Combined Notes to Condensed Financial Statements (Unaudited)
Index to Combined Notes to Condensed Financial Statements
The notes to the condensed financial statements that follow are a combined presentation. The following list indicates the Registrants to which the notes apply:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Registrant |
| | PPL | | PPL Electric | | LG&E | | KU |
| 1. Interim Financial Statements | | x | | x | | x | | x |
| | | | | | | | |
| 2. Segment and Related Information | | x | | x | | x | | x |
| 3. Revenue from Contracts with Customers | | x | | x | | x | | x |
| 4. Earnings Per Share | | x | | | | | | |
| 5. Income Taxes | | x | | x | | x | | x |
| 6. Utility Rate Regulation | | x | | x | | x | | x |
| 7. Financing Activities | | x | | x | | x | | x |
| | | | | | | | |
| 8. Acquisitions, Development and Divestitures | | x | | | | | | |
| 9. Defined Benefits | | x | | x | | x | | x |
| 10. Commitments and Contingencies | | x | | x | | x | | x |
| 11. Related Party Transactions | | | | x | | x | | x |
| 12. Other Income (Expense) - net | | x | | x | | | | |
| 13. Fair Value Measurements | | x | | x | | x | | x |
| 14. Derivative Instruments and Hedging Activities | | x | | x | | x | | x |
| 15. Asset Retirement Obligations | | x | | | | x | | x |
| 16. Accumulated Other Comprehensive Income (Loss) | | x | | | | | | |
| | | | | | | | |
1. Interim Financial Statements
(All Registrants)
Capitalized terms and abbreviations appearing in the unaudited combined notes to condensed financial statements are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted. The specific Registrant to which disclosures are applicable is identified in parenthetical headings in italics above the applicable disclosure or within the applicable disclosure for each Registrant's related activities and disclosures. Within combined disclosures, amounts are disclosed for any Registrant when significant.
The accompanying unaudited condensed financial statements have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and, therefore, do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation in accordance with GAAP are reflected in the condensed financial statements. All adjustments are of a normal recurring nature, except as otherwise disclosed. Each Registrant's Balance Sheet at December 31, 2021 is derived from that Registrant's 2021 audited Balance Sheet. The financial statements and notes thereto should be read in conjunction with the financial statements and notes contained in each Registrant's 2021 Form 10-K. The results of operations for the three and six months ended June 30, 2022 are not necessarily indicative of the results to be expected for the full year ending December 31, 2022 or other future periods, because results for interim periods can be disproportionately influenced by various factors, developments and seasonal variations.
(PPL)
On March 17, 2021, PPL WPD Limited entered into a share purchase agreement to sell PPL's U.K. utility business, which prior to its sale substantially represented PPL's U.K. Regulated segment, to a subsidiary of National Grid plc. The sale was completed on June 14, 2021. The results of operations of the U.K. utility business are classified as Discontinued Operations on PPL's Statements of Income for the three and six months ended June 30, 2021. PPL has elected to separately report the cash flows of
continuing and discontinued operations on the Statements of Cash Flows for the six months ended June 30, 2021. Unless otherwise noted, the notes to these financial statements exclude amounts related to discontinued operations. See Note 8 for additional information.
On May 25, 2022, PPL Rhode Island Holdings, a subsidiary of PPL, acquired 100% of the outstanding shares of common stock of Narragansett Electric from National Grid USA (National Grid U.S.), a subsidiary of National Grid plc (the Acquisition). The results of Narragansett Electric are included in the consolidated results of PPL from the date of the Acquisition. Following the closing of the Acquisition, Narragansett Electric provides services doing business under the name Rhode Island Energy (RIE). See Note 8 for additional information.
2. Segment and Related Information
(PPL)
PPL is organized into three segments: Kentucky Regulated, Pennsylvania Regulated and Rhode Island Regulated. PPL's segments are segmented by geographic location.
The Kentucky Regulated segment consists primarily of LG&E's and KU's regulated electricity generation, transmission and
distribution operations, as well as LG&E's regulated distribution and sale of natural gas.
The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric.
The Rhode Island Regulated segment includes the regulated electricity transmission and distribution and natural gas distribution operations of RIE, which were acquired on May 25, 2022.
"Corporate and Other" primarily includes financing costs incurred at the corporate level that have not been allocated or assigned to the segments, certain other unallocated costs, certain non-recoverable costs resulting from commitments made to the Rhode Island Division of Public Utilities and Carriers and the Attorney General of the State of Rhode Island in conjunction with the acquisition of Narragansett Electric and the financial results of Safari Energy, which is presented to reconcile segment information to PPL's consolidated results.
As a result of the June 14, 2021 sale of the U.K. utility business, PPL determined segment information for the U.K.
Regulated segment would no longer be provided beginning with the March 31, 2021 Form 10-Q. See Note 8 for additional information.
Income Statement data for the segments and reconciliation to PPL's consolidated results for the periods ended June 30 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| | | | | | | |
| Operating Revenues from external customers | | | | | | | |
| Kentucky Regulated | $ | 883 | | | $ | 741 | | | $ | 1,887 | | | $ | 1,626 | |
| Pennsylvania Regulated | 676 | | | 537 | | | 1,451 | | | 1,142 | |
| Rhode Island Regulated | 128 | | | — | | | 128 | | | — | |
| Corporate and Other | 9 | | | 10 | | | 12 | | | 18 | |
| Total | $ | 1,696 | | | $ | 1,288 | | | $ | 3,478 | | | $ | 2,786 | |
| | | | | | | |
| Net Income (Loss) | | | | | | | |
| | | | | | | |
| Kentucky Regulated | $ | 102 | | | $ | 84 | | | $ | 281 | | | $ | 230 | |
| Pennsylvania Regulated | 124 | | | 96 | | | 267 | | | 209 | |
| Rhode Island Regulated | (29) | | | — | | | (29) | | | — | |
| Corporate and Other | (78) | | | (716) | | | (127) | | | (772) | |
| Discontinued Operations (a) | — | | | 555 | | | — | | | (1,488) | |
| Total | $ | 119 | | | $ | 19 | | | $ | 392 | | | $ | (1,821) | |
(a)See Note 8 for additional information on the sale of the U.K. utility business.
The following provides Balance Sheet data for the segments and reconciliation to PPL's consolidated Balance Sheets as of:
| | | | | | | | | | | |
| June 30,
2022 | | December 31,
2021 |
| Assets | | | |
| Kentucky Regulated | $ | 16,454 | | | $ | 16,360 | |
| Pennsylvania Regulated | 13,361 | | | 13,336 | |
| Rhode Island Regulated | 5,819 | | | — | |
| Corporate and Other (a) | 1,428 | | | 3,527 | |
| Total | $ | 37,062 | | | $ | 33,223 | |
(a)Primarily consists of unallocated items, including cash, PP&E, goodwill, the elimination of inter-segment transactions as well as the assets of Safari Energy.
(PPL Electric, LG&E and KU)
PPL Electric has two operating segments, distribution and transmission, which are aggregated into a single reportable segment. LG&E and KU are individually single operating and reportable segments.
3. Revenue from Contracts with Customers
(All Registrants)
See Note 3 in the Registrants' 2021 Form 10-K for a discussion of the principal activities from which PPL Electric, LG&E and KU and PPL’s Pennsylvania Regulated and Kentucky Regulated segments generate their revenues.
(PPL)
Rhode Island Regulated Segment Revenues
The Rhode Island Regulated segment generates substantially all of its revenues from contracts with customers from RIE’s regulated tariff-based transmission and distribution of electricity and regulated tariff-based distribution of natural gas.
Distribution Revenue
Distribution revenues are primarily from the sale of electricity, natural gas, and related services to retail customers. Distribution sales are regulated by the RIPUC, which is responsible for approving the rates and other terms of services as part of the rate making process. Natural gas and electric distribution revenues are derived from the regulated sale and distribution of electricity and natural gas to residential, commercial, and industrial customers within RIE’s service territory under the tariff rates. The performance obligation related to distribution sales is to provide electricity and natural gas to customers on demand. The performance obligation is satisfied over time because the customer simultaneously receives and consumes the electricity or natural gas as services are provided. RIE records revenues related to the distribution sales based upon the approved tariff rate and the volume delivered to the customers, which corresponds with the amount RIE has the right to invoice.
Distribution revenue also includes estimated unbilled amounts, which represent the estimated amounts due from retail customers as a result of customer's bills rendered throughout the month, rather than bills being rendered at the end of the month. Unbilled revenues are determined based on estimated unbilled sales volumes for the respective customer classes and then applying the applicable tariff rate to those volumes. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. This method of recognition fairly presents RIE's transfer of electricity and natural gas to the customer as the amount recognized is based on actual and estimated volumes delivered and the tariff rate per unit of energy and any applicable fixed charges or regulatory mechanisms as approved by the respective regulatory body.
Certain customers have the option to obtain electricity or natural gas from other suppliers. In those circumstances, revenue is only recognized for providing delivery of the commodity to the customer.
Transmission Revenue
RIE’s transmission services are regulated by the FERC and coordinated with Independent System Operator (ISO) – New England (ISO-NE). Additionally, RIE makes available its transmission facilities to NEP, for operation and control pursuant to an integrated facilities agreement, Service Agreement No. 23 (Integrated Facilities Agreement or IFA). These revenues arise under tariff/rate agreements and are collected primarily from RIE’s Rhode Island distribution customers. The revenue is recognized over-time as transmission services are provided and consumed. This method of recognition fairly presents RIE’s transfer of transmission services as the daily rate is set by a FERC-approved formula-based rate.
(All Registrants)
The following tables reconcile "Operating Revenues" included in each Registrant's Statement of Income with revenues generated from contracts with customers for the periods ended June 30.
| | | | | | | | | | | | | | | | | | | | | | | |
| 2022 Three Months |
| PPL | | PPL Electric | | LG&E | | KU |
| Operating Revenues (a) | $ | 1,696 | | | $ | 676 | | | $ | 410 | | | $ | 491 | |
| Revenues derived from: | | | | | | | |
| Alternative revenue programs (b) | (40) | | | (23) | | | 3 | | | 1 | |
| Other (c) | (6) | | | (3) | | | (2) | | | (2) | |
| Revenues from Contracts with Customers | $ | 1,650 | | | $ | 650 | | | $ | 411 | | | $ | 490 | |
| |
| 2021 Three Months |
| PPL | | PPL Electric | | LG&E | | KU |
| Operating Revenues (a) | $ | 1,288 | | | $ | 537 | | | $ | 342 | | | $ | 411 | |
| Revenues derived from: | | | | | | | |
| Alternative revenue programs (b) | 19 | | | 24 | | | (1) | | | (4) | |
| Other (c) | (5) | | | — | | | (2) | | | (3) | |
| Revenues from Contracts with Customers | $ | 1,302 | | | $ | 561 | | | $ | 339 | | | $ | 404 | |
| | | | | | | |
| 2022 Six Months |
| PPL | | PPL Electric | | LG&E | | KU |
| Operating Revenues (a) | $ | 3,478 | | | $ | 1,451 | | | $ | 903 | | | $ | 1,016 | |
| Revenues derived from: | | | | | | | |
| Alternative revenue programs (b) | (67) | | | (59) | | | 9 | | | 4 | |
| Other (c) | (13) | | | (7) | | | (4) | | | (3) | |
| Revenues from Contracts with Customers | $ | 3,398 | | | $ | 1,385 | | | $ | 908 | | | $ | 1,017 | |
| |
| 2021 Six Months |
| PPL | | PPL Electric | | LG&E | | KU |
| Operating Revenues (a) | $ | 2,786 | | | $ | 1,142 | | | $ | 770 | | | $ | 880 | |
| Revenues derived from: | | | | | | | |
| Alternative revenue programs (b) | 43 | | | 46 | | | (1) | | | (2) | |
| Other (c) | (11) | | | — | | | (5) | | | (6) | |
| Revenues from Contracts with Customers | $ | 2,818 | | | $ | 1,188 | | | $ | 764 | | | $ | 872 | |
(a)PPL includes $128 million for the three and six months ended June 30, 2022 of revenues from external customers reported by the Rhode Island Regulated segment. PPL Electric represents revenues from external customers reported by the Pennsylvania Regulated segment and LG&E and KU, net of intercompany power sales and transmission revenues, represent revenues from external customers reported by the Kentucky Regulated segment. See Note 2 for additional information.
(b)This line item shows the over/under collection of rate mechanisms deemed alternative revenue programs with over-collections of revenue shown as positive amounts in the table above and under-collections shown as negative amounts. For PPL Electric, the three and six months ended June 30, 2022, include $30 million and $74 million related to the amortization of the regulatory liability primarily recorded in 2021 for a reduction in the transmission formula rate return on equity that is reflected in rates in 2022. The three and six months ended June 30, 2021, included a $24 million and $51 million revenue reduction recorded as a result of the challenge to the transmission formula rate return on equity. See Note 6 for additional information.
(c)Represents additional revenues outside the scope of revenues from contracts with customers, such as lease and other miscellaneous revenues.
