Utility Rate Regulation

9 Months Ended

Sep. 30, 2022

6. Utility Rate Regulation

(All Registrants)

The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.


	PPL				PPL Electric
	September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
Current Regulatory Assets:


Gas supply clause	$	60	$	21	$	—	$	—
Rate adjustment mechanisms	96		—		—		—
Smart meter rider	5		11		5		11
Universal service rider	8		—		8		—
Fuel adjustment clause	46		11		—		—
Other	19		21		—		11
Total current regulatory assets	$	234	$	64	$	13	$	22

Noncurrent Regulatory Assets:
Defined benefit plans	$	670	$	523	$	252	$	256
Plant outage costs	48		54		—		—
Net metering	52		—		—		—
Environmental cost recovery	104		—		—		—
Taxes recoverable through future rates	48		—		—		—
Storm costs	127		11		—		—
Unamortized loss on debt	24		24		3		4
Interest rate swaps	7		18		—		—
Terminated interest rate swaps	66		70		—		—
Accumulated cost of removal of utility plant	216		228		216		228
AROs	309		302		—		—
Other	44		6		—		—
Total noncurrent regulatory assets	$	1,715	$	1,236	$	471	$	488


	PPL				PPL Electric
	September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
Current Regulatory Liabilities:
Generation supply charge	$	19	$	10	$	19	$	10
Transmission service charge	10		21		10		21
Universal service rider	—		17		—		17
TCJA customer refund	25		22		25		22
Act 129 compliance rider	18		10		18		10
Transmission formula rate return on equity (a)	—		73		—		73
Economic relief billing credit	—		27		—		—
Transmission formula rate	11		—		11		—
Derivative instruments	71		—		—		—
Rate adjustment mechanism	77		—		—		—
Energy efficiency	23		—		—		—
RIE bill credit (b)	50		—		—		—
Other	25		2		4		—
Total current regulatory liabilities	$	329	$	182	$	87	$	153



Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	925	$	639	$	—	$	—
Power purchase agreement - OVEC	29		35		—		—
Net deferred taxes	2,112		1,591		783		531
Defined benefit plans	148		95		40		28
Terminated interest rate swaps	60		62		—		—
Energy efficiency	46		—		—		—
Other	61		—		—		—
Total noncurrent regulatory liabilities	$	3,381	$	2,422	$	823	$	559


	LG&E				KU
	September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
Current Regulatory Assets:

Gas supply clause	$	32	$	21	$	—	$	—
Gas line tracker	—		3		—		—

Generation formula rate	—		—		—		2

Fuel adjustment clause	16		4		30		7

Other	1		5		3		—
Total current regulatory assets	$	49	$	33	$	33	$	9

Noncurrent Regulatory Assets:
Defined benefit plans	$	203	$	164	$	135	$	103
Storm costs	7		8		3		3
Unamortized loss on debt	11		12		8		8
Interest rate swaps	7		18		—		—
Terminated interest rate swaps	38		41		27		29
AROs	76		75		221		227
Plant outage costs	13		15		35		39
Other	10		4		11		2
Total noncurrent regulatory assets	$	365	$	337	$	440	$	411


	LG&E				KU
	September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
Current Regulatory Liabilities:









Economic relief billing credit	$	—	$	21	$	—	$	6

Other	4		—		6		2
Total current regulatory liabilities	$	4	$	21	$	6	$	8

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	273	$	262	$	384	$	377

Power purchase agreement - OVEC	20		24		9		11
Net deferred taxes	480		491		552		569
Defined benefit plans	11		10		60		57

Terminated interest rate swaps	30		31		30		31

Total noncurrent regulatory liabilities	$	814	$	818	$	1,035	$	1,045

(a)See “Regulatory Matters - Federal Matters - PPL Electric Transmission Formula Rate Return on Equity” below for additional information.

(b)As a condition of the acquisition, RIE will provide a credit to all its electric and natural gas distribution customers in the total amount of $50 million. The credits are expected to be issued during the fourth quarter of 2022. See Note 8 for additional information.

Following is an overview of regulatory assets and liabilities detailed in the preceding tables which were recognized as a result of the acquisition of RIE. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."

Derivative Instruments

RIE evaluates open derivative instruments for regulatory deferral by determining if they are probable of recovery from, or refund to, customers through future rates. Derivative instruments that qualify for recovery are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. The balance is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.

