstanding, Basic | 502 |
| | 449 |
| | 431 |
|
| | | | | |
Weighted Average Common Shares Outstanding, Diluted | 505 |
| | 452 |
| | 434 |
|
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in millions) |
Net Income (Loss) | $ | 1,486 | | | $ | (773) | | | $ | 791 | |
Other comprehensive income (loss): | | | | | |
Adjustment to pension and other postemployment plans (net of tax expense of $7, $-0- and $4, respectively) | 21 | | | (5) | | | 12 | |
Net deferred loss from cash flow hedges (net of tax benefit of $-0-, $-0- and $1, respectively) | — | | | — | | | (2) | |
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0- and $-0-, respectively) | 2 | | | — | | | 1 | |
Reclassification of net deferred losses from cash flow hedges (net of tax expense of $-0-, $4, and $-0-, respectively) | — | | | 15 | | | — | |
Other comprehensive income (loss) from unconsolidated affiliates (net of tax of $-0-, $-0-, and $-0-, respectively) | 3 | | | (2) | | | (1) | |
Total | 26 | | | 8 | | | 10 | |
Comprehensive income (loss) | 1,512 | | | (765) | | | 801 |
Income allocated to preferred shareholders | 95 | | | 176 | | | 117 | |
Comprehensive income (loss) available to common shareholders | $ | 1,417 | | | $ | (941) | | | $ | 684 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
| (in millions) |
Net income | $ | 791 |
| | $ | 368 |
| | $ | 1,792 |
|
Other comprehensive income (loss): | | | |
| | |
Adjustment to pension and other postretirement plans (net of tax expense (benefit) of $4, ($2) and $6, respectively) | 12 |
| | (10 | ) | | 6 |
|
Net deferred gain (loss) from cash flow hedges (net of tax expense (benefit) of ($1), ($4) and ($2), respectively) | (2 | ) | | (15 | ) | | (3 | ) |
Reclassification of deferred loss from cash flow hedges realized in net income (net of tax expense of $-0-, $-0- and $-0-, respectively) | 1 |
| | — |
| | — |
|
Other comprehensive loss from unconsolidated affiliates (net of tax of $-0-, $-0-, and $-0-, respectively) | (1 | ) | | — |
| | — |
|
Other comprehensive income (loss) | 10 |
| | (25 | ) | | 3 |
|
Comprehensive income | 801 |
| | 343 |
| | 1795 |
|
Preferred stock dividend requirement | 117 |
| | 35 |
| | — |
|
Comprehensive income available to common shareholders | $ | 684 |
| | $ | 308 |
| | $ | 1,795 |
|
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| (in millions) |
ASSETS | | | |
Current Assets: | | | |
Cash and cash equivalents ($92 and $139 related to VIEs, respectively) | $ | 230 | | | $ | 147 | |
Investment in equity securities | 1,439 | | | 871 | |
| | | |
Accounts receivable ($29 and $23 related to VIEs, respectively), less allowance for credit losses of $44 and $52, respectively | 690 | | | 676 | |
Accrued unbilled revenues, less allowance for credit losses of $6 and $5, respectively | 513 | | | 505 | |
| | | |
Natural gas and coal inventory | 186 | | | 203 | |
Materials and supplies | 422 | | | 297 | |
Non-trading derivative assets | 9 | | | — | |
Taxes receivable | 1 | | | 82 | |
Current assets held for sale | 2,338 | | | — | |
Regulatory assets | 1,395 | | | 18 | |
Prepaid expense and other current assets ($19 and $15 related to VIEs, respectively) | 132 | | | 121 | |
Total current assets | 7,355 | | | 2,920 | |
Property, Plant and Equipment, net | 23,484 | | | 22,362 | |