The following tables show revenues from contracts with customers disaggregated by customer class for the periods ended June 30.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months |
| Residential | | Commercial | | Industrial | | Other (a) | | Wholesale - municipality | | Wholesale - other (b) | | Transmission | | Revenues from Contracts with Customers |
| | | | | | | | | | | | | | | |
| PPL | | | | | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | | | | |
| PA Regulated | $ | 329 | | | $ | 117 | | | $ | 30 | | | $ | 14 | | | $ | — | | | $ | — | | | $ | 160 | | | $ | 650 | |
| KY Regulated | 339 | | | 251 | | | 167 | | | 93 | | | 8 | | | 26 | | | — | | | 884 | |
| RI Regulated | 31 | | | 12 | | | 1 | | | 47 | | | — | | | — | | | 16 | | | 107 | |
| Corp and Other | — | | | — | | | — | | | 9 | | | — | | | — | | | — | | | 9 | |
| Total PPL | $ | 699 | | | $ | 380 | | | $ | 198 | | | $ | 163 | | | $ | 8 | | | $ | 26 | | | $ | 176 | | | $ | 1,650 | |
| | | | | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | | | | |
| PA Regulated | $ | 279 | | | $ | 83 | | | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 173 | | | $ | 561 | |
| KY Regulated | 288 | | | 214 | | | 141 | | | 70 | | | 5 | | | 13 | | | — | | | 731 | |
| RI Regulated | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Corp and Other | — | | | — | | | — | | | 10 | | | — | | | — | | | — | | | 10 | |
| Total PPL | $ | 567 | | | $ | 297 | | | $ | 154 | | | $ | 93 | | | $ | 5 | | | $ | 13 | | | $ | 173 | | | $ | 1,302 | |
| | | | | | | | | | | | | | | |
| PPL Electric | | | | | | | | | | | | | | | |
| 2022 | $ | 329 | | | $ | 117 | | | $ | 30 | | | $ | 14 | | | $ | — | | | $ | — | | | $ | 160 | | | $ | 650 | |
| 2021 | $ | 279 | | | $ | 83 | | | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 173 | | | $ | 561 | |
| | | | | | | | | | | | | | | |
| LG&E | | | | | | | | | | | | | | | |
| 2022 | $ | 169 | | | $ | 124 | | | $ | 49 | | | $ | 47 | | | $ | — | | | $ | 22 | | | $ | — | | | $ | 411 | |
| 2021 | $ | 144 | | | $ | 107 | | | $ | 43 | | | $ | 31 | | | $ | — | | | $ | 14 | | | $ | — | | | $ | 339 | |
| | | | | | | | | | | | | | | |
| KU | | | | | | | | | | | | | | | |
| 2022 | $ | 170 | | | $ | 127 | | | $ | 118 | | | $ | 45 | | | $ | 8 | | | $ | 22 | | | $ | — | | | $ | 490 | |
| 2021 | $ | 144 | | | $ | 107 | | | $ | 98 | | | $ | 39 | | | $ | 5 | | | $ | 11 | | | $ | — | | | $ | 404 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months |
| Residential | | Commercial | | Industrial | | Other (a) | | Wholesale - municipality | | Wholesale - other (b) | | Transmission | | Revenues from Contracts with Customers |
| | | | | | | | | | | | | | | |
| PPL | | | | | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | | | | |
| PA Regulated | $ | 782 | | | $ | 225 | | | $ | 45 | | | $ | 26 | | | $ | — | | | $ | — | | | $ | 307 | | | $ | 1,385 | |
| KY Regulated | 817 | | | 521 | | | 321 | | | 176 | | | 14 | | | 45 | | | — | | | 1,894 | |
| RI Regulated | 31 | | | 12 | | | 1 | | | 47 | | | — | | | — | | | 16 | | | 107 | |
| Corp and Other | — | | | — | | | — | | | 12 | | | — | | | — | | | — | | | 12 | |
| Total PPL | $ | 1,630 | | | $ | 758 | | | $ | 367 | | | $ | 261 | | | $ | 14 | | | $ | 45 | | | $ | 323 | | | $ | 3,398 | |
| | | | | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | | | | |
| PA Regulated | $ | 640 | | | $ | 165 | | | $ | 25 | | | $ | 25 | | | $ | — | | | $ | — | | | $ | 333 | | | $ | 1,188 | |
| KY Regulated | 701 | | | 445 | | | 281 | | | 141 | | | 11 | | | 33 | | | — | | | 1,612 | |
| RI Regulated | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Corp and Other | — | | | — | | | — | | | 18 | | | — | | | — | | | — | | | 18 | |
| Total PPL | $ | 1,341 | | | $ | 610 | | | $ | 306 | | | $ | 184 | | | $ | 11 | | | $ | 33 | | | $ | 333 | | | $ | 2,818 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six Months |
| Residential | | Commercial | | Industrial | | Other (a) | | Wholesale - municipality | | Wholesale - other (b) | | Transmission | | Revenues from Contracts with Customers |
| | | | | | | | | | | | | | | |
| PPL Electric | | | | | | | | | | | | | | | |
| 2022 | $ | 782 | | | $ | 225 | | | $ | 45 | | | $ | 26 | | | $ | — | | | $ | — | | | $ | 307 | | | $ | 1,385 | |
| 2021 | $ | 640 | | | $ | 165 | | | $ | 25 | | | $ | 25 | | | $ | — | | | $ | — | | | $ | 333 | | | $ | 1,188 | |
| | | | | | | | | | | | | | | |
| LG&E | | | | | | | | | | | | | | | |
| 2022 | $ | 415 | | | $ | 270 | | | $ | 94 | | | $ | 86 | | | $ | — | | | $ | 43 | | | $ | — | | | $ | 908 | |
| 2021 | $ | 349 | | | $ | 228 | | | $ | 89 | | | $ | 65 | | | $ | — | | | $ | 33 | | | $ | — | | | $ | 764 | |
| | | | | | | | | | | | | | | |
| KU | | | | | | | | | | | | | | | |
| 2022 | $ | 402 | | | $ | 251 | | | $ | 227 | | | $ | 89 | | | $ | 14 | | | $ | 34 | | | $ | — | | | $ | 1,017 | |
| 2021 | $ | 352 | | | $ | 217 | | | $ | 192 | | | $ | 76 | | | $ | 11 | | | $ | 24 | | | $ | — | | | $ | 872 | |
(a)Primarily includes revenues from pole attachments, street lighting, other public authorities and other non-core businesses. The Rhode Island Regulated segment also includes open access revenues.
(b)Includes wholesale power and transmission revenues. LG&E and KU amounts include intercompany power sales and transmission revenues, which are eliminated upon consolidation at the Kentucky Regulated segment.
As discussed in Note 2, PPL segments its business by geographic location. Revenues from external customers for each segment/geographic location are reconciled to revenues from contracts with customers in the footnotes to the tables above.
Contract receivables from customers are primarily included in "Accounts receivable - Customer", "Unbilled revenues", and "Other noncurrent assets" on the Balance Sheets.
The following table shows the accounts receivable and unbilled revenues balances that were impaired for the periods ended June 30.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months | | Six Months |
| 2022 | | 2021 | | 2022 | | 2021 |
| PPL | $ | 25 | | | $ | — | | | $ | 33 | | | $ | 2 | |
| PPL Electric | — | | | — | | | 5 | | | 1 | |
| LG&E | 1 | | | — | | | 2 | | | — | |
| KU | 1 | | | — | | | 2 | | | 1 | |
The following table shows the balances and certain activity of contract liabilities resulting from contracts with customers.
| | | | | | | | | | | | | | | | | | | | | | | |
| PPL | | PPL Electric | | LG&E | | KU |
Contract liabilities at December 31, 2021 | $ | 42 | | | $ | 25 | | | $ | 6 | | | $ | 6 | |
Contract liabilities at June 30, 2022 | 33 | | | 16 | | | 6 | | | 5 | |
Revenue recognized during the six months ended June 30, 2022 that was included in the contract liability balance at December 31, 2021 | 24 | | | 12 | | | 6 | | | 6 | |
| | | | | | | |
Contract liabilities at December 31, 2020 | $ | 40 | | | $ | 23 | | | $ | 5 | | | $ | 6 | |
Contract liabilities at June 30, 2021 | 31 | | | 16 | | | 5 | | | 5 | |
Revenue recognized during the six months ended June 30, 2021 that was included in the contract liability balance at December 31, 2020 | 23 | | | 11 | | | 5 | | | 6 | |
Contract liabilities result from recording contractual billings in advance for customer attachments to the Registrants' infrastructure and payments received in excess of revenues earned to date. Advanced billings for customer attachments are generally recognized as revenue ratably over the quarterly billing period. Payments received in excess of revenues earned to date are recognized as revenue as services are delivered in subsequent periods.
At June 30, 2022, PPL had $43 million of performance obligations attributable to Corporate and Other that have not been satisfied. Of this amount, PPL expects to recognize approximately $27 million within the next 12 months.
4. Earnings Per Share
(PPL)
Basic EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding during the applicable period. Diluted EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding, increased by incremental shares that would be outstanding if potentially dilutive share-based payment awards were converted to common shares as calculated using the Two-Class Method or Treasury Stock Method.
Reconciliations of the amounts of income and shares of PPL common stock (in thousands) for the periods ended June 30 used in the EPS calculation are:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Income (Numerator) | | | | | | | |
| | | | | | | |
| | | | | | | |
| Income (Loss) from continuing operations after income taxes available to PPL common shareowners - Basic and Diluted | $ | 119 | | | $ | (536) | | | $ | 392 | | | $ | (333) | |
| | | | | | | |
| Income (Loss) from discontinued operations (net of income taxes) available to PPL common shareowners - Basic and Diluted | $ | — | | | $ | 555 | | | $ | — | | | $ | (1,488) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Net income (loss) available to PPL common shareowners - Basic and Diluted | $ | 119 | | | $ | 19 | | | $ | 392 | | | $ | (1,821) | |
| | | | | | | |
| Shares of Common Stock (Denominator) | | | | | | | |
| Weighted-average shares - Basic EPS | 735,977 | | | 769,466 | | | 735,741 | | | 769,313 | |
| | | | | | | |
| Add: Dilutive share-based payment awards | 792 | | | — | | | 737 | | | — | |
| | | | | | | |
| Weighted-average shares - Diluted EPS | 736,769 | | | 769,466 | | | 736,478 | | | 769,313 | |
| | | | | | | |
| Basic and Diluted EPS | | | | | | | |
| Available to PPL common shareowners: | | | | | | | |
| Income (Loss) from continuing operations after income taxes | $ | 0.16 | | | $ | (0.69) | | | $ | 0.53 | | | $ | (0.44) | |
| Loss from discontinued operations (net of income taxes) | — | | | 0.72 | | | — | | | (1.93) | |
| Net Income (Loss) available to PPL common shareowners | $ | 0.16 | | | $ | 0.03 | | | $ | 0.53 | | | $ | (2.37) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
For the periods ended June 30, PPL issued shares of common stock related to stock-based compensation plans as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Stock-based compensation plans | — | | | 137 | | | 124 | | | 657 | |
| | | | | | | |
See Note 7 for common stock repurchased under an authorized share repurchase program.
For the periods ended June 30, the following shares (in thousands) were excluded from the computations of diluted EPS because the effect would have been antidilutive.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months |
| 2022 | | 2021 | | 2022 | | 2021 |
| Stock-based compensation awards | 66 | | | 3,443 | | | 110 | | | 1,838 | |
5. Income Taxes
Reconciliations of income tax expense (benefit) for the periods ended June 30 are as follows.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| (PPL) |
| Three Months | | Six Months |
| 2022 | | 2021 | | 2022 | | 2021 |
| Federal income tax on Income from Continuing Operations Before Income Taxes at statutory tax rate - 21% | $ | 32 | | | $ | (40) | | | $ | 104 | | | $ | 15 | |
| Increase (decrease) due to: | | | | | | | |
| State income taxes, net of federal income tax benefit | 27 | | | (18) | | | 48 | | | (5) | |
| Valuation allowance adjustments (a) | 7 | | | 26 | | | 10 | | | 34 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Impact of the U.K. Finance Acts on deferred tax balances (b) | — | | | 383 | | | — | | | 383 | |
| | | | | | | |
| Amortization of investment tax credit including deferred taxes on basis adjustment | (4) | | | — | | | (7) | | | (1) | |
| Depreciation and other items not normalized | (5) | | | (2) | | | (8) | | | (4) | |
| Amortization of excess deferred federal and state income taxes | (22) | | | (8) | | | (40) | | | (20) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Other | (3) | | | 4 | | | (1) | | | 2 | |
| Total increase (decrease) | — | | | 385 | | | 2 | | | 389 | |
| Total income tax expense (benefit) | $ | 32 | | | $ | 345 | | | $ | 106 | | | $ | 404 | |
(a)In June 2021, PPL recorded a $25 million state deferred tax benefit on a net operating loss and an offsetting valuation allowance in connection with the loss on extinguishment associated with a tender offer to purchase and retire PPL Capital Funding's outstanding Senior Notes.
(b)The U.K. Finance Act 2021, formally enacted on June 10, 2021, increased the U.K. corporation tax rate from 19% to 25%, effective April 1, 2023. The primary impact of the corporation tax rate increase was an increase in deferred tax liabilities of the U.K. utility business, which was sold on June 14, 2021, and a corresponding deferred tax expense of $383 million, which was recognized in continuing operations.
| | | | | | | | | | | | | | | | | | | | | | | |
| (PPL Electric) | | | | | | | |
| Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 35 | | | $ | 27 | | | $ | 76 | | | $ | 59 | |
| Increase (decrease) due to: | | | | | | | |
| State income taxes, net of federal income tax benefit | 13 | | | 10 | | | 28 | | | 22 | |
| | | | | | | |
| Depreciation and other items not normalized | (3) | | | (2) | | | (6) | | | (4) | |
| Amortization of excess deferred federal and state income taxes | (2) | | | (3) | | | (5) | | | (6) | |
| | | | | | | |
| | | | | | | |
| Other | 1 | | | 2 | | | 1 | | | — | |
| Total increase (decrease) | 9 | | | 7 | | | 18 | | | 12 | |
| Total income tax expense (benefit) | $ | 44 | | | $ | 34 | | | $ | 94 | | | $ | 71 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| (LG&E) | | | | | | | |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 13 | | | $ | 12 | | | $ | 37 | | | $ | 32 | |
| Increase (decrease) due to: | | | | | | | |
| State income taxes, net of federal income tax benefit | 2 | | | 2 | | | 7 | | | 6 | |
| | | | | | | |
| Amortization of excess deferred federal and state income taxes | (7) | | | (3) | | | (14) | | | (6) | |
| | | | | | | |
| | | | | | | |
| Other | 1 | | | 1 | | | (2) | | | (1) | |
| Total increase (decrease) | (4) | | | — | | | (9) | | | (1) | |
| Total income tax expense (benefit) | $ | 9 | | | $ | 12 | | | $ | 28 | | | $ | 31 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| (KU) | | | | | | | |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 17 | | | $ | 15 | | | $ | 45 | | | $ | 37 | |
| Increase (decrease) due to: | | | | | | | |
| State income taxes, net of federal income tax benefit | 3 | | | 3 | | | 8 | | | 7 | |
| | | | | | | |
| Amortization of excess deferred federal and state income taxes | (6) | | | (4) | | | (12) | | | (8) | |
| | | | | | | |
| | | | | | | |
| Other | 1 | | | (1) | | | (2) | | | (2) | |
| Total increase (decrease) | (2) | | | (2) | | | (6) | | | (3) | |
| Total income tax expense (benefit) | $ | 15 | | | $ | 13 | | | $ | 39 | | | $ | 34 | |
Other
Narragansett Electric Acquisition (PPL)
The acquisition of Narragansett Electric was deemed an asset acquisition for federal and state income tax purposes, as a result of PPL and National Grid making a tax election under Internal Revenue Code (IRC) §338(h)(10). Accordingly, the tax basis of substantially all of the assets acquired were increased to fair market value, which equaled net book value, thereby eliminating the related deferred tax assets and liabilities. The tax goodwill will be amortized for tax purposes over 15 years.
Pennsylvania State Tax Reform (PPL and PPL Electric)
On July 8, 2022, the Governor of Pennsylvania signed into law Pennsylvania House Bill 1342 (H.B. 1342). Among other changes to the state tax code, the bill will reduce the corporate net income tax rate from 9.99% to 8.99% beginning January 1, 2023, and reduces annually by half a percentage point until the rate reaches 4.99% in 2031.
GAAP requires that deferred tax assets and liabilities be measured at the enacted tax rate expected to apply when temporary book-to-tax differences are expected to be realized or settled. Accordingly, in the third quarter of 2022, PPL expects to record the impact of the reduced tax rate as a reduction in the accumulated deferred income taxes related to regulated operations in an amount between $200 million and $300 million, with a corresponding increase in regulatory liabilities. In addition, PPL expects to recognize a deferred tax benefit of between $3 million and $7 million primarily associated with the remeasurement of accumulated deferred income tax balances related to non-regulated operations.
The foregoing numbers are estimates that will be updated quarterly to reflect revised forecast, actual activity, and orders from regulatory authorities.