Energy Efficiency

Represents the difference between revenue billed to customers through RIE's energy efficiency charge and the costs of the RIE’s energy efficiency programs as approved by the RIPUC.

The energy efficiency charge is designed to collect the estimated costs of the RIE’s energy efficiency plan for the upcoming calendar year. The final annual over/under is reconciled in the next year's energy efficiency plan filing, as part of the reconciliation factor calculation. RIE may file to change the EEP charge at any time should significant over-or under-recoveries occur.

Environmental Cost Recovery

The regulatory asset represents deferred costs associated with RIE's share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated. RIE's rate plans provide for specific rate allowances for these costs, with variances deferred for future recovery from, or return to, customers. RIE believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. The regulatory asset represents the excess of amounts incurred for RIE's actual site investigation and remediation costs versus amounts received in rates.

Net Metering

Net metering deferral reflects the recovery mechanism for costs associated with customer-installed on-site generation facilities, including the costs of renewable generation credits. This surcharge provides RIE with a mechanism to recover such amounts. Net metering is reconcilable annually, and any over- or under-recovery from customers will be refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

Rate Adjustment Mechanisms

In addition to commodity costs, RIE is subject to a number of additional rate adjustment mechanisms whereby an asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the RIPUC. The rate adjustment mechanisms are reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.

Taxes Recoverable through Future Rates

Taxes recoverable through future rates represent the portion of future income taxes that will be recovered through future rates based upon established regulatory practices. Accordingly, this regulatory asset is recognized when the offsetting deferred tax liability is recognized. For general-purpose financial reporting, this regulatory asset and the deferred tax liability are not offset; rather, each is displayed separately. This regulatory asset is expected to be recovered over the period that the underlying book-tax timing differences reverse and the actual cash taxes are incurred.

Regulatory Matters

Rhode Island Activities (PPL)

Rate Case proceedings

At its August 24, 2018 Open Meeting, and subsequently memorialized pursuant to Report and Order No. 23823 issued May 5, 2020, the RIPUC approved the terms of an Amended Settlement Agreement (ASA), reflecting an allowed return on equity (ROE) rate of 9.275% based on a common equity ratio of approximately 51%. RIE is currently in year four of the multi-year rate plan (Rate Plan). On June 30, 2021, the Rhode Island Division of Public Utilities and Carriers consented to an open-ended extension of the term of the Rate Plan such that RIE was not required to file its next rate case in order for new rates take effect no later than September 1, 2022 as originally contemplated by the ASA. Pursuant to the settlement with the Rhode Island Office of the Attorney General in connection with the acquisition of RIE by PPL, RIE currently does not anticipate filing a new base rate case until at least three years following the closing of the acquisition. Pursuant to the open-ended extension, the Rate Year 3 level of base distribution rates under ASA will remain in effect and RIE will continue to operate under the current Rate Plan until a new Rate Plan is approved by the RIPUC.

The ASA includes additional provisions, including (i) an Electric Transportation Initiative (the ET Initiative) to facilitate the growth of Electric Vehicle (EV) adoption and scaling of the market for EV charging equipment to advance Rhode Island's zero emission vehicles and greenhouse gas emissions policy goals, which the RIPUC is continuing to review in connection with certain underspending in the ET Initiative and the timing of crediting customers the deferral balance pursuant to the ASA, (ii) two energy storage demonstration projects, which are on track for timely completion, (iii) a new incentive-only performance incentive for System Efficiency: Annual Megawatt (MW) Capacity Savings, which sunsets in 2021 and requires a tariff advice filing with the RIPUC to extend, and (iv) several additional metrics for tracking and reporting purposes only. The RIPUC discussed the ET Initiative at an Open Meeting on August 30, 2022, advising the Company to seek RIPUC authorization to continue the ET Initiative and/or to alter any of the targets established in the ASA for Rate Year 5 and beyond. No votes or official rulings were taken; however, based on this feedback, RIE has paused the ET programs in Rate Year 5.

