PPL CORPORATION
PPL ELECTRIC UTILITIES CORPORATION
LOUISVILLE GAS AND ELECTRIC COMPANY
KENTUCKY UTILITIES COMPANY
FORM 10-K ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 20172023
TABLE OF CONTENTS
This combined Form 10-K is separately filed by the following Registrants in their individual capacity: PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company. Information contained herein relating to any individual Registrant is filed by such Registrant solely on its own behalf and no Registrant makes any representation as to information relating to any other Registrant, except that information under "Forward-Looking Information" relating to subsidiaries of PPL Corporation is also attributed to PPL Corporation and information relating to the subsidiaries of LG&E and KU Energy LLC is also attributed to LG&E and KU Energy LLC.Corporation.
Unless otherwise specified, references in this Report, individually, to PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company are references to such entities directly or to one or more of their subsidiaries, as the case may be, the financial results of which subsidiaries are consolidated into such Registrants' financial statements in accordance with GAAP. This presentation has been applied where identification of particular subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis.
| Item | Page | ||||||||||
| PART I | |||||||||||
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| 1A. | |||||||||||
| 1B. | |||||||||||
| 1C. | |||||||||||
| 2. | |||||||||||
| 3. | |||||||||||
| 4. | |||||||||||
| PART II | |||||||||||
| 5. | |||||||||||
| 6. | |||||||||||
| 7. | |||||||||||
| Item | Page | ||
| PART I | |||
| 1. | |||
| 1A. | |||
| 1B. | |||
| 2. | |||
| 3. | |||
| 4. | |||
| PART II | |||
| 5. | |||
| 6. | |||
| 7. | |||
| Item | Page | ||||||||||
| 7A. | |||||||||||
| 8. | Financial Statements and Supplementary Data | ||||||||||
| FINANCIAL STATEMENTS | |||||||||||
| PPL Corporation and Subsidiaries | |||||||||||
| PPL Electric Utilities Corporation and Subsidiaries | |||||||||||
| Louisville Gas and Electric Company | |||||||||||
| Kentucky Utilities Company | |||||||||||
| Item | Page | ||||||||||
| COMBINED NOTES TO FINANCIAL STATEMENTS | |||||||||||
| 9. | |||||||||||
| 9A. | |||||||||||
| 9B. | |||||||||||
| 9C. | |||||||||||
| PART III | |||||||||||
| 10. | |||||||||||
| 11. | |||||||||||
| 12. | |||||||||||
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| 14. | |||||||||||
| PART IV | |||||||||||
| 15. | |||||||||||
| Item | Page | ||
| COMBINED NOTES TO FINANCIAL STATEMENTS | |||
| SUPPLEMENTARY DATA | |||
| Schedule I - Condensed Unconsolidated Financial Statements | |||
| 9. | |||
| 9A. | |||
| 9B. | |||
| PART III | |||
| 10. | |||
| 11. | |||
| 12. | |||
| 13. | |||
| 14. | |||
| PART IV | |||
| 15. | |||
GLOSSARY OF TERMS AND ABBREVIATIONS
PPL Corporation and its subsidiaries
CEP Reserves- CEP Reserves, Inc., a cash management subsidiary of PPL that maintains cash reserves for the balance sheet management of PPL and certain subsidiaries.
KU - Kentucky Utilities Company, a public utility subsidiary of LKE engaged in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky.
LG&E - Louisville Gas and Electric Company, a public utility subsidiary of LKE engaged in the regulated generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas in Kentucky.
LKE - LG&E and KU Energy LLC, a subsidiary of PPL and the parent of LG&E, KU and other subsidiaries.
LKS -LG&E and KU Services Company, a subsidiary of LKE that provides administrative, management and support services primarily to LG&E and KU, as well as to LKE and its other subsidiaries.
Narragansett Electric - The Narragansett Electric Company, an entity that serves electric and natural gas customers in Rhode Island. On May 25, 2022, PPL and its subsidiary, PPL Rhode Island Holdings announced the completion of the acquisition of Narragansett Electric, which will continue to provide services under the name Rhode Island Energy.
PPL - PPL Corporation, the ultimate parent holding company of PPL Electric, PPL Energy Funding, PPL Capital Funding, LKE, RIE and other subsidiaries.
PPL Capital Funding - PPL Capital Funding, Inc., a financing subsidiary of PPL that provides financing for the operations of PPL and certain subsidiaries. Debt issued by PPL Capital Funding is fully and unconditionally guaranteed as to payment by PPL.
PPL Electric - PPL Electric Utilities Corporation, a public utility subsidiary of PPL engaged in the regulated transmission and distribution of electricity in its Pennsylvania service area and that provides electricity supply to its retail customers in this area as a PLR.
PPL Energy Funding - PPL Energy Funding Corporation, a subsidiary of PPL and the parent holding company of PPL Global and other subsidiaries.
PPL Energy Holdings- PPL Energy Holdings, LLC, a subsidiary of PPL and the parent holding company of PPL Energy Funding, LKE, PPL Electric, PPL Rhode Island Holdings, PPL Services and other subsidiaries.
PPL EU Services - PPL EU Services Corporation, a subsidiary of PPL that providesprovided administrative, management and support services primarily to PPL Electric. On December 31, 2021, PPL EU Services merged into PPL Services.
PPL Global - PPL Global, LLC, a subsidiary of PPL Energy Funding that, prior to the sale of the U.K. utility business on June 14, 2021, primarily through its subsidiaries, ownsowned and operatesoperated WPD, PPL's regulated electricity distribution businesses in the U.K. PPL Global was not included in the sale of the U.K. utility business on June 14, 2021.
PPL Rhode Island Holdings - PPL Rhode Island Holdings, LLC, a subsidiary of PPL Energy Holdings formed for the purpose of acquiring Narragansett Electric to which certain interests of PPL Energy Holdings in the Narragansett SPA were assigned.
PPL Services - PPL Services Corporation, a subsidiary of PPL that provides administrative, management and support services to PPL and its subsidiaries.
PPL WPD Limited - an indirectPPL WPD Limited, a U.K. subsidiary of PPL Global, which carries a liability for a closed defined benefit pension plan and a receivable from WPD plc. Following a reorganization in October 2015 and October 2017,Global. Prior to the sale of the U.K. utility business on June 14, 2021, PPL WPD Limited iswas an indirect parent to WPD plc having previously been a sister company.
RIE - Rhode Island Energy, the name under which Narragansett Electric will continue to provide services subsequent to its acquisition by PPL and its subsidiaries.subsidiary, PPL Rhode Island Holdings on May 25, 2022.
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Other terms and abbreviations
£ - British pound sterling.
401(h) account(s) - a sub-account established within a qualified pension trust to provide for the payment of retiree medical costs.
Act 11 - Act 11 of 2012 that became effective on April 16, 2012. The Pennsylvania legislation authorized the PUCPAPUC to approve two specific ratemaking mechanisms: the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, a DSIC.
Act 129 - Act 129 of 2008 that became effective in October 2008. The law amended the Pennsylvania Public Utility Code and created an energy efficiency and conservation program and smart metering technology requirements, adopted new PLR electricity supply procurement rules, provided remedies for market misconduct and changed the Alternative Energy Portfolio Standard (AEPS).
Act 129 Smart Meter program - PPL Electric's system-wide meter replacement program that installs wireless digital meters that provide secure communication between PPL Electric and the meter as well as all related infrastructure.
AFUDC - allowance for funds used during construction. The cost of equity and debt funds used to finance construction projects of regulated businesses, which is capitalized as part of construction costs.
AOCI - accumulated other comprehensive income or loss.
ARO - asset retirement obligation.
ATM Program - at-the-market stock offering program.
Bcf - billion cubic feet. A unit of measure commonly used in quoting volumes of natural gas.
Cane Run Unit 7 - a natural gas combined-cycleNGCC generating unit in Kentucky, jointly owned by LG&E and KU.
CCR(s) -coal combustion residual(s). CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes.
Clean Air Act - federal legislation enacted to address certain environmental issues related to air emissions, including acid rain, ozone and toxic air emissions.
Clean Water Act - federal legislation enacted to address certain environmental issues relating to water quality including effluent discharges, cooling water intake, and dredge and fill activities.
CPCN - Certificate of Public Convenience and Necessity. Authority granted by the KPSC pursuant to Kentucky Revised Statute 278.020 to provide utility service to or for the public or the construction of certain plant, equipment, property or facilityfacilities for furnishing of utility service to the public. A CPCN is required for any capital addition, subject to KPSC jurisdiction, in excess of $100 million.
Customer Choice Act - the Pennsylvania Electricity Generation Customer Choice and Competition Act, legislation enacted to restructure the state's electric utility industry to create retail access to a competitive market for generation of electricity.
DDCP - Directors Deferred Compensation Plan.
DSM -Demand Side Management. Pursuant to Kentucky Revised Statute 278.285, the KPSC may determine the reasonableness of DSM programs proposed by any utility under its jurisdiction. DSM programs consist of energy efficiency programs intended to reduce peak demand and delay the investment in additional power plant construction, provide customers with tools and information regarding their energy usage and support energy efficiency.
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Earnings from Ongoing Operations-a non-GAAP financial measure of earnings adjusted for the impact of special items and used in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A).
EBPB- Employee Benefit Plan Board. The administrator of PPL's U.S. qualified retirement plans, which is charged with the fiduciary responsibility to oversee and manage those plans and the investments associated with those plans.
ECR - Environmental Cost Recovery. Pursuant to Kentucky Revised Statute 278.183, Kentucky electric utilities are entitled to the current recovery of costs of complying with the Clean Air Act, as amended, and those federal, state or local environmental requirements that apply to coal combustion wastes and by-productsbyproducts from the production of energy from coal.
ELG(s)- Effluent Limitation Guidelines, regulations promulgated by the EPA.
Environmental ResponseFund - Established in RIPUC Docket No. 2930. Created to satisfy remedial and clean-up obligations of RIE arising from the past ownership and/or operation of manufactured gas plants and sites associated with the operation and disposal activities of such gas plants.
EPA - Environmental Protection Agency, a U.S. government agency.
EPS - earnings per share.
FERC - Federal Energy Regulatory Commission, the U.S. federal agency that regulates, among other things, interstate transmission and wholesale sales of electricity, hydroelectric power projects and related matters.
GAAP - Generally Accepted Accounting Principles in the U.S.
GLT-gas line tracker. The KPSC approved mechanism for LG&E's recovery of certain costs associated with gas transmission lines, gas service lines, gas risers, leak mitigation, and gas main replacements.
Green Tariff - a KPSC approved rate schedule, permitting customers to contract with LG&E or KU for the purchase of renewable energy certificates, construction of solar generation and use of the energy produced, or the purchase of energy from a renewable energy generator.
GWh - gigawatt-hour, one million kilowatt hours.
IBEW- International Brotherhood of Electrical Workers.
ICPKE - The PPL Incentive Compensation Plan for Key Employees. The ICPKE provides for incentive compensation to certain employees below the level of senior executive.
If-Converted Method- A method applied to calculate diluted EPS for a company with outstanding convertible debt. This method generally adds back the interest charges of the debt to net income and the convertible debt is assumed to have been converted to equity at the beginning of the period, and the resulting common shares are treated as outstanding shares for diluted EPS calculations.
IRA-Inflation Reduction Act, a U.S. federal law, which aims to curb inflation by possibly reducing the federal government budget deficit, lowering prescription drug prices, and investing in domestic energy production while promoting clean energy.
IRS - Internal Revenue Service, a U.S. government agency.
ISO - Independent System Operator.
KPSC - Kentucky Public Service Commission, the state agency that has jurisdiction over the regulation of rates and service of utilities in Kentucky.
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KU 2010 Mortgage Indenture - KU's Indenture, dated as of October 1, 2010, to The Bank of New York Mellon, as supplemented.
kVA - kilovolt ampere.
kWh - kilowatt hour, basic unit of electrical energy.
LCIDA - Lehigh County Industrial Development Authority.
LG&E 2010 Mortgage Indenture - LG&E's Indenture, dated as of October 1, 2010, to The Bank of New York Mellon, as supplemented.
MMBtu - one million British Thermal Units.
Moody's - Moody's Investors Service, Inc., a credit rating agency.
MW - megawatt, one thousand kilowatts.
MWac - megawatt, alternating current. The measure of the power output from a solar installation.
NAAQS - National Ambient Air Quality Standards periodically adopted pursuant to the Clean Air Act.
National Grid USA - National Grid USA is a wholly-owned subsidiary of National Grid plc, a British multinational electricity and gas utility company headquartered in London, England.
NEP - New England Power Company, a National Grid U.S. affiliate.
NERC - North American Electric Reliability Corporation.
NGCC - natural gas-fired combined-cycle generating plant.Natural gas combined cycle.
NPNS - the normal purchases and normal sales exception as permitted by derivative accounting rules. Derivatives that qualify for this exception may receive accrual accounting treatment.
OCI - other comprehensive income or loss.
PAPUC - Pennsylvania Public Utility Commission, the state agency that regulates certain ratemaking, services, accounting and operations of Pennsylvania utilities.
PEDFA - Pennsylvania Economic Development Financing Authority.
Performance unit - stock-based compensation award that represents a variable number of shares of PPL common stock that a recipient may receive based on PPL's attainment of (i) relative total shareowner return (TSR) over a three-year performance period as compared to companies in the Philadelphia Stock ExchangePHLX Utility Sector Index; or (ii) corporate return on equity (ROE) based on the average of the annual ROE for each year of the three-year performance period. In light of the transformational nature of the potential sale of the U.K. utility business in 2021, PPL's ROE-based performance units issued for 2021 were based on a one-year performance period from January 1, 2021 to December 31, 2021; however, these units retained the three year vesting schedule and other characteristics.
PJM - PJM Interconnection, L.L.C., operator of the electricity transmission network and electricity energy market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
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PLR - Provider of Last Resort, the role of PPL Electric in providing default electricity supply within its delivery area to retail customers who have not chosen to select an alternative electricity supplier under the Customer Choice Act.
PP&E - property, plant and equipment.
PPL Energy Supply PPL EnergyPlus, LLC, a subsidiary of PPL Energy Supply that marketed and traded wholesale and retail electricity and gas, and supplied energy and energy services in competitive markets.
PPL EU Services - PPL EU Services Corporation, a former subsidiary of PPL that, prior to being merged into PPL Services on December 31, 2021, provided administrative, management and other subsidiaries.support services primarily to PPL Electric.
PPL WPD Investments Limited - PPL WPD Investments Limited, which was, prior to the sale of Pennsylvania utilities.
RAR – Retired Asset Recovery rider, established by KPSC orders in 2021 to provide for recovery of and return on the remaining investment in certain electric generating units upon their retirement over a ten-year period following retirement.
RCRA - Resource Conservation and Recovery Act of 1976.
Registrant(s) - refers to the Registrants named on the cover of this Report (each a "Registrant" and collectively, the "Registrants").
Riverstone - Riverstone Holdings LLC, a Delaware limited liability company and, as of December 6, 2016, ultimate parent company of the entities that own the competitive power generation business contributed to Talen Energy.
RTO - Regional Transmission Operator, an electric power transmission system operator that coordinates, controls and monitors a multi-state electric grid.
Safari Energy - Safari Energy, LLC, which was, prior to the sale of Safari Holdings on November 1, 2022, a subsidiary of Safari Holdings that provided solar energy solutions for commercial customers in the U.S.
Safari Holdings - Safari Holdings, LLC, which was, prior to its sale on November 1, 2022, a Delaware limited liabilitysubsidiary of PPL and parent holding company controlled by Riverstone, that owns the competitive power generation business contributed by its owners to Talenof Safari Energy.
Sarbanes-Oxley - Sarbanes-Oxley Act of 2002, which sets requirements for management's assessment of internal controls for financial reporting. It also requires an independent auditor to make its own assessment.
Scrubber - an air pollution control device that can remove particulates and/or gases (primarily sulfur dioxide) from exhaust gases.
SEC - the U.S. Securities and Exchange Commission, a U.S. government agency primarily responsible to protect investors and maintain the integrity of the securities markets.
SIP - PPL Corporation's Amended and Restated 2012 Stock Incentive Plan.
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Smart metering technology - technology that can measure, among other things, time of electricity consumption to permit offering rate incentives for usage during lower cost or demand intervals. The use of this technology also has the potential to strengthen network reliability.
SOFR - Secured Overnight Financing Rate, a broad measure of the cost of borrowing cash overnight collateralized by Treasury securities.
S&P - Standard & Poor'sS&P Global Ratings, Services, a credit rating agency.
Superfund - federal environmental statute that addresses remediation of contaminated sites; states also have similar statutes.
Talen Energy - Talen Energy Corporation, the Delaware corporation formed to be the publicly traded company and owner of the competitive generation assets of PPL Energy Supply and certain affiliates of Riverstone, which as of December 6, 2016, became wholly owned by Riverstone.
Talen Energy Marketing - Talen Energy Marketing, LLC, the newsuccessor name of PPL EnergyPlus, subsequent toafter the spinoff of PPL Energy Supply that marketed and traded wholesale and retail electricity and gas, and supplied energy and energy services in competitive markets, after the June 1, 2015 spinoff of PPL Energy Supply.
TCJA - Tax Cuts and Jobs Act. Comprehensive U.S. federal tax legislation enacted on December 22, 2017.
Total shareowner return - the change in market value of a share of the Company'scompany's common stock plus the value of all dividends paid on a share of the common stock during the applicable performance period, divided by the price of the common stock as of the beginning of the performance period. The price used for purposes of this calculation is the average share price for the 20 trading days at the beginning and end of the applicable period.
Treasury Stock Method - a method applied to calculate diluted EPS that assumes any proceeds that could be obtained upon exercise of options and warrants (and their equivalents) would be used to purchase common stock at the average market price during the relevant period.
VEBA - Voluntary Employee Benefit Association Trust, accounts for healthBeneficiary Association. A tax-exempt trust under the Internal Revenue Code Section 501 (c)(9) used by employers to fund and welfare plans for future benefit payments for employees, retirees or their beneficiaries.pay eligible medical, life and similar benefits.
VSCC - Virginia State Corporation Commission, the state agency that has jurisdiction over the regulation of Virginia corporations, including utilities.
WPD - Prior to the sale of the U.K. utility business on June 14, 2021, refers to PPL WPD Investments Limited and its subsidiaries. WPD was included in the sale of the U.K. utility business on June 14, 2021.
WPD plc - Western Power Distribution plc, prior to the sale of the U.K utility business, a U.K. indirect subsidiary of PPL WPD Limited. Its principal indirectly owned subsidiaries are WPD (East Midlands), WPD (South Wales), WPD (South West) and WPD (West Midlands). WPD plc was included in the sale of the U.K. utility business on June 14, 2021.
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Forward-looking Information
Statements contained in this Annual Report concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are other than statements of historical fact are "forward-looking statements" within the meaning of the federal securities laws. Although the Registrants believe that the expectations and assumptions reflected in these statements are reasonable, there can be no assurance that these expectations will prove to be correct. Forward-looking statements are subject to many risks and uncertainties, and actual results may differ materially from the results discussed in forward-looking statements. In addition to the specific factors discussed in "Item 1A. Risk Factors" and in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report, the following are among the important factors that could cause actual results to differ materially and adversely from the forward-looking statements:
•strategic acquisitions, dispositions, or similar transactions and our ability to consummate these business transactions or realize expected benefits from them;
•pandemic health events or other catastrophic events such as fires, earthquakes, explosions, floods, droughts, tornadoes, hurricanes and other extreme weather-related events (including events potentially caused or exacerbated by climate change) and their impact on economic conditions, financial markets and supply chains;
•capital market conditions, including the availability of capital, credit or insurance, changes in interest rates and certain economic indices, and decisions regarding capital structure;
•volatility in or the impact of other changes in financial markets, commodity prices and economic conditions, including inflation;
•weather and other conditions affecting generation, transmission and distribution operations, operating costs and customer energy use;
•the outcome of rate cases or other cost recovery, revenue or revenue filings;regulatory proceedings;
•the direct or indirect effects on PPL or its subsidiaries or business systems of cyber-based intrusion or the threat of cyberattacks;
•significant changes in U.S. or U.K. tax laws or regulations, including the TCJA;
•expansion of alternative and distributed sources of electricity generation and storage;
•the effectiveness of our risk management programs, including foreign currencycommodity and interest rate hedging;
•defaults by counterparties or suppliers for energy, capacity, coal, natural gas or key commodities, goods or services;
•a material decline in the market value of PPL's equity;
•significant decreases in the fair value of debt and equity securities and itstheir impact on the value of assets in defined benefit plans, and the potentialrelated cash funding requirements if the fair value declines;of those assets decline;
•interest rates and their effect on pension and retiree medical liabilities, ARO liabilities, and interest payable on certain debt securities;securities, and the general economy;
•the potential impact of any unrecorded commitments and liabilities of the Registrants and their subsidiaries;
•new accounting requirements or new interpretations or applications of existing requirements;
•adverse changes in the corporate credit ratings or securities analyst rankings of the Registrants and their securities;
•any requirement to record impairment charges pursuant to GAAP with respect to any of our significant investments;
•laws or regulations to reduce emissions of GHGs or the physical effects of climate change;
•continuing ability to access fuel supply for LG&E and KU, as well as the ability to recover fuel costs and environmental expenditures in a timely manner at LG&E and KU and natural gas supply costs at LG&E;&E and RIE;
•changes in political, regulatory or economic conditions in states regions or countriesregions where the Registrants or their subsidiaries conduct business;
•changes in state, federal or foreign legislation or regulatory developments;
•the impact of any state, federal or foreign investigations applicable to the Registrants and their subsidiaries and the energy industry;
•our ability to attract and retain qualified employees;
•the effect of changing expectations and demands of our customers, regulators, investors and stakeholders, including views on environmental, social and governance concerns;
•the effect of any business or industry restructuring;
•development of new projects, markets and technologies;
•performance of new ventures;
•collective labor bargaining negotiations;negotiations and labor costs; and
•the outcome of litigation againstinvolving the Registrants and their subsidiaries.
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Any forward-looking statements should be considered in light of these important factors and in conjunction with other documents of the Registrants on file with the SEC.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for the Registrants to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Any forward-looking statement speaks only as of the date on which such statement is made, and the Registrants undertake no obligation to update the information contained in the statement to reflect subsequent developments or information.
Investors should note that PPL announces material financial information in SEC filings, press releases and public conference calls. In accordance with SEC guidelines, PPL also uses the Investors section of its website, www.pplweb.com, to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on PPL's website is not part of this document.
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PART I
ITEM 1. BUSINESS
General
(All Registrants)
PPL, Corporation, headquartered in Allentown, Pennsylvania, is a utility holding company, incorporated in 1994, in connection with the deregulation of electricity generation in Pennsylvania, to serve as the parent company to the regulated utility, PPL Electric, and to generation and other unregulated business activities. PPL Electric was founded in 1920 as Pennsylvania Power & Light Company.1994. PPL, through its regulated utility subsidiaries, delivers electricity to customers in the U.K., Pennsylvania, Kentucky, Virginia, and Tennessee;Rhode Island; delivers natural gas to customers in Kentucky;Kentucky and Rhode Island; and generates electricity from power plants in Kentucky. In June 2015, PPL completed the spinoff of PPL Energy Supply, which combined its competitive power generation businesses with those of Riverstone to form a new, stand-alone, publicly traded company named Talen Energy. See "Spinoff of PPL Energy Supply" below for more information.
PPL's principal subsidiaries at December 31, 20172023 are shown below (* denotes a Registrant).
| PPL Corporation* | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPL Capital Funding | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPL Electric* | LKE A holding company that owns regulated utility operations through its subsidiaries, LG&E and KU | RIE Engages in the regulated transmission, distribution and sale of electricity and regulated distribution and sale of natural gas in Rhode Island | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
LG&E* | KU* | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Pennsylvania Regulated Segment | Kentucky Regulated Segment | Rhode Island Regulated Segment | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In addition to PPL, the other Registrants included in this filing are as follows.
PPL Electric Utilities Corporation, headquartered in Allentown, Pennsylvania, is a wholly ownedwholly-owned subsidiary of PPL organized in Pennsylvania in 1920 and a regulated public utility that is an electricity transmission and distribution service provider in eastern and central Pennsylvania. PPL Electric is subject to regulation as a public utility by the PUC,PAPUC, and certain of its transmission activities are subject to the jurisdiction of the FERC under the Federal Power Act. PPL Electric delivers electricity in its Pennsylvania service area and provides electricity supply to retail customers in that area as a PLR under the Customer Choice Act. PPL Electric was organized in 1920 as Pennsylvania Power & Light Company.
LG&E, and KU Energy LLC, headquartered in Louisville, Kentucky, is a wholly owned subsidiary of PPL and a holding company that owns regulated utility operations through its subsidiaries, LG&E and KU, which constitute substantially all of LKE's assets. LG&E and KU are engaged in the generation, transmission, distribution and sale of electricity. LG&E also
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of the FERC under the Federal Power Act. KU serves its Kentucky customers under the KU name and its Virginia customers under the Old Dominion Power name and its Kentucky and Tennessee customers under the KU name. KU was incorporated in Kentucky in 1912 and in Virginia in 1991.
Segment Information
(PPL)
PPL is organized into three reportable segments as depicted in the chart above: U.K. Regulated, Kentucky Regulated, and Pennsylvania Regulated. The U.K. Regulated segment has no related subsidiary Registrants. PPL's other reportable segments' resultswhich primarily representrepresents the results of its related subsidiary Registrants, except thatLG&E and KU, Pennsylvania Regulated, which primarily represents the reportable segments are also allocated certainresults of PPL Electric, and Rhode Island Regulated, which primarily represents the results of RIE. "Corporate and Other" primarily includes corporate level financing costs, certain unallocated costs, and othercertain non-recoverable costs that are not includedincurred in conjunction with the acquisition of Narragansett Electric and the financial results of Safari Energy, prior to its sale on November 1, 2022.
Beginning on January 1, 2023, the applicable subsidiary Registrants. PPL also has corporateKentucky Regulated segment consists primarily of the regulated electricity generation, transmission and other costs which primarily include financing costs incurred at the corporate level that have not been allocated or assigned to the segments,distribution operations conducted by LG&E and KU, as well as certain other unallocated costs.LG&E's regulated distribution and sale of natural gas. Prior to January 1, 2023, the Kentucky Regulated segment also included the financing activities of LKE. The financing activity of LKE is presented in "Corporate and Other" beginning on January 1, 2023. Prior periods have been adjusted to reflect this change. As a result, PPL’s segments consist of its regulated operations in Kentucky, Pennsylvania and Rhode Island and exclude any incremental financing activities of holding companies, which Management believes is a more meaningful presentation as it provides information on the June 1, 2015 spinoff of PPL Energy Supply, PPL no longer has a Supply segment. Thecore regulated operations of the Supply segment are included in "Loss from Discontinued Operations (net of income taxes)" on the Statements of Income.PPL.
A comparison of PPL's three regulatedRegulated segments is shown below.
| Kentucky | Pennsylvania | Rhode Island | |||||||||||||||
| Regulated | Regulated | Regulated | |||||||||||||||
| For the year ended December 31, 2023: | |||||||||||||||||
| Operating Revenues (in billions) | $ | 3.5 | $ | 3.0 | $ | 1.9 | |||||||||||
| Net Income (in millions) | $ | 552 | $ | 519 | $ | 96 | |||||||||||
| Electricity delivered (GWh) | 28,809 | 35,704 | 7,174 | ||||||||||||||
| Natural gas delivered (Bcf) | 41 | — | 38 | ||||||||||||||
| At December 31, 2023: | |||||||||||||||||
| Regulatory Asset Base (in billions) (a) | $ | 12.0 | $ | 9.8 | $ | 3.2 | |||||||||||
| Service area (in square miles) | 8,000 | 10,000 | 1,200 | ||||||||||||||
| Customers (in millions) | 1.3 | 1.5 | 0.8 | ||||||||||||||
| Kentucky | Pennsylvania | ||||||||||
| U.K. Regulated | Regulated | Regulated | |||||||||
| For the year ended December 31, 2017: | |||||||||||
| Operating Revenues (in billions) | $ | 2.1 | $ | 3.2 | $ | 2.2 | |||||
| Net Income (in millions) | $ | 652 | $ | 286 | $ | 359 | |||||
| Electricity delivered (GWh) | 74,317 | 31,839 | 35,996 | ||||||||
| At December 31, 2017: | |||||||||||
| Regulatory Asset Base (in billions) (a) | $ | 9.8 | $ | 9.2 | $ | 6.9 | |||||
| Service area (in square miles) | 21,600 | 9,400 | 10,000 | ||||||||
| End-users (in millions) | 7.9 | 1.3 | 1.4 | ||||||||
(a)Represents capitalization for Kentucky Regulated and rate base for Pennsylvania Regulated and Rhode Island Regulated. The amount for Rhode Island Regulated excludes acquisition-related adjustments for non-earning assets.
See Note 2 to the Financial Statements for additional financial information aboutby segment. See Note 3 to the segments.Financial Statements for additional revenue information.
(PPL Electric, LKE, LG&E and KU)
PPL Electric has two operating segments, thatdistribution and transmission, which are aggregated into a single reportable segment. LKE,Each of LG&E and KU are individuallyoperates as a single operating and reportable segments.segment.
| 2017 | 2016 | 2015 | |||||||||
| Operating Revenues (a) | $ | 2,091 | $ | 2,207 | $ | 2,410 | |||||
| 2017 | 2016 | |||||||
| Taxes collected in revenues | £ | 57 | £ | 53 | ||||
| Taxes recorded under GAAP | 139 | 119 | ||||||
| Incentive Received | Calendar Year Ended Incentive | |||||
| Calendar Year Ended Incentive Earned | (in millions) | Included in Revenue | ||||
| 2014 | £ | 83 | 2016 | |||
| 2015 | 79 | 2017 | ||||
| 2016 | 76 | 2018 | ||||
| 2017 (a) | 65-80 | 2019 | ||||
| 2018 (a) | 70-85 | 2020 | ||||
(PPL, LKE, LG&E and KU)
LG&E and KU direct subsidiaries of LKE, are engaged in the regulated generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, Virginia and Tennessee.also Virginia. LG&E also engages in the distribution and sale of natural gas in Kentucky. LG&E provides electric service to approximately 411,000436,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in nine counties and provides natural gas service to approximately 326,000335,000 customers in its electric service area and eight additional counties in Kentucky. KU provides electric service to approximately 525,000545,000 customers in 77 counties in central, southeastern and western Kentucky and approximately 28,000 customers in five counties in southwestern Virginia, and three customers in Tennessee, covering
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approximately 4,800 non-contiguous square miles. KU also sells wholesale electricity to 10two municipalities in Kentucky under load following contracts.
| 2017 | 2016 | 2015 | ||||||||||||||||||
| Revenue | % of Revenue | Revenue | % of Revenue | Revenue | % of Revenue | |||||||||||||||
| LKE | ||||||||||||||||||||
| Commercial | $ | 854 | 27 | $ | 834 | 27 | $ | 816 | 26 | |||||||||||
| Industrial | 603 | 19 | 601 | 19 | 628 | 20 | ||||||||||||||
| Residential | 1,259 | 40 | 1,261 | 40 | 1,245 | 40 | ||||||||||||||
| Other (a) | 280 | 9 | 288 | 9 | 267 | 9 | ||||||||||||||
| Wholesale - municipal | 112 | 4 | 116 | 4 | 114 | 4 | ||||||||||||||
| Wholesale - other (b) | 48 | 1 | 41 | 1 | 45 | 1 | ||||||||||||||
| Total | $ | 3,156 | 100 | $ | 3,141 | 100 | $ | 3,115 | 100 | |||||||||||
| 2017 | 2016 | 2015 | ||||||||||||||||||
| Revenue | % of Revenue | Revenue | % of Revenue | Revenue | % of Revenue | |||||||||||||||
| LG&E | ||||||||||||||||||||
| Commercial | $ | 453 | 31 | $ | 442 | 31 | $ | 436 | 30 | |||||||||||
| Industrial | 187 | 13 | 185 | 13 | 199 | 14 | ||||||||||||||
| Residential | 637 | 44 | 627 | 44 | 633 | 44 | ||||||||||||||
| Other (a) | 123 | 8 | 135 | 9 | 117 | 8 | ||||||||||||||
| Wholesale - other (b) | 53 | 4 | 41 | 3 | 59 | 4 | ||||||||||||||
| Total | $ | 1,453 | 100 | $ | 1,430 | 100 | $ | 1,444 | 100 | |||||||||||
| 2017 | 2016 | 2015 | ||||||||||||||||||
| Revenue | % of Revenue | Revenue | % of Revenue | Revenue | % of Revenue | |||||||||||||||
| KU | ||||||||||||||||||||
| Commercial | $ | 401 | 23 | $ | 392 | 22 | $ | 380 | 22 | |||||||||||
| Industrial | 416 | 24 | 416 | 24 | 429 | 25 | ||||||||||||||
| Residential | 622 | 36 | 634 | 36 | 612 | 35 | ||||||||||||||
| Other (a) | 157 | 9 | 153 | 9 | 150 | 9 | ||||||||||||||
| Wholesale - municipal | 112 | 6 | 116 | 7 | 114 | 7 | ||||||||||||||
| Wholesale - other (b) | 36 | 2 | 38 | 2 | 43 | 2 | ||||||||||||||
| Total | $ | 1,744 | 100 | $ | 1,749 | 100 | $ | 1,728 | 100 | |||||||||||
Franchises and Licenses
LG&E and KU provide electricity delivery service, and LG&E provides natural gas distribution service, in their respective service territories pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by state legislatures, cities or municipalities or other entities.
Competition
There are currently no other electric public utilities operating within the electric service areas of LKE.LG&E and KU. From time to time, bills are introduced into the Kentucky General Assembly which seek to authorize, promote or mandate increased distributed generation, customer choice or other developments. Neither the Kentucky General Assembly nor the KPSC has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of legislative or regulatory actions, if any, regarding industry restructuring and their impact on LKE,LG&E and KU, which may be significant, cannot currently
be predicted. Virginia, formerly a deregulated jurisdiction, has enacted legislation that implemented a hybrid model of cost-based regulation. KU's operations in Virginia have been and remain regulated.
Alternative energy sources such as electricity, oil, propane and other fuels indirectly impact LG&E's natural gas revenues. Marketers may also compete to sell natural gas to certain large end-users. LG&E's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity; therefore,commodity. Therefore, customer natural gas purchases from alternative suppliers do not generally impact LG&E's profitability. Some large industrial and commercial customers, however, may physically bypass LG&E's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.
Power Supply
At December 31, 2017, LKE2023, LG&E owned controlled or had a minority ownership interest in generating capacity of 8,0172,760 MW and KU owned generating capacity of which 2,920 MW related to LG&E and 5,097 MW related to KU, in Kentucky, Indiana, and Ohio.4,775 MW. See "Item 2. Properties - Kentucky Regulated Segment" for a complete list of LKE's generating facilities.
The system capacity of LKE'sLG&E's and KU's owned or controlled generation is based upon a number ofseveral factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changes in circumstances.
During 2017, LKE's2023, LG&E's and KU's power plants generated the following amounts of electricity.electricity:
| GWh | |||||||||||
| Fuel Source | LG&E | KU | |||||||||
| Coal | 10,509 | 13,219 | |||||||||
| Gas | 1,241 | 4,120 | |||||||||
| Hydro | 272 | 44 | |||||||||
| Solar | 8 | 12 | |||||||||
| Total (a) | 12,030 | 17,395 | |||||||||
| GWh | ||||||||
| Fuel Source | LKE | LG&E | KU | |||||
| Coal (a) | 28,519 | 12,161 | 16,358 | |||||
| Gas | 4,625 | 1,105 | 3,520 | |||||
| Hydro | 337 | 278 | 59 | |||||
| Solar | 18 | 7 | 11 | |||||
| Total (b) | 33,499 | 13,551 | 19,948 | |||||
(a)This generation represents a decrease for LG&E of 4% and a decrease for KU of 8% from 2022 output.
The majority of LG&E's and KU's generated electricity was used to supply their retail and KU's municipal customer base.bases.
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail and municipal customers. When LG&E has excess generation capacity after serving its own retail customers and its generation cost is lower than that of KU, KU purchases electricity from LG&E and vice versa.
LG&E and KU received approval from the KPSC to develop a 4 MW solar shareSolar Share facility to service a solar shareSolar Share program. The solar shareSolar Share program is an optional,a voluntary program that allows customers to subscribe capacity in the solar shareSolar Share facility. Construction is expected to begin,commences, in 500-kilowatt phases, when subscription is complete. As Construction of five 500-kilowatt phases was completed as
5
of December 31, 2017,2022. LG&E and KU have not yet constructed the first solar share facility and are actively marketingcontinue to market the program and continueare accepting subscriptions for the sixth 500-kilowatt phase.
On January 23, 2020, LG&E and KU applied to receive interest from customers.
On October 6, 2021, LG&E and KU entered into an agreement to purchase the initial 20 years of output of a proposed 125 MW third-party solar generation facility in connection with the Green Tariff option established in the 2018 Kentucky base rate cases. Pursuant to the agreements, LG&E and KU would purchase output of the facility and resell power as renewable energy to certain large customers. The generation facility is currently expected to be operational in the fourth quarter of 2026. PPL, LG&E and KU do not anticipate that this agreement will have a significant impact on their results of operations or financial condition.
On December 15, 2022, LG&E and KU filed an application with the KPSC for a CPCN for the construction and purchase of various generating facilities in conjunction with the retirement of four existing coal-fired generation units and three small gas-fired units. On March 24, 2023, Kentucky Senate Bill 4 (SB 4) went into effect, which requires KPSC approval of the retirement of fossil fuel-fired electric generating units in the state. On May 10, 2023, LG&E and KU filed an application with the KPSC seeking approval of the retirement of seven fossil fuel-fired generating units as required by SB 4. On May 16, 2023, the KPSC entered an Order consolidating the SB 4 filing proceeding into the CPCN case.
On November 6, 2023, the KPSC issued an order approving LG&E’s and KU’s requests (i) to construct a 640 MW net summer rating NGCC combustion turbine at LG&E's Mill Creek Generating Station in Jefferson County, Kentucky, (ii) to construct a 120 MWac solar photovoltaic electric generating facility in Mercer County, Kentucky, (iii) to acquire a 120 MWac solar facility to be built by a third-party solar developer in Marion County, Kentucky and (iv) to construct a 125 MW, 4-hour battery energy storage system facility at KU's E.W. Brown Generating Station. The KPSC denied the request to construct a 621 MW net summer rating NGCC combustion turbine at KU's E.W. Brown Generating Station in Mercer County, Kentucky at this time, based on the finding that the construction of this unit should be deferred with the construction date beginning on a date that provides for an in-service date in 2030. The order also authorized LG&E's and KU's entry into the four solar PPAs, subject to certain conditions, but deferred for future proceedings specific decisions on cost recovery treatment or mechanisms. Further, the order approved the new, adjusted or expanded energy efficiency programs contained in the requested 2024-2030 DSM plan.
The KPSC order included approval of the requested retirements of two existing coal-fired generation units at LG&E's Mill Creek Unit 1 (300 MW) and 2 (297 MW) in 2024 and 2027, subject to certain conditions, and three small gas-fired units. The order denied approval of the retirement of KU's E.W. Brown 3 Unit (412 MW) and Ghent Unit 2 (486 MW) in 2028 at this time, citing the need for additional clarity regarding environmental compliance regulations.
The new NGCC facility will be jointly owned by LG&E (31%) and KU (69%) and the solar units will be jointly owned by LG&E (37%) and KU (63%), the battery storage unit will be owned by LG&E, and the proposed PPA transactions and DSM programs will be entered into or conducted jointly by LG&E and KU, consistent with a combined capacity of 563 MW, atLG&E and KU's shared dispatch, cost allocation, tariff or other frameworks.
See Note 7 to the Cane Run plant.Financial Statements for additional information.
Fuel Supply
Coal and natural gas will continueare expected to be the predominant fuelfuels used by LG&E and KU for generation for the foreseeable future. Natural gas used for generation is primarily purchased using contractual arrangements separate from LG&E's natural gas distribution operations. Natural gas and oil will continue to beare also used for intermediate and peaking capacity and flame stabilization in coal-fired boilers.
Fuel inventory is maintained at levels estimated to be necessary to avoid operational disruptions at coal-fired generating units. Reliability of coal deliveries can be affected from time to time by a number ofseveral factors including fluctuations in demand, coal mine production issues, high or low river level events, lock outages and other supplier or transporter operating or financial difficulties.
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LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 20232028 and augment their coal supply agreements with spot market purchases, as needed.
For their existing units, LG&E and KU expect, for the foreseeable future, to purchase most of their coal from western Kentucky, southern Indiana, southern Illinois, northern West Virginia and southern Illinois.western Pennsylvania. LG&E and KU continue to purchase certain quantities of ultra-low sulfur content coal from Wyoming for blending at Trimble County Unit 2. Coal is delivered to the generating plants primarily by barge and rail.
To enhance the reliability of natural gas supply, LG&E and KU have secured firm long-term pipeline transport capacity services with contracts of various durations from 2019 to 2024through 2056 on the interstate pipeline serving Cane Run Unit 7.7, six simple cycle combustion turbines at the Trimble County site, and the future Mill Creek Unit 5. This pipeline also serves the six simple cycle combustion turbine units located at the Trimble County site as well as four othertwo simple cycle units at the Cane Run and Paddy's Run sites. LG&E has also secured long-term firm pipeline transport capacity on an interstate pipeline for the summer months through October 2018 to serve an additional simple cycle gas turbine operated under a tolling agreement that ends April 30, 2019.site. For the seven simple cycle combustion turbines at the E.W. Brown facility, no firm long-term pipeline transport capacity has been purchased due to the facility being interconnectedfacility's connection to two interstate pipelines and some of the units having dual fuel capability.
LG&E and KU have firm contracts for a portion of the natural gas fuel for Cane Run Unit 7 for delivery in future months.through 2026. The bulk of the natural gas fuel remainsis expected to be purchased on the spot market.
(PPL LKE and LG&E)
Natural Gas Distribution Supply
LG&E has a portfolio of supply arrangements of varying durations and terms that provide competitively priced natural gas designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. In tandem with pipeline transportation services, these natural gas supplies provide the reliability and flexibility necessary to serve LG&E's natural gas customers.
LG&E purchases natural gas supply transportation services from two pipelines. LG&E has a set of contracts with one pipeline that are subject to termination by LG&E between 20202025 and 2023.2028. Total winter season capacity under these contracts is 184,900 MMBtu/day and summer season capacity is 60,000 MMBtu/day. WithLG&E has two additional contracts with this same pipeline, LG&E also has anotherpipeline. One contract is for pipeline capacity through 2026 in the amount offor 60,000 MMBtu/day during both the winter and summer seasons. The other contract is for pipeline capacity through 2028 for 30,000 MMBtu/day during the winter season. LG&E has a single contract with a second pipeline with a total capacity of 20,000 MMBtu/day during both the winter and summer seasons that expires in 2023.2030.
LG&E expects to purchase natural gas supplies for its gas distribution operations from onshore producing regions in South Texas, East Texas, North Louisiana and Arkansas, as well as gas originating in the Marcellus and Utica production areas.
(PPL, LKE, LG&E and KU)
Transmission
LG&E and KU contract with the Tennessee Valley Authority to act as their transmission reliability coordinator and contract with TranServ International, Inc. to act as their independent transmission organization.
Rates
LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the FERC and the VSCC. LG&E and KU operate under a FERC-approved open access transmission tariff.
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LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets in Kentucky.
KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except for regulatory assets and liabilities related to the levelized fuel factor, accumulated deferred income taxes, pension and postretirement benefits, and AROs related to certain CCR impoundments, are excluded from the return on rate base utilized in the calculation of Virginia base rates, no return is earned on the related assets.
KU's rates to 10two municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except regulatory assets recorded for AROs related to CCR impoundments,accumulated deferred income taxes, are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets. In April 2014, nine municipalities submitted notices of termination, under the notice period provisions, to cease taking power under the wholesale requirements contracts. Such terminations are to be effective in 2019, except in the case of one municipality that terminated service in 2017.
See "Financial and Operational Developments" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 67 to the Financial Statements for additional information on cost recoverycurrent rate proceedings and rate mechanisms.
Pennsylvania Regulated Segment(PPL)
(PPL and PPL Electric)
PPL Electric delivers electricity to approximately 1.41.5 million customers in a 10,000-square mile territory in 29 counties ofwithin eastern and central Pennsylvania. PPL Electric also provides electricity supply to retail customers in this areaterritory as a PLR under the Customer Choice Act.
| 2017 | 2016 | 2015 | ||||||||||||||||||
| Revenue | % of Revenue | Revenue | % of Revenue | Revenue | % of Revenue | |||||||||||||||
| Distribution | ||||||||||||||||||||
| Residential | $ | 1,351 | 62 | $ | 1,327 | 61 | $ | 1,338 | 63 | |||||||||||
| Industrial | 44 | 2 | 42 | 2 | 58 | 3 | ||||||||||||||
| Commercial | 349 | 16 | 338 | 16 | 377 | 18 | ||||||||||||||
| Other (a) | (36 | ) | (2 | ) | (4 | ) | — | (44 | ) | (2 | ) | |||||||||
| Transmission | 487 | 22 | 453 | 21 | 395 | 18 | ||||||||||||||
| Total | $ | 2,195 | 100 | $ | 2,156 | 100 | $ | 2,124 | 100 | |||||||||||
Franchise, Licenses and Other Regulations
PPL Electric is authorized to provide electric public utility service throughout its service area as a result of grants by the Commonwealth of Pennsylvania in corporate charters to PPL Electric and companies whichthat it has succeeded, and as a result of certification by the PUC.PAPUC. PPL Electric is granted the right to enter the streets and highways by the Commonwealth subject to certain conditions. In general, such conditions have been met by ordinance, resolution, permit, acquiescence or other action by an appropriate local political subdivision or agency of the Commonwealth.
Competition
Pursuant to authorizations from the Commonwealth of Pennsylvania and the PUC,PAPUC, PPL Electric operates a regulated distribution monopoly in its service area. Accordingly, PPL Electric does not face competition in its electricity distribution business. Pursuant to the Customer Choice Act, generation of electricity is a competitive business in Pennsylvania, and PPL Electric does not own or operate any generation facilities.
The PPL Electric transmission business, operating under a FERC-approved PJM Open Access Transmission Tariff, is subject to competition pursuant to FERC Order 1000 from entities that are not incumbent PJM transmission owners with respect to the construction and ownership of transmission facilities within PJM.
Rates and Regulation
Transmission
PPL Electric's transmission facilities are within PJM, which operates the electricity transmission network and electric energy market in the Mid-Atlantic and Midwest regions of the U.S.
PJM serves as a FERC-approved Regional Transmission Operator (RTO) to promote greater participation and competition in the region it serves. In addition to operating the electricity transmission network, PJM also administers regional markets for energy, capacity and ancillary services. A primary objective of any RTO is to separate the operation of, and access to, the
8
transmission grid from market participants that buy or sell electricity in the same markets. Electric utilities continue to own the transmission assets and to receive their share of transmission revenues, but the RTO directs the control and operation of the transmission facilities. Certain types of transmission investmentinvestments are subject to competitive processes outlined in the PJM tariff.
As a PLR, PPL Electric also purchases transmission services from PJM. See "PLR" below.
See Note 67 to the Financial Statements for additional information on rate mechanisms.mechanisms and regulatory matters.
Distribution
PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). All regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base; therefore,base. Therefore, no return is earned on the related assets unless specifically provided for by the PUC.PAPUC. Currently, PPL Electric's Smart Meter rider and the DSIC are the only riders authorized to earn a return. Certain operating expenses are also included in PPL Electric's distribution base rates including wages and benefits, other operation and maintenance expenses, depreciation and taxes.
Pennsylvania's Alternative Energy Portfolio Standard (AEPS) requires electricityelectric distribution companies and electricity generation suppliers to obtain from alternative energy resources a portion of the electricity sold to retail customers in Pennsylvania. Under the default service procurement plans approved by the PUC,PAPUC, PPL Electric purchases all of the alternative energy generation supply it needs to comply with the AEPS.
Act 129 created an energy efficiency and conservation program, a demand side management program, smart metering technology requirements, new PLR generation supply procurement rules, remedies for market misconduct and changes to the existing AEPS.
Act 11 authorizes the PUCPAPUC to approve two specific ratemaking mechanisms: the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it is in a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging assets. PPL Electric has utilized the fully projected future test year mechanism in its 2015 base rate proceeding. PPL has had the ability to utilize the DSIC recovery mechanism since July 2013.
See "Regulatory Matters - Pennsylvania Activities" in Note 67 to the Financial Statements for additional information regarding Act 129on rate mechanisms and other legislative and regulatory impacts.matters.
PLR
The Customer Choice Act requires Electric Distribution Companies (EDCs),electric distribution companies, including PPL Electric, or an alternative supplier approved by the PUCPAPUC, to act as a PLR of electricity supply for customers who do not choose to shop for supply with a competitive supplier and provides that electricity supply costs will be recovered by the PLR pursuant to PUCPAPUC regulations. In 2017,2023, the following average percentages of PPL Electric's customer load were provided by competitive suppliers: 46%42% of residential, 85%80% of small commercial and industrial and 98%97% of large commercial and industrial customers. The PUC continues to favor expanding the competitive market for electricity. See "Regulatory Matters - Pennsylvania Activities - Act 129" in Note 6 to the Financial Statements for additional information.
PPL Electric's cost ofElectric’s electricity generation iscosts are established based onupon the results of a competitive solicitation process. The PUCIn December 2020, the PAPUC approved PPL Electric'sElectric’s default service plan for the period June 20151, 2021 through May 2017,31, 2025, which included 4includes a total of eight solicitations for electricity supply held semiannually in April and October. The PUC approved PPL Electric's default serviceThrough December 31, 2023, six auctions of the plan for the period June 2017 through May 2021, whichwere completed. This plan also includes a total of 8eight solicitations for electricity supplyalternative energy credits held semiannually in AprilJanuary and October. July. Through January 2024, six alternative energy credit solicitations have been completed.
9
Pursuant to both the current and future plans, PPL Electric contracts for all of the electricity supply for residential, customers and commercial and industrial customers who elect to take thatdefault service from PPL Electric. These solicitations includecontain a mix of products including 5-year block energy contracts for residential customers, 6- and 12-month fixed-price load-following contracts for residential and small commercial and industrial customers, and 12-
Numerous alternative suppliers have offered to provide generation supply in PPL Electric's service territory. Sincearea. As the cost of generation supply is a pass-through cost for PPL Electric, its financial results are not impacted if its customers purchase electricity supply from these alternative suppliers.
The PUC issued a Secretarial Letter on February 12, 2018 regardingRhode Island Regulated segment consists primarily of the TCJA. The Commissionregulated electricity transmission and distribution operations and regulated distribution and sale of natural gas conducted by RIE.
RIE is requesting comments from interested parties addressing whetherengaged in the Commission should adjust current customer ratesregulated transmission, distribution and sale of electricity and regulated distribution and sale of natural gas in Rhode Island. RIE provides electric service to reflectapproximately 514,000 customers and natural gas service to approximately 278,000 customers. RIE's service area covers substantially all of Rhode Island.
Franchises and Licenses
RIE provides electricity delivery service and natural gas distribution service in its service territory pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by the reduced federal income tax expense and, if so, the appropriate negative surchargeRhode Island state legislature, cities or municipalities or other methodology that would permit immediate adjustmententities.
Competition
There are currently no other electric or gas public utilities operating within the service area of RIE.
Alternative energy sources such as electricity, oil, propane and other fuels indirectly impact RIE's natural gas revenues. Marketers may also compete to consumersell natural gas to certain large end-users. RIE's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity. Therefore, customer natural gas purchases from alternative suppliers do not generally impact RIE's profitability. Some large industrial and commercial customers, however, may physically bypass RIE's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.
Rates and Regulation
In general, RIE operates subject to the jurisdiction of the FERC, the RIPUC and the Rhode Island Division of Public Utilities and Carriers.
Distribution
RIE owns and maintains electric and natural gas distribution networks in Rhode Island. 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 whetherother terms of services as part of the surchargerate 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 tariff rates approved by the RIPUC are designed to recover the costs incurred by RIE for products and services provided, along with a return on investment.
RIE’s distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). All regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base. Therefore, no return is earned on the related assets unless specifically provided for by the RIPUC. Currently, RIE's ISR and Renewable Energy Growth Program adjustment mechanisms are the only mechanisms authorized to earn a return. Certain operating expenses are also
10
included in RIE’s distribution base rates including wages and benefits, other operation and maintenance expenses, depreciation, and taxes.
Transmission
RIE owns an electric transmission system in Rhode Island. RIE’s transmission services are regulated by the FERC and coordinated with ISO – New England.
Deferral Mechanisms
RIE records revenues in accordance with accounting principles for rate-regulated operations for arrangements between RIE and the applicable regulator. These include various deferral mechanisms such as capital trackers, energy efficiency programs, and other programs that qualify as Alternative Revenue Programs (ARPs). ARPs enable RIE to adjust rates in the future, in response to past activities or completed events. RIE’s electric and gas distribution rates both have a revenue decoupling mechanism, which allows for annual adjustments to the RIE’s delivery rates, as a result of the reconciliation between allowed revenue and billed revenue. RIE also has other said methodology should provide that any refunds to customers due to reduced taxes be effective as of January 1, 2018. In addition, the Secretarial Letter requests certain Pennsylvania regulated utilities, including PPL Electric, to provide certain dataARPs related to the effectachievement of certain objectives, demand side management initiatives, and certain other rate making mechanisms. RIE recognizes ARPs with a corresponding offset to a regulatory asset or liability account when the regulatory specified events or conditions have been met, when the amounts are determinable, and are probable of recovery (or payment) through future rate adjustments.
Last Resort Service
RIE is required by the RIPUC and by statute to provide Last Resort Service. Last Resort Service is available to all customers who have not elected to receive their electric supply from a non-regulated power producer or any customer who, for any reason, has stopped receiving generation service from a non-regulated power producer.
The charge for Last Resort Service is the sum of the TCJA on PPL Electric’s income tax expenseapplicable Last Resort Service charges in addition to all appropriate Retail Delivery charges as stated in the applicable tariff. The monthly charge for Last Resort Service also includes the costs incurred by RIE to comply with the Renewable Energy Standard, established in Rhode Island General Laws Section 39-26-1 and rate basethe costs to comply with the RIPUC’s Rules Governing Energy Source Disclosure. The charge for Last Resort Service includes the administrative costs associated with the procurement of Last Resort Service, including whether anyan adjustment for uncollectible accounts as approved by the RIPUC.
Numerous alternative suppliers have offered to provide generation supply in RIE's service area. As the cost of the potential tax savingsgeneration supply is a pass-through cost for RIE, its financial results are not impacted if its customers purchase electricity supply from the reduced federal corporate tax rate can be used for purposes other than to reduce customer rates. PPL Electric’s responses are duethese alternative suppliers.
See Note 7 to the PUC not later than March 9, 2018.Financial Statements for additional information on rate mechanisms and regulatory matters.
Natural Gas Distribution Supply
To meet the projected annual gas supply requirements of approximately 37 Bcf, RIE has a portfolio of gas supply arrangements of varying contractual terms and durations to provide service to its customers. These natural gas supply arrangements include contracts with natural gas producers and marketers that reflect market price signals. RIE also has firm pipeline and underground storage capacity contracts to support the delivery of natural gas supplies to its customers. To manage the winter peak requirements for RIE customers, RIE contracts for liquified natural gas (LNG) service and owns and operates certain LNG storage facilities.
The FERCRIE gas supply portfolio includes contracts for firm transportation service with eleven interstate pipeline companies and natural gas storage operators. These contracts have various termination dates with certain contracts being subject to evergreen renewal provisions providing RIE with flexibility in managing its upstream resource portfolio.
RIE has not issued any guidance onpurchased and expects to continue to purchase natural gas supplies for its gas distribution operations from onshore producing regions accessed by its pipeline capacity portfolio in South Texas, East Texas, and Louisiana, as well as gas originating in the effect on ratesMarcellus and Utica production areas. RIE expects to purchase certain natural gas supplies that originate in Canada and from regional LNG import terminals.
11
Corporate and Other
(PPL)PPL Services provides PPL subsidiaries with administrative, management and support services. The costs of these services are charged directly to the respective recipients for the services provided or indirectly charged to applicable recipients based on an average of the recipients' relative invested capital, operation and maintenance expenses and number of employees or a ratio of overall direct and indirect costs.
PPL Capital Funding PPL's financing subsidiary, provides financing for the operations of PPL and certain subsidiaries. PPL's growth in rate-regulated businesses provides the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that enables PPL to cost effectively support targeted credit profiles across all of PPL's rated companies. As a result, PPL plans to utilizeutilizes PPL Capital Funding as a source of capital in future financings, in addition to continued direct financing by thecertain operating companies.
subsidiaries. Unlike those of PPL Services, PPL Capital Funding's costs are not generally charged to PPL subsidiaries. Costs are charged directly to PPL. However, PPL Capital Funding participated significantly
Beginning in 2023, the financing activity of LKE is included in Corporate and Other. Prior periods have been adjusted to reflect this change.
ENVIRONMENTAL MATTERS
(All Registrants)
The Registrants are subject to certain existing and developing federal, regional, state and local laws and regulations with respect to air and water quality, land use and other environmental matters, and may be subject to different and more stringent laws and regulations enacted in the financingfuture. The EPA and other federal agencies with jurisdiction over environmental matters have issued numerous environmental regulations relating to air, water and waste that directly affect the electric power industry. Due to these environmental issues, it may be necessary for the acquisitionsRegistrants to modify or cease certain operations or operation of LKEcertain facilities to comply with statutes, regulations and WPD Midlandsother requirements of regulatory bodies or courts. In addition, legal challenges to environmental permits or rules add uncertainty to estimating future costs of complying with such permits and certain associated financing costs were allocatedrules. The Biden administration is currently undertaking changes in a wide range of environmental programs.
See “Legal Matters” in Note 13 to the Financial Statements for a discussion of environmental commitments and contingencies. See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information on projected environmental capital expenditures for 2024 through 2026. See Note 19 to the Financial Statements for information related to the impacts of CCRs on AROs.
LG&E and KU are entitled to recover, through the ECR mechanism, certain costs of complying with the Clean Air Act, as amended, and other federal, state and local environmental requirements applicable to coal combustion wastes and by-products from coal-fired generating facilities upon KPSC review. Costs not covered by the ECR mechanism for LG&E and KU and all such costs for PPL Electric and RIE are subject to rate recovery at the discretion of the companies' respective state regulatory authorities, or the FERC, if applicable. Because PPL Electric and RIE do not own any generating plants, they have less exposure to related environmental compliance costs. The Registrants can provide no assurances as to the ultimate outcome of future proceedings before regulatory authorities.
Air
(PPL, LG&E and KU)
NAAQS
Applicable regulations require each state to identify areas within its boundaries that fail to meet the NAAQS, (known as nonattainment areas), and develop a state implementation plan to achieve and maintain compliance. States that are found to contribute significantly to another state's nonattainment with ozone standards are required to establish "good neighbor" state implementation plans. In addition, for attainment of ozone and fine particulates standards, certain states, including Kentucky, Regulated and U.K. Regulated segments. The associated financing costs, as wellare subject to a regional EPA program known as the financing costs associated with prior issuances of certain other PPL Capital Funding securities, have been assigned to the appropriate segments for purposes of PPL management's assessment of segment performance. The financing costs associated primarily with PPL Capital Funding's securities issuances beginning in 2013, with certain exceptions, have not been directly assigned or allocated to any segment.Cross-State Air Pollution Rule (CSAPR).
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The Clean Air Act has a significant impact on the operation of fossil fuel generation plants. The Clean Air Act requires the EPA periodically to establish and review NAAQS for six pollutants: carbon monoxide, lead, nitrogen dioxide, ozone (contributed to by nitrogen oxide emissions), particulate matter and sulfur dioxide. In December 2020, the EPA released final actions keeping the existing NAAQS standard for particulate matter and ozone without change, but the EPA subsequently announced reconsideration of those decisions in June 2021. On February 7, 2024, the EPA released a pre-publication revision to the particulate matter standard that lowers the primary standard for fine particulates. Based on the new standard, the EPA could potentially designate Jefferson County, Kentucky (Louisville) as being in nonattainment with the new particulate matter standard and require additional particulate matter reductions from sources including LG&E’s Mill Creek Station. The new particulate matter standard may also result in more stringent requirements for new generation located in nonattainment areas. PPL, LG&E, and KU are unable to predict future implementation actions or the outcome of future evaluations by the EPA and the states with respect to the NAAQS standards.
In January 2018, the EPA designated Jefferson County, Kentucky (Louisville) as being in nonattainment with the existing 2015 ozone standard. In 2020 and 2021, LG&E entered into agreements with the Louisville Metro Air Pollution Control District for temporary nitrogen oxide emission limits at LG&E's Mill Creek Station during those years to facilitate compliance with the ozone standard. In October 2022, Jefferson County was “bumped up” to the moderate nonattainment classification, but the Louisville Air Pollution Control District has applied to the EPA for Jefferson County to be redesignated as in attainment. If the EPA declines to issue such a redesignation, Jefferson County could be subject to additional requirements including requirements for installation of reasonably available control technology on coal-fired generating units.Compliance with such requirements may require installation of additional pollution controls or other compliance actions. PPL common shares ownedand LG&E are unable to determine the impact on operations until certain compliance determinations are made by the EPA and Kentucky.
In March 2021, the EPA released final revisions to the Cross-State Air Pollution Rule (CSAPR) aimed at ensuring compliance with the 2008 ozone NAAQS and providing for reductions in ozone season nitrogen oxide emissions for 2021 and subsequent years. Additionally, the EPA reversed its previous approval of the Kentucky State Implementation Plan with respect to these requirements. In March 2023, the EPA Administrator released a final Federal Implementation Plan under the Good Neighbor provisions of the Clean Air Act providing for significant additional nitrogen oxide emission reductions for compliance with the revised 2015 ozone NAAQS. The reductions in Kentucky state-wide nitrogen oxide budgets were scheduled to commence in 2023, with the largest reductions planned for 2026, based on the installation time frame for certain selective catalytic reduction controls, subject to future specific allowance calculations. PPL, shareownersLG&E and KU are currently assessing the potential impact of the Good Neighbor Plan revisions on operations. The rules provide for reduced availability of nitrogen oxide allowances that have historically permitted operational flexibility for fossil units and could potentially result in constraints that may require implementation of additional emission controls or accelerate implementation of lower emission generation technologies. In response to judicial orders that stayed the EPA’s denial of certain state implementation plans, the EPA in July 2023 issued an interim stay of implementation of Good Neighbor Plan requirements for emission sources in several states including Kentucky. Legal challenges to CSAPR and related determinations remain pending, and the U.S. Supreme Court will hear arguments on numerous stay applications filed by states and industry groups over the Good Neighbor Plan. In January 2023, the EPA released a proposed revision to increase the stringency of the current NAAQS for particulate matter. The EPA is continuing review of its previous determinations made in December 2020 to retain the existing NAAQS for ozone without change.
PPL, LG&E, and KU are unable to predict the ultimate outcome of pending litigation or future emission reductions that may be required by future federal rules or state implementation actions. Compliance with the NAAQS, CSAPR, Good Neighbor Plan, and related requirements may require installation of additional pollution controls or other compliance actions, inclusive of retirements, the costs of which PPL, LG&E and KU believe would be subject to rate recovery.
Proposed Modification of Mercury and Air Toxics Standards
In 2012, the EPA issued the Mercury and Air Toxics Standards (MATS) rule requiring reductions in mercury and other hazardous air pollutants from fossil fuel-fired power plants. LG&E and KU installed significant controls to achieve compliance with MATS and other rules. In April 2023, the EPA proposed to increase the stringency of MATS and further reduce emissions of certain hazardous air pollutants by reducing certain particulate matter standards by approximately two-thirds to reflect developments in control technologies. While the exact impact will depend on the provisions adopted in the final rule, PPL, LG&E, and KU do not expect significant operational changes or additional controls. PPL, LG&E, and KU will continue to monitor the ongoing rulemaking process.
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Proposed Greenhouse Gas Standards
On May 11, 2023, the EPA released proposed rules under Section 111 of the Clean Air Act to establish performance standards and emissions limits aimed at reducing GHG emissions from certain new, existing, and modified fossil fuel-fired electric generating units (EGUs). The proposed standards would require phased implementation of carbon mitigation technologies including state-of-the-art efficiency requirements, carbon capture and sequestration, low GHG hydrogen co-firing, and natural gas co-firing. New natural gas EGUs would be immediately subject to the stricter efficiency standard. The EPA’s proposed new GHG reduction requirements, if adopted, could potentially require significant additional compliance measures including changes in current operations, installation of capital equipment, and early retirement of certain coal-fired generating units. PPL, LG&E, and KU are unable to predict the precise impact of new GHG reduction requirements until issuance of final rules and resolution of related legal and regulatory proceedings. While the impact of new GHG reduction requirements on operations and financial results of operations could potentially be substantial, the cost of complying with such requirements is expected to be subject to rate recovery. PPL, LG&E, and KU will continue to monitor the ongoing rulemaking process.
Climate Change (All Registrants)
The Biden administration continues to undertake wide-ranging efforts to address climate change. Recent government actions and policy developments, including the President’s announced goal of a carbon free electricity sector by 2035, could have far-reaching impacts on PPL’s business operations, products, and services. On June 30, 2022, the U.S. Supreme Court ruled that provisions of the EPA's Clean Power Plan, premised on generation shifting from coal-fired plants to lower emitting natural gas-fired plants and renewables, exceeded the authority granted to the EPA under the Clean Air Act. The EPA has announced proposed new greenhouse gas rules discussed above. It is uncertain how the U.S. Supreme Court ruling may impact future EPA rulemaking. All of these developments are preliminary or ongoing in nature and the Registrants cannot predict the final outcome or ultimate impact on operations.
PPL has adopted a goal of net-zero carbon emissions by 2050, which PPL expects will include continuing to retire coal-fired generation and investing in research and innovation that will help to achieve this goal, while maintaining reliable and affordable energy in our service territories. The net-zero goal relates to direct and indirect carbon emissions consistent with Greenhouse Gas Protocol guidance and referenced by the EPA Center for Corporate Climate Leadership. Through 2021, PPL reduced carbon emissions nearly 60% from 2010 levels and is targeting a 70% reduction from 2010 levels by 2035 and an 80% reduction by 2040.
PPL is also aware of the various risks associated with climate change, including increased frequency and severity of severe weather. To address these risks, PPL continues to work to advance grid modernization and improve the Company's equipment to help mitigate the impacts of extreme weather events and improve reliability.
Water/Waste(PPL, LG&E and KU)
Clean Water Act
Regulations under the federal Clean Water Act dictate permitting and mitigation requirements for facilities and construction projects that impact "Waters of the United States". Many other requirements relate to power plant operations, including the treatment of pollutants in effluents prior to discharge, the temperature of effluent discharges and the location, design and construction of cooling water intake structures at generating facilities, and standards intended to protect aquatic organisms that become trapped at or pulled through cooling water intake structures at generating facilities. These requirements could impose significant costs for LG&E and KU, which are expected to be subject to rate recovery.
Clean Water Act Jurisdiction
Environmental groups and others have claimed that discharges to groundwater from leaking CCR impoundments at power plants are subject to Clean Water Act permitting. On April 12, 2019, the EPA released regulatory clarification finding that Clean Water Act jurisdiction does not cover such discharges to groundwater. On January 23, 2020, the EPA announced a final rule modifying the jurisdictional scope of the Clean Water Act. The announced rule revises the definition of the "Waters of the United States," including a revision to exclude groundwater from the definition. In April 2020, the U.S. Supreme Court issued a ruling that Clean Water Act jurisdiction may apply to certain discharges to groundwater that result in the functional equivalent of a direct discharge to navigable waters. PPL, LG&E, and KU are unaware of any unpermitted releases from their facilities that are subject to Clean Water Act jurisdiction, but future regulatory developments and judicial rulings could potentially subject certain releases from CCR impoundments and landfills to additional permitting and remediation requirements, which could impose substantial costs. Any associated costs are expected to be subject to rate recovery. PPL, LG&E and KU are unable to predict the outcome or financial impact of future regulatory proceedings and litigation.
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Waters of the U.S.
PPL, LG&E, and KU are subject to permitting and mitigation requirements for certain construction activities that impact "Waters of the United States." On April 21, 2020, the EPA and U.S. Army Corps of Engineers published a final rule revising the definition of "Waters of the United States" to exclude jurisdiction over certain surface waters. On August 30, 2021, a U.S. District Court in Arizona vacated and remanded the rule. On December 7, 2021, the EPA and U.S. Army Corps of Engineers proposed to repeal the rule and restore the definition of "Waters of the United States" that was in place prior to 2015. On January 24, 2022, the U.S. Supreme Court granted review of a case raising the issue of the appropriate scope of the definition of "Waters of the United States" under the Clean Water Act. On January 18, 2023, the EPA and U.S. Army Corps of Engineers published a final revision to the rule broadening the definition of Waters of the United States and reverting to the pre-2015 regulatory framework. Although the broader definition incorporates additional water bodies, any resulting permitting, construction, and operational expenses are expected to be immaterial and subject to rate recovery.
On May 25, 2023, the U.S. Supreme Court issued an opinion in Sackett v. EPA holding that the government’s jurisdiction to regulate wetlands under the Clean Water Act extends to wetlands with a continuous surface connection to bodies that are "waters of the United States." On September 8, 2023, the EPA issued a conforming rule that incorporated the holding of Sackett into federal definitions of waters of the United States; some states and industry groups have challenged the conforming rule as well. By limiting water bodies that fall within the jurisdiction of the Clean Water Act, the U.S. Supreme Court's decision could reduce the number of sharesprojects or the scope of project activities subject to federal permitting for wetlands. PPL, LG&E and KU are unable to predict the outcome of current or future litigation or regulatory proceedings, but do not expect a material impact on operations.
Superfund and Other Remediation(All Registrants)
From time to time, PPL's subsidiaries undertake testing, monitoring or remedial action in response to spills or other releases at various on-site and off-site locations, negotiate with the EPA and state and local agencies regarding actions necessary to comply with applicable requirements, negotiate with property owners and other third parties alleging impacts from PPL's operations and undertake similar actions necessary to resolve environmental matters that arise in the course of normal operations. Based on analyses to date, resolution of these environmental matters is not expected to have a significant adverse impact on the operations of PPL, common stock outstanding. The transaction is intendedPPL Electric, LG&E and KU.
Future cleanup or remediation work at sites not yet identified may result in significant additional costs for the Registrants. Insurance policies maintained by LG&E and KU may be available to cover certain of the costs or other obligations related to these matters, but the amount of insurance coverage or reimbursement cannot be tax-free to PPL and its shareowners for U.S. federal income tax purposes.estimated or assured.
See “Legal Matters” in Note 813 to the Financial Statements for additional information.
(All Registrants)
SEASONALITY
The demand for and market prices of electricity and natural gas are affected by weather. As a result, the Registrants' operating results in the future may fluctuate substantially on a seasonal basis, especially when unpredictable weather conditions make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities owned. See "Environmental Matters" in Note 13 to the Financial Statements for additional information regarding climate change.
FINANCIAL CONDITION
See "Financial Condition" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for this information.
CAPITAL EXPENDITURE REQUIREMENTS
See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information concerning projected capital expenditure requirements for 20182024 through 2022.2026. See Note 13 to the Financial Statements"Item 1. Business - Environmental Matters" for additional information concerning the potential impact on capital expenditures from environmental matters.
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HUMAN CAPITAL
PPL, together with its subsidiaries, is committed to fostering an exceptional workplace for employees. PPL pledges to enable the success of its current and future workforce by cultivating a diverse, equitable and inclusive culture, fostering professional development, encouraging employee engagement, and ensuring a safe and healthy work environment. Matters related to these priorities and corporate culture are overseen by PPL's senior management, which provides updates to the PPL Board of Directors (the Board). Pursuant to its charter, the Compensation Committee of the Board of Directors also periodically reviews and assesses the Company's strategy for human capital management. PPL's investment in the success of its workforce is embodied in the following areas with dedicated leadership and Board oversight:
•Diversity, equity and inclusion (DEI) - Foster an inclusive, respectful and diverse workplace through a comprehensive DEI strategy and commitments. PPL created a chief diversity officer position in 2022 to lead the company's DEI efforts. Senior management reviews demographic metrics, DEI objectives and associated programs semi-annually. The RegistrantsBoard also receives periodic updates from senior management on PPL's DEI strategy and initiatives.
•Employee engagement - Create a workplace that fosters an engaged, high-quality workforce. PPL's operating companies regularly conduct assessments related to employee engagement, safety and culture. Senior management reviews corporate culture with the Board at least annually.
•Professional development - Invest in the current and future workforce through training and development, succession planning and creation of a pipeline for internal advancement. Senior management reviews succession planning with the Compensation Committee of the Board on an annual basis.
•Comprehensive benefits - In addition to challenging careers and competitive salaries, PPL offers competitive benefits programs to attract and retain talent and support employees' well-being. PPL offers competitive vacation time, expanded leave for new parents, retirement programs, and internal and external development opportunities, including tuition reimbursement offerings for undergraduate and certain graduate degrees. Senior management conducts annual benchmarking of employee compensation and benefits.
•Safety and Compliance - PPL is committed to maintaining an ethical and safe workplace culture. Additional steps to ensure Board oversight in these areas include:
•Safety – PPL implements programs focused on health and safety, including emergency preparedness, vehicle safety and accident prevention. Employees receive safety training and are subjectencouraged to certain existingshare, implement, and developing federal, regional, statefollow best practices. Senior management receives monthly safety data updates to determine whether additional safety measures should be implemented. The Board reviews the company's safety programs and local laws and regulations with respectresults at least annually. The Board is also immediately engaged in the event of a fatality.
•Compliance – The Corporate Compliance Committee, including senior executives, meets quarterly to air and water quality, land usediscuss metrics and other environmental matters. The EPA has issued numerous environmental regulations relating to air, water and waste that directly affect the electric power industry. See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information on projected environmental capital expenditures for 2018 through 2022. Also, see "Environmental Matters" in Note 13 to the Financial Statements for additional information and Note 6 to the Financial Statements for informationmatters related to the recoverycompliance and ethics culture. Among the items discussed are statistics regarding Ethics Helpline reports and employee concerns. This information is also reviewed with the Audit Committee of environmental compliance costs.the Board quarterly.
At December 31, 2017,2023, PPL and its subsidiaries had the following full-time employees and employees represented by labor unions.unions:
| Total Full-Time Employees | Number of Union Employees | Percentage of Total Workforce | |||||||||||||||
| PPL | 6,629 | 2,450 | 37 | % | |||||||||||||
| PPL Electric | 1,438 | 960 | 67 | % | |||||||||||||
| LG&E | 927 | 592 | 64 | % | |||||||||||||
| KU | 759 | 111 | 15 | % | |||||||||||||
Total Full-Time Employees | Number of Union Employees | Percentage of Total Workforce | ||||||
| PPL | 12,512 | 6,113 | 49 | % | ||||
| PPL Electric | 1,755 | 1,084 | 62 | % | ||||
| LKE | 3,470 | 782 | 23 | % | ||||
| LG&E | 986 | 660 | 67 | % | ||||
| KU | 910 | 122 | 13 | % | ||||
(PPL and KU)
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(PPL)
AVAILABLE INFORMATION(All Registrants)
PPL's Internet website is www.pplweb.com. Under the Investors heading of that website, PPL provides access to all SEC filings of the Registrants (including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed or furnished pursuant to Section 13(d) or 15(d)) free of charge, as soon as reasonably practicable after filing with the SEC. The information contained on, or available through, PPL's Internet website is not, and shall not be deemed to be, incorporated by reference into this report. Additionally, the Registrants' filings are available at the SEC's website (www.sec.gov) and at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549, or by calling 1-800-SEC-0330..
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ITEM 1A. RISK FACTORS
The Registrants face various risks associated with their businesses. Our businesses, financial condition, cash flows or results of operations could be materially adversely affected by any of these risks. In addition, this report also contains forward-looking and other statements about our businesses that are subject to numerous risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 13 to the Financial Statements for moreadditional information concerning the risks described below and for other risks, uncertainties and factors that could impactaffect our businesses and financial results.
As used in this Item 1A., the terms "we," "our" and "us" generally refer to PPL and its consolidated subsidiaries taken as a whole, or PPL Electric and its consolidated subsidiaries taken as a whole within the Pennsylvania Regulated segment discussion, or LKELG&E, KU and itstheir consolidated subsidiaries taken as a whole within the Kentucky Regulated segment discussion, and RIE within the Rhode Island Regulated segment discussion.
Order of Subsection Presentation
A.Risks Related to Registrant Holding Company
B.Risks Related to Regulated Utility Operations
C.Risks Specific to Kentucky Regulated Segment
D.Risks Specific to Pennsylvania Regulated Segment
E.Risks Specific to Rhode Island Regulated Segment
F.Risks Related to All Segments
(PPL)
PPL is a holding company and political conditions and policiesconducts its operations primarily through subsidiaries. Substantially all of the U.K. governmentconsolidated assets of PPL are held by its subsidiaries. Accordingly, PPL's cash flows and ability to meet debt and guaranty obligations, as well as PPL's ability to pay dividends, are largely dependent upon the earnings of those subsidiaries and the European Union. These risks may adversely impact the results of operations of our U.K. distribution business or affect our ability to access U.K. revenues forother payment of distributions or for other corporate purposessuch earnings in the U.S.
Because PPL is a holding company, its debt and guaranty obligations are effectively subordinated to all existing and future liabilities of its subsidiaries. Although certain agreements to which certain subsidiaries are parties limit their ability to incur additional indebtedness, PPL and its subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities. Therefore, PPL's rights and the rights of its creditors, including rights of debt holders, to participate in the assets of any of its subsidiaries, in the event that such a subsidiary is liquidated or reorganized, will be subject to the prior claims of such subsidiary's creditors.
PPL may not realize the anticipated benefits of the RIE acquisition, which could materially adversely affect PPL's business, financial condition and results of operations.
PPL may not realize the anticipated financial and operational benefits from foreign lendersthe RIE acquisition if the business is not integrated in an efficient and lackeffective manner or if integration takes longer than anticipated. These integration risks include potential difficulties in conversion of localsystems and information, difficulties in harmonizing inconsistencies in standards, controls, procedures, practices and policies, disruption from the acquisition making it more difficult to maintain relationships with customers, employees or suppliers, and diversion of management time and attention to integration and other acquisition-related
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issues. In addition, PPL has incurred, and will continue to incur, significant costs in connection with the integration, and additional unanticipated costs may arise. No assurance can be given that the anticipated benefits from the acquisition will be achieved or, if achieved, the timing of their achievement. These risks and their consequences could result in increased costs or decreases in the amount of expected revenues and could have a material adverse effect on PPL's business, financial condition and results of operations.
(All Registrants)
B. Risks Related to Regulated Utility Operations
Our regulated utility businesses face many of the same risks, in addition to those risks that are unique to each of the Kentucky Regulated, Pennsylvania Regulated and Rhode Island Regulated segments. Set forth below are risk factors common to the regulated segments, followed by sections identifying separately the risks specific to each of these segments.
Our profitability is highly dependent on our ability to recover the costs of providing energy and utility services to our customers and earn an adequate return on our capital or loans;
The rates we charge our utility customers must be approved by the U.K. of its intent to withdraw from the European Union.
Our utility businesses are subject to significant and complex governmentalregulation.
In addition to regulating the rates we charge, various federal and state regulatory authorities regulate many aspects of our utility operations, including:
•the terms and conditions of our service and operations;
•financial and capital structure matters, and issuance of securities;
•siting, construction and operation of facilities;
•mandatory reliability and safety standards under the withdrawal. PPLEnergy Policy Act of 2005 and other standards of conduct;
•accounting, depreciation and cost allocation methodologies;
•tax matters;
•affiliate transactions;
•acquisition, retirement and disposal of utility assets; and
•various other matters, including energy efficiency.
Such regulations or changes thereto may subject us to higher operating costs or increased capital expenditures and failure to comply could result in sanctions or possible penalties which may not be recoverable from customers.
Our regulated businesses undertake significant capital projects and these activities are subjectto unforeseen costs, delays or failures, as well as risk of inadequate recovery ofresulting costs.
The regulated utility businesses are capital intensive and require significant investments in energy generation (in the case of LG&E and KU) and transmission, distribution and other infrastructure projects, such as projects for environmental compliance and system reliability. The completion of these projects without delays or cost overruns is subject to risks in many areas, including:
•approval, licensing and permitting;
•land acquisition and the availability of suitable land;
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•skilled labor or equipment shortages;
•construction problems or delays, including disputes with third-party intervenors;
•increases in commodity prices or labor rates;
•potential supply chain disruptions or delays; and
•contractor performance.
Failure to complete our capital projects on schedule or on budget, or at all, could adversely affect our financial performance, operations and future growth if such expenditures are not granted rate recovery by our regulators.
We are or may be subject to costs of remediation of environmental contamination at facilities owned or operated by our former subsidiaries.
We may be subject to liability for the costs of environmental remediation of property now or formerly owned by us with respect to substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. We also have current or previous ownership interests in sites associated with the production of manufactured gas for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Remediation activities associated with our former manufactured gas plant operations are one source of such costs. Citizen groups or others may bring litigation regarding environmental issues including claims of various types, such as property damage, personal injury and citizen challenges to compliance decisions on the enforcement of environmental requirements, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the impact, in eitheramount and timing of future expenditures (including the short-termpotential or long-term, on foreign exchange ratesmagnitude of fines or PPL’s long-term financial condition that may be experienced as a result of the actions taken by the U.K. governmentpenalties) related to withdraw from the European Union,such environmental matters, although such impactsthey could be significant.material.
