Regulatory Matters

12 Months Ended

Dec. 31, 2022

The following is a list of regulatory assets and liabilities, excluding amounts related to the Arkansas and Oklahoma Natural Gas businesses classified as held for sale as of December 31, 2021, reflected on the Registrants’ respective Consolidated Balance Sheets as of December 31, 2022 and 2021. For information about regulatory assets and liabilities in held for sale, see Note 4.


	December 31, 2022
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Benefit obligations (1)	$	392	$	—	$	5
Asset retirement obligations & other	237		64		155
Net deferred income taxes	83		34		40
Total future amounts recoverable from ratepayers	712		98		200
Amounts deferred for future recovery related to:
Extraordinary gas costs	1,073		—		1,073
Cost recovery riders	133		—		57
Hurricane and February 2021 Winter Storm Event restoration costs	129		113		16

Other regulatory assets	129		46		67
Gas recovery costs	108		—		108
Decoupling	3		—		3
COVID-19 incremental costs	13		8		5
TEEEF costs	182		182		—
Unrecognized equity return (2)	(54)		(27)		(5)
Total amounts deferred for future recovery	1,716		322		1,324
Amounts currently recovered in customer rates related to:
Authorized trackers and cost deferrals	499		25		369
Securitized regulatory assets	229		229		—
Unamortized loss on reacquired debt and hedging	88		64		12
Gas recovery costs	79		—		30
Extraordinary gas costs	294		—		294
Regulatory assets related to TCJA	47		47		—
Hurricane Harvey restoration costs	30		30		—
Benefit obligations	18		18		—
Unrecognized equity return (3)	(134)		(55)		(49)

Total amounts recovered in customer rates (4)	1,150		358		656
Total Regulatory Assets	$	3,578	$	778	$	2,180
Total Current Regulatory Assets (5)	$	1,385	$	—	$	1,336
Total Non-Current Regulatory Assets	$	2,193	$	778	$	844

Regulatory Liabilities:
Regulatory liabilities related to TCJA	$	1,436	$	716	$	536
Estimated removal costs	1,338		158		1,097
Other regulatory liabilities	496		281		193
Total Regulatory Liabilities	$	3,270	$	1,155	$	1,826
Total Current Regulatory Liabilities (6)	$	25	$	—	$	25
Total Non-Current Regulatory Liabilities	$	3,245	$	1,155	$	1,801


	December 31, 2021
	CenterPoint Energy		Houston Electric		CERC
	(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Benefit obligations (1)	$	412	$	—	$	5
Asset retirement obligations & other	240		45		171
Net deferred income taxes	41		29		5
Total future amounts recoverable from ratepayers	693		74		181
Amounts deferred for future recovery related to:
Extraordinary gas costs	1,528		—		1,517
Cost recovery riders	124		—		51
Hurricane and February 2021 Winter Storm Event restoration costs	105		105		—

Other regulatory assets	94		57		37
Gas recovery costs	29		—		29
Decoupling	25		—		25
COVID-19 incremental costs	23		8		15
TEEEF costs	21		21		—
Unrecognized equity return	(28)		(3)		(4)
Total amounts deferred for future recovery	1,921		188		1,670
Amounts currently recovered in customer rates related to:
Authorized trackers and cost deferrals	504		24		363
Securitized regulatory assets	420		420		—
Unamortized loss on reacquired debt and hedging	92		67		11
Gas recovery costs	72		—		59
Extraordinary gas costs	66		—		66
Regulatory assets related to TCJA	48		46		2
Hurricane Harvey restoration costs	43		43		—
Benefit obligations	28		24		4
Unrecognized equity return (3)	(171)		(97)		(47)

Total amounts recovered in customer rates	1,102		527		458
Total Regulatory Assets	$	3,716	$	789	$	2,309
Total Current Regulatory Assets (5)	$	1,395	$	—	$	1,371
Total Non-Current Regulatory Assets	$	2,321	$	789	$	938

Regulatory Liabilities:
Regulatory liabilities related to TCJA	$	1,389	$	738	$	573
Estimated removal costs	1,304		229		994
Other regulatory liabilities	481		205		149
Total Regulatory Liabilities	$	3,174	$	1,172	$	1,716
Total Current Regulatory Liabilities (6)	$	21	$	20	$	1
Total Non-Current Regulatory Liabilities	$	3,153	$	1,152	$	1,715

(1)Pension and postretirement-related regulatory assets balances are measured annually, and the ending amortization period may change based on the actuarial valuation.

(2)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on TEEEF costs and storm restoration costs; and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.