Advanced Metering Functionality and Grid Modernization

On January 21, 2021, RIE filed its Updated Advance Metering Functionality (AMF) Business Case and Grid Modernization Plan (GMP) with the RIPUC in accordance with the ASA. The Updated AMF Business Case – a foundational component of the GMP – seeks approval to deploy smart meters throughout the service territory. Pursuant to the written order issued on July 14, 2021, the RIPUC stayed the AMF and GMP proceedings pending further consideration following the issuance of a final Order by the Rhode Island Division of Public Utilities and Carriers on the Acquisition. RIE filed notice of withdrawal of the original Updated AMF Business Case and GMP with RIPUC on September 12, 2022 and intends to file a new AMF Business Case in November 2022, followed by a new GMP in December 2022.

COVID-19 Deferral Filing

On April 30, 2021, RIE filed a petition for approval to recognize regulatory assets related to COVID-19 Impacts (RIPUC Docket No. 5154). In its Petition, RIE seeks the RIPUC's authorization to create regulatory assets and consideration of future

cost recovery for the following COVID-19 Costs: (1) the increased cost of customer accounts receivable that RIE will be unable to collect as a result of the COVID-19 pandemic, and the executive orders and RIPUC orders restricting RIE's collection activities as a result of the pandemic, which will result in increased net charge-offs; (2) lost revenue from unassessed late payment charges; and (3) charges to RIE for other fees that RIE has waived pursuant to the RIPUC's orders in RIPUC Docket No. 5022. The RIPUC has not taken any action on the filing to date and RIE is continuing to monitor the docket. RIE intends to evaluate its request to create a regulatory asset for COVID-19-related bad debt expense to consider the impact, if any, of the proposed arrearage forgiveness sought in RIE’s Petition to Forgive Certain Arrearage Balances for Low-Income and Protected Customers in Docket No. 22-08-GE, which RIE filed with the RIPUC to fulfill its obligations under PPL's settlement with the Rhode Island Attorney General.

FY 2023 Gas Infrastructure, Safety and Reliability (ISR) Plan

At an Open Meeting on March 29, 2022, the RIPUC conditionally approved RIE’s FY 2023 Gas ISR Plan and associated revenue requirement, subject to further review regarding RIE’s Proactive Main Replacement Program and its decision to reconstruct and purchase heating and pressure regulation equipment located at RIE’s Wampanoag and Tiverton take stations. Regarding the Proactive Main Replacement Program, the Chair of the RIPUC questioned whether the new main should be deemed "used and useful" and, hence, placed into rate base before the old main is fully abandoned. Currently, the new main is deemed "in-service" once the pipe is installed and gassed in. The RIPUC held a hearing on June 1, 2022 to further review RIE's lag in performance in replacing mains, including reasons for the lag, ratemaking implications, and the "used and useful" standard. RIE responded to several record requests following the hearing. The RIPUC held an Open Meeting on September 13, 2022, regarding the Proactive Main Replacement Program and made the following rulings: (1) commencing with the Gas ISR plan to be filed in this calendar year 2022 (prospectively), new main constructed to replace leak prone pipe will not be considered used and useful, and therefore not eligible for rate base treatment, until the related old main is abandoned; and (2) approved the proactive main replacement revenue requirement set forth in the FY23 Gas ISR plan, thereby closing out the potential that this portion of the revenue requirement might be subject to refund. Also, the RIPUC directed RIE to submit prefiled testimony on the issue of its replacement of heating and pressure regulation facilities at the Wampanoag and Tiverton take stations and to address three issues, specifically: (i) a cost-benefit analysis arising from RIE's decision to take ownership of the reconstructed take station equipment; (ii) the potential that the benefits derived from the reconstruction and ownership transfer of the take station equipment will not be realized due to the future use of hydrogen or abandonment of the gas system; and (iii) the depreciation and accounting treatment of the reconstructed take station equipment. RIE filed this testimony with the RIPUC on May 16, 2022 and this issue is still pending before the RIPUC.

Federal Matters

PPL Electric Transmission Formula Rate Return on Equity (PPL and PPL Electric)

In May 2020, PP&L Industrial Customer Alliance (PPLICA) filed a complaint with the FERC alleging that PPL Electric's base ROE used to determine PPL Electric’s formula transmission rate was unjust and unreasonable. In August 2021, PPL Electric entered into a settlement agreement (the Settlement) with PPLICA and all other parties, including intervenors. The key aspects of the Settlement include changes to PPL Electric’s base ROE, changes to the equity component of PPL Electric's capital structure, allowing modification of the current rate year to a calendar year and allowing modification of the current formula rate based on a historic test year to a projected test year. The settlement was approved by the FERC in November 2021. The interim rates reflecting the agreed-to-base ROE in the Settlement were effective December 1, 2021.