C. Risks Specific to Kentucky Regulated Segment
(PPL, LG&E and KU)
We are subject to foreign currency exchange ratefinancial, operational, regulatory and other risks because a significant portion of our cash flowsrelated to requirements, developments and reported earningsuncertainties in environmental regulation, including those affecting coal-fired generation facilities.
Extensive federal, state and local environmental laws and regulations are currently generated by our U.K. business operations.
(PPL and LG&E)
We are subject to these distribution networks could reduce profitability both directly by incurring costs for network restorationoperational, regulatory and also through the system of penalties and rewards that Ofgem administers relating to customer service levels.other risks regarding natural gas supply infrastructure.
A failure by any of our U.K. regulated businesses to comply with the terms ofnatural gas pipeline explosion or associated incident could have a distribution license may lead to the issuance of an enforcement order by Ofgemsignificant impact on LG&E’s natural gas operations or result in significant damages and penalties that could have an adverse impact on PPL.
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activities, we could incur significant and unexpected costs to perform remedial activities on our natural gas infrastructure to ensure our continued safe and reliable operation. Recent pipeline incidents in the U.S. have also led to the introduction of proposed rules and possible federal legislative actions which could impose restrictions on LG&E’s operations or require more stringent testing to ensure pipeline integrity. Implementation of these regulations could increase our costs to comply with pipeline integrity and safety regulations.
D. Risks Specific to Pennsylvania Regulated Segment
(PPL and PPL Electric)
We face competition for transmission projects, which could adversely affect our rate base growth.
FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electricity transmission planning activities. The PPL Electric transmission business, operating under a FERC-approved PJM Open Access Transmission Tariff, is subject to competition pursuant to FERC Order 1000 from entities that are not incumbent PJM transmission owners with respect to the construction and ownership of transmission facilities within PJM. Increased competition can result in lower rate base growth.
We could be subject to higher costs and/or penalties related to Pennsylvania Conservation and Energy Efficiency Programs.
PPL Electric is subject to Act 129, which contains requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposes PLR electricity supply procurement rules, provides remedies for market misconduct, and made changes to the existing Alternative Energy Portfolio Standard. The law also requires electric utilities to meet specified goals for reduction in customer electricity usage and peak demand. Utilities not meeting these Act 129 requirements are subject to significant penalties that cannot be recovered in rates. Numerous factors outside of our control could prevent compliance with these requirements and result in penalties to us.
E. Risks Specific to the Rhode Island Regulated Segment
(PPL)
We are subject to operational, regulatory and other risks regarding natural gas supply infrastructure in Rhode Island.
A natural gas pipeline explosion or associated incident could have a significant impact on RIE's natural gas operations or result in significant damages and penalties that could have an adverse effectimpact on RIE’s financial position and results of operations. The Pipeline and Hazardous Materials Safety Administration enforces regulations that govern the design, construction, operation and maintenance of pipeline facilities. Failure to comply with these regulations could result in the assessment of fines or penalties against RIE. These regulations require, among other things, that pipeline operators take certain measures with respect to pipeline integrity. Depending on the operationsresults of integrity tests and financial condition of the U.K. regulated businessesother integrity program activities, we could incur significant and PPL.unexpected costs to perform remedial activities on our natural gas infrastructure to ensure our continued safe and reliable operation.
F. Risks Related to All Segments
(All Registrants)
A resurgence, or new variant of ourCOVID-19 or other pandemic health event and related remediation efforts could present challenges to businesses, iscommunities, workforces, markets and supply chains. At this time, the Registrants’ cannot predict the ways in which and the extent to which these or other pandemic-related factors may affect their business, earnings or other financial results.
Our business operations are continually subject to cyber-based security and data integrity risks.risks from vulnerabilities related to our IT systems, operational technology infrastructure and supply chain relationships.
Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems.systems and network infrastructure. The operation of our transmission and distribution operations,systems, including gas distribution systems, as well
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as our generation plants, are all reliant on cyber-based, technologiescomplex and therefore,integrated technologies. Systemic issues could arise as a result of upgrades to particular software or human error. In addition, these complex systems are subject to the risk that such systemsthey could be the target of disruptive actions principally by terrorists, nation state actors or criminals or otherwise be compromisedcompromised. Attacks may come through ransomware, software updates or patches, use of opensource software, firmware that hackers can manipulate to include malicious codes for exploitation at a later date, orthe compromising of hardware by unintentional events.bad actors, creating serious risks to our security, the security of our customers' information, and potentially to our ability to provide power. Attacks could also target our personnel or contractors through attempts to gain access or credentials that could be used to breach our systems. As a result, operations could be interrupted, property could be damaged and sensitive customer information lost or stolen, causing us to incur significant losses of revenues, other substantial liabilities and damages, costs to replace or repair damaged equipment and damage to our reputation. Threats to our systems and operations continue to emerge as new ways to compromise components of our systems or networks are developed. Additionally, cybersecurity risks also threaten our supply chains, including aspects that are not under our control, such as the incorporation of opensource software in systems or software that we use, that despite our efforts do not meet our current security standards.
In addition, under the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including PPL Electric, LG&E, KU and KU,RIE, are subject to mandatory reliability standards promulgated by NERC and SERC and enforced by the FERC. As thean operator of natural gas distribution systems, LG&E is also subject to mandatory reliability standards of the U.S. Department of Transportation.Transportation and is also subject to certain security directives related to cybersecurity issued by the Department of Homeland Security (DHS) Transportation Security Administration (TSA) in 2021. The TSA has determined that LG&E is critical, while RIE has not been notified of this distinction and is therefore not currently subject to the security directives. Failure to comply with suchthese standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of suchthe standards.
We are subject to risks associated with federal and state tax laws and regulations.
Changes in tax law including the recent enactment of the TCJA, as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations.operations and cash flows. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, gross receipts, franchise, sales and use, employment-related and other taxes. We also estimate our ability to utilize deferred tax benefitsassets and tax credits. Due toDependent upon the revenue needs of the jurisdictions in which our businesses operate, various tax and fee increases may be proposed or considered. We cannot predict changes in tax law or regulation or the effect of any such changes on our businesses. Any such changes could increase tax expense and could have a significant negative impact on our results of operations and cash flows.
Increases in electricity prices and/or a weak economy can lead to changes in legislative and regulatory policy, including the promotion of energy efficiency, conservation and distributed generation or self-generation, which may adversely impact our business.
Energy consumption is significantly impacted by overall levels of economic activity and costs of energy supplies. Economic downturns or periods of high energy supply costs can lead to changes in or the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency, alternative and renewable energy sources, and distributed or self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity demand, which could adversely affect our business.
We could be negatively affected by rising interest rates, downgrades to our credit ratings, adverse credit market conditions or other negative developments in our ability to access capital markets.
A downgrade in our credit ratings could negatively affect our ability to access capital and increase the cost of maintaining our credit facilities and any new debt.
Credit ratings assigned by Moody's and S&P to our businesses and their financial obligations have a significant impact on the cost of capital incurred by our businesses. A ratings downgrade could increase our short-term borrowing costs and negatively
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affect our ability to fund liquidity needs and access new long-term debt at acceptable interest rates. See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Ratings Triggers" for additional information on the financial impact of a downgrade in our credit ratings.
Our operating revenues could fluctuate on a seasonal basis, especially as a result of extreme weather conditions.conditions, including storms, or from changes in average temperatures for extended periods, which may be caused or exacerbated by climate change.
Our businesses are subject to seasonal demand cycles. For example, in some markets demand for, and market prices of, electricity peak during hot summer months, while in other markets such peaks occur in cold winter months. As a result, our overall operating results may fluctuate substantially on a seasonal basis if weather conditions diverge adversely from seasonal norms.
Our businesses are subject to physical, market and economic risks relating to potentialeffects of climate change.
Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects. Climate change may also contribute to heightened risk or severity of wildfires, which could disrupt our operations and cause us to incur significant costs, though the annual FEMA National Risk Index for wildfires in the jurisdictions in which we provide service is very low to relatively moderate. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Greenhouse gas regulation could increase the cost of electricity, particularly power generated by fossil fuels, and such increases could have a depressive effect on regional economies. Reduced economic and consumer activity in our service areas -- both generally and specific to certain industries and consumers accustomed to previously lower cost power -- could reduce demand for the power we generate, market and deliver. Also, demand for our energy-related services could be similarly lowered by consumers' preferences or market factors favoring energy efficiency, low-carbon power sources or reduced electricity usage. The Registrants' responses to such climate-related risks include compliance with evolving governmental policy and developing and implementing strategies designed to meet net zero carbon emissions goals, which may affect our financial condition, results of operations or cash flows.
We cannot predict the outcome of the legal proceedings andor investigations currently being conducted with respectrelated to our current and past business activities.businesses in which we are periodically involved. An adverseunfavorable outcome or determination in any of these matters could have a material adverse effect on our financial condition, results of operations or cash flows.
We are involved in legal proceedings, claims and litigation and periodically are subject to ongoing state and federal investigations arising out of our business operations, the most significant of which are summarized in "FederalItem 1. Business and "Regulatory Matters" in Note 67 to the Financial Statements and in "Legal Matters,"Matters" and "Regulatory Issues" and "Environmental Matters" in Note 13 to the Financial Statements. We cannot predict the ultimate outcome of these matters, nor can we reasonably estimate the costs or liabilities that could potentially result from a negative outcome in each case.
Significant increases in our operation and maintenance expenses, including health care and pension costs, could adversely affect our future earnings and liquidity.
We continually focus on limiting and reducing our operation and maintenance expenses. However, we expect to continue to face increased cost pressures in our operations. Increased costs of materials and labor may result from general inflation, increased regulatory requirements (especially in respect of environmental regulations), the need for higher-cost expertise in the workforce or other factors. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. These benefits give rise to significant expenses. Due to general inflation with respect to such costs, the aging demographics of our workforce and other factors, we have experienced significant health care cost inflation in recent years, and we expect our health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take to require employees and retirees to bear a higher portion of the costs of their health care benefits. In addition, we expect to continue to incur significant costs with respect to the defined benefit pension plans for our employees and retirees. The measurement of our expected future health care and pension obligations, costs and liabilities is highly dependent on a variety of assumptions, most of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost
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trends, inflation rates, benefit improvements, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs and cash contribution requirements to fund these benefits could increase significantly.
We may incur liabilities in connection with discontinued operations.divestitures.
In connection with various divestitures, and certain other transactions, we have indemnified or guaranteed parties against certain liabilities. These indemnities and guarantees relate, among other things, to liabilities which may arise with respect to the period during which we or our subsidiaries operated a divested business, and to certain ongoing contractual relationships and entitlements with respect to which we or our subsidiaries made commitments in connection with thea divestiture. See "Guarantees and Other Assurances" in Note 13 to the Financial Statements.
We are subject to liability risks relating to our generation,transmission and distribution operations.
The conduct of our physical and commercial operations subjects us to many risks, including risks of potential physical injury, property damage or other financial liability, caused to or by employees, customers, contractors, vendors, contractual or financial counterparties and other third parties.
Our facilities may not operate as planned, which may increase our expenses and decrease our revenues and have an adverse effect on our financial performance.
Operation of power plants, transmission and distribution facilities, information technology systems and other assets and activities subjects us to a variety of risks, including the breakdown or failure of equipment, accidents, security breaches, viruses or outages affecting information technology systems, labor disputes, obsolescence, delivery/transportation problems and disruptions of fuel supply and performance below expected levels. These events may impact our ability to conduct our businesses efficiently and lead to increased costs, expenses or losses. Operation of our delivery systems below our expectations may result in lost revenue and increased expense, including higher maintenance costs, which may not be recoverable from customers. Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them.
Although we maintain customary insurance coverage for certain of these risks, we do not carry insurance for all of these risks and no assurance can be given that such insurance coverage will be sufficient to compensate us in the event losses occur.
We are required to obtain, and to comply with, government permits and approvals.
We are required to obtain, and to comply with, numerous permits, approvals, licenses and certificates from governmental agencies. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which thea permit was sought unprofitable or otherwise unattractive. In addition, such permits or approvals may be subject to denial, revocation or modification under variouscertain circumstances. Failure to obtain or comply with the conditions of permits or approvals, or failure to comply with any applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our power delivery and may subject us to penalties and other sanctions. Although various regulators routinely renew existing licenses, renewal could be denied or jeopardized by various factors, including failure to provide adequate financial assurance for closure; failure to comply with environmental, health and safety laws and regulations or permit conditions; local community, political or other opposition; and executive, legislative or regulatory action.
Our cost or inability to obtain and comply with the permits and approvals required for our operations could have a material adverse effect on our operations and cash flows. In addition, new environmental legislation or regulations, if enacted, or changed interpretations of existing laws may elicit claims that historical routine modification activities at our facilities violated applicable laws and regulations. In addition to the possible imposition of fines in such cases, we may be required to undertake significant capital investments in pollution control technology and obtain additional operating permits or approvals, which could have an adverse impact on our business, results of operations, cash flows and financial condition.
War, other armed conflicts or terrorist attacks could have a material adverse effect on our business.
War, terrorist attacks and unrest have caused and may continue to cause instability in the world's financial and commercial markets and have contributed to high levels of volatility in prices for oil and gas.markets. In addition, unrest in the Middle East could lead to acts of terrorism in the United States the United Kingdom or elsewhere, and acts of terrorism could be directed against companies such as ours. Armed conflicts and terrorism and their effects on us or our markets may significantly affect our business and results of operations in the future. In addition, we may incur increased costs for security, including additional physical plant security and security personnel or additionalincreased capability following a terrorist incident.
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We are subject to counterparty performance, credit or other risk in theirthe provision of goods or services to us, which could adversely affect our ability to operate our facilities or conduct business activities.
We purchase from a variety of suppliers energy, capacity, fuel, natural gas, transmission service and certain commodities used in the physical operation of our businesses, as well as goods or services, including information technology rights and services, used in the administration of our businesses. Delivery of these goods and services is dependent on the continuing operational performance and financial viability of our contractual counterparties and also the markets, infrastructure or third-partiesthird parties they use to provide such goods and services to us. As a result, we are subject to the risks of disruptions, curtailments or increased costs in the operation of our businesses if such goods or services are unavailable or become subject to price spikes or if a counterparty fails to perform. Such disruptions could adversely affect our ability to operate our facilities or deliver our services and collect our revenues, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations. The performance of coal markets and producers may be the subject of increased counterparty risk to LKE, LG&E and KU currently due to weaknesses in such markets and suppliers. The coal industry is subject to increasing competitive pressures from natural gas markets, political pressures and new or more stringent environmental regulation, including greenhouse gases or other air emissions,regulation of combustion byproducts and water inputs or discharges. Consequently, the coal industry faces increased production costs or closed customer markets.
We are subject to the risk that our workforce and its knowledge base may become depleted in coming years.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. We are experiencing an increase inexperience attrition due primarily to the number of retiring employees, with the risk that critical knowledge will be lost and that it may be difficult to replace departed personnel, and to attract and retain new personnel, with appropriate skills and experience, due to a declining trend in the number of available skilled workers and an increase in competition for such workers.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
ITEM 1C. CYBERSECURITY(All Registrants)
Processes for Identifying, Assessing and Managing Material Risks from Cybersecurity Threats
PPL’s Chief Security Officer (CSO) is responsible for establishing PPL’s cyber-risk management strategy for PPL and the other Registrants and reports directly to PPL’s Chief Executive Officer. The CSO has over 25 years of experience leading technology and security organizations, has a degree in computer science, and holds professional certifications in information security, IT auditing, and privacy. He is also a member of nationally and internationally recognized industry and security organizations, including the Information Systems Audit and Control Association, International Association of Privacy Professionals, and the Domestic Security Alliance Council. PPL’s VP – Cybersecurity is responsible for implementing and executing the cyber-risk management strategy. The VP – Cybersecurity is a seasoned cybersecurity professional with a wealth of experience safeguarding digital assets across multiple industries. He maintains a globally recognized cyber certification and has held multiple certifications in the areas of cyber risk and information control, and actively contributes to industry advancement as a member of national and international industry groups. The teams managed by the CSO and VP – Cybersecurity are comprised of seasoned experts in cyber and IT security and possess appropriate experience to safeguard the company’s data, networks and systems, mitigate cyber risks and help prevent and combat cyber threats.
The Registrants manage cybersecurity risks through monitoring, defense and response tools, including independent third-party assessments, internal audit assessments of the program’s effectiveness, intelligence reports, cybersecurity threat trends, implementation of governance models, industry collaboration and employee training and awareness. The Registrants are actively engaged in cybersecurity related industry forums, public-private partnerships with law enforcement, cross-industry peer groups, and other efforts to help improve the protection of the U.S. electric grid.
The Registrants utilize monitoring tools, including but not limited to, cybersecurity incident and event management, penetration testing, intrusion detection and prevention, vulnerability assessments and anti-virus systems to detect anomalous or suspicious system or network activity. The Registrants may also become aware of a potential cybersecurity event or incident through employee reports, notification by a third-party service provider or business partner with potential impact to the Registrants or their systems, customers or notification by a government agency. The Registrants’ subject matter specialists from across the
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enterprise provide input and expertise into risk governance processes, including cybersecurity, information technology, legal, compliance, operations, and enterprise risk management.
In developing their cybersecurity programs, the Registrants are guided byvarious frameworks including the NIST Cybersecurity Framework, a voluntary framework that consists of standards, guidelines and best practices for managing cybersecurity risk, that is widely used by critical infrastructure industries to help determine and addressthe highest priority cybersecurity risks. The Registrants conduct regular internal cybersecurity audits and vulnerability assessments and regularly engage with third-party cybersecurity experts for external assessments of their cybersecurity controls, including technical, physical and social aspects, to better comprehend the scope and magnitude of active threats to the industry and nation and their potential impact on our systems.
PPL and the other Registrants also maintain a process to review the cyber risks that arise from the use of third-party service providers as well as programs and procedures to mitigate such risks internally and to assess the extent to which such providers effectively manage their own cyber risks.
The CSO chairs the Corporate Security Council, which holds regular meetings consisting of senior executive management and reviews and oversees cybersecurity risks. The VP – Cybersecurity chairs the Cybersecurity Governance Council, which governs actions to ensure that the Registrants are effectively managing cybersecurity risks, as well as the Cybersecurity Steering Committee, that drives accountability, establishes work priorities, and directs a portfolio of key cybersecurity projects and initiatives.
PPL has established an ExecutiveCrisis Team comprised of PPL’s executive leadership, including the Chief Executive Officer, Chief Financial Officer, Chief Human Resources Officer, Chief Legal Officer, Chief Operating Officer, VP – Public Affairs and Sustainability, VP – Corporate Communications, and additional officers as circumstances may warrant, to allow the company to respond quickly to a crisis, including a cyber event. This team governs and manages corporate crisis preparedness across the business lines, operations, and functions. Material or potentially material risks are escalated to the Executive Crisis Team and other appropriate leadership for review and action.
Also, the Registrants’ workforce undertakes mandatory role-based annual training on identifying, reporting, and escalating cyber and physical security concerns to further assist in the identification of risks as well as the acceptable use of corporate electronic resources. Additionally, all employees and contractors are required to participate in the Registrants’ ethical cyber phishing campaign program.
In addition to these enterprise-wide initiatives, PPL's Kentucky, Pennsylvania and Rhode Island operations are subject to extensive and rigorous mandatory cybersecurity requirements that are developed and enforced by NERC and approved by the FERC to protect grid security and reliability. LG&E is also subject to certain security directives related to cybersecurity issued by the Department of Homeland Security’s Transportation Security Administration in 2021. See Note 13 to the Financial Statements for additional information on these directives.
The Registrants have been subject to attempted cybersecurity threats and will likely continue to be subject to such attempts in the future. While PPL has not determined any cybersecurity incidents have materially affected the Registrants, including their business strategy, results of operations or financial condition, there can be no guarantee that the Registrants will not be the subject of future, successful attacks, threats or incidents, which may be material.
See “Risks Related to All Segments – Our business operations are continually subject to cyber-based security and data integrity risks from vulnerabilities related to our IT systems, operational technology infrastructure and supply chain relationships” in “Item 1A. Risk Factors” for a discussion of cybersecurity risks affecting the Registrants.
Oversight of Cybersecurity Risks by the Board of Directors and Management
PPL’s Board of Directors oversees the Registrants’ management of cybersecurity risk through various processes identified below.
The Board has direct oversight of the Registrants’ cybersecurity programs through periodic reports from the CSO, at least twice a year, regarding cybersecurity matters and risks as well as the adequacy and effectiveness of our cybersecurity risk management program. Through these reports, the Board monitors the Registrants’ programs, processes and procedures related to cybersecurity. The Board has directed the CEO and CSO to promptly inform the Board in the event of a material or potentially material cybersecurity event. Each member of the Board has access to management, including the CEO and CSO, to ask questions and engage on the company’s approach to prevent, detect, assess, and mitigate cybersecurity risk. PPL’s Board has several Board members with experience in cybersecurity, including one with a certificate in Cyber-Risk Oversight from the National Association of Corporate Directors.
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A primary function of the Audit Committee is to assist the Board in the oversight of the identification, assessment and management of risk. Cybersecurity risks are included in PPL’s enterprise risk management process and are reported to the Audit Committee of the Board on a quarterly basis or more frequently, as needed.
ITEM 2. PROPERTIES
Kentucky Regulated Segment(PPL, LKE, LG&E and KU)
LG&E's and KU's properties consist primarily of regulated generation facilities, electricity transmission and distribution assets and natural gas transmission and distribution assets in Kentucky. The capacity of generation units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances. The electricity generating capacity at December 31, 20172023 was:
| LKE | LG&E | KU | LG&E | KU | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Primary Fuel/Plant | Total MW Capacity Summer | Ownership or Other Interest in MW | % Ownership or Other Interest | Ownership or Other Interest in MW | % Ownership or Other Interest | Ownership or Other Interest in MW | Primary Fuel/Plant | Total MW Capacity Summer | % Ownership or Other Interest | Ownership or Other Interest in MW | % Ownership or Other Interest | Ownership or Other Interest in MW | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal | Coal | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ghent - Units 1- 4 | 1,919 | 1,919 | 100.00 | 1,919 | Ghent - Units 1- 4 | 1,919 | 100.00 | 1,919 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mill Creek - Units 1- 4 | 1,465 | 1,465 | 100.00 | 1,465 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown - Units 1-3 | 681 | 681 | 100.00 | 681 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown - Unit 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown - Unit 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown - Unit 3 | 412 | 100.00 | 412 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Trimble County - Unit 1 (a) | 493 | 370 | 75.00 | 370 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Trimble County - Unit 2 (a) | 732 | 549 | 14.25 | 104 | 60.75 | 445 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| OVEC - Clifty Creek (b) | 1,164 | 95 | 5.63 | 66 | 2.50 | 29 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| OVEC - Kyger Creek (b) | 956 | 78 | 5.63 | 54 | 2.50 | 24 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Trimble County - Unit 2 (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Trimble County - Unit 2 (a) | 732 | 14.25 | 104 | 60.75 | 445 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 7,410 | 5,157 | 2,059 | 3,098 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 5,021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 5,021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 5,021 | 1,939 | 2,776 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural Gas/Oil | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Unit 5 (c) | 130 | 130 | 53.00 | 69 | 47.00 | 61 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Unit 5 (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Unit 5 (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Unit 5 (b) | 130 | 53.00 | 69 | 47.00 | 61 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Units 6 - 7 | 292 | 292 | 38.00 | 111 | 62.00 | 181 | E.W. Brown Units 6 - 7 | 292 | 38.00 | 111 | 62.00 | 181 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Units 8 - 11 (c) | 484 | 484 | 100.00 | 484 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Units 8 - 11 (b) | E.W. Brown Units 8 - 11 (b) | 484 | 100.00 | 484 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Trimble County Units 5 - 6 | 318 | 318 | 29.00 | 92 | 71.00 | 226 | Trimble County Units 5 - 6 | 318 | 29.00 | 92 | 71.00 | 226 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Trimble County Units 7 - 10 | 636 | 636 | 37.00 | 235 | 63.00 | 401 | Trimble County Units 7 - 10 | 636 | 37.00 | 235 | 63.00 | 401 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Paddy's Run Units 11 - 12 | 35 | 35 | 100.00 | 35 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Paddy's Run Unit 12 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Paddy's Run Unit 13 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Paddy's Run Unit 13 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Paddy's Run Unit 13 | 147 | 147 | 53.00 | 78 | 47.00 | 69 | 147 | 53.00 | 78 | 47.00 | 69 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Haefling - Units 1 - 2 | 24 | 24 | 100.00 | 24 | Haefling - Units 1 - 2 | 24 | 100.00 | 24 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Zorn Unit | 14 | 14 | 100.00 | 14 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cane Run Unit 7 | 662 | 662 | 22.00 | 146 | 78.00 | 516 | Cane Run Unit 7 | 662 | 22.00 | 146 | 78.00 | 516 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cane Run Unit 11 | 14 | 14 | 100.00 | 14 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,756 | 2,756 | 794 | 1,962 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2,716 | 2,716 | 754 | 1,962 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hydro | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ohio Falls - Units 1-8 | 64 | 64 | 100.00 | 64 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ohio Falls - Units 1-8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ohio Falls - Units 1-8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dix Dam - Units 1-3 | 32 | 32 | 100.00 | 32 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 96 | 96 | 64 | 32 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dix Dam - Units 1-3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dix Dam - Units 1-3 | 32 | 100.00 | 32 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 96 | 96 | 64 | 32 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Solar | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Solar (d) | 8 | 8 | 39.00 | 3 | 61.00 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Solar (c) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Solar (c) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| E.W. Brown Solar (c) | 8 | 39.00 | 3 | 61.00 | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 10,270 | 8,017 | 2,920 | 5,097 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 7,841 | 2,760 | 4,775 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)Trimble County Unit 1 and Trimble County Unit 2 are jointly owned with Illinois Municipal Electric Agency and Indiana Municipal Power Agency. Each owner is entitled to its proportionate share of the units' total output and funds its proportionate share of capital, fuel and other operating costs. See Note 12 to the Financial Statements for additional information.
(b)There is an inlet air cooling system attributable to these units. This inlet air cooling system is not jointly owned; however, it is used to increase production on the units to which it relates, resulting in an additional 12 MW of capacity for LG&E and an additional 86 MW of capacity for KU.
(c)This unit is a 10 MW facility and achieves such production. The 8 MW solar facility summer capacity rating is reflective of an average expected output across the peak hours during the summer period based on average weather conditions at the solar facility.
For a description of LG&E's and KU's service areas, see "Item 1. Business - General - Segment Information - Kentucky Regulated Segment." At December 31, 2017,2023, LG&E's and KU's electricity transmission system included in the aggregate, 45 substations (31 of which are shared with theand distribution system) with a total capacity of 8 million kVAsystems and 669 pole miles of lines. LG&E's distribution system included 97 substations (31 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,892 circuit miles of overhead lines and 2,553 underground cable miles. KU's transmission system included 142 substations (60 of which are shared with the distribution system) with a total capacity of 14 million kVA and 4,066 pole miles of lines. KU's distribution system included 469 substations (60 of which are shared with the transmission system) with a total capacity of 7 million kVA, 14,016circuit miles of overhead lines and2,484underground cable miles.
LG&E's natural gas transmission system includes 4,310 milesand distribution systems were:
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| LG&E | KU | |||||||||||||||||||||||||
| Distribution | Transmission | Distribution | Transmission | |||||||||||||||||||||||
| Electricity System | ||||||||||||||||||||||||||
| Substations (a) | 96 | 78 | 462 | 212 | ||||||||||||||||||||||
| Capacity (in millions of kVA) | 5 | 8 | 8 | 15 | ||||||||||||||||||||||
| Overhead lines (circuit miles) | 3,880 | 663 | 14,086 | 4,064 | ||||||||||||||||||||||
| Underground lines (circuit miles) | 2,824 | 6 | 2,789 | 4 | ||||||||||||||||||||||
| Natural Gas System | ||||||||||||||||||||||||||
| Distribution mains (miles) | 4,447 | — | — | — | ||||||||||||||||||||||
| Transmission pipeline (miles) | — | 234 | — | — | ||||||||||||||||||||||
| Transmission storage lines (miles) | — | 95 | — | — | ||||||||||||||||||||||
| Combustion turbine lines (miles) | — | 19 | — | 11 | ||||||||||||||||||||||
| Storage fields | — | 4 | — | — | ||||||||||||||||||||||
| Storage field capacity (Bcf) | — | 11 | — | — | ||||||||||||||||||||||
(a)191 substations (61 at LG&E and 130 at KU) are shared between the distribution mains and 396 miles of gas transmission mains, consisting of 260 miles of gas transmission pipeline, 117 miles of gas transmission storage lines, 18 miles of gas combustion turbine lines and one mile of gas transmission pipeline in regulator facilities. Five underground natural gas storage fields, with a total working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to ultimate consumers. KU's service area includes an additional 11 miles of gas transmission pipeline providing gas supply to natural gas combustion turbine electricity generating units.systems.
Substantially all of LG&E's and KU's respective real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and, in the case of LG&E, the storage and distribution of natural gas, is subject to the lien of either the LG&E 2010 Mortgage Indenture or the KU 2010 Mortgage Indenture. See Note 78 to the Financial Statements for additional information.
LG&E and KU continuously reexamine development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them or pursue other options. In 2016,See Item 1. Business for a discussion related to LG&E&E's and KU received approval from the KPSC to develop a 4 MW solar share facility to service a solar share program. The solar share program is an optional, voluntary program that allows customers to subscribe capacity in the solar share facility. Construction is expected to begin, in 500-kilowatt phases, when subscription is complete. As of December 31, 2017, LG&E and KU have not yet constructed the first solar share facility and are actively marketing theKU's Solar Share program and continue to receive interest from customers.2022 CPCN filing.
Pennsylvania Regulated Segment(PPL and PPL Electric)
For a description of PPL Electric's service territory,area, see "Item 1. Business - General - Segment Information - Pennsylvania Regulated Segment." PPL Electric has electric transmission and distribution lines in public streets and highways pursuant to franchises and rights-of-way secured from property owners. At December 31, 2017,2023, PPL Electric's transmission system includes 4952 substations with a total capacity of 2832 million kVA and 5,4005,295 circuit miles in service. PPL Electric's distribution system includes 351353 substations with a total capacity of 1415 million kVA, 37,19536,569 circuit miles of overhead lines and 8,5498,891 underground circuit miles. All of PPL Electric's facilities are located in Pennsylvania. Substantially all of PPL Electric's distribution properties and certain transmission properties are subject to the lien of the PPL Electric 2001 Mortgage Indenture. See Note 78 to the Financial Statements for additional information.
For a description of RIE's service area, see "Item 1. Business - General - Segment Information - Rhode Island Regulated Segment." At December 31, 2023, RIE's electric transmission system includes 44 substations with capacity of 33 kVA or higher, 342 circuit miles of overhead lines and 45 underground circuit miles. RIE's electric distribution system includes 59 substations, 5,328 circuit miles of overhead lines and 1,234 underground circuit miles. RIE also has distribution mains for information on the Regional Transmission Line Expansion Plan.its natural gas system with mileage of 3,227 miles. All of RIE's facilities are located in Rhode Island.
ITEM 3. LEGAL PROCEEDINGS
See Notes 5, 6, 7, 9 and 13 to the Financial Statements for information regarding legal, tax litigation,and regulatory matters and environmental proceedings and matters.proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash" for information regarding certain restrictions on the ability to pay dividends for all Registrants.
PPL Corporation
Additional information for this item is set forth in the sections entitled "Quarterly Financial, Common Stock Price and Dividend Data," "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and "Shareowner and Investor Information" of this report. At January 31, 2018,2024 there were 55,40944,305 common stock shareowners of record.
| Period | Total Number of Shares (or Units) Purchased (1) | Average Price Paid per Share (or Unit) | Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans of Programs | Maximum Number (or Approximate Dollar Value) of Shares(or Units) that May Yet Be Purchased Under the Plans or Programs (1) | |||
| October 1 to October 31, 2017 | |||||||
| November 1 to November 30, 2017 | |||||||
| December 1 to December 31, 2017 | 6,956 | $ | 36.27 | ||||
| Total | 6,956 | $ | 36.27 | ||||
PPL Electric Utilities Corporation
There is no established public trading market for PPL Electric's common stock, as PPL owns 100% of the outstanding common shares. Dividends paid to PPL on those common shares are determined by PPL Electric's Board of Directors. PPL Electric paid common stock dividends to PPL of $336$323 million in 20172023 and $288$340 million in 2016.2022.
Louisville Gas and Electric Company
There is no established public trading market for LG&E's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by LG&E's Board of Directors. LG&E paid common stock dividends to LKE of $192$166 million in 20172023 and $128$275 million in 2016.2022.
Kentucky Utilities Company
There is no established public trading market for KU's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by KU's Board of Directors. KU paid common stock dividends to LKE of $226$190 million in 20172023 and $248$296 million in 2016.2022.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
| PPL Corporation (a) (b) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
Income Items (in millions) | ||||||||||||||||||||
| Operating revenues | $ | 7,447 | $ | 7,517 | $ | 7,669 | $ | 7,852 | $ | 7,263 | ||||||||||
| Operating income | 3,068 | 3,048 | 2,831 | 2,867 | 2,561 | |||||||||||||||
| Income from continuing operations after income taxes attributable to PPL shareowners | 1,128 | 1,902 | 1,603 | 1,437 | 1,368 | |||||||||||||||
Income (loss) from discontinued operations (net of income taxes) (f) | — | — | (921 | ) | 300 | (238 | ) | |||||||||||||
| Net income attributable to PPL shareowners (f) | 1,128 | 1,902 | 682 | 1,737 | 1,130 | |||||||||||||||
Balance Sheet Items (in millions) | ||||||||||||||||||||
| Total assets (d) | 41,479 | 38,315 | 39,301 | 48,606 | 45,889 | |||||||||||||||
| Short-term debt (d) | 1,080 | 923 | 916 | 836 | 701 | |||||||||||||||
| Long-term debt (d) | 20,195 | 18,326 | 19,048 | 18,054 | 18,269 | |||||||||||||||
| Common equity (d) | 10,761 | 9,899 | 9,919 | 13,628 | 12,466 | |||||||||||||||
| Total capitalization (d) | 32,036 | 29,148 | 29,883 | 32,518 | 31,436 | |||||||||||||||
| Financial Ratios | ||||||||||||||||||||
| Return on common equity - % (d)(f) | 10.9 | 19.2 | 5.8 | 13.0 | 9.8 | |||||||||||||||
| Ratio of earnings to fixed charges (c) | 3.1 | 3.8 | 2.8 | 2.8 | 2.4 | |||||||||||||||
| Common Stock Data | ||||||||||||||||||||
| Number of shares outstanding - Basic (in thousands) | ||||||||||||||||||||
| Year-end | 693,398 | 679,731 | 673,857 | 665,849 | 630,321 | |||||||||||||||
| Weighted-average | 685,240 | 677,592 | 669,814 | 653,504 | 608,983 | |||||||||||||||
Income from continuing operations after income taxes available to PPL common shareowners - Basic EPS | $ | 1.64 | $ | 2.80 | $ | 2.38 | $ | 2.19 | $ | 2.24 | ||||||||||
Income from continuing operations after income taxes available to PPL common shareowners - Diluted EPS | $ | 1.64 | $ | 2.79 | $ | 2.37 | $ | 2.16 | $ | 2.12 | ||||||||||
| Net income available to PPL common shareowners - Basic EPS | $ | 1.64 | $ | 2.80 | $ | 1.01 | $ | 2.64 | $ | 1.85 | ||||||||||
| Net income available to PPL common shareowners - Diluted EPS | $ | 1.64 | $ | 2.79 | $ | 1.01 | $ | 2.61 | $ | 1.76 | ||||||||||
| Dividends declared per share of common stock | $ | 1.58 | $ | 1.52 | $ | 1.50 | $ | 1.49 | $ | 1.47 | ||||||||||
| Book value per share (d) | $ | 15.52 | $ | 14.56 | $ | 14.72 | $ | 20.47 | $ | 19.78 | ||||||||||
| Market price per share | $ | 30.95 | $ | 34.05 | $ | 34.13 | $ | 36.33 | $ | 30.09 | ||||||||||
| Dividend payout ratio - % (e)(f) | 96 | 55 | 149 | 57 | 84 | |||||||||||||||
| Dividend yield - % (g) | 5.1 | 4.5 | 4.4 | 4.1 | 4.9 | |||||||||||||||
| Price earnings ratio (e)(f)(g) | 18.9 | 12.2 | 33.8 | 13.9 | 17.1 | |||||||||||||||
| Sales Data - GWh | ||||||||||||||||||||
| Domestic - Electric energy supplied - wholesale | 2,084 | 2,177 | 2,241 | 2,365 | 2,383 | |||||||||||||||
| Domestic - Electric energy delivered - retail | 65,751 | 67,474 | 67,798 | 68,569 | 67,848 | |||||||||||||||
| U.K. - Electric energy delivered | 74,317 | 74,728 | 75,907 | 75,813 | 78,219 | |||||||||||||||
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
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Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
(All Registrants)
This "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" is separately filed by PPL, PPL Electric, LKE, LG&E and KU. Information contained herein relating to any individual Registrant is filed by such Registrant solely on its own behalf, and no Registrant makes any representation as to information relating to any other Registrant. 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 individual Registrants when significant.
The following should be read in conjunction with the Registrants' Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
•"Overview" provides a description of each Registrant's business strategy and a discussion of important financial and operational developments.
•"Results of Operations" for all Registrants includes a "Statement of Income Analysis," which discusses significant changes in principal line items on the Statements of Income, comparing 20172023 with 2016 and 2016 with 2015.2022. For PPL, "Results of Operations" also includes "Segment Earnings" and "Margins"Earnings," which provideprovides a detailed analysis of earnings by reportable segment. These discussions include the non-GAAP financial measures, includingmeasure "Earnings from Ongoing Operations" and "Margins" and provide explanationsan explanation of the non-GAAP financial measuresmeasure and a reconciliation of the non-GAAP financial measuresmeasure to the most comparable GAAP measure. The "2018 Outlook" discussion identifies key factors expected to impact 2018 earnings. For PPL Electric, LKE, LG&E and KU, a summary of earnings and margins is also provided.
•"Financial Condition - Liquidity and Capital Resources" provides an analysis of the Registrants' liquidity positions and credit profiles. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.
•"Financial Condition - Risk Management" provides an explanation of the Registrants' risk management programs relating to market and credit risk.
•"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of the Registrants and that require their management to make significant estimates, assumptions and other judgments of inherently uncertain matters.
For comparison of the Registrants’ results of operations and cash flows for the years ended December 31, 2022 to December 31, 2021, refer to “Item 7. Combined Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2022 Form 10-K, filed with the SEC on February 17, 2023.
Overview
For a description of the Registrants and their businesses, see "Item 1. Business."
Business Strategy
(All Registrants)
PPL's strategy, which is supported by the other Registrants and subsidiaries, is to achieve industry-leading performance in safety, reliability, customer satisfaction and operational efficiency; to advance a clean energy transition while maintaining affordability and reliability; to maintain a strong earningsfinancial foundation and dividend growth potential that will create significantlong-term value for its shareownersour shareowners; to foster a diverse and positions PPL well for continued growthexceptional workplace; and success.to build strong communities in areas that we serve.
Central to PPL's businesses of WPD, PPL Electric, LG&E and KU plan to achieve growth by providing efficient, reliable and safe operations and strong customer service, maintaining constructive regulatory relationships and achieving timely recovery of costs. These businesses are expected to achieve strong, long-term growth in rate base in the U.S. and RAV in the U.K., driven by planned significant capital expenditures to maintain existing assets and improve system reliability and, for LKE, LG&E and
30
supply clauseclause) and recovery on construction work-in-progress)work-in-progress that reduce regulatory lag and provide timely recovery of and return on, as appropriate, prudently incurred costs. In addition, the KPSC requires a utility to obtain a CPCN prior to constructing a facility, unless the construction is an ordinary extension of existing facilities in the usual course of business or does not involve sufficient capital outlay to materially affect the utility's financial condition. Although such KPSC proceedings do not directly address cost recovery issues, the KPSC, in awarding a CPCN, concludes that the public convenience and necessity require the construction of the facility on the basis that the facility is the lowest reasonable cost alternative to address the need. In Pennsylvania, the FERC transmission formula rate,rates, DSIC mechanism, Smart Meter Rider and other recovery mechanisms are in placeoperate to reduce regulatory lag and provide for timely recovery of and a return on, as appropriate, prudently incurred costs. In Rhode Island, FERC formula rates, the gas cost adjustment, net metering, infrastructure, safety and reliability (ISR) and revenue decoupling mechanisms and other rate adjustment mechanisms operate to reduce regulatory lag and provide timely recovery of and return on, as appropriate, prudently incurred costs.
Financial and Operational Developments
On December 22, 2017, President Trump signed2023, PPL announced that it entered into lawa settlement agreement (Settlement Agreement) with Talen Montana, LLC and affiliated entities (Talen) to resolve all claims made by Talen in Talen Montana, LLC et al. v. PPL Corp. et al, Adv. No 22-09001 pending before the TCJA. Substantially allU.S. Bankruptcy Court for the Southern District of Texas and arising out of the provisionsJune 2015 spinoff of PPL Energy Supply, which was renamed Talen. Under the terms of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the taxation of corporations, including provisions specifically applicable to regulated public utilities. The more significant changes that impact the Registrants are:
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Income tax expense (benefit) | $ | 321 | $ | (13 | ) | $ | 112 | $ | — | $ | — | ||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Income tax expense (benefit) | $ | 220 | $ | (13 | ) | $ | 112 | $ | — | $ | — | ||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Net Increase in Regulatory Liabilities | $ | 2,185 | $ | 1,019 | $ | 1,166 | $ | 532 | $ | 634 | |||||||||
a settlement in January 2024. This matter is now concluded. See "Legal Matters" in Note 513 to the Financial Statements for additional information.
During 2023, PPL purchased approximately $300 million of renewable tax credits, as allowed by the IRA. The credits were acquired at a discount. PPL believes that it will be able to monetize the acquired credits within the foreseeable future and recorded the associated benefit of the discount as a reduction of income taxes as of December 31, 2023. In addition, PPL recorded a deferred tax asset representing credits that will be utilized in European Union (PPL)future periods.
IRS Revenue Procedure 2023-15 (PPL and LG&E)
On March 29, 2017,April 14, 2023, the U.K. formally notifiedIRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax purposes. PPL and LG&E are currently reviewing the European Council of the European Union (EU) ofrevenue procedure to determine its intent to withdraw from the EU, thereby commencing the two-year negotiation period to establish the terms of that withdrawal under Article 50 of the Lisbon Treaty. Article 50 specifies that if a member state decides to withdraw from the EU, it must notify the European
Regulatory Requirements
(All Registrants)
The Registrants cannot predict the impact that future regulatory requirements may have on their financial condition or results of operations.
(PPL, LKE, LG&E and KU)
Environmental Considerations for Coal-Fired Generation
The businesses of LKE, LG&E and KU are subject to extensive federal, state and local environmental laws, rules and regulations, including those pertaining to CCRs, GHG, ELGs and the Clean Power Plan.ELGs. See Note 6, Note Notes 7, 13 and Note 19 to the Financial Statements for a discussion of these significant environmental matters. These and other stringent environmental requirements led PPL, LKE, LG&E and KU to retire approximately 800 1,200 MW of coal-fired generating plants in Kentucky primarilysince 2010. As part of the long-term generation planning process, LG&E and KU evaluate a range of factors including the impact of potential stricter environmental regulations, fuel price scenarios, the cost of replacement generation, continued operations and major maintenance costs and the risk of major equipment failures in 2015. Additionally, KU anticipates retiringdetermining when to retire generation assets.
As a result of environmental requirements and aging infrastructure, LG&E has sought and obtained approval to retire two older coal-fired units at the Mill Creek Plant. Mill Creek Unit 1, with 300 MW of capacity, is expected to be retired in 2024. Mill Creek Unit 2, with 297 MW of capacity, is expected to be retired in 2027, subject to certain conditions. See Note 7 to the Financial Statements for additional information.
31
CPCN and SB 4 Application
On December 15, 2022, LG&E and KU filed an application with the KPSC for a CPCN for the construction and purchase of various generating facilities in conjunction with the retirement of four existing coal-fired generation units and three small gas-fired units. On March 24, 2023, Kentucky Senate Bill 4 (SB 4) went into effect, which requires KPSC approval of the retirement of fossil fuel-fired electric generating units in the state. On May 10, 2023, LG&E and KU filed an application with the KPSC seeking approval of the retirement of seven fossil fuel-fired generating units as required by SB 4. On May 16, 2023, the KPSC entered an Order consolidating the SB 4 filing proceeding into the CPCN case.
On November 6, 2023, the KPSC issued an order approving LG&E’s and KU’s requests (i) to construct a 640 MW net summer rating NGCC combustion turbine at LG&E's Mill Creek Generating Station in Jefferson County, Kentucky, (ii) to construct a 120 MWac solar photovoltaic electric generating facility in Mercer County, Kentucky, (iii) to acquire a 120 MWac solar facility to be built by a third-party solar developer in Marion County, Kentucky and (iv) to construct a 125 MW, 4-hour battery energy storage system facility at KU's E.W. Brown plant in 2019 withGenerating Station. The KPSC denied the request to construct a combined621 MW net summer rating capacityNGCC combustion turbine at KU's E.W. Brown Generating Station in Mercer County, Kentucky at this time, based on the finding that the construction of 272 MW.this unit should be deferred with the construction date beginning on a date that provides for an in-service date in 2030. The order also authorized LG&E's and KU's entry into the four solar PPAs, subject to certain conditions, but deferred for future proceedings specific decisions on cost recovery treatment or mechanisms. Further, the order approved the new, adjusted or expanded energy efficiency programs contained in the requested 2024-2030 DSM plan.
See Note 7 to the Financial Statements for additional information.
Kentucky March 2023 Storm
On March 3, 2023, LG&E and KU experienced significant windstorm activity in their service territories, resulting in substantial damage to certain of the environmental requirements discussed above, LKE projects $828LG&E's and KU's assets with total costs incurred through December 31, 2023 of $74 million ($33533 million at LG&E and $493$41 million at KU) in environmental capital investment over the next five years. See PPL's "Financial Condition - Forecasted Uses of Cash - Capital Expenditures", Note 6 and Note 13 for additional information.
FERC Transmission Rate Filing
In 2018, LG&E and KU base electricity ratesapplied to the FERC requesting elimination of $55 million, reflectingcertain on-going waivers and credits to a return on equitysub-set of 9.75%,transmission customers relating to the withdrawal1998 merger of LG&E's and KU's request forparent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a CPCN for the Advanced Metering Systemregional transmission operator and other changes to the revenue requirements, which dealt primarily with the timingenergy market. The application sought termination of cost recovery, including depreciation rates.
November 16 order. LG&E and KU cannot predict the ultimate outcome of these proceedings.
certain
32
waivers and credits primarily through base rates increases, provided, however, that increases associated with the FERC's May 18, 2023 order are expected to be subject to future rate proceedings.
Advanced Metering Functionality (AMF)
In 2021, RIE filed its Updated AMF Business Case and Grid Modernization Plan (GMP) with the RIPUC in accordance with the Amended Settlement Agreement (ASA) approved by the RIPUC in August 2018, and which among other things, sought approval to deploy smart meters throughout the service territory. After PPL completed the acquisition of RIE, RIE filed a new AMF Business Case with the RIPUC in 2022, consisting of a detailed proposal for full-scale deployment of AMF across its electric service territory.
On September 27, 2023, the RIPUC unanimously approved RIE to deploy an AMF-based metering system for the electric distribution business. RIE is authorized to seek recovery of the approved capital investment through the ISR process with an overall multi-year cap on recovery at approximately $153 million, subject to certain terms, conditions and limitations with respect to the Financial Statementspotential offsets and recoverability of certain costs. RIE is required to continue spending even if above the recovery cap, until it achieves the functionalities outlined in the AMF Business Case. RIE filed with the RIPUC (i) an updated electric Service Quality Plan on December 27, 2023 for RIPUC approval and (ii) additional information relatedcompliance tariff provisions regarding recovery and updated cost schedules to reflect the spinoffRIPUC's decision on December 22, 2023 for RIPUC approval. RIE cannot predict the outcome of PPL Energy Supply, including the components of Discontinued Operations.these matters.
Results of Operations
(PPL)
The "Statement of Income Analysis" discussion below describes significant changes in principal line items on the Statements of Income, comparing year-to-year changes.2023 with 2022. The "Earnings" discussion"Segment Earnings" discussions provides a summaryreview of earnings. The "Margins" discussion includesresults by reportable segment. These discussions include the non-GAAP financial measure "Earnings from Ongoing Operations" and provide an explanation of the non-GAAP financial measure and a reconciliation of non-GAAP financial measuresthe measure to "Operating Income."the most comparable GAAP measure.
(PPL Electric, LG&E and KU)
A "Statement of Income Analysis" is presented separately for PPL Electric, LG&E and KU. The "Statement of Income Analysis" discussion below describes significant changes in principal line items on the Statements of Income, comparing 2023 with 2022. The results of operations section for PPL Electric, LG&E and KU is presented in a reduced disclosure format in accordance with General Instructions (I)(2)(a) of Form 10-K.
33
PPL: Statement of Income Analysis and Segment Earnings and Margins
Statement of Income Analysis
Net income for the years ended December 31 includes the following results.results:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Operating Revenues | $ | 8,312 | $ | 7,902 | $ | 410 | |||||||||||
| Operating Expenses | |||||||||||||||||
| Operation | |||||||||||||||||
| Fuel | 733 | 931 | (198) | ||||||||||||||
| Energy purchases | 1,841 | 1,686 | 155 | ||||||||||||||
| Other operation and maintenance | 2,462 | 2,398 | 64 | ||||||||||||||
| Depreciation | 1,254 | 1,181 | 73 | ||||||||||||||
| Taxes, other than income | 392 | 332 | 60 | ||||||||||||||
| Total Operating Expenses | 6,682 | 6,528 | 154 | ||||||||||||||
| Other Income (Expense) - net | (40) | 54 | (94) | ||||||||||||||
| Interest Expense | 666 | 513 | 153 | ||||||||||||||
| Income from Continuing Operations Before Income Taxes | 924 | 915 | 9 | ||||||||||||||
| Income Taxes | 184 | 201 | (17) | ||||||||||||||
| Income from Continuing Operations After Income Taxes | 740 | 714 | 26 | ||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) (Note 9) | — | 42 | (42) | ||||||||||||||
| Net Income (Loss) | $ | 740 | $ | 756 | $ | (16) | |||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating Revenues | $ | 7,447 | $ | 7,517 | $ | 7,669 | $ | (70 | ) | $ | (152 | ) | |||||||
| Operating Expenses | |||||||||||||||||||
| Operation | |||||||||||||||||||
| Fuel | 759 | 791 | 863 | (32 | ) | (72 | ) | ||||||||||||
| Energy purchases | 685 | 706 | 855 | (21 | ) | (149 | ) | ||||||||||||
| Other operation and maintenance | 1,635 | 1,745 | 1,938 | (110 | ) | (193 | ) | ||||||||||||
| Depreciation | 1,008 | 926 | 883 | 82 | 43 | ||||||||||||||
| Taxes, other than income | 292 | 301 | 299 | (9 | ) | 2 | |||||||||||||
| Total Operating Expenses | 4,379 | 4,469 | 4,838 | (90 | ) | (369 | ) | ||||||||||||
| Other Income (Expense) - net | (255 | ) | 390 | 108 | (645 | ) | 282 | ||||||||||||
| Interest Expense | 901 | 888 | 871 | 13 | 17 | ||||||||||||||
| Income Taxes | 784 | 648 | 465 | 136 | 183 | ||||||||||||||
| Income from Continuing Operations After Income Taxes | 1,128 | 1,902 | 1,603 | (774 | ) | 299 | |||||||||||||
| Loss from Discontinued Operations (net of income taxes) | — | — | (921 | ) | — | 921 | |||||||||||||
| Net Income | $ | 1,128 | $ | 1,902 | $ | 682 | $ | (774 | ) | $ | 1,220 | ||||||||
Operating Revenues
The increase (decrease) in operating revenues was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Domestic: | |||||||
| PPL Electric Distribution price (a) | $ | 53 | $ | 126 | |||
| PPL Electric Distribution volume | (21 | ) | (9 | ) | |||
| PPL Electric PLR Revenue (b) | (16 | ) | (135 | ) | |||
| PPL Electric Transmission Formula Rate | 34 | 59 | |||||
| LKE Base rates | 58 | 68 | |||||
| LKE Volumes (c) | (73 | ) | 1 | ||||
| LKE Fuel and other energy prices (d) | 10 | (81 | ) | ||||
| LKE ECR | 10 | 39 | |||||
| Other | (9 | ) | (17 | ) | |||
| Total Domestic | 46 | 51 | |||||
| U.K.: | |||||||
| Price | 60 | 98 | |||||
| Volume | (30 | ) | (36 | ) | |||
| Foreign currency exchange rates | (154 | ) | (255 | ) | |||
| Other | 8 | (10 | ) | ||||
| Total U.K. | (116 | ) | (203 | ) | |||
| Total | $ | (70 | ) | $ | (152 | ) | |
| 2023 vs. 2022 | |||||
| PPL Electric distribution price (a) | |||||
| $ | 58 | |||
| PPL Electric distribution volume (b) | ||||
| (68) | ||||
| PPL Electric PLR (c) | ||||
| (61) | |||||
| PPL Electric transmission formula rate (d) | |||||
| LG&E volumes (b) | (37) | ||||
| LG&E fuel and other energy purchases | (157) | ||||
| LG&E economic relief billing credit, net of amortization of $0 | 12 | ||||
| KU volumes (b) | (60) | ||||
| KU fuel and other energy purchases (e) | (132) | ||||
| KU economic relief billing credit, net of amortization of $0 | 5 | ||||
| Acquisition of RIE (f) | 796 | ||||
| RIE energy purchases and other recoveries | (63) | ||||
| RIE capital investment | 23 | ||||
| RIE customer bill credits (g) | 50 | ||||
| Other | (7) | ||||
| Total | $ | 410 | |||
(a)The increase was primarily due to reconcilable cost recovery mechanisms approved by the PAPUC.
(b) The decreases were primarily due to weather, along with other lower usage in 2023 at PPL Electric.
(c) The decrease was primarily due to the result of fewer PLR customers, lower customer volumes due to weather and other lower usage, partially offset by higher energy prices.
(d) The increase was primarily due to returns on additional transmission capital investments and recovery of related depreciation expense, partially offset by a lower PPL zonal peak load billing factor in the first quarter of 2023.
(e) The decrease was primarily due to lower recoveries of fuel and energy purchases due to lower commodity costs and volumes.
(f) The increase wasprimarily due to the results for 2023 including a full year of RIE operations compared to 2022, which includes only operations beginning on the acquisition date of May 25, 2022.
(g) See Note 9 to the Financial Statements for additional information.
34
Fuel
Fuel expense decreased $32$198 million in 20172023 compared with 20162022, primarily due to a decrease in fuel usage driven by mildercommodity costs of $46 million at LG&E and $89 million at KU and a decrease in volumes due to weather of $15 million at LG&E and $50 million at KU.
Energy Purchases
The increase (decrease) in 2017.energy purchases was due to:
| 2023 vs. 2022 | |||||
| PPL Electric PLR volumes | $ | (169) | |||
| PPL Electric PLR prices | 92 | ||||
| PPL Electric alternative energy credits volumes | (12) | ||||
| PPL Electric alternative energy credits prices | 29 | ||||
| LG&E commodity costs | (52) | ||||
| LG&E volumes (a) | (24) | ||||
| RIE commodity costs | (62) | ||||
| Acquisition of RIE (b) | 354 | ||||
| Other | (1) | ||||
| Total | $ | 155 | |||
(a)The decrease was primarily due to a decrease in market prices for coal and natural gas.weather.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Domestic: | |||||||
| LKE plant operations and maintenance (a) | $ | (2 | ) | $ | (19 | ) | |
| LKE pension expense | 1 | (12 | ) | ||||
| PPL Electric payroll-related costs | (12 | ) | (26 | ) | |||
| PPL Electric Act 129 | 9 | (15 | ) | ||||
| PPL Electric contractor related expenses | (4 | ) | 7 | ||||
| PPL Electric vegetation management | (17 | ) | 4 | ||||
| PPL Electric universal service programs | (3 | ) | 3 | ||||
| Storm costs | 4 | 6 | |||||
| Bad debts | (17 | ) | (5 | ) | |||
| Stock compensation expense | 5 | (6 | ) | ||||
| Third-party costs related to the spinoff of PPL Energy Supply (Note 8) | — | (13 | ) | ||||
| Separation benefits related to the spinoff of PPL Energy Supply (Note 8) | — | (8 | ) | ||||
| Corporate costs previously included in discontinued operations | — | 8 | |||||
| Other | (1 | ) | 18 | ||||
| U.K.: | |||||||
| Pension expense (b) | (67 | ) | (86 | ) | |||
| Foreign currency exchange rates | (15 | ) | (33 | ) | |||
| Third-party engineering | 6 | (8 | ) | ||||
| Other | 3 | (8 | ) | ||||
| Total | $ | (110 | ) | $ | (193 | ) | |
| 2023 vs. 2022 | |||||
| LG&E plant operations and maintenance expenses | (13) | ||||
| LG&E generation outage expenses | (12) | ||||
| LG&E gas maintenance and | (11) | ||||
| KU plant operations and maintenance | (18) | ||||
| KU generation outage expenses | (15) | ||||
| KU vegetation management expenses | (19) | ||||
| Acquisition of RIE (a) | 217 | ||||
| Sale of Safari Holdings (b) | (54) | ||||
| Transition costs associated with RIE | 81 | ||||
| Transaction costs associated with RIE | (18) | ||||
| Commitments made during RIE acquisition process (b) | (43) | ||||
| Other | (31) | ||||
| Total | $ | 64 | |||
(a)The increase wasprimarily due to the results for 2023 including a full year of RIE operations compared to 2022, which includes only operations beginning on the acquisition date of May 25, 2022.
(b)See Note 9 to the Financial Statements for additional information.
35
Depreciation
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Additions to PP&E, net | $ | 93 | $ | 76 | |||
| Foreign currency exchange rates | (16 | ) | (27 | ) | |||
| Depreciation rates (a) | 15 | — | |||||
| Other | (10 | ) | (6 | ) | |||
| Total | $ | 82 | $ | 43 | |||
Taxes, Other Than Income
The increase (decrease) in taxes, other than income was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| State gross receipts tax (a) | $ | 3 | $ | 11 | |||
| Domestic property tax expense | 4 | 4 | |||||
| Domestic capital stock tax | (6 | ) | — | ||||
| Foreign currency exchange rates | (8 | ) | (15 | ) | |||
| Other | (2 | ) | 2 | ||||
| Total | $ | (9 | ) | $ | 2 | ||
| 2023 vs. 2022 | ||||||
| $ | 20 | |||||
| Property tax expense (a) | 42 | |||||
| Other | (2) | |||||
| Total | $ | 60 | ||||
(a)The increases wereprimarily due to the results for 2023 including a full year of RIE operations compared to 2022, which includes only operations beginning on the acquisition date of May 25, 2022.
Other Income (Expense) - net
| 2023 vs. 2022 | |||||
| Defined benefit plans - non-service credits (Note 11) | $ | (7) | |||
| Interest income | 28 | ||||
| AFUDC - equity component | 8 | ||||
| Talen litigation (a) | (125) | ||||
| Other | 2 | ||||
| Total | $ | (94) | |||
(a)See "Legal Matters - Talen Litigation" in 2017 compared with 2016 and increased $282 million in 2016 compared with 2015 primarily dueNote 13 to changes in realized and unrealized gains (losses) on foreign currency contracts to economically hedge GBP denominated earnings from WPD.the Financial Statements for additional information.
Interest Expense
The increase (decrease) in interest expense was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Long-term debt interest expense (a) | $ | 34 | $ | 63 | |||
| Short-term debt interest | 7 | 2 | |||||
| Hedging activities and ineffectiveness | 1 | (4 | ) | ||||
| Foreign currency exchange rates | (26 | ) | (43 | ) | |||
| Other | (3 | ) | (1 | ) | |||
| Total | $ | 13 | $ | 17 | |||
| 2023 vs. 2022 | |||||
| Long-term debt (a) | 144 | ||||
| Short-term debt | 6 | ||||
| Other | 3 | ||||
| Total | $ | 153 | |||
(a) The increase was primarily due to debt issuancesincreased borrowings at WPD in November 2015, LG&E, and KU, in September 2015PPL Electric, and PPL Capital Funding, in May 2016 as well asalong with higher interest rates on bonds refinanced in September 2015 at LG&E, KU and KU.PPL Capital Funding. See Note 8 to the Financial Statements for additional information. The increase was also due to the results for 2023 including a full year of RIE operations compared to 2022, which includes only operations beginning on the acquisition date of May 25, 2022.
Income Taxes
The increase (decrease) in income taxes was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Change in pre-tax income at current period tax rates | $ | (223 | ) | $ | 184 | ||
| Valuation allowance adjustments (a) | 20 | (8 | ) | ||||
| Federal and state tax reserve adjustments (b) | — | 22 | |||||
| Foreign income tax return adjustments | (10 | ) | 2 | ||||
| U.S. income tax on foreign earnings net of foreign tax credit (c) | 89 | (50 | ) | ||||
| Impact of U.K. Finance Acts (d) | 33 | 42 | |||||
| Deferred tax impact of U.S. tax reform (e) | 220 | — | |||||
| Stock-based compensation (f) | 7 | (10 | ) | ||||
| Other | — | 1 | |||||
| Total | $ | 136 | $ | 183 | |||
| 2023 vs. 2022 | |||||
| (8) | |||||
| Income tax credits | (19) | ||||
| Amortization of | 6 | ||||
| Other | 4 | ||||
| Total | $ | (17) | |||
36
(a) In addition to credits internally generated, in 2023, PPL purchased approximately $300 million of renewable tax credits, as allowed by the IRA. PPL recorded deferred incomea current tax expense of $16 millionbenefit and $13 million for valuation allowances primarily related to increased Pennsylvania net operating loss carryforwards expected to be unutilized.
See Note 56 to the Financial Statements for additional information on income taxes.
Segment Earnings
PPL's Net Income (Loss) by reportable segments was as follows:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Kentucky Regulated (a) | $ | 552 | $ | 549 | $ | 3 | |||||||||||
| Pennsylvania Regulated | 519 | 525 | (6) | ||||||||||||||
| Rhode Island Regulated | 96 | (44) | 140 | ||||||||||||||
| Corporate and Other (a)(b) | (427) | (316) | (111) | ||||||||||||||
| Discontinued Operations (c) | — | 42 | (42) | ||||||||||||||
| Net Income (Loss) | $ | 740 | $ | 756 | $ | (16) | |||||||||||
(a)The financing activity of LKE is presented in Corporate and Other beginning on January 1, 2023. Prior periods have been adjusted to reflect this change.
(b)Primarily represents financing and certain other costs incurred at the corporate level that have not been allocated or assigned to the segments, which are presented to reconcile segment information to PPL's consolidated results.
(c)See Note 9 to the Financial Statements for additional information.
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| U.K. Regulated | $ | 652 | $ | 1,246 | $ | 1,121 | $ | (594 | ) | $ | 125 | ||||||||
| Kentucky Regulated | 286 | 398 | 326 | (112 | ) | 72 | |||||||||||||
| Pennsylvania Regulated | 359 | 338 | 252 | 21 | 86 | ||||||||||||||
| Corporate and Other (a) | (169 | ) | (80 | ) | (96 | ) | (89 | ) | 16 | ||||||||||
| Discontinued Operations (b) | — | — | (921 | ) | — | 921 | |||||||||||||
| Net Income | $ | 1,128 | $ | 1,902 | $ | 682 | $ | (774 | ) | $ | 1,220 | ||||||||
Earnings from Ongoing Operations
Management utilizes "Earnings from Ongoing Operations" as a non-GAAP financial measure that should not be considered as an alternative to net income, an indicator of operating performance determined in accordance with GAAP. PPL believes that Earnings from Ongoing Operations is useful and meaningful to investors because it provides management's view of PPL's earnings performance as another criterion in making investment decisions. In addition, PPL's management uses Earnings from Ongoing Operations in measuring achievement of certain corporate performance goals, including targets for certain executive incentive compensation. Other companies may use different measures to present financial performance.
Earnings from Ongoing Operations is adjusted for the impact of special items. Special items are presented in the financial tables on an after-tax basis with the related income taxes on special items separately disclosed. Income taxes on special items, when applicable, are calculated based on the effectivestatutory tax rate of the entity where the activity is recorded. Special items include:may include items such as:
• Gains and losses on sales of assets not in the ordinary course of business.
• Impairment charges.
• Significant workforce reduction and other restructuring effects.
• Acquisition and divestiture-related adjustments.
• Significant losses on early extinguishment of debt.
• Other charges or credits that are, in management's view, non-recurring or otherwise not reflective of the company's ongoing operations.
37
PPL's Earnings from Ongoing Operations by reportable segment were as follows:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Kentucky Regulated (a) | $ | 564 | $ | 557 | $ | 7 | |||||||||||
| Pennsylvania Regulated | 548 | 516 | 32 | ||||||||||||||
| Rhode Island Regulated | 152 | 65 | 87 | ||||||||||||||
| Corporate and Other (a) | (81) | (97) | 16 | ||||||||||||||
| Earnings from Ongoing Operations | $ | 1,183 | $ | 1,041 | $ | 142 | |||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| U.K. Regulated | $ | 885 | $ | 1,015 | $ | 968 | $ | (130 | ) | $ | 47 | ||||||||
| Kentucky Regulated | 395 | 398 | 343 | (3 | ) | 55 | |||||||||||||
| Pennsylvania Regulated | 349 | 338 | 252 | 11 | 86 | ||||||||||||||
| Corporate and Other | (76 | ) | (77 | ) | (74 | ) | 1 | (3 | ) | ||||||||||
| Earnings from Ongoing Operations | $ | 1,553 | $ | 1,674 | $ | 1,489 | $ | (121 | ) | $ | 185 | ||||||||
(a)The financing activity of LKE is presented in Corporate and Other beginning on January 1, 2023. Prior periods have been adjusted to reflect this change.
See "Reconciliation of Earnings from Ongoing Operations" below for a reconciliation of this non-GAAP financial measure to Net Income.
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating revenues | $ | 2,091 | $ | 2,207 | $ | 2,410 | $ | (116 | ) | $ | (203 | ) | |||||||
| Other operation and maintenance | 272 | 344 | 477 | (72 | ) | (133 | ) | ||||||||||||
| Depreciation | 230 | 233 | 242 | (3 | ) | (9 | ) | ||||||||||||
| Taxes, other than income | 127 | 135 | 148 | (8 | ) | (13 | ) | ||||||||||||
| Total operating expenses | 629 | 712 | 867 | (83 | ) | (155 | ) | ||||||||||||
| Other Income (Expense) - net | (261 | ) | 386 | 123 | (647 | ) | 263 | ||||||||||||
| Interest Expense | 397 | 402 | 417 | (5 | ) | (15 | ) | ||||||||||||
| Income Taxes | 152 | 233 | 128 | (81 | ) | 105 | |||||||||||||
| Net Income | 652 | 1,246 | 1,121 | (594 | ) | 125 | |||||||||||||
| Less: Special Items | (233 | ) | 231 | 153 | (464 | ) | 78 | ||||||||||||
| Earnings from Ongoing Operations | $ | 885 | $ | 1,015 | $ | 968 | $ | (130 | ) | $ | 47 | ||||||||
| Income Statement Line Item | 2017 | 2016 | 2015 | ||||||||||
| Foreign currency economic hedges, net of tax of $59, $4, ($30) (a) | Other Income (Expense) - net | $ | (111 | ) | $ | (8 | ) | $ | 55 | ||||
| U.S. tax reform (b) | Income Taxes | (122 | ) | — | — | ||||||||
| Settlement of foreign currency contracts, net of tax of $0, ($108), $0 (c) | Other Income (Expense) - net | — | 202 | — | |||||||||
| Change in U.K. tax rate (d) | Income Taxes | — | 37 | 78 | |||||||||
| WPD Midlands acquisition-related adjustment, net of tax of $0, $0, ($1) | Other operation and maintenance | — | — | 2 | |||||||||
| Settlement of certain income tax positions (e) | Income Taxes | — | — | 18 | |||||||||
| Total | $ | (233 | ) | $ | 231 | $ | 153 | ||||||
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| U.K. | |||||||
| Gross margins | $ | 30 | $ | 62 | |||
| Other operation and maintenance | 64 | 94 | |||||
| Depreciation | (14 | ) | (18 | ) | |||
| Interest expense | (21 | ) | (28 | ) | |||
| Other | (6 | ) | (3 | ) | |||
| Income taxes | 11 | (18 | ) | ||||
| U.S. | |||||||
| Interest expense and other | 1 | (2 | ) | ||||
| Income taxes | (10 | ) | 41 | ||||
| Foreign currency exchange, after-tax | (185 | ) | (81 | ) | |||
| Earnings from Ongoing Operations | (130 | ) | 47 | ||||
| Special items, after-tax | (464 | ) | 78 | ||||
| Net Income | $ | (594 | ) | $ | 125 | ||
Kentucky Regulated Segment
The Kentucky Regulated segment consists primarily of LKE'sLG&E's and KU's regulated electricity generation, transmission and distribution operations, of LG&E and KU, as well as LG&E's regulated distribution and sale of natural gas. In addition, certain acquisition-related financing costs are allocated to the Kentucky Regulated segment. The Kentucky Regulated segment represents 25% of PPL's Net Income for 2017 and 35% of PPL's assets at December 31, 2017.
Net Income and Earnings from Ongoing Operations include the following results.results:
| Change | ||||||||||||||||||||||||||||||||||||||||||
| Change | 2023 | 2022 (a) | 2023 vs. 2022 | |||||||||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | ||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 3,156 | $ | 3,141 | $ | 3,115 | $ | 15 | $ | 26 | ||||||||||||||||||||||||||||||||
| Operating Revenues | ||||||||||||||||||||||||||||||||||||||||||
| Fuel | 759 | 791 | 863 | (32 | ) | (72 | ) | |||||||||||||||||||||||||||||||||||
| Energy purchases | 178 | 171 | 184 | 7 | (13 | ) | ||||||||||||||||||||||||||||||||||||
| Other operation and maintenance | 806 | 804 | 837 | 2 | (33 | ) | ||||||||||||||||||||||||||||||||||||
| Depreciation | 439 | 404 | 382 | 35 | 22 | |||||||||||||||||||||||||||||||||||||
| Taxes, other than income | 65 | 62 | 57 | 3 | 5 | |||||||||||||||||||||||||||||||||||||
| Total operating expenses | 2,247 | 2,232 | 2,323 | 15 | (91 | ) | ||||||||||||||||||||||||||||||||||||
| Other Income (Expense) - net | (3 | ) | (9 | ) | (13 | ) | 6 | 4 | ||||||||||||||||||||||||||||||||||
| Interest Expense | 261 | 260 | 232 | 1 | 28 | |||||||||||||||||||||||||||||||||||||
| Income Taxes | 359 | 242 | 221 | 117 | 21 | |||||||||||||||||||||||||||||||||||||
| Net Income | ||||||||||||||||||||||||||||||||||||||||||
| Net Income | ||||||||||||||||||||||||||||||||||||||||||
| Net Income | 286 | 398 | 326 | (112 | ) | 72 | ||||||||||||||||||||||||||||||||||||
| Less: Special Items | (109 | ) | — | (17 | ) | (109 | ) | 17 | ||||||||||||||||||||||||||||||||||
| Earnings from Ongoing Operations | $ | 395 | $ | 398 | $ | 343 | $ | (3 | ) | $ | 55 | |||||||||||||||||||||||||||||||
(a)The financing activity of LKE is presented in Corporate and Other beginning on January 1, 2023. Prior periods have been adjusted to reflect this change.
The following after-tax gains (losses), which management considers special items, impacted the Kentucky Regulated segment's results and are excluded from Earnings from Ongoing Operations. Operations:
| Income Statement Line Item | 2023 | 2022 | |||||||||||||||
| Strategic corporate initiatives, net of tax of $0, $3 (a) | Other operation and maintenance | $ | (1) | $ | (8) | ||||||||||||
| FERC transmission credit refund, net of tax of $2 (b) | Other operation and maintenance | (6) | — | ||||||||||||||
| Unbilled revenue estimate adjustment, net of tax of $2 (c) | Operating Revenues | (5) | — | ||||||||||||||
| Total | $ | (12) | $ | (8) | |||||||||||||
| Income Statement Line Item | 2017 | 2016 | 2015 | ||||||||||
| U.S. tax reform (a) | Income Taxes | $ | (112 | ) | $ | — | $ | — | |||||
| Adjustment to investment, net of tax of $0, $0, $0 (b) | Other Income (Expense) - net | (1 | ) | — | — | ||||||||
| Settlement of indemnification agreement, net of tax of ($2), $0, $0 (c) | Other Income (Expense) - net | 4 | — | — | |||||||||
| Certain income tax valuation allowances (d) | Income Taxes | — | — | (12 | ) | ||||||||
| LKE acquisition - related adjustment, net of tax of $0, $0, $0 (e) | Other Income (Expense) - net | �� | — | (5 | ) | ||||||||
| Total | $ | (109 | ) | $ | — | $ | (17 | ) | |||||
(a)Costs incurred related to PPL's corporate centralization efforts.
(b)Prior period impact related to a FERC refund order. See Note 7 to the Financial Statements for additional information.
The changes in the components of the Kentucky Regulated segment's results between these periods were due to the factors set forth below, which reflect amounts classified as Kentucky Gross Margins andexclude the items that management considers special on separate linesspecial.
38
| 2023 vs. 2022 | |||||
| Operating Revenues | $ | (352) | |||
| Fuel | 198 | ||||
| Energy purchases | 81 | ||||
| Other operation and maintenance | 131 | ||||
| Depreciation | (11) | ||||
| Taxes, other than income | (1) | ||||
| Other Income (Expense) - net | — | ||||
| Interest Expense | (30) | ||||
| Income Taxes | (9) | ||||
| Earnings from Ongoing Operations | 7 | ||||
| Special Items, after-tax | (4) | ||||
| Net Income | $ | 3 | |||
•Lower operating revenues in 2023 compared with 2022, primarily due to a $290 million decrease in recoveries of fuel and notenergy purchases due to lower commodity costs and lower volumes and a $97 million decrease in their respective Statementsales volumes primarily due to weather, partially offset by a $17 million increase due to the expiration of Income line item. the economic relief billing credit in June 2022.
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Kentucky Gross Margins | $ | 29 | $ | 83 | |||
| Other operation and maintenance | — | 42 | |||||
| Depreciation | (27 | ) | (4 | ) | |||
| Taxes, other than income | (2 | ) | (4 | ) | |||
| Other Income (Expense) - net | 1 | (1 | ) | ||||
| Interest Expense | (1 | ) | (28 | ) | |||
| Income Taxes | (3 | ) | (33 | ) | |||
| Earnings from Ongoing Operations | (3 | ) | 55 | ||||
| Special Items, after-tax | (109 | ) | 17 | ||||
| Net Income | $ | (112 | ) | $ | 72 | ||
•Lower other operation and maintenance expense in 20162023 compared with 20152022, primarily due to a $29$31 million reduction of costs as a result of coal units retireddecrease in 2015 at the Cane Run and Green River plants, partially offset by $5 million of additional costs for Cane Run Unit 7 plant operations and $12maintenance expenses, a $27 million of lower pension expense mainly due to higher discount ratesdecrease in generation outage expenses, a $21 million decrease in vegetation management expenses, an $11 million decrease in gas maintenance and deferred amortization of actuarial losses.losses expenses and other items that were not individually significant.
•Higher depreciationinterest expense in 20172023 compared with 20162022, primarily due to additions to PP&E, net of retirements, and higher depreciation rates effective July 1, 2017.
Pennsylvania Regulated Segment
The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric. In addition, certain costs are allocated to the Pennsylvania Regulated segment. The Pennsylvania Regulated segment represents 32% of PPL's Net Income for 2017 and 24% of PPL's assets at December 31, 2017.
Net Income and Earnings from Ongoing Operations include the following results.results:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Operating Revenues | $ | 3,008 | $ | 3,030 | $ | (22) | |||||||||||
| Energy purchases | 992 | 1,048 | (56) | ||||||||||||||
| Other operation and maintenance | 605 | 605 | — | ||||||||||||||
| Depreciation | 397 | 393 | 4 | ||||||||||||||
| Taxes, other than income | 143 | 149 | (6) | ||||||||||||||
| Total operating expenses | 2,137 | 2,195 | (58) | ||||||||||||||
| Other Income (Expense) - net | 39 | 35 | 4 | ||||||||||||||
| Interest Expense | 223 | 171 | 52 | ||||||||||||||
| Income Taxes | 168 | 174 | (6) | ||||||||||||||
| Net Income | 519 | 525 | (6) | ||||||||||||||
| Less: Special Items | (29) | 9 | (38) | ||||||||||||||
| Earnings from Ongoing Operations | $ | 548 | $ | 516 | $ | 32 | |||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating revenues | $ | 2,195 | $ | 2,156 | $ | 2,124 | $ | 39 | $ | 32 | |||||||||
| Energy purchases | |||||||||||||||||||
| External | 507 | 535 | 657 | (28 | ) | (122 | ) | ||||||||||||
| Intersegment | — | — | 14 | — | (14 | ) | |||||||||||||
| Other operation and maintenance | 571 | 601 | 607 | (30 | ) | (6 | ) | ||||||||||||
| Depreciation | 309 | 253 | 214 | 56 | 39 | ||||||||||||||
| Taxes, other than income | 107 | 105 | 94 | 2 | 11 | ||||||||||||||
| Total operating expenses | 1,494 | 1,494 | 1,586 | — | (92 | ) | |||||||||||||
| Other Income (Expense) - net | 16 | 17 | 8 | (1 | ) | 9 | |||||||||||||
| Interest Expense | 142 | 129 | 130 | 13 | (1 | ) | |||||||||||||
| Income Taxes | 216 | 212 | 164 | 4 | 48 | ||||||||||||||
| Net Income | 359 | 338 | 252 | 21 | 86 | ||||||||||||||
| Less: Special Items | 10 | — | — | 10 | — | ||||||||||||||
| Earnings from Ongoing Operations | $ | 349 | $ | 338 | $ | 252 | $ | 11 | $ | 86 | |||||||||
The following after-tax gain,gains (losses), which management considers a special item,items, impacted the Pennsylvania Regulated segment's results and isare excluded from Earnings from Ongoing Operations. Operations:
39
| Income Statement Line Item | Income Statement Line Item | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||
| PA tax rate change (a) | |||||||||||||||||||||||||||||||||||||||||
| PPL Electric billing issue, net of tax of $10 (b) | |||||||||||||||||||||||||||||||||||||||||
| PPL Electric billing issue, net of tax of $0 (b) | |||||||||||||||||||||||||||||||||||||||||
| Strategic corporate initiatives, net of tax of $1 (c) | |||||||||||||||||||||||||||||||||||||||||
| Other non-recurring charges, net of tax of $1 (d) | |||||||||||||||||||||||||||||||||||||||||
| Income Statement Line Item | 2017 | 2016 | 2015 | ||||||||||||||||||||||||||||||||||||||
| U.S. tax reform (a) | Income Taxes | $ | 10 | $ | — | $ | — | ||||||||||||||||||||||||||||||||||
| Total | $ | 10 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||
| Total | |||||||||||||||||||||||||||||||||||||||||
| Total | |||||||||||||||||||||||||||||||||||||||||
(a)Impact of Pennsylvania state tax reform. See Note 6 to the Financial Statements for additional information.
(b)Certain expenses related to billing issues. See Note 7 to the Financial Statements for additional information.
(c)Costs incurred related to PPL's corporate centralization efforts.
(d)Certain expenses associated with a litigation settlement.
The changes in the components of the Pennsylvania Regulated segment's results between these periods wereare due to the factors set forth below, which reflect amounts classified as Pennsylvania Gross Margins andexclude the itemitems that management considers special on separate linesspecial.
| 2023 vs. 2022 | |||||
| Operating Revenues | $ | (22) | |||
| Energy purchases | 56 | ||||
| Other operation and maintenance | 40 | ||||
| Depreciation | (4) | ||||
| Taxes, other than income | 6 | ||||
| Other Income (Expense) - net | 5 | ||||
| Interest Expense | (52) | ||||
| Income Taxes | 3 | ||||
| Earnings from Ongoing Operations | 32 | ||||
| Special Items, after-tax | (38) | ||||
| Net Income | $ | (6) | |||
•Lower operating revenues in 2023 compared to 2022, primarily due to $68 million of lower distribution volumes primarily related to weather and notother lower usage in their respective Statement2023, $61 million of Income line items.lower PLR, partially offset by $58 million of higher distribution prices and $51 million of transmission formula rate impacts.
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Pennsylvania Gross Margins | $ | 31 | $ | 177 | |||
| Other operation and maintenance | 42 | — | |||||
| Depreciation | (35 | ) | (39 | ) | |||
| Taxes, other than income | 1 | (14 | ) | ||||
| Other Income (Expense) - net | (1 | ) | 9 | ||||
| Interest Expense | (13 | ) | 1 | ||||
| Income Taxes | (14 | ) | (48 | ) | |||
| Earnings from Ongoing Operations | 11 | 86 | |||||
| Special Item, after-tax | 10 | — | |||||
| Net Income | $ | 21 | $ | 86 | |||
•Lower other operation and maintenance expense for 2017in 2023 compared with 2016to 2022, primarily due to $17 million of lower bad debt expense, $17 million of lower vegetation management expense andexpenses of $19 million, lower other operations expenses of $12 million and lower cancelled projects of lower payroll related$9 million.
•Higher interest expense in 2023 compared to 2022, primarily due to increased borrowings.