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.
7. Financing Activities
Credit Arrangements and Short-term Debt
(All Registrants)
The Registrants maintain credit facilities to enhance liquidity, provide credit support and act as a backstop to commercial paper programs. For reporting purposes, on a consolidated basis, PPL's arrangements listed below include the credit facilities and commercial paper programs of PPL Electric, LG&E and KU. The amounts listed in the borrowed column below are recorded as "Short-term debt" on the Balance Sheets. The following credit facilities were in place at:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | Expiration
Date | | Capacity | | Borrowed | | Letters of
Credit
and
Commercial
Paper
Issued | | Unused
Capacity | | Borrowed | | Letters of
Credit
and
Commercial
Paper
Issued |
| PPL | | | | | | | | | | | | | |
| PPL Capital Funding (a) | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2026 | | $ | 1,250 | | | $ | — | | | $ | 256 | | | $ | 994 | | | $ | — | | | $ | — | |
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| Bilateral Credit Facility | Mar. 2023 | | 100 | | | — | | | — | | | 100 | | | — | | | — | |
| Bilateral Credit Facility (b) | Mar. 2023 | | 100 | | | — | | | 60 | | | 40 | | | — | | | 15 | |
| Total PPL Capital Funding Credit Facilities | | | $ | 1,450 | | | $ | — | | | $ | 316 | | | $ | 1,134 | | | $ | — | | | $ | 15 | |
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| PPL Electric | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2026 | | $ | 650 | | | $ | — | | | $ | 1 | | | $ | 649 | | | $ | — | | | $ | 1 | |
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| LG&E | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2026 | | $ | 500 | | | $ | — | | | $ | 394 | | | $ | 106 | | | $ | — | | | $ | 69 | |
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| KU | | | | | | | | | | | | | |
| Syndicated Credit Facility | Dec. 2026 | | $ | 400 | | | $ | — | | | $ | 338 | | | $ | 62 | | | $ | — | | | $ | — | |
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(a)PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL.
(b)Includes a $45 million letter of credit on behalf of RIE.
(PPL, LG&E and KU)
In March 2022, PPL Capital Funding amended and restated its two existing $50 million bilateral credit facilities to extend the termination dates from March 9, 2022 to March 6, 2023 and to increase the borrowing capacity under each facility to $100 million.
In July 2022, LG&E entered into a $300 million term loan credit facility expiring in 2024. On July 29, 2022, LG&E borrowed $300 million under this facility at an initial interest rate of 3.23%. The per annum interest rate fluctuates based on the applicable secured overnight financing rate plus a spread. The proceeds will be used to repay short-term debt and for general corporate purposes.
In July 2022, KU entered into a $300 million term loan credit facility expiring in 2024. On July 29, 2022, KU borrowed $300 million under this facility at an initial interest rate of 3.23%. The per annum interest rate fluctuates based on the applicable secured overnight financing rate plus a spread. The proceeds will be used to repay short-term debt and for general corporate purposes.
(All Registrants)
PPL Capital Funding, PPL Electric, LG&E and KU maintain commercial paper programs to provide an additional financing source to fund short-term liquidity needs. Commercial paper issuances, included in "Short-term debt" on the Balance Sheets, are supported by the respective Registrant's credit facilities. The following commercial paper programs were in place at:
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| | June 30, 2022 | | December 31, 2021 |
| Weighted -
Average
Interest Rate | | Capacity | | Commercial
Paper
Issuances | | Unused
Capacity | | Weighted -
Average
Interest Rate | | Commercial
Paper
Issuances |
| PPL Capital Funding (a) | 1.19% | | $ | 1,350 | | | $ | 256 | | | $ | 1,094 | | | | | $ | — | |
PPL Electric | | | 650 | | | — | | | 650 | | | | | — | |
| LG&E | 1.20% | | 425 | | | 394 | | | 31 | | | 0.31% | | 69 | |
| KU | 1.21% | | 350 | | | 338 | | | 12 | | | | | — | |
| Total | | | $ | 2,775 | | | $ | 988 | | | $ | 1,787 | | | | | $ | 69 | |
(a)PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL.
(PPL Electric, LG&E, and KU)
See Note 11 for discussion of intercompany borrowings.
(PPL)
Long-term Debt
As a result of the acquisition of Narragansett Electric on May 25, 2022, PPL assumed approximately $1.5 billion of long-term debt. The following was outstanding at June 30, 2022:
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| | Weighted-Average
Rate (a) | | Maturities (a) | | June 30, 2022 |
| RIE | | | | | |
| Senior Unsecured Notes | 4.10 | % | | 2028 - 2042 | | $ | 1,500 | |
| Senior Secured Notes/First Mortgage Bonds (b) | 8.27 | % | | 2022 - 2025 | | 16 | |
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| Total Long-term Debt before adjustments | | | | | 1,516 | |
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| Unamortized debt issuance costs | | | | | (6) | |
| Total Long-term Debt | | | | | 1,510 | |
| Less current portion of Long-term Debt | | | | | 14 | |
| Total Long-term Debt, noncurrent | | | | | $ | 1,496 | |
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(a)The table reflects principal maturities only, based on stated maturities or earlier put dates, and the weighted-average rates as of June 30, 2022.
(b)Includes first mortgage bonds with an annual sinking fund requirement of $750,000 through maturity in 2025.
The aggregate maturities of long-term debt, based on stated maturities or earlier put dates, for the periods 2022 through 2026 and thereafter are as follows:
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| RIE |
| 2022 | $ | 14 | |
| 2023 | 1 | |
| 2024 | 1 | |
| 2025 | 1 | |
| 2026 | — | |
| Thereafter | 1,499 | |
| Total | $ | 1,516 | |
Equity Securities
Share Repurchase
In August 2021, PPL's Board of Directors authorized share repurchases of up to $3 billion of PPL common shares. In 2021, PPL repurchased approximately $1 billion of PPL common shares. There were no share repurchases during the three and six months ended June 30, 2022. The actual additional amounts to be repurchased pursuant to this authority will depend on various factors, including PPL’s share price and market conditions. PPL may purchase shares on each trading day subject to market conditions and principles of best execution.
Dividends
In June 2022, PPL declared a quarterly common stock dividend, payable July 1, 2022, of 22.5 cents per share (equivalent to 90.0 cents per annum).
Preferred Stock
RIE has $3 million of certain issues of non-participating cumulative preferred stock outstanding that can be redeemed at the option of RIE. There are no mandatory redemption provisions on the cumulative preferred stock. Dividends on the cumulative preferred stock accrue quarterly and are prior to any dividends on the common stock of RIE. Pursuant to the preferred stock arrangement, as long as any preferred stock is outstanding, certain restrictions on payment of common stock dividends would come into effect if the common stock equity of RIE was, or by reason of payment of such dividends became, less than 25% of total capitalization of RIE. RIE was current on the preferred stock dividends and was in compliance with this covenant and accordingly, was not restricted as to the payment of common stock dividends under the foregoing provisions as of June 30, 2022.
8. Acquisitions, Development and Divestitures
(PPL)
Acquisitions
Acquisition of Narragansett Electric
On May 25, 2022, PPL Rhode Island Holdings acquired 100% of the outstanding shares of common stock of Narragansett Electric from National Grid U.S., a subsidiary of National Grid plc (the Acquisition). Narragansett Electric, whose service area covers substantially all of Rhode Island, is primarily engaged in the transmission and distribution of natural gas and electricity. The Acquisition expands PPL's portfolio of regulated natural gas and electricity transmission and distribution assets and is expected to improve credit metrics and enhance long term earnings growth. Following the closing of the Acquisition, Narragansett Electric provides services doing business under the name Rhode Island Energy (RIE).
The consideration for the Acquisition consisted of approximately $3.8 billion in cash and approximately $1.5 billion of long-term debt assumed through the transaction. The fair value of the consideration paid for Narragansett Electric was as follows (in billions):
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| Aggregate enterprise consideration | | | | | | $ | 5.3 | |
| Less: fair value of assumed long-term debt outstanding | | | | | | 1.5 | |
| Total cash consideration | | | | | | $ | 3.8 | |
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The $3.8 billion total cash consideration paid was funded with proceeds from PPL's 2021 sale of its U.K. utility business.
In connection with the Acquisition, National Grid USA Service Company, Inc., National Grid U.S. and Narragansett Electric have entered into a transition services agreement (TSA), pursuant to which National Grid has agreed to provide certain transition services to Narragansett Electric to facilitate the transition of the operation of Narragansett Electric to PPL following the Acquisition, as agreed upon in the Narragansett SPA. The TSA is for an initial two-year term and is subject to extension as necessary to complete the successful transition. TSA costs of $18 million were incurred for the three and six-month periods ended June 30, 2022.
Acquisition Approval
The Acquisition required certain approvals or waivers, including, among others, approval of National Grid USA's shareholders, authorizations or waivers from the Rhode Island Division of Public Utilities and Carriers, the Massachusetts Department of Public Utilities, the Federal Communications Commission (FCC), and the FERC, as well as review under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. All such approvals were received prior to closing of the Acquisition.
Commitments to the Rhode Island Division of Public Utilities and Carriers and the Attorney General of the State of Rhode Island
As a condition to the Acquisition, PPL made certain commitments to the Rhode Island Division of Public Utilities and Carriers and the Attorney General of the State of Rhode Island. As a result:
•RIE will provide a credit to all of its electric and natural gas distribution customers in the total amount of $50 million. Based on the relative number of electric distribution customers and natural gas distribution customers, RIE expects to credit $33 million to electric customers and $17 million to natural gas customers. Each electric customer will receive the same credit, and each natural gas customer will receive the same credit. On July 12, 2022, the RIPUC voted to suspend the tariff advice for bill credits for 60 days to allow more time to issue discovery on the filing. These credits will reduce revenue in future periods when the credits are issued.
•RIE will forgive approximately $44 million ($21 million net of allowance for doubtful accounts) in arrearages for low-income and protected residential customers, which represents 100% of the arrearages over 90 days for those customers as of March 31, 2022. PPL deemed these accounts uncollectible and fully reserved for them in the second quarter of 2022, resulting in an increase to "Other operations and maintenance expense" of $23 million for the three and six-month periods ended June 30, 2022.
•RIE will not file a base rate case seeking an increase in base distribution rates for natural gas and/or electric service sooner than three years from the Acquisition date, and RIE will not submit a request for a change in base rates unless and until there is at least twelve months of operating experience under PPL's exclusive leadership and after the TSA with National Grid terminates.
•RIE will forgo potential recovery of any and all transition costs which PPL estimates will be approximately $408 million through June 30, 2024 and includes (1) the installation of certain information technology systems; (2) modification and enhancements to physical facilities in Rhode Island; and (3) incurring costs related to severance payments, communications and branding changes, and other transition related costs. These costs will be expensed as incurred. These costs were $74 million and $101 million for the three and six-month periods ended June 30, 2022.
•RIE will not seek to recover any transaction costs related to the Acquisition, which were $27 million through June 30, 2022, including $16 million and $18 million for the three and six-month periods ended June 30, 2022 which were recorded in "Other operations and maintenance expense."
•RIE will not seek to recover in rates any markup charged by National Grid U.S. and/or its affiliates under the TSA. These amounts were immaterial as of June 30, 2022.
•In June 2022, RIE expensed $20 million of regulatory assets as of the Acquisition date for the Gas Business Enablement (GBE) project and for certain Cybersecurity/IT investments related to GBE. The expense was recorded to "Other operations and maintenance expense" on the income statement for the three and six months ended June 30, 2022. RIE will not seek to recover these regulatory assets from customers in any future proceedings.
•RIE will exclude all goodwill from the ratemaking capital structure.
•RIE will hold harmless Rhode Island customers from any changes to Accumulated Deferred Income Taxes (ADIT) as a result of the Acquisition. RIE reserves the right to seek rate adjustments based on future changes to ADIT that are not related to the Acquisition.
•RIE will not increase its revenue requirement to a level higher than what would exist in the absence of the Acquisition as a result of any restatement of pension and other post-retirement benefits plan assets and liabilities to fair value after the close of the Acquisition.
•Rhode Island Holdings will contribute $2.5 million to the Rhode Island Commerce Corporation's Renewable Energy Fund and not use any of the $2.5 million to meet its pre-existing renewable energy credit goals in Rhode Island or any other state. This contribution was made during the quarter ended June 30, 2022 and was recorded in "Other Income (Expense)."
•RIE will make available up to $2.5 million for the Rhode Island Attorney General to utilize as needed in evaluating PPL's report on RIE's specific decarbonization goals to support Rhode Island's 2021 Act on Climate or to assess the future of the gas distribution business in Rhode Island. This amount was accrued during the quarter ended June 30, 2022 and was recorded in "Other Income (Expense)."
•Various other operational and reporting commitments have been established.
Purchase Price Allocation
The operations of Narragansett Electric are subject to the accounting for certain types of regulation as prescribed by GAAP. The carrying value of Narragansett Electric’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets acquired or liabilities assumed, nor the unaudited pro forma financial information presented below, reflect any adjustments related to these amounts.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was $1,581 million, which has been recorded as goodwill. PPL has elected to not push down the effects of purchase accounting to the financial statements of RIE or PPL's Rhode Island Regulated segment. Accordingly, the Rhode Island Regulated segment includes $725 million of legacy goodwill acquired. The remaining excess purchase price of $856 million is being included in PPL's Corporate and Other category for segment reporting purposes. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the ability of PPL to leverage its assembled workforce to take advantage of those growth opportunities and the attractiveness of stable, growing cash flows. The tax goodwill will be deductible for income tax purposes, and as such, deferred taxes will be recorded related to goodwill.
The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed that were recorded in PPL’s Consolidated Balance Sheet at the Acquisition date. The allocation is subject to change during the one-year measurement period as additional information is obtained about the facts and circumstances that existed at closing. The items pending finalization include, but are not limited to, final working capital adjustments and the valuation of defined benefit plans. As a result, the amount of goodwill included below may change by a material amount as PPL finalizes the allocation of the purchase price.
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| | | | | | May 25, 2022 |
| Assets | | | | | | |
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| Current Assets | | | | | | |
| Cash and Cash Equivalents | | | | | | $ | 142 | |
| Accounts Receivable (a) | | | | | | 195 | |
| Unbilled Revenues | | | | | | 54 | |
| Price Risk Management Assets | | | | | | 99 | |
| Regulatory Assets | | | | | | 75 | |
| Other Current Assets | | | | | | 65 | |
| Total Current Assets | | | | | | 630 | |
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| | | | | | May 25, 2022 |
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| Noncurrent Assets | | | | | | |
| Property, Plant and Equipment, net | | | | | | 3,990 | |
| Regulatory Assets | | | | | | 437 | |
| Goodwill | | | | | | 1,581 | |
| Other Noncurrent Assets | | | | | | 134 | |
| Total Noncurrent Assets | | | | | | 6,142 | |
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| Total Assets | | | | | | $ | 6,772 | |
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| Liabilities | | | | | | |
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| Current Liabilities | | | | | | |
| Long-Term Debt Due Within One Year | | | | | | $ | 14 | |
| Accounts Payable | | | | | | 183 | |
| Taxes Accrued | | | | | | 44 | |
| Regulatory Liabilities | | | | | | 237 | |
| Other Current Liabilities | | | | | | 198 | |
| Total Current Liabilities | | | | | | 676 | |
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| Noncurrent Liabilities | | | | | | |
| Long-Term Debt | | | | | | 1,496 | |
| Regulatory Liabilities | | | | | | 628 | |
| Other Deferred Credits and Noncurrent Liabilities | | | | | | 150 | |
| Noncurrent Liabilities | | | | | | 2,274 | |
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| Total Purchase Price (Balance Sheet Net Assets) | | | | | | $ | 3,822 | |
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(a) Amounts represent fair value as of May 25, 2022. The gross contractual amount is $255 million. Cash flows not expected to be collected as of May 25, 2022 are $60 million.