(3)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on its true-up balance of stranded costs, other changes and related interest resulting from the formerly integrated electric utilities prior to Texas deregulation to be recovered in rates through 2024 and certain storm restoration balances; and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.

(4)Of the $1.2 billion, $358 million and $656 million currently being recovered in customer rates related to CenterPoint Energy, Houston Electric and CERC, respectively, $390 million, $294 million and $96 million is earning a return, respectively. The weighted average recovery period of regulatory assets currently being recovered in base rates, not earning a return, which totals $531 million, $64 million and $424 million for CenterPoint Energy, Houston Electric and CERC, respectively, is 11 years, 28 years and 7 years, respectively. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the weighted average recovery period calculation.

(5)Current regulatory assets for both CenterPoint Energy and CERC include extraordinary gas costs of $1,175 million as of December 31, 2022 and $1,256 million and $1,245 million, respectively, as of December 31, 2021.

(6)Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.

The table below reflects the amount of allowed equity return recognized by each Registrant in its Statements of Consolidated Income:


	Year Ended December 31,
	2022						2021						2020
	CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC		CenterPoint Energy		Houston Electric		CERC
	(in millions)
Allowed equity return recognized	$	45	$	42	$	2	$	40	$	37	$	2	$	31	$	31	$	—

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 certain generating facilities not more than twenty-four months before the unit is retired. The Governor of Indiana signed the legislation on April 19, 2021. On May 10, 2022, CenterPoint Energy (Indiana Electric) filed an application with the IURC to securitize qualified costs associated with its planned retirements of coal generation facilities. Total qualified costs are estimated at $359 million, of which $350 million would be financed and $9 million are estimated total ongoing costs. A hearing was held before the IURC on September 7, 2022 and a final order was received on January 4, 2023 authorizing the issuance of up to $350 million in securitization bonds. As a result of this order, CenterPoint Energy will reclassify property, plant and equipment to be recovered through securitization to a regulatory asset during the first quarter of 2023.

February 2021 Winter Storm Event

In February 2021, certain of the Registrants’ jurisdictions experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted their businesses. 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. While demand for electricity reached extraordinary levels due to the extreme cold, the supply of electricity significantly decreased in part because of the inability of certain power generation facilities to supply electric power to the grid. Houston Electric does not own or operate any electric generation facilities other than TEEEF. Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. ERCOT serves as the independent system operator and regional reliability coordinator for member electric power systems in most of Texas. To comply with ERCOT’s orders, Houston Electric implemented controlled outages across its service territory, resulting in a substantial number of businesses and residents being without power, many for extended periods of time, in compliance with ERCOT’s directives as an emergency procedure to avoid prolonged large-scale state-wide blackouts and long-term damage to the electric system in Texas. In anticipation of this weather event, Houston Electric implemented its emergency operations plan’s processes and procedures necessary to respond to such events, including establishing an incident command center and calling for mutual assistance from other utilities where needed, among other measures. Throughout the February 2021 Winter Storm Event, Houston Electric remained in contact with its regulators and stakeholders, including federal, state and local officials, as well as the PUCT and ERCOT.

The February 2021 Winter Storm Event also impacted wholesale prices of CenterPoint Energy’s and CERC’s natural gas purchases and their ability to serve customers in their Natural Gas service territories, including due to the reduction in available natural gas capacity and impacts to CenterPoint Energy’s and CERC’s natural gas supply portfolio activities, and the effects of weather on their systems and their ability to transport natural gas, among other things. The overall natural gas market, including the markets from which CenterPoint Energy and CERC sourced a significant portion of their natural gas for their operations,

experienced significant impacts caused by the February 2021 Winter Storm Event, resulting in extraordinary increases in the price of natural gas purchased by CenterPoint Energy and CERC.

On February 13, 2021, the Railroad Commission authorized each Texas natural gas distribution utility to record in a regulatory asset the extraordinary expenses associated with the February 2021 Winter Storm Event, including, but not limited to, natural gas cost and other costs related to the procurement and transportation of natural gas supply, subject to recovery in future regulatory proceedings. The Texas governor signed legislation in June 2021 that authorizes the Railroad Commission to use securitization financing and the issuance of customer rate relief bonds for recovery of extraordinary natural gas costs incurred by natural gas utilities as a result of the February 2021 Winter Storm Event. On November 12, 2021, the RRC issued a Regulatory Asset Determination Order which authorized CERC to include $1.1 billion in a regulatory asset which should be included for recovery through customer rate relief bond financing. In addition, CenterPoint Energy’s and CERC’s Natural Gas utilities in jurisdictions outside of Texas deferred under-recovered natural gas cost as regulatory assets under existing recovery mechanisms and are seeking recovery of the increased cost of natural gas. As of December 31, 2022, both CenterPoint Energy and CERC have recorded current regulatory assets of $1,175 million and non-current regulatory assets of $202 million associated with the February 2021 Winter Storm Event. As of December 31, 2021, CenterPoint Energy and CERC have recorded current regulatory assets of $1,410 million and $1,399 million, respectively, of which $154 million related to Arkansas and Oklahoma are reflected as held for sale at both CenterPoint Energy and CERC, and non-current regulatory assets of $583 million and $583 million respectively, of which $244 million related to Arkansas and Oklahoma are reflected as held for sale at both CenterPoint Energy and CERC, associated with the February 2021 Winter Storm Event. See Note 4 for further information.