Rhode Island Regulated Segment
The Rhode Island Regulated segment consists primarily of the regulated electricity transmission and distribution operations and
regulated distribution and sale of natural gas conducted by RIE.
Net Income (Loss) and Earnings from Ongoing Operations include the following results:
40
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Operating Revenues | $ | 1,851 | $ | 1,038 | $ | 813 | |||||||||||
| Energy purchases | 658 | 365 | 293 | ||||||||||||||
| Other operation and maintenance | 705 | 531 | 174 | ||||||||||||||
| Depreciation | 156 | 92 | 64 | ||||||||||||||
| Taxes, other than income | 156 | 92 | 64 | ||||||||||||||
| Total operating expenses | 1,675 | 1,080 | 595 | ||||||||||||||
| Other Income (Expense) - net | 19 | 23 | (4) | ||||||||||||||
| Interest Expense | 83 | 39 | 44 | ||||||||||||||
| Income Taxes | 16 | (14) | 30 | ||||||||||||||
| Net Income (Loss) | 96 | (44) | 140 | ||||||||||||||
| Less: Special Items | (56) | (109) | 53 | ||||||||||||||
| Earnings from Ongoing Operations | $ | 152 | $ | 65 | $ | 87 | |||||||||||
The following after-tax gains (losses), which management considers special items, impacted the Rhode Island Regulated segment's results and are excluded from Earnings from Ongoing Operations:
| Income Statement Line Item | 2023 | 2022 | |||||||||||||||||||||||||||
| Acquisition integration, net of tax of $17, $18 (a) | Other operation and maintenance | $ | (65) | $ | (70) | ||||||||||||||||||||||||
| Acquisition integration, net of tax of $0 | Other Income (Expense) - net | — | 1 | ||||||||||||||||||||||||||
| Acquisition integration, net of tax of ($2), $10 (b) | Operating Revenues | 8 | (40) | ||||||||||||||||||||||||||
| Acquisition integration, net of tax of ($1) | Depreciation | 2 | — | ||||||||||||||||||||||||||
| Acquisition integration, net of tax of $0 | Interest Expense | (1) | — | ||||||||||||||||||||||||||
| Total Special Items | $ | (56) | $ | (109) | |||||||||||||||||||||||||
(a)Primarily includes certain TSA costs for IT systems that will not be part of PPL's ongoing operations. 2022 also includes costs for certain commitments made during the acquisition process.
(b)The 2023 amount relates to the prior period impact of a methodology change for Infrastructure, Safety, and Reliability revenues. The 2022 amount relates to certain commitments made during the acquisition process.
The changes in the components of the Rhode Island Regulated segment's results between these periods are due to the factors set forth below, which exclude the items that management considers special.
| 2023 vs. 2022 | |||||
| Operating Revenues | $ | 753 | |||
| Energy purchases | (293) | ||||
| Other operation and maintenance | (180) | ||||
| Depreciation | (67) | ||||
| Taxes, other than income | (64) | ||||
| Other Income (Expense) - net | (3) | ||||
| Interest Expense | (43) | ||||
| Income Taxes | (16) | ||||
| Earnings from Ongoing Operations | 87 | ||||
| Special Items, after-tax | 53 | ||||
| Net Income | $ | 140 | |||
•Higher operating revenues in 2023 compared with 2022, primarily due to $796 million resulting from the full year ended December 31, 2023 including a full year of RIE operations compared to the comparable period in 2022, which includes only operations beginning on the acquisition date of May 25, 2022, and a $23 million increase in capital investments, partially offset by a $63 million decrease in energy purchases and other recoveries.
•Higher energy purchases in 2023 compared with 2022, primarily due to $354 million resulting from the full year ended December 31, 2023 including a full year of RIE operations compared to the comparable period in 2022, which includes only operations beginning on the acquisition date of May 25, 2022, partially offset by a $62 million decrease in commodity costs.
41
•Higher other operation and maintenance expense in 2023 compared with 2022, primarily due to $186 million resulting from the full year ended December 31, 2023 including a full year of RIE operations compared to the comparable period in 2022, which includes only operations beginning on the acquisition date of May 25, 2022 and a $13 million increase in energy efficiency program expenses, partially offset by $19 million of higher corporate service costs allocated to PPL Electric.lower transmission costs.
•Higher taxes, other than income for 2016in 2023 compared with 20152022, primarily due to the settlementresults for the full year ended December 31, 2023 including a full year of a 2011 gross receipts tax audit resultingRIE operations compared to the comparable period in 2022, which includes only operations beginning on the reversalacquisition date of $17 million of previously recognized reserves in 2015.May 25, 2022.
•Higher interest expense for 2017in 2023 compared with 20162022, primarily due to $29 million resulting from the full year ended December 31, 2023 including a full year of RIE operations compared to the comparable period in 2022, which includes only operations beginning on the acquisition date of May 25, 2022, and $14 million due to increased borrowings and higher interest rates.
•Higher income taxes in 2023 compared to 2022 primarily due to the issuanceresults for the full year ended December 31, 2023 including a full year of $475 millionRIE operations compared to the comparable period in 2022, which includes only operations beginning on the acquisition date of 3.950% First Mortgage Bonds in May 2017.25, 2022.
Reconciliation of Earnings from Ongoing Operations
The following tables contain after-tax gains (losses), in total, which management considers special items, that are excluded from Earnings from Ongoing Operations, and a reconciliation to PPL's "Net Income" for the years ended December 31.
| 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| KY Regulated | PA Regulated | RI Regulated | Corporate and Other | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | $ | 552 | $ | 519 | $ | 96 | $ | (427) | $ | 740 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Talen litigation costs, net of tax of $26 (a) | — | — | — | (99) | (99) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Strategic corporate initiatives, net of tax of $0, $1, $3 (b) | (1) | (2) | — | (10) | (13) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Acquisition integration, net of tax of $14, $58 (c) | — | — | (56) | (218) | (274) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Sale of Safari Holdings, net of tax of $0 (d) | — | — | — | (4) | (4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric billing issue, net of tax of $10 (e) | — | (24) | — | — | (24) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| FERC transmission credit refund, net of tax of $2 (f) | (6) | — | — | — | (6) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Unbilled revenue estimate adjustment, net of tax of $2 (g) | (5) | — | — | — | (5) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other non-recurring charges, net of tax of $1, $0 (h) | — | (3) | — | (15) | (18) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Special Items | (12) | (29) | (56) | (346) | (443) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Earnings from Ongoing Operations | $ | 564 | $ | 548 | $ | 152 | $ | (81) | $ | 1,183 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2017 | |||||||||||||||||||
| U.K. Regulated | KY Regulated | PA Regulated | Corporate and Other | Total | |||||||||||||||
| Net Income | $ | 652 | $ | 286 | $ | 359 | $ | (169 | ) | $ | 1,128 | ||||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||
| Foreign currency economic hedges, net of tax of $59 | (111 | ) | — | — | — | (111 | ) | ||||||||||||
| Spinoff of the Supply segment, net of tax of ($1) | — | — | — | 4 | 4 | ||||||||||||||
| Other: | |||||||||||||||||||
| U.S. tax reform (a) | (122 | ) | (112 | ) | 10 | (97 | ) | (321 | ) | ||||||||||
| Adjustment to investment, net of tax of $0 | — | (1 | ) | — | — | (1 | ) | ||||||||||||
| Settlement of indemnification agreement, net of tax of ($2) | — | 4 | — | — | 4 | ||||||||||||||
| Total Special Items | (233 | ) | (109 | ) | 10 | (93 | ) | (425 | ) | ||||||||||
| Earnings from Ongoing Operations | $ | 885 | $ | 395 | $ | 349 | $ | (76 | ) | $ | 1,553 | ||||||||
| 2016 | |||||||||||||||||||
| U.K. Regulated | KY Regulated | PA Regulated | Corporate and Other | Total | |||||||||||||||
| Net Income | $ | 1,246 | $ | 398 | $ | 338 | $ | (80 | ) | $ | 1,902 | ||||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||
| Foreign currency economic hedges, net of tax of $4 | (8 | ) | — | — | — | (8 | ) | ||||||||||||
| Spinoff of the Supply segment, net of tax of $2 | — | — | — | (3 | ) | (3 | ) | ||||||||||||
| Other: | |||||||||||||||||||
| Settlement of foreign currency contracts, net of tax of ($108) | 202 | — | — | — | 202 | ||||||||||||||
| Change in U.K. tax rate | 37 | — | — | — | 37 | ||||||||||||||
| Total Special Items | 231 | — | — | (3 | ) | 228 | |||||||||||||
| Earnings from Ongoing Operations | $ | 1,015 | $ | 398 | $ | 338 | $ | (77 | ) | $ | 1,674 | ||||||||
| 2015 | |||||||||||||||||||||||
U.K. Regulated | KY Regulated | PA Regulated | Corporate and Other | Discontinued Operations | Total | ||||||||||||||||||
| Net Income | $ | 1,121 | $ | 326 | $ | 252 | $ | (96 | ) | $ | (921 | ) | $ | 682 | |||||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||||||
| Foreign currency economic hedges, net of tax of ($30) | 55 | — | — | — | — | 55 | |||||||||||||||||
| Spinoff of the Supply segment: | |||||||||||||||||||||||
| Discontinued operations, net of tax of $30 | — | — | — | — | (921 | ) | (921 | ) | |||||||||||||||
| Transition and transaction costs, net of tax of $6 | — | — | — | (12 | ) | — | (12 | ) | |||||||||||||||
| Employee transitional services, net of tax of $2 | — | — | — | (5 | ) | — | (5 | ) | |||||||||||||||
| Separation benefits, net of tax of $3 | — | — | — | (5 | ) | — | (5 | ) | |||||||||||||||
| Other | |||||||||||||||||||||||
| Change in U.K. tax rate | 78 | — | — | — | — | 78 | |||||||||||||||||
| Settlement of certain income tax positions | 18 | — | — | — | — | 18 | |||||||||||||||||
| WPD Midlands acquisition-related adjustment, net of tax of ($1) | 2 | — | — | — | — | 2 | |||||||||||||||||
| Certain income tax valuation allowances | — | (12 | ) | — | — | — | (12 | ) | |||||||||||||||
| LKE acquisition-related adjustment, net of tax of $0 | — | (5 | ) | — | — | — | (5 | ) | |||||||||||||||
| Total Special Items | 153 | (17 | ) | — | (22 | ) | (921 | ) | (807 | ) | |||||||||||||
| Earnings from Ongoing Operations | $ | 968 | $ | 343 | $ | 252 | $ | (74 | ) | $ | — | $ | 1,489 | ||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| U.K. Regulated | |||||||||||||||||||
| U.K. Gross Margins | $ | 1,952 | $ | 2,067 | $ | 2,243 | $ | (115 | ) | $ | (176 | ) | |||||||
| Impact of changes in foreign currency exchange rates | (145 | ) | (238 | ) | |||||||||||||||
| U.K. Gross Margins excluding impact of foreign currency exchange rates | $ | 30 | $ | 62 | |||||||||||||||
| Kentucky Regulated | |||||||||||||||||||
| Kentucky Gross Margins | |||||||||||||||||||
| LG&E | $ | 910 | $ | 887 | $ | 867 | $ | 23 | $ | 20 | |||||||||
| KU | 1,128 | 1,122 | 1,059 | 6 | 63 | ||||||||||||||
| Total Kentucky Gross Margins | $ | 2,038 | $ | 2,009 | $ | 1,926 | $ | 29 | $ | 83 | |||||||||
| Pennsylvania Regulated | |||||||||||||||||||
| Pennsylvania Gross Margins | |||||||||||||||||||
| Distribution | $ | 958 | $ | 960 | $ | 842 | $ | (2 | ) | $ | 118 | ||||||||
| Transmission | 487 | 454 | 395 | 33 | 59 | ||||||||||||||
| Total Pennsylvania Gross Margins | $ | 1,445 | $ | 1,414 | $ | 1,237 | $ | 31 | $ | 177 | |||||||||
| 2017 | |||||||||||||||||||
U.K. Gross Margins | Kentucky Gross Margins | PA Gross Margins | Other (a) | Operating Income (b) | |||||||||||||||
| Operating Revenues | $ | 2,050 | (c) | $ | 3,156 | $ | 2,195 | $ | 46 | $ | 7,447 | ||||||||
| Operating Expenses | |||||||||||||||||||
| Fuel | — | 759 | — | — | 759 | ||||||||||||||
| Energy purchases | — | 178 | 507 | — | 685 | ||||||||||||||
| Other operation and maintenance | 98 | 111 | 120 | 1,306 | 1,635 | ||||||||||||||
| Depreciation | — | 64 | 21 | 923 | 1,008 | ||||||||||||||
| Taxes, other than income | — | 6 | 102 | 184 | 292 | ||||||||||||||
| Total Operating Expenses | 98 | 1,118 | 750 | 2,413 | 4,379 | ||||||||||||||
| Total | $ | 1,952 | $ | 2,038 | $ | 1,445 | $ | (2,367 | ) | $ | 3,068 | ||||||||
| 2016 | |||||||||||||||||||
U.K. Gross Margins | Kentucky Gross Margins | PA Gross Margins | Other (a) | Operating Income (b) | |||||||||||||||
| Operating Revenues | $ | 2,165 | (c) | $ | 3,141 | $ | 2,156 | $ | 55 | $ | 7,517 | ||||||||
| Operating Expenses | |||||||||||||||||||
| Fuel | — | 791 | — | — | 791 | ||||||||||||||
| Energy purchases | — | 171 | 535 | — | 706 | ||||||||||||||
| Other operation and maintenance | 98 | 109 | 108 | 1,430 | 1,745 | ||||||||||||||
| Depreciation | — | 56 | — | 870 | 926 | ||||||||||||||
| Taxes, other than income | — | 5 | 99 | 197 | 301 | ||||||||||||||
| Total Operating Expenses | 98 | 1,132 | 742 | 2,497 | 4,469 | ||||||||||||||
| Total | $ | 2,067 | $ | 2,009 | $ | 1,414 | $ | (2,442 | ) | $ | 3,048 | ||||||||
| 2015 | |||||||||||||||||||
U.K. Gross Margins | Kentucky Gross Margins | PA Gross Margins | Other (a) | Operating Income (b) | |||||||||||||||
| Operating Revenues | $ | 2,364 | (c) | $ | 3,115 | $ | 2,124 | $ | 66 | $ | 7,669 | ||||||||
| Operating Expenses | |||||||||||||||||||
| Fuel | — | 863 | — | — | 863 | ||||||||||||||
| Energy purchases | — | 184 | 657 | 14 | 855 | ||||||||||||||
| Energy purchases from affiliate | — | — | 14 | (14 | ) | — | |||||||||||||
| Other operation and maintenance | 121 | 100 | 114 | 1,603 | 1,938 | ||||||||||||||
| Depreciation | — | 38 | — | 845 | 883 | ||||||||||||||
| Taxes, other than income | — | 4 | 102 | 193 | 299 | ||||||||||||||
| Total Operating Expenses | 121 | 1,189 | 887 | 2,641 | 4,838 | ||||||||||||||
| Total | $ | 2,243 | $ | 1,926 | $ | 1,237 | $ | (2,575 | ) | $ | 2,831 | ||||||||
(b)Represents costs primarily related to PPL's centralization efforts and other strategic efforts.
(c)Rhode Island Regulated primarily includes certain TSA costs for IT systems that will not be part of PPL's ongoing operations. Corporate and Other primarily includes integration and related costs associated with the acquisition of RIE.
(d)Primarily final closing and other related adjustments for the sale of Safari Holdings.
(e)Certain expenses related to billing issues. See Note 7 to the Financial Statements for additional information.
(f)Prior period impact related to a discussionFERC refund order. See Note 7 to the Financial Statements for additional information.
(g)Prior period impact of a methodology change in determining unbilled revenues.
(h)PA Regulated includes certain expenses related to a litigation settlement. Corporate and Other primarily includes certain expenses related to distributed energy investments.
42
| 2022 | |||||||||||||||||||||||||||||||||||||||||
| KY Regulated (g) | PA Regulated | RI Regulated | Corporate and Other (g) | Discontinued Operations (a) | Total | ||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | $ | 549 | $ | 525 | $ | (44) | $ | (316) | $ | 42 | $ | 756 | |||||||||||||||||||||||||||||
| Less: Special Items (expense) benefit: | |||||||||||||||||||||||||||||||||||||||||
| Income (loss) from Discontinued Operations (a) | — | — | — | — | 42 | 42 | |||||||||||||||||||||||||||||||||||
| Talen litigation costs, net of tax of $0 (b) | — | — | — | 1 | — | 1 | |||||||||||||||||||||||||||||||||||
| Strategic corporate initiatives, net of tax of $3, $4 (c) | (8) | — | — | (15) | — | (23) | |||||||||||||||||||||||||||||||||||
| Acquisition integration, net of tax of $28, $39 (d) | — | — | (109) | (148) | — | (257) | |||||||||||||||||||||||||||||||||||
| PA tax rate change (e) | — | 9 | — | (4) | — | 5 | |||||||||||||||||||||||||||||||||||
| Sale of Safari Holdings, net of tax of $16 (f) | — | — | — | (53) | — | (53) | |||||||||||||||||||||||||||||||||||
| Total Special Items | (8) | 9 | (109) | (219) | 42 | (285) | |||||||||||||||||||||||||||||||||||
| Earnings from Ongoing Operations | $ | 557 | $ | 516 | $ | 65 | $ | (97) | $ | — | $ | 1,041 | |||||||||||||||||||||||||||||
(a)See Note 9 to the risks, uncertaintiesFinancial Statements for additional information.
(b)PPL incurred legal expenses and factorsreceived insurance reimbursement related to litigation with its former affiliate, Talen Montana. See Note 13 to the Financial Statements for additional information.
(c)Costs incurred primarily in connection with corporate centralization efforts.
(d)Rhode Island Regulated includes costs incurred primarily related to certain TSA costs for IT systems that may impact future earnings.will not be part of PPL’s ongoing operations and costs for certain commitments made during the acquisition process. Corporate and Other primarily includes integration and related costs associated with the acquisition of RIE.
(e)Impact of Pennsylvania state tax reform. See Note 6 to the Financial Statements for additional information.
(g)The financing activity of LKE is presented in Corporate and Other beginning on January 1, 2023. Prior periods have been adjusted to reflect this change.
PPL Electric: Statement of Income Analysis Earnings and Margins
Net income for the years ended December 31 includes the following results.results:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Operating Revenues | $ | 3,008 | $ | 3,030 | $ | (22) | |||||||||||
| Operating Expenses | |||||||||||||||||
| Operation | |||||||||||||||||
| Energy purchases | 992 | 1,048 | (56) | ||||||||||||||
| Other operation and maintenance | 605 | 605 | — | ||||||||||||||
| Depreciation | 397 | 393 | 4 | ||||||||||||||
| Taxes, other than income | 143 | 149 | (6) | ||||||||||||||
| Total Operating Expenses | 2,137 | 2,195 | (58) | ||||||||||||||
| Other Income (Expense) - net | 39 | 30 | 9 | ||||||||||||||
| Interest Income from Affiliate | — | 5 | (5) | ||||||||||||||
| Interest Expense | 223 | 171 | 52 | ||||||||||||||
| Income Taxes | 168 | 174 | (6) | ||||||||||||||
| Net Income | $ | 519 | $ | 525 | $ | (6) | |||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating Revenues | $ | 2,195 | $ | 2,156 | $ | 2,124 | $ | 39 | $ | 32 | |||||||||
| Operating Expenses | |||||||||||||||||||
| Operation | |||||||||||||||||||
| Energy purchases | 507 | 535 | 657 | (28 | ) | (122 | ) | ||||||||||||
| Energy purchases from affiliate | — | — | 14 | — | (14 | ) | |||||||||||||
| Other operation and maintenance | 571 | 599 | 607 | (28 | ) | (8 | ) | ||||||||||||
| Depreciation | 309 | 253 | 214 | 56 | 39 | ||||||||||||||
| Taxes, other than income | 107 | 105 | 94 | 2 | 11 | ||||||||||||||
| Total Operating Expenses | 1,494 | 1,492 | 1,586 | 2 | (94 | ) | |||||||||||||
| Other Income (Expense) - net | 11 | 17 | 8 | (6 | ) | 9 | |||||||||||||
| Interest Income from Affiliate | 5 | — | — | 5 | — | ||||||||||||||
| Interest Expense | 142 | 129 | 130 | 13 | (1 | ) | |||||||||||||
| Income Taxes | 213 | 212 | 164 | 1 | 48 | ||||||||||||||
| Net Income | $ | 362 | $ | 340 | $ | 252 | $ | 22 | $ | 88 | |||||||||
Operating Revenues
The increase (decrease) in operating revenues was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Distribution Price (a) | $ | 53 | $ | 126 | |||
| Distribution volume | (21 | ) | (9 | ) | |||
| PLR (b) | (16 | ) | (135 | ) | |||
| Transmission Formula Rate | 34 | 59 | |||||
| Other | (11 | ) | (9 | ) | |||
| Total | $ | 39 | $ | 32 | |||
| 2023 vs. 2022 | |||||
| Distribution Price (a) | |||||
| $ | 58 | ||||
| Distribution volume (b) | |||||
| PLR (c) | (61) | ||||
| Transmission Formula Rate (d) | 51 | ||||
| Other | (2) | ||||
| Total | $ | (22) | |||
(a)The increase was primarily due to lower energy purchase prices as described below.
Energy Purchases
Energy purchases decreased $28 million in 2017 compared with 2016 and $122 million in 2016 compared with 2015 primarily due to lower PLR prices.reconcilable cost recovery mechanisms approved by the PAPUC.
Energy Purchases from Affiliate
Energy purchases from affiliate decreased $14 million in 2016 compared with 2015 as a result of the June 1, 2015 PPL Energy Supply spinoff.Other Operation and Maintenance
DepreciationDepreciation increased by $56 million in 2017 compared with 2016 primarily due to additional assets placed into service, related to the ongoing efforts to ensure the reliabilityweather and other lower usage in 2023.
Depreciation increased by $39 million in 2016 compared with 2015 primarily due to additional assets placed into service, related to the ongoing efforts to ensure the reliability of the delivery system and the replacement of aging infrastructure, net of retirements.Taxes, Other Than IncomeTaxes, other than income increased by $11 million in 2016 compared with 2015(c)The decrease was primarily due to the settlementresult of a 2011 gross receipts tax audit that resulted in the reversal of $17 million of previously recognized reserves in 2015.fewer PLR customers, lower customer volumes due to weather and other lower usage, partially offset by higher energy prices.
57
Interest Expense
Interest expense increased $13 million in 2017 compared with 2016,(d)The increase was primarily due to the May 2017 issuancereturns on additional transmission capital investments and recovery of $475 million of 3.950% First Mortgage Bonds due 2047.
Income TaxesThe increase (decrease) in income taxes was due to:
See Note 5 to the Financial Statements for additional information on income taxes.
Earnings
Excluding special items, earnings increased in 2017 compared with 2016, primarily due to lower operation and maintenance expense and higher transmission margins from additional capital investments, partially offset by a lower PPL zonal peak load billing factor lower distribution sales volumes due to unfavorable weather, higher depreciation expense, higher interest expense and higher income taxes.in the first quarter of 2023.
Earnings increasedEnergy Purchases
The table below quantifies the changes in the components of Net Income between these periods, which reflect amounts classified as Pennsylvania Gross Margins and an item that management considers special on separate lines within the table and not in their respective Statement of Income line items.
Margins"Pennsylvania Gross Margins" is a non-GAAP financial performance measure that management utilizes as an indicator of the performance of its business. See PPL's "Results of Operations - Margins" for information on why management believes this measure is useful and for explanations of the underlying drivers of the changes between periods.
58
The following tables contain the components from the Statements of Income that are included in this non-GAAP financial measure and a reconciliation to "Operating Income."
LKE: Statement of Income Analysis, Earnings and Margins
59
(b)The increase (decrease) in other operation and maintenancedecrease was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Act 129 | $ | 9 | $ | (15 | ) | ||
| Universal service programs | (3 | ) | 3 | ||||
| Contractor-related expenses | (4 | ) | 7 | ||||
| Vegetation management | (17 | ) | 4 | ||||
| Payroll-related costs | (12 | ) | (26 | ) | |||
| Corporate service costs | 19 | 8 | |||||
| Storm costs | 5 | 9 | |||||
| Bad debts | (17 | ) | (4 | ) | |||
| Environmental costs | — | (6 | ) | ||||
| Other | (8 | ) | 12 | ||||
| Total | $ | (28 | ) | $ | (8 | ) | |
43
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Change in pre-tax income at current period tax rates | $ | 10 | $ | 58 | |||
| Depreciation not normalized | — | (5 | ) | ||||
| Deferred tax impact of U.S. tax reform (a) | (13 | ) | — | ||||
| Stock-based compensation (b) | 4 | (6 | ) | ||||
| Other | — | 1 | |||||
| Total | $ | 1 | $ | 48 | |||
| 2017 | 2016 | 2015 | |||||||||
| Net Income | $ | 362 | $ | 340 | $ | 252 | |||||
| Special item, gain (loss), after-tax | 10 | — | — | ||||||||
Energy purchases decreased $56 million in 20162023 compared with 2015,2022, primarily due to higher base electricity rates for distribution effective January 1, 2016,lower PLR volumes of $169 million and higher transmission margins from additional capital investments,lower alternative energy credits volumes of $12 million, partially offset by higher depreciationPLR prices of $92 million and higher alternative energy credits prices of $29 million.
Interest Expense
Interest expense and the release of a gross receipts tax reserveincreased $52 million in 2015.2023 compared with 2022, primarily due to increased borrowings.
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Pennsylvania Gross Margins | $ | 31 | $ | 177 | |||
| Other operation and maintenance | 40 | 2 | |||||
| Depreciation | (35 | ) | (39 | ) | |||
| Taxes, other than income | 1 | (14 | ) | ||||
| Other Income (Expense) - net | (1 | ) | 9 | ||||
| Interest Expense | (13 | ) | 1 | ||||
| Income Taxes | (11 | ) | (48 | ) | |||
| Special Item, after-tax | 10 | — | |||||
| Net Income | $ | 22 | $ | 88 | |||
| 2017 | 2016 | ||||||||||||||||||||||
PA Gross Margins | Other (a) | Operating Income (b) | PA Gross Margins | Other (a) | Operating Income (b) | ||||||||||||||||||
| Operating Revenues | $ | 2,195 | $ | — | $ | 2,195 | $ | 2,156 | $ | — | $ | 2,156 | |||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Energy purchases | 507 | — | 507 | 535 | — | 535 | |||||||||||||||||
| Other operation and maintenance | 120 | 451 | 571 | 108 | 491 | 599 | |||||||||||||||||
| Depreciation | 21 | 288 | 309 | — | 253 | 253 | |||||||||||||||||
| Taxes, other than income | 102 | 5 | 107 | 99 | 6 | 105 | |||||||||||||||||
| Total Operating Expenses | 750 | 744 | 1,494 | 742 | 750 | 1,492 | |||||||||||||||||
| Total | $ | 1,445 | $ | (744 | ) | $ | 701 | $ | 1,414 | $ | (750 | ) | $ | 664 | |||||||||
| 2015 | |||||||||||
| PA Gross Margins | Other (a) | Operating Income (b) | |||||||||
| Operating Revenues | $ | 2,124 | $ | — | $ | 2,124 | |||||
| Operating Expenses | |||||||||||
| Energy purchases | 657 | — | 657 | ||||||||
| Energy purchases from affiliate | 14 | — | 14 | ||||||||
| Other operation and maintenance | 114 | 493 | 607 | ||||||||
| Depreciation | — | 214 | 214 | ||||||||
| Taxes, other than income | 102 | (8 | ) | 94 | |||||||
| Total Operating Expenses | 887 | 699 | 1,586 | ||||||||
| Total | $ | 1,237 | $ | (699 | ) | $ | 538 | ||||
LG&E: Statement of Income Analysis
Net income for the years ended December 31 includes the following results.results:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Operating Revenues | |||||||||||||||||
| Retail and wholesale | $ | 1,580 | $ | 1,762 | $ | (182) | |||||||||||
| Electric revenue from affiliate | 33 | 36 | (3) | ||||||||||||||
| Total Operating Revenues | 1,613 | 1,798 | (185) | ||||||||||||||
| Operating Expenses | |||||||||||||||||
| Operation | |||||||||||||||||
| Fuel | 286 | 346 | (60) | ||||||||||||||
| Energy purchases | 168 | 245 | (77) | ||||||||||||||
| Energy purchases from affiliates | 12 | 25 | (13) | ||||||||||||||
| Other operation and maintenance | 364 | 416 | (52) | ||||||||||||||
| Depreciation | 302 | 298 | 4 | ||||||||||||||
| Taxes, other than income | 48 | 48 | — | ||||||||||||||
| Total Operating Expenses | 1,180 | 1,378 | (198) | ||||||||||||||
| Other Income (Expense) - net | 3 | 4 | (1) | ||||||||||||||
| Interest Income from Affiliates | 1 | — | 1 | ||||||||||||||
| Interest Expense | 102 | 89 | 13 | ||||||||||||||
| Income Taxes | 69 | 63 | 6 | ||||||||||||||
| Net Income | $ | 266 | $ | 272 | $ | (6) | |||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating Revenues | $ | 3,156 | $ | 3,141 | $ | 3,115 | $ | 15 | $ | 26 | |||||||||
| Operating Expenses | |||||||||||||||||||
| Operation | |||||||||||||||||||
| Fuel | 759 | 791 | 863 | (32 | ) | (72 | ) | ||||||||||||
| Energy purchases | 178 | 171 | 184 | 7 | (13 | ) | |||||||||||||
| Other operation and maintenance | 806 | 804 | 837 | 2 | (33 | ) | |||||||||||||
| Depreciation | 439 | 404 | 382 | 35 | 22 | ||||||||||||||
| Taxes, other than income | 65 | 62 | 57 | 3 | 5 | ||||||||||||||
| Total Operating Expenses | 2,247 | 2,232 | 2,323 | 15 | (91 | ) | |||||||||||||
| Other Income (Expense) - net | (3 | ) | (9 | ) | (8 | ) | 6 | (1 | ) | ||||||||||
| Interest Expense | 197 | 197 | 178 | — | 19 | ||||||||||||||
| Interest Expense with Affiliate | 18 | 17 | 3 | 1 | 14 | ||||||||||||||
| Income Taxes | 375 | 257 | 239 | 118 | 18 | ||||||||||||||
| Net Income | $ | 316 | $ | 429 | $ | 364 | $ | (113 | ) | $ | 65 | ||||||||
Operating Revenues
The increase (decrease) in operating revenues was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Base rates | $ | 58 | $ | 68 | |||
| Volumes (a) | (73 | ) | 1 | ||||
| Fuel and other energy prices (b) | 10 | (81 | ) | ||||
| ECR | 10 | 39 | |||||
| Other | 10 | (1 | ) | ||||
| Total | $ | 15 | $ | 26 | |||
| 2023 vs. 2022 | |||||
| Fuel and other energy purchases (a) | |||||
| $ | (160) | ||||
| Volumes (b) | |||||
| Economic relief billing credit, net of | 12 | ||||
| Total | $ | (185) | |||
(a)The decrease was primarily due to lower recoveries of fuel and energy purchases due to lower commodity costs and volumes.
(b)The decrease was primarily due to weather.
Fuel
Fuel expense decreased $32$60 million in 20172023 compared with 20162022, primarily due to a $46 million decrease in fuel usage driven by milder weathercommodity costs and a $15 million decrease in 2017.volumes primarily due to weather.
44
Energy Purchases
Energy purchases decreased $72$77 million in 20162023 compared with 20152022, primarily due to a $52 million decrease in market prices for coalcommodity costs and natural gas.a $24 million decrease in volumes primarily due to weather.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Plant operations and maintenance (a) | $ | (2 | ) | $ | (19 | ) | |
| Pension expense | 1 | (12 | ) | ||||
| Timing and scope of scheduled generation maintenance outages | (1 | ) | (5 | ) | |||
| Storm costs | (1 | ) | (3 | ) | |||
| Bad debts | — | (1 | ) | ||||
| Energy efficiency programs | — | 5 | |||||
| Other | 5 | 2 | |||||
| Total | $ | 2 | $ | (33 | ) | ||
| 2023 vs. 2022 | ||||||||
| Plant operation and | $ | (13) | ||||||
| Transmission credits | 3 | |||||||
| Generation outage expenses | (12) | |||||||
| Vegetation management expenses | (2) | |||||||
| Gas maintenance and losses expenses | (11) | |||||||
| Bad debt expense | (3) | |||||||
| Other | (14) | |||||||
| Total | $ | (52) | ||||||
Interest Expense
Interest expense increased $35$13 million in 20172023 compared with 20162022, primarily due to a $19 million increase related to additions to PP&E, net of retirements, and a $15$6 million increase related to higher depreciation rates effective July 1, 2017.
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Change in pre-tax income at current period tax rates | $ | 2 | $ | 32 | |||
| Certain income tax valuation allowances | — | (12 | ) | ||||
| U.S. tax reform (a) | 112 | — | |||||
| Other | 4 | (2 | ) | ||||
| Total | $ | 118 | $ | 18 | |||
| 2017 | 2016 | 2015 | |||||||||
| Net Income | $ | 316 | $ | 429 | $ | 364 | |||||
| Special items, gains (losses), after-tax | (109 | ) | — | (12 | ) | ||||||
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Margins | $ | 29 | $ | 83 | |||
| Other operation and maintenance | — | 42 | |||||
| Depreciation | (27 | ) | (4 | ) | |||
| Taxes, Other than income | (2 | ) | (4 | ) | |||
| Other Income (Expense) - net | 1 | (1 | ) | ||||
| Interest Expense | (1 | ) | (33 | ) | |||
| Income Taxes | (4 | ) | (30 | ) | |||
| Special items, gains (losses), after-tax (a) | (109 | ) | 12 | ||||
| Net Income | $ | (113 | ) | $ | 65 | ||
| 2017 | 2016 | ||||||||||||||||||||||
| Margins | Other (a) | Operating Income (b) | Margins | Other (a) | Operating Income (b) | ||||||||||||||||||
| Operating Revenues | $ | 3,156 | $ | — | $ | 3,156 | $ | 3,141 | $ | — | $ | 3,141 | |||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Fuel | 759 | — | 759 | 791 | — | 791 | |||||||||||||||||
| Energy purchases | 178 | — | 178 | 171 | — | 171 | |||||||||||||||||
| Other operation and maintenance | 111 | 695 | 806 | 109 | 695 | 804 | |||||||||||||||||
| Depreciation | 64 | 375 | 439 | 56 | 348 | 404 | |||||||||||||||||
| Taxes, other than income | 6 | 59 | 65 | 5 | 57 | 62 | |||||||||||||||||
| Total Operating Expenses | 1,118 | 1,129 | 2,247 | 1,132 | 1,100 | 2,232 | |||||||||||||||||
| Total | $ | 2,038 | $ | (1,129 | ) | $ | 909 | $ | 2,009 | $ | (1,100 | ) | $ | 909 | |||||||||
| 2015 | |||||||||||
| Margins | Other (a) | Operating Income (b) | |||||||||
| Operating Revenues | $ | 3,115 | $ | — | $ | 3,115 | |||||
| Operating Expenses | |||||||||||
| Fuel | 863 | — | 863 | ||||||||
| Energy purchases | 184 | — | 184 | ||||||||
| Other operation and maintenance | 100 | 737 | 837 | ||||||||
| Depreciation | 38 | 344 | 382 | ||||||||
| Taxes, other than income | 4 | 53 | 57 | ||||||||
| Total Operating Expenses | 1,189 | 1,134 | 2,323 | ||||||||
| Total | $ | 1,926 | $ | (1,134 | ) | $ | 792 | ||||
KU: Statement of Income Analysis
Net income for the years ended December 31 includes the following results.results:
| Change | |||||||||||||||||
| 2023 | 2022 | 2023 vs. 2022 | |||||||||||||||
| Operating Revenues | |||||||||||||||||
| Retail and wholesale | $ | 1,872 | $ | 2,049 | $ | (177) | |||||||||||
| Electric revenue from affiliate | 12 | 25 | (13) | ||||||||||||||
| Total Operating Revenues | 1,884 | 2,074 | (190) | ||||||||||||||
| Operating Expenses | |||||||||||||||||
| Operation | |||||||||||||||||
| Fuel | 447 | 585 | (138) | ||||||||||||||
| Energy purchases | 24 | 28 | (4) | ||||||||||||||
| Energy purchases from affiliates | 33 | 36 | (3) | ||||||||||||||
| Other operation and maintenance | 427 | 487 | (60) | ||||||||||||||
| Depreciation | 392 | 386 | 6 | ||||||||||||||
| Taxes, other than income | 45 | 45 | — | ||||||||||||||
| Total Operating Expenses | 1,368 | 1,567 | (199) | ||||||||||||||
| Other Income (Expense) - net | 8 | 8 | — | ||||||||||||||
| Interest Expense | 134 | 117 | 17 | ||||||||||||||
| Interest Expense from Affiliate | 1 | — | 1 | ||||||||||||||
| Income Taxes | 77 | 76 | 1 | ||||||||||||||
| Net Income | $ | 312 | $ | 322 | $ | (10) | |||||||||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating Revenues | |||||||||||||||||||
| Retail and wholesale | $ | 1,422 | $ | 1,406 | $ | 1,407 | $ | 16 | $ | (1 | ) | ||||||||
| Electric revenue from affiliate | 31 | 24 | 37 | 7 | (13 | ) | |||||||||||||
| Total Operating Revenues | 1,453 | 1,430 | 1,444 | 23 | (14 | ) | |||||||||||||
| Operating Expenses | |||||||||||||||||||
| Operation | |||||||||||||||||||
| Fuel | 292 | 301 | 329 | (9 | ) | (28 | ) | ||||||||||||
| Energy purchases | 160 | 153 | 166 | 7 | (13 | ) | |||||||||||||
| Energy purchases from affiliates | 10 | 14 | 20 | (4 | ) | (6 | ) | ||||||||||||
| Other operation and maintenance | 355 | 355 | 377 | — | (22 | ) | |||||||||||||
| Depreciation | 183 | 170 | 162 | 13 | 8 | ||||||||||||||
| Taxes, other than income | 33 | 32 | 28 | 1 | 4 | ||||||||||||||
| Total Operating Expenses | 1,033 | 1,025 | 1,082 | 8 | (57 | ) | |||||||||||||
| Other Income (Expense) - net | (5 | ) | (5 | ) | (6 | ) | — | 1 | |||||||||||
| Interest Expense | 71 | 71 | 57 | — | 14 | ||||||||||||||
| Income Taxes | 131 | 126 | 114 | 5 | 12 | ||||||||||||||
| Net Income | $ | 213 | $ | 203 | $ | 185 | $ | 10 | $ | 18 | |||||||||
Operating Revenues
The increase (decrease) in operating revenues was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Base rates | $ | 32 | $ | 4 | |||
| Volumes (a) | (20 | ) | (8 | ) | |||
| Fuel and other energy prices (b) | — | (36 | ) | ||||
| ECR | 5 | 26 | |||||
| Other | 6 | — | |||||
| Total | $ | 23 | $ | (14 | ) | ||
45
| 2023 vs. 2022 | |||||
| Fuel and other energy purchases (a) | $ | (144) | |||
| Volumes (b) | (60) | ||||
| Economic relief billing credit, net of amortization $0 | 5 | ||||
| Other | 9 | ||||
| Total | $ | (190) | |||
(a)The decrease was primarily due to lower recoveries of fuel and energy purchases due to lower commodity costs and volumes.
(b)The decrease was primarily due to weather.
Fuel
Fuel expense decreased $28$138 million in 20162023 compared with 20152022, primarily due to a $24$89 million decrease in market prices for coalcommodity costs and natural gas.a $50 million decrease in volumes primarily due to weather.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Plant operations and maintenance (a) | $ | (1 | ) | $ | (21 | ) | |
| Pension expense | 1 | (6 | ) | ||||
| Timing and scope of scheduled generation maintenance outages | — | 3 | |||||
| Storm costs | (1 | ) | (2 | ) | |||
| Energy efficiency programs | — | 2 | |||||
| Other | 1 | 2 | |||||
| Total | $ | — | $ | (22 | ) | ||
| 2023 vs. 2022 | |||||
| (18) | |||||
| Transmission credits | 10 | ||||
| Generation outage expenses | (15) | ||||
| Vegetation management expenses | (19) | ||||
| Bad debt expense | (3) | ||||
| Other | (15) | ||||
| Total | $ | (60) | |||
Interest Expense
Interest expense increased $14$17 million in 20162023 compared with 2015 primarily due to the issuance of $300 million of incremental First Mortgage Bonds in September 2015 and higher interest rates on $250 million of First Mortgage Bonds refinanced by LG&E.
| 2017 | 2016 | 2015 | |||||||||
| Net Income | $ | 213 | $ | 203 | $ | 185 | |||||
| Special items, gains (losses), after-tax (a) | — | — | — | ||||||||
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Margins | $ | 23 | $ | 20 | |||
| Other operation and maintenance | 2 | 23 | |||||
| Depreciation | (10 | ) | 3 | ||||
| Taxes, other than income | — | (3 | ) | ||||
| Other Income (Expense) - net | — | 1 | |||||
| Interest Expense | — | (14 | ) | ||||
| Income Taxes | (5 | ) | (12 | ) | |||
| Net Income | $ | 10 | $ | 18 | |||
| 2017 | 2016 | ||||||||||||||||||||||
| Margins | Other (a) | Operating Income (b) | Margins | Other (a) | Operating Income (b) | ||||||||||||||||||
| Operating Revenues | $ | 1,453 | $ | — | $ | 1,453 | $ | 1,430 | $ | — | $ | 1,430 | |||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Fuel | 292 | — | 292 | 301 | — | 301 | |||||||||||||||||
| Energy purchases | 170 | — | 170 | 167 | — | 167 | |||||||||||||||||
| Other operation and maintenance | 45 | 310 | 355 | 43 | 312 | 355 | |||||||||||||||||
| Depreciation | 32 | 151 | 183 | 29 | 141 | 170 | |||||||||||||||||
| Taxes, other than income | 4 | 29 | 33 | 3 | 29 | 32 | |||||||||||||||||
| Total Operating Expenses | 543 | 490 | 1,033 | 543 | 482 | 1,025 | |||||||||||||||||
| Total | $ | 910 | $ | (490 | ) | $ | 420 | $ | 887 | $ | (482 | ) | $ | 405 | |||||||||
| 2015 | |||||||||||
| Margins | Other (a) | Operating Income (b) | |||||||||
| Operating Revenues | $ | 1,444 | $ | — | $ | 1,444 | |||||
| Operating Expenses | |||||||||||
| Fuel | 329 | — | 329 | ||||||||
| Energy purchases | 186 | — | 186 | ||||||||
| Other operation and maintenance | 42 | 335 | 377 | ||||||||
| Depreciation | 18 | 144 | 162 | ||||||||
| Taxes, other than income | 2 | 26 | 28 | ||||||||
| Total Operating Expenses | 577 | 505 | 1,082 | ||||||||
| Total | $ | 867 | $ | (505 | ) | $ | 362 | ||||
| Change | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 vs. 2016 | 2016 vs. 2015 | |||||||||||||||
| Operating Revenues | |||||||||||||||||||
| Retail and wholesale | $ | 1,734 | $ | 1,735 | $ | 1,708 | $ | (1 | ) | $ | 27 | ||||||||
| Electric revenue from affiliate | 10 | 14 | 20 | (4 | ) | (6 | ) | ||||||||||||
| Total Operating Revenues | 1,744 | 1,749 | 1,728 | (5 | ) | 21 | |||||||||||||
| Operating Expenses | |||||||||||||||||||
| Operation | |||||||||||||||||||
| Fuel | 467 | 490 | 534 | (23 | ) | (44 | ) | ||||||||||||
| Energy purchases | 18 | 18 | 18 | — | — | ||||||||||||||
| Energy purchases from affiliates | 31 | 24 | 37 | 7 | (13 | ) | |||||||||||||
| Other operation and maintenance | 424 | 424 | 435 | — | (11 | ) | |||||||||||||
| Depreciation | 255 | 234 | 220 | 21 | 14 | ||||||||||||||
| Taxes, other than income | 32 | 30 | 29 | 2 | 1 | ||||||||||||||
| Total Operating Expenses | 1,227 | 1,220 | 1,273 | 7 | (53 | ) | |||||||||||||
| Other Income (Expense) - net | (3 | ) | (5 | ) | 1 | 2 | (6 | ) | |||||||||||
| Interest Expense | 96 | 96 | 82 | — | 14 | ||||||||||||||
| Income Taxes | 159 | 163 | 140 | (4 | ) | 23 | |||||||||||||
| Net Income | $ | 259 | $ | 265 | $ | 234 | $ | (6 | ) | $ | 31 | ||||||||
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Base rates | $ | 26 | $ | 64 | |||
| Volumes (a) | (48 | ) | (8 | ) | |||
| Fuel and other energy prices (b) | 8 | (47 | ) | ||||
| ECR | 5 | 13 | |||||
| Other | 4 | (1 | ) | ||||
| Total | $ | (5 | ) | $ | 21 | ||
| 2017 | 2016 | 2015 | |||||||||
| Net Income | $ | 259 | $ | 265 | $ | 234 | |||||
| Special items, gains (losses), after tax | (1 | ) | — | — | |||||||
| 2017 vs. 2016 | 2016 vs. 2015 | ||||||
| Margins | $ | 6 | $ | 63 | |||
| Other operation and maintenance | — | 19 | |||||
| Depreciation | (16 | ) | (7 | ) | |||
| Taxes, Other than income | (2 | ) | (1 | ) | |||
| Other Income (Expense) - net | 3 | (6 | ) | ||||
| Interest Expense | — | (14 | ) | ||||
| Income Taxes | 4 | (23 | ) | ||||
| Special items, gains (losses), after-tax (a) | (1 | ) | — | ||||
| Net Income | $ | (6 | ) | $ | 31 | ||
| 2017 | 2016 | ||||||||||||||||||||||
| Margins | Other (a) | Operating Income (b) | Margins | Other (a) | Operating Income (b) | ||||||||||||||||||
| Operating Revenues | $ | 1,744 | $ | — | $ | 1,744 | $ | 1,749 | $ | — | $ | 1,749 | |||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Fuel | 467 | — | 467 | 490 | — | 490 | |||||||||||||||||
| Energy purchases | 49 | — | 49 | 42 | — | 42 | |||||||||||||||||
| Other operation and maintenance | 66 | 358 | 424 | 66 | 358 | 424 | |||||||||||||||||
| Depreciation | 32 | 223 | 255 | 27 | 207 | 234 | |||||||||||||||||
| Taxes, other than income | 2 | 30 | 32 | 2 | 28 | 30 | |||||||||||||||||
| Total Operating Expenses | 616 | 611 | 1,227 | 627 | 593 | 1,220 | |||||||||||||||||
| Total | $ | 1,128 | $ | (611 | ) | $ | 517 | $ | 1,122 | $ | (593 | ) | $ | 529 | |||||||||
| 2015 | |||||||||||
| Margins | Other (a) | Operating Income (b) | |||||||||
| Operating Revenues | $ | 1,728 | $ | — | $ | 1,728 | |||||
| Operating Expenses | |||||||||||
| Fuel | 534 | — | 534 | ||||||||
| Energy purchases | 55 | — | 55 | ||||||||
| Other operation and maintenance | 58 | 377 | 435 | ||||||||
| Depreciation | 20 | 200 | 220 | ||||||||
| Taxes, other than income | 2 | 27 | 29 | ||||||||
| Total Operating Expenses | 669 | 604 | 1,273 | ||||||||
| Total | $ | 1,059 | $ | (604 | ) | $ | 455 | ||||
Financial Condition
The remainder of this Item 7 in this Form 10-K is presented on a combined basis, providing information, as applicable, for all Registrants.
Liquidity and Capital Resources
(All Registrants)
The Registrants' cash flows from operations and access to cost effectivecost-effective bank and capital markets are subject to risks and uncertainties. See "Item 1A. Risk Factors" for a discussion of risks and uncertainties that could affect the Registrants' cash flows.
The Registrants had the following at:
46
| PPL | PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Short-term debt | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Short-term debt | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Short-term debt | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt due within one year | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes payable with affiliates | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL (a) | PPL Electric | LKE | LG&E | KU | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 485 | $ | 49 | $ | 30 | $ | 15 | $ | 15 | ||||||||||||||||||||||||||||||||||||||||||||||
| Short-term debt | 1,080 | — | 244 | 199 | 45 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt due within one year | 348 | — | 98 | 98 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes payable with affiliates | — | 225 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 341 | $ | 13 | $ | 13 | $ | 5 | $ | 7 | ||||||||||||||||||||||||||||||||||||||||||||||
| Short-term debt | 923 | 295 | 185 | 169 | 16 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt due within one year | 518 | 224 | 194 | 194 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes payable with affiliates | — | 163 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2015 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 836 | $ | 47 | $ | 30 | $ | 19 | $ | 11 | ||||||||||||||||||||||||||||||||||||||||||||||
| Short-term debt | 916 | — | 265 | 142 | 48 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt due within one year | 485 | — | 25 | 25 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Notes payables with affiliates | — | 54 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(PPL)
The Statements of Cash Flows separately report the cash flows of the discontinued operations. The "Operating Activities," "Investing Activities" and "Financing Activities" sections below include only the cash flows of continuing operations.
(All Registrants)
Net cash provided by (used in) operating, investing and financing activities for the years ended December 31 and the changes between periods were as follows. follows:
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||
| Operating activities | $ | 1,758 | $ | 912 | $ | 609 | $ | 647 | |||||||||||||||
| Investing activities | (2,383) | (958) | (378) | (566) | |||||||||||||||||||
| Financing activities | 650 | 72 | (280) | (64) | |||||||||||||||||||
| 2022 | |||||||||||||||||||||||
| Operating activities | $ | 1,730 | $ | 757 | $ | 543 | $ | 661 | |||||||||||||||
| Investing activities | (5,654) | (387) | (360) | (547) | |||||||||||||||||||
| Financing activities | 709 | (366) | (99) | (106) | |||||||||||||||||||
| 2023 vs. 2022 Change | |||||||||||||||||||||||
| Operating activities | $ | 28 | $ | 155 | $ | 66 | $ | (14) | |||||||||||||||
| Investing activities | 3,271 | (571) | (18) | (19) | |||||||||||||||||||
| Financing activities | (59) | 438 | (181) | 42 | |||||||||||||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2017 | |||||||||||||||||||
| Operating activities | $ | 2,461 | $ | 880 | $ | 1,099 | $ | 512 | $ | 634 | |||||||||
| Investing activities | (3,156 | ) | (1,252 | ) | (888 | ) | (458 | ) | (428 | ) | |||||||||
| Financing activities | 824 | 408 | (194 | ) | (44 | ) | (198 | ) | |||||||||||
| 2016 | |||||||||||||||||||
| Operating activities | $ | 2,890 | $ | 872 | $ | 1,027 | $ | 482 | $ | 606 | |||||||||
| Investing activities | (2,918 | ) | (1,130 | ) | (790 | ) | (439 | ) | (349 | ) | |||||||||
| Financing activities | (439 | ) | 224 | (254 | ) | (57 | ) | (261 | ) | ||||||||||
| 2015 | |||||||||||||||||||
| Operating activities | $ | 2,272 | $ | 602 | $ | 1,063 | $ | 554 | $ | 608 | |||||||||
| Investing activities | (3,439 | ) | (1,108 | ) | (1,203 | ) | (689 | ) | (512 | ) | |||||||||
| Financing activities | 482 | 339 | 149 | 144 | (96 | ) | |||||||||||||
| 2017 vs. 2016 Change | |||||||||||||||||||
| Operating activities | $ | (429 | ) | $ | 8 | $ | 72 | $ | 30 | $ | 28 | ||||||||
| Investing activities | (238 | ) | (122 | ) | (98 | ) | (19 | ) | (79 | ) | |||||||||
| Financing activities | 1,263 | 184 | 60 | 13 | 63 | ||||||||||||||
| 2016 vs. 2015 Change | |||||||||||||||||||
| Operating activities | $ | 618 | $ | 270 | $ | (36 | ) | $ | (72 | ) | $ | (2 | ) | ||||||
| Investing activities | 521 | (22 | ) | 413 | 250 | 163 | |||||||||||||
| Financing activities | (921 | ) | (115 | ) | (403 | ) | (201 | ) | (165 | ) | |||||||||
Operating Activities
The components of the change in cash provided by (used in) operating activities were as follows. follows:
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| 2023 vs. 2022 | |||||||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||||||
| Net income | $ | 26 | $ | (6) | $ | (6) | $ | (10) | |||||||||||||||
| Non-cash components | 81 | (54) | (6) | (10) | |||||||||||||||||||
| Working capital | 253 | 158 | 81 | 28 | |||||||||||||||||||
| Defined benefit plan funding | (1) | (5) | 3 | 1 | |||||||||||||||||||
| Other operating activities | (331) | 62 | (6) | (23) | |||||||||||||||||||
| Total | $ | 28 | $ | 155 | $ | 66 | $ | (14) | |||||||||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2017 vs. 2016 | |||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||
| Net income | $ | (774 | ) | $ | 22 | $ | (113 | ) | $ | 10 | $ | (6 | ) | ||||||
| Non-cash components | 363 | 100 | 31 | (8 | ) | 42 | |||||||||||||
| Working capital | 38 | (87 | ) | 93 | (33 | ) | (14 | ) | |||||||||||
| Defined benefit plan funding | (138 | ) | (24 | ) | 50 | 42 | (3 | ) | |||||||||||
| Other operating activities | 82 | (3 | ) | 11 | 19 | 9 | |||||||||||||
| Total | $ | (429 | ) | $ | 8 | $ | 72 | $ | 30 | $ | 28 | ||||||||
| 2016 vs. 2015 | |||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||
| Net income | $ | 299 | $ | 88 | $ | 65 | $ | 18 | $ | 31 | |||||||||
| Non-cash components | 195 | 40 | 66 | 20 | (20 | ) | |||||||||||||
| Working capital | 47 | 101 | (206 | ) | (100 | ) | (51 | ) | |||||||||||
| Defined benefit plan funding | 72 | 33 | (15 | ) | (20 | ) | 1 | ||||||||||||
| Other operating activities | 5 | 8 | 54 | 10 | 37 | ||||||||||||||
| Total | $ | 618 | $ | 270 | $ | (36 | ) | $ | (72 | ) | $ | (2 | ) | ||||||
47
(PPL)
PPL had a $429 million decrease in cash provided by operating activities from continuing operations in 20172023 increased $28 million compared with 2016.2022.
•Net income declined $774increased $26 million between periods and included an increase in net non-cash benefitscharges of $363$81 million. The increase in net non-cash benefitscharges was primarily due to an increase in unrealized losses on hedging activities,depreciation (primarily due to the acquisition of RIE) and an increase in deferred income taxes and investment tax credits (primarily due to the impact of the TCJA) and an increase in depreciation expense (primarily due to additional assets placed into service, net of retirements, and higher depreciation rates at LG&E and KU effective July 1, 2017, partially offset by the impact of foreign currency at WPD)book versus tax plant timing differences), partially offset by an increase in the U.K. net periodic defined benefit creditsplans income (primarily due to a decreasehigher expected return) and loss on sale of Safari Holdings in the U.K. pension plan discount rates used to calculate the interest cost component of the net periodic defined benefit costs (credits) and increase in expected returns).2022.
•The $38 million increase in cash from changes in working capital was primarily due a decrease in net regulatory assets and liabilities (due to timing of rate recovery mechanisms), a decrease in fuel, materials and supplies (primarily due to a decrease in fuel purchases due to lower generation driven by milder weather in 2017 compared to 2016) and a decrease in unbilled revenue (primarily due to lower growth in volumes in 2017 compared to 2016), partially offset by a decrease in accounts payable (due to timing of payments), a decrease in taxes payable (primarily due to the timing of payments) and an increase in accounts receivable.
•The $331 million decrease in net regulatory assets and liabilities (due to timing of rate recovery mechanisms) andcash provided by other operating activities was driven by a decrease in unbilled revenuenon-current liabilities (primarily due to lower growth in volumes in 2017 compared to 2016).
(PPL Retirement Plan.Electric)
PPL Electric had an $270 million increase inElectric's cash provided by operating activities in 20162023 increased $155 million compared with 2015.2022.
•Net income improved by $88decreased $6 million between the periods. Thisperiods and included an additional $40 milliona decrease in non-cash components of net$54 million. The decrease in non-cash benefitscomponents was primarily due to a $39 milliondecrease in deferred income taxes and investment tax credits (primarily related to a change in state tax rates) and an increase in depreciationdefined benefit plan income (primarily due to a higher expected return), partially offset by an increase in amortization expense (primarily due to the replacement of aging infrastructure and to ensure system reliability)an increase in IT projects placed into service).
•The $101$158 million increase in cash from changes in working capital was primarily due to an increasea decrease in accounts payableunbilled revenue (primarily due to timing of payments)weather), an increase in taxes payableregulatory liabilities (primarily due to timing of payments)prior years' refunds to customers related to the transmission formula rate return on equity reduction) and a decreasean increase in prepaymentsaccrued interest (primarily due to higher tax paymentsnew debt issuances in 2015)2023), partially offset by an increase in net regulatory assetsaccounts receivable and liabilities (due to timing of rate recovery mechanisms), an increasea decrease in unbilled revenuesaccounts payable (primarily due to higher volumes and favorable weather compared to December 2015) and an increase in accounts receivable.pricing).
(LG&E)
LG&E's cash provided by operating activities in 20172023 increased $66 million compared with 2016.2022.
•Net income declined by $113decreased $6 million between the periods and included an increasea decrease in non-cash components of $31 million of net$6 million. The decrease in non-cash chargescomponents was primarily due to a $35 million increase in depreciation expense and a $3 million increasedecrease in deferred income taxes and investment tax credits (primarily due to the impact of the TCJA, largely offset by book versus tax plant timing differences and reduced benefit from net operating losses.differences).
•Net income improved bydecreased $10 million between the periods and included a decrease in non-cash components of $8$10 million of netThe decrease in non-cash chargescomponents was primarily due to a $21 million decrease in deferred income taxes largelyand investment tax credits (primarily due to book versus tax plant timing differences, partially offset by a $13 million increase in depreciation expense.differences).
48
2022) and a decrease in net regulatory assets (primarily due to the timing of payments,rate recovery mechanisms), partially offset by a decrease in accounts receivable frompayable and accounts payable to affiliates (primarily due to lower intercompany settlements associated with energy sales and inventory and an increase in other current liabilities due to customer advances and the timing of payments.payments).
•The increase in cash from LG&E's other operating activities was driven primarily by lower payments for the settlement of interest rate swaps.
Investing Activities
(All Registrants)
The components of the change in cash provided by (used in) investing activities were as follows. follows:
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| 2023 vs. 2022 | |||||||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||||||
| Expenditures for PP&E | $ | (235) | $ | (70) | $ | (7) | $ | (25) | |||||||||||||||
| Proceeds from sale of Safari Holdings, net of cash divested | (146) | — | — | — | |||||||||||||||||||
| Acquisition of Narragansett Electric, net of cash acquired | 3,660 | — | — | — | |||||||||||||||||||
| Notes receivable from affiliate | — | (499) | — | — | |||||||||||||||||||
| Other investing activities | (8) | (2) | (11) | 6 | |||||||||||||||||||
| Total | $ | 3,271 | $ | (571) | $ | (18) | $ | (19) | |||||||||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2017 vs. 2016 | |||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||
| Expenditures for PP&E | $ | (213 | ) | $ | (119 | ) | $ | (101 | ) | $ | (19 | ) | $ | (82 | ) | ||||
| Investment activity, net | (2 | ) | — | — | — | — | |||||||||||||
| Other investing activities | (23 | ) | (3 | ) | 3 | — | 3 | ||||||||||||
| Total | $ | (238 | ) | $ | (122 | ) | $ | (98 | ) | $ | (19 | ) | $ | (79 | ) | ||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2016 vs. 2015 | |||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||
| Expenditures for PP&E | $ | 613 | $ | (28 | ) | $ | 419 | $ | 250 | $ | 169 | ||||||||
| Investment activity, net | (134 | ) | — | — | — | — | |||||||||||||
| Other investing activities | 42 | 6 | (6 | ) | — | (6 | ) | ||||||||||||
| Total | $ | 521 | $ | (22 | ) | $ | 413 | $ | 250 | $ | 163 | ||||||||
For PPL, the increase in 2017 compared with 2016, higherexpenditures for PP&E was due to a full year of project expenditures at RIE in 2023 and an increase in project expenditures at PPL Electric, LKE, LG&E and KU were partially offset by lower project expenditures at WPD.KU. The increase in project expenditures forat PPL Electric was primarily due to an increase in transmission capital spending related to the ongoing efforts to improve reliability and replace aging infrastructure, as well as the roll-out of the Act 129 Smart Meter program.projects. The increase in expenditures for LKE, LG&E andat KU was primarily due to increased spending for environmental water projects at LG&E’s Mill Creek plant, CCR projects at the Trimble County plant and increasedhigher spending on various transmission projects at KU,related to economic development in its service territory, storm restoration and Advanced Metering Infrastructure projects, partially offset by lower spending driven by completion of environmental air projects. The decrease in expenditures at WPD was primarily due to a decrease in foreign currency exchange rates partially offset by an increase in expenditures to enhance system reliability.
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 20182024 through 2022.2026.
For PPL Electric, the changes in "Notes receivable from affiliate" activity resulted from payments received on the short-term note between affiliates in 2022, issued to support general corporate purposes. See Note 14 to the Financial Statements for further discussion of intercompany borrowings.
Financing Activities
(All Registrants)
The components of the change in cash provided by (used in) financing activities were as follows. follows:
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| 2023 vs. 2022 | |||||||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||||||
| Long-term debt issuance/retirement, net | $ | 812 | $ | 89 | $ | (136) | $ | (154) | |||||||||||||||
| Dividends | 83 | 17 | 109 | 106 | |||||||||||||||||||
| Capital contributions/distributions, net | — | 126 | (184) | (92) | |||||||||||||||||||
| Changes in net short-term debt | (909) | 219 | (289) | (109) | |||||||||||||||||||
| Note payable with affiliate | — | — | 324 | 294 | |||||||||||||||||||
| Other financing activities | (45) | (13) | (5) | (3) | |||||||||||||||||||
| Total | $ | (59) | $ | 438 | $ | (181) | $ | 42 | |||||||||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2017 vs. 2016 | |||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||
| Debt issuance/retirement, net | $ | 935 | $ | 470 | $ | 115 | $ | 115 | $ | — | |||||||||
| Stock issuances/redemptions, net | 309 | — | — | — | — | ||||||||||||||
| Dividends | (42 | ) | (48 | ) | — | (64 | ) | 22 | |||||||||||
| Capital contributions/distributions, net | 355 | (147 | ) | (41 | ) | (20 | ) | ||||||||||||
| Changes in net short-term debt (a) | 86 | (590 | ) | 92 | 3 | 61 | |||||||||||||
| Other financing activities | (25 | ) | (3 | ) | — | — | — | ||||||||||||
| Total | $ | 1,263 | $ | 184 | $ | 60 | $ | 13 | $ | 63 | |||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2016 vs. 2015 | |||||||||||||||||||
| Change - Cash Provided (Used): | |||||||||||||||||||
| Debt issuance/retirement, net | $ | (824 | ) | $ | (248 | ) | $ | (175 | ) | $ | (325 | ) | $ | (250 | ) | ||||
| Debt issuance/retirement, affiliate | — | (400 | ) | — | — | ||||||||||||||
| Stock issuances/redemptions, net | (59 | ) | — | — | — | — | |||||||||||||
| Dividends | (26 | ) | (107 | ) | — | (9 | ) | (95 | ) | ||||||||||
| Capital contributions/distributions, net | (55 | ) | (161 | ) | (19 | ) | 20 | ||||||||||||
| Changes in net short-term debt (a) | (65 | ) | 295 | 326 | 149 | 156 | |||||||||||||
| Other financing activities | 53 | — | 7 | 3 | 4 | ||||||||||||||
| Total | $ | (921 | ) | $ | (115 | ) | $ | (403 | ) | $ | (201 | ) | $ | (165 | ) | ||||
(All Registrants)
See Note 8 to the Financial Statements in this Form 10-K for information on 2023 activity.
49
See "Long-term Debt and Equity Securities" below for additional information on current year activity. See "Forecasted Sources of Cash" for a discussion of the Registrants' plans to issue debt and equity securities, as well as a discussion of credit facility capacity available to the Registrants. Also see "Forecasted Uses of Cash" for a discussion of PPL's plans to pay dividends on common securities in the future, as well as the Registrants' maturities of long-term debt.
Long-term Debt and Equity Securities
Long-term debt and equity securities activity for 20172023 included:
| Debt | Stock | ||||||||||||||||||||||
| Issuances (a) | Retirements | Issuances (b) | Repurchases | ||||||||||||||||||||
| Cash Flow Impact: | |||||||||||||||||||||||
| PPL | $ | 3,252 | $ | 1,854 | $ | 5 | $ | — | |||||||||||||||
| PPL Electric | 1,329 | 1,240 | — | — | |||||||||||||||||||
| LG&E | 464 | 300 | — | — | |||||||||||||||||||
| KU | 459 | 313 | — | — | |||||||||||||||||||
| Debt | Net Stock | ||||||||||
| Issuances (a) | Retirements | Issuances | |||||||||
| Cash Flow Impact: | |||||||||||
| PPL | $ | 1,515 | $ | 168 | $ | 453 | |||||
| PPL Electric | 470 | — | |||||||||
| LKE | 160 | 70 | |||||||||
| LG&E | 160 | 70 | |||||||||
| KU | — | — | |||||||||
(a)Issuances are net of pricing discounts, where applicable, and exclude the impact of debt issuance costs. Includes debt issuances with affiliates.
(b)Includes issuances of common stock and treasury stock, which are included in "Other financing activities" on the Statements of Cash Flows.
See Note 78 to the Financial Statements for additional information about long-term debt.debt information.
Forecasted Sources of Cash
(All Registrants)
The Registrants expect to continue to have adequate liquidity available from operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances.issuances to meet their requirements with respect to their contractual obligations and anticipated capital expenditures. Additionally, subject to market conditions, the Registrants and their subsidiaries may access the capital markets, and PPL Electric, LG&E and KU anticipate receiving equity contributions from their parent or member in 2018.2024.
Credit Facilities
The Registrants maintain credit facilities to enhance liquidity, provide credit support and provide a backstop to commercial paper programs. Amounts borrowed under these credit facilities are reflected in "Short-term debt" on the Balance Sheets except for borrowings under LG&E's term loan agreement which are reflected in "Long-term debt" on the Balance Sheets. At December 31, 2017,2023, the total committed borrowing capacity under credit facilities and the borrowings under these facilities were:
External
| Committed Capacity | Borrowed | Letters of Credit and Commercial Paper Issued (d) | Unused Capacity | ||||||||||||||||||||
| PPL Capital Funding Credit Facilities (a) | $ | 1,350 | $ | — | $ | 390 | $ | 960 | |||||||||||||||
| PPL Electric Credit Facilities | 650 | — | 511 | 139 | |||||||||||||||||||
| LG&E Credit Facilities | 500 | — | — | 500 | |||||||||||||||||||
| KU Credit Facilities | 400 | — | 93 | 307 | |||||||||||||||||||
| Total Credit Facilities (b) (c) | $ | 2,900 | $ | — | $ | 994 | $ | 1,906 | |||||||||||||||
(a)Includes a $1.25 billion syndicated credit facility with a $250 million borrowing sublimit for RIE and a $1 billion sublimit for PPL Capital Funding at December 31, 2023. RIE’s borrowing sublimit is adjustable, at the borrowers’ option, from $0 to $600 million, with the remaining balance of the $1.25 billion available under the facility allocated to PPL Capital Funding. At December 31, 2023, PPL Capital Funding had $365 million of commercial paper outstanding and RIE had $25 million of commercial paper outstanding. On January 5, 2024, the borrowing sublimits under the facility were reallocated to $400 million at RIE and $850 million at PPL Capital Funding.
(b)The syndicated credit facilities and PPL Capital Funding's bilateral facility, each contain a financial covenant requiring debt to total capitalization not to exceed 70% for PPL Capital Funding, RIE, PPL Electric, LG&E and KU, as calculated in accordance with the facility, and other customary covenants.
50
| Committed Capacity | Borrowed | Letters of Credit and Commercial Paper Issued | Unused Capacity | ||||||||||||
| PPL Capital Funding Credit Facilities | $ | 1,400 | $ | — | $ | 248 | $ | 1,152 | |||||||
| PPL Electric Credit Facility | 650 | — | 1 | 649 | |||||||||||
| LKE Credit Facility | 75 | — | — | 75 | |||||||||||
| LG&E Credit Facilities | 700 | 100 | 199 | 401 | |||||||||||
| KU Credit Facilities | 598 | — | 243 | 355 | |||||||||||
| Total LKE Consolidated | 1,373 | 100 | 442 | 831 | |||||||||||
| Total U.S. Credit Facilities (a) (b) | $ | 3,423 | $ | 100 | $ | 691 | $ | 2,632 | |||||||
| Total U.K. Credit Facilities (b) (c) | £ | 1,055 | £ | 448 | £ | — | £ | 605 | |||||||
The commitments under the domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than the following percentages of the total committed capacity: PPL - 10%9%, PPL Electric 7%, LKE - 18%7%, LG&E - 33%7% and KU - 37%7%.
(c)Each company pays customary fees under its respective syndicated credit facility. Borrowings generally bear interest at applicable SOFR, plus an applicable margin.
In addition to the financial covenants noted in the table above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. The Registrants monitor compliance with the covenants on a regular basis. At December 31, 2017,2023, the Registrants were in compliance with these covenants. At this time, the Registrants believe that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 78 to the Financial Statements for further discussion of the Registrants' credit facilities.
Intercompany (LKE, (LG&E and KU)
| Committed Capacity | Borrowed | Commercial Paper Issued | Unused Capacity | ||||||||||||||||||||
| LG&E Money Pool (a) | $ | 750 | $ | — | $ | — | $ | 750 | |||||||||||||||
| KU Money Pool (a) | 650 | — | 93 | 557 | |||||||||||||||||||
(a)LG&E and KU)KU participate in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E, and LKE and/or LG&E make available to KU funds up to the difference between LG&E's and KU's FERC borrowing limit and LG&E's and KU's commercial paper capacity limit, at an interest rate based on the lower of a market index of commercial paper issues and two additional rate options based on the lower of a market index of commercial paper issues and two additional rate options based on SOFR.
Committed Capacity | Borrowed | Non-affiliate Used Capacity | Unused Capacity | ||||||||||||
| LKE Credit Facility | $ | 275 | $ | 225 | $ | — | $ | 50 | |||||||
| LG&E Money Pool (a) | 500 | — | 199 | 301 | |||||||||||
| KU Money Pool (a) | 500 | — | 45 | 455 | |||||||||||
See Note 14 to the Financial Statements for further discussion of intercompany credit facilities.
Commercial Paper (All Registrants)
| December 31, 2023 | |||||||||||||||||
| Capacity | Commercial Paper Issuances (b) | Unused Capacity | |||||||||||||||
| PPL Capital Funding (a) | $ | 1,350 | $ | 365 | $ | 985 | |||||||||||
| Rhode Island Energy (a) | 400 | 25 | 375 | ||||||||||||||
| PPL Electric | 650 | 510 | 140 | ||||||||||||||
| LG&E | 500 | — | 500 | ||||||||||||||
| KU | 400 | 93 | 307 | ||||||||||||||
| Total PPL | $ | 3,300 | $ | 993 | $ | 2,307 | |||||||||||
(a)Issuances under the PPL Capital Funding and RIE commercial paper programs are supported by the PPL Capital Funding syndicated credit facility, which has a total capacity of $1.25 billion, with a $250 million borrowing sublimit for RIE and a $1 billion sublimit for PPL Capital Funding at December 31, 2023. RIE’s borrowing sublimit is adjustable, at the borrowers’ option, from $0 to $600 million, with the remaining balance of the $1.25 billion available under the facility allocated to PPL Capital Funding. On January 5, 2024, the borrowing sublimits under the facility were reallocated to $400 million at RIE and $850 million at PPL Capital Funding.
(b)Commercial paper issued reflects the undiscounted face value of the issuance.
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| December 31, 2017 | |||||||||||
| Capacity | Commercial Paper Issuances | Unused Capacity | |||||||||
| PPL Capital Funding | $ | 1,000 | $ | 230 | $ | 770 | |||||
| PPL Electric | 650 | — | 650 | ||||||||
| LG&E | 350 | 199 | 151 | ||||||||
| KU | 350 | 45 | 305 | ||||||||
| Total LKE | 700 | 244 | 456 | ||||||||
| Total PPL | $ | 2,350 | $ | 474 | $ | 1,876 | |||||
Long-term Debt and Equity Securities
(PPL)
PPL and its subsidiaries are authorized to incur,issue, at the discretion of management and subject to market conditions, up to $3.2$3.5 billion of long-term indebtednessdebt securities, which includes the $650 million issued by PPL Electric in 2018,January 2024, the proceeds of which would be used to fund capital expenditures and for general corporate purposes. RIE is authorized to issue, at the discretion of management and subject to market conditions and regulatory approvals, up to $500 million of long-term debt securities, the proceeds of which would be used to repay short-term debt incurred to fund capital expenditures and for general corporate purposes.
(PPL Electric)
PPL Electric is authorized to issue, at the discretion of management and subject to market conditions and regulatory approvals, up to $1 billion of long-term debt securities, which includes the $650 million issued in January 2024, the proceeds of which would be used to fund capital expenditures and for general corporate purposes.
LG&E is authorized to issue, at the discretion of management and subject to market conditions and regulatory approvals, up to $3.5 billion of equity over three years.
Contributions from Parent/Member Parent (PPL Electric, LKE, LG&E and KU)
From time to time, LKE's member or the parents of PPL Electric, LG&E and KU make capital contributions to subsidiaries. The proceeds from these contributions are used to fund capital expenditures and for other general corporate purposes and, in the case of LKE, to make contributions to its subsidiaries.purposes.
Forecasted Uses of Cash
(All Registrants)
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, the Registrants currently expect to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock, distributions by LKE to its member, and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows the Registrants' current capital expenditure projections for the years 20182024 through 2022.2026. Expenditures for the domestic regulated utilities are expected to be recovered through rates, pending regulatory approval.
| Projected | ||||||||||||||||||||||||||||||||
| Total | 2024 (a) | 2025 | 2026 | |||||||||||||||||||||||||||||
| PPL | ||||||||||||||||||||||||||||||||
| Generating facilities | $ | 2,200 | $ | 625 | $ | 850 | $ | 725 | ||||||||||||||||||||||||
| Electric distribution facilities | 3,275 | 1,075 | 1,125 | 1,075 | ||||||||||||||||||||||||||||
| Gas distribution facilities | 1,050 | 300 | 375 | 375 | ||||||||||||||||||||||||||||
| Transmission facilities | 3,700 | 1,000 | 1,275 | 1,425 | ||||||||||||||||||||||||||||
| Other | 350 | 125 | 125 | 100 | ||||||||||||||||||||||||||||
| Total Capital Expenditures | $ | 10,575 | $ | 3,125 | $ | 3,750 | $ | 3,700 | ||||||||||||||||||||||||
| Projected | |||||||||||||||||||||||
| Total | 2018 (b) | 2019 | 2020 | 2021 | 2022 | ||||||||||||||||||
| PPL | |||||||||||||||||||||||
| Construction expenditures (a) | |||||||||||||||||||||||
| Generating facilities | $ | 892 | $ | 238 | $ | 253 | $ | 124 | $ | 204 | $ | 73 | |||||||||||
| Distribution facilities | 9,244 | 1,875 | 1,819 | 1,851 | 1,863 | 1,836 | |||||||||||||||||
| Transmission facilities | 3,771 | 902 | 854 | 883 | 628 | 504 | |||||||||||||||||
| Environmental | 828 | 429 | 191 | 91 | 62 | 55 | |||||||||||||||||
| Other | 685 | 127 | 201 | 193 | 117 | 47 | |||||||||||||||||
| Total Capital Expenditures | $ | 15,420 | $ | 3,571 | $ | 3,318 | $ | 3,142 | $ | 2,874 | $ | 2,515 | |||||||||||
PPL Electric (a) | |||||||||||||||||||||||
| Distribution facilities | $ | 2,077 | $ | 476 | $ | 404 | $ | 403 | $ | 396 | $ | 398 | |||||||||||
| Transmission facilities | 2,901 | 757 | 686 | 692 | 404 | 362 | |||||||||||||||||
| Total Capital Expenditures | $ | 4,978 | $ | 1,233 | $ | 1,090 | $ | 1,095 | $ | 800 | $ | 760 | |||||||||||
LKE | |||||||||||||||||||||||
| Generating facilities | $ | 892 | $ | 238 | $ | 253 | $ | 124 | $ | 204 | $ | 73 | |||||||||||
| Distribution facilities | 1,699 | 347 | 388 | 360 | 338 | 266 | |||||||||||||||||
| Transmission facilities | 870 | 144 | 169 | 190 | 225 | 142 | |||||||||||||||||
| Environmental | 828 | 429 | 191 | 91 | 62 | 55 | |||||||||||||||||
| Other | 663 | 119 | 196 | 189 | 114 | 45 | |||||||||||||||||
| Total Capital Expenditures | $ | 4,952 | $ | 1,277 | $ | 1,197 | $ | 954 | $ | 943 | $ | 581 | |||||||||||
LG&E | |||||||||||||||||||||||
| Generating facilities | $ | 408 | $ | 127 | $ | 108 | $ | 35 | $ | 94 | $ | 44 | |||||||||||
| Distribution facilities | 1,084 | 223 | 265 | 233 | 210 | 153 | |||||||||||||||||
| Transmission facilities | 161 | 27 | 36 | 36 | 40 | 22 | |||||||||||||||||
| Environmental | 335 | 176 | 83 | 38 | 22 | 16 | |||||||||||||||||
| Other | 331 | 58 | 97 | 94 | 58 | 24 | |||||||||||||||||
| Total Capital Expenditures | $ | 2,319 | $ | 611 | $ | 589 | $ | 436 | $ | 424 | $ | 259 | |||||||||||
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| Projected | ||||||||||||||||||||||||||||||||
| Total | 2024 (a) | 2025 | 2026 | |||||||||||||||||||||||||||||
| PPL Electric | ||||||||||||||||||||||||||||||||
| Electric distribution facilities | $ | 1,325 | $ | 500 | $ | 425 | $ | 400 | ||||||||||||||||||||||||
| Transmission facilities | 2,300 | 675 | 800 | 825 | ||||||||||||||||||||||||||||
| Total Capital Expenditures | $ | 3,625 | $ | 1,175 | $ | 1,225 | $ | 1,225 | ||||||||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||||||||
| Generating facilities | $ | 1,050 | $ | 250 | $ | 450 | $ | 350 | ||||||||||||||||||||||||
| Electric distribution facilities | 500 | 150 | 175 | 175 | ||||||||||||||||||||||||||||
| Gas distribution facilities | 300 | 75 | 125 | 100 | ||||||||||||||||||||||||||||
| Transmission facilities | 150 | 50 | 50 | 50 | ||||||||||||||||||||||||||||
| Other | 125 | 50 | 50 | 25 | ||||||||||||||||||||||||||||
| Total Capital Expenditures | $ | 2,125 | $ | 575 | $ | 850 | $ | 700 | ||||||||||||||||||||||||
| KU | ||||||||||||||||||||||||||||||||
| Generating facilities | $ | 1,150 | $ | 375 | $ | 400 | $ | 375 | ||||||||||||||||||||||||
| Electric distribution facilities | 625 | 175 | 225 | 225 | ||||||||||||||||||||||||||||
| Transmission facilities | 450 | 75 | 125 | 250 | ||||||||||||||||||||||||||||
| Other | 225 | 75 | 75 | 75 | ||||||||||||||||||||||||||||
| Total Capital Expenditures | $ | 2,450 | $ | 700 | $ | 825 | $ | 925 | ||||||||||||||||||||||||
| Projected | |||||||||||||||||||||||
| Total | 2018 (b) | 2019 | 2020 | 2021 | 2022 | ||||||||||||||||||
KU | |||||||||||||||||||||||
| Generating facilities | $ | 484 | $ | 111 | $ | 145 | $ | 89 | $ | 110 | $ | 29 | |||||||||||
| Distribution facilities | 615 | 124 | 123 | 127 | 128 | 113 | |||||||||||||||||
| Transmission facilities | 709 | 117 | 133 | 154 | 185 | 120 | |||||||||||||||||
| Environmental | 493 | 253 | 108 | 53 | 40 | 39 | |||||||||||||||||
| Other | 332 | 61 | 99 | 95 | 56 | 21 | |||||||||||||||||
| Total Capital Expenditures | $ | 2,633 | $ | 666 | $ | 608 | $ | 518 | $ | 519 | $ | 322 | |||||||||||
(a)The 2024 total excludes amounts included in accounts payable as of December 31, 2023.
Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. For the years presented, this table includes PPL Electric's asset optimization program to replace aging transmission and distribution assets.