Pro Forma Financial Information
The actual RIE Operating Revenues and Net income attributable to PPL included in PPL's Statement of Income for the period ended June 30, 2022, and PPL's unaudited pro forma 2022 and 2021 Operating Revenues and Net Income (Loss) attributable to PPL, including RIE, as if the Acquisition had occurred on January 1, 2021 are as follows.
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| | | | | | Operating Revenues | | Net Income (Loss) |
| Actual RIE results included from May 25, 2022 - June 30, 2022 (a) | | | | | | $ | 128 | | | $ | (29) | |
| PPL Pro Forma for the six months ended 2022 | | | | | | 4,203 | | | 456 | |
| PPL Pro Forma for the six months ended 2021 | | | | | | 3,588 | | | (259) | |
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(a)Net Income (Loss) includes expenses of $48 million (pre-tax) related to commitments made as a condition of the Acquisition.
The pro forma financial information presented above has been derived from the historical consolidated financial statements of PPL and Narragansett Electric. Non-recurring items included in the 2022 pro forma financial information include: (a) $18 million (pre-tax) of transaction costs related to the Acquisition, primarily for advisory, accounting and legal fees incurred, (b) $101 million (pre-tax) of Acquisition integration costs, (c) write-offs of $43 million (pre-tax) of certain accounts receivable and regulatory assets of RIE and $5 million (pre-tax) of expenses accrued in support of Rhode Island's decarbonization goals, all of which were conditions of the Acquisition, and (d) the income tax effect of these items, which was tax effected at the statutory federal income tax rate of 21%.
Non-recurring items included in the 2021 pro forma financial information include: (a) $10 million (pre-tax) of Acquisition integration costs and (b) the income tax effect of this item, which was tax effected at the statutory federal income tax rate of 21%. Losses from the discontinued operations (net of income taxes) of PPL of $1,488 million in 2021 were excluded from the pro forma amount above.
Discontinued Operations
Sale of the U.K. Utility Business
On June 14, 2021, PPL WPD Limited completed the sale of PPL's utility business to National Grid Holdings One plc (National Grid U.K.), a subsidiary of National Grid plc. The transaction resulted in cash proceeds of $10.7 billion inclusive of foreign currency hedges executed by PPL. PPL received net proceeds, after taxes and fees, of $10.4 billion. PPL WPD Limited agreed to indemnify National Grid U.K. for certain tax related matters. See Note 10 for additional information. PPL has not had and will not have any significant involvement with the U.K. utility business since completion of the sale.
Summarized Results of Discontinued Operations
The operations of the U.K. utility business are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income for the periods ended June 30, 2021 as follows:
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| | | Three Months | | | | Six Months |
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| Operating Revenues | | | $ | 710 | | | | | $ | 1,344 | |
| Operating Expenses | | | 214 | | | | | 466 | |
| Other Income (Expense) - net | | | 136 | | | | | 202 | |
| Interest Expense (a) | | | 116 | | | | | 209 | |
| Income before income taxes | | | 516 | | | | | 871 | |
| Loss on sale | | | 38 | | | | | (1,609) | |
| Income taxes | | | (1) | | | | | 750 | |
| Income (Loss) from Discontinued Operations (net of income taxes) | | | $ | 555 | | | | | $ | (1,488) | |
(a)No interest from corporate level debt was allocated to discontinued operations
9. Defined Benefits
(PPL)
Certain net periodic defined benefit costs are applied to accounts that are further distributed among capital, expense, regulatory assets and regulatory liabilities, including certain costs allocated to applicable subsidiaries for plans sponsored by PPL Services and LKE. Following are the net periodic defined benefit costs (credits) of the plans sponsored by PPL and its subsidiaries for the periods ended June 30:
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| Pension Benefits |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| PPL | | | | | | | |
| Service cost | $ | 13 | | | $ | 15 | | | $ | 25 | | | $ | 28 | |
| Interest cost | 30 | | | 29 | | | 62 | | | 61 | |
| Expected return on plan assets | (63) | | | (66) | | | (127) | | | (127) | |
| Amortization of: | | | | | | | |
| Prior service cost | 2 | | | 2 | | | 4 | | | 4 | |
| Actuarial loss | 17 | | | 24 | | | 29 | | | 49 | |
| Net periodic defined benefit costs (credits) before settlements | (1) | | | 4 | | | (7) | | | 15 | |
| Settlements (a) | 12 | | | — | | | 12 | | | — | |
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| Net periodic defined benefit costs (credits) | $ | 11 | | | $ | 4 | | | $ | 5 | | | $ | 15 | |
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(a)Due to the amount of lump sum payment distributions from the LKE qualified pension plan, settlement charges were incurred during the three and six months ended June 30, 2022. In accordance with existing regulatory accounting treatment, LG&E and KU have primarily maintained the settlement charge in regulatory assets to be amortized over 15 years.
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| | Other Postretirement Benefits |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
| PPL | | | | | | | |
| Service cost | $ | 2 | | | $ | 1 | | | $ | 3 | | | $ | 3 | |
| Interest cost | 4 | | | 4 | | | 8 | | | 8 | |
| Expected return on plan assets | (6) | | | (7) | | | (12) | | | (12) | |
| Amortization of: | | | | | | | |
| Prior service cost | 1 | | | 1 | | | 1 | | | 1 | |
| Actuarial loss | (2) | | | — | | | (2) | | | |
| Net periodic defined benefit costs (credits) | $ | (1) | | | $ | (1) | | | $ | (2) | | | $ | — | |
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(All Registrants)
The non-service cost components of net periodic defined benefit costs (credits) (interest cost, expected return on plan assets, amortization of prior service cost and amortization of actuarial gain and loss) are presented in "Other Income (Expense) - net" on the Statements of Income. See Note 12 for additional information.
10. Commitments and Contingencies
Energy Purchase Commitments (PPL)
RIE has several long-term contracts for the purchase of electric power. Substantially all of these contracts require power to be delivered before RIE is obligated to make payment. Additionally, RIE has entered into various contracts for gas delivery, storage, and supply services. Certain of these contracts require payment of annual demand charges, which are recoverable from customers. RIE is liable for these payments regardless of the level of service required from third-parties.
These contracts include the following commitments: | | | | | |
Contract Type | Maximum Maturity Date |
Electric power | 2024 |
Gas-related | Beyond 2027 |
RIE’s commitments under these long-term contracts subsequent to June 30, 2022 are summarized in the table below.
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| Total | | 2022 | | 2023-2024 | | 2025-2026 | | After 2026 |
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| Energy Purchase Obligations | $ | 809 | | | $ | 200 | | | $ | 216 | | | $ | 81 | | | $ | 312 | |
Long-term Contracts for Renewable Energy (PPL)
Several of the obligations included in the table above relate to certain long-term contracts for renewable energy, including:
•the Deepwater Wind Power Purchase Agreement (PPA), involving a proposal for a small scale renewable energy generation project of up to eight offshore wind turbines with an aggregate nameplate capacity of up to 30 MW to benefit the Town of New Shoreham and an underwater cable to Block Island, which entered into service in October 2016;
•the Three-State Procurement, involving eight long-term contracts pursuant to the Rhode Island Long-Term Contracting Standard (LTCS) of which 36.75 MW is currently operational and with respect to which RIE collects 2.75% remunerations in the annual payments pursuant to the LTCS; and
•the Offshore Wind Energy Procurement, pursuant to a 20-year power purchase agreement (PPA) with DWW Rev I, LLC (Revolution Wind), with and expected capacity of 408 MW expected to be operational in 2024; this contract was approved without remuneration, but allows RIE to seek costs incurred under the agreement.
In addition, RIE is obligated under the LTCS (as amended in 2014) to annually solicit for renewable projects until 90 MW of renewable capacity has been secured. To date these solicitations, as approved by the RIPUC, have included: (i) a 15-year PPA with Orbit Energy Rhode Island, LLC for a 3.2 MW anaerobic digester biogas project located in Johnston, Rhode Island, placed in service in 2017, (ii) a 15-year PPA with Black Bear Development Holdings, LLC for a 3.9 MW run-of-river hydroelectric plant located in Orono, Maine, placed in service in 2013, (iii) a 15-year PPA with Champlain Wind, LLC for a 48 MW land-based wind project located in Carroll Plantation and Kossuth Township, Maine, placed in service in January 2017, but which was ultimately terminated and its contribution to the 90 MW total requiring replacement, (iv) a 15-year PPA with Copenhagen Wind Farm, LLC for an 80 MW land-based wind project located in Denmark, New York, placed in service in 2018, and (v) a 20 year PPA with Gravel Pit Solar II, LLC (Gravel Pit Solar) for a 49.5 MW land based bifacial solar project located in East Windsor, CT that was terminated on May 24, 2022. RIE will be required to backfill approximately 3 MW to fulfill the required 90 MW under LTCS.
In addition to the LTCS, in July 2022, Rhode Island passed an amendment to the Affordable Clean Energy Security Act (ACES) that requires RIE to issue a request for proposals (RFP) for at least 600 MW but no greater than 1,000 MW of newly developed offshore wind capacity no later than October 15, 2022. RIE must file the RFP with the RIPUC for public comment 30 days in advance. RIE must negotiate in good faith to achieve a commercially reasonable contract and must file said contract with the RIPUC for approval no later than March 15, 2024, unless RIE can show that the bids are unlikely to lead to a contract that meets all of the statutory requirements.
As approved by the RIPUC, RIE is allowed to pass through commodity-related/purchased power costs to customers and collect remuneration equal to 2.75% for long-term contracts approved pursuant to LTCS that have achieved commercial operation. For long-term contracts approved pursuant to ACES, as amended, on or after January 1, 2022, RIE is entitled to financial remuneration equal to 1.0% through December 31, 2026 for those projects that are commercially operating. For long-term contracts approved pursuant to ACES on or after January 1, 2027, RIE is not entitled to any financial remuneration, unless otherwise granted by the RIPUC. Also, the amendments to ACES added a provision, which provides that for any calendar year in which RIE’s actual return on equity exceeds the return on equity allowed by the RIPUC in the last general rate case, the RIPUC may adjust any or all remuneration to assure that such remuneration does not result in or contribute toward RIE earning above its allowed return for such calendar year.
Legal Matters
(All Registrants)
PPL and its subsidiaries are involved in legal proceedings, claims and litigation in the ordinary course of business. PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.
Talen Litigation
(PPL)
Background
In September 2013, one of PPL's former subsidiaries, PPL Montana entered into an agreement to sell its hydroelectric generating facilities. In June 2014, PPL and PPL Energy Supply, the parent company of PPL Montana, entered into various definitive agreements with affiliates of Riverstone to spin off PPL Energy Supply and ultimately combine it with Riverstone's competitive power generation businesses to form a stand-alone company named Talen Energy. In November 2014, after executing the spinoff agreements but prior to the closing of the spinoff transaction, PPL Montana closed the sale of its hydroelectric generating facilities. Subsequently, on June 1, 2015, the spinoff of PPL Energy Supply was completed. Following the spinoff transaction, PPL had no continuing ownership interest in or control of PPL Energy Supply. In connection with the spinoff transaction, PPL Montana became Talen Montana, LLC (Talen Montana), a subsidiary of Talen Energy. Talen Energy Marketing also became a subsidiary of Talen Energy as a result of the June 2015 spinoff of PPL Energy Supply. Talen Energy has owned and operated both Talen Montana and Talen Energy Marketing since the spinoff. At the time of the spinoff, affiliates of Riverstone acquired a 35% ownership interest in Talen Energy. Riverstone subsequently acquired the remaining interests in Talen Energy in a take private transaction in December 2016.
Talen Montana Retirement Plan and Talen Energy Marketing, LLC, Individually and on Behalf of All Others Similarly Situated v. PPL Corporation et al.
On October 29, 2018, Talen Montana Retirement Plan and Talen Energy Marketing filed a putative class action complaint on behalf of current and contingent creditors of Talen Montana who allegedly suffered harm or allegedly will suffer reasonably foreseeable harm as a result of a November 2014 distribution of proceeds from the sale of then-PPL Montana's hydroelectric generating facilities. The action was filed in the Sixteenth Judicial District of the State of Montana, Rosebud County, against PPL and certain of its affiliates and current and former officers and directors (Talen Putative Class Action). Plaintiff asserts claims for, among other things, fraudulent transfer, both actual and constructive; recovery against subsequent transferees; civil conspiracy; aiding and abetting tortious conduct; and unjust enrichment. Plaintiff is seeking avoidance of the purportedly fraudulent transfer, unspecified damages, including punitive damages, the imposition of a constructive trust, and other relief. In December 2018, PPL removed the Talen Putative Class Action from the Sixteenth Judicial District of the State of Montana to the United States District Court for the District of Montana, Billings Division (MT Federal Court). In January 2019, the plaintiff moved to remand the Talen Putative Class Action back to state court, and dismissed without prejudice all current and former PPL Corporation directors from the case. In September 2019, the MT Federal Court granted plaintiff's motion to remand the case back to state court. Although, the PPL defendants petitioned the Ninth Circuit Court of Appeals to grant an appeal of the remand decision, in November 2019, the Ninth Circuit Court of Appeals denied that request and in December 2019, Talen Montana Retirement Plan filed a Second Amended Complaint in the Sixteenth Judicial District of the State of Montana, Rosebud County, which removed Talen Energy Marketing as a plaintiff. In January 2020, PPL defendants filed a motion to dismiss the Second Amended Complaint or, in the alternative, to stay the proceedings pending the resolution of the below mentioned Delaware Action. The Court held a hearing on June 24, 2020 regarding the motions. On September 11, 2020, the Court granted PPL defendants' alternative Motion for a Stay of the proceedings. As described below, this case will now proceed in the United States Bankruptcy Court for the Southern District of Texas (Texas Bankruptcy Court).
PPL Corporation et al. vs. Riverstone Holdings LLC, Talen Energy Corporation et al.