Amounts for the under recovery of natural gas costs associated with the February 2021 Winter Storm Event are reflected in current and non-current regulatory assets on CenterPoint Energy’s and CERC’s Condensed Consolidated Balance Sheets. Recovery of natural gas costs within the regulatory assets as of December 31, 2022 is probable and may be subject to customary regulatory prudence reviews in all jurisdictions that may impact the amounts ultimately recovered. CenterPoint Energy and CERC has approximately $75 million of the total $2 billion of natural gas costs incurred during the February 2021 Winter Storm Event remaining under prudence review. CenterPoint Energy and CERC have begun recovery of natural gas costs in Louisiana and Minnesota, and recovery of natural gas costs in Indiana and Mississippi is complete. CenterPoint Energy and CERC have filed for securitization of natural gas costs in Texas, received commission approval and issuance of a financing order in 2022, and expect the Texas Public Financing Authority to issue customer rate relief bonds in first half of 2023. As part of the closing of the sale of CenterPoint Energy’s and CERC’s Natural Gas businesses in Arkansas and Oklahoma, CERC received as part of the purchase price $398 million for unrecovered natural gas costs associated with the February 2021 Winter Storm Event. In Minnesota, testimonies were filed in CERC’s high gas cost prudency review case by intervenors proposing significant disallowances for all natural gas utilities and for CERC, ranging from $45 million to $409 million. The natural gas costs in Minnesota were incurred in accordance with the plan on file with the MPUC and CenterPoint Energy believes the costs were prudently incurred and are eligible for recovery. In May 2022, the administrative law judges reviewing the gas prudency case concluded that CERC acted prudently in connection with the February 2021 Winter Storm Event and recommended no disallowance of CERC’s jurisdictional gas costs incurred during the event. The commissioners of the MPUC heard oral arguments on the administrative law judges’ report and held deliberations in August 2022. At the deliberations, the MPUC generally found that CERC acted prudently, but it determined that CERC could have done more to offset costs with natural gas storage, peak shaving resources (LNG and propane-air) and curtailment of service to interruptible commercial/industrial customers. As a result, the MPUC disallowed recovery of approximately $36 million of the $409 million originally requested and CERC’s regulatory asset balance as of September 30, 2022 was reduced to reflect the disallowance. Other natural gas utilities in Minnesota received disallowances related to similar topics in a similar proportion to their gas costs. Further, the MPUC required all regulated natural gas utilities to make a filing explaining how they can improve or modify their practices to protect ratepayers from extraordinary natural gas price spikes in the future. CERC made its compliance filing on September 15, 2022. On October 19, 2022, the MPUC issued its written order. CERC filed a petition for reconsideration on November 8, 2022 and a written order denying the petition for reconsideration was issued on January 6, 2023.

As of both December 31, 2022 and 2021, as authorized by the PUCT, CenterPoint Energy and Houston Electric recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ default on their obligation to pay delivery charges to Houston Electric net of collateral. Additionally, as of December 31, 2022 and 2021, CenterPoint Energy and Houston Electric recorded a regulatory asset of $16 million and $15 million, respectively, to defer operations and maintenance costs associated with the February 2021 Winter Storm Event.

See Note 15(d) for further information regarding litigation related to the February 2021 Winter Storm Event.