Contractual Obligations
The Registrants have assumed various financial obligations and commitments in the ordinary course of conducting business. At December 31, 2017,2023, estimated contractual cash obligations were as follows:
| Total | 2018 | 2019 - 2020 | 2021 - 2022 | After 2022 | Total | 2024 | 2025-2026 | 2027-2028 | After 2028 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL | PPL | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term Debt (a) | $ | 20,282 | $ | 348 | $ | 1,708 | $ | 2,424 | $ | 15,802 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest on Long-term Debt (b) | 15,318 | 868 | 1,723 | 1,529 | 11,198 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating Leases (c) | 96 | 28 | 27 | 16 | 25 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Purchase Obligations (d) | 3,636 | 1,121 | 1,374 | 563 | 578 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other Long-term Liabilities Reflected on the Balance Sheet (e) | 565 | 293 | 272 | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Contractual Cash Obligations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Contractual Cash Obligations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Contractual Cash Obligations | $ | 39,897 | $ | 2,658 | $ | 5,104 | $ | 4,532 | $ | 27,603 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term Debt (a) | $ | 3,339 | $ | — | $ | 100 | $ | 874 | $ | 2,365 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest on Long-term Debt (b) | 2,894 | 141 | 282 | 260 | 2,211 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Unconditional Power Purchase Obligations | 77 | 23 | 45 | 9 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Contractual Cash Obligations | $ | 6,310 | $ | 164 | $ | 427 | $ | 1,143 | $ | 4,576 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term Debt (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest on Long-term Debt (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operating Leases (c) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal and Natural Gas Purchase Obligations (e) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Unconditional Power Purchase Obligations (f) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Construction Obligations (g) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other Obligations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other Obligations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other Obligations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Contractual Cash Obligations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
53
| Total | 2024 | 2025-2026 | 2027-2028 | After 2028 | |||||||||||||||||||||||||
| KU | |||||||||||||||||||||||||||||
| Long-term Debt (a) | $ | 3,089 | $ | — | $ | 414 | $ | 60 | $ | 2,615 | |||||||||||||||||||
| Interest on Long-term Debt (b) | 2,127 | 130 | 251 | 234 | 1,512 | ||||||||||||||||||||||||
| Operating Leases (c) | 22 | 9 | 9 | 3 | 1 | ||||||||||||||||||||||||
| Coal and Natural Gas Purchase Obligations (e) | 953 | 328 | 460 | 165 | — | ||||||||||||||||||||||||
| Unconditional Power Purchase Obligations (f) | 132 | 12 | 22 | 21 | 77 | ||||||||||||||||||||||||
| Construction Obligations (g) | 85 | 50 | 31 | 2 | 2 | ||||||||||||||||||||||||
| Other Obligations | 108 | 46 | 47 | 11 | 4 | ||||||||||||||||||||||||
| Total Contractual Cash Obligations | $ | 6,516 | $ | 575 | $ | 1,234 | $ | 496 | $ | 4,211 | |||||||||||||||||||
| Total | 2018 | 2019 - 2020 | 2021 - 2022 | After 2022 | |||||||||||||||
| LKE | |||||||||||||||||||
| Long-term Debt (a) | $ | 5,200 | $ | 98 | $ | 1,405 | $ | 250 | $ | 3,447 | |||||||||
| Interest on Long-term Debt (b) | 3,120 | 199 | 388 | 300 | 2,233 | ||||||||||||||
| Operating Leases (c) | 82 | 26 | 27 | 14 | 15 | ||||||||||||||
| Coal and Natural Gas Purchase Obligations (f) | 1,955 | 582 | 930 | 375 | 68 | ||||||||||||||
| Unconditional Power Purchase Obligations (g) | 593 | 29 | 53 | 54 | 457 | ||||||||||||||
| Construction Obligations (h) | 500 | 305 | 147 | 48 | — | ||||||||||||||
| Pension Benefit Plan Obligations (e) | 105 | 105 | — | — | — | ||||||||||||||
| Other Obligations | 417 | 151 | 143 | 70 | 53 | ||||||||||||||
| Total Contractual Cash Obligations | $ | 11,972 | $ | 1,495 | $ | 3,093 | $ | 1,111 | $ | 6,273 | |||||||||
| LG&E | |||||||||||||||||||
| Long-term Debt (a) | $ | 1,724 | $ | 98 | $ | 334 | $ | — | $ | 1,292 | |||||||||
| Interest on Long-term Debt (b) | 1,185 | 63 | 117 | 108 | 897 | ||||||||||||||
| Operating Leases (c) | 39 | 15 | 13 | 5 | 6 | ||||||||||||||
| Coal and Natural Gas Purchase Obligations (f) | 839 | 252 | 403 | 154 | 30 | ||||||||||||||
| Unconditional Power Purchase Obligations (g) | 411 | 20 | 37 | 38 | 316 | ||||||||||||||
| Construction Obligations (h) | 256 | 185 | 62 | 9 | — | ||||||||||||||
| Pension Benefit Plan Obligations (e) | 54 | 54 | — | — | — | ||||||||||||||
| Other Obligations | 149 | 47 | 59 | 26 | 17 | ||||||||||||||
| Total Contractual Cash Obligations | $ | 4,657 | $ | 734 | $ | 1,025 | $ | 340 | $ | 2,558 | |||||||||
| KU | |||||||||||||||||||
| Long-term Debt (a) | $ | 2,351 | $ | — | $ | 596 | $ | — | $ | 1,755 | |||||||||
| Interest on Long-term Debt (b) | 1,719 | 93 | 186 | 153 | 1,287 | ||||||||||||||
| Operating Leases (c) | 41 | 10 | 14 | 9 | 8 | ||||||||||||||
| Coal and Natural Gas Purchase Obligations (f) | 1,115 | 330 | 527 | 221 | 37 | ||||||||||||||
| Unconditional Power Purchase Obligations (g) | 182 | 9 | 16 | 16 | 141 | ||||||||||||||
| Construction Obligations (h) | 218 | 101 | 80 | 37 | — | ||||||||||||||
| Pension Benefit Plan Obligations (e) | 46 | 46 | — | — | — | ||||||||||||||
| Other Obligations | 187 | 49 | 64 | 38 | 36 | ||||||||||||||
| Total Contractual Cash Obligations | $ | 5,859 | $ | 638 | $ | 1,483 | $ | 474 | $ | 3,264 | |||||||||
(b)Assumes interest payments through stated maturity or earlier put dates. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)See Note 10 to the Financial Statements for additional information.
(d)The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes, as applicable, the purchase obligations of electricity, coal, natural gas and limestone, as well as certain construction expenditures, which are also included in the Capital Expenditures discussion above.
(e)Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 13 to the Financial Statements for additional information.
Dividends/Distributions
(PPL)
PPL views dividends as an integral component of shareowner return and expects to continue to pay dividends in amounts that are within the context of maintainingintended to maintain a capitalization structure that supports investment grade credit ratings. In November 2017,2023, PPL declared its quarterly common stock dividend, payable January 2, 2018,2024, at 39.524.00 cents per share (equivalent to $1.58$0.96 per annum). On February 22, 2018,16, 2024, PPL announced that the company is increasing itsa quarterly common stock dividend to 41.0of 25.75 cents per share, on a quarterly basis (equivalentpayable April 1, 2024, to 1.64 per annum).shareowners of record as of March 8, 2024. Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other relevant factors.
Subject to certain exceptions, PPL may not declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067 or 2013 Series B Junior Subordinated Notes due 2073.2067. At December 31, 2017,2023, no interest payments were deferred.
(PPL Electric, LKE, LG&E and KU)
From time to time, as determined by their respective Board of Directors, the Registrants pay dividends, distributions or distributions,return capital, as applicable, to their respective shareholders or members. Certain of the credit facilities of PPL Electric, LKE, LG&E and KU include minimum debt covenant ratios that could effectively restrict the payment of dividends or distributions.
(All Registrants)
See Note 78 to the Financial Statements for these and other restrictions related to distributions on capital interests for the Registrants and their subsidiaries.
Purchase or Redemption of Debt Securities
The Registrants will continue to evaluate outstanding debt securities and may decide to purchase or redeem these securities in open market or privately negotiated transactions, in exchange transactions or otherwise, depending upon prevailing market conditions, available cash and other factors, and may be commenced or suspended at any time. The amounts involved may be material.
54
Rating Agency Actions
Moody's and S&P periodically review the credit ratings of the debt of the Registrants and their subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of the Registrants and their subsidiaries are based on information provided by the Registrants and other sources. The ratings of Moody's and S&P are not a recommendation to buy, sell or hold any securities of the Registrants or their subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.
The credit ratings of the Registrants and their subsidiaries affect their liquidity, access to capital markets and cost of borrowing under their credit facilities. A downgrade in the Registrants' or their subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets. The Registrants and their subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
The following table sets forth the Registrants' and their subsidiaries' credit ratings for outstanding debt securities or commercial paper programs as of December 31, 2017.
2023.
| Senior Unsecured | Senior Secured | Commercial Paper | |||||||||||||||||||||||||||||||||||||||||||
| Issuer | Moody's | S&P | Moody's | S&P | Moody's | S&P | |||||||||||||||||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||||||||||||||||
| PPL Capital Funding | BBB+ | P-2 | A-2 | ||||||||||||||||||||||||||||||||||||||||||
| A3 | A- | P-2 | A-2 | ||||||||||||||||||||||||||||||||||||||||||
| PPL and PPL Electric | |||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | A1 | P-2 | |||||||||||||||||||||||||||||||||||||||||||
| PPL, LG&E and | |||||||||||||||||||||||||||||||||||||||||||||
| A1 | A | P-2 | A-2 | ||||||||||||||||||||||||||||||||||||||||||
| A1 | A | P-2 | A-2 | ||||||||||||||||||||||||||||||||||||||||||
The rating agencies have taken the following actions related to the Registrants and their subsidiaries.
(PPL)
In March 2017, Moody's andJune 2023, Moody’s assigned RIE's commercial paper a Short-Term Rating of P-2.
In June 2023, S&P assigned ratings of Baa1 and A- to WPD (South Wales)’s £50 million 0.01% Index-linked Senior Notes due 2029.
Ratings Triggers
(PPL, LKE, LG&E and KU)
Various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, and interest rate and foreign currency instruments, (for PPL), contain provisions that require the posting of additional collateral or permit the counterparty to terminate the contract, if PPL's, LKE's, LG&E's or KU's or their subsidiaries' credit rating, as applicable, were to fall below investment grade. See Note 17 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral requirements for PPL, LKE and LG&E for derivative contracts in a net liability position at December 31, 2017.2023.
Guarantees for Subsidiaries(PPL)
PPL guarantees certain consolidated affiliate financing arrangements. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, accelerate maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. At this
time, PPL believes that these covenants will not limit access to relevant funding sources. See Note 13 to the Financial Statements for additional information about guarantees.
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Other Contingent Obligations(All Registrants)
The Registrants have entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 13 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
(All Registrants)
See Notes 1, 16 and 17 to the Financial Statements for information about the Registrants' risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These are not precise indicators of expected future losses, but are rather only indicators of possible losses under normal market conditions at a given confidence level.
Interest Rate Risk
The following interest rate hedges were outstanding at December 31. 31:
| 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| Exposure Hedged | Fair Value, Net - Asset (Liability) (a) | Effect of a 10% Adverse Movement in Rates (b) | Maturities Ranging Through | Exposure Hedged | Fair Value, Net - Asset (Liability) (a) | Effect of a 10% Adverse Movement in Rates (b) | |||||||||||||||||||||||||||||||||||
| PPL and LG&E | |||||||||||||||||||||||||||||||||||||||||
| Economic hedges | |||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps (c) | $ | 64 | $ | (7) | $ | (1) | 2033 | $ | 64 | $ | (7) | $ | (1) | ||||||||||||||||||||||||||||
| 2017 | 2016 | ||||||||||||||||||||||||
Exposure Hedged | Fair Value, Net - Asset (Liability) (a) | Effect of a 10% Adverse Movement in Rates (b) | Maturities Ranging Through | Exposure Hedged | Fair Value, Net - Asset (Liability) (a) | Effect of a 10% Adverse Movement in Rates (b) | |||||||||||||||||||
| PPL | |||||||||||||||||||||||||
| Cash flow hedges | |||||||||||||||||||||||||
| Cross-currency swaps (c) | $ | 702 | $ | 103 | $ | (84 | ) | 2028 | $ | 802 | $ | 191 | $ | (90 | ) | ||||||||||
| Economic hedges | |||||||||||||||||||||||||
| Interest rate swaps (d) | 147 | (27 | ) | (1 | ) | 2033 | 147 | (32 | ) | (2 | ) | ||||||||||||||
| LKE | |||||||||||||||||||||||||
| Economic hedges | |||||||||||||||||||||||||
| Interest rate swaps (d) | 147 | (27 | ) | (1 | ) | 2033 | 147 | (32 | ) | (2 | ) | ||||||||||||||
| LG&E | |||||||||||||||||||||||||
| Economic hedges | |||||||||||||||||||||||||
| Interest rate swaps (d) | 147 | (27 | ) | (1 | ) | 2033 | 147 | (32 | ) | (2 | ) | ||||||||||||||
(a)Includes accrued interest, if applicable.
(b)Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability. Sensitivities represent a 10% adverse movement in interest rates.
(c)Realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in the fair value of these derivatives are included in regulatory assets or regulatory liabilities.
The Registrants are exposed to a potential increase in interest expense and to changes in the fair value of their debt portfolios. The estimated impact of a 10% adverse movement in interest rates on interest expense at December 31, 2017 and 2016 was insignificant for PPL, PPL Electric, LKE, LG&E and KU. The estimated impact of a 10% adverse movement in interest rates on the fair value of debt and interest expense at December 31 is shown below.
| 10% Adverse Movement in Rates on Fair Value of Debt | 10% Adverse Movement in Rates on Interest Expense For Floating Exposure | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| PPL | $ | 593 | $ | 495 | $ | 8 | $ | 16 | |||||||||||||||
| PPL Electric | 250 | 178 | 3 | 6 | |||||||||||||||||||
| LG&E | 95 | 84 | — | 3 | |||||||||||||||||||
| KU | 137 | 127 | 1 | 2 | |||||||||||||||||||
| 10% Adverse Movement in Rates | |||||||
| 2017 | 2016 | ||||||
| PPL | $ | 620 | $ | 590 | |||
| PPL Electric | 162 | 138 | |||||
| LKE | 168 | 182 | |||||
| LG&E | 62 | 66 | |||||
| KU | 92 | 100 | |||||
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| 2017 | 2016 | ||||||||||||||||||||||||
Exposure Hedged | Fair Value, Net - Asset (Liability) | Effect of a 10% Adverse Movement in Foreign Currency Exchange Rates (a) | Maturities Ranging Through | Exposure Hedged | Fair Value, Net - Asset (Liability) | Effect of a 10% Adverse Movement in Foreign Currency Exchange Rates (a) | |||||||||||||||||||
| Economic hedges (b) | £ | 2,563 | $ | 15 | $ | (323 | ) | 2020 | £ | 1,909 | $ | 184 | $ | (215 | ) | ||||||||||
Commodity Price Risk
PPL is exposed to commodity price risk through its domestic 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 PUC-approvedPAPUC-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.costs. These mechanisms generally provide for timely recovery of market price fluctuations associated with these expenses.
costs.•RIE utilizes derivative instruments pursuant to its RIPUC-approved plan to manage commodity price risk associated with its natural gas purchases. RIE's commodity price risk management strategy is to reduce fluctuations in firm gas sales prices to its customers. RIE's costs associated with derivatives instruments are recoverable through its RIPUC- approved cost recovery mechanisms. 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.
Defined Benefit Plans - Equity Securities Price Risk
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of equity securities price risk on plan assets.
Credit Risk
(All Registrants)
Credit risk is the riskpotential loss that the Registrants would incurmay be incurred due to a loss as a result of nonperformance by counterparties of their contractual obligations. The Registrants maintain credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, the Registrants, as applicable, have concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact the Registrants' overall exposurecounterparty's non-performance.
PPL is exposed to credit risk positively or negatively,from "in-the-money" transactions with counterparties, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
PPL and its subsidiaries have credit policies in future rates. At December 31, 2017, mostplace to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the successful bidders under alluse 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 solicitations had anevent that the counterparties' credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit rating from S&P, and were not required to post collateral under the Agreement. A small portionlimit.
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(All Registrants)
Related Party Transactions
The Registrants are not aware of any material ownership interests or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with the Registrants. See Note 14 to the Financial Statements for additional information on related party transactions for PPL Electric, LKE, LG&E and KU.
Acquisitions, Development and Divestitures
The Registrants from time to time evaluate opportunities for potential acquisitions, divestitures, and development projects. See Note 9 to the Financial Statements for additional information on acquisition and divestiture activity. Development projects are reexamined based on market conditions and other factors to determine whether to proceed with,
modify or terminate the projects. Any resulting transactions may impact future financial results. See Note 8 to the Financial Statements for information on the more significant activities.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to PPL's, PPL Electric's, LKE's, LG&E's and KU'sthe Registrants' air emissions, water discharges and the management of hazardous and solid waste, as well as other aspects of the Registrants' businesses. The costcosts of compliance or alleged non-compliance cannot be predicted with certainty but could be significant. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed. Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the costcosts for their products or their demand for the Registrants' services. Increased capital and operating costs are expected to be subject to rate recovery. PPL, PPL Electric, LKE, LG&E and KUThe Registrants can provide no assurances as to the ultimate outcome of future environmental or rate proceedings before regulatory authorities.
See "Legal Matters" in Note 13 to the Financial Statements for a discussion of the more significant environmental matters including: Legal Matters, NAAQS, Climate Change, CCRs, and ELGs.claims. See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information on projected environmental capital expenditures for 20182024 through 2022.2026. See Note 19 to the Financial Statements for information related to the impacts of CCRs on AROs. See "Item 1. Business - Environmental Matters" for additional information.
Sustainability
Increasing attention has been focused on a broad range of corporate activities under the heading of “sustainability”, which has resulted in a significant increase in the number of requests from interested parties for information on sustainability topics. These parties range from investor groups focused on environmental, social, governance and other matters to non-investors concerned with a variety of public policy matters. Often the scope of the information sought is very broad and not necessarily relevant to an issuer’s business or industry. As a result, a number of private groups have proposed to standardize the subject matter constituting sustainability, either generally or by industry. Those efforts remain ongoing. In addition, certain of these private groups have advocated that the SEC promulgate regulations requiring specific sustainability reporting under the Securities Exchange Act of 1934, as amended (the “’34 Act”)’34 Act), or that issuers voluntarily include certain sustainability disclosure in their ’34 Act reports. To date, no new reportingIn March 2022, the SEC proposed broad-based climate disclosure requirements have been adoptedfor public companies. The proposed rule would require public companies to disclose direct and indirect GHG emissions, strategic insights, and certain financial implications in public disclosures. The proposed rulemaking elicited significant debate and comment. While a final rulemaking is currently expected to be issued in the first half of 2024, PPL cannot predict the final legal requirements or proposed bywhen the SEC.requirements will be effective.
As has been PPL’s practice, to the extent sustainability issues have or may have a material impact on the Registrants’ financial condition or results of operation, PPL discloses such matters in accordance with applicable securities law and SEC regulations. With respect to other sustainability topics that PPL deems relevant to investors but that are not required to be reported under applicable securities law and SEC regulation, PPL will continue each spring to publish its annual sustainability report including tracking reductions related to the company's goal to reduce carbon emissions and post that report on its corporate website at www.pplweb.com and on www.pplsustainability.com. Neither the information in such annual sustainability report nor the information at such websites is incorporated in this Form 10-K by reference, and it should not be considered a part of this Form
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10-K. In preparing its sustainability report, PPL is guided by the framework established by the Global Reporting Initiative, which identifies environmental, social, governance and other subject matter categories, together with recentcategories. PPL also participates in efforts by the Edison Electric Institute and American Gas Association to provide guidance as to the appropriate subset of sustainability information that can be applied consistently across the electric and gas utility industry.industries. Additionally, PPL consults widely used reporting frameworks for discrete sustainability topics, including corporate political contributions and climate-related issues. PPL also responds to the climate survey of CDP, a not-for-profit organization based in the United Kingdom formerly known as the Carbon Disclosure Project, that runs the global disclosure system that enables investors, companies, cities, states and regions to measure and manage their environmental impacts.
Cybersecurity
See “Cybersecurity Management” in “Item 1. Business” and “Item 1A. Risk factors”Factors” and “Item 1C. Cybersecurity” for a discussion of cybersecurity risks affecting the Registrants and the related strategies for managing these risks.
Competition
See "Competition" under each of PPL's reportable segments in "Item 1. Business - General - Segment Information" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting the Registrants.
New Accounting Guidance
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to an understanding of the reported financial condition or results of operations and require management to make estimates or other judgments of matters that are inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). Senior management has reviewed with PPL's Audit Committee these critical accounting policies, the following disclosures regarding their application, and the estimates and assumptions regarding them.
Defined Benefits
(All Registrants)
Certain of the Registrants and/or their subsidiaries sponsor or participate in as applicable, certain qualified funded and non-qualified unfunded defined benefit pension plans and both funded and unfunded other postretirement benefit plans. These plans are applicable to the majority of the Registrants' employees (based on eligibility for their applicable plans). The Registrants and certain of their subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to AOCI or, in the case of PPL Electric, LG&E and KU, regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Notes 61, 7 and 11 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
A summary of plan sponsors by Registrant and whether a Registrant or its subsidiaries sponsor (S) or participate in and receives allocations (P) from those plans is shown in the table below.
| Plan Sponsor | PPL | PPL Electric | LG&E | KU | |||||||||||||||||||||||||||||||
| PPL Services | S | P | |||||||||||||||||||||||||||||||||
| P | |||||||||||||||||||||||||||||||||||
| P | |||||||||||||||||||||||||||||||||||
Management makes certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. As such, annual net periodic defined benefit costs are recorded in current earnings or regulatory assets and liabilities based on estimated results. Any differences between actual and estimated results are recorded in AOCI or, in the case of PPL Electric, LG&E and KU, regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in AOCI or regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primarysignificant assumptions are:
•Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
In selecting the discount rates for U.S. defined benefit plans, the plan sponsors start with a cash flow analysis of the expected benefit payment stream for their plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.
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for a hypothetical settlement portfolio. The plan sponsors projectthen use the single discount rate derived from matching the discounted benefit payment stream to the market value of the selected bond portfolio.
•Expected Return on Plan Assets - The expected long-term rates of return for pension and other postretirement benefits are based on plan assetsmanagement's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
•Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. In selecting a rate of compensation increase, plan sponsors consider past experience, in lightthe potential impact of movements in inflation rates.rates and expectations of ongoing compensation practices.
| Assumption / Registrant | 2017 | 2016 | ||||
| Discount rate | ||||||
| Pension - PPL (U.S.) | 3.70 | % | 4.21 | % | ||
| Pension - PPL (U.K.) Obligations | 2.65 | % | 2.87 | % | ||
| Pension - PPL (U.K.) Service Cost (a) | 2.73 | % | 2.99 | % | ||
| Pension - PPL (U.K.) Interest Cost (a) | 2.31 | % | 2.41 | % | ||
| Pension - LKE | 3.69 | % | 4.19 | % | ||
| Pension - LG&E | 3.65 | % | 4.13 | % | ||
| Other Postretirement - PPL | 3.64 | % | 4.11 | % | ||
| Other Postretirement - LKE | 3.65 | % | 4.12 | % | ||
| Expected return on plan assets | ||||||
| Pension - PPL (U.S.) | 7.25 | % | 7.00 | % | ||
| Pension - PPL (U.K.) | 7.23 | % | 7.22 | % | ||
| Pension - LKE | 7.25 | % | 7.00 | % | ||
| Pension - LG&E | 7.25 | % | 7.00 | % | ||
| Other Postretirement - PPL | 6.40 | % | 6.21 | % | ||
| Other Postretirement - LKE | 7.15 | % | 6.82 | % | ||
| Rate of compensation increase | ||||||
| Pension - PPL (U.S.) | 3.78 | % | 3.95 | % | ||
| Pension - PPL (U.K.) | 3.50 | % | 3.50 | % | ||
| Pension - LKE | 3.50 | % | 3.50 | % | ||
| Other Postretirement - PPL | 3.75 | % | 3.92 | % | ||
| Other Postretirement - LKE | 3.50 | % | 3.50 | % | ||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Balance Sheet: | |||||||||||||||||||
| Regulatory assets (a) | $ | 880 | $ | 504 | $ | 376 | $ | 234 | $ | 142 | |||||||||
| Regulatory liabilities | 27 | 27 | 27 | ||||||||||||||||
| Pension assets | 284 | ||||||||||||||||||
| Pension liabilities | 813 | 246 | 369 | 45 | 36 | ||||||||||||||
Other postretirement and postemployment benefit liabilities | 184 | 62 | 107 | 74 | 32 | ||||||||||||||
| AOCI (pre-tax) | 3,144 | 150 | |||||||||||||||||
| Statement of Income: | |||||||||||||||||||
| Defined benefits expense | $ | (87 | ) | $ | 12 | $ | 33 | $ | 11 | $ | 5 | ||||||||
| Increase (decrease) from prior year | (52 | ) | 1 | 3 | — | (2 | ) | ||||||||||||
| Increase (Decrease) | ||||||
| Actuarial assumption | ||||||
| (0.25 | %) | |||||
| Expected Return on Plan Assets | (0.25 | %) | ||||
| Rate of Compensation Increase | 0.25 | % | ||||
| Increase (Decrease) | Increase (Decrease) | (Increase) Decrease | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||||||
| Actuarial assumption | Defined Benefit Asset | Defined Benefit Liabilities | AOCI (pre-tax) | Net Regulatory Assets | Defined Benefit Costs | ||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||
| Discount rates | $ | (21) | $ | (80) | $ | 27 | $ | 74 | $ | — | |||||||||||||||||||
| Expected return on plan assets | n/a | n/a | n/a | n/a | 10 | ||||||||||||||||||||||||
| Rate of compensation increase | (3) | (7) | 3 | 7 | 1 | ||||||||||||||||||||||||
| PPL Electric | |||||||||||||||||||||||||||||
| Discount rates | — | (35) | — | 35 | (1) | ||||||||||||||||||||||||
| Expected return on plan assets | n/a | n/a | — | n/a | 4 | ||||||||||||||||||||||||
| Rate of compensation increase | — | (3) | — | 3 | — | ||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||
| Discount rates | (9) | 1 | n/a | 10 | 1 | ||||||||||||||||||||||||
| Expected return on plan assets | n/a | n/a | n/a | n/a | 1 | ||||||||||||||||||||||||
| Rate of compensation increase | (1) | — | n/a | 1 | — | ||||||||||||||||||||||||
| KU | |||||||||||||||||||||||||||||
| Discount rates | (7) | 1 | n/a | 8 | — | ||||||||||||||||||||||||
| Expected return on plan assets | n/a | n/a | n/a | n/a | 1 | ||||||||||||||||||||||||
| Rate of compensation increase | (1) | — | n/a | 1 | — | ||||||||||||||||||||||||
| Increase (Decrease) | (Increase) Decrease | Increase (Decrease) | Increase (Decrease) | ||||||||||||
| Actuarial assumption | Defined Benefit Liabilities | AOCI (pre-tax) | Net Regulatory Assets | Defined Benefit Costs | |||||||||||
| PPL | |||||||||||||||
| Discount rates | $ | 520 | $ | 416 | $ | 104 | $ | 43 | |||||||
| Expected return on plan assets | n/a | n/a | n/a | 27 | |||||||||||
| Rate of compensation increase | 72 | 60 | 12 | 9 | |||||||||||
| Health care cost trend rate (a) | 4 | — | 4 | — | |||||||||||
| PPL Electric | |||||||||||||||
| Discount rates | 64 | — | 64 | 4 | |||||||||||
| Expected return on plan assets | n/a | — | n/a | 4 | |||||||||||
| Rate of compensation increase | 8 | — | 8 | 1 | |||||||||||
| Health care cost trend rate (a) | 1 | — | 1 | — | |||||||||||
| LKE | |||||||||||||||
| Discount rates | 68 | 28 | 40 | 8 | |||||||||||
| Expected return on plan assets | n/a | n/a | n/a | 3 | |||||||||||
| Rate of compensation increase | 10 | 5 | 5 | 2 | |||||||||||
| Health care cost trend rate (a) | 3 | — | 3 | — | |||||||||||
| LG&E | |||||||||||||||
| Discount rates | 21 | n/a | 21 | 3 | |||||||||||
| Expected return on plan assets | n/a | n/a | n/a | 1 | |||||||||||
| Rate of compensation increase | 2 | n/a | 2 | — | |||||||||||
| Health care cost trend rate (a) | 1 | n/a | 1 | — | |||||||||||
| KU | |||||||||||||||
| Discount rates | 18 | n/a | 18 | 2 | |||||||||||
| Expected return on plan assets | n/a | n/a | n/a | 1 | |||||||||||
| Rate of compensation increase | 3 | n/a | 3 | — | |||||||||||
| Health care cost trend rate (a) | 2 | n/a | 2 | — | |||||||||||
Income Taxes(All Registrants)
Significant management judgment is also required in developing the Registrants' provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken inon tax returns and valuation allowances on deferred tax assets and whether the undistributed earningsassets.
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On a quarterly basis, uncertain tax positions are reassessed by considering information known as of the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.
The need for valuation allowances to reduce deferred tax assets also requires significant management judgment. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number ofseveral factors in assessing the expected realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considersWhen evaluating the need for valuation allowances, the uncertainty posed by political risk and the effect of this uncertainty on the varioussuch factors that management takes into account in evaluating the need for valuation allowances.is also considered by management. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.
See Note 56 to the Financial Statements for income tax disclosures, including the impact of the TCJA and management's conclusion that the undistributed earnings of WPD are considered indefinitely reinvested. Based on this conclusion, PPL Global does not record U.S. federal income taxes on WPD's undistributed earnings.disclosures.
Regulatory Assets and Liabilities
(All Registrants)
PPL Electric, LG&E, KU and KU,RIE are subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to the Registrants and other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels and is subject to change in the future. If future recovery of costs
ceases to be probable, the regulatory asset would be written-off. Additionally, the regulatory agencies can provide flexibility in the manner and timing of recovery of regulatory assets.
See Note 67 to the Financial Statements for regulatory assets and regulatory liabilities recorded at December 31, 20172023 and 2016,2022, as well as additional information on those regulatory assets and liabilities. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
Price Risk Management(PPL)
See "Financial Condition - Risk Management" above, as well as "Price Risk Management" in Note 1 to the Financial Statements.above.
Goodwill Impairment(PPL, LKE, LG&E and KU)
Goodwill is tested for impairment at the reporting unit level. PPL has determined itsThe reporting units to be atof PPL include the same level as its reportable segments. LKE,Kentucky Regulated reporting unit, the Pennsylvania Regulated reporting unit, and the Rhode Island Regulated reporting unit. LG&E and KU are individuallyeach single operating and reportable segments. reporting units. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the reporting unit's fair value. Additionally, goodwill
The fair value of a reporting unit is tested forcompared with the carrying value and an impairment after a portioncharge is recognized if the carrying amount exceeds the fair value of goodwill has been allocated to a business to be disposed of.the reporting unit.
PPL, LKE,for its reporting units, and individually, LG&E and KU, may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. IfSee "Long-Lived and Intangible Assets - Asset Impairment (Excluding Investments)" in Note 1 to the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value
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As of $2.6 billion related to the acquisition of WPDOctober 1, 2023, PPL, for its reporting units, and $662 million related to the acquisition of LKE. PPL (for its U.K. Regulated and Kentucky Regulated segments), and individually, LKE, LG&E and KU, elected to perform the qualitative step zero evaluation of goodwill, as of October 1, 2017.goodwill. These evaluations considered the excess of fair value over the carrying value of each reporting unit that was calculated during step one of the quantitative impairment tests performed in the fourth quarter of 2015,2022, and the relevant events and circumstances that occurred since those tests were performed including:
•current year financial performance versus the prior year;year,
•changes in planned capital expenditures;expenditures,
•the consistency of forecasted free cash flows;flows,
•earnings quality and sustainability;sustainability,
•changes in market participant discount rates;rates,
•changes in long-term growth rates;rates,
•changes in PPL's market capitalization;capitalization, and
•the overall economic and regulatory environments in which these regulated entities operate.
Based on these evaluations, management concluded it was not more likely than not that the fair value of these reporting units was less than their carrying values.value. As such, the two-stepstep one quantitative impairment test was not performed. performed and no impairment was recognized.
Asset Retirement Obligations(PPL, LKE, LG&E and KU)
ARO liabilities are required to be recognized for legal obligations associated with the retirement of long-lived assets. The initial obligation isInitial obligations are measured at its estimated fair value. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount is recorded as an increase in the value of the capitalized asset and amortized to expense, regulatory assets or regulatory liabilities over the asset's useful life of the asset. For LKE, LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, at the time of retirement, the related ARO regulatory asset is offset against the associated cost of removal regulatory liability, PP&E and ARO liability.life.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that consider estimated retirement costs in current period dollars, that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO.ARO estimate. Any change to the capitalized asset positive or negative, is generally amortized over the remaining life of the associated long-lived asset.
See "Long-Lived and Intangible Assets - Asset Retirement Obligations" in Note 1, Note 7 and Note 19 to the Financial Statements for additional information on AROs.
At December 31, 2017,2023, the total recorded balances and information on the most significant recorded AROs were as follows.
| Most Significant AROs | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total ARO Recorded | Total ARO Recorded | Amount Recorded | % of Total | Description | |||||||||||||||||||||||||||||||||||||||||||||
| Most Significant AROs | |||||||||||||||||||||||||||||||||||||||||||||||||
Total ARO Recorded | Amount Recorded | % of Total | Description | ||||||||||||||||||||||||||||||||||||||||||||||
| PPL | $ | 397 | $ | 284 | 72 | Ponds, landfills and natural gas mains | |||||||||||||||||||||||||||||||||||||||||||
| LKE | 356 | 284 | 80 | Ponds, landfills and natural gas mains | |||||||||||||||||||||||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||||||||||||||||||||
| LG&E | 121 | 89 | 74 | Ponds, landfills and natural gas mains | $ | 85 | $ | $ | 63 | 74 | 74 | Ponds, landfills and natural gas mains | Ponds, landfills and natural gas mains | ||||||||||||||||||||||||||||||||||||
| KU | 235 | 195 | 83 | Ponds and landfills | KU | 66 | 37 | 37 | 56 | 56 | Ponds and landfills | Ponds and landfills | |||||||||||||||||||||||||||||||||||||
The most significant assumptions surrounding AROs are the forecasted retirement costs (including the settlement dates and the timing of cash flows), the discount rates and the inflation rates. At December 31, 2017,2023, a 10% increase to retirement cost would increase these ARO liabilities by $32 million.$7 million at LG&E and $11 million at KU. A 0.25% decrease in the discount rate would increase these ARO liabilities by $4$5 million at LG&E and $1 million at KU and a 0.25% increase in the inflation rate would increase these ARO liabilities by $2 million.$4 million at LG&E. There would be no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of these changes in assumptions.
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Revenue Recognition - Unbilled Revenues(LKE,PPL, LG&E and KU)
weather normalization or other regulatory provisions of rate structures. See "Unbilled revenues" on the Registrants' Balance Sheets for balances at December 31, 2017 and 2016.
Other Information(All Registrants)
PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Reference is made to "Risk Management" for the Registrants in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations."
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareowners and the Board of Directors of PPL Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PPL Corporation and subsidiaries (the "Company") as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years thenin the period ended December 31, 2023, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years thenin the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017,2023, based on criteria established inInternal Control –— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2018,16, 2024, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinionopinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities– Impact of Rate-Regulation on Regulatory Assets and Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, the Company owns and operates four cost-based rate-regulated utilities for which rates are set by regulatory commissions to enable the regulated utility to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated
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customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific rate orders or, in certain cases, regulatory commission precedent for transactions or events. While the Company has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulatory commissions will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management’s internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and liabilities. We tested the effectiveness of management’s internal controls over the recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for the Company and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated the Company’s disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
February 22, 201816, 2024
We have served as the Company's auditor since 2015.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareowner and the Board of Directors of PPL Electric Utilities Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PPL Electric Utilities Corporation and subsidiaries (the "Company") as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, equity, and cash flows, for each of the three years thenin the period ended December 31, 2023, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years thenin the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities– Impact of Rate-Regulation on Regulatory Assets and Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, PPL Electric Utilities Company (PPL Electric) is a cost-based rate-regulated utility for which rates are set by regulatory commissions to enable the regulated utility to recover the costs of providing electric service and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific rate orders or, in certain
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cases, regulatory commission precedent for transactions or events. While PPL Electric has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulatory commissions will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management’s internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and liabilities. We tested the effectiveness of management’s internal controls over the recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for PPL Electric and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated PPL Electric’s disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
February 22, 2018 16, 2024
We have served as the Company's auditor since 2015.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Sole MemberStockholder and the Board of Directors of LG&ELouisville Gas and KU Energy LLCElectric Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of LG&ELouisville Gas and KU Energy LLC and subsidiariesElectric Company (the “Company”"Company") as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years thenin the period ended December 31, 2023, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years thenin the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities– Impact of Rate-Regulation on Regulatory Assets and Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, Louisville Gas & Electric Company (LG&E) is a cost-based rate-regulated utility for which rates are set by regulatory commissions to enable the regulated utility to recover the costs of providing electric or gas services, as applicable, and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. The accounting for regulatory assets and regulatory liabilities is based on specific rate orders or, in certain cases, regulatory commission precedent for transactions or events. While LG&E has indicated that it expects to recover costs
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from customers through regulated rates, there is a risk that the regulatory commissions will not approve full recovery of and return on such costs or approve recovery on a timely basis in future regulatory decisions.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management’s internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and liabilities. We tested the effectiveness of management’s internal controls over the recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for LG&E and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated LG&E’s disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Louisville, Kentucky
February 22, 201816, 2024
We have served as the Company’s auditor since 2015.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder and the Board of Directors of Louisville Gas and ElectricKentucky Utilities Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Louisville Gas and ElectricKentucky Utilities Company (the “Company”"Company") as of December 31, 20172023 and 2016,2022, the related statements of income, equity, and cash flows, for each of the three years thenin the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years thenin the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities– Impact of Rate-Regulation on Regulatory Assets and Liabilities and Related Disclosures – Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
As discussed in Note 1 to the financial statements, Kentucky Utilities Company (KU) is a cost-based rate-regulated utility for which rates are set by regulatory commissions to enable the regulated utility to recover the costs of providing electric service and to provide a reasonable return to shareholders. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by generally accepted accounting principles and reflect the effects of regulatory actions.
Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.The accounting for regulatory assets and regulatory liabilities is based on specific rate orders or, in certain
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cases, regulatory commission precedent for transactions or events. While KU has indicated that it expects to recover costs from customers through regulated rates, there is a risk that the regulatory commissions will not approve full recovery of and return onsuch costs or approve recovery on a timely basis in future regulatory decisions.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in continually assessing whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environments, the ability to recover costs through regulated rates, and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by regulatory commissions included the following, among others:
•We tested the effectiveness of management’s internal controls over evaluating the likelihood of recovery or refund in future rates of costs deferred as regulatory assets and liabilities. We tested the effectiveness of management’s internal controls over the recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We obtained and read relevant regulatory orders issued by the regulatory commissions for KU and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
•We evaluated KU’s disclosures related to the impacts of rate-regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP
Louisville, Kentucky
February 22, 201816, 2024
We have served as the Company’s auditor since 2015.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, except share data)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Operating Revenues | $ | 7,447 | $ | 7,517 | $ | 7,669 | ||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operation | Operation | |||||||||||||||||||||||||||||||||
| Fuel | 759 | 791 | 863 | |||||||||||||||||||||||||||||||
| Energy purchases | 685 | 706 | 855 | |||||||||||||||||||||||||||||||
| Other operation and maintenance | 1,635 | 1,745 | 1,938 | |||||||||||||||||||||||||||||||
| Depreciation | 1,008 | 926 | 883 | |||||||||||||||||||||||||||||||
| Taxes, other than income | 292 | 301 | 299 | |||||||||||||||||||||||||||||||
| Total Operating Expenses | 4,379 | 4,469 | 4,838 | |||||||||||||||||||||||||||||||
| Operating Income | 3,068 | 3,048 | 2,831 | |||||||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) - net | (255 | ) | 390 | 108 | ||||||||||||||||||||||||||||||
| Other Income (Expense) - net (Note 15) | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) - net (Note 15) | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) - net (Note 15) | ||||||||||||||||||||||||||||||||||
| Interest Expense | ||||||||||||||||||||||||||||||||||
| Interest Expense | ||||||||||||||||||||||||||||||||||
| Interest Expense | 901 | 888 | 871 | |||||||||||||||||||||||||||||||
| Income from Continuing Operations Before Income Taxes | 1,912 | 2,550 | 2,068 | |||||||||||||||||||||||||||||||
| Income from Continuing Operations Before Income Taxes | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations Before Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | 784 | 648 | 465 | |||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | 1,128 | 1,902 | 1,603 | |||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Loss from Discontinued Operations (net of income taxes) (Note 8) | — | — | (921 | ) | ||||||||||||||||||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) (Note 9) | ||||||||||||||||||||||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) (Note 9) | ||||||||||||||||||||||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) (Note 9) | ||||||||||||||||||||||||||||||||||
| Net Income | $ | 1,128 | $ | 1,902 | $ | 682 | ||||||||||||||||||||||||||||
| Net Income (Loss) | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) | ||||||||||||||||||||||||||||||||||
| Earnings Per Share of Common Stock: | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes Available to PPL Common Shareowners: | ||||||||||||||||||||||||||||||||||
| Earnings Per Share of Common Stock: | ||||||||||||||||||||||||||||||||||
| Earnings Per Share of Common Stock: | ||||||||||||||||||||||||||||||||||
| Basic | $ | 1.64 | $ | 2.80 | $ | 2.38 | ||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) Available to PPL Common Shareowners | ||||||||||||||||||||||||||||||||||
| Diluted | $ | 1.64 | $ | 2.79 | $ | 2.37 | ||||||||||||||||||||||||||||
| Net Income Available to PPL Common Shareowners: | ||||||||||||||||||||||||||||||||||
| Basic | $ | 1.64 | $ | 2.80 | $ | 1.01 | ||||||||||||||||||||||||||||
| Diluted | $ | 1.64 | $ | 2.79 | $ | 1.01 | ||||||||||||||||||||||||||||
| Diluted | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income from Continuing Operations After Income Taxes | ||||||||||||||||||||||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) Available to PPL Common Shareowners | ||||||||||||||||||||||||||||||||||
| Dividends Declared Per Share of Common Stock | $ | 1.58 | $ | 1.52 | $ | 1.50 | ||||||||||||||||||||||||||||
| Weighted-Average Shares of Common Stock Outstanding (in thousands) | ||||||||||||||||||||||||||||||||||
| Weighted-Average Shares of Common Stock Outstanding (in thousands) | ||||||||||||||||||||||||||||||||||
| Weighted-Average Shares of Common Stock Outstanding (in thousands) | ||||||||||||||||||||||||||||||||||
| Basic | 685,240 | 677,592 | 669,814 | |||||||||||||||||||||||||||||||
| Diluted | 687,334 | 680,446 | 672,586 | |||||||||||||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
73
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
| 2017 | 2016 | 2015 | |||||||||
| Net income | $ | 1,128 | $ | 1,902 | $ | 682 | |||||
| Other comprehensive income (loss): | |||||||||||
| Amounts arising during the period - gains (losses), net of tax (expense) benefit: | |||||||||||
| Foreign currency translation adjustments, net of tax of ($1), ($4), $1 | 538 | (1,107 | ) | (234 | ) | ||||||
| Available-for-sale securities, net of tax of $0, $0, ($9) | — | — | 8 | ||||||||
| Qualifying derivatives, net of tax of $19, ($18), $0 | (79 | ) | 91 | 26 | |||||||
| Defined benefit plans: | |||||||||||
| Prior service costs, net of tax of $0, $2, $6 | — | (3 | ) | (9 | ) | ||||||
| Net actuarial gain (loss), net of tax of $72, $40, $67 | (308 | ) | (61 | ) | (366 | ) | |||||
| Reclassifications to net income - (gains) losses, net of tax expense (benefit): | |||||||||||
| Available-for-sale securities, net of tax of $0, $0, $2 | — | — | (2 | ) | |||||||
| Qualifying derivatives, net of tax of ($18), $21, ($15) | 73 | (91 | ) | 2 | |||||||
| Equity investees' other comprehensive (income) loss, net of tax of $0, $0, $0 | 1 | (1 | ) | (1 | ) | ||||||
| Defined benefit plans: | |||||||||||
| Prior service costs, net of tax of ($1), ($1), $0 | 1 | 1 | — | ||||||||
| Net actuarial (gain) loss, net of tax of ($37), ($35), ($46) | 130 | 121 | 146 | ||||||||
| Total other comprehensive income (loss) | 356 | (1,050 | ) | (430 | ) | ||||||
| Comprehensive income | $ | 1,484 | $ | 852 | $ | 252 | |||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Net income (loss) | $ | 740 | $ | 756 | $ | (1,480) | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Amounts arising during the period - gains (losses), net of tax (expense) benefit: | |||||||||||||||||
| Foreign currency translation adjustments, net of tax of $0, $0, ($123) | — | — | 372 | ||||||||||||||
| Qualifying derivatives, net of tax of $0, $0, $11 | — | — | (39) | ||||||||||||||
| Equity investees' other comprehensive income (loss), net tax of $0, $0, $0 | 1 | 2 | — | ||||||||||||||
| Defined benefit plans: | |||||||||||||||||
| Prior service costs, net of tax of $0, $0, $0 | — | (1) | — | ||||||||||||||
| Net actuarial gain (loss), net of tax of $15, ($2), $1 | (41) | 11 | (1) | ||||||||||||||
| Reclassifications from AOCI - (gains) losses, net of tax expense (benefit): | |||||||||||||||||
| Qualifying derivatives, net of tax of $0, ($1), ($5) | 3 | 2 | 25 | ||||||||||||||
| Defined benefit plans: | |||||||||||||||||
| Prior service costs, net of tax of ($1), ($1), ($1) | 1 | 2 | 2 | ||||||||||||||
| Net actuarial (gain) loss, net of tax of $0, ($7), ($33) | (3) | 17 | 126 | ||||||||||||||
| Reclassifications from AOCI due to sale of the U.K. utility business - (gains) losses, net of tax expense (benefit): | |||||||||||||||||
| Foreign currency translation adjustments, net of tax of $0, $0, $140 | — | — | 786 | ||||||||||||||
| Qualifying derivatives, net of tax of $0, $0, $0 | — | — | 15 | ||||||||||||||
| Defined benefit plans: | |||||||||||||||||
| Prior service costs, net of tax of $0, $0, ($2) | — | — | 8 | ||||||||||||||
| Net actuarial (gain) loss, net of tax of $0, $0, ($798) | — | — | 2,769 | ||||||||||||||
| Total other comprehensive income (loss) | (39) | 33 | 4,063 | ||||||||||||||
| Comprehensive income | $ | 701 | $ | 789 | $ | 2,583 | |||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
74
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Cash Flows from Operating Activities | Cash Flows from Operating Activities | |||||||||||||||||||||||||||||||||
| Net income | $ | 1,128 | $ | 1,902 | $ | 682 | ||||||||||||||||||||||||||||
| Loss from discontinued operations (net of income taxes) | — | — | 921 | |||||||||||||||||||||||||||||||
| Net income (loss) | ||||||||||||||||||||||||||||||||||
| Loss (income) from discontinued operations (net of income taxes) | ||||||||||||||||||||||||||||||||||
| Income from continuing operations (net of income taxes) | 1,128 | 1,902 | 1,603 | |||||||||||||||||||||||||||||||
| Adjustments to reconcile Income from continuing operations (net of taxes) to net cash provided by (used in) operating activities - continuing operations | ||||||||||||||||||||||||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities | Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||||||||||||||||||||||
| Depreciation | 1,008 | 926 | 883 | |||||||||||||||||||||||||||||||
| Amortization | 97 | 80 | 59 | |||||||||||||||||||||||||||||||
| Defined benefit plans - expense (income) | (95 | ) | (40 | ) | 56 | |||||||||||||||||||||||||||||
| Deferred income taxes and investment tax credits | 707 | 560 | 428 | |||||||||||||||||||||||||||||||
| Unrealized (gains) losses on derivatives, and other hedging activities | 178 | 19 | (77 | ) | ||||||||||||||||||||||||||||||
| Stock compensation expense | 38 | 28 | 31 | |||||||||||||||||||||||||||||||
| Stock compensation expense | ||||||||||||||||||||||||||||||||||
| Stock compensation expense | ||||||||||||||||||||||||||||||||||
| Loss on sale of Safari Holdings | ||||||||||||||||||||||||||||||||||
| Impairment of solar panels | ||||||||||||||||||||||||||||||||||
| Loss on extinguishment of debt | ||||||||||||||||||||||||||||||||||
| Other | (9 | ) | (12 | ) | (14 | ) | ||||||||||||||||||||||||||||
| Change in current assets and current liabilities | Change in current assets and current liabilities | |||||||||||||||||||||||||||||||||
| Accounts receivable | (33 | ) | (15 | ) | 47 | |||||||||||||||||||||||||||||
| Accounts payable | (10 | ) | 57 | (116 | ) | |||||||||||||||||||||||||||||
| Unbilled revenues | (48 | ) | (63 | ) | 54 | |||||||||||||||||||||||||||||
| Fuel, materials and supplies | 40 | (3 | ) | 24 | ||||||||||||||||||||||||||||||
| Taxes payable | 3 | 31 | (175 | ) | ||||||||||||||||||||||||||||||
| Taxes payable | ||||||||||||||||||||||||||||||||||
| Taxes payable | ||||||||||||||||||||||||||||||||||
| Regulatory assets and liabilities, net | (12 | ) | (59 | ) | 42 | |||||||||||||||||||||||||||||
| Regulatory assets and liabilities, net | ||||||||||||||||||||||||||||||||||
| Regulatory assets and liabilities, net | ||||||||||||||||||||||||||||||||||
| Accrued interest | ||||||||||||||||||||||||||||||||||
| Other | 14 | (32 | ) | (7 | ) | |||||||||||||||||||||||||||||
| Other operating activities | Other operating activities | |||||||||||||||||||||||||||||||||
| Defined benefit plans - funding | (565 | ) | (427 | ) | (499 | ) | ||||||||||||||||||||||||||||
| Settlement of interest rate swaps | 2 | (9 | ) | (101 | ) | |||||||||||||||||||||||||||||
| Other assets | ||||||||||||||||||||||||||||||||||
| Other assets | ||||||||||||||||||||||||||||||||||
| Other assets | 30 | 42 | (19 | ) | ||||||||||||||||||||||||||||||
| Other liabilities | (12 | ) | (95 | ) | 53 | |||||||||||||||||||||||||||||
| Net cash provided by operating activities - continuing operations | 2,461 | 2,890 | 2,272 | |||||||||||||||||||||||||||||||
| Net cash provided by operating activities - discontinued operations | — | — | 343 | |||||||||||||||||||||||||||||||
| Net cash provided by operating activities | 2,461 | 2,890 | 2,615 | |||||||||||||||||||||||||||||||
| Cash Flows from Investing Activities | Cash Flows from Investing Activities | |||||||||||||||||||||||||||||||||
| Expenditures for property, plant and equipment | (3,133 | ) | (2,920 | ) | (3,533 | ) | ||||||||||||||||||||||||||||
| Expenditures for intangible assets | (38 | ) | (37 | ) | (37 | ) | ||||||||||||||||||||||||||||
| Proceeds from the sale of other investments | — | 2 | 136 | |||||||||||||||||||||||||||||||
| Proceeds from sale of Safari Holdings, net of cash divested | ||||||||||||||||||||||||||||||||||
| Proceeds from sale of Safari Holdings, net of cash divested | ||||||||||||||||||||||||||||||||||
| Proceeds from sale of Safari Holdings, net of cash divested | ||||||||||||||||||||||||||||||||||
| Proceeds from sale of U.K. utility business, net of cash divested | ||||||||||||||||||||||||||||||||||
| Acquisition of Narragansett Electric, net of cash acquired | ||||||||||||||||||||||||||||||||||
| Other investing activities | 15 | 37 | (5 | ) | ||||||||||||||||||||||||||||||
| Net cash used in investing activities - continuing operations | (3,156 | ) | (2,918 | ) | (3,439 | ) | ||||||||||||||||||||||||||||
| Net cash used in investing activities - discontinued operations | — | — | (149 | ) | ||||||||||||||||||||||||||||||
| Net cash used in investing activities | (3,156 | ) | (2,918 | ) | (3,588 | ) | ||||||||||||||||||||||||||||
| Net cash provided by (used in) investing activities - continuing operations | ||||||||||||||||||||||||||||||||||
| Net cash provided by (used in) investing activities - discontinued operations | ||||||||||||||||||||||||||||||||||
| Net cash provided by (used in) investing activities | ||||||||||||||||||||||||||||||||||
| Cash Flows from Financing Activities | Cash Flows from Financing Activities | |||||||||||||||||||||||||||||||||
| Issuance of long-term debt | 1,515 | 1,342 | 2,236 | |||||||||||||||||||||||||||||||
| Retirement of long-term debt | (168 | ) | (930 | ) | (1,000 | ) | ||||||||||||||||||||||||||||
| Issuance of common stock | 453 | 144 | 203 | |||||||||||||||||||||||||||||||
| Payment of common stock dividends | (1,072 | ) | (1,030 | ) | (1,004 | ) | ||||||||||||||||||||||||||||
| Net increase in short-term debt | 115 | 29 | 94 | |||||||||||||||||||||||||||||||
| Payment of common stock dividends | ||||||||||||||||||||||||||||||||||
| Payment of common stock dividends | ||||||||||||||||||||||||||||||||||
| Purchase of treasury stock | ||||||||||||||||||||||||||||||||||
| Retirement of term loan | ||||||||||||||||||||||||||||||||||
| Retirement of term loan | ||||||||||||||||||||||||||||||||||
| Retirement of term loan | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Net increase (decrease) in short-term debt | ||||||||||||||||||||||||||||||||||
| Other financing activities | (19 | ) | 6 | (47 | ) | |||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities - continuing operations | 824 | (439 | ) | 482 | ||||||||||||||||||||||||||||||
| Net cash used in financing activities - discontinued operations | — | — | (546 | ) | ||||||||||||||||||||||||||||||
| Net cash distributions to parent from discontinued operations | — | — | 132 | |||||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities - discontinued operations | ||||||||||||||||||||||||||||||||||
| Contributions from discontinued operations | ||||||||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | 824 | (439 | ) | 68 | ||||||||||||||||||||||||||||||
| Effect of Exchange Rates on Cash and Cash Equivalents | 15 | (28 | ) | (10 | ) | |||||||||||||||||||||||||||||
| Net (Increase) Decrease in Cash and Cash Equivalents included in Discontinued Operations | — | — | 352 | |||||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 144 | (495 | ) | (563 | ) | |||||||||||||||||||||||||||||
| Cash and Cash Equivalents at Beginning of Period | 341 | 836 | 1,399 | |||||||||||||||||||||||||||||||
| Cash and Cash Equivalents at End of Period | $ | 485 | $ | 341 | $ | 836 | ||||||||||||||||||||||||||||
| Effect of Exchange Rates on Cash, Cash Equivalents and Restricted Cash included in Discontinued Operations | ||||||||||||||||||||||||||||||||||
| Net (Increase) Decrease in Cash, Cash Equivalents and Restricted Cash included in Discontinued Operations | ||||||||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid during the period for: | Cash paid during the period for: | |||||||||||||||||||||||||||||||||
| Interest - net of amount capitalized | $ | 845 | $ | 854 | $ | 822 | ||||||||||||||||||||||||||||
| Income taxes - net | $ | 65 | $ | 70 | $ | 179 | ||||||||||||||||||||||||||||
| Significant non-cash transactions: | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | $ | 360 | $ | 281 | $ | 310 | ||||||||||||||||||||||||||||
| Accrued expenditures for intangible assets at December 31, | $ | 68 | $ | 117 | $ | 55 | ||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
75
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Assets | Assets | ||||||||||||||||||||
| Current Assets | Current Assets | ||||||||||||||||||||
| Cash and cash equivalents | $ | 485 | $ | 341 | |||||||||||||||||
| Accounts receivable (less reserve: 2017, $51; 2016, $54) | |||||||||||||||||||||
| Accounts receivable (less reserve: 2023, $123; 2022, $87) | Accounts receivable (less reserve: 2023, $123; 2022, $87) | ||||||||||||||||||||
| Customer | 681 | 666 | |||||||||||||||||||
| Other | 100 | 46 | |||||||||||||||||||
| Unbilled revenues | 543 | 480 | |||||||||||||||||||
| Unbilled revenues (less reserve: 2023, $4; 2022, $6) | |||||||||||||||||||||
| Fuel, materials and supplies | 320 | 356 | |||||||||||||||||||
| Prepayments | 66 | 63 | |||||||||||||||||||
| Price risk management assets | 49 | 63 | |||||||||||||||||||
| Regulatory assets | |||||||||||||||||||||
| Other current assets | 50 | 52 | |||||||||||||||||||
| Total Current Assets | |||||||||||||||||||||
| Total Current Assets | |||||||||||||||||||||
| Total Current Assets | 2,294 | 2,067 | |||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Regulated utility plant | 38,228 | 34,674 | |||||||||||||||||||
| Less: accumulated depreciation - regulated utility plant | 6,785 | 6,013 | |||||||||||||||||||
| Regulated utility plant, net | 31,443 | 28,661 | |||||||||||||||||||
| Non-regulated property, plant and equipment | 384 | 413 | |||||||||||||||||||
| Less: accumulated depreciation - non-regulated property, plant and equipment | 110 | 134 | |||||||||||||||||||
| Non-regulated property, plant and equipment, net | 274 | 279 | |||||||||||||||||||
| Construction work in progress | 1,375 | 1,134 | |||||||||||||||||||
| Property, Plant and Equipment, net | 33,092 | 30,074 | |||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Regulatory assets | 1,504 | 1,918 | |||||||||||||||||||
| Goodwill | 3,258 | 3,060 | |||||||||||||||||||
| Other intangibles | 697 | 700 | |||||||||||||||||||
| Pension benefit asset | 284 | 9 | |||||||||||||||||||
| Price risk management assets | 215 | 336 | |||||||||||||||||||
| Other noncurrent assets | 135 | 151 | |||||||||||||||||||
| Other noncurrent assets (less reserve for accounts receivable: 2023, $2; 2022, $2) | |||||||||||||||||||||
| Total Other Noncurrent Assets | 6,093 | 6,174 | |||||||||||||||||||
| Total Assets | $ | 41,479 | $ | 38,315 | |||||||||||||||||
| Total Assets | |||||||||||||||||||||
| Total Assets | |||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Liabilities and Equity | Liabilities and Equity | ||||||||||||||||||||
| Current Liabilities | Current Liabilities | ||||||||||||||||||||
| Short-term debt | $ | 1,080 | $ | 923 | |||||||||||||||||
| Long-term debt due within one year | 348 | 518 | |||||||||||||||||||
| Accounts payable | 924 | 820 | |||||||||||||||||||
| Taxes | 105 | 101 | |||||||||||||||||||
| Interest | 282 | 270 | |||||||||||||||||||
| Dividends | 273 | 259 | |||||||||||||||||||
| Customer deposits | 292 | 276 | |||||||||||||||||||
| Regulatory liabilities | 95 | 101 | |||||||||||||||||||
| Other current liabilities | 624 | 569 | |||||||||||||||||||
| Total Current Liabilities | |||||||||||||||||||||
| Total Current Liabilities | |||||||||||||||||||||
| Total Current Liabilities | 4,023 | 3,837 | |||||||||||||||||||
| Long-term Debt | 19,847 | 17,808 | |||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred income taxes | 2,462 | 3,889 | |||||||||||||||||||
| Investment tax credits | 129 | 132 | |||||||||||||||||||
| Accrued pension obligations | 800 | 1,001 | |||||||||||||||||||
| Asset retirement obligations | 312 | 428 | |||||||||||||||||||
| Regulatory liabilities | 2,704 | 899 | |||||||||||||||||||
| Other deferred credits and noncurrent liabilities | 441 | 422 | |||||||||||||||||||
| Total Deferred Credits and Other Noncurrent Liabilities | 6,848 | 6,771 | |||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 6 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Common stock - $0.01 par value (a) | 7 | 7 | |||||||||||||||||||
| Additional paid-in capital | 10,305 | 9,841 | |||||||||||||||||||
| Treasury stock | |||||||||||||||||||||
| Earnings reinvested | 3,871 | 3,829 | |||||||||||||||||||
| Accumulated other comprehensive loss | (3,422 | ) | (3,778 | ) | |||||||||||||||||
| Total Shareowners' Common Equity | |||||||||||||||||||||
| Noncontrolling interests | Noncontrolling interests | — | 3 | ||||||||||||||||||
| Total Equity | 10,761 | 9,899 | |||||||||||||||||||
| Total Liabilities and Equity | $ | 41,479 | $ | 38,315 | |||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
(a)1,560,000 shares authorized; 770,013 shares issued and 737,130 shares outstanding at December 31, 2023. 1,560,000 shares authorized; 770,013 shares issued and 736,487 shares outstanding at December 31, 2022.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
77
CONSOLIDATED STATEMENTS OF EQUITY
PPL Corporation and Subsidiaries
(Millions of Dollars)
| PPL Shareowners | ||||||||||||||||||||||
Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Accumulated other comprehensive loss | Total | |||||||||||||||||
| December 31, 2014 | 665,849 | $ | 7 | $ | 9,433 | $ | 6,462 | $ | (2,274 | ) | $ | 13,628 | ||||||||||
| Common stock issued | 8,008 | 249 | 249 | |||||||||||||||||||
| Stock-based compensation | 5 | 5 | ||||||||||||||||||||
| Net income | 682 | 682 | ||||||||||||||||||||
| Dividends and dividend equivalents | (1,010 | ) | (1,010 | ) | ||||||||||||||||||
| Distribution of PPL Energy Supply (Note 8) | (3,181 | ) | (24 | ) | (3,205 | ) | ||||||||||||||||
| Other comprehensive income (loss) | (430 | ) | (430 | ) | ||||||||||||||||||
| December 31, 2015 | 673,857 | $ | 7 | $ | 9,687 | $ | 2,953 | $ | (2,728 | ) | $ | 9,919 | ||||||||||
| Common stock issued | 5,874 | 185 | 185 | |||||||||||||||||||
| Stock-based compensation | (31 | ) | (31 | ) | ||||||||||||||||||
| Net income | 1,902 | 1,902 | ||||||||||||||||||||
| Dividends and dividend equivalents | (1,033 | ) | (1,033 | ) | ||||||||||||||||||
| Other comprehensive income (loss) | (1,050 | ) | (1,050 | ) | ||||||||||||||||||
| Adoption of stock-based compensation guidance cumulative effect adjustment (Note 1) | 7 | 7 | ||||||||||||||||||||
| December 31, 2016 | 679,731 | $ | 7 | $ | 9,841 | $ | 3,829 | $ | (3,778 | ) | $ | 9,899 | ||||||||||
| Common stock issued | 13,667 | 482 | 482 | |||||||||||||||||||
| Stock-based compensation | (18 | ) | (18 | ) | ||||||||||||||||||
| Net income | 1,128 | 1,128 | ||||||||||||||||||||
| Dividends and dividend equivalents | (1,086 | ) | (1,086 | ) | ||||||||||||||||||
| Other comprehensive income (loss) | 356 | 356 | ||||||||||||||||||||
| December 31, 2017 | 693,398 | $ | 7 | $ | 10,305 | $ | 3,871 | $ | (3,422 | ) | $ | 10,761 | ||||||||||
| Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Treasury Stock | Earnings reinvested | Accumulated other comprehensive loss | Noncontrolling interest | Total | ||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2020 | 768,907 | $ | 8 | $ | 12,270 | $ | — | $ | 5,315 | $ | (4,220) | $ | — | $ | 13,373 | ||||||||||||||||||||||||||||||||||||||
| Common stock issued | 983 | 29 | 29 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Treasury stock | (34,778) | (1,003) | (1,003) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | 4 | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | (1,480) | (1,480) | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends and dividend equivalents (b) | (1,263) | (1,263) | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | 4,063 | 4,063 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2021 | 735,112 | $ | 8 | $ | 12,303 | $ | (1,003) | $ | 2,572 | $ | (157) | $ | — | $ | 13,723 | ||||||||||||||||||||||||||||||||||||||
| Common stock issued | 123 | 5 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Treasury stock | 1,252 | 36 | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | 9 | 9 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | 756 | 756 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends and dividend equivalents (b) | (647) | (647) | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Preferred stock | 3 | 3 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | 33 | 33 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | 736,487 | $ | 8 | $ | 12,317 | $ | (967) | $ | 2,681 | $ | (124) | $ | 3 | $ | 13,918 | ||||||||||||||||||||||||||||||||||||||
| Treasury stock issued | 643 | 4 | 19 | 23 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | 5 | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | 740 | 740 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends and dividend equivalents (b) | (711) | (711) | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Preferred stock | (3) | (3) | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | (39) | (39) | |||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | 737,130 | $ | 8 | $ | 12,326 | $ | (948) | $ | 2,710 | $ | (163) | $ | — | $ | 13,933 | ||||||||||||||||||||||||||||||||||||||
(a)Shares in thousands. Each share entitles the holder to one vote on any question presented at any shareowners' meeting.
(b)Dividends declared per share of common stock at December 31, 2023, 2022 and 2021 were: $0.960, $0.875 and $1.660.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
(THIS PAGE LEFT BLANK INTENTIONALLY.)
79
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
| 2023 | 2022 | 2021 | |||||||||||||||
| Operating Revenues | $ | 3,008 | $ | 3,030 | $ | 2,402 | |||||||||||
| Operating Expenses | |||||||||||||||||
| Operation | |||||||||||||||||
| Energy purchases | 992 | 1,048 | 566 | ||||||||||||||
| Other operation and maintenance | 605 | 605 | 557 | ||||||||||||||
| Depreciation | 397 | 393 | 424 | ||||||||||||||
| Taxes, other than income | 143 | 149 | 120 | ||||||||||||||
| Total Operating Expenses | 2,137 | 2,195 | 1,667 | ||||||||||||||
| Operating Income | 871 | 835 | 735 | ||||||||||||||
| Other Income (Expense) - net | 39 | 30 | 21 | ||||||||||||||
| Interest Income from Affiliate | — | 5 | 5 | ||||||||||||||
| Interest Expense | 223 | 171 | 162 | ||||||||||||||
| Income Before Income Taxes | 687 | 699 | 599 | ||||||||||||||
| Income Taxes | 168 | 174 | 154 | ||||||||||||||
| Net Income (a) | $ | 519 | $ | 525 | $ | 445 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Operating Revenues | $ | 2,195 | $ | 2,156 | $ | 2,124 | |||||
| Operating Expenses | |||||||||||
| Operation | |||||||||||
| Energy purchases | 507 | 535 | 657 | ||||||||
| Energy purchases from affiliate | — | — | 14 | ||||||||
| Other operation and maintenance | 571 | 599 | 607 | ||||||||
| Depreciation | 309 | 253 | 214 | ||||||||
| Taxes, other than income | 107 | 105 | 94 | ||||||||
| Total Operating Expenses | 1,494 | 1,492 | 1,586 | ||||||||
| Operating Income | 701 | 664 | 538 | ||||||||
| Other Income (Expense) - net | 11 | 17 | 8 | ||||||||
| Interest Income from Affiliate | 5 | — | — | ||||||||
| Interest Expense | 142 | 129 | 130 | ||||||||
| Income Before Income Taxes | 575 | 552 | 416 | ||||||||
| Income Taxes | 213 | 212 | 164 | ||||||||
| Net Income (a) | $ | 362 | $ | 340 | $ | 252 | |||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
80
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Cash Flows from Operating Activities | Cash Flows from Operating Activities | |||||||||||||||||||||||||||||||||
| Net income | $ | 362 | $ | 340 | $ | 252 | ||||||||||||||||||||||||||||
| Adjustments to reconcile net income to net cash provided by (used in) operating activities | Adjustments to reconcile net income to net cash provided by (used in) operating activities | |||||||||||||||||||||||||||||||||
| Depreciation | 309 | 253 | 214 | |||||||||||||||||||||||||||||||
| Amortization | 33 | 32 | 26 | |||||||||||||||||||||||||||||||
| Defined benefit plans - expense | 12 | 11 | 16 | |||||||||||||||||||||||||||||||
| Defined benefit plans expense (income) | ||||||||||||||||||||||||||||||||||
| Deferred income taxes and investment tax credits | 258 | 221 | 220 | |||||||||||||||||||||||||||||||
| Other | (8 | ) | (13 | ) | (12 | ) | ||||||||||||||||||||||||||||
| Change in current assets and current liabilities | Change in current assets and current liabilities | |||||||||||||||||||||||||||||||||
| Accounts receivable | (57 | ) | 16 | 50 | ||||||||||||||||||||||||||||||
| Accounts payable | 3 | 58 | (107 | ) | ||||||||||||||||||||||||||||||
| Unbilled revenues | (13 | ) | (23 | ) | 22 | |||||||||||||||||||||||||||||
| Materials and supplies | ||||||||||||||||||||||||||||||||||
| Prepayments | 3 | 43 | (1 | ) | ||||||||||||||||||||||||||||||
| Regulatory assets and liabilities | (5 | ) | (62 | ) | 35 | |||||||||||||||||||||||||||||
| Regulatory assets and liabilities, net | ||||||||||||||||||||||||||||||||||
| Taxes payable | (4 | ) | (12 | ) | (108 | ) | ||||||||||||||||||||||||||||
| Accrued interest | ||||||||||||||||||||||||||||||||||
| Other | (1 | ) | (7 | ) | 21 | |||||||||||||||||||||||||||||
| Other operating activities | Other operating activities | |||||||||||||||||||||||||||||||||
| Defined benefit plans - funding | (24 | ) | — | (33 | ) | |||||||||||||||||||||||||||||
| Other assets | 15 | 19 | (10 | ) | ||||||||||||||||||||||||||||||
| Other liabilities | (3 | ) | (4 | ) | 17 | |||||||||||||||||||||||||||||
| Net cash provided by operating activities | 880 | 872 | 602 | |||||||||||||||||||||||||||||||
| Cash Flows from Investing Activities | ||||||||||||||||||||||||||||||||||
| Cash Flows from Investing Activities | ||||||||||||||||||||||||||||||||||
| Cash Flows from Investing Activities | ||||||||||||||||||||||||||||||||||
| Expenditures for property, plant and equipment | (1,244 | ) | (1,125 | ) | (1,097 | ) | ||||||||||||||||||||||||||||
| Expenditures for intangible assets | (10 | ) | (9 | ) | (10 | ) | ||||||||||||||||||||||||||||
| Net (increase) decrease in notes receivable from affiliate | ||||||||||||||||||||||||||||||||||
| Other investing activities | 2 | 4 | (1 | ) | ||||||||||||||||||||||||||||||
| Net cash used in investing activities | (1,252 | ) | (1,130 | ) | (1,108 | ) | ||||||||||||||||||||||||||||
| Cash Flows from Financing Activities | ||||||||||||||||||||||||||||||||||
| Cash Flows from Financing Activities | ||||||||||||||||||||||||||||||||||
| Cash Flows from Financing Activities | ||||||||||||||||||||||||||||||||||
| Issuance of long-term debt | 470 | 224 | 348 | |||||||||||||||||||||||||||||||
| Retirement of long-term debt | — | (224 | ) | (100 | ) | |||||||||||||||||||||||||||||
| Contributions from PPL | 575 | 220 | 275 | |||||||||||||||||||||||||||||||
| Contributions from parent | ||||||||||||||||||||||||||||||||||
| Payment of common stock dividends to parent | (336 | ) | (288 | ) | (181 | ) | ||||||||||||||||||||||||||||
| Net increase (decrease) in short-term debt | (295 | ) | 295 | — | ||||||||||||||||||||||||||||||
| Return of capital to parent | ||||||||||||||||||||||||||||||||||
| Net increase in short-term debt | ||||||||||||||||||||||||||||||||||
| Debt issuance costs | ||||||||||||||||||||||||||||||||||
| Other financing activities | (6 | ) | (3 | ) | (3 | ) | ||||||||||||||||||||||||||||
| Net cash provided by financing activities | 408 | 224 | 339 | |||||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | ||||||||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 36 | (34 | ) | (167 | ) | |||||||||||||||||||||||||||||
| Cash and Cash Equivalents at Beginning of Period | 13 | 47 | 214 | |||||||||||||||||||||||||||||||
| Cash and Cash Equivalents at End of Period | $ | 49 | $ | 13 | $ | 47 | ||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid during the period for: | Cash paid during the period for: | |||||||||||||||||||||||||||||||||
| Interest - net of amount capitalized | $ | 128 | $ | 115 | $ | 117 | ||||||||||||||||||||||||||||
| Income taxes - net | $ | 4 | $ | (48 | ) | $ | 38 | |||||||||||||||||||||||||||
| Significant non-cash transactions: | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | $ | 133 | $ | 126 | $ | 98 | ||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
| 2023 | 2022 | ||||||||||
| Assets | |||||||||||
| Current Assets | |||||||||||
| Cash and cash equivalents | $ | 51 | $ | 25 | |||||||
| Accounts receivable (less reserve: 2023, $46; 2022, $28) | |||||||||||
| Customer | 434 | 357 | |||||||||
| Other | 8 | 12 | |||||||||
| Accounts receivable from affiliates | 10 | 3 | |||||||||
| Unbilled revenues (less reserve: 2023, $2; 2022, $2) | 149 | 224 | |||||||||
| Materials and supplies | 99 | 69 | |||||||||
| Prepayments | 44 | 34 | |||||||||
| Regulatory assets | 57 | 13 | |||||||||
| Other current assets | 17 | 22 | |||||||||
| Total Current Assets | 869 | 759 | |||||||||
| Property, Plant and Equipment | |||||||||||
| Regulated utility plant | 15,575 | 14,794 | |||||||||
| Less: accumulated depreciation - regulated utility plant | 3,822 | 3,544 | |||||||||
| Regulated utility plant, net | 11,753 | 11,250 | |||||||||
| Construction work in progress | 680 | 593 | |||||||||
| Property, Plant and Equipment, net | 12,433 | 11,843 | |||||||||
| Other Noncurrent Assets | |||||||||||
| Regulatory assets | 598 | 568 | |||||||||
| Intangibles | 269 | 269 | |||||||||
| Other noncurrent assets (less reserve for accounts receivable: 2023, $2; 2022, $2) | 125 | 126 | |||||||||
| Total Other Noncurrent Assets | 992 | 963 | |||||||||
| Total Assets | $ | 14,294 | $ | 13,565 | |||||||
| 2017 | 2016 | ||||||
| Assets | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 49 | $ | 13 | |||
| Accounts receivable (less reserve: 2017, $24; 2016, $28) | |||||||
| Customer | 279 | 272 | |||||
| Other | 71 | 21 | |||||
| Unbilled revenues | 127 | 114 | |||||
| Materials and supplies | 34 | 32 | |||||
| Prepayments | 6 | 9 | |||||
| Regulatory assets | 16 | 19 | |||||
| Other current assets | 6 | 8 | |||||
| Total Current Assets | 588 | 488 | |||||
| Property, Plant and Equipment | |||||||
| Regulated utility plant | 10,785 | 9,654 | |||||
| Less: accumulated depreciation - regulated utility plant | 2,778 | 2,714 | |||||
| Regulated utility plant, net | 8,007 | 6,940 | |||||
| Construction work in progress | 508 | 641 | |||||
| Property, Plant and Equipment, net | 8,515 | 7,581 | |||||
| Other Noncurrent Assets | |||||||
| Regulatory assets | 709 | 1,094 | |||||
| Intangibles | 259 | 251 | |||||
| Other noncurrent assets | 11 | 12 | |||||
| Total Other Noncurrent Assets | 979 | 1,357 | |||||
| Total Assets | $ | 10,082 | $ | 9,426 | |||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
82
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Liabilities and Equity | Liabilities and Equity | ||||||||||||||||||||
| Current Liabilities | Current Liabilities | ||||||||||||||||||||
| Short-term debt | $ | — | $ | 295 | |||||||||||||||||
| Long-term debt due within one year | — | 224 | |||||||||||||||||||
| Accounts payable | 386 | 367 | |||||||||||||||||||
| Accounts payable to affiliates | 31 | 42 | |||||||||||||||||||
| Taxes | 8 | 12 | |||||||||||||||||||
| Interest | 36 | 34 | |||||||||||||||||||
| Regulatory liabilities | |||||||||||||||||||||
| Regulatory liabilities | |||||||||||||||||||||
| Regulatory liabilities | 86 | 83 | |||||||||||||||||||
| Other current liabilities | 98 | 101 | |||||||||||||||||||
| Total Current Liabilities | 645 | 1,158 | |||||||||||||||||||
| Long-term Debt | 3,298 | 2,607 | |||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred income taxes | 1,154 | 1,899 | |||||||||||||||||||
| Accrued pension obligations | 246 | 281 | |||||||||||||||||||
| Regulatory liabilities | |||||||||||||||||||||
| Regulatory liabilities | |||||||||||||||||||||
| Regulatory liabilities | 668 | — | |||||||||||||||||||
| Other deferred credits and noncurrent liabilities | 79 | 90 | |||||||||||||||||||
| Total Deferred Credits and Other Noncurrent Liabilities | 2,147 | 2,270 | |||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 6 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Common stock - no par value (a) | 364 | 364 | |||||||||||||||||||
| Additional paid-in capital | 2,729 | 2,154 | |||||||||||||||||||
| Earnings reinvested | 899 | 873 | |||||||||||||||||||
| Total Equity | 3,992 | 3,391 | |||||||||||||||||||
| Total Liabilities and Equity | $ | 10,082 | $ | 9,426 | |||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
(a)170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2023 and December 31, 2022.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
83
CONSOLIDATED STATEMENTS OF EQUITY
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Total | ||||||||||||||
| December 31, 2014 | 66,368 | $ | 364 | $ | 1,603 | $ | 750 | $ | 2,717 | |||||||||
| Net income | 252 | 252 | ||||||||||||||||
| Capital contributions from PPL (b) | 331 | 331 | ||||||||||||||||
| Dividends declared on common stock | (181 | ) | (181 | ) | ||||||||||||||
| December 31, 2015 | 66,368 | $ | 364 | $ | 1,934 | $ | 821 | $ | 3,119 | |||||||||
| Net income | 340 | 340 | ||||||||||||||||
| Capital contributions from PPL | 220 | 220 | ||||||||||||||||
| Dividends declared on common stock | (288 | ) | (288 | ) | ||||||||||||||
| December 31, 2016 | 66,368 | $ | 364 | $ | 2,154 | $ | 873 | $ | 3,391 | |||||||||
| Net income | 362 | 362 | ||||||||||||||||
| Capital contributions from PPL | 575 | 575 | ||||||||||||||||
| Dividends declared on common stock | (336 | ) | (336 | ) | ||||||||||||||
| December 31, 2017 | 66,368 | $ | 364 | $ | 2,729 | $ | 899 | $ | 3,992 | |||||||||
| Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Total | |||||||||||||||||||||||||
| December 31, 2020 | 66,368 | $ | 364 | $ | 3,753 | $ | 1,007 | $ | 5,124 | ||||||||||||||||||||
| Net income | 445 | 445 | |||||||||||||||||||||||||||
| Capital contributions from parent | 1,075 | 1,075 | |||||||||||||||||||||||||||
| Return of capital to parent | (574) | (574) | |||||||||||||||||||||||||||
| Dividends declared on common stock | (334) | (334) | |||||||||||||||||||||||||||
| December 31, 2021 | 66,368 | $ | 364 | $ | 4,254 | $ | 1,118 | $ | 5,736 | ||||||||||||||||||||
| Net income | 525 | 525 | |||||||||||||||||||||||||||
| Return of capital to parent | (170) | (170) | |||||||||||||||||||||||||||
| Dividends declared on common stock | (340) | (340) | |||||||||||||||||||||||||||
| December 31, 2022 | 66,368 | $ | 364 | $ | 4,084 | $ | 1,303 | $ | 5,751 | ||||||||||||||||||||
| Net income | 519 | 519 | |||||||||||||||||||||||||||
| Capital contributions from parent | 206 | 206 | |||||||||||||||||||||||||||
| Return of capital to parent | (250) | (250) | |||||||||||||||||||||||||||
| Dividends declared on common stock | (323) | (323) | |||||||||||||||||||||||||||
| December 31, 2023 | 66,368 | $ | 364 | $ | 4,040 | $ | 1,499 | $ | 5,903 | ||||||||||||||||||||
(a)Shares in thousands. All common shares of PPL Electric stock are owned by PPL.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
84
| 2017 | 2016 | 2015 | |||||||||
| Operating Revenues | $ | 3,156 | $ | 3,141 | $ | 3,115 | |||||
| Operating Expenses | |||||||||||
| Operation | |||||||||||
| Fuel | 759 | 791 | 863 | ||||||||
| Energy purchases | 178 | 171 | 184 | ||||||||
| Other operation and maintenance | 806 | 804 | 837 | ||||||||
| Depreciation | 439 | 404 | 382 | ||||||||
| Taxes, other than income | 65 | 62 | 57 | ||||||||
| Total Operating Expenses | 2,247 | 2,232 | 2,323 | ||||||||
| Operating Income | 909 | 909 | 792 | ||||||||
| Other Income (Expense) - net | (3 | ) | (9 | ) | (8 | ) | |||||
| Interest Expense | 197 | 197 | 178 | ||||||||
| Interest Expense with Affiliate | 18 | 17 | 3 | ||||||||
| Income Before Income Taxes | 691 | 686 | 603 | ||||||||
| Income Taxes | 375 | 257 | 239 | ||||||||
| Net Income | $ | 316 | $ | 429 | $ | 364 | |||||
| 2017 | 2016 | 2015 | |||||||||
| Net income | $ | 316 | $ | 429 | $ | 364 | |||||
| Other comprehensive income (loss): | |||||||||||
| Amounts arising during the period - gains (losses), net of tax (expense) benefit: | |||||||||||
| Defined benefit plans: | |||||||||||
| Prior service costs, net of tax of $1, $0, $2 | (2 | ) | — | (3 | ) | ||||||
| Net actuarial gain (loss), net of tax of $13, $18, $2 | (23 | ) | (27 | ) | (4 | ) | |||||
| Reclassifications to net income - (gains) losses, net of tax expense (benefit): | |||||||||||
| Equity investees' other comprehensive (income) loss, net of tax of $0, $0, $0 | 1 | (1 | ) | — | |||||||
| Defined benefit plans: | |||||||||||
| Prior service costs, net of tax of ($1), ($1), ($1) | 1 | 2 | 1 | ||||||||
| Net actuarial (gain) loss, net of tax of ($2), ($1), ($3) | 5 | 2 | 5 | ||||||||
| Total other comprehensive income (loss) | (18 | ) | (24 | ) | (1 | ) | |||||
| Comprehensive income | $ | 298 | $ | 405 | $ | 363 | |||||
| 2017 | 2016 | 2015 | |||||||||
| Cash Flows from Operating Activities | |||||||||||
| Net income | $ | 316 | $ | 429 | $ | 364 | |||||
| Adjustments to reconcile net income to net cash provided by (used in) operating activities | |||||||||||
| Depreciation | 439 | 404 | 382 | ||||||||
| Amortization | 24 | 29 | 27 | ||||||||
| Defined benefit plans - expense | 25 | 27 | 38 | ||||||||
| Deferred income taxes and investment tax credits | 294 | 291 | 236 | ||||||||
| Other | — | — | 2 | ||||||||
| Change in current assets and current liabilities | |||||||||||
| Accounts receivable | (12 | ) | (31 | ) | 24 | ||||||
| Accounts payable | (9 | ) | 24 | (58 | ) | ||||||
| Accounts payable to affiliates | 2 | 1 | (2 | ) | |||||||
| Unbilled revenues | (33 | ) | (23 | ) | 20 | ||||||
| Fuel, materials and supplies | 45 | 2 | 6 | ||||||||
| Income tax receivable | — | 1 | 135 | ||||||||
| Taxes payable | 27 | (7 | ) | 10 | |||||||
| Accrued interest | — | — | 9 | ||||||||
| Other | 34 | (6 | ) | 23 | |||||||
| Other operating activities | |||||||||||
| Defined benefit plans - funding | (35 | ) | (85 | ) | (70 | ) | |||||
| Settlement of interest rate swaps | — | (9 | ) | (88 | ) | ||||||
| Expenditures for asset retirement obligations | (34 | ) | (26 | ) | (7 | ) | |||||
| Other assets | 8 | 2 | (7 | ) | |||||||
| Other liabilities | 8 | 4 | 19 | ||||||||
| Net cash provided by operating activities | 1,099 | 1,027 | 1,063 | ||||||||
| Cash Flows from Investing Activities | |||||||||||
| Expenditures for property, plant and equipment | (892 | ) | (791 | ) | (1,210 | ) | |||||
| Other investing activities | 4 | 1 | 7 | ||||||||
| Net cash used in investing activities | (888 | ) | (790 | ) | (1,203 | ) | |||||
| Cash Flows from Financing Activities | |||||||||||
| Net increase in notes payable with affiliates | 62 | 109 | 13 | ||||||||
| Issuance of long-term note with affiliate | — | — | 400 | ||||||||
| Issuance of long-term debt | 160 | 221 | 1,050 | ||||||||
| Retirement of long-term debt | (70 | ) | (246 | ) | (900 | ) | |||||
| Distributions to member | (402 | ) | (316 | ) | (219 | ) | |||||
| Contributions from member | — | 61 | 125 | ||||||||
| Net increase (decrease) in short-term debt | 59 | (80 | ) | (310 | ) | ||||||
Other financing activities | (3 | ) | (3 | ) | (10 | ) | |||||
| Net cash provided by (used in) financing activities | (194 | ) | (254 | ) | 149 | ||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 17 | (17 | ) | 9 | |||||||
| Cash and Cash Equivalents at Beginning of Period | 13 | 30 | 21 | ||||||||
| Cash and Cash Equivalents at End of Period | $ | 30 | $ | 13 | $ | 30 | |||||
| Supplemental Disclosures of Cash Flow Information | |||||||||||
| Cash paid (received) during the period for: | |||||||||||
| Interest - net of amount capitalized | $ | 204 | $ | 198 | $ | 163 | |||||
| Income taxes - net | $ | 48 | $ | (24 | ) | $ | (139 | ) | |||
| Significant non-cash transactions: | |||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | $ | 174 | $ | 104 | $ | 150 | |||||
| 2017 | 2016 | ||||||
| Assets | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | 30 | $ | 13 | |||
| Accounts receivable (less reserve: 2017, $25; 2016, $24) | |||||||
| Customer | 246 | 235 | |||||
| Other | 44 | 17 | |||||
| Unbilled revenues | 203 | 170 | |||||
| Fuel, materials and supplies | 254 | 297 | |||||
| Prepayments | 25 | 24 | |||||
| Regulatory assets | 18 | 20 | |||||
| Other current assets | 8 | 4 | |||||
| Total Current Assets | 828 | 780 | |||||
| Property, Plant and Equipment | |||||||
| Regulated utility plant | 13,187 | 12,746 | |||||
| Less: accumulated depreciation - regulated utility plant | 1,785 | 1,465 | |||||
| Regulated utility plant, net | 11,402 | 11,281 | |||||
| Construction work in progress | 627 | 317 | |||||
| Property, Plant and Equipment, net | 12,029 | 11,598 | |||||
| Other Noncurrent Assets | |||||||
| Regulatory assets | 795 | 824 | |||||
| Goodwill | 996 | 996 | |||||
| Other intangibles | 86 | 95 | |||||
| Other noncurrent assets | 68 | 78 | |||||
| Total Other Noncurrent Assets | 1,945 | 1,993 | |||||
| Total Assets | $ | 14,802 | $ | 14,371 | |||
| 2017 | 2016 | ||||||
| Liabilities and Equity | |||||||
| Current Liabilities | |||||||
| Short-term debt | $ | 244 | $ | 185 | |||
| Long-term debt due within one year | 98 | 194 | |||||
| Notes payable with affiliates | 225 | 163 | |||||
| Accounts payable | 338 | 251 | |||||
| Accounts payable to affiliates | 7 | 6 | |||||
| Customer deposits | 58 | 56 | |||||
| Taxes | 66 | 39 | |||||
| Price risk management liabilities | 4 | 4 | |||||
| Regulatory liabilities | 9 | 18 | |||||
| Interest | 32 | 32 | |||||
| Asset retirement obligations | 85 | 60 | |||||
| Other current liabilities | 161 | 119 | |||||
| Total Current Liabilities | 1,327 | 1,127 | |||||
| Long-term Debt | |||||||
| Long-term debt | 4,661 | 4,471 | |||||
| Long-term debt to affiliate | 400 | 400 | |||||
| Total Long-term Debt | 5,061 | 4,871 | |||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||
| Deferred income taxes | 866 | 1,735 | |||||
| Investment tax credits | 129 | 132 | |||||
| Price risk management liabilities | 22 | 27 | |||||
| Accrued pension obligations | 365 | 350 | |||||
| Asset retirement obligations | 271 | 373 | |||||
| Regulatory liabilities | 2,036 | 899 | |||||
| Other deferred credits and noncurrent liabilities | 162 | 190 | |||||
| Total Deferred Credits and Other Noncurrent Liabilities | 3,851 | 3,706 | |||||
| Commitments and Contingent Liabilities (Notes 6 and 13) | |||||||
| Member's equity | 4,563 | 4,667 | |||||
| Total Liabilities and Equity | $ | 14,802 | $ | 14,371 | |||
Member's Equity | |||
| December 31, 2014 | $ | 4,248 | |
| Net income | 364 | ||
| Contributions from member | 125 | ||
| Distributions to member | (219 | ) | |
| Other comprehensive income (loss) | (1 | ) | |
| December 31, 2015 | $ | 4,517 | |
| Net income | $ | 429 | |
| Contributions from member | 61 | ||
| Distributions to member | (316 | ) | |
| Other comprehensive income (loss) | (24 | ) | |
| December 31, 2016 | $ | 4,667 | |
| Net income | $ | 316 | |
| Distributions to member | (402 | ) | |
| Other comprehensive income (loss) | (18 | ) | |
| December 31, 2017 | $ | 4,563 | |
(THIS PAGE LEFT BLANK INTENTIONALLY.)