On November 30, 2018, PPL, certain PPL affiliates, and certain current and former officers and directors (PPL plaintiffs) filed a complaint in the Court of Chancery of the State of Delaware seeking various forms of relief against Riverstone, Talen Energy and certain of their affiliates (Delaware Action), in response to and as part of the defense strategy for an action filed by Talen Montana, LLC (the Talen Direct Action, since dismissed) and the Talen Putative Class Action described above (together, the Montana Actions) originally filed in Montana state court in October 2018. In the complaint, the PPL plaintiffs ask the Delaware Court of Chancery for declaratory and injunctive relief. This includes a declaratory judgment that, under the separation agreement governing the spinoff of PPL Energy Supply, all related claims that arise must be heard in Delaware; that the statute of limitations in Delaware and the spinoff agreement bar these claims at this time; that PPL is not liable for the claims in either the Talen Direct Action or the Talen Putative Class Action as PPL Montana was solvent at all relevant times; and that the separation agreement requires that Talen Energy indemnify PPL for all losses arising from the debts of Talen Montana, among other things. PPL's complaint also seeks damages against Riverstone for interfering with the separation agreement and against Riverstone affiliates for breach of the implied covenant of good faith and fair dealing. The complaint was subsequently
amended on January 11, 2019 and March 20, 2019, to include, among other things, claims related to indemnification with respect to the Montana Actions, request a declaration that the Montana Actions are time-barred under the spinoff agreements, and allege additional facts to support the tortious interference claim. In April 2019, the defendants filed motions to dismiss the amended complaint. In July 2019, the Court heard oral arguments from the parties regarding the motions to dismiss, and in October 2019, the Delaware Court of Chancery issued an opinion sustaining all of the PPL plaintiffs' claims except for the claim for breach of implied covenant of good faith and fair dealing. As a result of the dismissal of the Talen Direct Action in December 2019, in January 2020, Talen Energy filed a new motion to dismiss five of the remaining eight claims in the amended complaint. The Court heard oral argument on Talen's motion to dismiss on May 28, 2020, and on June 22, 2020, issued an opinion denying the motion in its entirety. Discovery is proceeding, and the parties have filed certain motions and cross-motions for summary judgment, which are not yet scheduled for hearing.
In January 2022, Vice-Chancellor Joseph R. Slights III, the judge assigned to this litigation, announced his retirement. Thereafter, this case was removed from the trial schedule and is awaiting the assignment of a new judge. As described below, this case will now proceed in the Texas Bankruptcy Court.
Talen Energy Supply, LLC et al. | Talen Montana LLC v. PPL Corp., PPL Capital Funding, Inc., PPL Electric Utilities Corp., and PPL Energy Funding (PPL and PPL Electric)
On May 9, 2022, Talen Energy Supply, LLC and 71 affiliates, including Talen Montana, LLC, filed petitions for protection under Chapter 11 of the Bankruptcy Code in the Texas Bankruptcy Court.
On May 10, 2022, Talen Montana, LLC, as debtor-in-possession, filed a complaint initiating an adversary proceeding (Adversary Proceeding) in the Texas Bankruptcy Court against PPL Corporation, PPL Capital Funding, Inc., PPL Electric Utilities Corporation, and PPL Energy Funding Corporation. Similar to the litigation in Montana, the Adversary Proceeding seeks the recovery of an allegedly fraudulent transfer relating to PPL Montana’s November 2014 sale of hydroelectric assets to Northwestern and subsequent distribution of certain proceeds of that sale, reiterating claims that the parties have already been litigating.
Also on May 10, 2022, certain Talen entities sought to remove both (1) the Montana action previously referred to as the Rosebud class action from state court to a federal district court in Montana (Montana District Court) and (2) the Delaware action to a federal district court in Delaware (Delaware District Court). Talen Montana, LLC then filed a motion to intervene and a motion to transfer the Montana case to the Texas Bankruptcy Court. Talen also filed a Motion to transfer the Delaware District Court action to the Texas Bankruptcy Court. Plaintiffs will seek to consolidate the Rosebud Class action and Delaware action in the Texas Bankruptcy Court.
With respect to each of the Talen-related matters described above, PPL believes that the 2014 distribution of proceeds was made in compliance with all applicable laws and that PPL Montana was solvent at all relevant times. Additionally, the agreements entered into in connection with the spinoff, which PPL and affiliates of Talen Energy and Riverstone negotiated and executed prior to the 2014 distribution, directly address the treatment of the proceeds from the sale of PPL Montana's hydroelectric generating facilities; in those agreements, Talen Energy and Riverstone definitively agreed that PPL was entitled to retain the proceeds.
PPL believes that it has meritorious defenses to the claims made in the Adversary Proceeding and intends to vigorously defend against this action. At this time, PPL cannot predict the outcome of the Adversary Proceeding or estimate the range of possible losses, if any, that PPL might incur as a result of the claims, although they could be material.
Narragansett Electric Litigation (PPL)
Aquidneck Island
In January 2019, Narragansett Electric suffered a significant loss of gas supply to the distribution system that serves customers on Aquidneck Island in Rhode Island, affecting approximately 7,500 customers. Following Narraganset Electric’s efforts to address customer concerns and expenses following the incident, and an investigation by the Rhode Island Division of Public Utilities and Carriers, Narragansett Electric published a long-term capacity study for energy solutions for Aquidneck Island and gathered extensive stakeholder feedback. Narraganset Electric continues to discuss this matter with the Rhode Island Division of Public Utilities and Carriers. Narragansett Electric filed a supplemental application for its long-term solution on April 1, 2022.
Narragansett Electric is facing various lawsuits related to the Aquidneck Island gas supply interruption, including two purported class actions. Narragansett Electric is actively defending against these claims. This matter is covered by excess liability insurance, which is currently reimbursing RIE for ongoing costs and claim amounts, subject to reservation of rights, and is not expected to materially affect RIE’s results of operations, financial position or cash flows.
Energy Efficiency Programs Investigation
Narragansett Electric, while under the ownership of National Grid, performed an internal investigation into conduct associated with its energy efficiency programs. Any adjustments that may be a result of the internal investigation remain subject to review and approval by the RIPUC. At this time, it is not possible to predict the final outcome or determine the total amount of any additional liabilities that may be incurred in connection with it by Narragansett Electric. This review by the RIPUC may be impacted by other investigations that are ongoing related to National Grid. Narragansett Electric does not expect this matter will have a material adverse effect on its results of operations, financial position or cash flows.
On June 27, 2022, the RIPUC opened a new docket (RIPUC Docket 22-05-EE) to investigate RIE’s actions and the actions of its National Grid employees during the time RIE was a National Grid USA affiliate being provided services by National Grid USA Service Company, Inc. relating to the manipulation of the reporting of invoices affecting the calculation of past energy efficiency shareholder incentives and the resulting impact on customers.
E.W. Brown Environmental Assessment (PPL and KU)
KU is undertaking extensive remedial measures at the E.W. Brown plant including closure of the former ash pond, implementation of a groundwater remedial action plan and performance of a corrective action plan including aquatic study of adjacent surface waters and risk assessment. The aquatic study and risk assessment are being undertaken pursuant to a 2017 agreed Order with the Kentucky Energy and Environment Cabinet (KEEC). KU conducted sampling of Herrington Lake in 2017 and 2018. In June 2019, KU submitted to the KEEC the required aquatic study and risk assessment, conducted by an independent third-party consultant, finding that discharges from the E.W. Brown plant have not had any significant impact on Herrington Lake and that the water in the lake is safe for recreational use and meets safe drinking water standards. On May 31, 2021, the KEEC approved the report and released a response to public comments. On August 6, 2021, KU submitted a Supplemental Remedial Alternatives Analysis report to the KEEC that outlines proposed additional fish, water, and sediment testing. On February 18, 2022, the KEEC provided approval to KU to proceed with the proposed sampling, which commenced in the spring of 2022.
Air (PPL and LG&E)
Sulfuric Acid Mist Emissions
In June 2016, the EPA issued a notice of violation under the Clean Air Act alleging that LG&E violated applicable rules relating to sulfuric acid mist emissions at its Mill Creek plant. The notice alleges failure to install proper controls, failure to operate the facility consistent with good air pollution control practice and causing emissions exceeding applicable requirements or constituting a nuisance or endangerment. LG&E believes it has complied with applicable regulations during the relevant time period. On July 31, 2020, the U.S. Department of Justice and Louisville Metro Air Pollution Control District filed a complaint in the U.S. District Court for the Western District of Kentucky alleging violations specified in the EPA notice of violation and seeking civil penalties and injunctive relief. In October 2020, LG&E filed a motion to dismiss the complaint. In December 2020, the U.S. Department of Justice and the Louisville Metro Air Pollution Control District filed an amended complaint. In February 2021, LG&E filed a renewed motion to dismiss regarding the amended complaint. On February 23, 2022, the court entered a Consent Decree negotiated by the parties to resolve the violations alleged in the complaint. The Consent Decree requires LG&E to pay a civil penalty and perform a supplemental environmental project (SEP). The agreed penalty and SEP do not have a significant impact on LG&E's operations or financial condition.
Water/Waste (PPL, LG&E and KU)
ELGs
In 2015, the EPA finalized ELGs for wastewater discharge permits for new and existing steam electricity generating facilities. These guidelines require deployment of additional control technologies providing physical, chemical and biological treatment and mandate operational changes including "no discharge" requirements for certain wastewaters. The implementation date for
individual generating stations was to be determined by the states on a case-by-case basis according to criteria provided by the EPA. Legal challenges to the final rule were consolidated before the U.S. Court of Appeals for the Fifth Circuit. In April 2017, the EPA announced that it would grant petitions for reconsideration of the rule. In September 2017, the EPA issued a rule to postpone the compliance date for certain requirements. On October 13, 2020, the EPA published final revisions to its best available technology standards for certain wastewaters and potential extensions to compliance dates (the Reconsideration Rule). The rule is expected to be implemented by the states or applicable permitting authorities in the course of their normal permitting activities. LG&E and KU are currently implementing responsive compliance strategies and schedules. Certain aspects of these compliance plans and estimates relate to developments in state water quality standards, which are separate from the ELG rule or its implementation. Certain costs are included in the Registrants' capital plans and expected to be recovered from customers through rate recovery mechanisms, but additional costs and recovery will depend on further regulatory developments at the state level. In August 2021, the EPA published a notice of rulemaking initiative announcing that it will propose revisions to the Reconsideration Rule and determine "whether more stringent limitations and standards are appropriate." Compliance with the Reconsideration Rule is required during the pendency of the rulemaking process.
CCRs
In 2015, the EPA issued a final rule governing management of CCRs which include fly ash, bottom ash and sulfur dioxide scrubber wastes. The CCR Rule imposes extensive new requirements for certain CCR impoundments and landfills, including public notifications, location restrictions, design and operating standards, groundwater monitoring and corrective action requirements, and closure and post-closure care requirements, and specifies restrictions relating to the beneficial use of CCRs. In July 2018, the EPA issued a final rule extending the deadline for closure of certain impoundments and adopting other substantive changes. In August 2018, the D.C. Circuit Court of Appeals vacated and remanded portions of the CCR Rule. In December 2019, the EPA addressed the deficiencies identified by the court and proposed amendments to change the closure deadline. In August 2020, the EPA published a final rule extending the deadline to initiate closure to April 11, 2021, while providing for certain extensions. The EPA is conducting ongoing rulemaking actions regarding various other amendments to the rule. Certain ongoing legal challenges to various provisions of the CCR Rule have been held in abeyance pending review by the EPA pursuant to the President's executive order. PPL, LG&E, and KU are monitoring the EPA’s ongoing efforts to refine and implement the regulatory program under the CCR Rule. The EPA has issued several recent proposed regulatory determinations, facility notifications and public announcements which indicate increased scrutiny by the EPA to determine the adequacy of measures taken by facility owners and operators to achieve closure of CCR surface impoundments and landfills. In particular, the agency indicated that it will focus on certain practices that it views as posing a threat of continuing groundwater contamination. Future guidance, regulatory determinations, rulemakings and other developments could potentially require revisions to current LG&E and KU compliance plans including additional monitoring and remediation at surface impoundments and landfills, the cost of which could be substantial. PPL, LG&E and KU are unable to predict the outcome of the ongoing litigation, rulemaking, and regulatory determinations or potential impacts on current LG&E and KU compliance plans. The Registrants are currently finalizing closure plans and schedules.
In January 2017, Kentucky issued a new state rule relating to CCR management, effective May 2017, aimed at reflecting the requirements of the federal CCR rule. As a result of a subsequent legal challenge, in January 2018, the Franklin County, Kentucky Circuit Court issued an opinion invalidating certain procedural elements of the rule. LG&E and KU presently operate their facilities under continuing permits authorized under the former program and do not currently anticipate material impacts as a result of the judicial ruling. Associated costs are expected to be subject to rate recovery.
LG&E and KU received KPSC approval for a compliance plan providing for the closure of impoundments at the Mill Creek, Trimble County, E.W. Brown, and Ghent stations, and construction of process water management facilities at those plants. In addition to the foregoing measures required for compliance with the federal CCR rule, KU also received KPSC approval for its plans to close impoundments at the retired Green River, Pineville and Tyrone plants to comply with applicable state law. LG&E and KU have completed planned closure measures at most of the subject impoundments and have commenced post closure groundwater monitoring as required at those facilities. LG&E and KU generally expect to complete all impoundment closures within five years of commencement, although a longer period may be required to complete closure of some facilities. Associated costs are expected to be subject to rate recovery.
In connection with the final CCR rule, LG&E and KU recorded adjustments to existing AROs beginning in 2015 and continue to record adjustments as required. See Note 15 for additional information. Further changes to AROs, current capital plans or operating costs may be required as estimates are refined based on closure developments, groundwater monitoring results, and regulatory or legal proceedings. Costs relating to this rule are expected to be subject to rate recovery.
Superfund and Other Remediation (All Registrants)
PPL, PPL Electric, LG&E and KU are potentially responsible for investigating and remediating contamination under the federal Superfund program and similar state programs. Actions are under way at certain sites including former coal gas manufacturing plants in Pennsylvania and Kentucky previously owned or operated by, or currently owned by predecessors or affiliates of, PPL Electric, LG&E and KU. PPL Electric is potentially responsible for a share of clean-up costs at certain sites including the Columbia Gas Plant site and the Brodhead site. Cleanup actions have been or are being undertaken at these sites as requested by governmental agencies, the costs of which have not been and are not expected to be significant to PPL Electric.
As of June 30, 2022 and December 31, 2021, PPL Electric had a recorded liability of $10 million representing its best estimate of the probable loss incurred to remediate the sites identified above. Depending on the outcome of investigations at identified sites where investigations have not begun or been completed, or developments at sites for which information is incomplete, additional costs of remediation could be incurred. PPL Electric, LG&E and KU lack sufficient information about such additional sites to estimate any potential liability or range of reasonably possible losses, if any, related to these sites. Such costs, however, are not currently expected to be significant.
The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of coal gas manufacturing. As a result, individual states may establish stricter standards for water quality and soil cleanup, that could require several PPL subsidiaries to take more extensive assessment and remedial actions at former coal gas manufacturing plants. The Registrants cannot reasonably estimate a range of possible losses, if any, related to these matters.