Other Assets: | | | |
Goodwill | 4,294 | | | 4,697 | |
Regulatory assets ($420 and $633 related to VIEs, respectively) | 2,321 | | | 2,094 | |
| | | |
Non-trading derivative assets | 5 | | | — | |
| | | |
Preferred units - unconsolidated affiliate | — | | | 363 | |
| | | |
Non-current assets held for sale | — | | | 782 | |
Other non-current assets | 220 | | | 253 | |
Total other assets | 6,840 | | | 8,189 | |
Total Assets | $ | 37,679 | | | $ | 33,471 | |
|
| | | | | | | |
| December 31, 2019 |
| December 31, 2018 |
| (in millions) |
ASSETS | | | |
Current Assets: | | | |
Cash and cash equivalents ($216 and $335 related to VIEs, respectively) | $ | 241 |
| | $ | 4,231 |
|
Investment in marketable securities | 822 |
| | 540 |
|
Accounts receivable ($26 and $56 related to VIEs, respectively), less bad debt reserve of $21 and $18, respectively | 1,249 |
| | 1,190 |
|
Accrued unbilled revenues | 586 |
| | 378 |
|
Natural gas and coal inventory | 277 |
| | 194 |
|
Materials and supplies | 269 |
| | 200 |
|
Non-trading derivative assets | 136 |
| | 100 |
|
Taxes receivable | 106 |
| | — |
|
Prepaid expense and other current assets ($19 and $34 related to VIEs, respectively) | 161 |
| | 192 |
|
Total current assets | 3,847 |
| | 7,025 |
|
Property, Plant and Equipment, net | 20,945 |
| | 14,044 |
|
Other Assets: | |
| | |
|
Goodwill | 5,164 |
| | 867 |
|
Regulatory assets ($788 and $1,059 related to VIEs, respectively) | 2,117 |
| | 1,967 |
|
Non-trading derivative assets | 58 |
| | 38 |
|
Investment in unconsolidated affiliates | 2,408 |
| | 2,482 |
|
Preferred units - unconsolidated affiliate | 363 |
| | 363 |
|
Intangible assets, net | 321 |
| | 65 |
|
Other | 216 |
| | 158 |
|
Total other assets | 10,647 |
| | 5,940 |
|
Total Assets | $ | 35,439 |
| | $ | 27,009 |
|
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, cont.
| | | | | | | | | | | |
| December 31, 2021 | | December 31, 2020 |
| (in millions, except par value and shares) |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
Current Liabilities: | | | |
Short-term borrowings | $ | 7 | | | $ | 24 | |
Current portion of VIE Securitization Bonds long-term debt | 220 | | | 211 | |
Indexed debt, net | 10 | | | 15 | |
Current portion of other long-term debt | 308 | | | 1,669 | |
Indexed debt securities derivative | 903 | | | 953 | |
Accounts payable | 1,196 | | | 853 | |
| | | |
Taxes accrued | 378 | | | 265 | |
Interest accrued | 136 | | | 145 | |
Dividends accrued | 131 | | | 136 | |
Customer deposits | 111 | | | 119 | |
Non-trading derivative liabilities | 2 | | | 3 | |
| | | |
Current liabilities held for sale | 562 | | | — | |
Other | 323 | | | 432 | |
Total current liabilities | 4,287 | | | 4,825 | |
Other Liabilities: | | | |
Deferred income taxes, net | 3,904 | | | 3,603 | |
Non-trading derivative liabilities | 12 | | | 27 | |
Benefit obligations | 511 | | | 680 | |
Regulatory liabilities | 3,153 | | | 3,448 | |
| | | |
Other | 836 | | | 1,019 | |
Total other liabilities | 8,416 | | | 8,777 | |
Long-term Debt: | | | |
VIE Securitization Bonds, net | 317 | | | 536 | |
Other long-term debt, net | 15,241 | | | 10,985 | |
Total long-term debt, net | 15,558 | | | 11,521 | |
Commitments and Contingencies (Note 16) | 0 | | 0 |
Temporary Equity (Note 19) | 3 | | | — | |