85
STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Operating Revenues | Operating Revenues | |||||||||||||||||||||||||||||||||
| Retail and wholesale | $ | 1,422 | $ | 1,406 | $ | 1,407 | ||||||||||||||||||||||||||||
| Electric revenue from affiliate | 31 | 24 | 37 | |||||||||||||||||||||||||||||||
| Total Operating Revenues | 1,453 | 1,430 | 1,444 | |||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operation | Operation | |||||||||||||||||||||||||||||||||
| Fuel | 292 | 301 | 329 | |||||||||||||||||||||||||||||||
| Energy purchases | 160 | 153 | 166 | |||||||||||||||||||||||||||||||
| Energy purchases from affiliate | 10 | 14 | 20 | |||||||||||||||||||||||||||||||
| Other operation and maintenance | 355 | 355 | 377 | |||||||||||||||||||||||||||||||
| Depreciation | 183 | 170 | 162 | |||||||||||||||||||||||||||||||
| Taxes, other than income | 33 | 32 | 28 | |||||||||||||||||||||||||||||||
| Total Operating Expenses | 1,033 | 1,025 | 1,082 | |||||||||||||||||||||||||||||||
| Operating Income | 420 | 405 | 362 | |||||||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) – net | (5 | ) | (5 | ) | (6 | ) | ||||||||||||||||||||||||||||
| Other Income (Expense) – net | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) – net | ||||||||||||||||||||||||||||||||||
| Interest Income from Affiliates | ||||||||||||||||||||||||||||||||||
| Interest Income from Affiliates | ||||||||||||||||||||||||||||||||||
| Interest Income from Affiliates | ||||||||||||||||||||||||||||||||||
| Interest Expense | ||||||||||||||||||||||||||||||||||
| Interest Expense | ||||||||||||||||||||||||||||||||||
| Interest Expense | 71 | 71 | 57 | |||||||||||||||||||||||||||||||
| Income Before Income Taxes | 344 | 329 | 299 | |||||||||||||||||||||||||||||||
| Income Before Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Before Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | 131 | 126 | 114 | |||||||||||||||||||||||||||||||
| Net Income (a) | $ | 213 | $ | 203 | $ | 185 | ||||||||||||||||||||||||||||
| Net Income (a) | ||||||||||||||||||||||||||||||||||
| Net Income (a) | ||||||||||||||||||||||||||||||||||
(a)Net income equals comprehensive income.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
86
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Cash Flows from Operating Activities | Cash Flows from Operating Activities | |||||||||||||||||||||||||||||||||
| Net income | $ | 213 | $ | 203 | $ | 185 | ||||||||||||||||||||||||||||
| Adjustments to reconcile net income to net cash provided by (used in) operating activities | Adjustments to reconcile net income to net cash provided by (used in) operating activities | |||||||||||||||||||||||||||||||||
| Depreciation | 183 | 170 | 162 | |||||||||||||||||||||||||||||||
| Amortization | 14 | 14 | 11 | |||||||||||||||||||||||||||||||
| Defined benefit plans - expense | 7 | 8 | 12 | |||||||||||||||||||||||||||||||
| Deferred income taxes and investment tax credits | 126 | 147 | 126 | |||||||||||||||||||||||||||||||
| Other | 1 | — | 8 | |||||||||||||||||||||||||||||||
| Change in current assets and current liabilities | Change in current assets and current liabilities | |||||||||||||||||||||||||||||||||
| Accounts receivable | (7 | ) | (22 | ) | 19 | |||||||||||||||||||||||||||||
| Accounts receivable from affiliates | 4 | (16 | ) | 11 | ||||||||||||||||||||||||||||||
| Accounts payable | (7 | ) | 31 | (29 | ) | |||||||||||||||||||||||||||||
| Accounts payable to affiliates | (4 | ) | 1 | 5 | ||||||||||||||||||||||||||||||
| Unbilled revenues | (16 | ) | (8 | ) | 9 | |||||||||||||||||||||||||||||
| Fuel, materials and supplies | 12 | 8 | 3 | |||||||||||||||||||||||||||||||
| Income tax receivable | — | 4 | 70 | |||||||||||||||||||||||||||||||
| Regulatory assets and liabilities, net | ||||||||||||||||||||||||||||||||||
| Taxes payable | ||||||||||||||||||||||||||||||||||
| Taxes payable | ||||||||||||||||||||||||||||||||||
| Taxes payable | (15 | ) | 20 | 1 | ||||||||||||||||||||||||||||||
| Accrued interest | — | — | 5 | |||||||||||||||||||||||||||||||
| Other | 11 | (7 | ) | 17 | ||||||||||||||||||||||||||||||
| Other operating activities | Other operating activities | |||||||||||||||||||||||||||||||||
| Defined benefit plans - funding | (4 | ) | (46 | ) | (26 | ) | ||||||||||||||||||||||||||||
| Settlement of interest rate swaps | — | (9 | ) | (44 | ) | |||||||||||||||||||||||||||||
| Expenditures for asset retirement obligations | ||||||||||||||||||||||||||||||||||
| Expenditures for asset retirement obligations | ||||||||||||||||||||||||||||||||||
| Expenditures for asset retirement obligations | (15 | ) | (18 | ) | (6 | ) | ||||||||||||||||||||||||||||
| Other assets | 5 | — | 11 | |||||||||||||||||||||||||||||||
| Other liabilities | 4 | 2 | 4 | |||||||||||||||||||||||||||||||
| Net cash provided by operating activities | 512 | 482 | 554 | |||||||||||||||||||||||||||||||
| Cash Flows from Investing Activities | Cash Flows from Investing Activities | |||||||||||||||||||||||||||||||||
| Expenditures for property, plant and equipment | (458 | ) | (439 | ) | (689 | ) | ||||||||||||||||||||||||||||
| Other investing activities | ||||||||||||||||||||||||||||||||||
| Net cash used in investing activities | (458 | ) | (439 | ) | (689 | ) | ||||||||||||||||||||||||||||
| Cash Flows from Financing Activities | Cash Flows from Financing Activities | |||||||||||||||||||||||||||||||||
| Net increase (decrease) in notes payable with affiliates | ||||||||||||||||||||||||||||||||||
| Issuance of long-term debt | 160 | 125 | 550 | |||||||||||||||||||||||||||||||
| Retirement of long-term debt | (70 | ) | (150 | ) | (250 | ) | ||||||||||||||||||||||||||||
| Payment of common stock dividends to parent | ||||||||||||||||||||||||||||||||||
| Payment of common stock dividends to parent | ||||||||||||||||||||||||||||||||||
| Payment of common stock dividends to parent | (192 | ) | (128 | ) | (119 | ) | ||||||||||||||||||||||||||||
| Contributions from parent | 30 | 71 | 90 | |||||||||||||||||||||||||||||||
| Return of capital to parent | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Net increase (decrease) in short-term debt | 30 | 27 | (122 | ) | ||||||||||||||||||||||||||||||
| Other financing activities | (2 | ) | (2 | ) | (5 | ) | ||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | (44 | ) | (57 | ) | 144 | |||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 10 | (14 | ) | 9 | ||||||||||||||||||||||||||||||
| Cash and Cash Equivalents at Beginning of Period | 5 | 19 | 10 | |||||||||||||||||||||||||||||||
| Cash and Cash Equivalents at End of Period | $ | 15 | $ | 5 | $ | 19 | ||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid during the period for: | Cash paid during the period for: | |||||||||||||||||||||||||||||||||
| Interest - net of amount capitalized | $ | 65 | $ | 65 | $ | 48 | ||||||||||||||||||||||||||||
| Income taxes - net | $ | 22 | $ | (43 | ) | $ | (81 | ) | ||||||||||||||||||||||||||
| Significant non-cash transactions: | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | $ | 92 | $ | 56 | $ | 97 | ||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
BALANCE SHEETS AT DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Assets | Assets | ||||||||||||||||||||
| Current Assets | Current Assets | ||||||||||||||||||||
| Cash and cash equivalents | $ | 15 | $ | 5 | |||||||||||||||||
| Accounts receivable (less reserve: 2017, $1; 2016, $2) | |||||||||||||||||||||
| Accounts receivable (less reserve: 2023, $6; 2022, $3) | Accounts receivable (less reserve: 2023, $6; 2022, $3) | ||||||||||||||||||||
| Customer | 116 | 109 | |||||||||||||||||||
| Other | 13 | 11 | |||||||||||||||||||
| Unbilled revenues | 91 | 75 | |||||||||||||||||||
| Unbilled revenues (less reserve: 2023, $0; 2022, $0) | |||||||||||||||||||||
| Accounts receivable from affiliates | 24 | 28 | |||||||||||||||||||
| Fuel, materials and supplies | 131 | 143 | |||||||||||||||||||
| Prepayments | 11 | 12 | |||||||||||||||||||
| Regulatory assets | |||||||||||||||||||||
| Regulatory assets | |||||||||||||||||||||
| Regulatory assets | 12 | 9 | |||||||||||||||||||
| Other current assets | 3 | 1 | |||||||||||||||||||
| Total Current Assets | |||||||||||||||||||||
| Total Current Assets | |||||||||||||||||||||
| Total Current Assets | 416 | 393 | |||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Regulated utility plant | 5,587 | 5,357 | |||||||||||||||||||
| Less: accumulated depreciation - regulated utility plant | 614 | 498 | |||||||||||||||||||
| Regulated utility plant, net | 4,973 | 4,859 | |||||||||||||||||||
| Construction work in progress | 305 | 133 | |||||||||||||||||||
| Property, Plant and Equipment, net | 5,278 | 4,992 | |||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Regulatory assets | 411 | 450 | |||||||||||||||||||
| Goodwill | 389 | 389 | |||||||||||||||||||
| Other intangibles | 53 | 59 | |||||||||||||||||||
| Other noncurrent assets | 12 | 17 | |||||||||||||||||||
| Total Other Noncurrent Assets | 865 | 915 | |||||||||||||||||||
| Total Assets | $ | 6,559 | $ | 6,300 | |||||||||||||||||
| Total Assets | |||||||||||||||||||||
| Total Assets | |||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
BALANCE SHEETS AT DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Liabilities and Equity | Liabilities and Equity | ||||||||||||||||||||
| Current Liabilities | Current Liabilities | ||||||||||||||||||||
| Short-term debt | $ | 199 | $ | 169 | |||||||||||||||||
| Long-term debt due within one year | 98 | 194 | |||||||||||||||||||
| Accounts payable | |||||||||||||||||||||
| Accounts payable | |||||||||||||||||||||
| Accounts payable | 179 | 148 | |||||||||||||||||||
| Accounts payable to affiliates | 23 | 26 | |||||||||||||||||||
| Customer deposits | 27 | 27 | |||||||||||||||||||
| Taxes | 25 | 40 | |||||||||||||||||||
| Price risk management liabilities | 4 | 4 | |||||||||||||||||||
| Regulatory liabilities | 3 | 5 | |||||||||||||||||||
| Interest | 11 | 11 | |||||||||||||||||||
| Asset retirement obligations | 24 | 41 | |||||||||||||||||||
| Other current liabilities | 52 | 36 | |||||||||||||||||||
| Total Current Liabilities | 645 | 701 | |||||||||||||||||||
| Long-term Debt | 1,611 | 1,423 | |||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred income taxes | 572 | 974 | |||||||||||||||||||
| Investment tax credits | 35 | 36 | |||||||||||||||||||
| Price risk management liabilities | 22 | 27 | |||||||||||||||||||
| Accrued pension obligations | 45 | 53 | |||||||||||||||||||
| Asset retirement obligations | |||||||||||||||||||||
| Asset retirement obligations | |||||||||||||||||||||
| Asset retirement obligations | 97 | 104 | |||||||||||||||||||
| Regulatory liabilities | 919 | 419 | |||||||||||||||||||
| Other deferred credits and noncurrent liabilities | 86 | 87 | |||||||||||||||||||
| Total Deferred Credits and Other Noncurrent Liabilities | 1,776 | 1,700 | |||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 6 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Stockholder's Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Common stock - no par value (a) | 424 | 424 | |||||||||||||||||||
| Additional paid-in capital | 1,712 | 1,682 | |||||||||||||||||||
| Earnings reinvested | 391 | 370 | |||||||||||||||||||
| Total Equity | 2,527 | 2,476 | |||||||||||||||||||
| Total Liabilities and Equity | $ | 6,559 | $ | 6,300 | |||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
(a)75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2023 and December 31, 2022.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
89
STATEMENTS OF EQUITY
Louisville Gas and Electric Company
(Millions of Dollars)
Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Total | ||||||||||||||
| December 31, 2014 | 21,294 | $ | 424 | $ | 1,521 | $ | 229 | $ | 2,174 | |||||||||
| Net income | 185 | 185 | ||||||||||||||||
| Capital contributions from LKE | 90 | 90 | ||||||||||||||||
| Cash dividends declared on common stock | (119 | ) | (119 | ) | ||||||||||||||
| December 31, 2015 | 21,294 | $ | 424 | $ | 1,611 | $ | 295 | $ | 2,330 | |||||||||
| Net income | 203 | 203 | ||||||||||||||||
| Capital contributions from LKE | 71 | 71 | ||||||||||||||||
| Cash dividends declared on common stock | (128 | ) | (128 | ) | ||||||||||||||
| December 31, 2016 | 21,294 | $ | 424 | $ | 1,682 | $ | 370 | $ | 2,476 | |||||||||
| Net income | 213 | 213 | ||||||||||||||||
| Capital contributions from LKE | 30 | 30 | ||||||||||||||||
| Cash dividends declared on common stock | (192 | ) | (192 | ) | ||||||||||||||
| December 31, 2017 | 21,294 | $ | 424 | $ | 1,712 | $ | 391 | $ | 2,527 | |||||||||
| Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Total | |||||||||||||||||||||||||
| December 31, 2020 | 21,294 | $ | 424 | $ | 1,923 | $ | 601 | $ | 2,948 | ||||||||||||||||||||
| Net income | 249 | 249 | |||||||||||||||||||||||||||
| Capital contributions from parent | 74 | 74 | |||||||||||||||||||||||||||
| Cash dividends declared on common stock | (192) | (192) | |||||||||||||||||||||||||||
| December 31, 2021 | 21,294 | $ | 424 | $ | 1,997 | $ | 658 | $ | 3,079 | ||||||||||||||||||||
| Net income | 272 | 272 | |||||||||||||||||||||||||||
| Capital contributions from parent | 90 | 90 | |||||||||||||||||||||||||||
| Cash dividends declared on common stock | (275) | (275) | |||||||||||||||||||||||||||
| December 31, 2022 | 21,294 | $ | 424 | $ | 2,087 | $ | 655 | $ | 3,166 | ||||||||||||||||||||
| Net income | 266 | 266 | |||||||||||||||||||||||||||
| Capital contributions from parent | 67 | 67 | |||||||||||||||||||||||||||
| Return of capital to parent | (161) | (161) | |||||||||||||||||||||||||||
| Cash dividends declared on common stock | (166) | (166) | |||||||||||||||||||||||||||
| December 31, 2023 | 21,294 | $ | 424 | $ | 1,993 | $ | 755 | $ | 3,172 | ||||||||||||||||||||
(a)Shares in thousands. All common shares of LG&E stock are owned by LKE.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
90
(THIS PAGE LEFT BLANK INTENTIONALLY.)
91
STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Operating Revenues | Operating Revenues | |||||||||||||||||||||||||||||||||
| Retail and wholesale | $ | 1,734 | $ | 1,735 | $ | 1,708 | ||||||||||||||||||||||||||||
| Electric revenue from affiliate | 10 | 14 | 20 | |||||||||||||||||||||||||||||||
| Total Operating Revenues | 1,744 | 1,749 | 1,728 | |||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||
| Operation | Operation | |||||||||||||||||||||||||||||||||
| Fuel | 467 | 490 | 534 | |||||||||||||||||||||||||||||||
| Energy purchases | 18 | 18 | 18 | |||||||||||||||||||||||||||||||
| Energy purchases from affiliate | 31 | 24 | 37 | |||||||||||||||||||||||||||||||
| Other operation and maintenance | 424 | 424 | 435 | |||||||||||||||||||||||||||||||
| Depreciation | 255 | 234 | 220 | |||||||||||||||||||||||||||||||
| Taxes, other than income | 32 | 30 | 29 | |||||||||||||||||||||||||||||||
| Total Operating Expenses | 1,227 | 1,220 | 1,273 | |||||||||||||||||||||||||||||||
| Operating Income | 517 | 529 | 455 | |||||||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||||||||||
| Operating Income | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) – net | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) – net | ||||||||||||||||||||||||||||||||||
| Other Income (Expense) – net | (3 | ) | (5 | ) | 1 | |||||||||||||||||||||||||||||
| Interest Expense | 96 | 96 | 82 | |||||||||||||||||||||||||||||||
| Interest Expense | ||||||||||||||||||||||||||||||||||
| Interest Expense | ||||||||||||||||||||||||||||||||||
| Interest Expense from Affiliate | ||||||||||||||||||||||||||||||||||
| Interest Expense from Affiliate | ||||||||||||||||||||||||||||||||||
| Interest Expense from Affiliate | ||||||||||||||||||||||||||||||||||
| Income Before Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Before Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Before Income Taxes | 418 | 428 | 374 | |||||||||||||||||||||||||||||||
| Income Taxes | 159 | 163 | 140 | |||||||||||||||||||||||||||||||
| Income Taxes | ||||||||||||||||||||||||||||||||||
| Income Taxes | ||||||||||||||||||||||||||||||||||
| Net Income (a) | $ | 259 | $ | 265 | $ | 234 | ||||||||||||||||||||||||||||
| Net Income (a) | ||||||||||||||||||||||||||||||||||
| Net Income (a) | ||||||||||||||||||||||||||||||||||
(a)Net income equals comprehensive income.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
92
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars)
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Cash Flows from Operating Activities | Cash Flows from Operating Activities | |||||||||||||||||||||||||||||||||
| Net income | $ | 259 | $ | 265 | $ | 234 | ||||||||||||||||||||||||||||
| Adjustments to reconcile net income to net cash provided by (used in) operating activities | Adjustments to reconcile net income to net cash provided by (used in) operating activities | |||||||||||||||||||||||||||||||||
| Depreciation | 255 | 234 | 220 | |||||||||||||||||||||||||||||||
| Amortization | 9 | 14 | 13 | |||||||||||||||||||||||||||||||
| Defined benefit plans - expense | 4 | 5 | 10 | |||||||||||||||||||||||||||||||
| Defined benefit plans - expense (income) | ||||||||||||||||||||||||||||||||||
| Deferred income taxes and investment tax credits | 152 | 126 | 160 | |||||||||||||||||||||||||||||||
| Other | — | (1 | ) | (5 | ) | |||||||||||||||||||||||||||||
| Change in current assets and current liabilities | Change in current assets and current liabilities | |||||||||||||||||||||||||||||||||
| Accounts receivable | (5 | ) | (8 | ) | 5 | |||||||||||||||||||||||||||||
| Accounts receivable from affiliates | — | 1 | (1 | ) | ||||||||||||||||||||||||||||||
| Accounts payable | — | (10 | ) | (32 | ) | |||||||||||||||||||||||||||||
| Accounts payable to affiliates | (6 | ) | 15 | (10 | ) | |||||||||||||||||||||||||||||
| Unbilled revenues | (17 | ) | (15 | ) | 11 | |||||||||||||||||||||||||||||
| Fuel, materials and supplies | 32 | (6 | ) | 3 | ||||||||||||||||||||||||||||||
| Income tax receivable | — | — | 59 | |||||||||||||||||||||||||||||||
| Regulatory assets and liabilities, net | ||||||||||||||||||||||||||||||||||
| Taxes payable | ||||||||||||||||||||||||||||||||||
| Taxes payable | ||||||||||||||||||||||||||||||||||
| Taxes payable | (26 | ) | 25 | 6 | ||||||||||||||||||||||||||||||
| Accrued interest | — | — | 5 | |||||||||||||||||||||||||||||||
| Other | 7 | (3 | ) | 4 | ||||||||||||||||||||||||||||||
| Other operating activities | Other operating activities | |||||||||||||||||||||||||||||||||
| Defined benefit plans - funding | (23 | ) | (20 | ) | (21 | ) | ||||||||||||||||||||||||||||
| Settlement of interest rate swaps | — | — | (44 | ) | ||||||||||||||||||||||||||||||
| Expenditures for asset retirement obligations | ||||||||||||||||||||||||||||||||||
| Expenditures for asset retirement obligations | ||||||||||||||||||||||||||||||||||
| Expenditures for asset retirement obligations | (19 | ) | (8 | ) | (1 | ) | ||||||||||||||||||||||||||||
| Other assets | 3 | (6 | ) | (11 | ) | |||||||||||||||||||||||||||||
| Other liabilities | 9 | (2 | ) | 3 | ||||||||||||||||||||||||||||||
| Net cash provided by operating activities | 634 | 606 | 608 | |||||||||||||||||||||||||||||||
| Cash Flows from Investing Activities | Cash Flows from Investing Activities | |||||||||||||||||||||||||||||||||
| Expenditures for property, plant and equipment | (432 | ) | (350 | ) | (519 | ) | ||||||||||||||||||||||||||||
| Other investing activities | 4 | 1 | 7 | |||||||||||||||||||||||||||||||
| Net cash used in investing activities | (428 | ) | (349 | ) | (512 | ) | ||||||||||||||||||||||||||||
| Cash Flows from Financing Activities | Cash Flows from Financing Activities | |||||||||||||||||||||||||||||||||
| Net increase (decrease) in notes payable with affiliates | ||||||||||||||||||||||||||||||||||
| Issuance of long-term debt | — | 96 | 500 | |||||||||||||||||||||||||||||||
| Retirement of long-term debt | — | (96 | ) | (250 | ) | |||||||||||||||||||||||||||||
| Payment of common stock dividends to parent | (226 | ) | (248 | ) | (153 | ) | ||||||||||||||||||||||||||||
| Contributions from parent | — | 20 | — | |||||||||||||||||||||||||||||||
| Return of capital to parent | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Retirement of commercial paper | ||||||||||||||||||||||||||||||||||
| Net increase (decrease) in short-term debt | 29 | (32 | ) | (188 | ) | |||||||||||||||||||||||||||||
| Other financing activities | (1 | ) | (1 | ) | (5 | ) | ||||||||||||||||||||||||||||
| Net cash used in financing activities | (198 | ) | (261 | ) | (96 | ) | ||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 8 | (4 | ) | — | ||||||||||||||||||||||||||||||
| Cash and Cash Equivalents at Beginning of Period | 7 | 11 | 11 | |||||||||||||||||||||||||||||||
| Cash and Cash Equivalents at End of Period | $ | 15 | $ | 7 | $ | 11 | ||||||||||||||||||||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | ||||||||||||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid (received) during the period for: | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||||||||||||||||
| Cash paid during the period for: | Cash paid during the period for: | |||||||||||||||||||||||||||||||||
| Interest - net of amount capitalized | $ | 92 | $ | 89 | $ | 75 | ||||||||||||||||||||||||||||
| Income taxes - net | $ | 34 | $ | 13 | $ | (84 | ) | |||||||||||||||||||||||||||
| Significant non-cash transactions: | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | $ | 82 | $ | 47 | $ | 53 | ||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
| Accrued expenditures for property, plant and equipment at December 31, | ||||||||||||||||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
BALANCE SHEETS AT DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Assets | Assets | ||||||||||||||||||||
| Current Assets | Current Assets | ||||||||||||||||||||
| Cash and cash equivalents | $ | 15 | $ | 7 | |||||||||||||||||
| Accounts receivable (less reserve: 2017, $1; 2016, $2) | |||||||||||||||||||||
| Accounts receivable (less reserve: 2023, $2; 2022, $3) | Accounts receivable (less reserve: 2023, $2; 2022, $3) | ||||||||||||||||||||
| Customer | 130 | 126 | |||||||||||||||||||
| Other | 30 | 5 | |||||||||||||||||||
| Unbilled revenues | 112 | 95 | |||||||||||||||||||
| Unbilled revenues (less reserve: 2023, $0; 2022, $0) | |||||||||||||||||||||
| Fuel, materials and supplies | |||||||||||||||||||||
| Fuel, materials and supplies | |||||||||||||||||||||
| Fuel, materials and supplies | 123 | 154 | |||||||||||||||||||
| Prepayments | 14 | 12 | |||||||||||||||||||
| Regulatory assets | |||||||||||||||||||||
| Regulatory assets | |||||||||||||||||||||
| Regulatory assets | 6 | 11 | |||||||||||||||||||
| Other current assets | 5 | 3 | |||||||||||||||||||
| Total Current Assets | |||||||||||||||||||||
| Total Current Assets | |||||||||||||||||||||
| Total Current Assets | 435 | 413 | |||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||
| Regulated utility plant | 7,592 | 7,382 | |||||||||||||||||||
| Less: accumulated depreciation - regulated utility plant | 1,170 | 965 | |||||||||||||||||||
| Regulated utility plant, net | 6,422 | 6,417 | |||||||||||||||||||
| Construction work in progress | 321 | 181 | |||||||||||||||||||
| Property, Plant and Equipment, net | 6,743 | 6,598 | |||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Other Noncurrent Assets | |||||||||||||||||||||
| Regulatory assets | 384 | 374 | |||||||||||||||||||
| Goodwill | 607 | 607 | |||||||||||||||||||
| Other intangibles | 33 | 36 | |||||||||||||||||||
| Other noncurrent assets | 52 | 57 | |||||||||||||||||||
| Total Other Noncurrent Assets | 1,076 | 1,074 | |||||||||||||||||||
| Total Assets | $ | 8,254 | $ | 8,085 | |||||||||||||||||
| Total Assets | |||||||||||||||||||||
| Total Assets | |||||||||||||||||||||
The accompanying Notes to Financial Statements are an integral part of the financial statements.
94
BALANCE SHEETS AT DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars, shares in thousands)
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Liabilities and Equity | Liabilities and Equity | ||||||||||||||||||||
| Current Liabilities | Current Liabilities | ||||||||||||||||||||
| Short-term debt | $ | 45 | $ | 16 | |||||||||||||||||
| Long-term debt due within one year | |||||||||||||||||||||
| Long-term debt due within one year | |||||||||||||||||||||
| Long-term debt due within one year | |||||||||||||||||||||
| Accounts payable | 137 | 78 | |||||||||||||||||||
| Accounts payable to affiliates | 53 | 56 | |||||||||||||||||||
| Customer deposits | 31 | 29 | |||||||||||||||||||
| Taxes | 19 | 45 | |||||||||||||||||||
| Regulatory liabilities | |||||||||||||||||||||
| Regulatory liabilities | |||||||||||||||||||||
| Regulatory liabilities | 6 | 13 | |||||||||||||||||||
| Interest | 16 | 16 | |||||||||||||||||||
| Asset retirement obligations | 61 | 19 | |||||||||||||||||||
| Other current liabilities | 46 | 36 | |||||||||||||||||||
| Total Current Liabilities | 414 | 308 | |||||||||||||||||||
| Long-term Debt | 2,328 | 2,327 | |||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Long-term Debt | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred Credits and Other Noncurrent Liabilities | |||||||||||||||||||||
| Deferred income taxes | 691 | 1,170 | |||||||||||||||||||
| Investment tax credits | 94 | 96 | |||||||||||||||||||
| Accrued pension obligations | 36 | 62 | |||||||||||||||||||
| Asset retirement obligations | |||||||||||||||||||||
| Asset retirement obligations | |||||||||||||||||||||
| Asset retirement obligations | 174 | 269 | |||||||||||||||||||
| Regulatory liabilities | 1,117 | 480 | |||||||||||||||||||
| Other deferred credits and noncurrent liabilities | 43 | 50 | |||||||||||||||||||
| Total Deferred Credits and Other Noncurrent Liabilities | 2,155 | 2,127 | |||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 6 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Commitments and Contingent Liabilities (Notes 7 and 13) | |||||||||||||||||||||
| Stockholder's Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Equity | |||||||||||||||||||||
| Common stock - no par value (a) | 308 | 308 | |||||||||||||||||||
| Additional paid-in capital | 2,616 | 2,616 | |||||||||||||||||||
| Accumulated other comprehensive loss | — | (1 | ) | ||||||||||||||||||
| Earnings reinvested | |||||||||||||||||||||
| Earnings reinvested | |||||||||||||||||||||
| Earnings reinvested | 433 | 400 | |||||||||||||||||||
| Total Equity | 3,357 | 3,323 | |||||||||||||||||||
| Total Liabilities and Equity | $ | 8,254 | $ | 8,085 | |||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
| Total Liabilities and Equity | |||||||||||||||||||||
(a) 80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2023 and December 31, 2022.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
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STATEMENTS OF EQUITY
Kentucky Utilities Company
(Millions of Dollars)
Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Accumulated other comprehensive income (loss) | Total | |||||||||||||||||
| December 31, 2014 | 37,818 | $ | 308 | $ | 2,596 | $ | 302 | $ | — | $ | 3,206 | |||||||||||
| Net income | 234 | 234 | ||||||||||||||||||||
| Cash dividends declared on common stock | (153 | ) | (153 | ) | ||||||||||||||||||
| December 31, 2015 | 37,818 | $ | 308 | $ | 2,596 | $ | 383 | $ | — | $ | 3,287 | |||||||||||
| Net income | 265 | 265 | ||||||||||||||||||||
| Capital contributions from LKE | 20 | 20 | ||||||||||||||||||||
| Cash dividends declared on common stock | (248 | ) | (248 | ) | ||||||||||||||||||
| Other comprehensive income (loss) | (1 | ) | (1 | ) | ||||||||||||||||||
| December 31, 2016 | 37,818 | $ | 308 | $ | 2,616 | $ | 400 | $ | (1 | ) | $ | 3,323 | ||||||||||
| Net income | 259 | 259 | ||||||||||||||||||||
| Cash dividends declared on common stock | (226 | ) | (226 | ) | ||||||||||||||||||
| Other comprehensive income (loss) | 1 | 1 | ||||||||||||||||||||
| December 31, 2017 | 37,818 | $ | 308 | $ | 2,616 | $ | 433 | $ | — | $ | 3,357 | |||||||||||
| Common stock shares outstanding (a) | Common stock | Additional paid-in capital | Earnings reinvested | Total | |||||||||||||||||||||||||
| December 31, 2020 | 37,818 | $ | 308 | $ | 2,857 | $ | 617 | $ | 3,782 | ||||||||||||||||||||
| Net income | 296 | 296 | |||||||||||||||||||||||||||
| Capital contributions from parent | 100 | 100 | |||||||||||||||||||||||||||
| Cash dividends declared on common stock | (250) | (250) | |||||||||||||||||||||||||||
| December 31, 2021 | 37,818 | $ | 308 | $ | 2,957 | $ | 663 | $ | 3,928 | ||||||||||||||||||||
| Net income | 322 | 322 | |||||||||||||||||||||||||||
| Capital contributions from parent | 84 | 84 | |||||||||||||||||||||||||||
| Cash dividends declared on common stock | (296) | (296) | |||||||||||||||||||||||||||
| December 31, 2022 | 37,818 | $ | 308 | $ | 3,041 | $ | 689 | $ | 4,038 | ||||||||||||||||||||
| Net income | 312 | 312 | |||||||||||||||||||||||||||
| Capital contributions from parent | 76 | 76 | |||||||||||||||||||||||||||
| Return of capital to parent | (84) | (84) | |||||||||||||||||||||||||||
| Cash dividends declared on common stock | (190) | (190) | |||||||||||||||||||||||||||
| December 31, 2023 | 37,818 | $ | 308 | $ | 3,033 | $ | 811 | $ | 4,152 | ||||||||||||||||||||
(a)Shares in thousands. All common shares of KU stock are owned by LKE.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
COMBINED NOTES TO FINANCIAL STATEMENTS
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:
| Registrant | ||||||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | |||||||||||||||||||||||
| 1. Summary of Significant Accounting Policies | x | x | x | x | ||||||||||||||||||||||
| 2. Segment and Related Information | x | x | x | x | ||||||||||||||||||||||
| 3. Revenue from Contracts with Customers | x | x | x | x | ||||||||||||||||||||||
| 4. Preferred Securities | x | x | x | x | ||||||||||||||||||||||
| 5. Earnings Per Share | x | |||||||||||||||||||||||||
| 6. Income and Other Taxes | x | x | x | x | ||||||||||||||||||||||
| 7. Utility Rate Regulation | x | x | x | x | ||||||||||||||||||||||
| 8. Financing Activities | x | x | x | x | ||||||||||||||||||||||
| 9. Acquisitions, Development and Divestitures | x | |||||||||||||||||||||||||
| 10. Leases | x | x | x | x | ||||||||||||||||||||||
| 11. Retirement and Postemployment Benefits | x | x | x | x | ||||||||||||||||||||||
| 12. Jointly Owned Facilities | x | x | x | |||||||||||||||||||||||
| 13. Commitments and Contingencies | x | x | x | x | ||||||||||||||||||||||
| 14. Related Party Transactions | x | x | x | |||||||||||||||||||||||
| 15. Other Income (Expense) - net | x | x | ||||||||||||||||||||||||
| 16. Fair Value Measurements | x | x | x | x | ||||||||||||||||||||||
| 17. Derivative Instruments and Hedging Activities | x | x | x | x | ||||||||||||||||||||||
| 18. Goodwill and Other Intangible Assets | x | x | x | x | ||||||||||||||||||||||
| 19. Asset Retirement Obligations | x | x | x | x | ||||||||||||||||||||||
| 20. Accumulated Other Comprehensive Income (Loss) | x | |||||||||||||||||||||||||
| 21. New Accounting Guidance Pending Adoption | x | x | x | x | ||||||||||||||||||||||
1. Summary of Significant Accounting Policies
(All Registrants)
General
Capitalized terms and abbreviations appearing in the combined notes to 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 Registrants' related activities and disclosures. Within combined disclosures, amounts are disclosed for any Registrant when significant.
Business and Consolidation
(PPL)
PPL is a utility holding company that, through its regulated subsidiaries, is primarily engaged in: 1) the distribution of electricity in the U.K.; 2) the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas, primarily in Kentucky; 2) the transmission, distribution and sale of electricity in Pennsylvania; and 3) the transmission, distribution and sale of electricity and the distribution and sale of natural gas in Pennsylvania.Rhode Island. Headquartered in Allentown, PA, PPL's principal subsidiaries are PPL Global, LKE (including its principal subsidiaries, LG&E, and KU)KU, RIE and PPL Electric. PPL's corporate level financing subsidiary is PPL Capital Funding.
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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 2022 and 2021. PPL Global, through indirect, wholly owned subsidiaries, operates distribution networks providing electricityhas elected to separately report the cash flows of continuing and discontinued operations on the Statements of Cash Flows for 2022 and 2021. Unless otherwise noted, the notes to these financial statements exclude amounts related to discontinued operations. See Note 9 for additional information.
On May 25, 2022, PPL Rhode Island Holdings, a wholly-owned subsidiary of PPL, acquired 100% of the outstanding shares of common stock of Narragansett Electric from National Grid U.S., a subsidiary of National Grid plc. Narragansett Electric, whose service area covers substantially all of Rhode Island, is primarily engaged in the U.K. WPD serves end-users in South Walestransmission, distribution and southwestsale of electricity and central England. Its principal subsidiariesthe distribution and sale of natural gas. The results of Narragansett Electric are WPD (South Wales), WPD (South West), WPD (East Midlands) and WPD (West Midlands).
(PPL and PPL Electric)
(PPL, LKE, LG&E and KU)
(All Registrants)
The financial statements of the Registrants include each company's own accounts as well as the accounts of all entities in which the company has a controlling financial interest. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for Variable Interest Entities (VIEs). The Registrants consolidate a VIE when they are determined to have a controlling interest in the VIE and, as a result, are the primary beneficiary of the entity. The RegistrantsAmounts consolidated under the VIE guidance are not material to the primary beneficiary in any VIEs. Investments in entities in which a company has the ability toRegistrants.
The financial statements of PPL, LKE, LG&E and KU include their share of any undivided interests in jointly owned facilities, as well as their share of the related operating costs of those facilities. See Note 12 for additional information.
Regulation
(PPL Electric, LG&E and KU)All Registrants)
PPL Electric, RIE, LG&E and KU are cost-based rate-regulated utilities for which rates are set by regulators to enable PPL Electric, RIE, LG&E and KU to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders. Base rates are generally established based on a future test period. As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by GAAP and reflect the effects of regulatory actions. Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates. The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future costs, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and regulatory liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC or the applicable state regulatory commissions. See Note 67 for additional details regarding regulatory matters.
Accounting Records
The system of accounts for domestic regulated entities is maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the applicable state regulatory commissions.
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Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Loss Accruals
Potential losses are accrued when (1) information is available that indicates it is "probable" that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The Registrants continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss accruals for environmental remediation are discounted when appropriate.
The accrual of contingencies that might result in gains is not recorded, unless realization is assured.
Earnings Per Share(PPL)
EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareowners. Share-
Price Risk Management
(All Registrants)
Interest rate contracts are used to hedge exposure to changes in the fair value of debt instruments and to hedge exposure to variability in expected cash flows associated with existing floating-rate debt instruments or forecasted fixed-rate issuances of debt. Foreign currency exchange contracts are usedDerivative instruments pursuant to hedge foreign currency exposures, primarilyregulator approved plans to manage commodity price risk associated with PPL's investmentsnatural gas purchases to reduce fluctuations in U.K. subsidiaries.natural gas prices and costs associated with these derivatives instruments are generally recoverable through approved cost recovery mechanism. Similar derivatives may receive different accounting treatment, depending on management's intended use and documentation.
Certain contracts may not meet the definition of a derivative because they lack a notional amount or a net settlement provision. In cases where there is no net settlement provision, markets are periodically assessed to determine whether market mechanisms have evolved that wouldto facilitate net settlement. Certain derivative contracts may be excluded from the requirements of derivative accounting treatment because NPNS has been elected. These contracts are accounted for using accrual accounting. Contracts that have been classified as derivative contracts are reflected on the balance sheets at fair value. The portion of derivative positions that deliver within a year are included in "Current Assets" and "Current Liabilities," while the portion of derivative positions that deliver beyond a year are recorded in "Other Noncurrent Assets" and "Deferred Credits and Other Noncurrent Liabilities."
Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing activities on the Statements of Cash Flows, depending on the classification of the hedged items.
PPL and its subsidiaries have elected not to offset net derivative positions against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.
Derivative transactions may be marked to fair value through regulatory assets/liabilities at PPL Electric, RIE, LG&E and KU, if approved by the appropriate regulatory body. These transactions generally include the effect of interest rate swaps or commodity gas contracts that are included in customer rates.
(PPL and PPL Electric)
To meet its obligationtheir obligations as a PLRlast resort providers of electricity supply to itstheir customers, PPL Electric hasand RIE have entered into certain contracts that meet the definition of a derivative. However, NPNS has been elected for these contracts.
(All Registrants)
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See Notes 16 and 17 for additional information on derivatives.
| 2017 | 2016 | 2015 | |||||||||
| Domestic electric and gas revenues (a) | $ | 5,351 | $ | 5,297 | $ | 5,239 | |||||
| U.K. operating revenues (b) | 2,091 | 2,207 | 2,410 | ||||||||
| Domestic - other | 5 | 13 | 20 | ||||||||
| Total | $ | 7,447 | $ | 7,517 | $ | 7,669 | |||||
Revenue Recognition
(All Registrants)
Operating revenues are primarily recorded based on energy deliveries through the end of theeach calendar month. Unbilled retail revenues result because customers' bills are rendered throughout the month, rather than bills being rendered at the end of the month. For LKE,RIE, LG&E and KU, unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh or Mcf by the estimated average cents per kWh.kWh or Mcf. Any difference between estimated and actual revenues is adjusted the following month when the previous unbilled estimate is reversed and actual billings occur. For PPL Electric, unbilled revenues for a month are calculated by multiplying the actual unbilled kWhvolumes by an average ratethe price per customer class.tariff.
Financing and under-recovered amounts arising for the periods beginning with the 2014/15 regulatory year and refunded/recovered under RIIO-ED1 will be refunded/recovered on a two year lag (previously one year). Therefore the 2014/15 over/under-recovery adjustment occurred in the 2016/17 regulatory year.Other Receivables
(All Registrants)
Accounts receivable are reported on the Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Financing receivables include accounts receivable, with the exception of those items within accounts receivable that are not subject to the current expected credit loss model.
these analyses. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
PPL Electric, RIE, LG&E and KU have identified one class of financing receivables, “accounts receivable - customer”, which includes financing receivables for all billed and unbilled sales with customers. All other financing receivables are classified as other.
100
The changes in the allowance for doubtful accounts were: are included in the following table. Amounts relate to financing receivables, except as noted.
| Additions | ||||||||||||||||||||||||||
| Balance at Beginning of Period | Charged to Income | Deductions (a) | Balance at End of Period | |||||||||||||||||||||||
| PPL | ||||||||||||||||||||||||||
| 2023 | $ | 95 | $ | 87 | $ | 52 | $ | 130 | (c) | |||||||||||||||||
| 2022 | 69 | 78 | 52 | 95 | (c) | |||||||||||||||||||||
| 2021 | 73 | 26 | 30 | 69 | (c) | |||||||||||||||||||||
PPL Electric | ||||||||||||||||||||||||||
| 2023 | $ | 33 | $ | 52 | $ | 35 | $ | 50 | (b) | |||||||||||||||||
| 2022 | 35 | 27 | 29 | 33 | (b) | |||||||||||||||||||||
| 2021 | 41 | 13 | 19 | 35 | (b) | |||||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||
| 2023 | $ | 4 | $ | 4 | $ | 2 | $ | 6 | ||||||||||||||||||
| 2022 | 3 | 6 | 5 | 4 | ||||||||||||||||||||||
| 2021 | 3 | 4 | 4 | 3 | ||||||||||||||||||||||
| KU | ||||||||||||||||||||||||||
| 2023 | $ | 3 | $ | 3 | $ | 4 | $ | 2 | ||||||||||||||||||
| 2022 | 3 | 6 | 6 | 3 | ||||||||||||||||||||||
| 2021 | 2 | 8 | 7 | 3 | ||||||||||||||||||||||
| Additions | |||||||||||||||||||
Balance at Beginning of Period | Charged to Income | Charged to Other Accounts | Deductions (a) | Balance at End of Period | |||||||||||||||
| PPL | |||||||||||||||||||
| 2017 | $ | 54 | $ | 28 | $ | (1 | ) | $ | 30 | $ | 51 | ||||||||
| 2016 | 41 | 44 | — | 31 | 54 | ||||||||||||||
| 2015 | 44 | 49 | (2 | ) | 50 | 41 | |||||||||||||
| PPL Electric | |||||||||||||||||||
| 2017 | $ | 28 | $ | 18 | $ | — | $ | 22 | $ | 24 | |||||||||
| 2016 | 16 | 35 | — | 23 | 28 | ||||||||||||||
| 2015 | 17 | 39 | — | 40 | 16 | ||||||||||||||
(a)Primarily related to uncollectible accounts written off.
(b)Includes $3 million related to other accounts receivables at December 31, 2023, 2022 and 2021.
(c)Includes $41 million, $36 million and $32 million related to other accounts receivables at December 31, 2023, 2022 and 2021.
| Additions | |||||||||||||||||||
Balance at Beginning of Period | Charged to Income | Charged to Other Accounts | Deductions (a) | Balance at End of Period | |||||||||||||||
| LKE | |||||||||||||||||||
| 2017 | $ | 24 | $ | 8 | $ | (1 | ) | $ | 6 | $ | 25 | ||||||||
| 2016 | 23 | 8 | — | 7 | 24 | ||||||||||||||
| 2015 | 25 | 9 | (2 | ) | 9 | 23 | |||||||||||||
| LG&E | |||||||||||||||||||
| 2017 | $ | 2 | $ | 2 | $ | (1 | ) | $ | 2 | $ | 1 | ||||||||
| 2016 | 1 | 2 | 1 | 2 | 2 | ||||||||||||||
| 2015 | 2 | 2 | — | 3 | 1 | ||||||||||||||
| KU | |||||||||||||||||||
| 2017 | $ | 2 | $ | 4 | $ | (1 | ) | $ | 4 | $ | 1 | ||||||||
| 2016 | 2 | 4 | — | 4 | 2 | ||||||||||||||
| 2015 | 2 | 5 | — | 5 | 2 | ||||||||||||||
Cash
(All Registrants)
Cash Equivalents
All highly liquid investments with original maturities of three months or less are considered to be cash equivalents.
(PPL, LG&E and PPL Electric)KU)
Restricted Cash and Cash Equivalents
Bank deposits and other cash equivalents that are restricted by agreement or that have been clearly designated for a specific purpose are classified as restricted cash and cash equivalents. The change in restricted cash and cash equivalents is reported as an investing activity on the Statements of Cash Flows. On the Balance Sheets, the current portion of restricted cash and cash equivalents is included in "Other current assets," while the noncurrent portion is included in "Other noncurrent assets." See Note 16 for a reconciliation of Cash, Cash Equivalents and Restricted Cash reported within the Balance Sheets to the amounts shown on the Statements of Cash Flows.
| PPL | PPL Electric | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Low carbon network fund (a) | $ | 17 | $ | 17 | $ | — | $ | — | |||||||
| Other | 9 | 9 | 2 | 2 | |||||||||||
| Total | $ | 26 | $ | 26 | $ | 2 | $ | 2 | |||||||
(All Registrants)
Fair Value Measurements
The Registrants value certain financial and nonfinancial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to price risk management assets and liabilities, investments in securities in defined benefit plans, and cash and cash equivalents. PPL and its subsidiaries use, as appropriate, 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) to measure the fair value of an asset or liability. 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 Registrants classify fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:
•Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
•Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability.
•Level 3 - unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value.
Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, the Registrants' assessment of the significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy.
Investments
Generally, the original maturity date of an investment and management's intent and ability to sell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for other than current operations or are clearly designated for expenditure in the acquisition or construction of noncurrent assets or for the liquidation of long-term debts, are classified as long-term.
Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and less than a year, as well as investments with original maturities of greater than a year that management has the ability and intent to sell within a year, are included in "Other current assets" on the Balance Sheets.
Long-Lived and Intangible Assets
Property, Plant and Equipment
PP&E is recorded at original cost, unless impaired. PP&E acquired in business combinations is recorded at fair value at the time of acquisition. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. PP&E acquired in business combinations is recorded at fair value at the time of acquisition. Original cost for constructed assets includes material, labor, contractor costs, certain overheads and financing costs, where applicable. Included in PP&E are capitalized costs of software projects that were developed or obtained for internal use. The cost of repairs and minor replacements are charged to expense as incurred. The Registrants record costs associated with planned major maintenance projects in the period in which thework is performed and costs are incurred. No costs associated with planned major maintenance projects are accrued to PP&E in advance of the period in which the work is performed. LG&E and KU accrue costs of removal net of estimated salvage value through depreciation, which is included in the calculation of customer rates over the assets' depreciable lives in accordance with regulatory practices. Cost of removal amounts accrued through depreciation rates are accumulated as a regulatory liability until the removal costs are incurred. For LKE, LG&E and KU, all ARO depreciation expenses are reclassified to a regulatory asset. See "Asset Retirement Obligations" below and Note 6 for additional information. PPL Electric records net costs of removal when incurred as a regulatory asset. The regulatory asset is subsequently amortized through depreciation over a five-year period, which is recoverable in customer rates in accordance with regulatory practices.
AFUDC is capitalized at PPL Electric and RIE as part of the construction costs for cost-based rate-regulated projects for which a return on such costs is recovered after the project is placed in service. AFUDC is capitalized at LG&E and KU for certain projects as part of the construction cost of approved projects. LG&E and KU are generally provided a return on construction work in progress for other projects. The debt component of AFUDC is credited to "Interest Expense" and the equity component is credited to "Other Income (Expense) - net" on the Statements of Income. LG&E and KU generally do not record AFUDC, except for certain instances in KU's FERC approved rates charged to its municipal customers, as a return is provided on construction work in progress.
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| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | $ | 12 | $ | 7 | $ | 6 | |||||||||||
| PPL Electric | 7 | 5 | 6 | ||||||||||||||
| LG&E | 1 | — | — | ||||||||||||||
| KU | 1 | — | — | ||||||||||||||
Depreciation
Depreciation is recorded over the estimated useful lives of property using various methods including the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant portion of an operating unit that
was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income, unless otherwise required by regulators. RIE, LG&E and KU accrue costs of removal net of estimated salvage value through depreciation, which is included in the calculation of customer rates over the assets' depreciable lives in accordance with regulatory practices. Cost of removal amounts accrued through depreciation rates are accumulated as a regulatory liability until the removal costs are incurred. For LG&E and KU, all ARO depreciation expenses are reclassified to a regulatory asset or regulatory liability. See "Asset Retirement Obligations" below and Note 7 for additional information. PPL Electric records net costs of removal when incurred as a regulatory asset. The regulatory asset is subsequently amortized through depreciation over a five-year period, which is recoverable in customer rates in accordance with regulatory practices.
Following are the weighted-average annual rates of depreciation, for regulated utility plant, for the years ended December 31:
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | 3.26 | % | 3.21 | % | 3.61 | % | |||||||||||
| PPL Electric | 2.62 | % | 2.75 | % | 3.05 | % | |||||||||||
| LG&E | 4.00 | % | 4.16 | % | 3.99 | % | |||||||||||
| KU | 3.95 | % | 4.01 | % | 4.17 | % | |||||||||||
| 2017 | 2016 | 2015 | ||||||
| PPL | 2.65 | % | 2.73 | % | 2.57 | % | ||
| PPL Electric | 2.86 | % | 2.63 | % | 2.46 | % | ||
| LKE | 3.64 | % | 3.69 | % | 3.69 | % | ||
| LG&E | 3.63 | % | 3.58 | % | 3.65 | % | ||
| KU | 3.66 | % | 3.77 | % | 3.71 | % | ||
Goodwill and Other Intangible Assets
Goodwill represents the excess of the purchase price paid over the fair value of the identifiable net assets acquired in a business combination.
Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed
or otherwise used. Costs incurred to obtain an initial license and renew or extend terms of licenses are capitalized as intangible assets.
When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, PPL and its subsidiaries consider:
•the expected use of the asset;
•the expected useful life of other assets to which the useful life of the intangible asset may relate;
•legal, regulatory, or contractual provisions that may limit the useful life;
•the company's historical experience as evidence of its ability to support renewal or extension;
•the effects of obsolescence, demand, competition, and other economic factors; and,
•the level of maintenance expenditures required to obtain the expected future cash flows from the asset.
Asset Impairment (Excluding Investments)
The Registrants review long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or circumstances indicate carrying amounts may not be recoverable.
A long-lived asset classified as held and used is impaired when the carrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value.
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A long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell.
PPL, LKE, LG&E and KU review goodwill for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the unit's fair value. Additionally, goodwill must be tested for impairment in circumstances when a portion of goodwill has been allocated to a business to be disposed. PPL's, LKE's, LG&E's and KU's reporting units are primarily at the operating segment level.
Goodwill recognized upon the acquisition of Narragansett Electric was assigned for impairment testing by PPL to its reporting units expected to benefit from the acquisition, which were the Rhode Island Regulated reporting unit, the Pennsylvania Regulated reporting unit and the Kentucky Regulated reporting unit. See Note 9 for additional information regarding the acquisition.
PPL, LKE,for its reporting units, and individually, LG&E and KU, may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero")step zero) is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if management concludes it is more likely than not that the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.
If the carrying amount of the reporting unit, including goodwill, exceeds its fair value, an impairment loss is recognized in an amount equal to that excess, limited to the implied fair valuetotal amount of goodwill must be calculated in the same manner as goodwill in a business combination. The fair value of a reporting unit is allocated to all assetsthat reporting unit.
As of October 1, 2023, PPL, for its reporting units, and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, goodwill is written down to its implied fair value.
•current year financial performance versus the prior year;year,
•changes in planned capital expenditures;expenditures,
•the consistency of forecasted free cash flows;flows,
•earnings quality and sustainability;sustainability,
•changes in market participant discount rates;rates,
•changes in long-term growth rates,
•changes in PPL's market capitalization;capitalization, and
•the overall economic and regulatory environments in which these regulated entities operate.
Based on these evaluations, management concluded it was not more likely than not that the fair value of these reporting units was less than their carrying value. As such, the two-stepstep one quantitative impairment test was not performed and no impairment was recognized.
(PPL, LKE, LG&E and KU)
Asset Retirement Obligations
PPL and its subsidiaries record liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and offset with an increase in the value of the capitalized asset, which is depreciated over the asset's useful life. Until the obligation is settled, the liability is increased through the recognition of accretion expense classified within "Other operation and maintenance" on the Statements of Incometo reflect changes in the obligation due to the passage of time. For LKE, LG&E and KU, all ARO accretion and depreciation expenses are reclassified as a regulatory asset.asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, at the time of retirement, the related ARO regulatory assetdeferred accretion and depreciation expense is offset against the associatedrecovered through cost of removal regulatory liability, PP&E and ARO liability.removal.
Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset. See Note 67 and Note 19 for additional information on AROs.
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Compensation and Benefits
Defined Benefits(All Registrants)
Certain PPL subsidiaries sponsor various defined benefit pension and other postretirement plans. An asset or liability is recorded to recognize the funded status of all defined benefit plans with an offsetting entry to AOCI or, for LG&E, KU, RIE and PPL Electric, to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.
The expected return on plan assets is determined based on a market-related value of plan assets, which is calculated by rolling forward the prior year market-related value with contributions, disbursements and long-term expected return on investments. One-fifth of the difference between the actual value and the expected value is added (or subtracted if negative) to the expected value to determine the new market-related value.
PPL usesand its subsidiaries, excluding RIE, use an accelerated amortization method for the recognition of gains and losses for its defined benefit pension plans. Under the accelerated method, actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants.required amortization period. Actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service periodfull required amortization period. RIE uses the standard amortization method under GAAP for recognition of active plan participants.gains and losses for its defined benefit pension plan.
See Note 67 for a discussion of the regulatory treatment of defined benefit costs and Note 11 for a discussion of defined benefits.
Stock-Based Compensation(PPL, PPL Electric and LKE)(PPL)
PPL has several stock-based compensation plans for purposes of granting stock options, restricted stock, restricted stock units and performance units to certain employees as well as stock units and restricted stock units to directors. PPL grants most stock-
Taxes
Income Taxes
(All Registrants)
PPL and its domestic subsidiaries file a consolidated U.S. federal income tax return.
Significant management judgment is also required in developing the Registrants' provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken inon tax returns and valuation allowances on deferred tax assets and whether the undistributed earnings of WPD are considered indefinitely reinvested.assets.
Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, as well as the tax effects of net operating losses and tax credit carryforwards.
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The Registrants record valuation allowances to reduce deferred income tax assets to the amounts that are more likely than notmore-likely-than-not to be realized. The Registrants consider the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies in initially recording and subsequently reevaluating the need for valuation allowances.allowances requires significant management judgment. If the Registrants determine that they are able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made. Likewise, if the Registrants determine that they are not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.
The Registrants defer investment tax credits when the credits are utilizedgenerated and amortize the deferred amounts over the average lives of the related assets. With respect to acquired renewable tax credits, pursuant to the IRA, any benefit is recognized in the period the credits can be utilized.
The Registrants recognize tax-related interest and penalties in "Income Taxes" on their Statements of Income.
The Registrants use the portfolio approach method of accounting for deferred taxes related to pre-tax OCI transactions. The portfolio approach involves a strict period-by-period cumulative incremental allocation of income taxes to the change in income and losses reflected in OCI. Under this approach, the net cumulative tax effect is ignored. The net change in unrealized gains and losses recorded in AOCI under this approach would be eliminated only on the date the investment portfolio is classified as held for sale or is liquidated.
See Note 56 to the Financial Statements for additional discussion regarding income taxes, including the impact of the TCJA and management's conclusion that the undistributed earnings of WPD are considered indefinitely reinvested.tax disclosures.
The provision for PPL's, PPL Electric's, LKE's, LG&E's and KU'sthe Registrants' deferred income taxes forrelated to regulatory assets and liabilities is based upon the ratemaking principles reflected in rates established by therelevant regulators. The difference in the provision for deferred income taxes for regulatory assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included on the Balance Sheets in noncurrent "Regulatory assets" or "Regulatory liabilities."
(PPL Electric, LKE, LG&E and KU)
The income tax provision for PPL Electric, LG&E and KU is calculated in accordance with an intercompany tax sharing agreement, which provides that taxable income be calculated as if PPL Electric, LG&E, KU and any domestic subsidiaries each filed a separate return. Tax benefits are not shared between companies. The entity that generates a tax benefit is the entity that is entitled to the tax benefit. The effect of PPL filing a consolidated tax return is taken into account in the settlement of current taxes and the recognition of deferred taxes.
At December 31, the following intercompany tax receivables (payables) were recorded:
| 2023 | 2022 | ||||||||||
| PPL Electric | $ | (21) | $ | 2 | |||||||
| LG&E | (5) | (6) | |||||||||
| KU | (3) | 4 | |||||||||
| 2017 | 2016 | ||||||
| PPL Electric | $ | 61 | $ | 13 | |||
| LKE | (23 | ) | 1 | ||||
| LG&E | — | (18 | ) | ||||
| KU | — | (29 | ) | ||||
Taxes, Other Than Income(All Registrants)
The Registrants present sales taxes in "Other current liabilities" and PPL presents value-added taxes in "Taxes" on the Balance Sheets. These taxes are not reflected on the Statements of Income. See Note 56 for details onof taxes included in "Taxes, other than income" on the Statements of Income.
Other
(All Registrants)
Leases
The Registrants evaluatedetermine whether contractual arrangements entered into contain a lease by evaluating whether those arrangements either implicitly or explicitly identify an asset, whether the Registrants have the right to obtain substantially all of the economic benefits from use of the asset throughout the term of the arrangement, and whether the Registrants have the right to direct the use of the asset. Renewal options are included in the lease term if it is reasonably certain the Registrants will exercise those options. Periods for which the Registrants are reasonably certain not to exercise termination options are also included in the
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lease term. The Registrants have certain agreements with lease and non-lease components, such as office space leases, which are generally accounted for separately.
Short-term leases are leases with a term that is 12 months or less and do not include a purchase option or option to extend the initial term of the lease to greater than 12 months that the Registrants are reasonably certain to exercise. The Registrants have made an accounting purposes.policy election to not recognize the right-of-use asset and the lease liability arising from leases classified as short-term.
The discount rate for a lease is the rate implicit in the lease unless that rate cannot be readily determined. In that case, the Registrants are required to use their incremental borrowing rate, which is the rate the Registrants would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment.
The Registrants receive secured borrowing rates from financial institutions based on their applicable credit profiles. The Registrants use the secured rate which corresponds with the term of the applicable lease. See Note 910 for additional information.
Fuel, Materials and Supplies
Fuel, natural gas stored underground and materials and supplies are valued using the average cost method. Fuel costs for electricelectricity generation are charged to expense as used. For RIE, natural gas supply costs are charged to expense when delivered to customers. For LG&E, natural gas supply costs are charged to expense as delivered to the distribution system. See Note 67 for further discussion of the fuel adjustment clauseclauses and gas supply clause.
"Fuel, materials and supplies" on the Balance Sheets consisted of the following at December 31:
| 2023 | |||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| Fuel | $ | 144 | $ | — | $ | 50 | $ | 94 | |||||||||||||||
| Natural gas stored underground | 58 | — | 34 | — | |||||||||||||||||||
| Materials and supplies | 303 | 99 | 59 | 91 | |||||||||||||||||||
| Total | $ | 505 | $ | 99 | $ | 143 | $ | 185 | |||||||||||||||
| PPL | LKE | LG&E | KU | ||||||||||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||
| Fuel | $ | 107 | $ | 158 | $ | 107 | $ | 158 | $ | 45 | $ | 60 | $ | 62 | $ | 98 | |||||||||||||||
| Natural gas stored underground | 43 | 42 | 43 | 42 | 43 | 42 | — | — | |||||||||||||||||||||||
| Materials and supplies | 170 | 156 | 104 | 97 | 43 | 41 | 61 | 56 | |||||||||||||||||||||||
| Total | $ | 320 | $ | 356 | $ | 254 | $ | 297 | $ | 131 | $ | 143 | $ | 123 | $ | 154 | |||||||||||||||
| 2022 | |||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| Fuel | $ | 125 | $ | — | $ | 44 | $ | 81 | |||||||||||||||
| Natural gas stored underground | 91 | — | 68 | — | |||||||||||||||||||
| Materials and supplies | 227 | 69 | 54 | 86 | |||||||||||||||||||
| Total | $ | 443 | $ | 69 | $ | 166 | $ | 167 | |||||||||||||||
(PPL)
Purchased Renewable Energy Certificates (RECs) are stated at cost and are used to measure compliance with state renewable energy standards. RECs support new renewable generation standards and are held primarily to be utilized in fulfillment of ContentsRIE’s compliance obligations.
Guarantees
Generally, the initial measurement of a guarantee liability is the fair value of the guarantee at its inception. However, there are certain guarantees excluded from the scope of accounting guidance and other guarantees that are not subject to the initial recognition and measurement provisions of accounting guidance that only require disclosure. See Note 13 for further discussion of recorded and unrecorded guarantees.
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(PPL)
Treasury Stock(PPL)
PPL generally restores all shares of common stock acquired to authorized but unissued shares of common stock upon or soon after acquisition. In connection with its share repurchases in 2021, PPL has not returned these shares to authorized but unissued shares; it intends to retain these shares as Treasury stock to use in connection with certain compensation plans.
2. Segment and Related Information
(PPL)
PPL is organized into three segments: U.K. Regulated, Kentucky Regulated, Pennsylvania Regulated, and PennsylvaniaRhode Island Regulated. PPL's segments are segmented by geographic location.
The Pennsylvania Regulated segment includes the regulated electricity transmission and distribution operations of PPL Electric. In addition, certain costs are allocated to
The Rhode Island Regulated segment includes the Pennsylvania Regulated segment.regulated electricity transmission and distribution and natural gas distribution operations of RIE, which was acquired on May 25, 2022.
"Corporate and Other" primarily includes corporate level financing costs, incurred at the corporate level that have not been allocated or assigned to the segments, as well as certain other unallocated costs, whichand certain non-recoverable costs incurred in conjunction with the acquisition of Narragansett Electric and the financial results of Safari Energy, prior to its sale on November 1, 2022. "Corporate and Other" is presented to reconcile segment information to PPL's consolidated results.
Income Statement data for the segments and reconciliation to PPL's consolidated results for the years ended December 31 are as follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Operating Revenues from external customers (a) | |||||||||||||||||
| Kentucky Regulated | $ | 3,452 | $ | 3,811 | $ | 3,348 | |||||||||||
| Pennsylvania Regulated | 3,008 | 3,030 | 2,402 | ||||||||||||||
| Rhode Island Regulated | 1,851 | 1,038 | — | ||||||||||||||
| Corporate and Other | 1 | 23 | 33 | ||||||||||||||
| Total | $ | 8,312 | $ | 7,902 | $ | 5,783 | |||||||||||
| Depreciation | |||||||||||||||||
| Kentucky Regulated | $ | 696 | $ | 685 | $ | 647 | |||||||||||
| Pennsylvania Regulated | 397 | 393 | 424 | ||||||||||||||
| Rhode Island Regulated | 156 | 92 | — | ||||||||||||||
| Corporate and Other | 5 | 11 | 11 | ||||||||||||||
| Total | $ | 1,254 | $ | 1,181 | $ | 1,082 | |||||||||||
| Amortization (b) | |||||||||||||||||
| Kentucky Regulated | $ | 33 | $ | 23 | $ | 15 | |||||||||||
| Pennsylvania Regulated | 41 | 22 | 19 | ||||||||||||||
| Rhode Island Regulated | 1 | 2 | — | ||||||||||||||
| Corporate and Other | 6 | 5 | 5 | ||||||||||||||
| Total | $ | 81 | $ | 52 | $ | 39 | |||||||||||
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| 2023 | 2022 | 2021 | |||||||||||||||
| Interest Expense | |||||||||||||||||
| Kentucky Regulated | $ | 235 | $ | 205 | $ | 196 | |||||||||||
| Pennsylvania Regulated | 223 | 171 | 162 | ||||||||||||||
| Rhode Island Regulated | 83 | 39 | — | ||||||||||||||
| Corporate and Other (c) | 125 | 98 | 560 | ||||||||||||||
| Total | $ | 666 | $ | 513 | $ | 918 | |||||||||||
| Income Before Income Taxes | |||||||||||||||||
| Kentucky Regulated | $ | 689 | $ | 678 | $ | 615 | |||||||||||
| Pennsylvania Regulated | 687 | 699 | 599 | ||||||||||||||
| Rhode Island Regulated | 112 | (58) | — | ||||||||||||||
| Corporate and Other | (564) | (404) | (693) | ||||||||||||||
| Total | $ | 924 | $ | 915 | $ | 521 | |||||||||||
| Income Taxes (d) | |||||||||||||||||
| Kentucky Regulated | $ | 137 | $ | 129 | $ | 107 | |||||||||||
| Pennsylvania Regulated | 168 | 174 | 154 | ||||||||||||||
| Rhode Island Regulated | 16 | (14) | — | ||||||||||||||
| Corporate and Other | (137) | (88) | 242 | ||||||||||||||
| Total | $ | 184 | $ | 201 | $ | 503 | |||||||||||
| Deferred income taxes and investment tax credits (e) | |||||||||||||||||
| Kentucky Regulated | $ | (17) | $ | 6 | $ | 272 | |||||||||||
| Pennsylvania Regulated | 46 | 91 | 79 | ||||||||||||||
| Rhode Island Regulated | 48 | 39 | — | ||||||||||||||
| Corporate and Other | 245 | 43 | (264) | ||||||||||||||
| Total | $ | 322 | $ | 179 | $ | 87 | |||||||||||
| Net Income | |||||||||||||||||
| Kentucky Regulated | $ | 552 | $ | 549 | $ | 508 | |||||||||||
| Pennsylvania Regulated | 519 | 525 | 445 | ||||||||||||||
| Rhode Island Regulated | 96 | (44) | — | ||||||||||||||
| Corporate and Other (c) | (427) | (316) | (935) | ||||||||||||||
| Discontinued Operations | — | 42 | (1,498) | ||||||||||||||
| Total | $ | 740 | $ | 756 | $ | (1,480) | |||||||||||
(a)See Note 1 and Note 3 for additional information on Operating Revenues.
| 2017 | 2016 | 2015 | |||||||||
| Operating Revenues from external customers (a) | |||||||||||
| U.K. Regulated | $ | 2,091 | $ | 2,207 | $ | 2,410 | |||||
| Kentucky Regulated | 3,156 | 3,141 | 3,115 | ||||||||
| Pennsylvania Regulated | 2,195 | 2,156 | 2,124 | ||||||||
| Corporate and Other | 5 | 13 | 20 | ||||||||
| Total | $ | 7,447 | $ | 7,517 | $ | 7,669 | |||||
| Depreciation | |||||||||||
| U.K. Regulated | $ | 230 | $ | 233 | $ | 242 | |||||
| Kentucky Regulated | 439 | 404 | 382 | ||||||||
| Pennsylvania Regulated | 309 | 253 | 214 | ||||||||
| Corporate and Other | 30 | 36 | 45 | ||||||||
| Total | $ | 1,008 | $ | 926 | $ | 883 | |||||
| Amortization (b) | |||||||||||
| U.K. Regulated | $ | 34 | $ | 16 | $ | 6 | |||||
| Kentucky Regulated | 24 | 29 | 27 | ||||||||
| Pennsylvania Regulated | 33 | 32 | 26 | ||||||||
| Corporate and Other | 6 | 3 | — | ||||||||
| Total | $ | 97 | $ | 80 | $ | 59 | |||||
| Unrealized (gains) losses on derivatives and other hedging activities (c) | |||||||||||
| U.K. Regulated | $ | 166 | $ | 13 | $ | (88 | ) | ||||
| Kentucky Regulated | 6 | 6 | 11 | ||||||||
| Corporate and Other | 6 | — | — | ||||||||
| Total | $ | 178 | $ | 19 | $ | (77 | ) | ||||
| Interest Expense | |||||||||||
| U.K. Regulated | $ | 397 | $ | 402 | $ | 417 | |||||
| Kentucky Regulated | 261 | 260 | 232 | ||||||||
| Pennsylvania Regulated | 142 | 129 | 130 | ||||||||
| Corporate and Other | 101 | 97 | 92 | ||||||||
| Total | $ | 901 | $ | 888 | $ | 871 | |||||
| Income from Continuing Operations Before Income Taxes | |||||||||||
| U.K. Regulated | $ | 804 | $ | 1,479 | $ | 1,249 | |||||
| Kentucky Regulated | 645 | 640 | 547 | ||||||||
| Pennsylvania Regulated | 575 | 550 | 416 | ||||||||
| Corporate and Other (d) | (112 | ) | (119 | ) | (144 | ) | |||||
| Total | $ | 1,912 | $ | 2,550 | $ | 2,068 | |||||
| Income Taxes (e) | |||||||||||
| U.K. Regulated | $ | 152 | $ | 233 | $ | 128 | |||||
| Kentucky Regulated | 359 | 242 | 221 | ||||||||
| Pennsylvania Regulated | 216 | 212 | 164 | ||||||||
| Corporate and Other (d) | 57 | (39 | ) | (48 | ) | ||||||
| Total | $ | 784 | $ | 648 | $ | 465 | |||||
| Deferred income taxes and investment tax credits (f) | |||||||||||
| U.K. Regulated | $ | 66 | $ | 31 | $ | 45 | |||||
| Kentucky Regulated | 294 | 291 | 236 | ||||||||
| Pennsylvania Regulated | 257 | 221 | 220 | ||||||||
| Corporate and Other (d) | 90 | 17 | (73 | ) | |||||||
| Total | $ | 707 | $ | 560 | $ | 428 | |||||
(c)2021 includes losses from the extinguishment of PPL Capital Funding debt. See Note 8 for additional information.
(d)Represents both current and deferred income taxes, including investment tax credits.
| 2017 | 2016 | 2015 | |||||||||
| Net Income | |||||||||||
| U.K. Regulated | $ | 652 | $ | 1,246 | $ | 1,121 | |||||
| Kentucky Regulated | 286 | 398 | 326 | ||||||||
| Pennsylvania Regulated | 359 | 338 | 252 | ||||||||
| Corporate and Other (d) | (169 | ) | (80 | ) | (96 | ) | |||||
| Discontinued Operations (g) | — | — | (921 | ) | |||||||
| Total | $ | 1,128 | $ | 1,902 | $ | 682 | |||||
Cash Flow data for the segments and reconciliation to PPL's consolidated results for the years ended December 31 are as follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Expenditures for long-lived assets | |||||||||||||||||
| Kentucky Regulated | $ | 950 | $ | 917 | $ | 1,026 | |||||||||||
| Pennsylvania Regulated | 956 | 889 | 904 | ||||||||||||||
| Rhode Island Regulated | 454 | 268 | — | ||||||||||||||
| Corporate and Other | 30 | 84 | 49 | ||||||||||||||
| Total | $ | 2,390 | $ | 2,158 | $ | 1,979 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Expenditures for long-lived assets | |||||||||||
| U.K. Regulated | $ | 1,015 | $ | 1,031 | $ | 1,242 | |||||
| Kentucky Regulated | 892 | 791 | 1,210 | ||||||||
| Pennsylvania Regulated | 1,254 | 1,134 | 1,107 | ||||||||
| Corporate and Other | 10 | 1 | 11 | ||||||||
| Total | $ | 3,171 | $ | 2,957 | $ | 3,570 | |||||
The following provides Balance Sheet data for the segments and reconciliation to PPL's consolidated results as of:
| As of December 31, | |||||||
| 2017 | 2016 | ||||||
| Total Assets | |||||||
| U.K. Regulated (a) | $ | 16,813 | $ | 14,537 | |||
| Kentucky Regulated | 14,468 | 14,037 | |||||
| Pennsylvania Regulated | 10,082 | 9,426 | |||||
| Corporate and Other (b) | 116 | 315 | |||||
| Total | $ | 41,479 | $ | 38,315 | |||
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| 2017 | 2016 | 2015 | |||||||||
| Revenues from external customers | |||||||||||
| U.K. | $ | 2,091 | $ | 2,207 | $ | 2,410 | |||||
| U.S. | 5,356 | 5,310 | 5,259 | ||||||||
| Total | $ | 7,447 | $ | 7,517 | $ | 7,669 | |||||
| As of December 31, | |||||||
| 2017 | 2016 | ||||||
| Long-Lived Assets | |||||||
| U.K. | $ | 12,851 | $ | 11,177 | |||
| U.S. | 20,936 | 19,595 | |||||
| Total | $ | 33,787 | $ | 30,772 | |||
| As of December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Total Assets | |||||||||||
| Kentucky Regulated | $ | 17,029 | $ | 16,904 | |||||||
| Pennsylvania Regulated | 14,294 | 13,565 | |||||||||
| Rhode Island Regulated | 6,515 | 6,081 | |||||||||
| Corporate and Other (a) | 1,398 | 1,287 | |||||||||
| Total | $ | 39,236 | $ | 37,837 | |||||||
(a)Primarily consists of unallocated items, including cash, PP&E, goodwill, and the elimination of inter-segment transactions.
(PPL Electric, LKE, LG&E and KU)
PPL Electric has two operating segments, thatdistribution and transmission, which are aggregated into a single reportable segment. LKE, Each of LG&E and KU operates as a single operating and reportable segment.
3. Revenue from Contracts with Customers
(All Registrants)
The following is a description of the principal activities from which the Registrants and PPL’s segments generate their revenues.
(PPL and PPL Electric)
Pennsylvania Regulated Segment Revenue
The Pennsylvania Regulated segment generates substantially all of its revenues from contracts with customers from PPL Electric’s tariff-based distribution and transmission of electricity.
