Utility Rate Regulation

6 Months Ended

Jun. 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
	June 30, 2022		December 31, 2021		June 30, 2022		December 31, 2021
Current Regulatory Assets:


Gas supply clause	$	44	$	21	$	—	$	—
Rate adjustment mechanisms	77		—		—		—
Smart meter rider	6		11		6		11
Fuel adjustment clause	47		11		—		—
Other	24		21		5		11
Total current regulatory assets	$	198	$	64	$	11	$	22

Noncurrent Regulatory Assets:
Defined benefit plans	$	603	$	523	$	241	$	256
Plant outage costs	49		54		—		—
Net metering	51		—		—		—
Environmental cost recovery	102		—		—		—
Taxes recoverable through future rates	50		—		—		—
Storm costs	146		11		—		—
Unamortized loss on debt	22		24		3		4
Interest rate swaps	10		18		—		—
Terminated interest rate swaps	67		70		—		—
Accumulated cost of removal of utility plant	226		228		226		228
AROs	309		302		—		—
Other	46		6		—		—
Total noncurrent regulatory assets	$	1,681	$	1,236	$	470	$	488


	PPL				PPL Electric
	June 30, 2022		December 31, 2021		June 30, 2022		December 31, 2021
Current Regulatory Liabilities:
Generation supply charge	$	12	$	10	$	12	$	10
Transmission service charge	14		21		14		21
Universal service rider	—		17		—		17
TCJA customer refund	20		22		20		22
Act 129 compliance rider	15		10		15		10
Transmission formula rate return on equity (a)	8		73		8		73
Economic relief billing credit	—		27		—		—
Derivative instruments	55		—		—		—
Rate adjustment mechanism	74		—		—		—
Energy efficiency	23		—		—		—
Other	20		2		—		—
Total current regulatory liabilities	$	241	$	182	$	69	$	153



Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	917	$	639	$	—	$	—
Power purchase agreement - OVEC	30		35		—		—
Net deferred taxes	1,857		1,591		513		531
Defined benefit plans	106		95		36		28
Terminated interest rate swaps	62		62		—		—
Energy efficiency	35		—		—		—
Other	49		—		—		—
Total noncurrent regulatory liabilities	$	3,056	$	2,422	$	549	$	559


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

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

Generation formula rate	—		—		2		2

Fuel adjustment clause	17		4		30		7

Other	3		5		1		—
Total current regulatory assets	$	52	$	33	$	33	$	9

Noncurrent Regulatory Assets:
Defined benefit plans	$	189	$	164	$	123	$	103
Storm costs	8		8		3		3
Unamortized loss on debt	12		12		7		8
Interest rate swaps	10		18		—		—
Terminated interest rate swaps	39		41		28		29
AROs	75		75		222		227
Plant outage costs	13		15		36		39
Other	9		4		11		2
Total noncurrent regulatory assets	$	355	$	337	$	430	$	411


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









Economic relief billing credit	$	—	$	21	$	—	$	6
Other	3		—		5		2
Total current regulatory liabilities	$	3	$	21	$	5	$	8

Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant	$	274	$	262	$	379	$	377

Power purchase agreement - OVEC	21		24		9		11
Net deferred taxes	483		491		559		569
Defined benefit plans	11		10		59		57

Terminated interest rate swaps	31		31		31		31

Total noncurrent regulatory liabilities	$	820	$	818	$	1,037	$	1,045

(a)See “Regulatory Matters - Federal Matters - PPL Electric Transmission Formula Rate Return on Equity” below 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 plus a full reconciliation of all costs and revenues for the current year including a reconciliation of forecasted revenue and costs for months of the current year for which actual data is not available at the time of the filing. Any projected amounts included in the energy efficiency charge filing are subject to reconciliation to actual amounts and any difference will be reflected in a future energy efficiency charge filing. 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 received in rates over RIE's actual site investigation and remediation costs.

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

On August 24, 2018, 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.

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 rate case settlement. 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 intends to withdraw the original AMF Updated Business Case and GMP and file a new AMF Business Case in September 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 and the matter is still pending with the RIPUC. If the RIPUC rules that RIE may not include a new main in rate base until it has completed the abandonment of the old main, the RIPUC may order an adjustment to the revenue requirement through the 2023 annual reconciliation process. Such a decision could cause a 1-year decline in the annual total for Capital Additions/ Plant In-Service. RIE cannot predict the outcome of this matter and an estimate of the impact cannot be determined. 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 six months ended June 30, 2021, PPL and PPL Electric recorded a revenue reduction on the Statement of Income of $17 million and $36 million after-tax representing an estimate of the revenue subject to refund from the date of the complaint through June 30, 2021. Of these amounts, $7 million and $13 million for the three and six months ended June 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 three and six months ended June 30, 2022, $30 million and $74 million of revenue was refunded to customers, respectively. 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 FERC's orders on the elimination of the mitigation and required transition mechanism. Oral arguments in the appellate proceeding occurred on February 14, 2022. LG&E and KU cannot predict the outcome of the respective appellate and FERC proceedings. 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 in future rate proceedings 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 six months ended June 30, 2022 was $14 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 six months ended June 30, 2022, PPL Electric purchased $273 million and $622 million of accounts receivable from alternative suppliers. During the three and six months ended June 30, 2021, PPL Electric purchased $250 million and $574 million of accounts receivable from alternative suppliers.