Shareholders’ Equity: | | | |
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized, 800,000 shares and 2,402,400 shares outstanding, respectively, $800 and $2,402 liquidation preference, respectively (Note 13) | 790 | | | 2,363 | |
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 628,923,534 shares and 551,355,861 shares outstanding, respectively | 6 | | | 6 | |
Additional paid-in capital | 8,529 | | | 6,914 | |
Retained earnings (accumulated deficit) | 154 | | | (845) | |
Accumulated other comprehensive loss | (64) | | | (90) | |
Total shareholders’ equity | 9,415 | | | 8,348 | |
Total Liabilities and Shareholders’ Equity | $ | 37,679 | | | $ | 33,471 | |
|
| | | | | | | |
| December 31, 2019 |
| December 31, 2018 |
| (in millions, except par value and shares) |
LIABILITIES AND SHAREHOLDERS’ EQUITY | |
| | |
|
Current Liabilities: | |
| | |
|
Current portion of VIE Securitization Bonds long-term debt | $ | 231 |
| | $ | 458 |
|
Indexed debt, net | 19 |
| | 24 |
|
Current portion of other long-term debt | 618 |
| | — |
|
Indexed debt securities derivative | 893 |
| | 601 |
|
Accounts payable | 1,138 |
| | 1,240 |
|
Taxes accrued | 241 |
| | 204 |
|
Interest accrued | 158 |
| | 121 |
|
Dividends accrued | — |
| | 187 |
|
Customer deposits | 125 |
| | 86 |
|
Non-trading derivative liabilities | 51 |
| | 126 |
|
Other | 414 |
| | 255 |
|
Total current liabilities | 3,888 |
| | 3,302 |
|
Other Liabilities: | |
| | |
|
Deferred income taxes, net | 3,928 |
| | 3,239 |
|
Non-trading derivative liabilities | 29 |
| | 5 |
|
Benefit obligations | 754 |
| | 796 |
|
Regulatory liabilities | 3,474 |
| | 2,525 |
|
Other | 763 |
| | 402 |
|
Total other liabilities | 8,948 |
| | 6,967 |
|
Long-term Debt: | |
| | |
|
VIE Securitization Bonds, net | 746 |
| | 977 |
|
Other long-term debt, net | 13,498 |
| | 7,705 |
|
Total long-term debt, net | 14,244 |
| | 8,682 |
|
Commitments and Contingencies (Note 16) |
|
| |
|
|
Shareholders’ Equity: | | | |
Cumulative preferred stock, $0.01 par value, 20,000,000 shares authorized | — |
| | — |
|
Series A Preferred Stock, $0.01 par value, $800 aggregate liquidation preference, 800,000 shares outstanding | 790 |
| | 790 |
|
Series B Preferred Stock, $0.01 par value, $978 aggregate liquidation preference, 977,500 shares outstanding | 950 |
| | 950 |
|
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 502,242,061 shares and 501,197,784 shares outstanding, respectively | 5 |
| | 5 |
|
Additional paid-in capital | 6,080 |
| | 6,072 |
|
Retained earnings | 632 |
| | 349 |
|
Accumulated other comprehensive loss | (98 | ) | | (108 | ) |
Total shareholders’ equity | 8,359 |
| | 8,058 |
|
Total Liabilities and Shareholders’ Equity | $ | 35,439 |
| | $ | 27,009 |
|
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2019 |
| 2018 |
| 2017 |
| (in millions) |
Cash Flows from Operating Activities: | | | | | |
Net income | $ | 791 |
| | $ | 368 |
| | $ | 1,792 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | |
| | |
Depreciation and amortization | 1,287 |
| | 1,243 |
| | 1,036 |
|
Amortization of deferred financing costs | 29 |
| | 48 |
| | 24 |
|
Deferred income taxes | 69 |
| | 48 |
| | (770 | ) |
Amortization of intangible assets in Non-utility cost of revenues | 24 |
| | — |
| | — |
|
Goodwill impairment | 48 |