Distribution Revenue
PPL Electric provides distribution services to residential, commercial, industrial, municipal and governmental end users of energy. PPL Electric satisfies its performance obligation to its distribution customers and revenue is recognized over time as electricity is delivered and simultaneously consumed by the customer. The amount of revenue recognized is the volume of electricity delivered during the period multiplied by the price per tariff, plus a monthly fixed charge. This method of recognition fairly presents PPL Electric's transfer of electric service to the customer as the calculation is based on volumes delivered, and the price per tariff and the monthly fixed charge are set by the PAPUC. Customers are typically billed monthly and outstanding amounts are normally due within 21 days of the date of the bill.
Distribution customers are "at will" customers of PPL Electric with no term contract and no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with PPL Electric’s retail account contracts.
Certain customers have the option to obtain electricity from other suppliers where PPL Electric facilitates the delivery. In those circumstances, revenue is only recognized for providing delivery of the commodity to the customer.
Transmission Revenue
PPL Electric generates transmission revenues from a FERC-approved PJM Open Access Transmission Tariff. An annual revenue requirement for PPL Electric to provide transmission services is calculated using a formula-based rate. This revenue requirement is converted into a daily rate (dollars per day). PPL Electric satisfies its performance obligation to provide transmission services and revenue is recognized over time as transmission services are provided and consumed. This method of recognition fairly presents PPL Electric's transfer of transmission services as the daily rate is set by a FERC approved formula-based rate. PJM remits payment on a weekly basis.
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PPL Electric's agreement to provide transmission services contains no minimum purchase commitment. The performance obligation is limited to the service requested and received to date. Accordingly, PPL Electric has no unsatisfied performance obligations.
(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 and then applying tariff rates 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.
Distribution customers are "at will" customers of RIE with no term contract and no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with RIE's retail account contracts.
Certain customers have the option to obtain electricity or natural gas from other suppliers where RIE facilitates the delivery. 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 ISO – New England (ISO-NE). As of January 1, 2023, RIE is a transmission operator. These revenues arise under tariff/rate agreements and are collected primarily from RIE’s 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.
RIE's agreement to provide transmission services contains no minimum purchase commitment. The performance obligation is limited to the service requested and received to date. Accordingly, RIE has no unsatisfied performance obligations.
(PPL, LG&E and KU)
Kentucky Regulated Segment Revenue
The Kentucky Regulated Segment generates substantially all of its revenues from contracts with customers from LG&E's and KU's regulated tariff-based sales of electricity and LG&E's regulated tariff-based sales of natural gas.
LG&E and KU are individually single operatingengaged in the generation, transmission, distribution and reportable segments.sale of electricity in Kentucky and, in KU's case, Virginia. LG&E also engages in the distribution and sale of natural gas in Kentucky. Revenue from these activities is generated from tariffs approved by applicable regulatory authorities including the FERC, KPSC and VSCC. LG&E and KU satisfy their
performance obligations upon LG&E's and KU's delivery of electricity and LG&E's delivery of natural gas to customers. This revenue is recognized over time as the customer simultaneously receives and consumes the benefits provided by LG&E and KU. The amount of revenue recognized is the billed volume of electricity or natural gas delivered multiplied by a tariff rate per-unit of energy, plus any applicable fixed charges or additional regulatory mechanisms. Customers are billed monthly and outstanding amounts are typically due within 22 days of the date of the bill. Additionally, unbilled revenues are recognized as a result of customers' bills rendered throughout the month, rather than bills being rendered at the end of the month. Unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh or Mcf delivered but not yet billed by the estimated average cents per kWh or Mcf. 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 LG&E's and KU's transfer of electricity and LG&E's transfer of 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 set by the respective regulatory body.
LG&E's and KU's customers generally have no minimum purchase commitment. Performance obligations are limited to the service requested and received to date. Accordingly, there is no unsatisfied performance obligation associated with these customers.
(All Registrants)
The following table reconciles "Operating Revenues" included in each Registrant's Statement of Income with revenues generated from contracts with customers for the years ended December31:
| 2023 | |||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| Operating Revenues (a) | $ | 8,312 | $ | 3,008 | $ | 1,613 | $ | 1,884 | |||||||||||||||
| Revenues derived from: | |||||||||||||||||||||||
| Alternative revenue programs (b) | 1 | 5 | (1) | (5) | |||||||||||||||||||
| Other (c) | (23) | (15) | (4) | (4) | |||||||||||||||||||
| Revenues from Contracts with Customers | $ | 8,290 | $ | 2,998 | $ | 1,608 | $ | 1,875 | |||||||||||||||
| 2022 | |||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| Operating Revenues (a) | $ | 7,902 | $ | 3,030 | $ | 1,798 | $ | 2,074 | |||||||||||||||
| Revenues derived from: | |||||||||||||||||||||||
| Alternative revenue programs (b) | (92) | (56) | 9 | 5 | |||||||||||||||||||
| Other (c) | (24) | (14) | (6) | (4) | |||||||||||||||||||
| Revenues from Contracts with Customers | $ | 7,786 | $ | 2,960 | $ | 1,801 | $ | 2,075 | |||||||||||||||
| 2021 | |||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||
| Operating Revenues (a) | $ | 5,783 | $ | 2,402 | $ | 1,569 | $ | 1,826 | |||||||||||||||
| Revenues derived from: | |||||||||||||||||||||||
| Alternative revenue programs (b) | 77 | 83 | (3) | (3) | |||||||||||||||||||
| Other (c) | (22) | (3) | (8) | (9) | |||||||||||||||||||
| Revenues from Contracts with Customers | $ | 5,838 | $ | 2,482 | $ | 1,558 | $ | 1,814 | |||||||||||||||
(a)PPL includes $1,851 million and $1,038 million for the twelve months ended December 31, 2023 and 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 as negative amounts. For PPL Electric, revenue in 2022 includes $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. Revenue in 2021 was reduced by $78 million for a reduction in the transmission formula rate return on equity.
(c)Represents additional revenues outside the scope of revenues from contracts with customers such as leases and other miscellaneous revenues.
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The following table shows revenues from contracts with customers disaggregated by customer class for the years ended December31:
| Residential | Commercial | Industrial | Other (a) | Wholesale - municipality | Wholesale - other (b) | Transmission | Revenues from Contracts with Customers | ||||||||||||||||||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||||||||||||||||||||
| PA Regulated | $ | 1,649 | $ | 444 | $ | 55 | $ | 54 | $ | — | $ | — | $ | 796 | $ | 2,998 | |||||||||||||||||||||||||||||||
| RI Regulated | 640 | 228 | 20 | 793 | — | — | 170 | 1,851 | |||||||||||||||||||||||||||||||||||||||
| KY Regulated | 1,458 | 1,001 | 637 | 272 | 22 | 50 | — | 3,440 | |||||||||||||||||||||||||||||||||||||||
| Corp and Other | — | — | — | 1 | — | — | — | 1 | |||||||||||||||||||||||||||||||||||||||
| Total PPL | $ | 3,747 | $ | 1,673 | $ | 712 | $ | 1,120 | $ | 22 | $ | 50 | $ | 966 | $ | 8,290 | |||||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||||||||||||||||||||
| PA Regulated | $ | 1,647 | $ | 491 | $ | 85 | $ | 54 | $ | — | $ | — | $ | 683 | $ | 2,960 | |||||||||||||||||||||||||||||||
| RI Regulated | 299 | 101 | 9 | 478 | — | — | 101 | 988 | |||||||||||||||||||||||||||||||||||||||
| KY Regulated | 1,637 | 1,068 | 662 | 323 | 28 | 97 | — | 3,815 | |||||||||||||||||||||||||||||||||||||||
| Corp and Other | — | — | — | 23 | — | — | — | 23 | |||||||||||||||||||||||||||||||||||||||
| Total PPL | $ | 3,583 | $ | 1,660 | $ | 756 | $ | 878 | $ | 28 | $ | 97 | $ | 784 | $ | 7,786 | |||||||||||||||||||||||||||||||
| 2021 | |||||||||||||||||||||||||||||||||||||||||||||||
| PA Regulated | $ | 1,299 | $ | 350 | $ | 53 | $ | 50 | $ | — | $ | — | $ | 730 | $ | 2,482 | |||||||||||||||||||||||||||||||
| RI Regulated | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| KY Regulated | 1,416 | 928 | 586 | 305 | 24 | 66 | — | 3,325 | |||||||||||||||||||||||||||||||||||||||
| Corp and Other | — | — | — | 31 | — | — | — | 31 | |||||||||||||||||||||||||||||||||||||||
| Total PPL | $ | 2,715 | $ | 1,278 | $ | 639 | $ | 386 | $ | 24 | $ | 66 | $ | 730 | $ | 5,838 | |||||||||||||||||||||||||||||||
| PPL Electric | |||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | $ | 1,649 | $ | 444 | $ | 55 | $ | 54 | $ | — | $ | — | $ | 796 | $ | 2,998 | |||||||||||||||||||||||||||||||
| 2022 | $ | 1,647 | $ | 491 | $ | 85 | $ | 54 | $ | — | $ | — | $ | 683 | $ | 2,960 | |||||||||||||||||||||||||||||||
| 2021 | $ | 1,299 | $ | 350 | $ | 53 | $ | 50 | $ | — | $ | — | $ | 730 | $ | 2,482 | |||||||||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | $ | 751 | $ | 517 | $ | 189 | $ | 104 | $ | — | $ | 47 | $ | — | $ | 1,608 | |||||||||||||||||||||||||||||||
| 2022 | $ | 835 | $ | 551 | $ | 199 | $ | 141 | $ | — | $ | 75 | $ | — | $ | 1,801 | |||||||||||||||||||||||||||||||
| 2021 | $ | 711 | $ | 473 | $ | 180 | $ | 145 | $ | — | $ | 49 | $ | — | $ | 1,558 | |||||||||||||||||||||||||||||||
| KU | |||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | $ | 707 | $ | 484 | $ | 448 | $ | 168 | $ | 22 | $ | 46 | $ | — | $ | 1,875 | |||||||||||||||||||||||||||||||
| 2022 | $ | 802 | $ | 517 | $ | 463 | $ | 182 | $ | 28 | $ | 83 | $ | — | $ | 2,075 | |||||||||||||||||||||||||||||||
| 2021 | $ | 705 | $ | 455 | $ | 406 | $ | 160 | $ | 24 | $ | 64 | $ | — | $ | 1,814 | |||||||||||||||||||||||||||||||
(a)Primarily includes revenues from pole attachments, street lighting, other public authorities and other non-core businesses. The Rhode Island Regulated segment primarily includes open access tariff revenues, which are calculated on combined customer classes.
(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 PPL.
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. PPL Electric's revenues from contracts with customers are further disaggregated by distribution and transmission as indicated in the above tables.
Contract receivables from customers are primarily included in "Accounts receivable - Customer" and "Unbilled revenues" on the Balance Sheets.
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The following table shows the accounts receivable and unbilled revenues balances that were impaired for the year ended December31:
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL(a) | $ | 79 | $ | 70 | $ | 22 | |||||||||||
| PPL Electric | 47 | 21 | 10 | ||||||||||||||
| LG&E | 4 | 6 | 4 | ||||||||||||||
| KU | 2 | 6 | 8 | ||||||||||||||
(a)Includes $23 million for the twelve months ended December 31, 2022 related to the commitment to forgive customer arrearages for low-income and protected residential customers at RIE. See Note 9 for additional information.
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 as of December 31, 2023 | $ | 43 | $ | 29 | $ | 6 | $ | 7 | |||||||||||||||
| Contract liabilities as of December 31, 2022 | 34 | 23 | 5 | 6 | |||||||||||||||||||
| Revenue recognized during the year ended December 31, 2023 that was included in the contract liability balance at December 31, 2022 | 21 | 10 | 5 | 6 | |||||||||||||||||||
| Contract liabilities as of December 31, 2022 | $ | 34 | $ | 23 | $ | 5 | $ | 6 | |||||||||||||||
| Contract liabilities as of December 31, 2021 | 42 | 25 | 6 | 6 | |||||||||||||||||||
| Revenue recognized during the year ended December 31, 2022 that was included in the contract liability balance at December 31, 2021 | 25 | 12 | 6 | 6 | |||||||||||||||||||
| Contract liabilities as of December 31, 2021 | $ | 42 | $ | 25 | $ | 6 | $ | 6 | |||||||||||||||
| Contract liabilities as of December 31, 2020 | 40 | 23 | 5 | 6 | |||||||||||||||||||
| Revenue recognized during the year ended December 31, 2021 that was included in the contract liability balance at December 31, 2020 | 24 | 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 recognized as revenue ratably over the billing period. Payments received in excess of revenues earned to date are recognized as revenue as services are delivered in subsequent periods.
4. Preferred Securities
(PPL)
PPL is authorized to issue up to 10 million shares of preferred stock. No PPL preferred stock was issued or outstanding in 2017, 20162023, 2022 or 2015.2021.
(PPL Electric)
PPL Electric is authorized to issue up to 20,629,936 shares of preferred stock. No PPL Electric preferred stock was issued or outstanding in 2017, 20162023, 2022 or 2015.2021.
(LG&E)
LG&E is authorized to issue up to 1,720,000 shares of preferred stock at a $25 par value and 6,750,000 shares of preferred stock without par value. LG&E had no preferred stock issued or outstanding in 2017, 20162023, 2022 or 2015.2021.
(KU)
KU is authorized to issue up to 5,300,000 shares of preferred stock and 2,000,000 shares of preference stock without par value. KU had no preferred or preference stock issued or outstanding in 2017, 20162023, 2022 or 2015.2021.
5. 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 the number of incremental shares that would be outstanding if potentially dilutive non-participating securitiesshare-based payment awards were converted to common shares as calculated using the Two-Class Method or Treasury Stock Method. The If-Converted Method will be applied to the Exchangeable Senior Notes due 2028 issued in February 2023. See Note 8 for additional information. Incremental non-participating securities that have a dilutive impact are detailed in the table below.
Reconciliations of the amounts of income and shares of PPL common stock (in thousands) for the periods ended December 31, used in the EPS calculation are:
| 2023 | 2022 | 2021 | |||||||||||||||
| Income (Numerator) | |||||||||||||||||
| Income from continuing operations after income taxes | $ | 740 | $ | 714 | $ | 18 | |||||||||||
| Less amounts allocated to participating securities | 1 | 1 | — | ||||||||||||||
| Income from continuing operations after income taxes available to PPL common shareowners - Basic and Diluted | $ | 739 | $ | 713 | $ | 18 | |||||||||||
| Income (loss) from discontinued operations (net of income taxes) available to PPL common shareowners - Basic and Diluted | $ | — | $ | 42 | $ | (1,498) | |||||||||||
| Net income (loss) attributable to PPL | $ | 740 | $ | 756 | (1,480) | ||||||||||||
| Less amounts allocated to participating securities | 1 | 1 | — | ||||||||||||||
| Net income (loss) available to PPL common shareowners - Basic and Diluted | $ | 739 | $ | 755 | $ | (1,480) | |||||||||||
| Shares of Common Stock (Denominator) | |||||||||||||||||
| Weighted-average shares - Basic EPS | 737,036 | 736,027 | 762,902 | ||||||||||||||
| Add: Dilutive share-based payment awards (a) | 1,130 | 875 | 1,917 | ||||||||||||||
| Weighted-average shares - Diluted EPS | 738,166 | 736,902 | 764,819 | ||||||||||||||
| Basic EPS | |||||||||||||||||
| Available to PPL common shareowners: | |||||||||||||||||
| Income from continuing operations after income taxes | $ | 1.00 | $ | 0.97 | $ | 0.03 | |||||||||||
| Income (loss) from discontinued operations (net of income taxes) | — | 0.06 | (1.96) | ||||||||||||||
| Net Income (Loss) available to PPL common shareowners | $ | 1.00 | $ | 1.03 | $ | (1.93) | |||||||||||
| Diluted EPS | |||||||||||||||||
| Available to PPL common shareowners: | |||||||||||||||||
| Income from continuing operations after income taxes | $ | 1.00 | $ | 0.96 | $ | 0.03 | |||||||||||
| Income (loss) from discontinued operations (net of income taxes) | — | 0.06 | (1.96) | ||||||||||||||
| Net Income (Loss) available to PPL common shareowners | $ | 1.00 | $ | 1.02 | $ | (1.93) | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Income (Numerator) | |||||||||||
| Income from continuing operations after income taxes | $ | 1,128 | $ | 1,902 | $ | 1,603 | |||||
| Less amounts allocated to participating securities | 2 | 6 | 6 | ||||||||
Income from continuing operations after income taxes available to PPL common shareowners - Basic and Diluted | $ | 1,126 | $ | 1,896 | $ | 1,597 | |||||
Income (loss) from discontinued operations (net of income taxes) available to PPL common shareowners - Basic and Diluted | $ | — | $ | — | $ | (921 | ) | ||||
| Net income | $ | 1,128 | $ | 1,902 | $ | 682 | |||||
| Less amounts allocated to participating securities | 2 | 6 | 2 | ||||||||
| Net income available to PPL common shareowners - Basic and Diluted | $ | 1,126 | $ | 1,896 | $ | 680 | |||||
(a)The Treasury Stock Method was applied to non-participating share-based payment awards.
| 2017 | 2016 | 2015 | |||||||||
| Shares of Common Stock (Denominator) | |||||||||||
| Weighted-average shares - Basic EPS | 685,240 | 677,592 | 669,814 | ||||||||
| Add incremental non-participating securities: | |||||||||||
| Share-based payment awards (a) | 2,094 | 2,854 | 2,772 | ||||||||
| Weighted-average shares - Diluted EPS | 687,334 | 680,446 | 672,586 | ||||||||
| Basic EPS | |||||||||||
| Available to PPL common shareowners: | |||||||||||
| Income from continuing operations after income taxes | $ | 1.64 | $ | 2.80 | $ | 2.38 | |||||
| Income (loss) from discontinued operations (net of income taxes) | — | — | (1.37 | ) | |||||||
| Net Income | $ | 1.64 | $ | 2.80 | $ | 1.01 | |||||
| Diluted EPS | |||||||||||
| Available to PPL common shareowners: | |||||||||||
| Income from continuing operations after income taxes | $ | 1.64 | $ | 2.79 | $ | 2.37 | |||||
| Income (loss) from discontinued operations (net of income taxes) | — | — | (1.36 | ) | |||||||
| Net Income | $ | 1.64 | $ | 2.79 | $ | 1.01 | |||||
For the yearyears ended December 31, PPL issued common stock related to stock-based compensation plans and DRIP as follows (in thousands):
| 2023 | 2022 | ||||||||||
| Stock-based compensation plans (a) | — | 124 | |||||||||
(a)Includes stock options exercised, vesting of performance units, vesting of restricted stock and restricted stock units and conversion of stock units granted to directors.
115
For the years ended December 31, the following shares (in thousands) were excluded from the computations of diluted EPS because the effect would have been antidilutive:
| 2017 | 2016 | 2015 | ||||||
| Stock options | 696 | 696 | 1,087 | |||||
| Performance units | — | 176 | 36 | |||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Stock-based compensation awards | 243 | 93 | 1,783 | ||||||||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Income tax expense (benefit) | $ | 321 | $ | (13 | ) | $ | 112 | $ | — | $ | — | ||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Income tax expense (benefit) | $ | 220 | $ | (13 | ) | $ | 112 | $ | — | $ | — | ||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| Net Increase in Regulatory Liabilities | $ | 2,185 | $ | 1,019 | $ | 1,166 | $ | 532 | $ | 634 | |||||||||
(PPL)
"Income (Loss) from Continuing Operations Before Income Taxes" included the following:is from domestic operations.
| 2017 | 2016 | 2015 | |||||||||
| Domestic income | $ | 874 | $ | 1,463 | $ | 968 | |||||
| Foreign income | 1,038 | 1,087 | 1,100 | ||||||||
| Total | $ | 1,912 | $ | 2,550 | $ | 2,068 | |||||
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes and the tax effects of net operating loss and tax credit carryforwards. The provision for PPL's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles of the applicable jurisdiction. See Notes 1 and 67 for additional information.
Net deferred tax assets have been recognized based on management's estimates of future taxable income for the U.S. and the U.K.income.
Significant components of PPL's deferred income tax assets and liabilities were as follows:
| 2023 | 2022 | ||||||||||
| Deferred Tax Assets | |||||||||||
| Deferred investment tax credits | $ | 28 | $ | 29 | |||||||
| Regulatory liabilities | 123 | 88 | |||||||||
| Income taxes due to customers | 436 | 448 | |||||||||
| Accrued pension and postretirement costs | 101 | 86 | |||||||||
| State loss carryforwards | 253 | 230 | |||||||||
| Federal and state tax credit carryforwards | 67 | 68 | |||||||||
| Internal Revenue Code Section 197 intangibles (a) | 78 | 85 | |||||||||
| Contributions in aid of construction | 149 | 114 | |||||||||
| Other | 139 | 87 | |||||||||
| Valuation allowances | (245) | (213) | |||||||||
| Total deferred tax assets | 1,129 | 1,022 | |||||||||
| Deferred Tax Liabilities | |||||||||||
| Plant - net | 3,749 | 3,609 | |||||||||
| Regulatory assets | 376 | 337 | |||||||||
| Prepayments | 47 | 46 | |||||||||
| Goodwill | 22 | 7 | |||||||||
| Other | 30 | 23 | |||||||||
| Total deferred tax liabilities | 4,224 | 4,022 | |||||||||
| Net deferred tax liability | $ | 3,095 | $ | 3,000 | |||||||
(a)Certain of the RIE assets acquired in 2022 are treated as intangibles for tax purposes and are amortized over a 15 year period. PPL recorded deferred tax assets on these intangibles, which will reverse as tax deductions are taken.
| 2017 (a) | 2016 | ||||||
| Deferred Tax Assets | |||||||
| Deferred investment tax credits | $ | 33 | $ | 51 | |||
| Regulatory liabilities | 62 | 94 | |||||
| Income taxes due to customer (b) | 499 | — | |||||
| Accrued pension costs | 159 | 250 | |||||
| Federal loss carryforwards | 356 | 565 | |||||
| State loss carryforwards | 409 | 326 | |||||
| Federal and state tax credit carryforwards | 455 | 256 | |||||
| Foreign capital loss carryforwards | 329 | 302 | |||||
| Foreign loss carryforwards | 2 | 3 | |||||
| Foreign - pensions | (32 | ) | 41 | ||||
| Foreign - regulatory obligations | 2 | 6 | |||||
| Foreign - other | 7 | 5 | |||||
| Contributions in aid of construction | 134 | 141 | |||||
| Domestic - other | 104 | 188 | |||||
| Unrealized losses on qualifying derivatives | 10 | 20 | |||||
| Valuation allowances | (838 | ) | (593 | ) | |||
| Total deferred tax assets | 1,691 | 1,655 | |||||
| Deferred Tax Liabilities | |||||||
| Domestic plant - net (b) | 3,168 | 4,325 | |||||
| Taxes recoverable through future rates (b) | — | 170 | |||||
| Regulatory assets | 211 | 343 | |||||
| Reacquired debt costs | 15 | 25 | |||||
| Foreign plant - net | 726 | 640 | |||||
| Domestic - other | 9 | 14 | |||||
| Total deferred tax liabilities | 4,129 | 5,517 | |||||
| Net deferred tax liability | $ | 2,438 | $ | 3,862 | |||
State deferred taxes are determined on a by entity and by jurisdiction basis.jurisdiction. As a result, $24$9 million and $27$6 million of net deferred tax assets are shown as "Other noncurrent assets" on the Balance Sheets for 20172023 and 2016.2022.
At December 31, 2017,2023, PPL had the following loss and tax credit carryforwards, related deferred tax assets and valuation allowances recorded against the deferred tax assets.assets:
| Gross | Deferred Tax Asset | Valuation Allowance | Expiration | ||||||||||||||||||||
| Loss and other carryforwards | |||||||||||||||||||||||
| State net operating losses | $ | 5,475 | $ | 253 | $ | (243) | 2024-2043 | ||||||||||||||||
| State charitable contributions | 10 | 1 | (1) | 2024-2028 | |||||||||||||||||||
| Gross | Deferred Tax Asset | Valuation Allowance | Expiration | ||||||||||
| Loss carryforwards | |||||||||||||
| Federal net operating losses (a) | $ | 1,662 | $ | 349 | $ | — | 2029-2037 | ||||||
| Federal charitable contributions (a) | 36 | 7 | — | 2020-2022 | |||||||||
| State net operating losses (a) | 5,512 | 407 | (348 | ) | 2018-2037 | ||||||||
| State charitable contributions (a) | 26 | 2 | — | 2018-2022 | |||||||||
| Foreign net operating losses | 10 | 2 | — | Indefinite | |||||||||
| Foreign capital losses | 1,938 | 329 | (329 | ) | Indefinite | ||||||||
116
| Credit carryforwards | |||||||||
| Federal investment tax credit | 133 | — | 2025-2036 | ||||||
| Federal alternative minimum tax credit (b) | 30 | — | Indefinite | ||||||
| Federal foreign tax credits (c) | 267 | (148 | ) | 2024-2027 | |||||
| Federal - other | 24 | (8 | ) | 2019-2037 | |||||
| State - other | 1 | — | Indefinite | ||||||
| Gross | Deferred Tax Asset | Valuation Allowance | Expiration | ||||||||||||||||||||
| Credit carryforwards | |||||||||||||||||||||||
| Federal investment tax credit | 51 | — | 2045 | ||||||||||||||||||||
| Federal - other | 5 | — | 2043 | ||||||||||||||||||||
| State recycling credit | 10 | — | 2028 | ||||||||||||||||||||
| State - other | 1 | — | Indefinite | ||||||||||||||||||||
Valuation allowances have been established for the amount that, more likely than not, will not be realized. The changes in deferred tax valuation allowances were as follows:
| Additions | |||||||||||||||||||||||||||||
| Balance at Beginning of Period | Charged to Income | Charged to Other Accounts | Deductions | Balance at End of Period | |||||||||||||||||||||||||
| 2023 | $ | 213 | $ | 54 | (a) | $ | — | $ | 22 | (b) | $ | 245 | |||||||||||||||||
| 2022 | 462 | 10 | — | 259 | (c) | 213 | |||||||||||||||||||||||
| 2021 | 536 | 48 | (d) | — | 122 | (e) | 462 | ||||||||||||||||||||||
| Additions | |||||||||||||||||||
Balance at Beginning of Period | Charged to Income | Charged to Other Accounts | Deductions | Balance at End of Period | |||||||||||||||
| 2017 | $ | 593 | $ | 256 | (a) | $ | — | $ | 11 | $ | 838 | ||||||||
| 2016 | 662 | 17 | 2 | 88 | (b) | 593 | |||||||||||||
| 2015 | 622 | 24 | 77 | (c) | 61 | (b) | 662 | ||||||||||||
(a)PPL has a Pennsylvania net operating loss fully offset by a valuation allowance. In addition,2023, PPL adjusted the reductionnet operating loss and related valuation allowance to be recorded at the current estimate of the U.S. federal corporateapplicable rate at which each portion of the net operating loss that will expire and be written off as the rate is reduced annually by one half a percentage point until the rate reaches to 4.99% in 2031.
(b)In 2023, PPL recorded a $22 million decrease in a valuation allowance on a 2003 state net operating loss carryforward that expired in 2023.
(c)In 2022, PPL recorded a $36 million decrease in a valuation allowance on a 2002 state net operating loss carryforward that expired in 2022 and a $213 million decrease in the valuation allowance due to the Pennsylvania rate change. See reconciliation of income tax rate enacted by the TCJA in 2017 resulted intable below.
(d)In 2021, PPL recorded a $62$31 million increase in federal deferred tax assets and a corresponding valuation allowance related to the federal tax benefits ofon a state net operating losses.
loss carryforward in connection with the loss on extinguishment associated with a tender offer to purchase and retire PPL Capital Funding's outstanding Senior Notes.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income from Continuing Operations Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were as follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Income Tax Expense (Benefit) | |||||||||||||||||
| Current - Federal (a) | $ | (175) | $ | (2) | $ | (1) | |||||||||||
| Current - State | 37 | 24 | 36 | ||||||||||||||
| Current - Foreign | — | — | (1) | ||||||||||||||
| Total Current Expense (Benefit) | (138) | 22 | 34 | ||||||||||||||
| Deferred - Federal (a) | 286 | 122 | 28 | ||||||||||||||
| Deferred - State | 48 | 68 | 105 | ||||||||||||||
| Deferred - Foreign (b) | — | — | 383 | ||||||||||||||
| Total Deferred Expense (Benefit), excluding operating loss carryforwards | 334 | 190 | 516 | ||||||||||||||
| Amortization of investment tax credit | (3) | (3) | (3) | ||||||||||||||
| Tax expense (benefit) of operating loss carryforwards | |||||||||||||||||
| Deferred - Federal | 3 | 2 | 12 | ||||||||||||||
| Deferred - State | (12) | (10) | (56) | ||||||||||||||
| Total Tax Expense (Benefit) of Operating Loss Carryforwards | (9) | (8) | (44) | ||||||||||||||
| Total income tax expense (benefit) | $ | 184 | $ | 201 | $ | 503 | |||||||||||
| Total income tax expense (benefit) - Federal | $ | 111 | $ | 119 | $ | 36 | |||||||||||
| Total income tax expense (benefit) - State | 73 | 82 | 85 | ||||||||||||||
| Total income tax expense (benefit) - Foreign | — | — | 382 | ||||||||||||||
| Total income tax expense (benefit) | $ | 184 | $ | 201 | $ | 503 | |||||||||||
(a)During 2023, PPL purchased approximately $300 million of renewable tax credits, as allowed by the IRA. PPL recorded a current tax benefit and a deferred tax expense for the utilization of approximately $250 million of the credits in 2023 and prior years, per the three-year carry-back rule. See "Other - Purchase of Renewable Tax Credits" below for additional information.
(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 in 2021.
| 2017 | 2016 | 2015 | |||||||||
| Income Tax Expense (Benefit) | |||||||||||
| Current - Federal | $ | 6 | $ | (14 | ) | $ | (26 | ) | |||
| Current - State | 25 | 21 | 25 | ||||||||
| Current - Foreign | 45 | 80 | 89 | ||||||||
| Total Current Expense | 76 | 87 | 88 | ||||||||
| Deferred - Federal (a) | 532 | 385 | 699 | ||||||||
| Deferred - State | 88 | 89 | 68 | ||||||||
| Deferred - Foreign | 133 | 86 | 41 | ||||||||
| Total Deferred Expense, excluding operating loss carryforwards | 753 | 560 | 808 | ||||||||
117
| 2017 | 2016 | 2015 | |||||||||
| Income Tax Expense (Benefit) | |||||||||||
| Amortization of investment tax credit | (3 | ) | (3 | ) | (4 | ) | |||||
| Tax expense (benefit) of operating loss carryforwards | |||||||||||
| Deferred - Federal (b) | (16 | ) | 25 | (396 | ) | ||||||
| Deferred - State | (26 | ) | (21 | ) | (31 | ) | |||||
| Total Tax Expense (Benefit) of Operating Loss Carryforwards | (42 | ) | 4 | (427 | ) | ||||||
| Total income taxes from continuing operations | $ | 784 | $ | 648 | $ | 465 | |||||
| Total income tax expense - Federal | $ | 519 | $ | 393 | $ | 273 | |||||
| Total income tax expense - State | 87 | 89 | 62 | ||||||||
| Total income tax expense - Foreign | 178 | 166 | 130 | ||||||||
| Total income taxes from continuing operations | $ | 784 | $ | 648 | $ | 465 | |||||
In the table above, the following income tax expense (benefit) are excluded from income taxes from continuing operations:taxes:
| 2023 | 2022 | 2021 | |||||||||||||||
| Discontinued operations | $ | — | $ | (42) | $ | 759 | |||||||||||
| Reclassification from AOCI due to sale of UK utility business | — | — | 660 | ||||||||||||||
| Other comprehensive income | (14) | 11 | 150 | ||||||||||||||
| Valuation allowance recorded to other comprehensive income | (1) | — | — | ||||||||||||||
| Total | $ | (15) | $ | (31) | $ | 1,569 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Discontinued operations - PPL Energy Supply Segment | $ | — | $ | — | $ | (30 | ) | ||||
| Stock-based compensation recorded to Earnings Reinvested | — | (7 | ) | — | |||||||
| Other comprehensive income | (34 | ) | (6 | ) | (2 | ) | |||||
| Valuation allowance on state deferred taxes recorded to other comprehensive income | (1 | ) | 1 | (4 | ) | ||||||
| Total | $ | (35 | ) | $ | (12 | ) | $ | (36 | ) | ||
| 2023 | 2022 | 2021 | |||||||||||||||
| Reconciliation of Income Tax Expense (Benefit) | |||||||||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 194 | $ | 192 | $ | 109 | |||||||||||
| State income taxes, net of federal income tax benefit | 58 | 68 | 23 | ||||||||||||||
| Valuation allowance adjustments (a) | 12 | 9 | 48 | ||||||||||||||
| Income tax credits (b) | (22) | (3) | (2) | ||||||||||||||
| Impact of the U.K. Finance Acts on deferred tax balances (c) | — | — | 383 | ||||||||||||||
| Depreciation and other items not normalized | (10) | (8) | (5) | ||||||||||||||
| Amortization of excess deferred federal and state income taxes | (48) | (54) | (54) | ||||||||||||||
| Non-deductible officer's salary | 1 | 5 | 6 | ||||||||||||||
| Other | (1) | (8) | (5) | ||||||||||||||
| Total increase (decrease) | (10) | 9 | 394 | ||||||||||||||
| Total income tax expense (benefit) | $ | 184 | $ | 201 | $ | 503 | |||||||||||
| Effective income tax rate | 19.9% | 22.0% | 96.5% | ||||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Reconciliation of Income Tax Expense | |||||||||||
| Federal income tax on Income from Continuing Operations Before Income Taxes at statutory tax rate - 35% | $ | 669 | $ | 893 | $ | 724 | |||||
| Increase (decrease) due to: | |||||||||||
| State income taxes, net of federal income tax benefit | 46 | 46 | 31 | ||||||||
| Valuation allowance adjustments (a) | 36 | 16 | 24 | ||||||||
| Impact of lower U.K. income tax rates (b) | (176 | ) | (177 | ) | (176 | ) | |||||
| U.S. income tax on foreign earnings - net of foreign tax credit (c) | 47 | (42 | ) | 8 | |||||||
| Federal and state tax reserves adjustments (d) | — | — | (22 | ) | |||||||
| Foreign income return adjustments | (8 | ) | 2 | — | |||||||
| Impact of the U.K. Finance Acts on deferred tax balances (b) | (16 | ) | (49 | ) | (91 | ) | |||||
| Depreciation not normalized | (10 | ) | (10 | ) | (5 | ) | |||||
| Interest benefit on U.K. financing entities | (16 | ) | (17 | ) | (20 | ) | |||||
| Stock-based compensation (e) | (3 | ) | (10 | ) | — | ||||||
| Deferred tax impact of U.S. tax reform (f) | 220 | — | — | ||||||||
| Other | (5 | ) | (4 | ) | (8 | ) | |||||
| Total increase (decrease) | 115 | (245 | ) | (259 | ) | ||||||
| Total income taxes from continuing operations | $ | 784 | $ | 648 | $ | 465 | |||||
| Effective income tax rate | 41.0 | % | 25.4 | % | 22.5 | % | |||||
(c)The U.K. Finance Act 2015,2021, formally enacted in November 2015, reducedon June 10, 2021, increased the U.K. statutory incomecorporation tax rate from 20%19% to 19%25%, effective April 1, 2017 and from 19% to 18% effective April 1, 2020. As a result, PPL reduced its net2023. 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 recognized a $90 millioncorresponding deferred income tax benefit during 2015, related to both rate decreases.
| 2023 | 2022 | 2021 | |||||||||||||||
| Taxes, other than income | |||||||||||||||||
| State gross receipts (a) | $ | 195 | $ | 175 | $ | 113 | |||||||||||
| Property and other (a) | 197 | 157 | 94 | ||||||||||||||
| Total | $ | 392 | $ | 332 | $ | 207 | |||||||||||
(a)Increase in 2022 is primarily related to enactment of the TCJA. The enacted tax law included a conversion from a worldwide tax system to a territorial tax system, effective January 1, 2018. In the transitiondue to the territorial regime,acquisition of RIE on May 25, 2022. The increase in 2023 isprimarily due to the results for 2023 including a one-time transition tax was imposed on PPL’s unrepatriated accumulated foreign earnings in 2017. These earnings were treated as a taxable deemed dividendfull year of RIE operations compared to PPL of approximately $462 million, including $205 million of foreign tax credits. As the PPL consolidated U.S. group had a taxable loss for 2017, inclusive of the taxable deemed dividend, these credits were recorded as a deferred tax asset. However, it is expected that under the TCJA,2022, which includes only $83 million of the $205 million of foreign tax credits will be realized in the carry forward period. Accordingly, a valuation allowanceoperations beginning on the current year foreign tax credits in the amount of $122 million has been recorded to reflect the reduction in the future utilization of the credits. The foreign tax credits associated with the deemed repatriation result in a gross carryforward and corresponding deferred tax asset of $205 million offset by a valuation allowance of $122 million.acquisition date.
| 2017 | 2016 | 2015 | |||||||||
| Taxes, other than income | |||||||||||
| State gross receipts (a) | $ | 102 | $ | 100 | $ | 89 | |||||
| State capital stock | (6 | ) | — | — | |||||||
| Foreign property | 127 | 135 | 148 | ||||||||
| Domestic Other | 69 | 66 | 62 | ||||||||
| Total | $ | 292 | $ | 301 | $ | 299 | |||||
(PPL Electric)
The provision for PPL Electric's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the PUCPAPUC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of PPL Electric's deferred income tax assets and liabilities were as follows:
118
| 2023 | 2023 | 2022 | ||||||||||||||||||||||||
| Deferred Tax Assets | Deferred Tax Assets | |||||||||||||||||||||||||
| Accrued pension and postretirement costs | ||||||||||||||||||||||||||
| Contributions in aid of construction | ||||||||||||||||||||||||||
| Regulatory liabilities | ||||||||||||||||||||||||||
| Income taxes due to customers | ||||||||||||||||||||||||||
| 2017 (a) | 2016 | |||||||||||||||||||||||||
| Deferred Tax Assets | ||||||||||||||||||||||||||
| Accrued pension costs | $ | 63 | $ | 107 | ||||||||||||||||||||||
| Contributions in aid of construction | 117 | 112 | ||||||||||||||||||||||||
| Regulatory liabilities | 25 | 34 | ||||||||||||||||||||||||
| Income taxes due to customers (b) | 193 | — | ||||||||||||||||||||||||
| State loss carryforwards | 19 | 22 | ||||||||||||||||||||||||
| Federal loss carryforwards | 91 | 147 | ||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Other | 45 | 81 | ||||||||||||||||||||||||
| Total deferred tax assets | 553 | 503 | ||||||||||||||||||||||||
| Deferred Tax Liabilities | ||||||||||||||||||||||||||
| Electric utility plant - net (b) | 1,544 | 2,001 | ||||||||||||||||||||||||
| Taxes recoverable through future rates (b) | — | 141 | ||||||||||||||||||||||||
| Reacquired debt costs | 8 | 15 | ||||||||||||||||||||||||
| Deferred Tax Liabilities | ||||||||||||||||||||||||||
| Deferred Tax Liabilities | ||||||||||||||||||||||||||
| Electric utility plant - net | ||||||||||||||||||||||||||
| Regulatory assets | 150 | 240 | ||||||||||||||||||||||||
| Regulatory assets | ||||||||||||||||||||||||||
| Regulatory assets | ||||||||||||||||||||||||||
| Prepayments | ||||||||||||||||||||||||||
| Other | 5 | 5 | ||||||||||||||||||||||||
| Total deferred tax liabilities | 1,707 | 2,402 | ||||||||||||||||||||||||
| Net deferred tax liability | $ | 1,154 | $ | 1,899 | ||||||||||||||||||||||
| Gross | Deferred Tax Asset | Expiration | |||||||
| Loss carryforwards (a) | |||||||||
| Federal net operating losses | $ | 426 | $ | 89 | 2031-2037 | ||||
| Federal charitable contributions | 8 | 2 | 2020-2022 | ||||||
| State net operating losses | 233 | 18 | 2030-2032 | ||||||
| State charitable contributions | 13 | 1 | 2018-2022 | ||||||
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were as follows.follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Income Tax Expense (Benefit) | |||||||||||||||||
| Current - Federal | $ | 91 | $ | 63 | $ | 40 | |||||||||||
| Current - State | 31 | 20 | 35 | ||||||||||||||
| Total Current Expense (Benefit) | 122 | 83 | 75 | ||||||||||||||
| Deferred - Federal | 28 | 60 | 59 | ||||||||||||||
| Deferred - State | 18 | 31 | 20 | ||||||||||||||
| Total Deferred Expense (Benefit), excluding operating loss carryforwards | 46 | 91 | 79 | ||||||||||||||
| Total income tax expense (benefit) | $ | 168 | $ | 174 | $ | 154 | |||||||||||
| Total income tax expense (benefit) - Federal | $ | 119 | $ | 123 | $ | 99 | |||||||||||
| Total income tax expense (benefit) - State | 49 | 51 | 55 | ||||||||||||||
| Total income tax expense (benefit) | $ | 168 | $ | 174 | $ | 154 | |||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Reconciliation of Income Tax Expense (Benefit) | |||||||||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 144 | $ | 147 | $ | 126 | |||||||||||
| Increase (decrease) due to: | |||||||||||||||||
| State income taxes, net of federal income tax benefit | 49 | 54 | 46 | ||||||||||||||
| Depreciation and other items not normalized | (9) | (7) | (5) | ||||||||||||||
| Amortization of excess deferred federal income taxes (a) | (11) | (12) | (14) | ||||||||||||||
| State income tax rate change (b) | — | (9) | — | ||||||||||||||
| Other | (5) | 1 | 1 | ||||||||||||||
| Total increase (decrease) | 24 | 27 | 28 | ||||||||||||||
| Total income tax expense (benefit) | $ | 168 | $ | 174 | $ | 154 | |||||||||||
| Effective income tax rate | 24.5% | 24.9% | 25.7% | ||||||||||||||
(a)In 2023, 2022, and 2021, PPL Electric recorded lower income tax expense for the amortization of excess deferred taxes that primarily resulted from the U.S. federal corporate income tax rate reduction from 35% to 21% enacted by the TCJA. This amortization represents each year's refund amount, prior to a tax gross-up, to be paid to customers for previously collected deferred taxes at higher income tax rates.
(b)2022 includes a deferred tax benefit of $9 million due to the corporate net income tax rate reduction. See "Other - Pennsylvania State Tax Reform" below for additional information.
| 2017 | 2016 | 2015 | |||||||||
| Income Tax Expense (Benefit) | |||||||||||
| Current - Federal | $ | (65 | ) | $ | (29 | ) | $ | (80 | ) | ||
| Current - State | 20 | 19 | 23 | ||||||||
| Total Current Expense (Benefit) | (45 | ) | (10 | ) | (57 | ) | |||||
| Deferred - Federal (a) | 234 | 193 | 287 | ||||||||
| Deferred - State | 29 | 29 | 12 | ||||||||
| Total Deferred Expense, excluding operating loss carryforwards | 263 | 222 | 299 | ||||||||
119
| 2017 | 2016 | 2015 | |||||||||
| Amortization of investment tax credit | — | — | — | ||||||||
| Tax expense (benefit) of operating loss carryforwards | |||||||||||
| Deferred - Federal | (5 | ) | — | (75 | ) | ||||||
| Deferred - State | — | — | (3 | ) | |||||||
| Total Tax Expense (Benefit) of Operating Loss Carryforwards | (5 | ) | — | (78 | ) | ||||||
| Total income tax expense | $ | 213 | $ | 212 | $ | 164 | |||||
| Total income tax expense - Federal | $ | 164 | $ | 164 | $ | 132 | |||||
| Total income tax expense - State | 49 | 48 | 32 | ||||||||
| Total income tax expense | $ | 213 | $ | 212 | $ | 164 | |||||
| 2017 | 2016 | 2015 | |||||||||
| Reconciliation of Income Taxes | |||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 35% | $ | 201 | $ | 193 | $ | 146 | |||||
| Increase (decrease) due to: | |||||||||||
| State income taxes, net of federal income tax benefit | 36 | 36 | 25 | ||||||||
| Depreciation not normalized | (8 | ) | (8 | ) | (4 | ) | |||||
| Stock-based compensation (a) | (2 | ) | (6 | ) | — | ||||||
| Deferred tax impact of U.S. tax reform (b) | (13 | ) | — | — | |||||||
| Other | (1 | ) | (3 | ) | (3 | ) | |||||
| Total increase (decrease) | 12 | 19 | 18 | ||||||||
| Total income tax expense | $ | 213 | $ | 212 | $ | 164 | |||||
| Effective income tax rate | 37.0 | % | 38.4 | % | 39.4 | % | |||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Taxes, other than income | |||||||||||||||||
| State gross receipts | $ | 136 | $ | 142 | $ | 113 | |||||||||||
| Property and other | 7 | 7 | 7 | ||||||||||||||
| Total | $ | 143 | $ | 149 | $ | 120 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Taxes, other than income | |||||||||||
| State gross receipts (a) | $ | 102 | $ | 100 | $ | 89 | |||||
| Property and other | 5 | 5 | 5 | ||||||||
| Total | $ | 107 | $ | 105 | $ | 94 | |||||
| 2017 (a) | 2016 | ||||||
| Deferred Tax Assets | |||||||
| Federal loss carryforwards | $ | 150 | $ | 248 | |||
| State loss carryforwards | 41 | 35 | |||||
| Federal tax credit carryforwards | 181 | 186 | |||||
| Contributions in aid of construction | 17 | 29 | |||||
| Regulatory liabilities | 37 | 60 | |||||
| Accrued pension costs | 29 | 58 | |||||
| Income taxes due to customers (b) | 305 | 15 | |||||
| Deferred investment tax credits | 33 | 51 | |||||
| Derivative liability | 7 | 12 | |||||
| Other | 26 | 49 | |||||
| Valuation allowances | (8 | ) | (11 | ) | |||
| Total deferred tax assets | 818 | 732 | |||||
| Deferred Tax Liabilities | |||||||
| Plant - net (b) | 1,615 | 2,352 | |||||
| Regulatory assets | 61 | 102 | |||||
| Other | 8 | 13 | |||||
| Total deferred tax liabilities | 1,684 | 2,467 | |||||
| Net deferred tax liability | $ | 866 | $ | 1,735 | |||
| Gross | Deferred Tax Asset | Valuation Allowance | Expiration | ||||||||||
| Loss carryforwards (a) | |||||||||||||
| Federal net operating losses | $ | 713 | $ | 150 | $ | — | 2028-2037 | ||||||
| Federal charitable contributions | 14 | 3 | — | 2020-2022 | |||||||||
| State net operating losses | 874 | 41 | — | 2028-2037 | |||||||||
| Credit carryforwards | |||||||||
| Federal investment tax credit | 133 | — | 2025-2036 | ||||||
| Federal alternative minimum tax credit (b) | 27 | — | Indefinite | ||||||
| Federal - other | 21 | (8 | ) | 2019-2037 | |||||
| State - other | 1 | — | Indefinite | ||||||
Balance at Beginning of Period | Additions | Deductions | Balance at End of Period | ||||||||||||
| 2017 | $ | 11 | $ | 4 | (a) | $ | 7 | (b) | $ | 8 | |||||
| 2016 | 12 | — | 1 | (b) | 11 | ||||||||||
| 2015 | — | 12 | (c) | — | 12 | ||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Income Tax Expense (Benefit) | |||||||||||
| Current - Federal | $ | 74 | $ | (36 | ) | $ | 2 | ||||
| Current - State | 6 | 1 | 1 | ||||||||
| Total Current Expense (Benefit) | 80 | (35 | ) | 3 | |||||||
| Deferred - Federal (a) | 268 | 248 | 405 | ||||||||
| Deferred - State | 32 | 38 | 32 | ||||||||
| Total Deferred Expense, excluding benefits of operating loss carryforwards | 300 | 286 | 437 | ||||||||
| Amortization of investment tax credit - Federal | (3 | ) | (3 | ) | (3 | ) | |||||
| Tax benefit of operating loss carryforwards | |||||||||||
| Deferred - Federal | (2 | ) | 10 | (198 | ) | ||||||
| Deferred - State | — | (1 | ) | — | |||||||
| Total Tax Expense (Benefit) of Operating Loss Carryforwards | (2 | ) | 9 | (198 | ) | ||||||
| Total income tax expense from continuing operations (b) | $ | 375 | $ | 257 | $ | 239 | |||||
| Total income tax expense - Federal | $ | 337 | $ | 219 | $ | 206 | |||||
| Total income tax expense - State | 38 | 38 | 33 | ||||||||
| Total income tax expense from continuing operations (b) | $ | 375 | $ | 257 | $ | 239 | |||||
| 2017 | 2016 | 2015 | |||||||||
| Reconciliation of Income Taxes | |||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 35% | $ | 242 | $ | 240 | $ | 211 | |||||
| Increase (decrease) due to: | |||||||||||
| State income taxes, net of federal income tax benefit | 25 | 25 | 22 | ||||||||
| Amortization of investment tax credit | (3 | ) | (3 | ) | (3 | ) | |||||
| Valuation allowance adjustment (a) | — | — | 12 | ||||||||
| Stock-based compensation (b) | 1 | (3 | ) | — | |||||||
| Deferred tax impact of U.S. tax reform (c) | 112 | — | — | ||||||||
| Other | (2 | ) | (2 | ) | (3 | ) | |||||
| Total increase | 133 | 17 | 28 | ||||||||
| Total income tax expense | $ | 375 | $ | 257 | $ | 239 | |||||
| Effective income tax rate | 54.3 | % | 37.5 | % | 39.6 | % | |||||
| 2017 | 2016 | 2015 | |||||||||
| Taxes, other than income | |||||||||||
| Property and other | $ | 65 | $ | 62 | $ | 57 | |||||
| Total | $ | 65 | $ | 62 | $ | 57 | |||||
(LG&E)
The provision for LG&E's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of LG&E's deferred income tax assets and liabilities were as follows:
| 2023 | 2022 | ||||||||||
| Deferred Tax Assets | |||||||||||
| Contributions in aid of construction | $ | 18 | $ | 17 | |||||||
| Regulatory liabilities | 19 | 18 | |||||||||
| Accrued pension and postretirement costs | 3 | — | |||||||||
| Deferred investment tax credits | 8 | 8 | |||||||||
| Income taxes due to customers | 115 | 119 | |||||||||
| State tax credit carryforwards | 8 | 9 | |||||||||
| Lease liabilities | 4 | 4 | |||||||||
| Valuation allowances | (8) | (9) | |||||||||
| Other | 8 | 8 | |||||||||
| Total deferred tax assets | 175 | 174 | |||||||||
| Deferred Tax Liabilities | |||||||||||
| Plant - net | 877 | 869 | |||||||||
| Regulatory assets | 67 | 69 | |||||||||
| Lease right-of-use assets | 3 | 3 | |||||||||
| Other | 4 | 4 | |||||||||
| Total deferred tax liabilities | 951 | 945 | |||||||||
| Net deferred tax liability | $ | 776 | $ | 771 | |||||||
| 2017 (a) | 2016 | ||||||
| Deferred Tax Assets | |||||||
| Federal loss carryforwards | $ | 29 | $ | 80 | |||
| Contributions in aid of construction | 11 | 18 | |||||
| Regulatory liabilities | 21 | 34 | |||||
| Deferred investment tax credits | 9 | 14 | |||||
| Income taxes due to customers (b) | 142 | 17 | |||||
| Derivative liability | 7 | 12 | |||||
| Other | 12 | 17 | |||||
| Total deferred tax assets | 231 | 192 | |||||
| Deferred Tax Liabilities | |||||||
| Plant - net (b) | 724 | 1,058 | |||||
| Regulatory assets | 40 | 65 | |||||
| Accrued pension costs | 34 | 35 | |||||
| Other | 5 | 8 | |||||
| Total deferred tax liabilities | 803 | 1,166 | |||||
| Net deferred tax liability | $ | 572 | $ | 974 | |||
At December 31, 2017,2023, LG&E had $140$8 million of federal net operating lossstate credit carryforwards that expire in 20352028 and $6an $8 million of federalvaluation allowance related to state credit carryforwards that expire from 2034due to 2037.insufficient projected Kentucky taxable income.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
| 2023 | 2022 | 2021 | |||||||||||||||
| Income Tax Expense (Benefit) | |||||||||||||||||
| Current - Federal | $ | 70 | $ | 60 | $ | 41 | |||||||||||
| Current - State | 13 | 9 | 5 | ||||||||||||||
| Total Current Expense (Benefit) | 83 | 69 | 46 | ||||||||||||||
| Deferred - Federal | (15) | (10) | 1 | ||||||||||||||
| Deferred - State | 2 | 5 | 8 | ||||||||||||||
| Total Deferred Expense (Benefit) | (13) | (5) | 9 | ||||||||||||||
| Amortization of investment tax credit - Federal | (1) | (1) | (1) | ||||||||||||||
| Total income tax expense (benefit) | $ | 69 | $ | 63 | $ | 54 | |||||||||||
| Total income tax expense (benefit) - Federal | $ | 54 | $ | 49 | $ | 41 | |||||||||||
| Total income tax expense (benefit) - State | 15 | 14 | 13 | ||||||||||||||
| Total income tax expense (benefit) | $ | 69 | $ | 63 | $ | 54 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Income Tax Expense (Benefit) | |||||||||||
| Current - Federal | $ | — | $ | (22 | ) | $ | (15 | ) | |||
| Current - State | 5 | 1 | 3 | ||||||||
| Total current Expense (Benefit) | 5 | (21 | ) | (12 | ) | ||||||
| Deferred - Federal | 112 | 134 | 190 | ||||||||
| Deferred - State | 14 | 18 | 13 | ||||||||
| Total Deferred Expense, excluding benefits of operating loss carryforwards | 126 | 152 | 203 | ||||||||
| Amortization of investment tax credit - Federal | (1 | ) | (1 | ) | (1 | ) | |||||
| Tax benefit of operating loss carryforwards | |||||||||||
| Deferred - Federal | 1 | (4 | ) | (76 | ) | ||||||
| Total Tax Benefit of Operating Loss Carryforwards | 1 | (4 | ) | (76 | ) | ||||||
| Total income tax expense | $ | 131 | $ | 126 | $ | 114 | |||||
| Total income tax expense - Federal | $ | 112 | $ | 107 | $ | 98 | |||||
| Total income tax expense - State | 19 | 19 | 16 | ||||||||
| Total income tax expense | $ | 131 | $ | 126 | $ | 114 | |||||
120
| 2023 | 2022 | 2021 | |||||||||||||||
| Reconciliation of Income Tax Expense (Benefit) | |||||||||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 70 | $ | 70 | $ | 64 | |||||||||||
| Increase (decrease) due to: | |||||||||||||||||
| State income taxes, net of federal income tax benefit | 13 | 13 | 12 | ||||||||||||||
| Amortization of excess deferred federal and state income taxes | (13) | (18) | (20) | ||||||||||||||
| Other | (1) | (2) | (2) | ||||||||||||||
| Total increase (decrease) | (1) | (7) | (10) | ||||||||||||||
| Total income tax expense (benefit) | $ | 69 | $ | 63 | $ | 54 | |||||||||||
| Effective income tax rate | 20.6% | 18.8% | 17.8% | ||||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Reconciliation of Income Taxes | |||||||||||
| Federal income tax on Income Before Income Taxes at | |||||||||||
| statutory tax rate - 35% | $ | 120 | $ | 115 | $ | 105 | |||||
| Increase (decrease) due to: | |||||||||||
| State income taxes, net of federal income tax benefit | 13 | 12 | 11 | ||||||||
| Amortization of investment tax credit | (1 | ) | (1 | ) | (1 | ) | |||||
| Other | (1 | ) | — | (1 | ) | ||||||
| Total increase | 11 | 11 | 9 | ||||||||
| Total income tax expense | $ | 131 | $ | 126 | $ | 114 | |||||
| Effective income tax rate | 38.1 | % | 38.3 | % | 38.1 | % | |||||
| 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||
| Taxes, other than income | Taxes, other than income | |||||||||||||||||||||||||||||||||
| Property and other | $ | 33 | $ | 32 | $ | 28 | ||||||||||||||||||||||||||||
| Total | $ | 33 | $ | 32 | $ | 28 | ||||||||||||||||||||||||||||
(KU)
The provision for KU's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC, the VSCC and the FERC. The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.
Significant components of KU's deferred income tax assets and liabilities were as follows:
| 2023 | 2022 | ||||||||||
| Deferred Tax Assets | |||||||||||
| Contributions in aid of construction | $ | 10 | $ | 9 | |||||||
| Regulatory liabilities | 23 | 23 | |||||||||
| Deferred investment tax credits | 21 | 21 | |||||||||
| Income taxes due to customers | 131 | 136 | |||||||||
| State tax credit carryforwards | 4 | 4 | |||||||||
| Lease liabilities | 5 | 5 | |||||||||
| Valuation allowances | (2) | (3) | |||||||||
| Other | 5 | 4 | |||||||||
| Total deferred tax assets | 197 | 199 | |||||||||
| Deferred Tax Liabilities | |||||||||||
| Plant - net | 1,045 | 1,028 | |||||||||
| Regulatory assets | 50 | 56 | |||||||||
| Pension and postretirement costs | 7 | 6 | |||||||||
| Lease right-of-use assets | 5 | 5 | |||||||||
| Other | 2 | — | |||||||||
| Total deferred tax liabilities | 1,109 | 1,095 | |||||||||
| Net deferred tax liability | $ | 912 | $ | 896 | |||||||
| 2017 (a) | 2016 | ||||||
| Deferred Tax Assets | |||||||
| Federal loss carryforwards | $ | 13 | $ | 79 | |||
| Contributions in aid of construction | 6 | 11 | |||||
| Regulatory liabilities | 16 | 26 | |||||
| Deferred investment tax credits | 24 | 37 | |||||
| Income taxes due to customers (b) | 163 | — | |||||
| Other | 9 | 11 | |||||
| Total deferred tax assets | 231 | 164 | |||||
| Deferred Tax Liabilities | |||||||
| Plant - net (b) | 882 | 1,280 | |||||
| Regulatory assets | 21 | 37 | |||||
| Accrued pension costs | 17 | 12 | |||||
| Other | 2 | 5 | |||||
| Total deferred tax liabilities | 922 | 1,334 | |||||
| Net deferred tax liability | $ | 691 | $ | 1,170 | |||
At December 31, 2017,2023, KU had $61$4 million of federal net operating lossstate credit carryforwards thatof which $2 million will expire in 20352028 and $6$2 million of federalthat has an indefinite carryforward period. At December 31, 2023, KU had a $2 million valuation allowance related to state credit carryforwards that expire from 2034due to 2037.insufficient projected Kentucky taxable income.
121
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:
| 2023 | 2022 | 2021 | |||||||||||||||
| Income Tax Expense (Benefit) | |||||||||||||||||
| Current - Federal | $ | 73 | $ | 63 | $ | 58 | |||||||||||
| Current - State | 13 | 11 | 8 | ||||||||||||||
| Total Current Expense (Benefit) | 86 | 74 | 66 | ||||||||||||||
| Deferred - Federal | (11) | (3) | (4) | ||||||||||||||
| Deferred - State | 4 | 7 | 7 | ||||||||||||||
| Total Deferred Expense (Benefit) | (7) | 4 | 3 | ||||||||||||||
| Amortization of investment tax credit - Federal | (2) | (2) | (2) | ||||||||||||||
| Total income tax expense (benefit) | $ | 77 | $ | 76 | $ | 67 | |||||||||||
| Total income tax expense (benefit) - Federal | $ | 60 | $ | 58 | $ | 52 | |||||||||||
| Total income tax expense (benefit) - State | 17 | 18 | 15 | ||||||||||||||
| Total income tax expense (benefit) | $ | 77 | $ | 76 | $ | 67 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Income Tax Expense (Benefit) | |||||||||||
| Current - Federal | $ | — | $ | 31 | $ | (21 | ) | ||||
| Current - State | 7 | 5 | 1 | ||||||||
| Total Current Expense (Benefit) | 7 | 36 | (20 | ) | |||||||
| Deferred - Federal | 138 | 131 | 240 | ||||||||
| Deferred - State | 16 | 19 | 19 | ||||||||
| Total Deferred Expense, excluding benefits of operating loss carryforwards | 154 | 150 | 259 | ||||||||
| Amortization of investment tax credit - Federal | (2 | ) | (2 | ) | (2 | ) | |||||
| Tax benefit of operating loss carryforwards | |||||||||||
| Deferred - Federal | — | (21 | ) | (97 | ) | ||||||
| Total Tax Benefit of Operating Loss Carryforwards | — | (21 | ) | (97 | ) | ||||||
| Total income tax expense (a) | $ | 159 | $ | 163 | $ | 140 | |||||
| Total income tax expense - Federal | $ | 136 | $ | 139 | $ | 120 | |||||
| Total income tax expense - State | 23 | 24 | 20 | ||||||||
| Total income tax expense (a) | $ | 159 | $ | 163 | $ | 140 | |||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Reconciliation of Income Tax Expense (Benefit) | |||||||||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 21% | $ | 82 | $ | 84 | $ | 76 | |||||||||||
| Increase (decrease) due to: | |||||||||||||||||
| State income taxes, net of federal income tax benefit | 15 | 16 | 14 | ||||||||||||||
| Amortization of investment tax credit | (2) | (2) | (2) | ||||||||||||||
| Amortization of excess deferred federal and state income taxes | (17) | (21) | (20) | ||||||||||||||
| Other | (1) | (1) | (1) | ||||||||||||||
| Total decrease | (5) | (8) | (9) | ||||||||||||||
| Total income tax expense (benefit) | $ | 77 | $ | 76 | $ | 67 | |||||||||||
| Effective income tax rate | 19.8% | 19.1% | 18.4% | ||||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Reconciliation of Income Taxes | |||||||||||
| Federal income tax on Income Before Income Taxes at statutory tax rate - 35% | $ | 146 | $ | 150 | $ | 131 | |||||
| Increase (decrease) due to: | |||||||||||
| State income taxes, net of federal income tax benefit | 15 | 16 | 13 | ||||||||
| Amortization of investment tax credit | (2 | ) | (2 | ) | (2 | ) | |||||
| Other | — | (1 | ) | (2 | ) | ||||||
| Total increase | 13 | 13 | 9 | ||||||||
| Total income tax expense | $ | 159 | $ | 163 | $ | 140 | |||||
| Effective income tax rate | 38.0 | % | 38.1 | % | 37.4 | % | |||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Taxes, other than income | |||||||||||||||||
| Property and other | $ | 45 | $ | 45 | $ | 41 | |||||||||||
| Total | $ | 45 | $ | 45 | $ | 41 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Taxes, other than income | |||||||||||
| Property and other | $ | 32 | $ | 30 | $ | 29 | |||||
| Total | $ | 32 | $ | 30 | $ | 29 | |||||
Unrecognized Tax Benefits(All Registrants)
PPL or its subsidiaries file tax returns in four major tax jurisdictions. The income tax provisions for PPL Electric, LG&E and KU are calculated in accordance with an intercompany tax sharing agreement, which provides that taxable income be calculated as if each domestic subsidiary filed a separate consolidated return. Based on this tax sharing agreement, PPL Electric or its subsidiaries indirectly or directly file tax returns in twothree major tax jurisdictions, and LKE, LG&E and KU or their subsidiaries indirectly or directly file tax returns in two major tax jurisdictions. With few exceptions, at December 31, 2017,2023, these jurisdictions, as well as the tax years that are no longer subject to examination, were as follows.
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||||
| U.S. (federal) | 2019 and prior | 2019 and prior | 2019 and prior | 2019 and prior | |||||||||||||||||||||
| Pennsylvania (state) | |||||||||||||||||||||||||
| U.K. (foreign) | |||||||||||||||||||||||||
122
Other
Purchase of Renewable Tax Credits (PPL)
During 2023, PPL purchased approximately $300 million of renewable tax credits, as allowed by the IRA. The credits were acquired at a discount. PPL believes that it will be able to monetize the acquired credits within the foreseeable future and recorded the associated benefit of the discount as a reduction of income taxes as of December 31, 2023. In 2015,addition, PPL recorded a deferred tax benefitasset representing credits that will be utilized in future periods.
Narragansett Electric Acquisition (PPL)
The acquisition of $24 million,Narragansett Electric on May 25, 2022 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 bases 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. This election resulted in tax goodwill that 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 settlementstate tax code, the bill reduces the corporate net income tax rate from 9.99% to 8.99% beginning January 1, 2023, and further reduces the rate annually by half a percentage point until the rate reaches 4.99% in 2031.
Inflation Reduction Act (All Registrants)
On August 16, 2022, the IRA was signed into law. Among other things, the IRA enacted a new 15% corporate "book minimum tax," which is based on adjusted GAAP pre-tax income and is only applicable to corporations whose pre-tax income exceeds a certain threshold. PPL does not expect to be subject to the book minimum tax for the year ended December 31, 2023. The Registrants will continue to assess the impacts of the IRA on their financial statements and will monitor guidance issued by the U.S. Treasury in the future. In addition, the IRA enacted numerous new tax credits, largely associated with renewable energy. PPL continues to assess the applicability of these provisions to PPL and its subsidiaries.
IRS auditRevenue Procedure 2023-15 (PPL and LG&E)
On April 14, 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized for tax years 1998-2011. Of this amount, $12 million is reflected in continuing operations.purposes. PPL finalizedand LG&E are currently reviewing the settlement of interest in 2016 and recorded an additional $3 million tax benefit.revenue procedure to determine its potential impact on their financial statements.
Regulatory Assets and Liabilities
(All Registrants)
PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to an item will be recovered or refunded within a year of the balance sheet date.
(PPL)
123
(PPL, LKE, LG&E and KU)
LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the FERC and the VSCC.
LG&E's and KU's Kentucky base rates are calculated based on recovery of costs as well as a return on capitalization (common equity, long-term debt and short-term debt) including adjustments for certain net investments and costs recovered separately through other means. As such, LG&E and KU generally earn a return on regulatory assets.
(PPL LKE and KU)
KU's Virginia base rates are calculated based on recovery of costs as well as a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). AllAs all regulatory assets and liabilities, except for regulatory assets and liabilities related to the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates. Therefore, no return is earned on the related assets.
KU's rates to municipal customers for wholesale power requirements are calculated based on annual updates to a formula rate that utilizes a return on rate base (net utility plant plus working capital less accumulated deferred income taxes and miscellaneous deductions). As all regulatory assets and liabilities, except accumulated deferred income taxes, are excluded from the return on rate base utilized in the development of municipal rates, no return is earned on the related assets.
(PPL and PPL Electric)
PPL Electric is subject to the jurisdiction of the PAPUC and the FERC. PPL Electric's distribution base rates are calculated based on recovery of costs as well as a return on distribution rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions). PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recovery of transmission costs incurred, a return on transmission-related rate base (net utility plant plus a working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions) and an automatic annual update. See "Transmission Formula Rate" below for additional information on this tariff. All regulatory assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.
(All Registrants)
The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations at December 31,:31:
| PPL | PPL Electric | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Current Regulatory Assets: | |||||||||||||||
| Environmental cost recovery | $ | 5 | $ | 6 | $ | — | $ | — | |||||||
| Generation formula rate | 6 | 11 | — | — | |||||||||||
| Transmission service charge | — | 7 | — | 7 | |||||||||||
| Gas supply clause | 4 | 3 | — | — | |||||||||||
| Smart meter rider | 15 | 6 | 15 | 6 | |||||||||||
| Storm costs | — | 5 | — | 5 | |||||||||||
| Other | 4 | 1 | 1 | 1 | |||||||||||
| Total current regulatory assets (a) | $ | 34 | $ | 39 | $ | 16 | $ | 19 | |||||||
| Noncurrent Regulatory Assets: | |||||||||||||||
| Defined benefit plans | $ | 880 | $ | 947 | $ | 504 | $ | 549 | |||||||
| Taxes recoverable through future rates | 3 | 340 | 3 | 340 | |||||||||||
| Storm costs | 33 | 57 | — | 9 | |||||||||||
| Unamortized loss on debt | 54 | 61 | 29 | 36 | |||||||||||
| Interest rate swaps | 26 | 31 | — | — | |||||||||||
| Terminated interest rate swaps | 92 | 98 | — | — | |||||||||||
| Accumulated cost of removal of utility plant | 173 | 159 | 173 | 159 | |||||||||||
| AROs | 234 | 211 | — | — | |||||||||||
| Other | 9 | 14 | — | 1 | |||||||||||
| Total noncurrent regulatory assets | $ | 1,504 | $ | 1,918 | $ | 709 | $ | 1,094 | |||||||
124
| Current Regulatory Liabilities: | |||||||||||||||
| Generation supply charge | $ | 34 | $ | 23 | $ | 34 | $ | 23 | |||||||
| Transmission service charge | 9 | — | 9 | — | |||||||||||
| Universal service rider | 26 | 14 | 26 | 14 | |||||||||||
| Transmission formula rate | 9 | 15 | 9 | 15 | |||||||||||
| Fuel adjustment clauses | 3 | 11 | — | — | |||||||||||
| Act 129 compliance rider | — | 17 | — | 17 | |||||||||||
| Storm damage expense rider | 8 | 13 | 8 | 13 | |||||||||||
| Other | 6 | 8 | — | 1 | |||||||||||
| Total current regulatory liabilities | $ | 95 | $ | 101 | $ | 86 | $ | 83 | |||||||
| Noncurrent Regulatory Liabilities: | |||||||||||||||
| Accumulated cost of removal of utility plant | $ | 677 | $ | 700 | $ | — | $ | — | |||||||
| Power purchase agreement - OVEC (b) | 68 | 75 | — | — | |||||||||||
| Net deferred taxes (c) | 1,853 | 23 | 668 | — | |||||||||||
| Defined benefit plans | 27 | 23 | — | — | |||||||||||
| Terminated interest rate swaps | 74 | 78 | — | — | |||||||||||
| Other | 5 | — | — | — | |||||||||||
| Total noncurrent regulatory liabilities | $ | 2,704 | $ | 899 | $ | 668 | $ | — | |||||||
| LKE | LG&E | KU | |||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||
| Current Regulatory Assets: | |||||||||||||||||||||||
| Environmental cost recovery | $ | 5 | $ | 6 | $ | 5 | $ | 6 | $ | — | $ | — | |||||||||||
| Generation formula rate | 6 | 11 | — | — | 6 | 11 | |||||||||||||||||
| Gas supply clause | 4 | 3 | 4 | 3 | — | — | |||||||||||||||||
| Other | 3 | — | 3 | — | — | — | |||||||||||||||||
| Total current regulatory assets | $ | 18 | $ | 20 | $ | 12 | $ | 9 | $ | 6 | $ | 11 | |||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| Current Regulatory Assets: | |||||||||||||||||||||||||||||||||||||||||||||||
| Gas supply clause | $ | — | $ | 41 | $ | — | $ | — | $ | — | $ | 13 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Rate adjustment mechanism | 118 | 96 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Renewable energy certificates | 14 | 14 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Derivative Instruments | 51 | 41 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Smart meter rider | 6 | 5 | 6 | 5 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Storm damage expense | 12 | — | 12 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Universal service rider | — | 3 | — | 3 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Fuel adjustment clause | 4 | 38 | — | — | 3 | 9 | — | 29 | |||||||||||||||||||||||||||||||||||||||
| Transmission service charge | 43 | — | 31 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| DSIC | 7 | 5 | 7 | 5 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Other | 38 | 15 | 1 | — | 4 | 1 | 3 | 3 | |||||||||||||||||||||||||||||||||||||||
| Total current regulatory assets | $ | 293 | $ | 258 | $ | 57 | $ | 13 | $ | 7 | $ | 23 | $ | 3 | $ | 32 | |||||||||||||||||||||||||||||||
| Noncurrent Regulatory Assets: | |||||||||||||||||||||||||||||||||||||||||||||||
| Defined benefit plans | $ | 887 | $ | 778 | $ | 417 | $ | 353 | $ | 217 | $ | 209 | $ | 136 | $ | 140 | |||||||||||||||||||||||||||||||
| Plant outage cost | 38 | 46 | — | — | 10 | 12 | 28 | 34 | |||||||||||||||||||||||||||||||||||||||
| Net Metering | 112 | 61 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Environmental Cost recovery | 99 | 102 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Taxes recoverable through future rates | — | 47 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Storm costs | 97 | 118 | — | — | 15 | 7 | 14 | 3 | |||||||||||||||||||||||||||||||||||||||
| Unamortized loss on debt | 22 | 21 | 3 | 3 | 10 | 11 | 7 | 7 | |||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | 7 | 7 | — | — | 7 | 7 | — | — | |||||||||||||||||||||||||||||||||||||||
| Terminated interest rate swaps | 58 | 63 | — | — | 34 | 37 | 24 | 26 | |||||||||||||||||||||||||||||||||||||||
| Accumulated cost of removal of utility plant | 178 | 212 | 178 | 212 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| AROs | 289 | 295 | — | — | 76 | 76 | 213 | 219 | |||||||||||||||||||||||||||||||||||||||
| Derivative Instruments | 8 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Other | 79 | 69 | — | — | 26 | 14 | 17 | 13 | |||||||||||||||||||||||||||||||||||||||
| Total noncurrent regulatory assets | $ | 1,874 | $ | 1,819 | $ | 598 | $ | 568 | $ | 395 | $ | 373 | $ | 439 | $ | 442 | |||||||||||||||||||||||||||||||
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| Current Regulatory Liabilities: | |||||||||||||||||||||||||||||||||||||||||||||||
| Generation supply charge | $ | 51 | $ | 37 | $ | 51 | $ | 37 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Transmission service charge | — | 14 | — | 7 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| TCJA customer refund | 5 | 15 | 5 | 15 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Act 129 compliance rider | 15 | 14 | 15 | 14 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Transmission formula rate | 21 | 12 | 18 | 12 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Rate adjustment mechanism | 72 | 96 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Energy efficiency | 23 | 23 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Gas supply clause | 15 | — | — | — | 15 | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Other | 23 | 27 | 2 | — | 1 | 7 | 1 | 6 | |||||||||||||||||||||||||||||||||||||||
Total current regulatory liabilities | $ | 225 | $ | 238 | $ | 91 | $ | 85 | $ | 16 | $ | 7 | $ | 1 | $ | 6 | |||||||||||||||||||||||||||||||
| Noncurrent Regulatory Liabilities: | |||||||||||||||||||||||||||||||||||||||||||||||
| Accumulated cost of removal of utility plant | $ | 996 | $ | 950 | $ | — | $ | — | $ | 306 | $ | 287 | $ | 399 | $ | 389 | |||||||||||||||||||||||||||||||
| Power purchase agreement - OVEC | 19 | 26 | — | — | 13 | 18 | 6 | 8 | |||||||||||||||||||||||||||||||||||||||
| Net deferred taxes | 1,977 | 2,094 | 763 | 775 | 459 | 477 | 523 | 546 | |||||||||||||||||||||||||||||||||||||||
| Defined benefit plans | 252 | 187 | 73 | 45 | 20 | 21 | 59 | 56 | |||||||||||||||||||||||||||||||||||||||
| Terminated interest rate swaps | 57 | 60 | — | — | 29 | 30 | 28 | 30 | |||||||||||||||||||||||||||||||||||||||
| Energy efficiency | 5 | 32 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Other | 34 | 63 | — | — | — | — | 3 | — | |||||||||||||||||||||||||||||||||||||||
| Total noncurrent regulatory liabilities | $ | 3,340 | $ | 3,412 | $ | 836 | $ | 820 | $ | 827 | $ | 833 | $ | 1,018 | $ | 1,029 | |||||||||||||||||||||||||||||||
| LKE | LG&E | KU | |||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||
| Noncurrent Regulatory Assets: | |||||||||||||||||||||||
| Defined benefit plans | $ | 376 | $ | 398 | $ | 234 | $ | 246 | $ | 142 | $ | 152 | |||||||||||
| Storm costs | 33 | 48 | 18 | 26 | 15 | 22 | |||||||||||||||||
| Unamortized loss on debt | 25 | 25 | 16 | 16 | 9 | 9 | |||||||||||||||||
| Interest rate swaps | 26 | 31 | 26 | 31 | — | — | |||||||||||||||||
| Terminated interest rate swaps | 92 | 98 | 54 | 57 | 38 | 41 | |||||||||||||||||
| AROs | 234 | 211 | 61 | 70 | 173 | 141 | |||||||||||||||||
| Other | 9 | 13 | 2 | 4 | 7 | 9 | |||||||||||||||||
| Total noncurrent regulatory assets | $ | 795 | $ | 824 | $ | 411 | $ | 450 | $ | 384 | $ | 374 | |||||||||||
| Current Regulatory Liabilities: | |||||||||||||||||||||||
| Demand side management | $ | — | $ | 3 | $ | — | $ | 2 | $ | — | $ | 1 | |||||||||||
| Fuel adjustment clause | 3 | 11 | — | 2 | 3 | 9 | |||||||||||||||||
| Gas line tracker | 3 | — | 3 | — | — | — | |||||||||||||||||
| Other | 3 | 4 | — | 1 | 3 | 3 | |||||||||||||||||
| Total current regulatory liabilities | $ | 9 | $ | 18 | $ | 3 | $ | 5 | $ | 6 | $ | 13 | |||||||||||
| Noncurrent Regulatory Liabilities: | |||||||||||||||||||||||
| Accumulated cost of removal | |||||||||||||||||||||||
| of utility plant | $ | 677 | $ | 700 | $ | 282 | $ | 305 | $ | 395 | $ | 395 | |||||||||||
| Power purchase agreement - OVEC (b) | 68 | 75 | 47 | 52 | 21 | 23 | |||||||||||||||||
| Net deferred taxes (c) | 1,185 | 23 | 552 | 23 | 633 | — | |||||||||||||||||
| Defined benefit plans | 27 | 23 | — | — | 27 | 23 | |||||||||||||||||
| Terminated interest rate swaps | 74 | 78 | 37 | 39 | 37 | 39 | |||||||||||||||||
| Other | 5 | — | 1 | — | 4 | — | |||||||||||||||||
| Total noncurrent regulatory liabilities | $ | 2,036 | $ | 899 | $ | 919 | $ | 419 | $ | 1,117 | $ | 480 | |||||||||||
Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables. Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."
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Defined Benefit Plans
(All Registrants)
Defined benefit plan regulatory assets and liabilities represent prior service cost and net actuarial gains and losses that will be recovered in defined benefit plans expense through future base rates based upon established regulatory practices and, generally, are amortized over the average remaining service lives of plan participants. These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is remeasured. Of the regulatory asset and liability balances recorded, costs of $68 million for PPL, $30 million for PPL Electric, $38 million for LKE, $26 million for LG&E and $12 million for KU, are expected to be amortized into net periodic defined benefit costs in 2018 in accordance with PPL's, PPL Electric's, LKE's, LG&E's and KU's pension accounting policy.
(PPL, LKE, LG&E and KU)
As a result of the 2014 Kentuckyprevious rate case settlement that became effective July 1, 2015,settlements and orders, the difference between pension cost calculated in accordance with LG&E's and KU's pension accounting policy and pension cost calculated using a 15-year amortization period for actuarial gains and losses isand settlements are recorded as a regulatory asset. As of December 31, 2017,2023, the balances were $33$86 million for PPL, and LKE, $18$46 million for LG&E and $15$40 million for KU. As of December 31, 2016,2022, the balances were $20$107 million for PPL, and LKE, $11$57 million for LG&E and $9$50 million for KU. Of
(PPL)
RIE is subject to a pension rate adjustment mechanism whereby the costs expecteddifference in amounts allowed to be amortized into net periodic definedrecovered in rates versus actual costs of RIE’s pension and other postretirement benefit costs in 2018, $16 million for PPL and LKE, $10 million for LG&E and $6 million for KU,plans that are expected to be recovered from or passed back to customers in future periods, are also recorded as a regulatory asset in 2018.assets and liabilities.
(All Registrants)
Storm Costs
PPL Electric, LG&E and KU have the ability to request from the PUC,PAPUC, the KPSC and the VSCC, as applicable, the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once such authority is granted, LG&E and KU can request recovery of those expenses in a base rate case and begin amortizing the costs when recovery starts. PPL Electric can recover qualifying expenses caused by major storm events, as defined in its retail tariff, over three years through the Storm Damage Expense Rider commencing in the application year after the storm occurred. PPL Electric's, LG&E's and KU's regulatory assets for storm costs approved for base rate recovery are being amortized through various dates ending in 2020.2031.
As provided in the ASA, RIE has the authority from the RIPUC to treat certain incremental O&M expenses related to specific extraordinary storms as a regulatory asset and defer such costs for regulatory accounting and reporting purposes. Once all expenses for the extraordinary storm have been finalized, RIE files a final accounting of those storm expenses with the RIPUC that is subject to review by the RIPUC and the Rhode Island Division of Public Utilities and Carriers.
Unamortized Loss on Debt
Unamortized loss on reacquired debt represents losses on long-term debt refinanced, reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing). Such costs are being amortized through 20292053 for PPL Electric, through 2042 for KU, and through 2044 for PPL, LKE and LG&E.
Accumulated Cost of Removal of Utility Plant
RIE, LG&E and KU charge costs of removal through depreciation expense with an offsetting credit to a regulatory liability. The regulatory liability is relieved as costs are incurred.
PPL Electric does not accrue for costs of removal. When costs of removal are incurred, PPL Electric records the costs as a regulatory asset. Such deferral is included in rates and amortized over the subsequent five-yearfive-year period.
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Net Deferred Taxes
Regulatory liabilities associated with net deferred taxes represent the future revenue impact from the adjustment of deferred income taxes required primarily for excess deferred taxes and unamortized investment tax credits. At December 31, 2017, excess deferred taxes recorded ascredits, largely a result of the TCJA were $2.2 billion at PPL, $1.0 billion at PPL Electric, $1.2 billion at LKE, $532 million at LG&E and $634 million at KU, which include the gross-up associated with the excess deferred taxes.enacted in 2017.