Houston Electric TEEEF

Pursuant to legislation passed in 2021, Houston Electric entered into two leases for TEEEF (mobile generation) which are detailed in Note 20. Houston Electric sought initial recovery of the lease costs for the TEEEF and the operational costs for transportation, mobilization and demobilization, labor and materials for interconnections, fuel for commissioning, testing and operation, purchase and lease of auxiliary equipment, and labor and materials for operations in its 2022 DCRF application. Houston Electric filed its DCRF application with the PUCT on April 5, 2022, and subsequently amended such filing on July 1, 2022 to show mobile generation in a separate Rider TEEEF, seeking recovery of deferred costs and the applicable return as of December 31, 2021 under these lease agreements of approximately $200 million. The annual revenue increase requested for these lease agreements is approximately $57 million. Intervenors in the proceeding filed testimony on September 16, 2022 challenging the acquisition and deployment of TEEEF and have recommended disallowances based on the overall contractual obligations. Houston Electric’s rebuttal testimony was filed on October 5, 2022 responding to intervenor positions, including estimating a financial loss impact ranging from $335 million to $354 million if the PUCT disallows recovery of TEEEF costs and the termination clause under the long-term lease is exercised. The termination clause in the long-term lease agreement, as amended, contains certain provisions that allow Houston Electric to terminate the lease within a specific window effective between October 1, 2022, and December 31, 2023 based upon a material adverse regulatory action. Houston Electric’s exposure to loss in the event of a full disallowance of TEEEF related investments, and assuming Houston Electric is unable to exercise the termination clause prior to its expiration, includes the lease costs deferred as a regulatory asset and finance ROU assets further discussed in Note 20, in addition to the allowed return and other related costs incurred through the date of disallowance. On October 13, 2022, the PUCT staff filed a statement of position recommending a longer amortization period for the short-term lease, deferral of associated rate case expenses to the next base rate proceeding and exclusion of the retail transmission rate class from allocation of TEEEF costs. Houston Electric indicated to the PUCT staff that it did not oppose their recommendations. The PUCT staff also reserved the right to take positions on additional issues after consideration of the evidence admitted into the record at the hearing. A hearing was held on October 18 through 20, 2022. Briefs were filed on November 16, 2022 and reply briefs were filed on December 2, 2022. On January 27, 2023, the administrative law judges issued a proposal for decision recommending that the leasing of the TEEEF was not prudent or reasonable and necessary and that the PUCT deny recovery of all of the TEEEF costs. The PUCT is expected to consider the proposal for decision on March 9, 2023.

Houston Electric defers costs associated with the short-term and long-term leases that are probable of recovery and would otherwise be charged to expense in a regulatory asset, including allowed returns, and determined that such regulatory assets remain probable of recovery as of December 31, 2022. ROU finance lease assets, such as assets acquired under the long-term leases, are evaluated for impairment under the long-lived asset impairment model by assessing if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. Houston Electric continues to monitor the on-going proceedings and did not record any impairments on its right of use assets in the year ended December 31, 2022 or 2021. See Note 20 for further information.

COVID-19 Regulatory Matters

Governors, public utility commissions and other authorities in the states in which the Registrants operate have issued a number of different orders related to the COVID-19 pandemic, including orders addressing customer non-payment and disconnection. Although the disconnect moratoriums have expired in the Registrants’ service territories, CenterPoint Energy continues to support those customers who may need payment assistance, arrangements or extensions.

On March 26, 2020, the PUCT issued an order related to accrual of regulatory assets granting authority for utilities to record as a regulatory asset expenses resulting from the effects of COVID-19. In the order, the PUCT noted that it will consider whether a utility’s request for recovery of the regulatory asset is reasonable and necessary in a future proceeding.

Commissions in all of Indiana Electric’s and CenterPoint Energy’s and CERC’s Natural Gas service territories have either (1) issued orders to record a regulatory asset for incremental bad debt expenses related to COVID-19, including costs associated with the suspension of disconnections and payment plans or (2) provided authority to recover bad debt expense through an existing tracking mechanism. Both CenterPoint Energy and CERC have recorded estimated incremental uncollectible receivables to the associated regulatory asset of $17 million as of December 31, 2022, and $29 million and $28 million, respectively, as of December 31, 2021.

In some of the states in which the Registrants operate, public utility commissions have authorized utilities to employ deferred accounting authority for certain COVID-19 related costs which ensure the safety and health of customers, employees, and contractors, that would not have been incurred in the normal course of business. CERC’s Natural Gas service territory in Minnesota will include any offsetting savings in the deferral. Other jurisdictions where the Registrants operate may require

them to offset the deferral with savings as well. The Mississippi RRA, approved by final order dated August 2, 2022, included the unamortized balance of the regulatory asset as of December 31, 2021 in rate base per Docket No. 2018-AD-141 Order Authorizing Utility Response and Accounting for COVID-19. The Minnesota general rate case filing, approved by written order on September 23, 2022, included a request to recover the COVID-19 regulatory asset balance as of June 30, 2021 over a two-year amortization period. The Louisiana RSP’s requested recovery of COVID-19 regulatory assets over a one-year period concurrent with RSP implementation.