| | — |
| | — |
|
Unrealized loss (gain) on marketable securities | (282 | ) | | 22 |
| | (7 | ) |
Loss (gain) on indexed debt securities | 292 |
| | 232 |
| | (49 | ) |
Write-down of natural gas inventory | 4 |
| | 2 |
| | — |
|
Equity in earnings of unconsolidated affiliates | (230 | ) | | (307 | ) | | (265 | ) |
Distributions from unconsolidated affiliates | 261 |
| | 267 |
| | — |
|
Pension contributions | (109 | ) | | (69 | ) | | (48 | ) |
Changes in other assets and liabilities, excluding acquisitions: | |
| | |
| | |
|
Accounts receivable and unbilled revenues, net | 226 |
| | (154 | ) | | (216 | ) |
Inventory | (52 | ) | | 1 |
| | (7 | ) |
Taxes receivable | (106 | ) | | — |
| | 30 |
|
Accounts payable | (455 | ) | | 220 |
| | 136 |
|
Fuel cost recovery | 92 |
| | 33 |
| | (85 | ) |
Non-trading derivatives, net | (64 | ) | | 103 |
| | (84 | ) |
Margin deposits, net | (56 | ) | | 5 |
| | (55 | ) |
Interest and taxes accrued | 54 |
| | 40 |
| | 5 |
|
Net regulatory assets and liabilities | (114 | ) | | 28 |
| | (107 | ) |
Other current assets | (22 | ) | | — |
| | (3 | ) |
Other current liabilities | (107 | ) | | (24 | ) | | 34 |
|
Other assets | 103 |
| | 6 |
| | (4 | ) |
Other liabilities | (54 | ) | | 12 |
| | 36 |
|
Other, net | 9 |
| | 12 |
| | 24 |
|
Net cash provided by operating activities | 1,638 |
| | 2,136 |
| | 1,417 |
|
Cash Flows from Investing Activities: | |
| | |
| | |
|
Capital expenditures | (2,506 | ) | | (1,651 | ) | | (1,426 | ) |
Acquisitions, net of cash acquired | (5,991 | ) | | — |
| | (132 | ) |
Distributions from unconsolidated affiliates in excess of cumulative earnings | 42 |
| | 30 |
| | 297 |
|
Proceeds from sale of marketable securities | — |
| | 398 |
| | — |
|
Proceeds from sale of assets | 5 |
| | — |
| | — |
|
Purchase of investments | (6 | ) | | — |
| | — |
|
Other, net | 35 |
| | 16 |
| | 4 |
|
Net cash used in investing activities | (8,421 | ) | | (1,207 | ) | | (1,257 | ) |
Cash Flows from Financing Activities: | |
| | |
| | |
|
Increase (decrease) in short-term borrowings, net | — |
| | (39 | ) | | 4 |
|
Proceeds from (payments of) commercial paper, net | 1,891 |
| | (1,543 | ) | | 349 |
|
Proceeds from long-term debt, net | 2,916 |
| | 2,495 |
| | 1,096 |
|
Payments of long-term debt | (1,302 | ) | | (484 | ) | | (1,211 | ) |
Loss on reacquired debt | — |
| | — |
| | (5 | ) |
Debt and equity issuance costs | (20 | ) | | (47 | ) | | (13 | ) |
Payment of dividends on Common Stock | (577 | ) | | (499 | ) | | (461 | ) |
Payment of dividends on preferred stock | (118 | ) | | (11 | ) | | — |
|
Proceeds from issuance of Common Stock, net | — |
| | 1,844 |
| | — |
|
Proceeds from issuance of preferred stock, net | — |
| | 1,740 |
| | — |
|
Distribution to ZENS holders | — |
| | (398 | ) | | — |
|
Other, net | (14 | ) | | (5 | ) | | (4 | ) |
Net cash provided by (used in) financing activities | 2,776 |
| | 3,053 |
| | (245 | ) |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | (4,007 | ) | | 3,982 |
| | (85 | ) |
Cash, Cash Equivalents and Restricted Cash at Beginning of Year | 4,278 |
| | 296 |
| | 381 |
|
Cash, Cash Equivalents and Restricted Cash at End of Year | $ | 271 |
| | $ | 4,278 |
| | $ | 296 |
|
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
| (in millions) |