(PPL and PPL Electric)
Distribution System Improvement Charge (DSIC)
The DSIC is authorized under Act 11 and is considered an alternative ratemaking mechanism providing more timely cost recovery of qualifying distribution system capital improvements. DSIC is charged to all customers taking distribution service as a percentage of total distribution revenue (excluding State Tax Adjustment Surcharge). DSIC is capped at 5% of the total amount billed to all customers for distribution service (including reconcilable riders) which provides a safeguard for customers. PPL Electric is permitted to utilize the DSIC mechanism so long as the rolling 12 month ROE for the applicable period does not exceed the PUC ROE in the company’s PAPUC quarterly financial report filing. The DSIC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
Generation Supply Charge (GSC)
The GSC is a cost recovery mechanism that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service. The recovery includes charges for generation supply, (energy and capacity and ancillary services), as well as administration of the acquisition process. In addition, the GSC contains a reconciliation mechanism whereby any over- or under-recovery from prior quartersperiods is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent rate filing period.
Transmission Service Charge (TSC)
PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers. PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approvedPAPUC-approved TSC cost recovery mechanism. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
RIE arranges transmission service on behalf of its customers and bills the costs of those services to customers, pursuant to its Transmission Service Cost Adjustment Provision. The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.
Transmission Formula Rate
PPL Electric's transmission revenues are billed in accordance with a FERC-approved Open Access Transmission Tariff that utilizes a formula-based rate recovery mechanism. Under this formula, beginning in 2023, rates are put into effect in Juneon January 1st of each year based upon prior year actual expenditures and current yearfrom the most recently filed FERC Form 1, forecasted capital additions.additions, and other data based on PPL Electric’s books and records. 2023 is considered a transitional period as the calendar year rate approved by FERC became effective April 1, 2023. Rates are then adjustedcompared during the following year to reflect actualthe estimated annual expenses and capital additions as reportedthat will be filed in PPL Electric'sElectric’s annual FERC Form 1, filed under the FERC's
Uniform System of Accounts. AnyUnder the mechanism, any difference between the revenue requirement in effect for the prior year and actual expenditures incurred for that year is recorded as a regulatory asset or regulatory liability.liability, and the regulatory asset or regulatory liability is to be recovered from or returned to customers starting one year after the conclusion of the rate year.
Storm Damage Expense Rider (SDER)
The SDER is a reconcilable automatic adjustment clause under which PPL Electric annually will compare actual storm costs to storm costs allowed in base rates and refund or recover any differences from customers. In the 2015 rate case settlement approved by the PUCPAPUC in November 2015, it was determined that reportable storm damage expenses to be recovered annually through base rates will be set at $15$20 million. The SDER will recover from or refund to customers as appropriate, onlythe applicable expenses from reportable storms that are greater than or less than $15as compared to the $20 million recovered annually through base rates. Beginning January 1, 2018, the amortized 2011 storm expense
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Act 129 Compliance Rider
In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric is currently in Phase IIV of PPL Electric'sthe energy efficiency and conservation plan which was approved by a PUC order in October 2009. The order allowed PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May 31, 2013.March 2021. Phase II of PPL's energy efficiency and conservation plan allowed PPL Electric to recover the maximum $185 million cost of the program over the three year period June 1, 2013 through May 31, 2016. Phase III of PPL's energy efficiency and conservation planIV allows PPL Electric to recover the maximum $313 million over the next five year-year period, June 1, 20162021 through May 31, 2021.2026. The plan includes programs intended to reduce electricity consumption. The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs. The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider. The Phase II program costs were reconciled at the end of the program and any remaining over- or under-recovery was rolled into Phase III. The actual Phase IIIIV program costs are reconcilable after each 12 month12-month period, and any over- or under-recovery from customers will be refunded or recovered over the next rate filing period. See below under "Regulatory Matters - Pennsylvania Activities" for additional information on Act 129.
Smart Meter Rider (SMR)
Act 129 which became effective November 14, 2008, requires each electric distribution company (EDC) with more than 100,000 customers to have a PUCPAPUC approved Smart Meter Technology Procurement and Installation Plan (SMP). As of December 31, 2019, PPL Electric filedreplaced substantially all of its initial SMP in 2009. However, in 2010, the PUC found that PPL Electric's "Advanced Metering Infrastructure" (AMI) system did not fully meet the standards of Act 129. In 2014, PPL Electric filed its current SMP, which was approved by the PUC in 2015. Under its SMP, PPL Electric will replace its currentold meters with new meters that meet the Act 129 requirements by the end of 2019. Underunder its SMP. In accordance with Act 129, EDCs are able to recover the costs and earn a return on capital of providing smart metering technology. PPL Electric uses a mechanism known as the Smart Meter Rider (SMR)SMR to recover the costs to implement its SMP on a full and current basis.SMP. The SMR is a reconciliation mechanism whereby any over-orover- or under-recovery from prior years is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarters.
Universal Service Rider (USR)
The USR provides for recovery of costs associated with universal service programs, OnTrack and Winter Relief Assistance Program (WRAP), provided by PPL Electric to residential customers. OnTrack is a special payment program for low-income households and WRAP provides low-income customers a means to reduce electric bills through energy saving methods. The USR rate is applied to residential customers who receive distribution service. The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.
TCJA Customer Refund
As a result of the reduced U.S federal corporate income tax rate as enacted by the TCJA, the PAPUC ruled that these tax benefits should be refunded to customers. Timing differences between the recognition of these tax benefits and the refund of the benefit to the customer creates a regulatory liability. PPL Electric's liability is being credited back to distribution customers through a temporary negative surcharge and remains in place until PPL Electric files and the PAPUC approves new base rates. The TCJA is reconcilable, and any over- or under-recovery from customers will be refunded or recovered annually in the subsequent year.
(PPL, LKE, LG&E and KU)
Fuel Adjustment Clauses
LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in power purchases and the cost of fuel to generate electricity, including transportation costs, from the costs embedded in base rates are adjusted in LG&E's and KU's rates. The KPSC requires formal reviews at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel adjustment clause and, to the extent appropriate, may conduct public hearings and reestablish the fuel charge included in base rates. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered within 12 months.
KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs and load for the fuel year (12 months ending March 31). The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the fuel year plus an adjustment for any under- or over-recovery of fuel expenses from the prior fuel year. The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered or refunded within 12 months.
AROs
As discussed in Note 1, 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.
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Power Purchase Agreement - OVEC
As a result of purchase accounting associated with PPL's acquisition of LG&E and KU, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LG&E and KU with offsets to regulatory liabilities. The regulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition. LG&E's and KU's customer rates continue to reflect the original contracts. See Notes 13 and 18 for additional discussion of the power purchase agreement.
Interest Rate Swaps
LG&E's unrealized gains and losses are recorded as regulatory assets or regulatory liabilities until they are realized as interest expense. Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures in 2033.
Terminated Interest Rate Swaps
Net realized gains and losses on all interest rate swaps are recovered through regulated rates. As such, any gains and losses on these derivatives are included in regulatory assets or liabilities and are primarily recognized in "Interest Expense" on the Statements of Income over the life of the associated debt.
Plant Outage Costs
From July 1, 2017 through June 30, 2021, plant outage costs were normalized for ratemaking purposes based on an average level of expenses. Plant outage expenses that were greater or less than the average will be collected from or returned to customers, through future base rates. Effective July 1, 2021 under-recovered plant outage costs are being amortized through 2029 for LG&E and KU.
(PPL)
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
Energy efficiency represents the difference between revenue billed to customers through RIE's energy efficiency charge and the costs of the RIE’s energy efficiency programs as approved by the RIPUC.
The energy efficiency charge is designed to collect the estimated costs of the RIE’s energy efficiency plan for the upcoming calendar year. The final annual over/under is reconciled in the next year's energy efficiency plan filing, as part of the reconciliation factor calculation. RIE may file to change the energy efficiency plan charge at any time should significant over-or under-recoveries occur.
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.
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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 are to be refunded or recovered annually in the subsequent year.
Renewable energy certificates (RECs)
Represents deferred costs associated with RIE's compliance obligation with the Rhode Island Renewable Portfolio Standard (RPS). The RPS is legislation established to foster the development of new renewable energy sources. The regulatory asset will be recovered over the next year.
Taxes Recoverable through Future Rates
Taxes recoverable through future rates represent the portion of future income taxes that are anticipated to 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.
(PPL, LG&E and KU)
Environmental Cost Recovery
Kentucky law permits LG&E and KU to recover the costs, including a return of operating expenses and a return of and on capital invested, of complying with the Clean Air Act and those federal, state or local environmental requirements, which apply to coal combustion wastes and by-products from coal-fired electricity generating facilities. The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return, as well as to provide for the roll-in of ECR amounts to base rates each two-year period. In December 2017, theThe KPSC issued orders continuing the use of anhas authorized return on equity of 9.7%9.35% for all existing approved ECR plans and projects. The ECR regulatory asset or liability represents the amount that has been under- or over-recovered due to timing or adjustments to the mechanism and is typically recovered or refunded within 12 months.
(PPL LKE and LG&E)
Gas Supply Clause
LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs and customer usage from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC. The gas supply clause also includes a separate natural gas procurement incentive mechanism, which allows LG&E's rates to be adjusted annually to share savings between the actual cost of gas purchases and market indices, with the shareholders and the customers during each performance-based rate year (12 months ending October 31). The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are typically recovered or refunded within 18 months.
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Regulatory Matters
Rhode Island Activities(PPL)
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, (ii) two energy storage demonstration projects, which are on track for timely completion, (iii) a performance incentive for System Efficiency: Annual Megawatt Capacity Savings, which sunset in 2021 and is a tracking and reporting only metric and (iv) several additional metrics for tracking and reporting purposes only. The RIPUC discussed the ET Initiative at an Open Meeting on August 30, 2022, advising RIE to seek RIPUC authorization to continue the ET Initiative and/or to alter any of the targets established in the ASA for Rate Year 5 and beyond. No votes or official rulings were taken; however, based on this feedback, RIE has paused the ET programs in Rate Year 5.
Advanced Metering Functionality (AMF)
In 2021, RIE filed its Updated AMF Business Case and Grid Modernization Plan (GMP) with the RIPUC in accordance with the Amended Settlement Agreement (ASA) approved by the RIPUC in August 2018, and which among other things, sought approval to deploy smart meters throughout the service territory. After PPL completed the acquisition of RIE, RIE filed a new AMF Business Case with the RIPUC in 2022, consisting of a detailed proposal for full-scale deployment of AMF across its electric service territory.
On September 27, 2023, the RIPUC unanimously approved RIE to deploy an AMF-based metering system for the electric distribution business. RIE is authorized to seek recovery of the approved capital investment through the ISR process with an overall multi-year cap on recovery at approximately $153 million, subject to certain terms, conditions and limitations with respect to the potential offsets and recoverability of certain costs. RIE is required to continue spending even if above the recovery cap, until it achieves the functionalities outlined in the AMF Business Case. RIE filed with the RIPUC (i) an updated electric Service Quality Plan on December 27, 2023 for RIPUC approval and (ii) additional compliance tariff provisions regarding recovery and updated cost schedules to reflect the RIPUC's decision on December 22, 2023 for RIPUC approval. RIE cannot predict the outcome of these matters.
Grid Modernization
RIE filed a new GMP with the RIPUC on December 30, 2022. The new GMP filing consists of a holistic suite of grid modernization investments that will provide RIE with the tools and capability to manage the electric distribution system more granularly considering a range of distributed energy resources adoption levels, accelerated by Rhode Island's climate mandates, while at the same time maintaining a safe and reliable electric distribution system. The GMP is an informational guidance document that supports the grid modernization investments to be proposed in future electric ISR plans. Consequently, RIE did not request approval from the RIPUC for any specific investments or seek cost recovery as part of the GMP; rather, RIE requested the RIPUC issues an order affirming RIE's compliance with its obligation to file a GMP that meets the requirements of the ASA. The RIPUC held a status conference on October 26, 2023, to discuss the scope of the RIPUC’s review of the GMP and its potential impact future electric ISR plans.
Petition for Deferral of Credit Card Fees
On January 31, 2024, RIE filed a petition to request approval to recognize regulatory assets related to the credit card, debit card, and related fees (Electronic Transaction Fees) that RIE has waived and will continue to waive on a going forward basis
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pursuant to the RIPUC orders in RIPUC Docket No. 5022 related to COVID-19 impacts. If approved, RIE plans to include a proposal as part of its next base distribution rate case for the amortization/recovery of the regulatory assets and to include future Electronic Transaction Fees in base distribution rates. RIE simultaneously filed a Notice of Withdrawal of its April 2021 petition to create regulatory assets for COVID-19 related bad debt expense and the lost revenue from unassessed late payment charges pending in Docket No. 5154. RIE is continuing to evaluate these other COVID-19 related costs and intends to reserve its rights to file for recovery of these costs in the future. RIE cannot predict the outcome of this matter.
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. The RIPUC held an Open Meeting on September 13, 2022, and issued its Order on November 18. 2022 regarding the Proactive Main Replacement Program and made the following rulings: (i) commencing with the Gas ISR plan to be filed in this calendar year 2022 (prospectively), new main constructed to replace leak prone pipe will not be considered used and useful, and therefore not eligible for rate base treatment, until the related old main is abandoned; and (ii) approved the proactive main replacement revenue requirement set forth in the FY 2023 Gas ISR plan. 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 the RIPUC has not taken any action to date on this issue. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan process. A new docket has been opened to address this matter with the goal of implementing changes for the FY 2025 ISR Plan. RIE filed its proposed gas ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan filing on December 22, 2023. RIE cannot predict the outcome of these matters.
FY 2024 Gas ISR Plan
On December 23, 2022, RIE filed its FY 2024 Gas ISR Plan with the RIPUC. At its January 20, 2023 Open Meeting, the RIPUC directed RIE to file supplemental budget and rate schedules to reflect an April 1 2015,to March 31 fiscal year. The supplemental budget that was filed with the RIIO-ED1 eight-year price control period commencedRIPUC on January 27, 2023 includes $187 million of capital investment spend. The supplemental rate schedules were filed on February 3, 2023. RIE and the Rhode Island Division of Public Utilities and Carriers reached an agreement on an approximately $171 million capital investment spending plan, and RIE filed a second supplemental budget on March 13, 2023. The RIPUC held a hearing on the plan on March 14, 2023. At an Open Meeting on March 29, 2023, the RIPUC approved the plan with an adjustment to the budget for WPD's four DNOs.the Proactive Main Replacement Program category resulting in a total approved FY 2024 Gas ISR Plan of $163 million for capital investment spend. On March 31, 2023, the RIPUC approved RIE's March 30, 2023 compliance filing for rates effective April 1, 2023. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan review and approval process starting with the FY 2025 ISR Plan. A new docket has been opened to address this matter with the goal of implementing changes for the FY 2025 ISR Plan. RIE filed its proposed gas ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan filing on December 22, 2023.RIE cannot predict the outcome of these matters.
FY 2025 Gas ISR Plan
On December 22, 2023, RIE filed its FY 2025 Gas ISR Plan with the RIPUC with a budget that includes $185 million of capital investment spend and up to $11 million of contingency plan spend in light of the Pipeline and Hazardous Materials Safety Administration’s potential enactment of regulations during FY 2025 that would significantly alter RIE’s leak detection and repair obligations under federal regulations. RIE also filed its proposed gas ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan. The RIPUC has scheduled hearings on March 7 and 11, 2024, and is scheduled to rule on the plan by the end of March 2024. RIE cannot predict the outcome of these matters.
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FY 2024 Electric ISR Plan
On December 23, 2022, RIE filed its FY 2024 Electric ISR Plan with the RIPUC. At its January 20, 2023 Open Meeting, the RIPUC directed RIE to file supplemental budget and rate schedules to reflect an April 1 to March 31 fiscal year. The supplemental budget filed with the RIPUC on January 27, 2023 includes $176 million of capital investment spend, $14 million of vegetation operations and management (O&M) spend and $3 million of Other O&M spend. The supplemental rate schedules were filed on February 3, 2023. RIE filed second supplemental budget schedules on March 21, 2023 which includes $166 million of capital investment spend, $14 million of vegetation management O&M spend and $1 million of Other O&M spend. The RIPUC held hearings in March 2023, and on March 29, 2023, approved the plan with modifications to the proposed capital investment spend, resulting in a total approved FY 2024 Electric ISR Plan of $112 million for capital investment spend, $14 million for vegetation management O&M spend, and $1 million for Other O&M spend.
On March 31, 2023, the RIPUC approved RIE's March 30, 2023 compliance filing for rates effective April 1, 2023. The RIPUC continues to consider the appropriate rate recovery treatment of projects not covered by an ISR plan for the applicable fiscal year, and additional definitions and procedures that may be implemented related to the ISR plan review and approval process. A new docket has been opened to address this matter with the goal of implementing changes for the FY 2025 ISR Plan. RIE filed its proposed electric ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan filing on December 21, 2023.RIE cannot predict the outcome of these matters.
FY 2025 Electric ISR Plan
On December 21, 2023, RIE filed its FY 2025 Electric ISR Plan with the RIPUC with a budget that includes $141 million of capital investment spend, $13 million of vegetation O&M spend and $1 million of Other O&M spend. RIE also filed its proposed electric ISR plan budgetary and reconciliation framework with its FY 2025 ISR Plan. The RIPUC has scheduled hearings on March 13 and 14, 2024, and is scheduled to rule on the plan by the end of March 2024. RIE cannot predict the outcome of these matters.
Kentucky Activities(PPL, LKE, LG&E and KU)
On January 10, 2018,December 15, 2022, LG&E and KU filed an application with the KPSC for a CPCN for the construction and purchase of various generating facilities in conjunction with the retirement of four existing coal-fired generation units and three small gas-fired units. On March 24, 2023, Kentucky Senate Bill 4 (SB 4) went into effect, which requires KPSC approval of the retirement of fossil fuel-fired electric generating units in the state. On May 10, 2023, LG&E and KU filed an application with the KPSC seeking approval of the retirement of seven fossil fuel-fired generating units as required by SB 4. On May 16, 2023, the KPSC entered an Order consolidating the SB 4 filing proceeding into the CPCN case.
On November 6, 2023, the KPSC issued an order approving LG&E’s and KU’s requests (i) to construct a 640 MW net summer rating NGCC combustion turbine at LG&E's Mill Creek Generating Station in Jefferson County, Kentucky, (ii) to construct a 120 MWac solar photovoltaic electric generating facility in Mercer County, Kentucky, (iii) to acquire a 120 MWac solar facility to be built by a third-party solar developer in Marion County, Kentucky and (iv) to construct a 125 MW, 4-hour battery energy storage system facility at KU's E.W. Brown Generating Station. The KPSC denied the request to construct a 621 MW net summer rating NGCC combustion turbine at KU's E.W. Brown Generating Station in Mercer County, Kentucky at this time, based on the finding that the construction of this unit should be deferred with the construction date beginning on a date that provides for an in-service date in 2030. The order also authorized LG&E's and KU's entry into the four solar PPAs, subject to certain conditions, but deferred for future proceedings specific decisions on cost recovery treatment or mechanisms. Further, the order approved the new, adjusted or expanded energy efficiency programs contained in the requested 2024-2030 DSM plan.
The KPSC order included approval of the requested retirements of two existing coal-fired generation units at LG&E's Mill Creek Unit 1 (300 MW) and 2 (297 MW) in 2024 and 2027, subject to certain conditions, and three small gas-fired units. The order denied approval of the retirement of KU's E.W. Brown 3 Unit (412 MW) and Ghent Unit 2 (486 MW) in 2028 at this time, citing the need for additional clarity regarding environmental compliance regulations.
The new NGCC facility will be jointly owned by LG&E (31%) and KU (69%) and the solar units will be jointly owned by LG&E (37%) and KU (63%), the battery storage unit will be owned by LG&E, and the proposed PPA transactions and DSM programs will be entered into or conducted jointly by LG&E and KU, consistent with LG&E and KU's shared dispatch, cost allocation, tariff or other frameworks.
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The order approved the requested AFUDC accounting treatment for associated financing costs, each as relating to the NGCC, solar and battery facilities to be constructed and owned by LG&E and KU. With respect to generating unit retirements that were approved by the KPSC, and separate from the order, LG&E and KU anticipate the recovery of associated costs, including the remaining net book value, for these units through the RAR or other rate mechanisms. The remaining net book values of LG&E’s Mill Creek 1 and 2 generating units were approximately $95 million and $244 million at December 31, 2023 and LG&E is continuing to depreciate these units using the current approved rates through their retirement dates in 2024 and 2027. LG&E expects to reclassify the net book value remaining at retirement, which is expected to total approximately $83 million for Mill Creek Unit 1 and $160 million for Mill Creek Unit 2, to a regulatory asset to be amortized over a period of ten years in accordance with the RAR.
Kentucky March 2023 Storm
On March 3, 2023, LG&E and KU experienced significant windstorm activity in their service territories, resulting in substantial damage to certain of LG&E's and KU's assets with total costs incurred through December 31, 2023 of $74 million ($33 million at LG&E and $41 million at KU). On March 17, 2023, LG&E and KU submitted a filing with the KPSC requesting regulatory asset treatment of the extraordinary operations and maintenance expenses portion of the costs incurred related to the windstorm. On April 5, 2023, the KPSC issued an order approving the request for accounting purposes, noting that approval for implementing Advanced Metering Systems across their Kentucky service territories, including gas operations forrecovery would be determined in LG&E. The full deployment is expected to be completed in 2021 with estimated capital costs&E’s and KU’s next base rate cases. As of $155 million and $104 million for KU andDecember 31, 2023, LG&E electric service and $62 million for LG&E gas service. The full Advanced Metering Systems deployment will also result in incremental operation and maintenance costs duringKU recorded regulatory assets related to the deployment phasestorm of $17$8 million and $11 million for KU and LG&E electric service and $3 million for LG&E gas service.million.
On December 22, 2023, the KPSC initiated an investigation into the practices of LG&E and KU Rates
March 15, 2024. LG&E and KU cannot predict the outcome of these proceedings.
Pennsylvania Activities(PPL and PPL Electric)
On January 31, 2023, the PAPUC initiated an investigation focused on billing issues related to estimated, irregular bills and customer service concerns following customer complaints, which for many customers were driven by increased prices for electricity supply. Certain bills issued during the time period of December 20, 2022 through January 9, 2023 were estimated due to a technical issue that prevented PPL Electric from providing actual collected meter data to customer facing and other internal systems. Customers also reported difficulties accessing PPL Electric's website and contacting the customer service call center. The PAPUC’s Bureau of Investigation & Enforcement (I&E) has directed PPL Electric to respond to certain inquiries and document requests. PPL Electric submitted its responses to the information request and cooperated fully with the investigation. PPL Electric reached a Settlement Agreement with I&E on November 21, 2023. In the settlement, PPL Electric agreed to pay a civil penalty of $1 million, make certain remedial improvements to its billing systems and processes, and agree to not seek recovery for extraordinary costs incurred in responding to the billing event. On November 21, 2023, PPL Electric and I&E submitted a Joint Petition for Approval of Settlement to the PAPUC. On January 18, 2024, the PAPUC issued an Order requesting public comment prior to the Commission entering a Final Order on the petition. Comments are due on February 28, 2024. PPL Electric is waiting for the PAPUC to issue a Final Order on the Joint Petition for Approval of Settlement. Approval is pending until the Commission has provided its final decision. PPL Electric cannot predict the outcome of this matter.
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Act 129
Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet, by specified dates, specified goals for reduction in customer electricity usage and peak demand. EDCs not meeting the requirements of Act 129 are subject to significant penalties. In November 2015, PPL Electric filed with the PUCPAPUC its Act 129 Phase IIIIV Energy Efficiency and Conservation Plan on November 30, 2020, for the five-year period starting June 1, 2016 through2021 and ending on May 31, 2021. In June 2016, the PUC approved2026. PPL Electric's Phase III
Act 129 also requires Default Service ProvidersEDCs to act as a default service provider (DSP) to provide, which provides electricity generation supply service to customers pursuant to a PUC-approvedPAPUC-approved default service procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP. PPL Electric is a DSP. Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20 years), with long-term contracts limited to 25% of load unless otherwise approved by the PUC.plan. A DSP is able to recover the costs associated with its default service procurement plan.
Federal Matters
FERC FormulaTransmission Rate Filing (PPL, LG&E and KU)
In April 2017, PPL Electric2018, LG&E and KU applied to the FERC requesting elimination of certain on-going waivers and credits to a sub-set of transmission customers relating to the 1998 merger of LG&E's and KU's parent entities and the 2006 withdrawal of LG&E and KU from the Midcontinent Independent System Operator, Inc. (MISO), a regional transmission operator and energy market. The application sought termination of LG&E's and KU's commitment to provide certain Kentucky municipalities mitigation for certain horizontal market power concerns arising out of the 1998 LG&E and KU merger and 2006 MISO withdrawal. The amounts at issue are generally waivers or credits granted to a limited number of Kentucky municipalities for either certain LG&E and KU or MISO transmission charges incurred for transmission service received. In 2019, the FERC granted LG&E's and KU's request to remove the ongoing credits, conditioned upon the implementation by LG&E and KU of a transition mechanism for certain existing power supply arrangements, which was subsequently filed, modified, and approved by the FERC in 2020 and 2021. In 2020, LG&E and KU and other parties filed appeals with the D.C. Circuit Court of Appeals regarding the FERC's orders on the elimination of the mitigation and required transition mechanism. In August 2022, the D.C. Circuit Court of Appeals issued an order remanding the proceedings back to the FERC. On May 18, 2023, the FERC issued an order on remand reversing its annual transmission formula rate update2019 decision and requiring LG&E and KU to refund credits previously withheld, including under such transition mechanism. LG&E and KU filed a petition for review of the FERC's May 18, 2023 order with the D.C. Circuit Court of Appeals, and provided refunds in accordance with the FERC reflectingorder on December 1, 2023. The FERC issued an order on LG&E and KU’s compliance filing on November 16, 2023, and LG&E and KU filed a revised revenue requirement.petition for review of this November 16 order on February 14, 2024. The filing establishesproceedings at the revenue requirement usedD.C. Circuit Court of Appeals were held on abeyance until February 15, 2024, but a motion to sethold the proceedings on abeyance for an additional 60 days was filed on February 15, 2024, to allow the FERC time to substantively address LG&E and KU’s request for rehearing of the November 16 order. LG&E and KU cannot predict the ultimate outcome of the proceedings or any other post decision process but do not expect the annual impact to have a material effect on their operations or financial condition. LG&E and KU currently receive recovery of certain waivers and credits primarily through base rates increases, provided, however, that took effectincreases associated with the FERC's May 18, 2023 order are expected to be subject to future rate proceedings.
Recovery of Transmission Costs (PPL)
Until December 2022, RIE's transmission facilities were operated in June 2017. combination with the transmission facilities of National Grid's New England affiliates, Massachusetts Electric Company (MECO) and New England Power (NEP), as a single integrated system with NEP designated as the combined operator. As of January 1, 2023, RIE operates its own transmission facilities. NE-ISO allocates RIE's 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 time periodROE for any challengestransmission 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 D. C. Circuit Court of Appeals (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 distinguish their case. Those determinations in other jurisdictions have recently been vacated and remanded back to the FERC for further proceedings by the D.C. Circuit Court of Appeals. The proceeding and the final base rate ROE determination in the
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New England matters remain open, pending a final order from the FERC. PPL Electric's annual update has expired. No formal challenges were submitted.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 PUC-approvedPAPUC-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 2017, 20162023, 2022 and 2015,2021, PPL Electric purchased $1.5 billion, $1.3 billion $1.4 billion and $1.3$1.2 billion of accounts receivable from unaffiliated third parties. During 2015, PPL Electric purchased $146 millionalternative suppliers.
(PPL)
In 2021 and 2022, the RIPUC approved various components of a Purchase of Receivables Program (POR) in Rhode Island for effect on April 1, 2022. Municipal aggregators and non-regulated power producers (collectively, Competitive Suppliers) are eligible to participate in accordance with RIE's approved electric tariffs for municipal aggregation and non-regulated power producers. Under the POR program, RIE will purchase the Competitive Suppliers' accounts receivablereceivables, including existing receivables, at discounted rates, regardless of whether RIE has collected the owed monies from PPL EnergyPlus. PPL Electric's purchases from PPL EnergyPluscustomers. The program is intended to make RIE whole through the implementation of a discount rate or Standard Complete Bill Percentage (SCBP) paid by Competitive Suppliers. RIE calculates the SCBP for 2015 included purchases through May 31, 2015, which iseach customer class and files the period during which PPL Electriccalculations with the RIPUC for review and PPL EnergyPlus were affiliated entities. Asapproval by February 15 of each year. At an Open Meeting on March 29, 2023, the RIPUC approved the SCBP for effect beginning on April 1, 2023 for a result of the June 1, 2015 spinoff of PPL Energy Supply and creation of Talen Energy, PPL EnergyPlus (renamed Talen Energy Marketing) is no longer an affiliate of PPL Electric. PPL Electric's purchases from Talen Energy Marketing subsequent to May 31, 2015 are included as purchases from unaffiliated third parties.one-year period.
Credit Arrangements and Short-term Debt
(All Registrants)
The Registrants maintain credit facilities to enhance liquidity, provide credit support and provide a backstop to commercial paper programs. For reporting purposes, on a consolidated basis, the credit facilities and commercial paper programs of PPL Electric, LKE, LG&E and KU also apply to PPL and the credit facilities and commercial paper programs of LG&E and KU also apply to LKE.PPL. The amounts listed in the borrowed column below are recorded as "Short-term debt" on the Balance Sheets except for
borrowings under PPL Electric's term loan agreement due March 2024 and borrowings under LG&E's Term Loan Facilityand KU's term loan agreements due July 2024, which are recorded aswere reflected in "Long-term debt" on the Balance Sheets.at December 31, 2022 and were repaid in 2023. The following credit facilities were in place at:
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||
Expiration Date | Capacity | Borrowed | Letters of Credit and Commercial Paper Issued | Unused Capacity | Borrowed | Letters of Credit and Commercial Paper Issued | |||||||||||||||||||
| PPL | |||||||||||||||||||||||||
| U.K. | |||||||||||||||||||||||||
| WPD plc | |||||||||||||||||||||||||
| Syndicated Credit Facility (a) (c) | Jan. 2022 | £ | 210 | £ | 148 | £ | — | £ | 60 | £ | 160 | £ | — | ||||||||||||
| WPD (South West) | |||||||||||||||||||||||||
| Syndicated Credit Facility (a) (c) | July 2021 | 245 | — | — | 245 | 110 | — | ||||||||||||||||||
| WPD (East Midlands) | |||||||||||||||||||||||||
| Syndicated Credit Facility (a) (c) | July 2021 | 300 | 180 | — | 120 | 9 | — | ||||||||||||||||||
| WPD (West Midlands) | |||||||||||||||||||||||||
| Syndicated Credit Facility (a) (c) | July 2021 | 300 | 120 | — | 180 | — | — | ||||||||||||||||||
| Uncommitted Credit Facilities | 100 | — | 4 | 96 | 60 | 4 | |||||||||||||||||||
| Total U.K. Credit Facilities (b) | £ | 1,155 | £ | 448 | £ | 4 | £ | 701 | £ | 339 | £ | 4 | |||||||||||||
| U.S. | |||||||||||||||||||||||||
| PPL Capital Funding | |||||||||||||||||||||||||
| Syndicated Credit Facility (c) (d) | Jan. 2022 | $ | 950 | $ | — | $ | 230 | $ | 720 | $ | — | $ | 20 | ||||||||||||
| Syndicated Credit Facility (c) (d) | Nov. 2018 | 300 | — | — | 300 | — | — | ||||||||||||||||||
| Bilateral Credit Facility (c) (d) | Mar. 2018 | 150 | — | 18 | 132 | — | 17 | ||||||||||||||||||
| Total PPL Capital Funding Credit Facilities | $ | 1,400 | $ | — | $ | 248 | $ | 1,152 | $ | — | $ | 37 | |||||||||||||
| PPL Electric | |||||||||||||||||||||||||
| Syndicated Credit Facility (c) (d) | Jan. 2022 | $ | 650 | $ | — | $ | 1 | $ | 649 | $ | — | $ | 296 | ||||||||||||
| LKE | |||||||||||||||||||||||||
| Syndicated Credit Facility (c) (d) | Oct. 2018 | $ | 75 | $ | — | $ | — | $ | 75 | $ | — | $ | — | ||||||||||||
| LG&E | |||||||||||||||||||||||||
| Syndicated Credit Facility (c) (d) | Jan. 2022 | $ | 500 | $ | — | $ | 199 | $ | 301 | $ | — | $ | 169 | ||||||||||||
| Term Loan Credit Facility (c) (e) | Oct. 2019 | 200 | 100 | — | 100 | — | — | ||||||||||||||||||
| Total LG&E Credit Facilities | $ | 700 | $ | 100 | $ | 199 | $ | 401 | $ | — | $ | 169 | |||||||||||||
| KU | |||||||||||||||||||||||||
| Syndicated Credit Facility (c) (d) | Jan. 2022 | $ | 400 | $ | — | $ | 45 | $ | 355 | $ | — | $ | 16 | ||||||||||||
| Letter of Credit Facility (c) (d) (f) | Oct. 2020 | 198 | — | 198 | — | — | 198 | ||||||||||||||||||
| Total KU Credit Facilities | $ | 598 | $ | — | $ | 243 | $ | 355 | $ | — | $ | 214 | |||||||||||||
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||
| Expiration Date | Capacity | Borrowed | Letters of Credit and Commercial Paper Issued (d) | Unused Capacity | Borrowed | Letters of Credit and Commercial Paper Issued (d) | |||||||||||||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||||||||||||
| PPL Capital Funding | |||||||||||||||||||||||||||||||||||||||||
| Syndicated Credit Facility (a) (b) (c) | Dec 2027 | $ | 1,250 | $ | — | $ | 390 | $ | 860 | $ | — | $ | 561 | ||||||||||||||||||||||||||||
| Bilateral Credit Facility (a) (b) | Mar 2024 | 100 | — | — | 100 | — | — | ||||||||||||||||||||||||||||||||||
| Bilateral Credit Facility (a) (b) | Mar 2024 | 100 | — | 13 | 87 | — | 58 | ||||||||||||||||||||||||||||||||||
| Total PPL Capital Funding Credit Facilities | $ | 1,450 | $ | — | $ | 403 | $ | 1,047 | $ | — | $ | 619 | |||||||||||||||||||||||||||||
| PPL Electric | |||||||||||||||||||||||||||||||||||||||||
| Syndicated Credit Facility (a) (b) | Dec 2027 | 650 | — | 511 | 139 | — | 146 | ||||||||||||||||||||||||||||||||||
| Term Loan Credit Facility (a) (b) | Mar 2024 | — | — | — | — | 250 | — | ||||||||||||||||||||||||||||||||||
| Total PPL Electric Credit Facilities | $ | 650 | $ | — | $ | 511 | $ | 139 | $ | 250 | $ | 146 | |||||||||||||||||||||||||||||
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| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||
| Expiration Date | Capacity | Borrowed | Letters of Credit and Commercial Paper Issued (d) | Unused Capacity | Borrowed | Letters of Credit and Commercial Paper Issued (d) | |||||||||||||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||||||||||||
| Syndicated Credit Facility (a) (b) | Dec 2027 | 500 | — | — | 500 | — | 180 | ||||||||||||||||||||||||||||||||||
| Term Loan Credit Facility (a) (b) | Jul 2024 | — | — | — | — | 300 | — | ||||||||||||||||||||||||||||||||||
| Total LG&E Credit Facilities | $ | 500 | $ | — | $ | — | $ | 500 | $ | 300 | $ | 180 | |||||||||||||||||||||||||||||
| KU | |||||||||||||||||||||||||||||||||||||||||
| Syndicated Credit Facility (a) (b) | Dec 2027 | 400 | — | 93 | 307 | — | 101 | ||||||||||||||||||||||||||||||||||
| Term Loan Credit Facility (a) (b) | Jul 2024 | — | — | — | — | 300 | — | ||||||||||||||||||||||||||||||||||
| Total KU Credit Facilities | $ | 400 | $ | — | $ | 93 | $ | 307 | $ | 300 | $ | 101 | |||||||||||||||||||||||||||||
(a)Each company pays customary fees under its $200respective facility and borrowings generally bear interest at applicable secured overnight financing rates or base rates, plus an applicable margin.
(b)The facilities contain a financial covenant requiring debt to total capitalization not to exceed 70% for PPL Capital Funding, RIE, PPL Electric, LG&E and KU, as calculated in accordance with the facilities and other customary covenants. Additionally, subject to certain conditions, PPL Capital Funding may request that the capacity of one of its bilateral credit facilities expiring in March 2024 be increased by up to $30 million term loan facility. The proceeds were used to repay short-term debt and for general corporate purposes.
(c)Included a $250 million borrowing sublimit for RIE and a $1 billion sublimit for PPL Capital Funding at December 31, 2023. At December 31, 2023, PPL Capital Funding had $365 million commercial paper outstanding and RIE had $25 million of commercial paper outstanding. RIE's obligations under the facility are not guaranteed by PPL. On January 5, 2024, the borrowing sublimits under the facility were reallocated to $400 million at RIE and $850 million at PPL Capital Funding.
(d)Commercial paper issued reflects the undiscounted face value of the issuance.
(PPL)
In March 2023, RIE was added as an authorized borrower under the PPL Capital Funding syndicated credit facility. At December 31, 2023, RIE’s borrowing limit under the facility was set at $250 million and PPL Capital Funding's borrowing limit was set at $1 billion. At December 31, 2023, PPL Capital Funding had $365 million commercial paper outstanding and RIE had $25 million of commercial paper outstanding. On January 5, 2024, the borrowing sublimits under the facility were reset to $400 million at RIE and $850 million at PPL Capital Funding.
(PPL and PPL Electric)
In March 2023, PPL Electric repaid its $250 million term loan expiring in January 2022 were extended to January 2023.March 2024 and terminated the facility.
(PPL PPL Electric,and LG&E)
In March 2023, LG&E repaid its $300 million term loan expiring in July 2024 and terminated the facility.
(PPL and KU)
In March 2023, KU repaid its $300 million term loan expiring in July 2024 and terminated the facility.
(All Registrants)
The Registrants maintain commercial paper programs to provide an additional financing source to fund short-term liquidity needs, as necessary.needs. Commercial paper issuances, included in "Short-term debt" on the Balance Sheets, are supported by the respective Registrant's Syndicated Credit Facility.credit facilities. The following commercial paper programs were in place at:
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| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted - Average Interest Rate | Capacity | Commercial Paper Issuances | Unused Capacity | Weighted - Average Interest Rate | Commercial Paper Issuances | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Capital Funding | 1.64% | $ | 1,000 | $ | 230 | $ | 770 | 1.10% | $ | 20 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted - Average Interest Rate | Weighted - Average Interest Rate | Capacity | Commercial Paper Issuances (c) | Unused Capacity | Weighted - Average Interest Rate | Commercial Paper Issuances (c) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Capital Funding (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| RIE (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Electric | 650 | — | 650 | 1.05% | 295 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| LG&E | 1.83% | 350 | 199 | 151 | 0.94% | 169 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| KU | 1.97% | 350 | 45 | 305 | 0.87% | 16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 2,350 | $ | 474 | $ | 1,876 | $ | 500 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)PPL Capital Funding's obligations are fully and unconditionally guaranteed by PPL.
(b)Issuances under the PPL Capital Funding and RIE commercial paper programs are supported by the PPL Capital Funding syndicated credit facility, which has a total capacity of $1.25 billion and under which they are both borrowers. PPL Capital Funding’s Commercial paper program is also backed by a separate bilateral credit facility for $100 million. The PPL Capital Funding syndicated credit facility includes a borrowing sublimit for RIE, which at December 31, 2023 was set at $250 million with the remaining $1 billion allocated to PPL Capital Funding. RIE's obligations under the facility are not guaranteed by PPL. The sublimits of each borrower may be decreased or increased at the borrowers’ option up to a prescribed amount such that all borrowings under the syndicated credit facility cannot exceed the size of the credit facility of $1.25 billion. On January 5, 2024, the borrowing sublimits under the facility were reallocated to $400 million at RIE and $850 million at PPL Capital Funding.
(c)Commercial paper issued reflects the undiscounted face value of the issuance.
(PPL)
In June 2023, RIE established a commercial paper program with a capacity of $400 million. This program is supported by PPL Capital Funding's syndicated credit facility, under which RIE is a co-borrower.
(PPL Electric, LKE, LG&E and KU)
See Note 14 for a discussion of intercompany borrowings.
Long-term Debt(All Registrants)
| December 31, | |||||||||||||||||||||||
| Weighted-Average Rate (d) | Maturities (d) | 2023 | 2022 | ||||||||||||||||||||
| PPL | |||||||||||||||||||||||
| Senior Unsecured Notes | 3.95 | % | 2026 - 2047 | $ | 3,066 | $ | 3,066 | ||||||||||||||||
| Senior Secured Notes/First Mortgage Bonds (a) (b) (c) | 4.35 | % | 2025 - 2053 | 10,229 | 8,957 | ||||||||||||||||||
| Exchangeable Senior Unsecured Notes | 2.88 | % | 2028 | 1,000 | — | ||||||||||||||||||
| Junior Subordinated Notes | 8.27 | % | 2067 | 480 | 480 | ||||||||||||||||||
| Term Loan Credit Facility | — | 850 | |||||||||||||||||||||
| Total Long-term Debt before adjustments | 14,775 | 13,353 | |||||||||||||||||||||
| Unamortized premium and (discount), net | (55) | (32) | |||||||||||||||||||||
| Unamortized debt issuance costs | (108) | (78) | |||||||||||||||||||||
| Total Long-term Debt | 14,612 | 13,243 | |||||||||||||||||||||
| Less current portion of Long-term Debt | 1 | 354 | |||||||||||||||||||||
| Total Long-term Debt, noncurrent | $ | 14,611 | $ | 12,889 | |||||||||||||||||||
| December 31, | ||||||||||||
| Weighted-Average Rate (g) | Maturities (g) | 2017 | 2016 | |||||||||
| PPL | ||||||||||||
| U.S. | ||||||||||||
| Senior Unsecured Notes | 3.78 | % | 2020 - 2047 | $ | 4,575 | $ | 4,075 | |||||
| Senior Secured Notes/First Mortgage Bonds (a) (b) (c) | 3.96 | % | 2018 - 2047 | 7,314 | 6,849 | |||||||
| Junior Subordinated Notes | 5.10 | % | 2067 - 2073 | 930 | 930 | |||||||
| Term Loan Credit Facility | 2.06 | % | 2019 | 100 | — | |||||||
| Total U.S. Long-term Debt | 12,919 | 11,854 | ||||||||||
| U.K. | ||||||||||||
| Senior Unsecured Notes (d) | 5.24 | % | 2020 - 2040 | 6,351 | 5,707 | |||||||
| Index-linked Senior Unsecured Notes (e) | 1.56 | % | 2026 - 2056 | 1,012 | 838 | |||||||
| Total U.K. Long-term Debt (f) | 7,363 | 6,545 | ||||||||||
| Total Long-term Debt Before Adjustments | 20,282 | 18,399 | ||||||||||
| Fair market value adjustments | 21 | 22 | ||||||||||
| Unamortized premium and (discount), net (e) | 14 | 20 | ||||||||||
| Unamortized debt issuance costs | (122 | ) | (115 | ) | ||||||||
| Total Long-term Debt | 20,195 | 18,326 | ||||||||||
| Less current portion of Long-term Debt | 348 | 518 | ||||||||||
| Total Long-term Debt, noncurrent | $ | 19,847 | $ | 17,808 | ||||||||
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| December 31, | |||||||||||||||||||||||
| Weighted-Average Rate (d) | Maturities (d) | 2023 | 2022 | ||||||||||||||||||||
| PPL Electric | |||||||||||||||||||||||
| Senior Secured Notes/First Mortgage Bonds (a) (b) | 4.61 | % | 2027 - 2053 | $ | 4,649 | $ | 4,289 | ||||||||||||||||
| Term Loan Credit Facility | — | 250 | |||||||||||||||||||||
| Total Long-term Debt Before Adjustments | 4,649 | 4,539 | |||||||||||||||||||||
| Unamortized discount | (42) | (22) | |||||||||||||||||||||
| Unamortized debt issuance costs | (40) | (31) | |||||||||||||||||||||
| Total Long-term Debt | 4,567 | 4,486 | |||||||||||||||||||||
| Less current portion of Long-term Debt | — | 340 | |||||||||||||||||||||
| Total Long-term Debt, noncurrent | $ | 4,567 | $ | 4,146 | |||||||||||||||||||
| LG&E | |||||||||||||||||||||||
| Senior Secured Notes/First Mortgage Bonds (a) (c) | 4.02 | % | 2025 - 2054 | $ | 2,489 | $ | 2,024 | ||||||||||||||||
| Term Loan Credit Facility | — | 300 | |||||||||||||||||||||
| Total Long-term Debt Before Adjustments | 2,489 | 2,324 | |||||||||||||||||||||
| Unamortized discount | (4) | (4) | |||||||||||||||||||||
| Unamortized debt issuance costs | (16) | (13) | |||||||||||||||||||||
| Total Long-term Debt | 2,469 | 2,307 | |||||||||||||||||||||
| Less current portion of Long-term Debt | — | — | |||||||||||||||||||||
| Total Long-term Debt, noncurrent | $ | 2,469 | $ | 2,307 | |||||||||||||||||||
| KU | |||||||||||||||||||||||
| Senior Secured Notes/First Mortgage Bonds (a) (c) | 4.22 | % | 2025 - 2054 | $ | 3,089 | $ | 2,642 | ||||||||||||||||
| Term Loan Credit Facility | — | 300 | |||||||||||||||||||||
| Total Long-term Debt Before Adjustments | 3,089 | 2,942 | |||||||||||||||||||||
| Unamortized premium | 5 | 5 | |||||||||||||||||||||
| Unamortized discount | (9) | (9) | |||||||||||||||||||||
| Unamortized debt issuance costs | (21) | (18) | |||||||||||||||||||||
| Total Long-term Debt | 3,064 | 2,920 | |||||||||||||||||||||
| Less current portion of Long-term Debt | — | 13 | |||||||||||||||||||||
| Total Long-term Debt, noncurrent | $ | 3,064 | $ | 2,907 | |||||||||||||||||||
| December 31, | ||||||||||||
| Weighted-Average Rate (g) | Maturities (g) | 2017 | 2016 | |||||||||
| PPL Electric | ||||||||||||
| Senior Secured Notes/First Mortgage Bonds (a) (b) | 4.23 | % | 2020 - 2047 | $ | 3,339 | $ | 2,864 | |||||
| Total Long-term Debt Before Adjustments | 3,339 | 2,864 | ||||||||||
| Unamortized discount | (16 | ) | (12 | ) | ||||||||
| Unamortized debt issuance costs | (25 | ) | (21 | ) | ||||||||
| Total Long-term Debt | 3,298 | 2,831 | ||||||||||
| Less current portion of Long-term Debt | — | 224 | ||||||||||
| Total Long-term Debt, noncurrent | $ | 3,298 | $ | 2,607 | ||||||||
| LKE | ||||||||||||
| Senior Unsecured Notes | 3.97 | % | 2020 - 2021 | $ | 725 | $ | 725 | |||||
| Term Loan Credit Facility | 2.06 | % | 2019 | 100 | — | |||||||
| First Mortgage Bonds (a) (c) | 3.73 | % | 2018 - 2045 | 3,975 | 3,985 | |||||||
| Long-term debt to affiliate | 3.50 | % | 2026 | 400 | 400 | |||||||
| Total Long-term Debt Before Adjustments | 5,200 | 5,110 | ||||||||||
| Fair market value adjustments | — | (1 | ) | |||||||||
| Unamortized discount | (14 | ) | (15 | ) | ||||||||
| Unamortized debt issuance costs | (27 | ) | (29 | ) | ||||||||
| Total Long-term Debt | 5,159 | 5,065 | ||||||||||
| Less current portion of Long-term Debt | 98 | 194 | ||||||||||
| Total Long-term Debt, noncurrent | $ | 5,061 | $ | 4,871 | ||||||||
| LG&E | ||||||||||||
| Term Loan Credit Facility | 2.06 | % | 2019 | $ | 100 | $ | — | |||||
| First Mortgage Bonds (a) (c) | 3.48 | % | 2018 - 2045 | 1,624 | 1,634 | |||||||
| Total Long-term Debt Before Adjustments | 1,724 | 1,634 | ||||||||||
| Fair market value adjustments | — | (1 | ) | |||||||||
| Unamortized discount | (4 | ) | (4 | ) | ||||||||
| Unamortized debt issuance costs | (11 | ) | (12 | ) | ||||||||
| Total Long-term Debt | 1,709 | 1,617 | ||||||||||
| Less current portion of Long-term Debt | 98 | 194 | ||||||||||
| Total Long-term Debt, noncurrent | $ | 1,611 | $ | 1,423 | ||||||||
| KU | ||||||||||||
| First Mortgage Bonds (a) (c) | 3.91 | % | 2019 - 2045 | $ | 2,351 | $ | 2,351 | |||||
| Total Long-term Debt Before Adjustments | 2,351 | 2,351 | ||||||||||
| Unamortized discount | (9 | ) | (9 | ) | ||||||||
| Unamortized debt issuance costs | (14 | ) | (15 | ) | ||||||||
| Total Long-term Debt | 2,328 | 2,327 | ||||||||||
| Less current portion of Long-term Debt | — | — | ||||||||||
| Total Long-term Debt, noncurrent | $ | 2,328 | $ | 2,327 | ||||||||
Includes LG&E's first mortgage bonds that are secured by the lien of the LG&E 2010 Mortgage Indenture which creates a lien, subject to certain exceptions and exclusions, on substantially all of LG&E's real and tangible personal property located in Kentucky and used or to be used in connection
with the generation, transmission and distribution of electricity and the storage and distribution of natural gas. The aggregate carrying value of the property subject to the lien was $4.7$5.9 billion and $4.4$5.8 billion at December 31, 20172023 and 2016.2022.
Includes KU's first mortgage bonds that are secured by the lien of the KU 2010 Mortgage Indenture which creates a lien, subject to certain exceptions and exclusions, on substantially all of KU's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity. The aggregate carrying value of the property subject to the lien was $6.0$7.3 billion and $5.8$7.1 billion at December 31, 20172023 and 2016.
2022.
(b)Includes PPL Electric's series of senior secured bonds that secure its obligations to make payments with respect to each series of Pollution Control Bonds that were issued by the LCIDA and the PEDFA on behalf of PPL Electric. These senior secured bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such Pollution Control Bonds. These senior secured bonds were issued under PPL Electric's 2001 Mortgage Indenture and are secured as noted in (a) above. The tax-exempt revenue bonds are subject to mandatory redemption upon determination that the interest rate on the bonds would be included in the holders' gross income for federal tax purposes.
(c)Includes LG&E's and KU's series of first mortgage bonds that were issued to the respective trustees of tax-exempt revenue bonds to secure its respective obligations to make payments with respect to each series of bonds. The first mortgage bonds were issued in the same principal amounts, contain payment and redemption provisions that correspond to and bear the same interest rate as such tax-exempt revenue bonds. These first mortgage bonds were issued under the LG&E 2010 Mortgage Indenture and the KU 2010 Mortgage Indenture and are secured as noted in (a) above. The related tax-exempt revenue
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bonds were issued by various governmental entities, principally counties in Kentucky, on behalf of LG&E and KU. The related revenue bond documents allow LG&E and KU to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, term rate of at least one year or, in some cases, an auction rate or a SOFR index rate. At December 31, 2017,2023, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a term rate mode totaled $514$894 million for LKE,PPL, comprised of $391$538 million and $123$356 million for LG&E and KU. At December 31, 2017,2023, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a variable rate mode totaled $375 million for LKE, comprised of $147$66 million and $228$33 million for LG&E and KU. These variable rate tax-exempt revenue bonds are subject to tender for purchase by LG&E and KU at the option of the holder and to mandatory tender for purchase by LG&E and KU upon the occurrence of certain events.
(d)The table reflects principal maturities only, based on stated maturities, |
The aggregate maturities of long-term debt, based on sinking fund requirements, stated maturities or earlier put dates, for the periods 20182024 through 20222028 and thereafter are as follows:
| PPL | PPL Electric | LG&E | KU | ||||||||||||||||||||||||||
| 2024 | $ | 1 | $ | — | $ | — | $ | — | |||||||||||||||||||||
| 2025 | 551 | — | 300 | 250 | |||||||||||||||||||||||||
| 2026 | 904 | — | 90 | 164 | |||||||||||||||||||||||||
| 2027 | 428 | 108 | 260 | 60 | |||||||||||||||||||||||||
| 2028 | 1,350 | — | — | — | |||||||||||||||||||||||||
| Thereafter | 11,541 | 4,541 | 1,839 | 2,615 | |||||||||||||||||||||||||
| Total | $ | 14,775 | $ | 4,649 | $ | 2,489 | $ | 3,089 | |||||||||||||||||||||
| PPL | PPL Electric | LKE | LG&E | KU | |||||||||||||||
| 2018 | $ | 348 | $ | — | $ | 98 | $ | 98 | $ | — | |||||||||
| 2019 | 430 | — | 430 | 334 | 96 | ||||||||||||||
| 2020 | 1,278 | 100 | 975 | — | 500 | ||||||||||||||
| 2021 | 1,150 | 400 | 250 | — | — | ||||||||||||||
| 2022 | 1,274 | 474 | — | — | — | ||||||||||||||
| Thereafter | 15,802 | 2,365 | 3,447 | 1,292 | 1,755 | ||||||||||||||
| Total | $ | 20,282 | $ | 3,339 | $ | 5,200 | $ | 1,724 | $ | 2,351 | |||||||||
(PPL)
In March 2017, WPD (South Wales) issued £50 million of 0.01% Index-linked Senior Notes due 2029. WPD (South Wales) received proceeds of £53 million, which equated to $64 million at the time of issuance, net of fees and including a premium. The principal amount of the notes is adjusted based on changes in a specified index, as detailed in the terms of the related indenture. The proceeds were used for general corporate purposes.
PPL Capital Funding may redeem all or any portion of the Notes, at its option, on or after March 20, 2026, if the last reported sale price of the common stock has been at least 130% of the exchange price then in effect for at least 20 trading days (whether or not consecutive), during any 30 consecutive trading day period, at a redemption price equal to 100% of the principal amount of the Notes to be redeemed, plus any accrued and unpaid interest. No sinking fund is provided for the Notes.
Subject to certain conditions, holders of the Notes will have the right to require PPL Capital Funding to repurchase all or a portion of their Notes upon maturity.the occurrence of a fundamental change, as defined in the indenture pursuant to which the Notes were issued at a repurchase price of 100% of their principal amount plus any accrued and unpaid interest. In connection with certain corporate events or if PPL Capital Funding calls any Notes for redemption, PPL Capital Funding will, under certain circumstances, increase the exchange rate for noteholders who elect to exchange their Notes in connection with any such corporate event or exchange their Notes called for redemption.
(PPL and PPL Electric)
In May 2017,March 2023, PPL Electric issued $475$600 million of 3.95%5.00% First Mortgage Bonds due 2047.2033 and $750 million of 5.25% First Mortgage Bonds due 2053. PPL Electric received proceeds of $466 million,$1.32 billion, net of a discountdiscounts and underwriting fees, which were used to repay debt, including PPL Electric's $250 million term loan, and for other general corporate purposes.
In March 2023, PPL Electric redeemed all of the outstanding $650 million aggregate principal amount of its First Mortgage Bonds, Floating Rate Series due 2024.
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In March 2023, PPL Electric redeemed all of the outstanding $250 million aggregate principal amount of its First Mortgage Bonds, Floating Rate Series due 2023.
In January 2024, PPL Electric issued $650 million of 4.85% First Mortgage Bonds due 2034. PPL Electric received proceeds of $644 million, net of discounts and underwriting fees, which will be used to repay short-term debt incurred primarilyand for capital expenditures.other general corporate purposes.
(PPL and LG&E)
In August 2017, the LCIDA remarketed $108March 2023, LG&E issued $400 million of Pollution Control5.45% First Mortgage Bonds due 2033. LG&E received proceeds of $396 million, net of discounts and underwriting fees, which were used to repay LG&E's $300 million term loan and for other general corporate purposes.
In December 2023, the County of Trimble, Kentucky issued $65 million of 4.70% Environmental Facilities Revenue Refunding Bonds (PPL Electric Utilities Corporation Project),2023 Series 2016BA due 2027 previously issued2054 on behalf of PPL Electric.LG&E which reimburses LG&E for costs used to finance the acquisition, construction, installation, and equipping of certain solid waste disposal facilities owned by LG&E located in Trimble County, Kentucky. In December 2023, LG&E received proceeds of $40 million for expenditures made. The bonds were remarketedremaining balance of $25 million is being held in escrow until qualifying expenditures are made and has been recorded as restricted cash and included in "Other noncurrent assets" on the Balance Sheet at a long-term rate and will bear interest at 1.80% through their mandatory purchase date of August 15, 2022.December 31, 2023.
(PPL LKE and LG&E)KU)
In April 2017, the Louisville/Jefferson County Metro Government of Kentucky remarketed $128March 2023, KU issued $400 million of Pollution Control Revenue5.45% First Mortgage Bonds 2003 Series A (Louisville Gasdue 2033. KU received proceeds of $396 million, net of discounts and Electric Company Project) due 2033 previously issued on behalf of LG&E. The bondsunderwriting fees, which were remarketed at a long-term rateused to repay KU's $300 million term loan and will bear interest at 1.50% through their mandatory purchase date of April 1, 2019.for general corporate purposes.
In June 2017,December 2023, the County of Trimble, Kentucky issued $60 million of Environmental Facilities Revenue Refunding Bonds, 2017 Series A (Louisville Gas and Electric Company Project) due 2033 on behalf of LG&E. The bonds were issued bearing interest at a rate of 3.75% through their maturity and are subject to an optional redemption on or after June 1, 2027. The proceeds of the bonds were used to redeem $60 million of Environmental Facilities Revenue Refunding Bonds, 2007 Series A (Louisville Gas and Electric Company Project) due 2033 previously issued by the County of Trimble, Kentucky on behalf of LG&E.
(PPL Electric, Company Project) due 2027.LG&E and KU)
See Note 14 for additional information related to intercompany borrowings.
Legal Separateness(All Registrants)
The subsidiaries of PPL are separate legal entities. PPL's subsidiaries are not liable for the debts of PPL. Accordingly, creditors of PPL may not satisfy their debts from the assets of PPL's subsidiaries absent a specific contractual undertaking by a subsidiary to pay PPL's creditors or as required by applicable law or regulation. Similarly, other than PPL's guarantee of PPL Capital Funding's obligations, PPL is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of PPL's subsidiaries may not satisfy their debts from the assets of PPL or its other subsidiaries absent a specific contractual undertaking by PPL or its other subsidiaries to pay the creditors or as required by applicable law or regulation.
Similarly, the subsidiaries of PPL Electric and LKE are each separate legal entities. These subsidiaries are not liable for the debts of PPL Electric and LKE.Electric. Accordingly, creditors of PPL Electric and LKE may not satisfy theirits debts from the assets of
141
(PPL)
In February 2015, PPL entered into two separate equity distribution agreements, pursuant to which PPL may sell, from time to time, up to an aggregate of $500 millionJune 2023, RIE redeemed all 49,089 shares of its common stock. The compensation paidoutstanding preferred stock at a redemption price equal to the selling agents by PPL may be up to 1%par value of the gross offering proceeds$50 per share, plus a premium of the shares sold with respect to each equity distribution agreement. PPL issued the following for the years ended December 31:$5 per share, plus a prorated dividend of $0.1875 per share. The total payment was $3 million.
| 2017 | 2016 | 2015 | |||||||||
| Number of shares (in thousands) | 10,373 | 710 | 1,477 | ||||||||
| Net Proceeds | $ | 377 | $ | 25 | $ | 49 | |||||
Distributions and Related Restrictions
In November 2017,2023, PPL declared its quarterly common stock dividend, payable January 2, 2018,2024, at 39.524.00 cents per share (equivalent to $1.580.96 cents per annum). On February 22, 2018,16, 2024, PPL announced that the company is increasing itsa quarterly common stock dividend to 41.0of 25.75 cents per share, on a quarterly basis (equivalentpayable April 1, 2024, to $1.64 per annum).shareowners of record as of March 8, 2024. Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other factors.
Neither PPL Capital Funding nor PPL may declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067 or 2013 Series B Junior Subordinated Notes due 2073.2067. At December 31, 2017,2023, no interest payments were deferred.
(All Registrants)
PPL relies on dividends or loans from its subsidiaries to fund PPL's dividends to its common shareholders. The net assets of certain PPL subsidiaries are subject to legal restrictions. LKE primarily relies on dividends from its subsidiaries to fund its distributions to PPL. LG&E, KU, and PPL Electric and RIE are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act. LG&E, KU, and PPL Electric and RIE believe, however, that this statutory restriction, as applied to their circumstances, would not be construed or applied by the FERC to prohibit the payment from retained earnings of dividends that are not excessive and are for lawful and legitimate business purposes. In February 2012, LG&E and KU petitioned the FERC requesting authorization to pay dividends in the future based on retained earnings balances calculated without giving effect to the impact of purchase accounting adjustments for thePPL's 2010 acquisition of LKE by PPL.LG&E and KU. In May 2012, the FERC approved the petitions with the further condition that each utility may not pay dividends if such payment would cause its adjusted equity ratio to fall below 30% of total capitalization. Accordingly, at December 31, 2017,2023, net assets of $2.7 billion ($1.1$1.5 billion for LG&E and $1.6$2.0 billion for KU)KU were restricted for purposes of paying dividends to LKE, and net assets of $3.1 billion ($1.4$1.7 billion for LG&E and $1.7$2.2 billion for KU)KU were available for payment of dividends to LKE. LG&E and KU believe they will not be required to change their current dividend practices as a result of the foregoing requirement. In addition, under Virginia law, KU is prohibited from making loans to affiliates without the prior approval of the VSCC. There are no comparable statutes under Kentucky law applicable to LG&E and KU, or under Pennsylvania law applicable to PPL Electric. However, orders from the KPSC require LG&E and KU to obtain prior consent or approval before lending amounts to PPL.
(PPL)
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 electricity and distribution of natural gas. The Acquisition expands PPL's portfolio of regulated natural gas and electricity transmission and distribution assets, has improved PPL's credit metrics and is expected to 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):
142
| Aggregate enterprise consideration | $ | 5.3 | ||||||||||||||||||
| Less: fair value of assumed long-term debt outstanding | 1.5 | |||||||||||||||||||
| Total cash consideration | $ | 3.8 | ||||||||||||||||||
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 certain aspects have been extended to the third quarter of 2024. The TSA is subject to further extension as necessary to complete the successful transition. TSA costs of $228 million and $123 million were incurred for the years ended December 31, 2023 and 2022.
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 provided a credit to all its electric and natural gas distribution customers in the total amount of $50 million ($40 million net of tax benefit). Based on the relative number of electric distribution customers and natural gas distribution customers as of November 1, 2022, RIE refunded, in the form of a bill credit, $33 million to electric customers and $17 million to natural gas customers of amounts collected from customers since the Acquisition date. Each electric customer received the same credit, and each natural gas customer received the same credit. A reduction of revenue and a regulatory liability of $50 million for the amounts refunded were recorded during the quarter ended September 30, 2022. These credits were issued during the fourth quarter of 2022. The amounts refunded will not impact RIE's earnings sharing regulatory mechanism.
•RIE forgave 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 as of September 30, 2022, resulting in an increase to "Other operations and maintenance expense" on the Statement of Income of $23 million for the year ended December 31, 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 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, which are being expensed as incurred, were $262 million and $181 million for the years ended December 31, 2023 and 2022.
•RIE will not seek to recover any transaction costs related to the Acquisition, which were $28 million through December 31, 2023, including an immaterial amount for the year ended December 31, 2023, and $18 million and $10 million for the years ended December 31, 2022 and 2021. These amounts were recorded in "Other operations and maintenance" on the Statement of Income.
•RIE will not seek to recover in rates any markup charged by National Grid U.S. and/or its affiliates under the TSA which were $7 million and $3 million for the year ended December 31, 2023 and 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" on the Statements of Income for the year ended December 31, 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.
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•Rhode Island Holdings contributed $2.5 million to the Rhode Island Commerce Corporation's Renewable Energy Fund and will 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 year ended December 31, 2022 and was recorded in "Other Income (Expense)" on the Statement of Income.
•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 year ended December 31, 2022 and was recorded in "Other Income (Expense) - net" on the Statement of Income.
•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 net assets and liabilities included in rate base. Therefore, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets acquired nor liabilities assumed reflect any adjustments related to these amounts.
Total goodwill resulting from the acquisition was $1,585 million. PPL has elected to not reflect the effects of purchase accounting in the separate financial statements of RIE or PPL's Rhode Island Regulated segment. Accordingly, the Rhode Island Regulated segment includes $725 million of acquired legacy goodwill. The remaining excess purchase price of $860 million is 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 Energy Supplyto leverage its assembled workforce to take advantage of those growth opportunities and the attractiveness of stable, growing cash flows. The tax goodwill is deductible for income tax purposes over a 15 year period, and as such, deferred taxes will be recorded as the tax deductions are taken.
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| Final Purchase Price Allocation | ||||||||||||||||||||
| Assets | ||||||||||||||||||||
| Current Assets | ||||||||||||||||||||
| Cash and Cash Equivalents | $ | 154 | ||||||||||||||||||
| Accounts Receivable (a) | 195 | |||||||||||||||||||
| Unbilled Revenues | 54 | |||||||||||||||||||
| Price Risk Management Assets | 99 | |||||||||||||||||||
| Regulatory Assets | 75 | |||||||||||||||||||
| Other Current Assets | 65 | |||||||||||||||||||
| Total Current Assets | 642 | |||||||||||||||||||
| Noncurrent Assets | ||||||||||||||||||||
| Property, Plant and Equipment, net | 3,992 | |||||||||||||||||||
| Regulatory Assets | 393 | |||||||||||||||||||
| Goodwill | 1,585 | |||||||||||||||||||
| Other Noncurrent Assets | 164 | |||||||||||||||||||
| Total Noncurrent Assets | 6,134 | |||||||||||||||||||
| Total Assets | $ | 6,776 | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||
| Current Liabilities | ||||||||||||||||||||
| Long-Term Debt Due Within One Year | $ | 14 | ||||||||||||||||||
| Accounts Payable | 180 | |||||||||||||||||||
| Taxes Accrued | 44 | |||||||||||||||||||
| Regulatory Liabilities | 239 | |||||||||||||||||||
| Other Current Liabilities | 198 | |||||||||||||||||||
| Total Current Liabilities | 675 | |||||||||||||||||||
| Noncurrent Liabilities | ||||||||||||||||||||
| Long-Term Debt | 1,496 | |||||||||||||||||||
| Regulatory Liabilities | 643 | |||||||||||||||||||
| Other Deferred Credits and Noncurrent Liabilities | 142 | |||||||||||||||||||
| Noncurrent Liabilities | 2,281 | |||||||||||||||||||
| Total Purchase Price (Balance Sheet Net Assets) | $ | 3,820 | ||||||||||||||||||
(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 were $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 December 31, 2022, and PPL's unaudited pro forma 2022 and 2021 Operating Revenues and Net Income (Loss) attributable to PPL, including receiptRIE, as if the Acquisition had occurred on January 1, 2021 are as follows.
| Operating Revenues | Net Income (Loss) | |||||||||||||||||||||||||
| Actual RIE results included from May 25, 2022 - December 31, 2022 (a) | $ | 1,038 | $ | (44) | ||||||||||||||||||||||
| PPL Pro Forma for the year ended 2022 | 8,667 | 790 | ||||||||||||||||||||||||
| PPL Pro Forma for the year ended 2021 | 7,478 | 159 | ||||||||||||||||||||||||
(a)Net Income (Loss) includes expenses of regulatory approvals$98 million (pre-tax) related to commitments made as a condition of the Acquisition.
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The pro forma financial information presented above has been derived from the NRC, FERC, DOJhistorical consolidated financial statements of PPL and PUC,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) $223 million (pre-tax) of Acquisition integration costs, (c) a $50 million reduction of revenue (pre-tax), 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 received by mid-April 2015. On April 29, 2015, PPL's Board of Directors declared the June 1, 2015 distribution to PPL's shareowners of record on May 20, 2015 of a newly formed entity, Holdco, which at closing owned allconditions of the membership interests of PPL Energy SupplyAcquisition, and all of(d) the common stock of Talen Energy.
| Approach | Weighting | Weighted Fair Value (in billions) | ||||
| Talen Energy Market Value | 50% | $ | 1.4 | |||
| Income/Discounted Cash Flow | 30% | 1.1 | ||||
| Alternative Market (Comparable Company) | 20% | 0.7 | ||||
| Estimated Fair Value | $ | 3.2 | ||||
Divestitures
Sale of Safari Holdings
On September 29, 2022, PPL signed a definitive agreement to take advantagesell all of synergies and other benefits that arise from control over another entity, and thatSafari Holdings membership interests to Aspen Power Services, LLC (Aspen Power). On November 1, 2022, PPL completed the market price of a company's individual share of stock does not reflect this additional value to a controlling shareholder. Therefore, the quoted market price need not be the sole measurement basis for determining the fair value, and including a control premium is appropriate in measuring the fair value of a reporting unit.sale (the Transaction).
In connection with the closing of the Transaction, PPL provided certain guarantees and other assurances. Certain of these guarantees and other assurances have been terminated as "Energy purchases from affiliate" but were eliminated in PPL's Consolidated Statements of Income.
Discontinued Operations
Sale of the U.K. Utility Business
On June 14, 2021, PPL Electric's energy purchases from Talen Energy Marketing were $106 millionWPD 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 $27 millionfees, of $10.4 billion.PPL WPD Limited agreed to indemnify National Grid U.K. for 2016certain tax related matters. See Note 13 for additional information. PPL has not had and 2015. There were no energy purchases from Talen Energy Marketing in 2017. These energy purchases are no longer considered affiliate transactions.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 Supply segmentU.K. utility business are included in "Loss"Income (Loss) from Discontinued Operations (net of income taxes)" on the StatementStatements of Income.Income for prior years, as there were no operations in 2023. Following are the components of Discontinued Operationsdiscontinued operations in the StatementStatements of Income for the period ended December 31:
| 2015 | |||
| Operating revenues | $ | 1,427 | |
| Operating expenses | 1,328 | ||
| Other Income (Expense) - net | (21 | ) | |
| Interest expense (a) | 150 | ||
| Income tax expense (benefit) | (30 | ) | |
| Loss on spinoff | (879 | ) | |
| Loss from Discontinued Operations (net of income taxes) | $ | (921 | ) |
| 2022 | 2021 | ||||||||||||||||||||||
| Operating Revenues | $ | — | $ | 1,344 | |||||||||||||||||||
| Operating Expenses | — | 467 | |||||||||||||||||||||
| Other Income (Expense) - net | — | 202 | |||||||||||||||||||||
| Interest Expense (a) | — | 209 | |||||||||||||||||||||
| Income before income taxes | — | 870 | |||||||||||||||||||||
| Loss on sale | — | (1,609) | |||||||||||||||||||||
| Income tax (benefit) expense | (42) | 759 | |||||||||||||||||||||
| Income (Loss) from Discontinued Operations (net of income taxes) | $ | 42 | $ | (1,498) | |||||||||||||||||||
(a)No interest from corporate level debt was as follows:allocated to discontinued operations.
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| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 45 | $ | 50 | $ | 49 | |||||
| LKE | 26 | 26 | 24 | ||||||||
| LG&E | 15 | 15 | 12 | ||||||||
| KU | 11 | 11 | 11 | ||||||||
| PPL | LKE | LG&E | KU | ||||||||||||
| 2018 | $ | 32 | $ | 26 | $ | 15 | $ | 10 | |||||||
| 2019 | 19 | 16 | 8 | 8 | |||||||||||
| 2020 | 13 | 11 | 5 | 6 | |||||||||||
| 2021 | 10 | 8 | 3 | 5 | |||||||||||
| 2022 | 8 | 6 | 2 | 4 | |||||||||||
| Thereafter | 22 | 15 | 6 | 8 | |||||||||||
| Total | $ | 104 | $ | 82 | $ | 39 | $ | 41 | |||||||
10. Leases
| Total Plan | Annual Grant Limit Total As % of Outstanding | Annual Grant | Annual Grant Limit For Individual Participants - Performance Based Awards | |||||||||||||
Award Limit | PPL Common Stock On First Day of | Limit Options | For awards denominated in | For awards denominated in | ||||||||||||
| Plan | (Shares) | Each Calendar Year | (Shares) | shares (Shares) | cash (in dollars) | |||||||||||
| SIP | 15,000,000 | 2,000,000 | 750,000 | $ | 15,000,000 | |||||||||||
| ICPKE | 14,199,796 | 2 | % | 3,000,000 | ||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 35.30 | $ | 33.84 | $ | 34.50 | |||||
| PPL Electric | 35.45 | 34.32 | 34.41 | ||||||||
| LKE | 35.25 | 33.73 | 34.89 | ||||||||
Restricted Shares/Units | Weighted- Average Grant Date Fair Value Per Share | |||||
| PPL | ||||||
| Nonvested, beginning of period | 1,337,025 | $ | 31.57 | |||
| Granted | 538,441 | 35.30 | ||||
| Vested | (567,001 | ) | 29.28 | |||
| Forfeited | (16,816 | ) | 34.28 | |||
| Nonvested, end of period (a) | 1,291,649 | 34.10 | ||||
Restricted Shares/Units | Weighted- Average Grant Date Fair Value Per Share | |||||
| PPL Electric | ||||||
| Nonvested, beginning of period | 204,570 | $ | 31.27 | |||
| Transfer between registrants | (5,250 | ) | 32.05 | |||
| Granted | 79,321 | 35.45 | ||||
| Vested | (91,117 | ) | 28.83 | |||
| Forfeited | (3,108 | ) | 34.68 | |||
| Nonvested, end of period | 184,416 | 34.20 | ||||
| LKE | ||||||
| Nonvested, beginning of period | 243,281 | $ | 31.53 | |||
| Transfer between registrants | 25,337 | 31.61 | ||||
| Granted | 97,775 | 35.25 | ||||
| Vested | (125,612 | ) | 29.68 | |||
| Forfeited | (9,224 | ) | 34.04 | |||
| Nonvested, end of period | 231,557 | 34.01 | ||||
| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 20 | $ | 30 | $ | 28 | |||||
| PPL Electric | 3 | 3 | 4 | ||||||||
| LKE | 4 | 5 | 4 | ||||||||
PPL has also entered into various operating leases primarily for office and warehouse space. These leases generally have fixed payments with expiration dates ranging from 2024 through 2051. RIE has various operating leases, primarily related to buildings, land, and finance leases related to fleet vehicles used to support the electric and gas operations, with lease terms ranging between 1 and 28 years. In measuring lease liabilities, the Company excludes variable lease payments, other than those that depend on an index or more from commencement of the performance period, disabilityrate, or death of an employee.
commencement date. The fair value of each performance unit granted was estimated using a Monte Carlo pricing model that considers stock beta, a risk-free interest rate, expected stock volatility and expected life. The stock beta was calculated comparing the risk of the individual securities to the average risk of the companies in the index group. The risk-free interest rate reflects the yield on a
| 2017 | 2016 | 2015 | ||||||
| Expected stock volatility | 17.40 | % | 19.60 | % | 15.90 | % | ||
| Expected life | 3 years | 3 years | 3 years | |||||
| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 38.38 | $ | 35.74 | $ | 36.76 | |||||
| PPL Electric | 38.37 | 35.68 | 37.93 | ||||||||
| LKE | 38.24 | 35.28 | 37.10 | ||||||||
| TSR Performance Units | Weighted- Average Grant Date Fair Value Per Share | |||||
| PPL | ||||||
| Nonvested, beginning of period | 1,070,536 | $ | 34.65 | |||
| Granted | 293,642 | 38.38 | ||||
| Vested | (243,983 | ) | 32.42 | |||
| Forfeited | (141,964 | ) | 32.27 | |||
| Nonvested, end of period (a) | 978,231 | 36.67 | ||||
| PPL Electric | ||||||
| Nonvested, beginning of period | 76,726 | $ | 34.68 | |||
| Granted | 26,086 | 38.37 | ||||
| Vested | (14,713 | ) | 32.14 | |||
| Forfeited | (12,586 | ) | 35.45 | |||
| Nonvested, end of period | 75,513 | 37.00 | ||||
| LKE | ||||||
| Nonvested, beginning of period | 191,601 | $ | 34.34 | |||
| Transfer between registrants | 8,307 | 35.96 | ||||
| Granted | 64,555 | 38.24 | ||||
| Vested | (48,980 | ) | 32.09 | |||
| Forfeited | (35,194 | ) | 35.25 | |||
| Nonvested, end of period | 180,289 | 36.69 | ||||
PPL Electric also has operating leases which do not have a significant impact to its operations.
(PPL, LG&E and LKE.KU)
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | |||||||||||||||||
| Lease cost: | |||||||||||||||||
| Finance lease cost: | |||||||||||||||||
| Amortization of right-of-use assets | $ | 1 | $ | — | $ | — | |||||||||||
| Interest on lease liabilities | — | — | — | ||||||||||||||
| Operating lease cost | 26 | 20 | 24 | ||||||||||||||
| Short-term lease cost | 6 | 6 | 6 | ||||||||||||||
| Total lease cost | $ | 33 | $ | 26 | $ | 30 | |||||||||||
| LG&E | |||||||||||||||||
| Lease cost: | |||||||||||||||||
| Operating lease cost | $ | 5 | $ | 6 | $ | 6 | |||||||||||
| Short-term lease cost | 1 | 1 | 1 | ||||||||||||||
| Total lease cost | $ | 6 | $ | 7 | $ | 7 | |||||||||||
| KU | |||||||||||||||||
| Lease cost: | |||||||||||||||||
| Operating lease cost | $ | 10 | $ | 9 | $ | 10 | |||||||||||
| Short-term lease cost | 1 | 2 | 1 | ||||||||||||||
| Total lease cost | $ | 11 | $ | 11 | $ | 11 | |||||||||||
The following table provides other key information related to add performance units based on achievement of a corporate Return on Equity (ROE). ROE performance units are intended to further align compensation with the company’s strategy and reward for future corporate performance.
Registrants' leases at December 31:
147
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | |||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||||||||
| Operating cash flows from finance leases | $ | — | $ | — | $ | — | |||||||||||
| Operating cash flows from operating leases | 25 | 26 | 23 | ||||||||||||||
| Financing cash flows from finance leases | 1 | — | — | ||||||||||||||
| Right-of-use asset obtained in exchange for new finance lease liabilities | 7 | — | — | ||||||||||||||
| Right-of-use asset obtained in exchange for new operating lease liabilities | 47 | 15 | 12 | ||||||||||||||
| LG&E | |||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||||||||
| Operating cash flows from operating leases | $ | 6 | $ | 8 | $ | 6 | |||||||||||
| Right-of-use asset obtained in exchange for new operating lease liabilities | 6 | 4 | 4 | ||||||||||||||
| KU | |||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||||||||
| Operating cash flows from operating leases | $ | 9 | $ | 12 | $ | 10 | |||||||||||
| Right-of-use asset obtained in exchange for new operating lease liabilities | 10 | 5 | 7 | ||||||||||||||
The following table provides the total future minimum rental payments for leases, as well as a reconciliation of these performance units will beundiscounted cash flows to the lease liabilities recognized on the Balance Sheets as of December 31, 2023.
| PPL | LG&E | KU | |||||||||||||||||||||
| Operating leases | Finance leases | Operating leases | Operating leases | ||||||||||||||||||||
| 2024 | $ | 24 | $ | 2 | $ | 6 | $ | 9 | |||||||||||||||
| 2025 | 18 | 1 | 5 | 6 | |||||||||||||||||||
| 2026 | 11 | 1 | 2 | 3 | |||||||||||||||||||
| 2027 | 9 | 1 | 1 | 2 | |||||||||||||||||||
| 2028 | 8 | 1 | 1 | 1 | |||||||||||||||||||
| Thereafter | 34 | 2 | — | 1 | |||||||||||||||||||
| Total | $ | 104 | $ | 8 | $ | 15 | $ | 22 | |||||||||||||||
Weighted-average discount rate | 4.68% | 7.56% | 4.05% | 4.36% | |||||||||||||||||||
| Weighted-average remaining lease term (in years) | 8 | 7 | 3 | 3 | |||||||||||||||||||
| Current lease liabilities (a) | $ | 21 | $ | 1 | $ | 6 | $ | 8 | |||||||||||||||
| Non-current lease liabilities (a) | 63 | 6 | 9 | 12 | |||||||||||||||||||
| Right-of-use assets (b) | 74 | 6 | 13 | 19 | |||||||||||||||||||
(a) Current lease liabilities are included in "Other Current Liabilities" on the Balance Sheets. Non-current lease liabilities are included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets. The difference between the total future minimum lease payments and the recorded lease liabilities is due to the impact of discounting.
(b) Operating lease right-of-use assets are included in "Other noncurrent assets" and finance lease right-of-use assets are included in "Property, Plant and Equipment" on the Balance Sheets.