In the three and nine months ended September 30, 2021, PPL and PPL Electric recorded a revenue reserve of $13 million ($10 million after-tax) and $64 million ($46 million after-tax) representing revenue subject to refund from the date of the complaint through June 30, 2021. Of these amounts, $28 million ($20 million after-tax) for the nine months ended September 30, 2021, related to the period from May 21, 2020 to December 31, 2020.

As of December 31, 2021, PPL and PPL Electric had a regulatory liability on the Balance Sheet of $73 million, which represents revenue subject to refund based on the difference between charges that were calculated using the ROE in effect at the time and charges calculated using the revised ROE provided for in the Settlement, plus interest at the FERC interest rate. During the nine months ended September 30, 2022, $74 million of revenue was refunded to customers. The total balance at December 31, 2021, plus additional interest recorded was refunded to customers by May 31, 2022.

FERC Transmission Rate Filing (PPL, LG&E and KU)

In 2018, LG&E and KU applied to the FERC requesting elimination of certain on-going credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the D.C. Circuit Court of Appeals regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. On August 4, 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. LG&E and KU cannot predict the outcome of the proceedings at the FERC on remand. LG&E and KU currently receive recovery of the waivers and credits provided through other rate mechanisms and such rate recovery would be anticipated to be adjusted consistent with potential changes or terminations of the waivers and credits, as such become effective.

Recovery of Transmission Costs (PPL)

On an interim basis, RIE's transmission facilities continue to be operated in combination with the transmission facilities of National Grid's New England affiliates, Massachusetts Electric Company (MECO) and NEP, as a single integrated system with NEP designated as the combined operator. NEP collects the costs of the combined transmission asset pool including a return on those facilities under NEP's Tariff No. 1 from the ISO. The ISO allocates these costs among transmission customers in New England, in accordance with the ISO Open Access Transmission Tariff (ISO-NE OATT).

According to the FERC orders, RIE is compensated for its actual monthly transmission costs, with its authorized maximum ROE of 11.74% on its transmission assets. The amount remitted by NEP to RIE for the three and nine months ended September 30, 2022 was $44 million and $58 million.

The ROE for transmission rates under the ISO-NE OATT is the subject of four complaints that are pending before the FERC. On October 16, 2014, the FERC issued an order on the first complaint, Opinion No. 531-A, resetting the base ROE applicable to transmission assets under the ISO-NE OATT from 11.14% to 10.57% effective as of October 16, 2014 and establishing a maximum ROE of 11.74%. On April 14, 2017, this order was vacated and remanded by the District of Columbia Circuit (Court of Appeals). After the remand, the FERC issued an order on October 16, 2018 applicable to all four pending cases where it proposed a new base ROE methodology that, with subsequent input and support from the New England Transmission Owners (NETO), yielded a base ROE of 10.41%. Subsequent to the FERC's October 2018 order in the New England Transmission Owners cases, the FERC further refined its ROE methodology in another proceeding and has applied that refined methodology to transmission owners’ ROEs in other jurisdictions, and the NETOs filed further information in the New England matters to distinguishing their case. Those determinations in other jurisdictions are currently on appeal before the Court of Appeals. The proceeding and the final base rate ROE determination in the New England matters remain open, pending a final order from the FERC. PPL cannot predict the outcome of this matter, and an estimate of the impact cannot be determined.

Other

Purchase of Receivables Program (PPL and PPL Electric)

In accordance with a PAPUC-approved purchase of accounts receivable program, PPL Electric purchases certain accounts receivable from alternative electricity suppliers at a discount, which reflects a provision for uncollectible accounts. The alternative electricity suppliers have no continuing involvement or interest in the purchased accounts receivable. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. During the three and nine months ended September 30, 2022, PPL Electric purchased $352 million and $974 million of accounts receivable from alternative suppliers. During the three and nine months ended September 30, 2021, PPL Electric purchased $309 million and $883 million of accounts receivable from alternative suppliers.