Cash Flows from Operating Activities: | | | | | |
Net income | $ | 1,486 | | | $ | (773) | | | $ | 791 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
Depreciation and amortization | 1,316 | | | 1,189 | | | 1,225 | |
| | | | | |
| | | | | |
| | | | | |
Deferred income taxes | 213 | | | (429) | | | 69 | |
Goodwill impairment and loss from reclassification to held for sale | — | | | 175 | | | 48 | |
Goodwill impairment | — | | | 185 | | | — | |
| | | | | |
Gain on Enable Merger | (681) | | | — | | | — | |
| | | | | |
Loss (gain) on equity securities | 172 | | | (49) | | | (282) | |
Loss (gain) on indexed debt securities | (50) | | | 60 | | | 292 | |
| | | | | |
Equity in (earnings) losses of unconsolidated affiliates | (339) | | | 1,428 | | | (230) | |
Distributions from unconsolidated affiliates | 155 | | | 113 | | | 261 | |
Pension contributions | (61) | | | (86) | | | (109) | |
Changes in other assets and liabilities, excluding acquisitions: | | | | | |
Accounts receivable and unbilled revenues, net | (98) | | | 90 | | | 226 | |
| | | | | |
Inventory | (140) | | | 9 | | | (52) | |
Taxes receivable | 81 | | | 24 | | | (106) | |
Accounts payable | 175 | | | 2 | | | (455) | |
| | | | | |
Net regulatory assets and liabilities | (2,295) | | | (107) | | | (22) | |
Other current assets and liabilities | 56 | | | 104 | | | (195) | |
Other assets and liabilities | (53) | | | 25 | | | 49 | |
Other operating activities, net | 85 | | | 35 | | | 128 | |
Net cash provided by operating activities | 22 | | | 1,995 | | | 1,638 | |
Cash Flows from Investing Activities: | | | | | |
Capital expenditures | (3,164) | | | (2,596) | | | (2,506) | |
Acquisitions, net of cash acquired | — | | | — | | | (5,991) | |
| | | | | |
Transaction costs related to Enable Merger (Note 4) | (49) | | | — | | | — | |
Cash received related to Enable Merger | 5 | | | — | | | — | |
Distributions from unconsolidated affiliates in excess of cumulative earnings | — | | | 80 | | | 42 | |
| | | | | |
| | | | | |
| | | | | |
Proceeds from sale of equity securities, net of transaction costs | 1,320 | | | — | | | — | |
Proceeds from divestitures (Note 4) | 22 | | | 1,215 | | | — | |
| | | | | |
| | | | | |
Other investing activities, net | 15 | | | 36 | | | 34 | |
Net cash used in investing activities | (1,851) | | | (1,265) | | | (8,421) | |
Cash Flows from Financing Activities: | | | | | |
Decrease in short-term borrowings, net | (27) | | | — | | | — | |
Payment of obligation for finance lease | (179) | | | — | | | — | |
Borrowings from revolving credit facilities | — | | | 1,050 | | | 135 | |
Repayments of revolving credit facilities | — | | | (1,050) | | | (135) | |
Proceeds from (payments of) commercial paper, net | 1,132 | | | (761) | | | 1,891 | |
Proceeds from long-term debt | 4,493 | | | 799 | | | 2,916 | |
Payments of long-term debt, including make-whole premiums | (2,968) | | | (1,724) | | | (1,302) | |
| | | | | |
| | | | | |
Payment of debt issuance costs | (38) | | | (8) | | | (20) | |
| | | | | |
Payment of dividends on Common Stock | (385) | | | (392) | | | (577) | |
Payment of dividends on Preferred Stock | (107) | | | (137) | | | (118) | |
Proceeds from issuance of Common Stock, net | — | | | 672 | | | — | |
Proceeds from issuance of Series C Preferred stock, net | — | | | 723 | | | — | |