Narragansett Electric
The EPA, the Massachusetts Department of Environmental Protection (MADEP), and the Rhode Island Department of Environmental Management (DEM) have alleged that Narragansett Electric is a potentially responsible party under state or federal law for the remediation of a number of sites at which hazardous substances are alleged to have been disposed. Narragansett Electric’s most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned by the Blackstone Valley Gas and Electric Company and the Rhode Island gas distribution assets of the New England Gas division of Southern Union Company and electric operations at certain Narragansett Electric facilities. Narragansett Electric is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA, DEM and MADEP. Expenditures incurred for the six months ended June 30, 2022 were $7 million.
Narragansett Electric estimated the remaining costs of environmental remediation activities were $101 million as of June 30, 2022. Narragansett Electric had a current portion of environmental remediation costs of $8 million included in current liabilities on the Balance Sheets at June 30, 2022. These undiscounted costs are expected to be incurred over approximately 30 years, and these undiscounted amounts have been recorded as estimated liabilities on the balance sheet. However, remediation costs for each site may be materially higher than estimated, depending on changing technologies and regulatory standards, selected end uses for each site, and actual environmental conditions encountered. Narragansett Electric has recovered amounts from certain insurers and potentially responsible parties, and, where appropriate, Narragansett Electric may seek additional recovery from other insurers and from other potentially responsible parties, but it is uncertain whether, and to what extent, such efforts will be successful.
The RIPUC has approved two settlement agreements that provides for rate recovery of qualified remediation costs of certain contaminated sites located in Rhode Island and Massachusetts. Rate-recoverable contributions for electric operations of approximately $3 million are added annually to the fund, along with interest and any recoveries from insurance carriers and other third-parties. In addition, Narragansett Electric recovers approximately $1 million annually for gas operations under a Distribution Adjustment Charge in which the qualified remediation costs are amortized over 10 years. See Note 6 for additional information on RIE's recorded environmental regulatory assets and liabilities.
Narragansett Electric believes that its ongoing operations and approach to addressing conditions at historical sites are in substantial compliance with all applicable environmental laws. Where Narragansett Electric has regulatory recovery, it believes that the obligations imposed on it because of the environmental laws will not have a material impact on PPL's results of operations or financial position.
Regulatory Issues
(All Registrants)
See Note 6 for information on regulatory matters related to utility rate regulation.
Electricity - Reliability Standards
The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk electric system in North America. The FERC oversees this process and independently enforces the Reliability Standards.
The Reliability Standards have the force and effect of law and apply to certain users of the bulk electric system, including electric utility companies, generators and marketers. Under the Federal Power Act, the FERC may assess civil penalties for certain violations.
PPL Electric, LG&E, KU, and RIE monitor their compliance with the Reliability Standards and self-report or self-log potential violations of applicable reliability requirements whenever identified, and submit accompanying mitigation plans, as required. The resolution of a small number of potential violations is pending. Penalties incurred to date have not been significant. Any Regional Reliability Entity determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC.
In the course of implementing their programs to ensure compliance with the Reliability Standards by those PPL affiliates subject to the standards, certain other instances of potential non-compliance may be identified from time to time. The Registrants cannot predict the outcome of these matters, and an estimate or range of possible losses cannot be determined.
Gas - Security Directives (PPL and LG&E)
In May and July of 2021, the Department of Homeland Security’s (DHS) Transportation Security Administration (TSA) released two security directives applicable to certain notified owners and operators of natural gas pipeline facilities (including local distribution companies) that TSA has determined to be critical. The first security directive required notified owners/operators to implement cybersecurity incident reporting to the DHS, designate a cybersecurity coordinator, and perform a gap assessment of current entity cybersecurity practices against certain voluntary TSA security guidelines and report relevant results and proposed mitigation to applicable DHS agencies. The second security directive required notified entities to implement a significant number of specified cyber security controls and processes. LG&E does not believe the security directives will have a significant impact on LG&E’s operations or financial condition.
Other
Guarantees and Other Assurances
(All Registrants)
In the normal course of business, the Registrants enter into agreements that provide financial performance assurance to third-parties on behalf of certain subsidiaries. Such agreements include, for example, guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies. These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage.
(PPL)
PPL fully and unconditionally guarantees all of the debt securities and loan obligations of PPL Capital Funding.
(All Registrants)
The table below details guarantees provided as of June 30, 2022. "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee. The probability of expected payment/performance under each of these guarantees is remote. For reporting purposes, on a consolidated basis, the guarantees of PPL include the guarantees of its subsidiary Registrants.
| | | | | | | | | | | | | | |
| Exposure at June 30, 2022 | | | Expiration
Date |
| PPL | | | | |
Indemnifications related to certain tax liabilities related to the sale of the U.K. utility business | £ | 50 | | (a) | | 2028 |
| LG&E and KU | | | | |
| LG&E and KU obligation of shortfall related to OVEC | | (b) | | |
(a)PPL WPD Limited entered into a Tax Deed dated June 9, 2021 in which it agreed to a tax indemnity regarding certain potential tax liabilities of the entities sold with respect to periods prior to the completion of the sale, subject to customary exclusions and limitations. Because National Grid Holdings One plc, the buyer, agreed to purchase indemnity insurance, the amount of the cap on the indemnity for these liabilities is £1, except with respect to certain surrenders of tax losses, for which the amount of the cap on the indemnity is £50 million.
(b)Pursuant to the OVEC power purchase contract, LG&E and KU are obligated to pay for their share of OVEC's excess debt service, post-retirement and decommissioning costs, as well as any shortfall from amounts included within a demand charge designed and expected to cover these costs over the term of the contract. PPL's proportionate share of OVEC's outstanding debt was $89 million at June 30, 2022, consisting of LG&E's share of $62 million and KU's share of $27 million. The maximum exposure and the expiration date of these potential obligations are not presently determinable. See "Energy Purchase Commitments" in Note 14 in PPL's, LG&E's and KU's 2021 Form 10-K for additional information on the OVEC power purchase contract.
The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business. These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration. The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated. Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is generally remote.
PPL, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage. The coverage provides maximum aggregate coverage of $225 million. This insurance may be applicable to obligations under certain of these contractual arrangements.
11. Related Party Transactions
Support Costs (PPL Electric, LG&E and KU)
PPL Services and LKS provide and, prior to its merger into PPL Services on December 31, 2021, PPL EU Services provided the Registrants, their respective subsidiaries and each other with administrative, management and support services. For all services companies, the costs of directly assignable and attributable services are charged to the respective recipients as direct support costs. General costs that cannot be directly attributed to a specific entity are allocated and charged to the respective recipients as indirect support costs. PPL Services and PPL EU Services use a three-factor methodology that includes the applicable recipients' invested capital, operation and maintenance expenses and number of employees to allocate indirect costs. PPL Services may also use a ratio of overall direct and indirect costs or a weighted average cost ratio. LKS bases its indirect allocations on the subsidiaries' number of employees, total assets, revenues, number of customers and/or other statistical information. PPL Services, LKS and PPL EU Services charged the following amounts for the periods ended June 30, including amounts applied to accounts that are further distributed between capital and expense on the books of the recipients, based on methods that are believed to be reasonable.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 |
PPL Electric from PPL Services | $ | 60 | | | $ | 11 | | | $ | 121 | | | $ | 21 | |
| PPL Electric from PPL EU Services | — | | | 49 | | | — | | | 99 | |
| LG&E from LKS | 41 | | | 44 | | | 80 | | | 86 | |
| KU from LKS | 42 | | | 45 | | | 86 | | | 89 | |
In addition to the charges for services noted above, LKS makes payments on behalf of LG&E and KU for fuel purchases and other costs for products or services provided by third-parties. LG&E and KU also provide services to each other and to LKS. Billings between LG&E and KU relate to labor and overheads associated with union and hourly employees performing work for the other company, charges related to jointly-owned generating units and other miscellaneous charges. Tax settlements between PPL and LG&E and KU are reimbursed through LKS.
Intercompany Borrowings
(PPL Electric)
PPL Energy Funding maintains a $1,200 million revolving line of credit with a PPL Electric subsidiary. At June 30, 2022 and December 31, 2021, PPL Energy Funding had borrowings outstanding in the amount of $166 million and $499 million. These balances are reflected in "Notes receivable from affiliate" on the PPL Electric Balance Sheets. The interest rates on borrowings are equal to one-month LIBOR plus a spread. Interest income is reflected in "Interest Income from Affiliate" on the PPL Electric Income Statements.
(LG&E and KU)
LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to the difference between LG&E's FERC borrowing limit and LG&E's commercial paper issued at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on LIBOR. LG&E's money pool borrowing limit is $356 million. At December 31, 2021, LG&E had borrowings outstanding from KU and/or LKE in the amount of $324 million. This balance is reflected in "Notes payable to affiliates" on the LG&E Balance Sheets. No balances were outstanding at June 30, 2022.
KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to the difference between KU's FERC borrowing limit and KU's commercial paper issued at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on LIBOR. KU's money pool borrowing limit is $312 million. At December 31, 2021, KU had borrowings outstanding from LG&E and/or LKE in the amount of $294 million. This balance is reflected in "Notes payable to affiliates" on the KU Balance Sheets. No balances were outstanding at June 30, 2022.
VEBA Funds Receivable (PPL Electric)
In 2018, PPL received a favorable private letter ruling from the IRS permitting a transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to a new subaccount within the VEBA, to be used to pay medical claims of active bargaining unit employees. Based on PPL Electric's participation in PPL’s Other Postretirement Benefit plan, PPL Electric was allocated a portion of the excess funds from PPL Services. These funds have been recorded as an intercompany receivable on PPL Electric's Balance Sheets. The receivable balance decreases as PPL Electric pays incurred medical claims and is reimbursed by PPL Services. The intercompany receivable balance associated with these funds was $5 million as of June 30, 2022, which was reflected in "Accounts receivable from affiliates" on the PPL Electric Balance Sheets. The intercompany receivable balance associated with these funds was $11 million as of December 31, 2021, the majority of which was reflected in "Accounts receivable from affiliates" on the PPL Electric Balance Sheets.
12. Other Income (Expense) - net
(PPL)
The details of "Other Income (Expense) - net" for the periods ended June 30, were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months | | | | |
| 2022 | | 2021 | | 2022 | | 2021 | | | | | | | | |
| Other Income | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Defined benefit plans - non-service credits (Note 9) | $ | 9 | | | $ | 8 | | | $ | 20 | | | $ | 12 | | | | | | | | | |
| Interest income | (1) | | | 4 | | | (2) | | | 4 | | | | | | | | | |
| AFUDC - equity component | 6 | | | 5 | | | 10 | | | 9 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Miscellaneous | 3 | | | 5 | | | 4 | | | 5 | | | | | | | | | |
| Total Other Income | 17 | | | 22 | | | 32 | | | 30 | | | | | | | | | |
| Other Expense | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Charitable contributions | 1 | | | 1 | | | 2 | | | 2 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Miscellaneous (a) | (10) | | | 8 | | | 4 | | | 15 | | | | | | | | | |
| Total Other Expense | (9) | | | 9 | | | 6 | | | 17 | | | | | | | | | |
| Other Income (Expense) - net | $ | 26 | | | $ | 13 | | | $ | 26 | | | $ | 13 | | | | | | | | | |
(a)Includes legal expenses incurred and insurance reimbursements received related to litigation with a former affiliate, Talen Montana. See Note 10 for additional information.
(PPL Electric)
The details of "Other Income (Expense) - net" for the periods ended June 30, were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months | | Six Months | | | | |
| 2022 | | 2021 | | 2022 | | 2021 | | | | | | | | |
| Other Income | | | | | | | | | | | | | | | |
| Defined benefit plans - non-service credits (Note 9) | $ | 4 | | | $ | 2 | | | $ | 8 | | | $ | 4 | | | | | | | | | |
| Interest income | — | | | — | | | 1 | | | — | | | | | | | | | |
| AFUDC - equity component | 4 | | | 4 | | | 8 | | | 9 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Total Other Income | 8 | | | 6 | | | 17 | | | 13 | | | | | | | | | |
| Other Expense | | | | | | | | | | | | | | | |
| Charitable contributions | — | | | — | | | 2 | | | 1 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Miscellaneous | 1 | | | 1 | | | 2 | | | 2 | | | | | | | | | |
| Total Other Expense | 1 | | | 1 | | | 4 | | | 3 | | | | | | | | | |
| Other Income (Expense) - net | $ | 7 | | | $ | 5 | | | $ | 13 | | | $ | 10 | | | | | | | | | |
13. Fair Value Measurements
(All Registrants)
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). A market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) are used to measure the fair value of an asset or liability, as appropriate. These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk. The fair value of a group of financial assets and liabilities is measured on a net basis. See Note 1 in each Registrant's 2021 Form 10-K for information on the levels in the fair value hierarchy.
Recurring Fair Value Measurements
The assets and liabilities measured at fair value were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 |
| PPL | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 336 | | | $ | 336 | | | $ | — | | | $ | — | | | $ | 3,571 | | | $ | 3,571 | | | $ | — | | | $ | — | |
| Restricted cash and cash equivalents (a) | 1 | | | 1 | | | — | | | — | | | 1 | | | 1 | | | — | | | — | |
| Total Cash, Cash Equivalents and Restricted Cash (b) | 337 | | | 337 | | | — | | | — | | | 3,572 | | | 3,572 | | | — | | | — | |
| Special use funds (a): | | | | | | | | | | | | | | | |
| Money market fund | — | | | — | | | — | | | — | | | 2 | | | 2 | | | — | | | — | |
| Commingled debt fund measured at NAV (c) | 16 | | | — | | | — | | | — | | | 22 | | | — | | | — | | | — | |
| Commingled equity fund measured at NAV (c) | 16 | | | — | | | — | | | — | | | 21 | | | — | | | — | | | — | |
| Total special use funds | 32 | | | — | | | — | | | — | | | 45 | | | 2 | | | — | | | — | |
| Price risk management assets (d): | | | | | | | | | | | | | | | |
| Gas contracts | 59 | | | — | | | 59 | | | — | | | — | | | — | | | — | | | — | |
| Total assets | $ | 428 | | | $ | 337 | | | $ | 59 | | | $ | — | | | $ | 3,617 | | | $ | 3,574 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 |
| | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | |
| Price risk management liabilities (d): | | | | | | | | | | | | | | | |
| Interest rate swaps | $ | 10 | | | $ | — | | | $ | 10 | | | $ | — | | | $ | 18 | | | $ | — | | | $ | 18 | | | $ | — | |
| Gas contracts | 4 | | | — | | | 4 | | | — | | | — | | | — | | | — | | | — | |
| Total price risk management liabilities | $ | 14 | | | $ | — | | | $ | 14 | | | $ | — | | | $ | 18 | | | $ | — | | | $ | 18 | | | $ | — | |
| | | | | | | | | | | | | | | |
| PPL Electric | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 29 | | | $ | 29 | | | $ | — | | | $ | — | | | $ | 21 | | | $ | 21 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| Total assets | $ | 29 | | | $ | 29 | | | $ | — | | | $ | — | | | $ | 21 | | | $ | 21 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| LG&E | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 18 | | | $ | 18 | | | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| Total assets | $ | 18 | | | $ | 18 | | | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | |
| Price risk management liabilities: | | | | | | | | | | | | | | | |
| Interest rate swaps | $ | 10 | | | $ | — | | | $ | 10 | | | $ | — | | | $ | 18 | | | $ | — | | | $ | 18 | | | $ | — | |
| Total price risk management liabilities | $ | 10 | | | $ | — | | | $ | 10 | | | $ | — | | | $ | 18 | | | $ | — | | | $ | 18 | | | $ | — | |
| | | | | | | | | | | | | | | |
| KU | | | | | | | | | | | | | | | |
| Assets | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 17 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | |
| Total assets | $ | 17 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | |
(a)Included in "Other current assets" on the Balance Sheets.