| | | | | |
Other financing activities, net | (5) | | | (6) | | | (14) | |
Net cash provided by (used in) financing activities | 1,916 | | | (834) | | | 2,776 | |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | 87 | | | (104) | | | (4,007) | |
Cash, Cash Equivalents and Restricted Cash at Beginning of Year | 167 | | | 271 | | | 4,278 | |
Cash, Cash Equivalents and Restricted Cash at End of Year | $ | 254 | | | $ | 167 | | | $ | 271 | |
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY
| | | 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 |
| Shares | | Amount | | Shares | | Amount | | Shares | | Amount | | Shares | | Amount | | Shares | | Amount | | Shares | | Amount |
| (in millions of dollars and shares, except per share amounts) | | (in millions of dollars and shares, except authorized shares and per share amounts) |
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares | | | | | | | | | | | | Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares | |
Balance, beginning of year | 2 |
| | $ | 1,740 |
| | — |
| | $ | — |
| | — |
| | $ | — |
| Balance, beginning of year | 3 | | | $ | 2,363 | | | 2 | | | $ | 1,740 | | | 2 | | | $ | 1,740 | |
Issuances of Series A Preferred Stock | — |
| | — |
| | 1 |
| | 790 |
| | — |
| | — |
| |
Issuances of Series B Preferred Stock | — |
| | — |
| | 1 |
| | 950 |
| | — |
| | — |
| |
| Issuances of Series C Preferred Stock, net of issuance costs | | Issuances of Series C Preferred Stock, net of issuance costs | — | | | — | | | 1 | | | 723 | | | — | | | — | |
Conversion of Series B Preferred Stock and Series C Preferred Stock | | Conversion of Series B Preferred Stock and Series C Preferred Stock | (2) | | | (1,573) | | | — | | | (100) | | | — | | | — | |
Balance, end of year | 2 |
| | 1,740 |
| | 2 |
| | 1,740 |
| | — |
| | — |
| Balance, end of year | 1 | | | 790 | | | 3 | | | 2,363 | | | 2 | | | 1,740 | |
Common Stock, $0.01 par value; authorized 1,000,000,000 shares | |
| | |
| | |
| | |
| | |
| | |
| Common Stock, $0.01 par value; authorized 1,000,000,000 shares | | | | | | | | | | | |
Balance, beginning of year | 501 |
| | 5 |
| | 431 |
| | 4 |
| | 431 |
| | 4 |
| Balance, beginning of year | 551 | | | 6 | | | 502 | | | 5 | | | 501 | | | 5 | |
Issuances related to benefit and investment plans | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Issuances related to benefit and investment plans | 1 | | | — | | | 1 | | | — | | | 1 | | | — | |
Issuances of Common Stock | — |
| | — |
| | 70 |
| | 1 |
| | — |
| | — |
| Issuances of Common Stock | 77 | | | — | | | 48 | | | 1 | | | — | | | — | |
Balance, end of year | 502 |
| | 5 |
| | 501 |
| | 5 |
| | 431 |
| | 4 |
| Balance, end of year | 629 | | | 6 | | | 551 | | | 6 | | | 502 | | | 5 | |
Additional Paid-in-Capital | | | | | |
| | |
| | | | | Additional Paid-in-Capital | | | | | | | | | | | |
Balance, beginning of year | | | 6,072 |
| | |
| | 4,209 |
| | | | 4,195 |
| Balance, beginning of year | | 6,914 | | | | | 6,080 | | | 6,072 | |
Issuances related to benefit and investment plans | | | 8 |
| | |
| | 19 |
| | | | 14 |
| Issuances related to benefit and investment plans | | 41 | | | | | 30 | | | 8 | |
Issuances of Common Stock, net of issuance costs | | | — |
| | |
| | 1,844 |
| | | | — |
| Issuances of Common Stock, net of issuance costs | | 1 | | | | | 672 | | | — | |
Conversion of Series B Preferred Stock and Series C Preferred Stock | | Conversion of Series B Preferred Stock and Series C Preferred Stock | | 1,573 | | | 100 | | | — | |
Recognition of beneficial conversion feature | | Recognition of beneficial conversion feature | | — | | | 32 | | | — | |
Balance, end of year | | | 6,080 |
| | |
| | 6,072 |
| | | | 4,209 |
| Balance, end of year | | 8,529 | | | | | 6,914 | | | 6,080 | |
Retained Earnings (Accumulated Deficit) | | | |
| | |
| | |
| | | | |
| Retained Earnings (Accumulated Deficit) | | | | | | | | |
Balance, beginning of year | | | 349 |
| | |
| | 543 |
| | | | (668 | ) | Balance, beginning of year | | (845) | | | | | 632 | | | 349 | |
Net income | | | 791 |
| | |
| | 368 |
| | | | 1,792 |
| |
Common Stock dividends declared ($0.8625, $1.1200 and $1.3475 per share, respectively) | | | (433 | ) | | |
| | (523 | ) | | | | (581 | ) | |
Series A Preferred Stock dividends declared ($30.6250, $32.1563 and $-0- per share, respectively) | | | (24 | ) | | | | (26 | ) | | | | — |
| |
Series B Preferred Stock dividends declared ($52.5000, $29.1667 and $-0- per share, respectively) | | | (51 | ) | | | | (28 | ) | | | | — |
| |
Adoption of ASU 2018-02 | | | — |
| | | | 15 |
| | | | — |
| |
Net income (loss) | | Net income (loss) | | 1,486 | | | | | (773) | | | 791 | |
Common Stock dividends declared (see Note 13) | | Common Stock dividends declared (see Note 13) | | (404) | | | | | (480) | | | (433) | |
Series A Preferred Stock dividends declared (see Note 13) | | Series A Preferred Stock dividends declared (see Note 13) | | (49) | | | (73) | | | (24) | |
Series B Preferred Stock dividends declared (see Note 13) | | Series B Preferred Stock dividends declared (see Note 13) | | (34) | | | (85) | | | (51) | |
Series C Preferred Stock dividends declared (see Note 13) | | Series C Preferred Stock dividends declared (see Note 13) | | — | | | (27) | | | — | |
Amortization of beneficial conversion feature | | Amortization of beneficial conversion feature | | — | | | (32) | | | — | |
Adoption of ASU 2016-13 | | Adoption of ASU 2016-13 | | — | | | (7) | | | — | |
| Balance, end of year | | | 632 |
| | |
| | 349 |
| | | | 543 |
| Balance, end of year | | 154 | | | | | (845) | | | 632 | |
Accumulated Other Comprehensive Loss | | | |
| | |
| | |
| | | | |
| Accumulated Other Comprehensive Loss | | | | | | | | |
Balance, beginning of year | | | (108 | ) | | |
| | (68 | ) | | | | (71 | ) | Balance, beginning of year | | (90) | | | | | (98) | | | (108) | |
Other comprehensive income (loss) | | | 10 |
| | |
| | (25 | ) | | | | 3 |
| |
Adoption of ASU 2018-02 | | | — |
| | | | (15 | ) | | | | — |
| |
Other comprehensive income | | Other comprehensive income | | 26 | | | | | 8 | | | 10 | |
| Balance, end of year | | | (98 | ) | | |
| | (108 | ) | | | | (68 | ) | Balance, end of year | | (64) | | | | | (90) | | | (98) | |
Total Shareholders’ Equity | | | $ | 8,359 |
| | |
| | $ | 8,058 |
| | | | $ | 4,688 |
| Total Shareholders’ Equity | | $ | 9,415 | | | | | $ | 8,348 | | | $ | 8,359 | |
See Combined Notes to Consolidated Financial Statements
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Company’s auditor since 1932.