(b)Total Cash, Cash Equivalents and Restricted Cash provides a reconciliation of these items reported within the Balance Sheets to the sum shown on the Statements of Cash Flows.
(c)In accordance with accounting guidance, certain investments that are measured at fair value using net asset value per share (NAV), or its equivalent, have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Balance Sheets.
(d)Current portion is included in "Other current asset" and "Other current liabilities" and noncurrent portion is included in "Other noncurrent assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
Special Use Funds
(PPL)
The special use funds are investments restricted for paying active union employee medical costs. In 2018, PPL received a favorable private letter ruling from the IRS permitting a transfer of excess funds from the PPL Bargaining Unit Retiree Health Plan VEBA to a new subaccount within the VEBA to be used to pay medical claims of active bargaining unit employees. The funds are invested primarily in commingled debt and equity funds measured at NAV and are classified as investments in equity securities. Changes in the fair value of the funds are recorded to the Statements of Income.
Price Risk Management Assets/Liabilities
Interest Rate Swaps (PPL, LG&E and KU)
To manage interest rate risk, PPL, LG&E and KU use interest rate contracts such as forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps. An income approach is used to measure the fair value of these contracts, utilizing readily observable inputs, such as forward interest rates (e.g., LIBOR and government security rates), as well as inputs that may not be observable, such as credit valuation adjustments. In certain cases, market information cannot practicably be obtained to value credit risk and therefore internal models are relied upon. These models use projected probabilities of default and estimated
recovery rates based on historical observances. When the credit valuation adjustment is significant to the overall valuation, the contracts are classified as Level 3.
Gas Contracts (PPL)
To manage gas commodity price risk associated with natural gas purchases, RIE utilizes over-the-counter (OTC) gas swaps contracts with pricing inputs obtained from the New York Mercantile Exchange (NYMEX) and the Intercontinental Exchange (ICE), except in cases where the ICE publishes seasonal averages or where there were no transactions within the last seven days. RIE may utilize discounting based on quoted interest rate curves, including consideration of non-performance risk, and may include a liquidity reserve calculated based on bid/ask spread. Substantially all of these price curves are observable in the marketplace throughout at least 95% of the remaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of 95% or higher. These contracts are classified as Level 2.
RIE also utilizes gas option and purchase and capacity transactions, which are valued based on internally developed models. Industry-standard valuation techniques, such as the Black-Scholes pricing model, are used for valuing such instruments. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivative instruments valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. RIE considers non-performance risk and liquidity risk in the valuation of derivative instruments categorized in Level 2 and Level 3.
Financial Instruments Not Recorded at Fair Value (All Registrants)
Long-term debt is classified as Level 2. The effect of third-party credit enhancements is not included in the fair value measurement. The carrying amounts of long-term debt on the Balance Sheets and their estimated fair values are set forth below.
| | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| Carrying
Amount (a) | | Fair Value | | Carrying
Amount (a) | | Fair Value |
| PPL | $ | 12,654 | | | $ | 12,110 | | | $ | 11,140 | | | $ | 12,955 | |
| PPL Electric | 4,486 | | | 4,436 | | | 4,484 | | | 5,272 | |
| LG&E | 2,007 | | | 1,914 | | | 2,006 | | | 2,363 | |
| KU | 2,619 | | | 2,458 | | | 2,618 | | | 3,120 | |
(a)Amounts are net of debt issuance costs.
The carrying amounts of other current financial instruments (except for long-term debt due within one year) approximate their fair values because of their short-term nature.
14. Derivative Instruments and Hedging Activities
(All Registrants)
Risk Management Objectives
PPL has a risk management policy approved by the Board of Directors to manage market risk associated with commodities, interest rates on debt issuances (including price, liquidity and volumetric risk) and credit risk (including non-performance risk and payment default risk). The Risk Management Committee, comprised of senior management and chaired by the Senior Director-Risk Management, oversees the risk management function. Key risk control activities designed to ensure compliance with the risk policy and detailed programs include, but are not limited to, credit review and approval, validation of transactions, verification of risk and transaction limits, value-at-risk analyses (VaR, a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level) and the coordination and reporting of the Enterprise Risk Management program.
Market Risk
Market risk includes the potential loss that may be incurred as a result of price changes associated with a particular financial or commodity instrument as well as market liquidity and volumetric risks. Forward contracts, futures contracts, options, swaps and structured transactions are utilized as part of risk management strategies to minimize unanticipated fluctuations in earnings caused by changes in commodity prices and interest rates. Many of these contracts meet the definition of a derivative. All derivatives are recognized on the Balance Sheets at their fair value, unless NPNS is elected.
The following summarizes the market risks that affect PPL and its subsidiaries.
Interest Rate Risk
•PPL and its subsidiaries are exposed to interest rate risk associated with forecasted fixed-rate and existing floating-rate debt issuances. PPL and LG&E utilize over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt. PPL, LG&E and KU utilize forward starting interest rate swaps to hedge changes in benchmark interest rates, when appropriate, in connection with future debt issuances.
•PPL and its subsidiaries are exposed to interest rate risk associated with debt securities and derivatives held by defined benefit plans. This risk is significantly mitigated to the extent that the plans are sponsored at, or sponsored on behalf of, the regulated domestic utilities due to the recovery methods in place.
Commodity Price Risk
PPL is exposed to commodity price risk through its subsidiaries as described below.
•PPL Electric is required to purchase electricity to fulfill its obligation as a PLR. Potential commodity price risk is mitigated through its PAPUC-approved cost recovery mechanism and full-requirement supply agreements to serve its PLR customers which transfer the risk to energy suppliers.
•LG&E's and KU's rates include certain mechanisms for fuel, fuel-related expenses and energy purchases. In addition, LG&E's rates include a mechanism for natural gas supply expenses. These mechanisms generally provide for timely recovery of market price fluctuations associated with these expenses.
•RIE utilizes derivative instruments pursuant to its RIPUC-approved plan to manage commodity price risk associated with its natural gas purchases. RIE's commodity risk management strategy is to reduce fluctuations in firm gas sales prices to its customers. RIE's costs associate with derivatives instruments are generally recoverable through its RIPUC- approved cost recovery mechanism. RIE is required to purchase electricity to fulfill its obligation to provide Last Resort Service (LRS). Potential commodity price risk is mitigated through its RIPUC-approved cost recovery mechanisms and full requirements service agreements to serve LRS customers, which transfer the risk to energy suppliers. RIE is required to contract through long-term agreements for clean energy supply under the Rhode Island Renewable Energy Growth program and Long-term Clean Energy Standard. Potential commodity price risk is mitigated through its RIPUC-approved cost recovery mechanisms, which true-up cost differences between contract prices and market prices.
Volumetric Risk
Volumetric risk is the risk related to the changes in volume of retail sales due to weather, economic conditions or other factors. PPL is exposed to volumetric risk through its subsidiaries as described below:
•PPL Electric, LG&E and KU are exposed to volumetric risk on retail sales, mainly due to weather and other economic conditions for which there is limited mitigation between rate cases.
•RIE is exposed to volumetric risk, which is significantly mitigated by regulatory mechanisms. RIE's electric and gas distribution rates both have a revenue decoupling mechanism, which allows for annual adjustments to RIE’s delivery rates.
Equity Securities Price Risk
•PPL and its subsidiaries are exposed to equity securities price risk associated with the fair value of the defined benefit plans' assets. This risk is significantly mitigated due to the recovery methods in place.
•PPL is exposed to equity securities price risk from future stock sales and/or purchases.
Credit Risk
Credit risk is the potential loss that may be incurred due to a counterparty's non-performance.
PPL is exposed to credit risk from "in-the-money" transactions with counterparties as well as additional credit risk through certain of its subsidiaries, as discussed below.
In the event a supplier of PPL, PPL Electric, LG&E or KU defaults on its obligation, those Registrants would be required to seek replacement power or replacement fuel in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities.
PPL and its subsidiaries have credit policies in place to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements or provisions. These agreements generally include credit mitigation provisions, such as margin, prepayment or collateral requirements. PPL and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.
Master Netting Arrangements (PPL, LG&E and KU)
Net derivative positions on the balance sheets are not offset against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
PPL had a $9 million obligation and no obligation to return or post cash collateral under master netting arrangements at June 30, 2022 and December 31, 2021.
LG&E and KU had no obligation to return or post cash collateral under master netting arrangements at June 30, 2022 and December 31, 2021.
See "Offsetting Derivative Instruments" below for a summary of derivative positions presented in the balance sheets where a right of setoff exists under these arrangements.
Interest Rate Risk
(All Registrants)
PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. A variety of financial derivative instruments are utilized to adjust the mix of fixed and floating interest rates in their debt portfolios, adjust the duration of the debt portfolios and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under PPL's risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of the debt portfolio due to changes in benchmark interest rates. In addition, the interest rate risk of certain subsidiaries is potentially mitigated as a result of the existing regulatory framework or the timing of rate cases.
Cash Flow Hedges (PPL)
Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings. Financial interest rate swap contracts that qualify as cash flow hedges may be entered into to hedge floating interest rate risk associated with both existing and anticipated debt issuances. PPL had no such contracts at June 30, 2022.
Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time period and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedged transaction is not probable of occurring.
For the three and six months ended June 30, 2022 and 2021, PPL had no cash flow hedges reclassified into earnings associated with discontinued cash flow hedges.
At June 30, 2022, the amount of accumulated net unrecognized after-tax gains (losses) on qualifying derivatives expected to be reclassified into earnings during the next 12 months is insignificant. Amounts are reclassified as the hedged interest expense is recorded.
Economic Activity (PPL and LG&E)
LG&E enters into interest rate swap contracts that economically hedge interest payments. Because realized gains and losses from the swaps, including terminated swap contracts, are recoverable through regulated rates, any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities until they are realized as interest expense. Realized gains and losses are recognized in "Interest Expense" on the Statements of Income at the time the underlying hedged interest expense is recorded. At June 30, 2022, LG&E held contracts with a notional amount of $64 million that mature in 2033.
Accounting and Reporting
(All Registrants)
All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless NPNS is elected. NPNS contracts include certain full requirement purchase contracts and other physical purchase contracts. Changes in the fair value of derivatives not designated as NPNS are recognized in earnings unless specific hedge accounting criteria are met and designated as such, except for the changes in fair values of LG&E's interest rate swaps and certain RIE commodity gas contracts that are recognized as regulatory assets or regulatory liabilities. See Note 6 for amounts recorded in regulatory assets and regulatory liabilities at June 30, 2022 and December 31, 2021.
See Note 1 in each Registrant's 2021 Form 10-K for additional information on accounting policies related to derivative instruments.
(PPL)
The following table presents the fair value and the location on the Balance Sheets of derivatives not designated as hedging instruments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | June 30, 2022 | | | | | | December 31, 2021 |
| | | | | | Assets | | Liabilities | | | | | | Assets | | Liabilities |
| Current: | | | | | | | | | | | | | | | |
| Price Risk Management Assets/Liabilities: | | | | | | | | | | | | | | | |
| Interest rate swaps (a) | | | | | $ | — | | | $ | 1 | | | | | | | $ | — | | | $ | 1 | |
| Gas contracts | | | | | 46 | | | 3 | | | | | | | — | | | — | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Total current | | | | | 46 | | | 4 | | | | | | | — | | | 1 | |
| Noncurrent: | | | | | | | | | | | | | | | |
| Price Risk Management Assets/Liabilities: | | | | | | | | | | | | | | | |
| Interest rate swaps (a) | | | | | — | | | 9 | | | | | | | — | | | 17 | |
| Gas contracts | | | | | 13 | | | 1 | | | | | | | — | | | — | |
| | | | | | | | | | | | | | | |
| Total noncurrent | | | | | 13 | | | 10 | | | | | | | — | | | 17 | |
| Total derivatives | | | | | $ | 59 | | | $ | 14 | | | | | | | $ | — | | | $ | 18 | |
(a)Current portion is included in "Price risk management assets" and "Other current liabilities" and noncurrent portion is included in "Price risk management assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets. Excludes accrued interest, if applicable.
The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets and regulatory liabilities for the period ended June 30, 2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months | | Six Months | | | | Three Months | | Six Months |
Derivative
Relationships | | Derivative Gain
(Loss) Recognized in
OCI | | Derivative Gain
(Loss) Recognized in
OCI | | Location of
Gain (Loss)
Recognized
in Income
on Derivative | | Gain (Loss)
Reclassified
from AOCI
into Income | | Gain (Loss)
Reclassified
from AOCI
into
Income |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest rate swaps | | $ | — | | | $ | — | | | Interest expense | | $ | (1) | | | $ | (2) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total | | $ | — | | | $ | — | | | | | $ | (1) | | | $ | (2) | |
| | | | | | | | | | | | | | | | | | | | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized in
Income on Derivative | | Three Months | | Six Months |
| | | | | | |
| Interest rate swaps | | Interest expense | | $ | — | | | $ | 1 | |
| Gas contracts | | Energy purchases | | 9 | | | 9 | |
| | Total | | $ | 9 | | | $ | 10 | |
| | | | | | |
| | | | | | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized as
Regulatory Liabilities/Assets | | Three Months | | Six Months |
| Interest rate swaps | | Regulatory assets - noncurrent | | $ | 4 | | | $ | 8 | |
The following tables present the pre-tax effect of derivative instruments recognized in income, OCI or regulatory assets and regulatory liabilities for the period ended June 30, 2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months | | Six Months | | | | Three Months | | Six Months |
Derivative
Relationships | | Derivative Gain
(Loss) Recognized in
OCI | | Derivative Gain
(Loss) Recognized in
OCI | | Location of
Gain (Loss)
Recognized
in Income
on Derivative | | Gain (Loss)
Reclassified
from AOCI
into Income | | Gain (Loss)
Reclassified
from AOCI
into Income |
| Cash Flow Hedges: | | | | | | | | | | |
| Interest rate swaps | | $ | — | | | $ | — | | | Interest expense | | $ | 14 | | | $ | 13 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | Loss from Discontinued Operations (net of taxes) | | (1) | | | (2) | |
| Cross-currency swaps | | (4) | | | (50) | | | Loss from Discontinued Operations (net of taxes) | | (2) | | | (39) | |
| Total | | $ | (4) | | | $ | (50) | | | | | $ | 11 | | | $ | (28) | |
| Net Investment Hedges: | | | | | | | | | | |
| Foreign currency contracts in discontinued operations | | $ | — | | | $ | 1 | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized in
Income on Derivative | | Three Months | | Six Months |
| Foreign currency contracts | | Loss from Discontinued operations (net of taxes) | | $ | (241) | | | $ | (266) | |
| Interest rate swaps | | Interest expense | | (1) | | | (2) | |
| | | Total | | $ | (242) | | | $ | (268) | |
Derivatives Not Designated as
Hedging Instruments | | Location of Gain (Loss) Recognized as
Regulatory Liabilities/Assets | | Three Months | | Six Months |
| Interest rate swaps | | Regulatory assets - noncurrent | | $ | (3) | | | $ | 3 | |
| | | | | | |
| | | | | | |
| | | | | | |
The following table presents the effect of cash flow hedge activity on the Statement of Income for the period ended June 30, 2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships | |
| Three Months | | Six Months | |
| Interest Expense | | Other Income (Expense) - net | | Interest Expense | | | | Other Income (Expense) - net | |
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 118 | | | $ | 26 | | | $ | 225 | | | | | $ | 26 | | |
| The effects of cash flow hedges: | | | | | | | | | | |
| Gain (Loss) on cash flow hedging relationships: | | | | | | | | | | |
| Interest rate swaps: | | | | | | | | | | |
| Amount of gain (loss) reclassified from AOCI to income | (1) | | | — | | | (2) | | | | | — | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The following table presents the effect of cash flow hedge activity on the Statement of Income for the period ended June 30, 2021.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships | |
| Three Months | | Six Months | |
| Interest Expense | | Income (Loss) from Discontinued Operations (net of taxes) | | Interest Expense | | | | Income (Loss) from Discontinued Operations (net of taxes) | |
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 474 | | | $ | 555 | | | $ | 627 | | | | | $ | (1,488) | | |
| The effects of cash flow hedges: | | | | | | | | | | |
| Gain (Loss) on cash flow hedging relationships: | | | | | | | | | | |
| Interest rate swaps: | | | | | | | | | | |
| Amount of gain (loss) reclassified from AOCI to income | 14 | | | (1) | | | 13 | | | | | (2) | | |
| Cross-currency swaps: | | | | | | | | | | |
| Hedged items | — | | | 2 | | | — | | | | | 39 | | |
| Amount of gain (loss) reclassified from AOCI to Income | — | | | (2) | | | — | | | | | (39) | | |
(LG&E)
The following table presents the fair value and the location on the Balance Sheets of derivatives not designated as hedging instruments.
| | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | December 31, 2021 |
| | Assets | | Liabilities | | Assets | | Liabilities |
| Current: | | | | | | | |
| Price Risk Management Assets/Liabilities: | | | | | | | |
| Interest rate swaps | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total current | — | | | 1 | | | — | | | 1 | |
| Noncurrent: | | | | | | | |
| Price Risk Management Assets/Liabilities: | | | | | | | |
| Interest rate swaps | — | | | 9 | | | — | | | 17 | |
| Total noncurrent | — | | | 9 | | | — | | | 17 | |
| Total derivatives | $ | — | | | $ | 10 | | | $ | — | | | $ | 18 | |
The following tables present the pre-tax effect of derivatives not designated as cash flow hedges that are recognized in income or regulatory assets for the period ended June 30, 2022.
| | | | | | | | | | | | | | | | | | | | |
| | | Location of Gain (Loss) Recognized in | | | | |
| Derivative Instruments | | Income on Derivatives | | Three Months | | Six Months |
| Interest rate swaps | | Interest expense | | $ | — | | | $ | 1 | |
| | | Location of Gain (Loss) Recognized in | | | | |
| Derivative Instruments | | Regulatory Assets | | Three Months | | Six Months |
| Interest rate swaps | | Regulatory assets - noncurrent | | $ | 4 | | | $ | 8 | |
The following tables present the pre-tax effect of derivatives not designated as cash flow hedges that are recognized in income or regulatory assets for the period ended June 30, 2021.
| | | | | | | | | | | | | | | | | | | | |
| | | Location of Gain (Loss) Recognized in | | | | |
| Derivative Instruments | | Income on Derivatives | | Three Months | | Six Months |
| Interest rate swaps | | Interest expense | | $ | (1) | | | $ | (2) | |
| | | Location of Gain (Loss) Recognized in | | | | |
| Derivative Instruments | | Regulatory Assets | | Three Months | | Six Months |
| Interest rate swaps | | Regulatory assets - noncurrent | | $ | (3) | | | $ | 3 | |
(PPL, LG&E and KU)
Offsetting Derivative Instruments
PPL, LG&E and KU or certain of their subsidiaries have master netting arrangements in place and also enter into agreements pursuant to which they purchase or sell certain energy and other products. Under the agreements, upon termination of the agreement as a result of a default or other termination event, the non-defaulting party typically would have a right to set off amounts owed under the agreement against any other obligations arising between the two parties (whether under the agreement or not), whether matured or contingent and irrespective of the currency, place of payment or place of booking of the obligation.
PPL, LG&E and KU have elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivatives agreements. The table below summarizes the derivative positions presented in the balance sheets where a right of setoff exists under these arrangements and related cash collateral received or pledged.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Assets | | Liabilities |
| | | | Eligible for Offset | | | | | | Eligible for Offset | | |
| Gross | | Derivative
Instruments | | Cash
Collateral
Received | | Net | | Gross | | Derivative
Instruments | | Cash
Collateral
Pledged | | Net |
| June 30, 2022 | | | | | | | | | | | | | | | |
| Treasury Derivatives | | | | | | | | | | | | | | | |
PPL | $ | 59 | | | $ | 3 | | | $ | 9 | | | $ | 47 | | | $ | 14 | | | $ | 3 | | | $ | — | | | $ | 11 | |
| LG&E | — | | | — | | | — | | | — | | | 10 | | | — | | | — | | | 10 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Assets | | Liabilities |
| | | | Eligible for Offset | | | | | | Eligible for Offset | | |
| Gross | | Derivative
Instruments | | Cash
Collateral
Received | | Net | | Gross | | Derivative
Instruments | | Cash
Collateral
Pledged | | Net |
| December 31, 2021 | | | | | | | | | | | | | | | |
| Treasury Derivatives | | | | | | | | | | | | | | | |
| PPL | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 18 | | | $ | — | | | $ | — | | | $ | 18 | |
| LG&E | — | | | — | | | — | | | — | | | 18 | | | — | | | — | | | 18 | |
Credit Risk-Related Contingent Features
Certain derivative contracts contain credit risk-related contingent features which, when in a net liability position, would permit the counterparties to require the transfer of additional collateral upon a decrease in the credit ratings of PPL, LG&E and KU or certain of their subsidiaries. Most of these features would require the transfer of additional collateral or permit the counterparty to terminate the contract if the applicable credit rating were to fall below investment grade. Some of these features also would allow the counterparty to require additional collateral upon each downgrade in credit rating at levels that remain above investment grade. In either case, if the applicable credit rating were to fall below investment grade, and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent features require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization on derivative instruments in net liability positions.
Additionally, certain derivative contracts contain credit risk-related contingent features that require adequate assurance of performance be provided if the other party has reasonable concerns regarding the performance of PPL's, LG&E's and KU's obligations under the contracts. A counterparty demanding adequate assurance could require a transfer of additional collateral or other security, including letters of credit, cash and guarantees from a creditworthy entity. This would typically involve negotiations among the parties. However, amounts disclosed below represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" features.
(PPL)
At June 30, 2022, derivative contracts in a net liability position that contain credit risk-related contingent features, collateral posted on those positions and the related effect of a decrease in credit ratings below investment grade was an immaterial amount.
15. Asset Retirement Obligations
(PPL, LG&E and KU)
PPL's, LG&E's and KU's ARO liabilities are primarily related to CCR closure costs. See Note 10 for information on the CCR rule. LG&E also has AROs related to natural gas mains and wells. LG&E's and KU's transmission and distribution lines largely operate under perpetual property easement agreements, which do not generally require restoration upon removal of the property. Therefore, no material AROs are recorded for transmission and distribution assets. For LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, deferred accretion and depreciation expense is recovered through cost of removal.
The changes in the carrying amounts of AROs were as follows.
| | | | | | | | | | | | | | | | | |
| | PPL | | LG&E | | KU |
| Balance at December 31, 2021 | $ | 189 | | | $ | 84 | | | $ | 105 | |
| Acquisition of RIE (a) | 10 | | | — | | | — | |
| Accretion | 2 | | | 2 | | | — | |
| | | | | |
| New obligations incurred | 1 | | | 1 | | | — | |
| Changes in estimated timing or cost | 2 | | | 1 | | | 1 | |
| Obligations settled | (23) | | | (9) | | | (14) | |
| Balance at June 30, 2022 | $ | 181 | | | $ | 79 | | | $ | 92 | |
(a) Represents RIE's retirement obligation balance as of the date of acquisition. See note 8 for additional information.
16. Accumulated Other Comprehensive Income (Loss)
(PPL)
The after-tax changes in AOCI by component for the periods ended June 30 were as follows.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Foreign
currency
translation
adjustments | | | | | | Unrealized gains (losses)
on qualifying
derivatives | | | | Defined benefit plans | | |
| | | | | | Equity
investees'
AOCI | | Prior
service
costs | | Actuarial
gain
(loss) | | Total |
| PPL | | | | | | | | | | | | | | | |
| March 31, 2022 | $ | — | | | | | | | $ | 2 | | | $ | 1 | | | $ | (6) | | | $ | (149) | | | $ | (152) | |
| Amounts arising during the period | — | | | | | | | — | | | 1 | | | — | | | 21 | | | 22 | |
| Reclassifications from AOCI | — | | | | | | | — | | | — | | | — | | | 6 | | | 6 | |
| Net OCI during the period | — | | | | | | | — | | | 1 | | | — | | | 27 | | | 28 | |
| June 30, 2022 | $ | — | | | | | | | $ | 2 | | | $ | 2 | | | $ | (6) | | | $ | (122) | | | $ | (124) | |
| | | | | | | | | | | | | | | |
| December 31, 2021 | $ | — | | | | | | | $ | 1 | | | $ | — | | | $ | (6) | | | $ | (152) | | | $ | (157) | |
| Amounts arising during the period | — | | | | | | | — | | | 2 | | | (1) | | | 21 | | | 22 | |
| Reclassifications from AOCI | — | | | | | | | 1 | | | — | | | 1 | | | 9 | | | 11 | |
| Net OCI during the period | — | | | | | | | 1 | | | 2 | | | — | | | 30 | | | 33 | |
| June 30, 2022 | $ | — | | | | | | | $ | 2 | | | $ | 2 | | | $ | (6) | | | $ | (122) | | | $ | (124) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Foreign
currency
translation
adjustments | | | | | | Unrealized gains (losses)
on qualifying
derivatives | | | | Defined benefit plans | | |
| | | | | | Equity
investees'
AOCI | | Prior
service
costs | | Actuarial
gain
(loss) | | Total |
| | | | | | | | | | | | | | | |
| March 31, 2021 | $ | (855) | | | | | | | $ | (5) | | | $ | — | | | $ | (16) | | | $ | (3,006) | | | $ | (3,882) | |
| Amounts arising during the period | 69 | | | | | | | (9) | | | — | | | — | | | (6) | | | 54 | |
| Reclassifications from AOCI | — | | | | | | | (1) | | | — | | | (7) | | | 67 | | | 59 | |
| Reclassifications from AOCI due to the sale of the U.K. utility business (Note 8) | 786 | | | | | | | 15 | | | — | | | 8 | | | 2,769 | | | 3,578 | |
| Net OCI during the period | 855 | | | | | | | 5 | | | — | | | 1 | | | 2,830 | | | 3,691 | |
| June 30, 2021 | $ | — | | | | | | | $ | — | | | $ | — | | | $ | (15) | | | $ | (176) | | | $ | (191) | |
| | | | | | | | | | | | | | | |
| December 31, 2020 | $ | (1,158) | | | | | | | $ | — | | | $ | — | | | $ | (16) | | | $ | (3,046) | | | $ | (4,220) | |
| Amounts arising during the period | 372 | | | | | | | (39) | | | — | | | — | | | (6) | | | 327 | |
| Reclassifications from AOCI | — | | | | | | | 24 | | | — | | | (7) | | | 107 | | | 124 | |
| Reclassifications from AOCI due to the sale of the U.K. utility business (Note 8) | 786 | | | | | | | 15 | | | — | | | 8 | | | 2,769 | | | 3,578 | |
| Net OCI during the period | 1,158 | | | | | | | — | | | — | | | 1 | | | 2,870 | | | 4,029 | |
| June 30, 2021 | $ | — | | | | | | | $ | — | | | $ | — | | | $ | (15) | | | $ | (176) | | | $ | (191) | |
The following table presents PPL's gains (losses) and related income taxes for reclassifications from AOCI for the periods ended June 30.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months | | Six Months | | Affected Line Item on the |
| Details about AOCI | | 2022 | | 2021 | | 2022 | | 2021 | | Statements of Income |
| Qualifying derivatives | | | | | | | | | | |
| Interest rate swaps | | $ | (1) | | | $ | 14 | | | $ | (2) | | | $ | 13 | | | Interest Expense |
| | | | | | | | | | |
| | — | | | (1) | | | — | | | (2) | | | Loss from Discontinued Operations (net of income taxes) |
| Cross-currency swaps | | — | | | (2) | | | — | | | (39) | | | Loss from Discontinued Operations (net of income taxes) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total Pre-tax | | (1) | | | 11 | | | (2) | | | (28) | | | |
| Income Taxes | | 1 | | | (10) | | | 1 | | | 4 | | | |
| Total After-tax | | — | | | 1 | | | (1) | | | (24) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Defined benefit plans | | | | | | | | | | |
| Prior service costs (a) | | — | | | 9 | | | (1) | | | 9 | | | |
| Net actuarial loss (a) | | (8) | | | (71) | | | (12) | | | (133) | | | |
| Total Pre-tax | | (8) | | | (62) | | | (13) | | | (124) | | | |
| Income Taxes | | 2 | | | 2 | | | 3 | | | 24 | | | |
| Total After-tax | | (6) | | | (60) | | | (10) | | | (100) | | | |
| | | | | | | | | | |
| Sale of the U.K. utility business (Note 9) | | | | | | | | | | |
| Foreign currency translation adjustments | | — | | | (646) | | | — | | | (646) | | | Loss from Discontinued Operations (net of income taxes) |
| Qualifying derivatives | | — | | | (15) | | | — | | | (15) | | | Loss from Discontinued Operations (net of income taxes) |
| Defined benefit plans | | — | | | (3,577) | | | — | | | (3,577) | | | Loss from Discontinued Operations (net of income taxes) |
| Total Pre-tax | | — | | | (4,238) | | | — | | | (4,238) | | | |
| Income Taxes | | — | | | 660 | | | — | | | 660 | | | |
| Total After-tax | | — | | | (3,578) | | | — | | | (3,578) | | | |
| Total reclassifications during the period | | $ | (6) | | | $ | (3,637) | | | $ | (11) | | | $ | (3,702) | | | |
(a) These AOCI components are included in the computation of net periodic defined benefit cost. See Note 9 for additional information.