Lessor Transactions
Third parties leased land from LG&E and KU at certain generation plants to produce refined coal used to generate electricity. The leases were operating leases and expired in 2021. Payments were allocated among lease and non-lease components as stated in the agreements. Lease payments were fixed or determined based on the calculated averageamount of refined coal used in electricity generation at the annual corporate ROEfacility. Payments received were primarily recorded as a regulatory liability and amortized in accordance with regulatory approvals. There are certain leases in which RIE is the lessor. Revenue under such leases was immaterial for eachthe year of the three-year performance period for PPL Corporation. ROE performance units represent a target number of shares (Target Award) of PPL's common stock that the recipient would receive upon PPL's attainment of the applicable ROE performance goal. ROE performance units can be paid up to 200% of the Target Award or forfeited with no payout if performance is below a minimum established performance threshold. Dividends payable during the performance cycle accumulate and are converted into additional performance units and are payable in shares of PPL common stock upon completion of the performance period based on the determination of the CGNC of whether the performance goals have been achieved. Under the plan provisions, these performance units are subject to forfeiture upon termination of employment except for retirement, disability or death of an employee.ended December 31, 2023.
The fair value of each ROE performance unit is based onfollowing table shows the closing price of PPL Common Stock onlease income recognized for the date of grant. The fair value of ROE performance units is recognized on a straight-line basis over the service period or through the date at which the employee reaches retirement eligibility. The fair value awards granted to retirement-eligible employees is recognized as compensation expense immediately upon the date of grant. As these awards are based on performance conditions, the level of attainment is monitored each reporting period and compensation expense is adjusted based on the expected attainment level.
| ROE Performance Unit | Weighted- Average Grant Date Fair Value Per Share | |||||
| PPL | ||||||
| Granted | 97,925 | $ | 34.42 | |||
| Forfeited | (997 | ) | 34.41 | |||
| Nonvested, end of period | 96,928 | 34.42 | ||||
| PPL Electric | ||||||
| Granted | 8,696 | $ | 34.41 | |||
| Nonvested, end of period | 8,696 | 34.41 | ||||
| LKE | ||||||
| Granted | 21,536 | $ | 34.29 | |||
| Forfeited | (997 | ) | 34.41 | |||
| Nonvested, end of period | 20,539 | 34.29 | ||||
148
Number of Options | Weighted Average Exercise Price Per Share | Weighted- Average Remaining Contractual Term (years) | Aggregate Total Intrinsic Value | |||||||||
| PPL | ||||||||||||
| Outstanding at beginning of period | 4,481,160 | $ | 28.98 | |||||||||
| Exercised | (718,977 | ) | 26.67 | |||||||||
| Outstanding and exercisable at end of period | 3,762,183 | 29.42 | 3.5 | $ | 14 | |||||||
| PPL Electric | ||||||||||||
| Outstanding at beginning of period | 240,939 | $ | 27.48 | |||||||||
| Exercised | (42,659 | ) | 26.99 | |||||||||
| Outstanding and exercisable at end of period | 198,280 | 27.58 | 3.8 | $ | 1 | |||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | $ | 4 | 6 | 11 | |||||||||||||
| LG&E | — | 2 | 5 | ||||||||||||||
| KU | — | — | 5 | ||||||||||||||
Number of Options | Weighted Average Exercise Price Per Share | Weighted- Average Remaining Contractual Term (years) | Aggregate Total Intrinsic Value | |||||||||
| LKE | ||||||||||||
| Outstanding at beginning of period | 61,896 | $ | 25.81 | |||||||||
| Exercised | (28,164 | ) | 26.59 | |||||||||
| Outstanding and exercisable at end of period | 33,732 | 25.15 | 4.1 | $ | — | |||||||
| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 32 | $ | 27 | $ | 33 | |||||
| PPL Electric | 18 | 16 | 14 | ||||||||
| LKE | 8 | 7 | 8 | ||||||||
| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 13 | $ | 12 | $ | 14 | |||||
| PPL Electric | 8 | 7 | 6 | ||||||||
| LKE | 3 | 3 | 3 | ||||||||
Unrecognized Compensation Expense | Weighted- Average Period for Recognition | ||||
| PPL | $ | 10 | 1.7 | ||
| PPL Electric | 2 | 1.7 | |||
| LKE | 1 | 1.6 | |||
11. Retirement and Postemployment Benefits
(All Registrants)
Defined Benefits
Effective January 1, 2012, PPL's primary defined benefit pension plan was closed to all newly hired salaried employees. Effective July 1, 2014, PPL's primary defined benefit pension plan was closed to all newly hired bargaining unit employees. Newly hired employees are eligible to participate in the PPL Retirement Savings Plan, a 401(k) savings plan with enhanced employer contributions.
The defined benefit pension plans of LKE and its subsidiaries were closed to new salaried and bargaining unit employees hired after December 31, 2005. Employees hired after December 31, 2005 receive additional company contributions above the standard matching contributions to their savings plans. The pension plans sponsored by LKE and LG&E were merged effective January 1, 2020 into the LG&E and KU Pension Plan. The merged plan is sponsored by LKE. LG&E and KU participate in this plan.
PPL and certain of its subsidiaries also provide supplemental retirement benefits to executives and other key management employees through unfunded nonqualified retirement plans.
The Rhode Island postretirement benefit plans other than pensions.provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage.
149
(PPL)
The following table provides the components of net periodic defined benefit costs (credits) for PPL's domestic (U.S.) and WPD's (U.K.) pension and other postretirement benefit plans for the years ended December 31.
| Pension Benefits | |||||||||||||||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||||||||||||||||
| Net periodic defined benefit costs (credits): | |||||||||||||||||||||||||||||||||||
| Service cost | $ | 65 | $ | 66 | $ | 96 | $ | 76 | $ | 69 | $ | 79 | $ | 7 | $ | 7 | $ | 11 | |||||||||||||||||
| Interest cost | 168 | 174 | 194 | 178 | 235 | 314 | 23 | 26 | 26 | ||||||||||||||||||||||||||
| Expected return on plan assets | (231 | ) | (228 | ) | (258 | ) | (514 | ) | (504 | ) | (523 | ) | (22 | ) | (22 | ) | (26 | ) | |||||||||||||||||
| Amortization of: | |||||||||||||||||||||||||||||||||||
| Prior service cost (credit) | 10 | 8 | 7 | — | — | — | (1 | ) | — | 1 | |||||||||||||||||||||||||
| Actuarial (gain) loss | 69 | 50 | 84 | 144 | 138 | 158 | 1 | 1 | — | ||||||||||||||||||||||||||
Net periodic defined benefit costs (credits) prior to settlements and termination benefits | 81 | 70 | 123 | (116 | ) | (62 | ) | 28 | 8 | 12 | 12 | ||||||||||||||||||||||||
| Settlements | 1 | 3 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Termination benefits | 1 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
Net periodic defined benefit costs (credits) | $ | 83 | $ | 73 | $ | 123 | $ | (116 | ) | $ | (62 | ) | $ | 28 | $ | 8 | $ | 12 | $ | 12 | |||||||||||||||
| Pension Benefits | |||||||||||||||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||||||||||||||||
| Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets/Liabilities - Gross: | |||||||||||||||||||||||||||||||||||
| Divestiture (a) | $ | — | $ | — | $ | (353 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (6 | ) | |||||||||||||||
| Settlement | (1 | ) | (3 | ) | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Net (gain) loss | 27 | 253 | 63 | 346 | 7 | 508 | (28 | ) | 9 | (9 | ) | ||||||||||||||||||||||||
Prior service cost (credit) | (1 | ) | 15 | 18 | — | — | — | 8 | — | — | |||||||||||||||||||||||||
| Amortization of: | |||||||||||||||||||||||||||||||||||
| Prior service (cost) credit | (10 | ) | (8 | ) | (7 | ) | — | — | — | 1 | (1 | ) | (1 | ) | |||||||||||||||||||||
| Actuarial gain (loss) | (69 | ) | (50 | ) | (85 | ) | (144 | ) | (138 | ) | (158 | ) | (1 | ) | (1 | ) | — | ||||||||||||||||||
Total recognized in OCI and regulatory assets/liabilities (b) | (54 | ) | 207 | (364 | ) | 202 | (131 | ) | 350 | (20 | ) | 7 | (16 | ) | |||||||||||||||||||||
Total recognized in net periodic defined benefit costs, OCI and regulatory assets/liabilities (b) | $ | 29 | $ | 280 | $ | (241 | ) | $ | 86 | $ | (193 | ) | $ | 378 | $ | (12 | ) | $ | 19 | $ | (4 | ) | |||||||||||||
| U.S. Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
| OCI | $ | (53 | ) | $ | 236 | $ | (269 | ) | $ | (25 | ) | $ | 7 | $ | 12 | ||||||||
| Regulatory assets/liabilities | (1 | ) | (29 | ) | (95 | ) | 5 | — | (28 | ) | |||||||||||||
Total recognized in OCI and regulatory assets/liabilities | $ | (54 | ) | $ | 207 | $ | (364 | ) | $ | (20 | ) | $ | 7 | $ | (16 | ) | |||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| Net periodic defined benefit costs (credits): | |||||||||||||||||||||||||||||||||||
| Service cost | $ | 34 | $ | 51 | $ | 56 | $ | 6 | $ | 7 | $ | 6 | |||||||||||||||||||||||
| Interest cost | 188 | 144 | 121 | 30 | 20 | 16 | |||||||||||||||||||||||||||||
| Expected return on plan assets | (309) | (276) | (255) | (30) | (28) | (23) | |||||||||||||||||||||||||||||
| Amortization of: | |||||||||||||||||||||||||||||||||||
| Prior service cost (credit) | 6 | 8 | 8 | 1 | 1 | 1 | |||||||||||||||||||||||||||||
| Actuarial (gain) loss | 2 | 51 | 93 | (5) | (5) | (1) | |||||||||||||||||||||||||||||
| Net periodic defined benefit costs (credits) prior to settlements and termination benefits | (79) | (22) | 23 | 2 | (5) | (1) | |||||||||||||||||||||||||||||
| Settlements (a) | — | 23 | 18 | — | — | — | |||||||||||||||||||||||||||||
| Net periodic defined benefit costs (credits) | $ | (79) | $ | 1 | $ | 41 | $ | 2 | $ | (5) | $ | (1) | |||||||||||||||||||||||
| Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets/Liabilities - Gross: | |||||||||||||||||||||||||||||||||||
| Net (loss)/gain allocated at acquisition | $ | — | $ | 33 | $ | — | $ | — | $ | (49) | $ | — | |||||||||||||||||||||||
| Settlement | — | (23) | (18) | — | — | — | |||||||||||||||||||||||||||||
| Net (gain) loss | 193 | 242 | 42 | (6) | — | (53) | |||||||||||||||||||||||||||||
| Prior service cost (credit) | 2 | — | 3 | — | — | — | |||||||||||||||||||||||||||||
| Amortization of: | |||||||||||||||||||||||||||||||||||
| Prior service (cost) credit | (6) | (8) | (8) | (1) | (1) | (1) | |||||||||||||||||||||||||||||
| Actuarial gain (loss) | (2) | (51) | (93) | 5 | 5 | 1 | |||||||||||||||||||||||||||||
| Total recognized in OCI and regulatory assets/liabilities | 187 | 193 | (74) | (2) | (45) | (53) | |||||||||||||||||||||||||||||
| Total recognized in net periodic defined benefit costs, OCI and regulatory assets/liabilities | $ | 108 | $ | 194 | $ | (33) | $ | — | $ | (50) | $ | (54) | |||||||||||||||||||||||
| Pension Benefits | |||||||
| U.S. | U.K. | ||||||
| Prior service cost (credit) | $ | 10 | $ | — | |||
| Actuarial (gain) loss | 86 | 152 | |||||
| Total | $ | 96 | $ | 152 | |||
| Amortization from Balance Sheet: | |||||||
| AOCI | $ | 28 | $ | 152 | |||
| Regulatory assets/liabilities | 68 | — | |||||
| Total | $ | 96 | $ | 152 | |||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
| Net periodic defined benefit costs (credits): | |||||||||||||||||||||||
| Service cost | $ | 24 | $ | 23 | $ | 26 | $ | 4 | $ | 5 | $ | 5 | |||||||||||
| Interest cost | 68 | 71 | 68 | 9 | 9 | 9 | |||||||||||||||||
| Expected return on plan assets | (92 | ) | (91 | ) | (88 | ) | (7 | ) | (6 | ) | (6 | ) | |||||||||||
| Amortization of: | |||||||||||||||||||||||
| Prior service cost | 8 | 8 | 7 | 1 | 3 | 3 | |||||||||||||||||
| Actuarial (gain) loss (a) | 31 | 21 | 37 | — | (1 | ) | — | ||||||||||||||||
| Net periodic defined benefit costs (b) | $ | 39 | $ | 32 | $ | 50 | $ | 7 | $ | 10 | $ | 11 | |||||||||||
Other Changes in Plan Assets and Benefit Obligations Recognized in OCI and Regulatory Assets/Liabilities - Gross: | |||||||||||||||||||||||
| Net (gain) loss | $ | 30 | $ | 119 | $ | 20 | $ | (14 | ) | $ | 6 | $ | (15 | ) | |||||||||
| Prior service cost | 7 | — | 19 | 8 | — | — | |||||||||||||||||
| Amortization of: | |||||||||||||||||||||||
| Prior service credit | (8 | ) | (8 | ) | (7 | ) | (1 | ) | (3 | ) | (3 | ) | |||||||||||
| Actuarial gain (loss) | (32 | ) | (21 | ) | (37 | ) | — | 1 | — | ||||||||||||||
Total recognized in OCI and regulatory assets/liabilities | (3 | ) | 90 | (5 | ) | (7 | ) | 4 | (18 | ) | |||||||||||||
Total recognized in net periodic defined benefit costs, OCI and regulatory assets/liabilities | $ | 36 | $ | 122 | $ | 45 | $ | — | $ | 14 | $ | (7 | ) | ||||||||||
| Pension Benefits | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| OCI | $ | 33 | $ | 42 | $ | 4 | $ | (2 | ) | $ | 2 | $ | (2 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Regulatory assets/liabilities | (36 | ) | 48 | (9 | ) | (5 | ) | 2 | (16 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total recognized in OCI and regulatory assets/liabilities | $ | (3 | ) | $ | 90 | $ | (5 | ) | $ | (7 | ) | $ | 4 | $ | (18 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||
| Prior service cost | $ | 9 | $ | 1 | |||
| Actuarial Loss | 39 | — | |||||
| Total | $ | 48 | $ | 1 | |||
| Amortization from Balance Sheet: | |||||||
| AOCI | $ | 11 | $ | — | |||
| Regulatory assets/liabilities | 37 | 1 | |||||
| Total | $ | 48 | $ | 1 | |||
| Pension Benefits | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Net periodic defined benefit costs (credits): | |||||||||||
| Service cost | $ | 1 | $ | 1 | $ | 1 | |||||
| Interest cost | 13 | 15 | 14 | ||||||||
| Expected return on plan assets | (22 | ) | (21 | ) | (20 | ) | |||||
| Amortization of: | |||||||||||
| Prior service cost | 5 | 4 | 3 | ||||||||
| Actuarial loss (a) | 9 | 7 | 11 | ||||||||
| Net periodic defined benefit costs (b) | $ | 6 | $ | 6 | $ | 9 | |||||
Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets - Gross: | |||||||||||
| Net (gain) loss | $ | (9 | ) | $ | 22 | $ | 8 | ||||
| Prior service cost | 7 | — | 10 | ||||||||
| Amortization of: | |||||||||||
| Prior service credit | (5 | ) | (4 | ) | (3 | ) | |||||
| Actuarial gain | (9 | ) | (7 | ) | (11 | ) | |||||
| Total recognized in regulatory assets/liabilities | (16 | ) | 11 | 4 | |||||||
| Total recognized in net periodic defined benefit costs and regulatory assets | $ | (10 | ) | $ | 17 | $ | 13 | ||||
Pension Benefits | |||
| Prior service cost | $ | 5 | |
| Actuarial loss | 9 | ||
| Total | $ | 14 | |
| Pension Benefits | |||||||||||||||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | |||||||||||||||||||||||||||
| PPL | $ | 59 | $ | 53 | $ | 71 | $ | (151 | ) | $ | (95 | ) | $ | (21 | ) | $ | 5 | $ | 7 | $ | 8 | ||||||||||||||
| PPL Electric (a) | 12 | 10 | 15 | — | 1 | — | |||||||||||||||||||||||||||||
| LKE (b) | 28 | 24 | 37 | 5 | 6 | 8 | |||||||||||||||||||||||||||||
| LG&E (b) | 8 | 8 | 12 | 3 | 3 | 4 | |||||||||||||||||||||||||||||
| KU (a) (b) | 4 | 5 | 9 | 1 | 2 | 2 | |||||||||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
| LG&E Non-Union Only | $ | 5 | $ | 4 | $ | 5 | $ | 3 | $ | 3 | $ | 4 | |||||||||||
PPL LKE and LG&E adopted the newuses base mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables with collar and factor adjustments, where applicable) for all U.S. defined benefit pension and other postretirement benefit plans. In addition, in 2014, PPL, LKEThe Pri-2012 base table and LG&E updated the basis for estimating projected mortality improvementsMP-2020 projection scale with varying adjustment factors based on the underlying demographic and selectedgeographic differences and experience of the IRS BB-2D two-dimensional improvement scale on a generational basisplan participants was used for all U.S. defined benefit pension and other postretirement benefit plans. In 2017, PPL, LKE and LG&E updated to the MP-2017 mortality improvement scale from 2006 on a generational basis. This new mortality assumption reflects the expectationperiods.
150
The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31. The U.K. pension benefits apply to PPL only.
| Pension Benefits | |||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| PPL | PPL | ||||||||||||||||||||||||||||||||||||||||||||||||
| Discount rate | 3.70 | % | 4.21 | % | 2.65 | % | 2.87 | % | 3.64 | % | 4.11 | % | Discount rate | 5.52 | % | 5.80 | % | 5.54 | % | 5.81 | % | ||||||||||||||||||||||||||||
| Rate of compensation increase | 3.78 | % | 3.95 | % | 3.50 | % | 3.50 | % | 3.75 | % | 3.92 | % | Rate of compensation increase | 3.43 | % | 3.77 | % | 3.43 | % | 3.78 | % | ||||||||||||||||||||||||||||
| LKE | |||||||||||||||||||||||||||||||||||||||||||||||||
| Discount rate | 3.69 | % | 4.19 | % | 3.65 | % | 4.12 | % | |||||||||||||||||||||||||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | |||||||||||||||||||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||||||||||||||||||||
| Discount rate | 3.65 | % | 4.13 | % | |||||||||||||||||||||||||||||||||||||||||||||
The following weighted-average assumptions were used to determine the net periodic defined benefit costs for the years ended December 31. The U.K. pension benefits apply to PPL only.
| Pension Benefits | ||||||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
| PPL | ||||||||||||||||||||||||||
| Discount rate service cost (b) | 4.21 | % | 4.59 | % | 4.25 | % | 2.99 | % | 3.90 | % | 3.85 | % | 4.11 | % | 4.48 | % | 4.09 | % | ||||||||
| Discount rate interest cost (b) | 4.21 | % | 4.59 | % | 4.25 | % | 2.41 | % | 3.14 | % | 3.85 | % | 4.11 | % | 4.48 | % | 4.09 | % | ||||||||
| Rate of compensation increase | 3.95 | % | 3.93 | % | 3.91 | % | 3.50 | % | 4.00 | % | 4.00 | % | 3.92 | % | 3.91 | % | 3.86 | % | ||||||||
| Expected return on plan assets (a) | 7.00 | % | 7.00 | % | 7.00 | % | 7.22 | % | 7.20 | % | 7.19 | % | 6.21 | % | 6.11 | % | 6.06 | % | ||||||||
| LKE | ||||||||||||||||||||||||||
| Discount rate | 4.19 | % | 4.56 | % | 4.25 | % | 4.12 | % | 4.49 | % | 4.06 | % | ||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | ||||||||||||||
| Expected return on plan assets (a) | 7.00 | % | 7.00 | % | 7.00 | % | 6.82 | % | 6.82 | % | 6.82 | % | ||||||||||||||
| Pension Benefits | ||||||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||
| Discount rate | 4.13 | % | 4.49 | % | 4.20 | % | ||||||||||||||||||||
| Expected return on plan assets (a) | 7.00 | % | 7.00 | % | 7.00 | % | ||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||||||
| Discount rate | 5.52 | % | 3.35 | % | 2.92 | % | 5.54 | % | 3.54 | % | 2.84 | % | |||||||||||||||||||||||
| Rate of compensation increase | 3.43 | % | 3.74 | % | 3.76 | % | 3.43 | % | 2.84 | % | 3.75 | % | |||||||||||||||||||||||
| Expected return on plan assets | 8.25 | % | 7.25 | % | 7.25 | % | 7.38 | % | 6.52 | % | 6.48 | % | |||||||||||||||||||||||
(a)The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
The following table provides the assumed health care cost trend rates for the years ended December 31:
| 2017 | 2016 | 2015 | ||||||
| PPL and LKE | ||||||||
| Health care cost trend rate assumed for next year | ||||||||
| – obligations | 6.6 | % | 7.0 | % | 6.8 | % | ||
| – cost | 7.0 | % | 6.8 | % | 7.2 | % | ||
| Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | ||||||||
| – obligations | 5.0 | % | 5.0 | % | 5.0 | % | ||
| – cost | 5.0 | % | 5.0 | % | 5.0 | % | ||
| Year that the rate reaches the ultimate trend rate | ||||||||
| – obligations | 2022 | 2022 | 2020 | |||||
| – cost | 2022 | 2020 | 2020 | |||||
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | |||||||||||||||||
| Health care cost trend rate assumed for next year | |||||||||||||||||
| – obligations | 6.25 | % | 6.50 | % | 6.25 | % | |||||||||||
| – cost | 6.50 | % | 6.25 | % | 6.50 | % | |||||||||||
| Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | |||||||||||||||||
| – obligations | 5.00 | % | 5.00 | % | 5.00 | % | |||||||||||
| – cost | 5.00 | % | 5.00 | % | 5.00 | % | |||||||||||
| Year that the rate reaches the ultimate trend rate | |||||||||||||||||
| – obligations | 2029 | 2029 | 2027 | ||||||||||||||
| – cost | 2029 | 2027 | 2027 | ||||||||||||||
| One Percentage Point | |||||||
| Increase | Decrease | ||||||
| Effect on accumulated postretirement benefit obligation | |||||||
| PPL | $ | 4 | $ | (4 | ) | ||
| LKE | 3 | (3 | ) | ||||
151
The funded status of PPL's plans at December 31 was as follows:
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Change in Benefit Obligation | |||||||||||||||||||||||
| Benefit Obligation, beginning of period | $ | 3,333 | $ | 3,989 | $ | 534 | $ | 504 | |||||||||||||||
| Service cost | 34 | 51 | 6 | 7 | |||||||||||||||||||
| Interest cost | 188 | 144 | 30 | 20 | |||||||||||||||||||
| Participant contributions | — | — | 9 | 9 | |||||||||||||||||||
| Plan amendments | 3 | — | — | — | |||||||||||||||||||
| Actuarial (gain) loss | 179 | (1,026) | 18 | (114) | |||||||||||||||||||
| Acquisition (a) | — | 553 | — | 163 | |||||||||||||||||||
| Settlements | (3) | (111) | — | — | |||||||||||||||||||
| Gross benefits paid | (280) | (267) | (59) | (55) | |||||||||||||||||||
| Benefit Obligation, end of period | 3,454 | 3,333 | 538 | 534 | |||||||||||||||||||
| Change in Plan Assets | |||||||||||||||||||||||
| Plan assets at fair value, beginning of period | 3,149 | 3,887 | 417 | 367 | |||||||||||||||||||
| Actual return on plan assets | 297 | (992) | 54 | (86) | |||||||||||||||||||
| Employer contributions | 13 | 9 | 16 | 19 | |||||||||||||||||||
| Participant contributions | — | — | 7 | 7 | |||||||||||||||||||
| Acquisition (a) | — | 623 | — | 160 | |||||||||||||||||||
| Settlements | (3) | (111) | — | — | |||||||||||||||||||
| Gross benefits paid | (280) | (267) | (56) | (50) | |||||||||||||||||||
| Plan assets at fair value, end of period | 3,176 | 3,149 | 438 | 417 | |||||||||||||||||||
| Funded Status, end of period | $ | (278) | $ | (184) | $ | (100) | $ | (117) | |||||||||||||||
| Amounts recognized in the Balance Sheets consist of: | |||||||||||||||||||||||
| Noncurrent asset | $ | 7 | $ | 33 | $ | 10 | $ | 9 | |||||||||||||||
| Current liability | (10) | (10) | (14) | (14) | |||||||||||||||||||
| Noncurrent liability | (275) | (207) | (96) | (112) | |||||||||||||||||||
| Net amount recognized, end of period | $ | (278) | $ | (184) | $ | (100) | $ | (117) | |||||||||||||||
| Amounts recognized in AOCI and regulatory assets/liabilities (pre-tax) consist of: | |||||||||||||||||||||||
| Prior service cost (credit) | $ | 11 | $ | 14 | $ | 10 | $ | 11 | |||||||||||||||
| Net actuarial (gain) loss | 1,017 | 827 | (96) | (95) | |||||||||||||||||||
| Total | $ | 1,028 | $ | 841 | $ | (86) | $ | (84) | |||||||||||||||
| Total accumulated benefit obligation for defined benefit pension plans | $ | 3,312 | $ | 3,197 | |||||||||||||||||||
| Pension Benefits | |||||||||||||||||||||||
| U.S. | U.K. | Other Postretirement Benefits | |||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||
| Change in Benefit Obligation | |||||||||||||||||||||||
| Benefit Obligation, beginning of period | $ | 4,079 | $ | 3,863 | $ | 7,383 | $ | 8,404 | $ | 591 | $ | 596 | |||||||||||
| Service cost | 65 | 66 | 76 | 69 | 7 | 7 | |||||||||||||||||
| Interest cost | 168 | 174 | 178 | 235 | 23 | 26 | |||||||||||||||||
| Participant contributions | — | — | 13 | 14 | 14 | 14 | |||||||||||||||||
| Plan amendments | (1 | ) | 14 | — | — | 8 | — | ||||||||||||||||
| Actuarial (gain) loss | 233 | 214 | 293 | 484 | 4 | 11 | |||||||||||||||||
| Settlements | (6 | ) | (9 | ) | (1 | ) | — | — | — | ||||||||||||||
| Termination benefits | 1 | — | — | — | — | — | |||||||||||||||||
| Gross benefits paid | (251 | ) | (243 | ) | (345 | ) | (357 | ) | (59 | ) | (64 | ) | |||||||||||
| Federal subsidy | — | — | — | — | 1 | 1 | |||||||||||||||||
| Currency conversion | — | — | 622 | (1,466 | ) | — | — | ||||||||||||||||
| Benefit Obligation, end of period | 4,288 | 4,079 | 8,219 | 7,383 | 589 | 591 | |||||||||||||||||
| Change in Plan Assets | |||||||||||||||||||||||
| Plan assets at fair value, beginning of period | 3,243 | 3,227 | 7,211 | 7,625 | 378 | 379 | |||||||||||||||||
| Actual return on plan assets | 437 | 189 | 480 | 979 | 54 | 25 | |||||||||||||||||
| Employer contributions | 65 | 79 | 486 | 330 | 15 | 19 | |||||||||||||||||
| Participant contributions | — | — | 13 | 14 | 13 | 14 | |||||||||||||||||
| Settlements | (6 | ) | (9 | ) | (1 | ) | — | — | — | ||||||||||||||
| Gross benefits paid | (251 | ) | (243 | ) | (345 | ) | (357 | ) | (55 | ) | (59 | ) | |||||||||||
| Currency conversion | — | — | 646 | (1,380 | ) | — | — | ||||||||||||||||
| Plan assets at fair value, end of period | 3,488 | 3,243 | 8,490 | 7,211 | 405 | 378 | |||||||||||||||||
| Funded Status, end of period | $ | (800 | ) | $ | (836 | ) | $ | 271 | $ | (172 | ) | $ | (184 | ) | $ | (213 | ) | ||||||
| Amounts recognized in the Balance Sheets consist of: | |||||||||||||||||||||||
| Noncurrent asset | $ | — | $ | — | $ | 284 | $ | 10 | $ | 2 | $ | 2 | |||||||||||
| Current liability | (13 | ) | (17 | ) | — | — | (3 | ) | (3 | ) | |||||||||||||
| Noncurrent liability | (787 | ) | (819 | ) | (13 | ) | (182 | ) | (183 | ) | (212 | ) | |||||||||||
| Net amount recognized, end of period | $ | (800 | ) | $ | (836 | ) | $ | 271 | $ | (172 | ) | $ | (184 | ) | $ | (213 | ) | ||||||
| Amounts recognized in AOCI and regulatory assets/liabilities (pre-tax) consist of: | |||||||||||||||||||||||
| Prior service cost (credit) | $ | 49 | $ | 59 | $ | — | $ | — | $ | 9 | $ | — | |||||||||||
| Net actuarial (gain) loss | 1,134 | 1,178 | 2,755 | 2,553 | 16 | 45 | |||||||||||||||||
| Total (a) | $ | 1,183 | $ | 1,237 | $ | 2,755 | $ | 2,553 | $ | 25 | $ | 45 | |||||||||||
Total accumulated benefit obligation for defined benefit pension plans | $ | 4,000 | $ | 3,807 | $ | 7,542 | $ | 6,780 | |||||||||||||||
For PPL's U.S. pension and other postretirement benefit plans, the amounts recognized in AOCI and regulatory assets/liabilities at December 31 were as follows:
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| AOCI | $ | 235 | $ | 183 | $ | 14 | $ | 13 | |||||||||||||||
| Regulatory assets/liabilities | 793 | 658 | (100) | (97) | |||||||||||||||||||
| Total | $ | 1,028 | $ | 841 | $ | (86) | $ | (84) | |||||||||||||||
| U.S. Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| AOCI | $ | 374 | $ | 357 | $ | 15 | $ | 20 | |||||||
| Regulatory assets/liabilities | 809 | 880 | 10 | 25 | |||||||||||
| Total | $ | 1,183 | $ | 1,237 | $ | 25 | $ | 45 | |||||||
The actuarial loss for pension plans in 2023 was primarily related to a change in the discount rate used to measure the benefit obligations of those plans. The actuarial gain for pension plans in 2022 was related to a change in the discount rate used to measure the benefit obligations of those plans.
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The following tables provide information on pension plans where the projected benefit obligation (PBO) or accumulated benefit obligation (ABO) exceed the fair value of plan assets:
| U.S. | U.K. | ||||||||||||||||||||||||||||
| PBO in excess of plan assets | PBO in excess of plan assets | PBO in excess of plan assets | |||||||||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||||||||
| Projected benefit obligation | $ | 4,288 | $ | 4,079 | $ | 3,083 | $ | 3,403 | |||||||||||||||||||||
| Fair value of plan assets | 3,488 | 3,243 | 3,070 | 3,221 | |||||||||||||||||||||||||
| U.S. | U.K. | ||||||||||||||||||||||||||||
| ABO in excess of plan assets | ABO in excess of plan assets | ||||||||||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ABO in excess of plan assets | |||||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||||||||
| Accumulated benefit obligation | $ | 4,000 | $ | 3,807 | $ | 10 | $ | 657 | |||||||||||||||||||||
| Fair value of plan assets | 3,488 | 3,243 | — | 643 | |||||||||||||||||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Change in Benefit Obligation | |||||||||||||||
| Benefit Obligation, beginning of period | $ | 1,669 | $ | 1,588 | $ | 220 | $ | 216 | |||||||
| Service cost | 24 | 23 | 4 | 5 | |||||||||||
| Interest cost | 68 | 71 | 9 | 9 | |||||||||||
| Participant contributions | — | — | 8 | 7 | |||||||||||
| Plan amendments (a) | 6 | — | 8 | — | |||||||||||
| Actuarial (gain) loss | 113 | 96 | (7 | ) | 4 | ||||||||||
| Gross benefits paid (a) | (109 | ) | (109 | ) | (19 | ) | (21 | ) | |||||||
| Benefit Obligation, end of period | 1,771 | 1,669 | 223 | 220 | |||||||||||
| Change in Plan Assets | |||||||||||||||
| Plan assets at fair value, beginning of period | 1,315 | 1,289 | 98 | 88 | |||||||||||
| Actual return on plan assets | 175 | 69 | 14 | 4 | |||||||||||
| Employer contributions | 21 | 66 | 15 | 20 | |||||||||||
| Participant contributions | — | — | 8 | 7 | |||||||||||
| Gross benefits paid | (109 | ) | (109 | ) | (19 | ) | (21 | ) | |||||||
| Plan assets at fair value, end of period | 1,402 | 1,315 | 116 | 98 | |||||||||||
| Funded Status, end of period | $ | (369 | ) | $ | (354 | ) | $ | (107 | ) | $ | (122 | ) | |||
| Amounts recognized in the Balance Sheets consist of: | |||||||||||||||
| Noncurrent asset | $ | — | $ | — | $ | 2 | $ | 2 | |||||||
| Current liability | (4 | ) | (4 | ) | (3 | ) | (3 | ) | |||||||
| Noncurrent liability | (365 | ) | (350 | ) | (106 | ) | (121 | ) | |||||||
| Net amount recognized, end of period | $ | (369 | ) | $ | (354 | ) | $ | (107 | ) | $ | (122 | ) | |||
| Amounts recognized in AOCI and regulatory assets/liabilities (pre-tax) consist of: | |||||||||||||||
| Prior service cost | $ | 44 | $ | 45 | $ | 13 | $ | 6 | |||||||
| Net actuarial (gain) loss | 434 | 436 | (26 | ) | (13 | ) | |||||||||
| Total | $ | 478 | $ | 481 | $ | (13 | ) | $ | (7 | ) | |||||
Total accumulated benefit obligation for defined benefit pension plans | $ | 1,616 | $ | 1,531 | |||||||||||
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||
| 2017 | 2016 | 2017 | 2016 | ||||||||||||
| AOCI | $ | 144 | $ | 111 | $ | 6 | $ | 8 | |||||||
| Regulatory assets/liabilities | 334 | 370 | (19 | ) | (15 | ) | |||||||||
| Total | $ | 478 | $ | 481 | $ | (13 | ) | $ | (7 | ) | |||||
| PBO in excess of plan assets | |||||||
| 2017 | 2016 | ||||||
| Projected benefit obligation | $ | 1,771 | $ | 1,669 | |||
| Fair value of plan assets | 1,402 | 1,315 | |||||
| ABO in excess of plan assets | |||||||
| 2017 | 2016 | ||||||
| Accumulated benefit obligation | $ | 1,616 | $ | 1,531 | |||
| Fair value of plan assets | 1,402 | 1,315 | |||||
| Pension Benefits | |||||||
| 2017 | 2016 | ||||||
| Change in Benefit Obligation | |||||||
| Benefit Obligation, beginning of period | $ | 329 | $ | 326 | |||
| Service cost | 1 | 1 | |||||
| Interest cost | 13 | 15 | |||||
| Plan amendments (a) | 6 | — | |||||
| Actuarial (gain) loss | 11 | 15 | |||||
| Gross benefits paid (a) | (34 | ) | (28 | ) | |||
| Benefit Obligation, end of period | 326 | 329 | |||||
| Change in Plan Assets | |||||||
| Plan assets at fair value, beginning of period | 318 | 297 | |||||
| Actual return on plan assets | 41 | 14 | |||||
| Employer contributions | — | 35 | |||||
| Gross benefits paid | (34 | ) | (28 | ) | |||
| Plan assets at fair value, end of period | 325 | 318 | |||||
| Funded Status, end of period | $ | (1 | ) | $ | (11 | ) | |
| Amounts recognized in the Balance Sheets consist of: | |||||||
| Noncurrent liability | $ | (1 | ) | $ | (11 | ) | |
| Net amount recognized, end of period | $ | (1 | ) | $ | (11 | ) | |
| Amounts recognized in regulatory assets (pre-tax) consist of: | |||||||
| Prior service cost | $ | 27 | $ | 25 | |||
| Net actuarial loss | 92 | 110 | |||||
| Total | $ | 119 | $ | 135 | |||
| Total accumulated benefit obligation for defined benefit pension plan | $ | 326 | $ | 329 | |||
| 2023 | 2022 | ||||||||||
| Pension | $ | (65) | $ | (34) | |||||||
| Other postretirement benefits | (55) | (60) | |||||||||
(LG&E)
Although LG&E does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE. LG&E is also allocated costs of defined benefitbenefits plans from LKS for defined benefit plans sponsored by LKE. See Note 14 for additional information on costs allocated to LG&E from LKS. These allocations are based on LG&E's participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of LG&E are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to LG&E resulted in liabilities at December 31 as follows:
| 2017 | 2016 | ||||||
| Pension | $ | 44 | $ | 42 | |||
| Other postretirement benefits | 74 | 76 | |||||
| 2023 | 2022 | ||||||||||
| Pension | $ | 34 | $ | 41 | |||||||
| Other postretirement benefits | (44) | (41) | |||||||||
| 2017 | 2016 | ||||||
| Pension | $ | 246 | $ | 281 | |||
| Other postretirement benefits | 62 | 72 | |||||
(KU)
Although KU does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE. KU is also allocated costs of defined benefit plans from LKS for defined benefit plans sponsored by LKE. See Note 14 for additional information on costs allocated to KU from LKS. These allocations are based on KU's participation in those plans, which management believes are reasonable. The actuarially determined obligations of current active employees and retired employees of KU are used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to KU resulted in liabilitiesassets/(liabilities) at December 31 as follows.
| 2017 | 2016 | 2023 | 2022 | ||||||||||||||||||
| Pension | $ | 36 | $ | 62 | |||||||||||||||||
| Other postretirement benefits | 32 | 40 | |||||||||||||||||||
Plan Assets - U.S. Pension Plans
All of PPL's primary legacy pension plan and thequalified pension plans sponsored by LKE are invested in the PPL Services Corporation Master Trust (the Master Trust) that also includes 401(h) accounts that are restricted for certain other postretirement benefit obligations of PPL, RIE and LKE. The investment strategy for the Master Trust is to achieve a risk-adjusted return on a mix of assets that, in combination with PPL's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments,
153
while also managing the duration of the assets to complement the duration of the liabilities. The Master Trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore has no significant concentration of risk.
The investment policy of the Master Trust outlines investment objectives and defines the responsibilities of the EBPB, external investment managers, investment advisor and trustee and custodian. The investment policy is reviewed annually by PPL's Board of Directors.
The EBPB created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios: growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return at a reasonable risk, including equity securities, certain debt securities and alternative investments. The immunizing portfolio consists of debt securities, generally with long durations, and derivative positions. The immunizing portfolio is designed to offset a portion of the change in the pension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of cash and cash equivalents.
Target allocation ranges have been developed for each portfolio based on input from external consultants with a goal of limiting funded status volatility. The EBPB monitors the investments in each portfolio and seeks to obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the EBPB establishes revised guidelines from time to time. EBPB investment guidelines as of the end of 20172023 are presented below.
The asset allocation for the trust and the target allocation by portfolio at December 31 are as follows:
| Percentage of trust assets | 2017 | |||||||
| 2017 (a) | 2016 | Target Asset Allocation (a) | ||||||
| Growth Portfolio | 56 | % | 52 | % | 55 | % | ||
| Equity securities | 32 | % | 30 | % | ||||
| Debt securities (b) | 14 | % | 12 | % | ||||
| Alternative investments | 10 | % | 10 | % | ||||
| Immunizing Portfolio | 43 | % | 46 | % | 43 | % | ||
| Debt securities (b) | 39 | % | 43 | % | ||||
| Derivatives | 4 | % | 3 | % | ||||
| Liquidity Portfolio | 1 | % | 2 | % | 2 | % | ||
| Total | 100 | % | 100 | % | 100 | % | ||
| Percentage of trust assets | 2023 | ||||||||||||||||
| 2023 | 2022 | Target Asset Allocation | |||||||||||||||
| Growth Portfolio | 54 | % | 55 | % | 55 | % | |||||||||||
| Equity securities | 31 | % | 31 | % | |||||||||||||
| Debt securities (a) | 12 | % | 13 | % | |||||||||||||
| Alternative investments | 11 | % | 11 | % | |||||||||||||
| Immunizing Portfolio | 43 | % | 43 | % | 43 | % | |||||||||||
| Debt securities (a) | 36 | % | 33 | % | |||||||||||||
| Derivatives (b) | 7 | % | 10 | % | |||||||||||||
| Liquidity Portfolio | 3 | % | 2 | % | 2 | % | |||||||||||
| Total | 100 | % | 100 | % | 100 | % | |||||||||||
(b)Includes posted collateral to support derivative instruments subject to counterparty risk.
The fair value of net assets in the Master Trust by asset class and level within the fair value hierarchy was:
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||||||||
| Fair Value Measurements Using | Fair Value Measurements Using | ||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| PPL Services Corporation Master Trust | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 301 | $ | 301 | $ | — | $ | — | $ | 181 | $ | 181 | $ | — | $ | — | |||||||||||||||
| Equity securities: | |||||||||||||||||||||||||||||||
| U.S. Equity | 229 | 229 | — | — | 152 | 152 | — | — | |||||||||||||||||||||||
| U.S. Equity fund measured at NAV (a) | 364 | — | — | — | 272 | — | — | — | |||||||||||||||||||||||
| International equity fund at NAV (a) | 538 | — | — | — | 551 | — | — | — | |||||||||||||||||||||||
| Commingled debt measured at NAV (a) | 611 | — | — | — | 546 | — | — | — | |||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2017 | December 31, 2016 | Fair Value Measurements Using | Fair Value Measurements Using | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value Measurements Using | Fair Value Measurements Using | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Services Corporation Master Trust | PPL Services Corporation Master Trust | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity securities: | Equity securities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Equity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Equity fund measured at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| International equity fund at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| International equity fund at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| International equity fund at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled debt measured at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities: | Debt securities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and U.S. government sponsored agency | 186 | 186 | — | — | 381 | 381 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate | 883 | — | 870 | 13 | 850 | — | 837 | 13 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | 10 | — | 10 | — | 8 | — | 8 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Alternative investments: | Alternative investments: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Real estate measured at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Real estate measured at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Real estate measured at NAV (a) | 109 | — | — | — | 102 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Private equity measured at NAV (a) | 80 | — | — | — | 80 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Private credit partnerships measured at NAV (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Hedge funds measured at NAV (a) | 175 | — | — | — | 167 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps and swaptions | 50 | — | 50 | — | 61 | — | 61 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | 1 | — | 1 | — | 3 | — | 3 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Insurance contracts | 24 | — | — | 24 | 27 | — | — | 27 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Services Corporation Master Trust assets, at fair value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL Services Corporation Master Trust assets, at fair value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPL Services Corporation Master Trust assets, at fair value | 3,561 | $ | 716 | $ | 931 | $ | 37 | 3,381 | $ | 714 | $ | 909 | $ | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Receivables and payables, net (b) | 72 | (15 | ) | Receivables and payables, net (b) | (16) | 67 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
401(h) accounts restricted for other postretirement benefit obligations | (145 | ) | (123 | ) | 401(h) accounts restricted for other postretirement benefit obligations | (124) | (126) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total PPL Services Corporation Master Trust pension assets | $ | 3,488 | $ | 3,243 | Total PPL Services Corporation Master Trust pension assets | $ | 3,175 | $ | 3,149 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)In accordance with accounting guidance, certain investments that are measured at fair value using the 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 statement of financial position.
(b)Receivables and payables, net represents amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received.
A reconciliation of the Master Trust assets classified as Level 3 at December 31, 20172023 is as follows:
Corporate debt | Insurance contracts | Total | |||||||||
| Balance at beginning of period | $ | 13 | $ | 27 | $ | 40 | |||||
| Actual return on plan assets | |||||||||||
| Relating to assets still held at the reporting date | — | 1 | 1 | ||||||||
| Purchases, sales and settlements | — | (4 | ) | (4 | ) | ||||||
| Balance at end of period | $ | 13 | $ | 24 | $ | 37 | |||||
| Corporate debt | |||||||||||||||||||||||
| Balance at beginning of period | $ | 16 | |||||||||||||||||||||
| Actual return on plan assets: | |||||||||||||||||||||||
| Relating to assets still held at the reporting date | (2) | ||||||||||||||||||||||
| Relating to assets sold during the period | 4 | ||||||||||||||||||||||
| Purchases, sales and settlements | (8) | ||||||||||||||||||||||
| Balance at end of period | $ | 10 | |||||||||||||||||||||
A reconciliation of the Master Trust assets classified as Level 3 at December 31, 20162022 is as follows:
Corporate debt | Insurance contracts | Total | |||||||||
| Balance at beginning of period | $ | 10 | $ | 32 | $ | 42 | |||||
| Actual return on plan assets | |||||||||||
| Relating to assets still held at the reporting date | — | 1 | 1 | ||||||||
| Purchases, sales and settlements | 3 | (6 | ) | (3 | ) | ||||||
| Balance at end of period | $ | 13 | $ | 27 | $ | 40 | |||||
| Corporate debt | |||||||||||||||||||||||
| Balance at beginning of period | $ | 20 | |||||||||||||||||||||
| Actual return on plan assets: | |||||||||||||||||||||||
| Relating to assets still held at the reporting date | (2) | ||||||||||||||||||||||
| Relating to assets sold during the period | 2 | ||||||||||||||||||||||
| Purchases, sales and settlements | (4) | ||||||||||||||||||||||
| Balance at end of period | $ | 16 | |||||||||||||||||||||
The fair value measurements of cash and cash equivalents are based on the amounts on deposit.
155
The market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and passively managed investments that are managed against various equity indices.
Investments in commingled equity and debt funds are categorized as equity securities. Investments in commingled equity funds include funds that invest in U.S. and international equity securities. Investments in commingled debt funds include funds that invest in a diversified portfolio of emerging market debt obligations, as well as funds that invest in investment grade long-duration fixed-income securities.
The fair value measurements of debt securities are generally based on evaluations that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. The fair value of debt securities is generally measured using a market approach, including the use of pricing models, which incorporate observable inputs. Common inputs include benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as payment data, future predicted cash flows, collateral performance and new issue data. For the Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by residential mortgages, auto loans, credit cards and other pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries; investments in debt securities issued by foreign governments and corporations.
Investments in real estate represent an investment in a partnership whose purpose is to manage investments in core U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The manager is focused on properties with high occupancy rates with quality tenants. This results in a focus on high income and stable cash flows with appreciation being a secondary factor. Core real estate generally has a lower degree of leverage when compared with more speculative real estate investing strategies. The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value.
Investments in private equity represent interests in partnerships in multiple early-stage venture capital funds and private equity fund of funds that use a number of diverse investment strategies. The partnerships have limited lives of at least 10 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. The Master Trust has unfunded commitments of $28 million that may be required during the lives of the partnerships. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.
Investments in private credit represent pools of actively managed loans that span capital structure and borrower type. Strategies carry different types and levels of risk. Returns from those strategies will vary in terms of yield, fees generated, loan loss rates and the pace of principal repayment. Investments have limited lives of approximately 2-8 years. The investment cannot be redeemed with the general partner; however, the interest may be sold to other parties, subject to the general partner’s approval. Fair value is based on an ownership interest in partners’ capital to which a proportionate share of net assets is attributed.
At December 31, 2023, the Master Trust had unfunded commitments of $85 million that may be required during the lives of the real estate, private equity and private credit partnerships.
Investments in hedge funds represent investments in a fund of hedge funds. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under most market conditions. Major investment strategies for the fund of hedge funds include long/short equity, tactical trading, event driven, and relative value. Shares may be redeemed withinwith 45 days prior written notice. The fund is subject to short term lockups and other restrictions. The fair value for the fund has been estimated using the net asset value per share.
The fair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard option valuation models and standard industry models. These securities primarily represent investments in treasury futures, total return swaps, interest rate swaps and swaptions (the option to enter into an interest rate swap), which are valued based on quoted prices, changes in the value of the underlying exposure or on the swap details, such as swap curves, notional amount, index and term of index, reset frequency, volatility and payer/receiver credit ratings.
156
Plan Assets - U.S. Other Postretirement Benefit Plans
The investment strategy with respect to other postretirement benefit obligations is to fund VEBA trusts and/or 401(h) accounts with voluntary contributions and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the Master Trust, other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers and, therefore, have no significant concentration of risk. Equity securities include investments in domestica large-cap commingled funds.fund and a global equity exchange-traded fund. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities, but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes. The asset allocation for the PPL VEBA trusts excluding LKE, and the target allocation, by asset class, at December 31 are detailed below.
| Percentage of plan assets | Target Asset Allocation | ||||||||||||||||
| 2023 | 2022 | 2023 | |||||||||||||||
| Asset Class | |||||||||||||||||
| Equity securities | 46 | % | 45 | % | 45 | % | |||||||||||
| Debt securities (a) | 48 | % | 48 | % | 49 | % | |||||||||||
| Cash and cash equivalents (b) | 6 | % | 7 | % | 6 | % | |||||||||||
| Total | 100 | % | 100 | % | 100 | % | |||||||||||
| Percentage of plan assets | Target Asset Allocation | |||||||
| 2017 | 2016 | 2017 | ||||||
| Asset Class | ||||||||
| U.S. Equity securities | 47 | % | 48 | % | 45 | % | ||
| Debt securities (a) | 49 | % | 50 | % | 50 | % | ||
| Cash and cash equivalents (b) | 4 | % | 2 | % | 5 | % | ||
| Total | 100 | % | 100 | % | 100 | % | ||
| (b)Includes |
The fair value of assets in the U.S. other postretirement benefit plans by asset class and level within the fair value hierarchy was:
| December 31, 2017 | December 31, 2016 | December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value Measurement Using | Fair Value Measurement Using | Fair Value Measurement Using | Fair Value Measurement Using | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Money market funds | $ | 10 | $ | 10 | $ | — | $ | — | $ | 5 | $ | 5 | $ | — | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Equity securities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity securities: | Equity securities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Large-cap equity fund measure at NAV (a) | 123 | — | — | — | 123 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled debt fund measured at NAV (a) | 96 | — | — | — | 114 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate bonds | 30 | — | 30 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipalities | — | — | — | — | 12 | — | 12 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Global equity exchange-traded fund | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term bond exchange-traded fund | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total VEBA trust assets, at fair value | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total VEBA trust assets, at fair value | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total VEBA trust assets, at fair value | 259 | $ | 10 | $ | 30 | $ | — | 254 | $ | 5 | $ | 12 | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Receivables and payables, net (b) | 1 | 1 | Receivables and payables, net (b) | (12) | (2) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 401(h) account assets | 145 | 123 | 401(h) account assets | 124 | 126 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total other postretirement benefit plan assets | $ | 405 | $ | 378 | Total other postretirement benefit plan assets | $ | 438 | $ | 417 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)In accordance with accounting guidance certain investments that are measured at fair value using the 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 statement of financial position.
(b)Receivables and payables represent amounts for investments sold/purchased but not yet settled along with interest and dividends earned but not yet received.
Investments in money market funds represent investments in funds that invest primarily in a diversified portfolio of investment grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The primary objective of the fund is a level of current income consistent with stability of principal and liquidity. Redemptions can be made daily on this fund.
Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Fair value measurements are not obtained from a quoted price in an active market but are based on firm quotes of net asset values per share as provided by the trustee of the fund. Redemptions can be made daily on this fund.
Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade long-duration fixed income securities. Redemptions can be made daily on these funds.
157
| Target Asset | ||||||||
| Percentage of plan assets | Allocation | |||||||
| 2017 | 2016 | 2017 | ||||||
| Asset Class | ||||||||
| Cash and cash equivalents | 2 | % | 1 | % | — | % | ||
| Equity securities | ||||||||
| U.K. | 2 | % | 3 | % | 2 | % | ||
| European (excluding the U.K.) | 1 | % | 2 | % | 1 | % | ||
| Asian-Pacific | 1 | % | 2 | % | 1 | % | ||
| North American | 1 | % | 3 | % | 1 | % | ||
| Emerging markets | 1 | % | 3 | % | 1 | % | ||
| Global equities | 16 | % | 6 | % | 10 | % | ||
| Global Tactical Asset Allocation | 33 | % | 33 | % | 41 | % | ||
| Debt securities (a) | 37 | % | 41 | % | 38 | % | ||
| Alternative investments | 6 | % | 6 | % | 5 | % | ||
| Total | 100 | % | 100 | % | 100 | % | ||
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||||||||
| Fair Value Measurement Using | Fair Value Measurement Using | ||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| Cash and cash equivalents | $ | 216 | $ | 216 | $ | — | $ | — | $ | 42 | $ | 42 | $ | — | $ | — | |||||||||||||||
| Equity securities measured at NAV (a) : | |||||||||||||||||||||||||||||||
| U.K. companies | 157 | — | — | — | 210 | — | — | — | |||||||||||||||||||||||
| European companies (excluding the U.K.) | 98 | — | — | — | 177 | — | — | — | |||||||||||||||||||||||
| Asian-Pacific companies | 60 | — | — | — | 140 | — | — | — | |||||||||||||||||||||||
| North American companies | 123 | — | — | — | 227 | — | — | — | |||||||||||||||||||||||
| Emerging markets companies | 62 | — | — | — | 209 | — | — | — | |||||||||||||||||||||||
| Global Equities | 1,335 | — | — | — | 466 | — | — | — | |||||||||||||||||||||||
| Other | 2,807 | — | — | — | 2,363 | — | — | — | |||||||||||||||||||||||
| Debt Securities: | |||||||||||||||||||||||||||||||
| U.K. corporate bonds | 3 | — | 3 | — | 2 | — | 2 | — | |||||||||||||||||||||||
| U.K. gilts | 3,137 | — | 3,137 | — | 2,940 | — | 2,940 | — | |||||||||||||||||||||||
| Alternative investments: | |||||||||||||||||||||||||||||||
| Real estate measured at NAV (a) | 492 | — | — | — | 435 | — | — | — | |||||||||||||||||||||||
| Fair value - U.K. pension plans | $ | 8,490 | $ | 216 | $ | 3,140 | $ | — | $ | 7,211 | $ | 42 | $ | 2,942 | $ | — | |||||||||||||||
Investments in global equity securities represent activelyexchange-traded fund represents a passively-managed pooled investment vehicle that invests in developed market equities and passively managed funds that are measured against various equity indices.
Investments in real estate represent holdings inlong-term bond exchange-traded fund represents a U.K. unitized fundpassively-managed pooled investment vehicle that owns and manages U.K. industrial and commercial real estate with a strategy of earning current rental income and achieving capital growth. The fair value measurementis designed to track the performance of the fund is based uponBloomberg U.S. Long Government/Credit Float Adjusted Index, which includes all medium and larger issues of U.S. Government, investment-grade corporate and investment-grade international dollar-denominated bonds that have maturities of greater than 10 years. Fair value measurements can be obtained from a net asset value per share, which is basedquoted price on the value of underlying properties that are independently appraised in accordance with Royal Institution of Chartered Surveyors valuation standards at least annually with quarterly valuation updates basedexchange. Redemptions can be made daily on recent sales of similar properties, leasing levels, property operations and/or market conditions. The fund may be subject to redemption restrictions in the unlikely event of a large forced sale in order to ensure other unit holders are not disadvantaged.this fund.
Expected Cash Flows - U.S. Defined Benefit Plans(PPL)
PPL sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets. PPL expects to make approximately $13$10 million of benefit payments under these plans in 2018.2024.
PPL is not required to make contributions to its other postretirement benefit plans but has historically funded these plans in amounts equal to the postretirement benefit costs recognized. Continuation of this past practice would cause PPL to contribute $14 million to its other postretirement benefit plans in 2018.2024.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the plans and the following federal subsidy payments are expected to be received by PPL.
| Other Postretirement | |||||||||||
| Pension | Benefit Payment | Expected Federal Subsidy | |||||||||
| 2018 | $ | 260 | $ | 51 | $ | 1 | |||||
| 2019 | 269 | 51 | — | ||||||||
| 2020 | 268 | 50 | 1 | ||||||||
| 2021 | 270 | 49 | — | ||||||||
| 2022 | 272 | 48 | — | ||||||||
| 2023-2027 | 1,328 | 218 | 2 | ||||||||
| Other Postretirement | |||||||||||||||||
| Pension | Benefit Payment | Expected Federal Subsidy | |||||||||||||||
| 2024 | $ | 299 | $ | 52 | $ | — | |||||||||||
| 2025 | 293 | 50 | — | ||||||||||||||
| 2026 | 290 | 49 | — | ||||||||||||||
| 2027 | 282 | 48 | — | ||||||||||||||
| 2028 | 277 | 47 | — | ||||||||||||||
| 2029-2033 | 1,322 | 216 | — | ||||||||||||||
| Other Postretirement | |||||||||||
| Pension | Benefit Payment | Expected Federal Subsidy | |||||||||
| 2018 | $ | 109 | $ | 14 | $ | — | |||||
| 2019 | 113 | 15 | — | ||||||||
| 2020 | 114 | 16 | 1 | ||||||||
| 2021 | 115 | 16 | — | ||||||||
| 2022 | 116 | 16 | — | ||||||||
| 2023-2027 | 573 | 79 | 2 | ||||||||
| Pension | |||
| 2018 | $ | 26 | |
| 2019 | 26 | ||
| 2020 | 26 | ||
| 2021 | 25 | ||
| 2022 | 24 | ||
| 2023-2027 | 104 | ||
| Pension | |||
| 2018 | $ | 343 | |
| 2019 | 349 | ||
| 2020 | 353 | ||
| 2021 | 356 | ||
| 2022 | 362 | ||
| 2023-2027 | 1,843 | ||
Savings Plans(All Registrants)
Substantially, all employees of PPL's subsidiaries are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were:
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL | $ | 48 | $ | 36 | $ | 29 | |||||||||||
| PPL Electric | 8 | 6 | 5 | ||||||||||||||
| LG&E | 8 | 7 | 7 | ||||||||||||||
| KU | 6 | 5 | 5 | ||||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| PPL | $ | 36 | $ | 35 | $ | 34 | |||||
| PPL Electric | 6 | 6 | 6 | ||||||||
| LKE | 18 | 17 | 16 | ||||||||
| LG&E | 5 | 5 | 5 | ||||||||
| KU | 4 | 4 | 4 | ||||||||
12. Jointly Owned Facilities
(PPL, LKE, LG&E and KU)
At December 31, 20172023 and 2016,2022, the Balance Sheets reflect the owned interests in the facilitiesgenerating plants listed below.
Ownership Interest | Electric Plant | Accumulated Depreciation | Construction Work in Progress | ||||||||||||
| PPL and LKE | |||||||||||||||
| December 31, 2017 | |||||||||||||||
| Generating Plants | |||||||||||||||
| Trimble County Unit 1 | 75.00 | % | $ | 427 | $ | 69 | $ | 1 | |||||||
| Trimble County Unit 2 | 75.00 | % | 1,032 | 176 | 198 | ||||||||||
| December 31, 2016 | |||||||||||||||
| Generating Plants | |||||||||||||||
| Trimble County Unit 1 | 75.00 | % | $ | 407 | $ | 55 | $ | 1 | |||||||
| Trimble County Unit 2 | 75.00 | % | 1,026 | 161 | 83 | ||||||||||
| LG&E | |||||||||||||||
| December 31, 2017 | |||||||||||||||
| Generating Plants | |||||||||||||||
| E.W. Brown Units 6-7 | 38.00 | % | $ | 41 | $ | 17 | $ | — | |||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 53.00 | % | 52 | 15 | — | ||||||||||
| Trimble County Unit 1 | 75.00 | % | 427 | 69 | 1 | ||||||||||
| Trimble County Unit 2 | 14.25 | % | 215 | 36 | 102 | ||||||||||
| Trimble County Units 5-6 | 29.00 | % | 32 | 9 | — | ||||||||||
| Trimble County Units 7-10 | 37.00 | % | 73 | 21 | — | ||||||||||
| Cane Run Unit 7 | 22.00 | % | 120 | 8 | 1 | ||||||||||
| E.W. Brown Solar Unit | 39.00 | % | 10 | 1 | — | ||||||||||
| December 31, 2016 | |||||||||||||||
| Generating Plants | |||||||||||||||
| E.W. Brown Units 6-7 | 38.00 | % | $ | 40 | $ | 15 | $ | — | |||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 53.00 | % | 55 | 12 | 1 | ||||||||||
| Trimble County Unit 1 | 75.00 | % | 407 | 55 | 1 | ||||||||||
| Trimble County Unit 2 | 14.25 | % | 214 | 32 | 43 | ||||||||||
| Trimble County Units 5-6 | 29.00 | % | 30 | 8 | 1 | ||||||||||
| Trimble County Units 7-10 | 37.00 | % | 71 | 17 | 1 | ||||||||||
| Cane Run Unit 7 | 22.00 | % | 114 | 5 | 2 | ||||||||||
| E.W. Brown Solar Unit | 39.00 | % | 10 | — | — | ||||||||||
| Ownership Interest | Electric Plant | Accumulated Depreciation | Construction Work in Progress | |||||||||||||||||||||||
| PPL | ||||||||||||||||||||||||||
| December 31, 2023 | ||||||||||||||||||||||||||
| Trimble County Unit 1 | 75.00 | % | $ | 464 | $ | 110 | $ | — | ||||||||||||||||||
| Trimble County Unit 2 | 75.00 | % | 1,490 | 300 | 49 | |||||||||||||||||||||
158
| Ownership Interest | Electric Plant | Accumulated Depreciation | Construction Work in Progress | |||||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||
| Trimble County Unit 1 | 75.00 | % | $ | 455 | $ | 94 | $ | 1 | ||||||||||||||||||
| Trimble County Unit 2 | 75.00 | % | 1,372 | 276 | 148 | |||||||||||||||||||||
| LG&E | ||||||||||||||||||||||||||
| December 31, 2023 | ||||||||||||||||||||||||||
| E.W. Brown Units 6-7 | 38.00 | % | $ | 53 | $ | 27 | $ | — | ||||||||||||||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 53.00 | % | 52 | 29 | — | |||||||||||||||||||||
| Trimble County Unit 1 | 75.00 | % | 464 | 110 | — | |||||||||||||||||||||
| Trimble County Unit 2 | 14.25 | % | 447 | 74 | 25 | |||||||||||||||||||||
| Trimble County Units 5-6 | 29.00 | % | 37 | 17 | — | |||||||||||||||||||||
| Trimble County Units 7-10 | 37.00 | % | 82 | 39 | — | |||||||||||||||||||||
| Cane Run Unit 7 | 22.00 | % | 127 | 25 | 3 | |||||||||||||||||||||
| E.W. Brown Solar Unit | 39.00 | % | 10 | 3 | — | |||||||||||||||||||||
| Solar Share | 44.00 | % | 3 | — | — | |||||||||||||||||||||
| Mercer Solar | 37.00 | % | 7 | — | — | |||||||||||||||||||||
| Mill Creek 5 | 31.00 | % | — | — | 2 | |||||||||||||||||||||
| Brown Wind | 36.00 | % | — | — | — | |||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||
| E.W. Brown Units 6-7 | 38.00 | % | $ | 53 | $ | 25 | $ | — | ||||||||||||||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 53.00 | % | 51 | 27 | — | |||||||||||||||||||||
| Trimble County Unit 1 | 75.00 | % | 455 | 94 | 1 | |||||||||||||||||||||
| Trimble County Unit 2 | 14.25 | % | 384 | 66 | 78 | |||||||||||||||||||||
| Trimble County Units 5-6 | 29.00 | % | 36 | 16 | — | |||||||||||||||||||||
| Trimble County Units 7-10 | 37.00 | % | 81 | 36 | — | |||||||||||||||||||||
| Cane Run Unit 7 | 22.00 | % | 126 | 21 | 2 | |||||||||||||||||||||
| E.W. Brown Solar Unit | 39.00 | % | 10 | 3 | — | |||||||||||||||||||||
| Solar Share | 44.00 | % | 3 | — | — | |||||||||||||||||||||
| KU | ||||||||||||||||||||||||||
| December 31, 2023 | ||||||||||||||||||||||||||
| E.W. Brown Units 6-7 | 62.00 | % | $ | 87 | $ | 45 | $ | — | ||||||||||||||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 47.00 | % | 46 | 25 | — | |||||||||||||||||||||
| Trimble County Unit 2 | 60.75 | % | 1,043 | 227 | 24 | |||||||||||||||||||||
| Trimble County Units 5-6 | 71.00 | % | 86 | 41 | — | |||||||||||||||||||||
| Trimble County Units 7-10 | 63.00 | % | 135 | 65 | — | |||||||||||||||||||||
| Cane Run Unit 7 | 78.00 | % | 449 | 90 | 10 | |||||||||||||||||||||
| E.W. Brown Solar Unit | 61.00 | % | 16 | 5 | — | |||||||||||||||||||||
| Solar Share | 56.00 | % | 4 | — | — | |||||||||||||||||||||
| Mercer Solar | 63.00 | % | 12 | — | 1 | |||||||||||||||||||||
| Mill Creek 5 | 69.00 | % | — | — | 3 | |||||||||||||||||||||
| Brown Wind | 64.00 | % | 1 | — | — | |||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||
| E.W. Brown Units 6-7 | 62.00 | % | $ | 87 | $ | 42 | $ | — | ||||||||||||||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 47.00 | % | 45 | 23 | — | |||||||||||||||||||||
| Trimble County Unit 2 | 60.75 | % | 987 | 210 | 70 | |||||||||||||||||||||
| Trimble County Units 5-6 | 71.00 | % | 84 | 38 | — | |||||||||||||||||||||
| Trimble County Units 7-10 | 63.00 | % | 133 | 61 | — | |||||||||||||||||||||
| Cane Run Unit 7 | 78.00 | % | 446 | 77 | 6 | |||||||||||||||||||||
| E.W. Brown Solar Unit | 61.00 | % | 16 | 5 | — | |||||||||||||||||||||
| Solar Share | 56.00 | % | 4 | — | — | |||||||||||||||||||||
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Ownership Interest | Electric Plant | Accumulated Depreciation | Construction Work in Progress | ||||||||||||
| KU | |||||||||||||||
| December 31, 2017 | |||||||||||||||
| Generating Plants | |||||||||||||||
| E.W. Brown Units 6-7 | 62.00 | % | $ | 66 | $ | 27 | $ | — | |||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 47.00 | % | 46 | 13 | — | ||||||||||
| Trimble County Unit 2 | 60.75 | % | 817 | 140 | 96 | ||||||||||
| Trimble County Units 5-6 | 71.00 | % | 76 | 20 | — | ||||||||||
| Trimble County Units 7-10 | 63.00 | % | 120 | 34 | — | ||||||||||
| Cane Run Unit 7 | 78.00 | % | 431 | 31 | 4 | ||||||||||
| E.W. Brown Solar Unit | 61.00 | % | 16 | 1 | — | ||||||||||
| December 31, 2016 | |||||||||||||||
| Generating Plants | |||||||||||||||
| E.W. Brown Units 6-7 | 62.00 | % | $ | 65 | $ | 23 | $ | — | |||||||
| Paddy's Run Unit 13 & E.W. Brown Unit 5 | 47.00 | % | 50 | 11 | 1 | ||||||||||
| Trimble County Unit 2 | 60.75 | % | 812 | 129 | 40 | ||||||||||
| Trimble County Units 5-6 | 71.00 | % | 74 | 19 | — | ||||||||||
| Trimble County Units 7-10 | 63.00 | % | 121 | 29 | 1 | ||||||||||
| Cane Run Unit 7 | 78.00 | % | 412 | 18 | 4 | ||||||||||
| E.W. Brown Solar Unit | 61.00 | % | 15 | — | — | ||||||||||
Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs associated with the plants is included in the corresponding operating expenses on the Statements of Income.
13. Commitments and Contingencies
Energy Purchase Commitments
(PPL, LKE, LG&E and KU)
LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's retail natural gas supply operations. These contracts include the following commitments:
| Contract Type | Maximum Maturity Date | ||||
| Natural Gas Fuel | |||||
| Natural Gas Retail Supply | |||||
| Coal | |||||
| Coal Transportation and Fleeting Services | |||||
| Natural Gas Transportation | |||||
LG&E and KU have a power purchase agreementPPA with OVEC expiring in June 2040. See footnote (f)(e) to the table in "Guarantees and Other Assurances" below for information on the OVEC power purchase contract, including recent developments in credit or debt conditions relating to OVEC.contract. Future obligations for power purchases from OVEC are unconditional demand payments, comprised of debt-service payments and contractually-required reimbursements of plant operating, maintenance and other expenses, and are projected as follows:
| LG&E | KU | Total | |||||||||||||||
| 2024 | $ | 26 | $ | 12 | $ | 38 | |||||||||||
| 2025 | 24 | 11 | 35 | ||||||||||||||
| 2026 | 24 | 11 | 35 | ||||||||||||||
| 2027 | 25 | 11 | 36 | ||||||||||||||
| 2028 | 22 | 10 | 32 | ||||||||||||||
| Thereafter | 175 | 77 | 252 | ||||||||||||||
| Total | $ | 296 | $ | 132 | $ | 428 | |||||||||||
| LG&E | KU | Total | |||||||||
| 2018 | $ | 20 | $ | 9 | $ | 29 | |||||
| 2019 | 19 | 8 | 27 | ||||||||
| 2020 | 18 | 8 | 26 | ||||||||
| 2021 | 19 | 8 | 27 | ||||||||
| 2022 | 19 | 8 | 27 | ||||||||
| Thereafter | 316 | 141 | 457 | ||||||||
| Total | $ | 411 | $ | 182 | $ | 593 | |||||
LG&E and KU had total energy purchases under the OVEC power purchase agreementPPA for the years ended December 31 as follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| LG&E | $ | 20 | $ | 21 | $ | 13 | |||||||||||
| KU | 9 | 9 | 6 | ||||||||||||||
| Total | $ | 29 | $ | 30 | $ | 19 | |||||||||||
(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 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 | 2025 | ||||
| Gas-related | Beyond 2029 | ||||
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| 2017 | 2016 | 2015 | |||||||||
| LG&E | $ | 14 | $ | 16 | $ | 15 | |||||
| KU | 6 | 7 | 7 | ||||||||
| Total | $ | 20 | $ | 23 | $ | 22 | |||||
| Total | 2024 | 2025-2026 | 2027-2028 | Thereafter | |||||||||||||||||||||||||
| Energy Purchase Obligations | $ | 1,087 | $ | 425 | $ | 196 | $ | 97 | $ | 369 | |||||||||||||||||||
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 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 six clean energy long-term contracts pursuant to the Rhode Island Long-Term Contracting Standard (LTCS) of which 36.427 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 PPA with Deep Water Wind Rev I, LLC (Revolution Wind), with an expected nameplate capacity of 408 MW expected to be operational in 2026; 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 contracting capacity has been secured. The RIPUC-approved solicitations currently in service include: (i) a 15-year PPA with Orbit Energy Rhode Island, LLC for a 3.2 MW nameplate 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 nameplate run-of-river hydroelectric plant located in Orono, Maine, placed in service in 2013, (iii) a 15-year PPA with Copenhagen Wind Farm, LLC for an 80 MW nameplate land-based wind project located in Denmark, New York, placed in service in 2018, and (iv) a 15-year PPA with Rhode Island LFG Genco, LLC for a 32.1 MW nameplate combined cycle combustion turbine generating facility fueled by a landfill gas project located in Johnston, Rhode Island, placed in service in 2013. On December 29, 2023, RIE filed an RFP with the RIPUC for approval under LTCS to backfill approximately 17.2 MW of renewable contracting capacity resulting from a terminated PPA to fulfill the required 90 MW under LTCS.
In addition to the LTCS, in October 2023, RIE issued a request for proposals (RFP) for 300 MW to approximately 1,200 MW of newly developed offshore wind energy projects, under the Affordable Clean Energy Security Act (ACES), as amended in 2022. Based on the RFP schedule, RIE anticipates beginning conditional project selection in June 2024. RIE must negotiate in good faith to achieve a commercially reasonable contract and may file such contract with the RIPUC for approval in December 2024, unless RIE shows that the bids are unlikely to lead to a contract that meets all of the statutory and RFP 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 prior to January 1, 2022, pursuant to LTCS as amended in 2022, and that have achieved commercial operation. For long-term contracts approved pursuant to LTCS or ACES, both 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 LTCS or ACES on or after January 1, 2027, RIE is not entitled to any financial remuneration, unless otherwise granted by the RIPUC. Also, the 2022 amendments to LTCS and 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.
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Talen Litigation
Background (PPL)
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 LKE)
In December 2013, six residents,October 2018, Talen Montana Retirement Plan and Talen Energy Marketing, LLC filed a putative class action complaint on behalf of themselvescurrent and others similarly situated,contingent creditors of Talen Montana (the Montana Action) who allegedly suffered harm or allegedly will suffer reasonably foreseeable harm as a result of, among other things, the November 2014 allegedly fraudulent transfer of $900 million of proceeds from the sale of then-PPL Montana's hydroelectric generating facilities.
In November 2018, PPL, certain PPL affiliates, and certain current and former officers and directors filed a class action complaint in the Court of Chancery of the State of Delaware seeking various forms of relief against LG&ERiverstone, Talen Energy and certain of their affiliates (the Delaware Action), in response to the Montana Action and as part of the defense strategy.
Talen Energy Supply, LLC et al. andTalen 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 U.S. DistrictBankruptcy Court for the WesternSouthern District of Kentucky alleging violationsTexas (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 sought the recovery of an allegedly fraudulent transfer relating to PPL Montana’s November 2014 sale of hydroelectric assets to Northwestern and subsequent distribution of approximately $900 million of proceeds from that sale, reiterating claims that the parties had already been litigating in Montana and Delaware.
Both the Montana Action and the Delaware Action were transferred to and consolidated in the Texas Bankruptcy Court. PPL filed its Answer and asserted a Counterclaim against the Talen and Riverstone entities, similar to the claims previously asserted in the Delaware Action, and filed a motion for partial summary judgment that was heard on October 31, 2022. Mediation occurred on February 22, 2023 before Judge David R. Jones of the Clean Air Act, RCRA,Texas Bankruptcy Court. The parties were not able to settle the case at that time. On June 14, 2023, the Texas Bankruptcy Court entered an Order denying PPL's motion for partial summary judgment.
A hearing on Riverstone’s motion for summary judgment occurred on August 24, 2023. The court ordered supplemental briefings from each party following the hearing. Defendants filed a second partial motion for summary judgment based on a safe harbor provision in the bankruptcy code on September 29, 2023. On December 22, 2023, PPL announced that it entered into a settlement agreement (Settlement Agreement) with Talen Montana, LLC and common lawaffiliated entities (Talen) to resolve all claims of nuisance, trespass and negligence. These plaintiffs seek injunctive relief and civil penalties, plus costs and attorney fees,made by Talen in Talen Montana, LLC et al. v. PPL Corp. et al, Adv. No 22-09001 pending before the U.S. Bankruptcy Court for the alleged statutory violations.Southern District of Texas and arising out of the June 2015 spinoff of PPL Energy Supply, which was renamed Talen. Under the common law claims, these plaintiffs seek monetary compensation and punitive damages for property damage and diminished property values for a class consisting of residents within four milesterms of the Cane Run plant. In their individual capacities, these plaintiffs sought compensation for alleged adverse health effects. In July 2014, the courtSettlement Agreement, PPL paid Talen $115 million and Talen dismissed the RCRAall claims against PPL. Separately, PPL and all but one Clean Air Act claim, but declinedRiverstone mutually agreed to dismiss the common law tort claims. In November 2016, the plaintiffs filed an amended complaint removing the personal injuryall remaining claims and removing certain previously named plaintiffs. In February 2017, the District Court issued an order dismissing PPL asin a defendant and dismissing the final federal claim against LG&E. On April 13, 2017, the federal District Court issued an order declining to exercise supplemental jurisdiction on the state law claims and dismissed the casesettlement in its entirety. On June 16, 2017, the plaintiffs filed a class action complaint in Jefferson Circuit Court, Kentucky, against LG&E alleging state law nuisance, negligence and trespass tort claims. The plaintiffs seek compensatory and punitive damages for alleged property damage due to purported plant emissions on behalf of a class of residents within one to three miles of the plant. Proceedings are currently underway regarding potential class certification, for which a decision may occur in late 2018 or in 2019. PPL, LKE and LG&E cannot predict the outcome of this matter. LG&E retired one coal-fired unit at the Cane Run plant in March 2015 and the remaining two coal-fired units at the plant in June 2015.
January 2024. This matter is now concluded.
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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. On June 27, 2022, the RIPUC opened a new docket (RIPUC Docket No. 22-05-EE) to investigate RIE’s actions and KU)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. The Rhode Island Attorney General and National Grid USA intervened in the docket.
On January 19, 2023, the Rhode Island Division of Public Utilities and Carriers (the Division) filed a motion to dismiss RIPUC Docket No. 22-05-EE without prejudice. As grounds for its motion, the Division stated that sufficient evidence exists in the docket to warrant an independent summary investigation by the Division, to include an audit of RIE, pursuant to Rhode Island General Laws Section 39-4-13. If the Division finds sufficient grounds, the Division may proceed to a formal hearing regarding the matters under investigation pursuant to Rhode Island General Laws Sections 39-4-14 and 39-4-15. Upon the conclusion of its investigation, the Division will provide the RIPUC with a report outlining the Division’s findings and final decision. On January 30, 2023, the Rhode Island Attorney General filed an objection to the Division’s motion to dismiss; RIE and National Grid each filed responses with the RIPUC requesting that any additional action taken by the RIPUC or the Division be considered after National Grid completes its internal investigation report, which National Grid filed with the RIPUC on March 10, 2023. On February 24, 2023, the Division initiated the independent summary investigation that it had referenced in its motion to dismiss. The RIPUC held a hearing on March 28, 2023 to hear oral arguments regarding the Division’s motion to dismiss and subsequently denied the motion. On November 27, 2023, the Division filed testimony recommending the RIPUC disallow a portion of the performance incentive awarded from 2012 through 2021, an amount of approximately $13 million, including interest. On January 19, 2024, the Division and the Rhode Island Attorney General filed their respective briefs recommending that the RIPUC assess financial penalties on the Company. The Division also recommended that the RIPUC consider further regulatory investigations and analysis within each of the energy efficiency dockets from 2012 through 2020, to confirm the accuracy of claimed savings and to document all conduct and actions that would trigger penalties pursuant to R.I. Gen. Laws §§ 39-2-8 and 39-1-22. This proceeding remains open and, in parallel, the Division’s summary investigation remains ongoing. 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 by RIE in connection with this matter or the Division’s summary investigation. RIE does not expect this matter will have a material adverse effect on its results of operations, financial position or cash flows.
E.W. Brown Environmental ClaimsAssessment(PPL and KU)
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 "zero 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
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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. In October 2020, the EPA published final revisions to its best available technology standards for certain wastewaters and potential extensions to compliance dates (the Reconsideration Rule). In March 2023, the EPA released a proposed rule that would modify the 2020 ELG revisions. The proposed rule would increase the stringency of previous control technology and zero discharge requirements, revise certain exemptions for generating units planned for retirement, and require case-by-case limitations for legacy wastewaters based on the best professional judgment of the state regulators. Compliance with the Reconsideration Rule is required during the pendency of the rulemaking process. The proposed rule is currently under evaluation, but could potentially result in significant operational changes and additional controls for LG&E and KU plants. The ELGs are 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.
CCRs
In 2015, the EPA issued a final order upholding the permit,rule governing management of CCRs which was subsequently appealed by the environmental groups. In September 2013, the Franklin Circuit Court reversed the KEEC orderinclude fly ash, bottom ash and remanded the permitsulfur 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 agency for further proceedings. LG&E and the KEEC appealed the order to the Kentucky Courtbeneficial use of Appeals.CCRs. In July 2015,2018, 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 upheldvacated and remanded portions of the lowerCCR Rule. In December 2019, the EPA addressed certain deficiencies identified by the court ruling. LG&E and proposed amendments to change the KEEC movedclosure deadline. In August 2020, the EPA published a final rule extending the deadline to initiate closure to April 11, 2021, while providing for discretionarycertain extensions. The EPA is conducting ongoing rulemaking actions regarding various other amendments to the rule including potentially making the rule applicable to certain inactive impoundments and landfills not currently subject to the rule. Certain ongoing legal challenges to various provisions of the CCR Rule have been held in abeyance pending review by the Kentucky Supreme Court. In February 2016, the Kentucky Supreme Court issued an order granting discretionary review and oral arguments were held in September 2016. On April 27, 2017, the Kentucky Supreme Court issued an order reversing the decision of the appellate court and upholding the permit issued to LG&E by the KEEC.
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 projectclosure 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 federal laws.KU have completed planned closure measures at most of the subject impoundments and have commenced post closure
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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 19 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)
The Registrants 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, Rhode Island and Kentucky previously owned or operated by, or currently owned by predecessors or affiliates of, PPL subsidiaries.
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, 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.
(PPL and PPL Electric)
PPL Electric is a potentially responsible party for a share of clean-up costs at certain sites. 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.
At December 31, 2023 and December 31, 2022, PPL Electric had a recorded liability of $8 million and $11 million, representing its best estimate of the probable loss incurred to remediate these sites.
(PPL)
RIE is a potentially responsible party for a share of clean-up costs at certain sites including 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 RIE facilities. RIE is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with governmental agencies, the costs of which have not been and are not expected to be significant to PPL.
At December 31, 2023 and December 31, 2022, RIE had a recorded liability of $99 million and $100 million, representing its best estimate of the remaining costs of environmental remediation activities. These undiscounted costs are expected to be incurred over approximately 30 years and generally to be subject to rate recovery. 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. RIE has recovered amounts from certain insurers and potentially responsible parties, and, where appropriate, 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 provide 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 RIE's Environmental Response Fund, established with RIPUC approval in March 2000 to address such costs, along with interest and any recoveries from insurance carriers and other third-parties. In addition, RIE recovers approximately $1 million annually for gas operations under a distribution adjustment charge in which
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the qualified remediation costs are amortized over 10 years. See Note 7 for additional information on RIE's recorded environmental regulatory assets and liabilities.
Regulatory Issues
See Note 67 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 KURIE 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 (including RFC or SERC) 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 cannotan estimate aor range of reasonably possible losses if any.cannot be determined.
Gas - Security Directives(PPL LKE,and LG&E and KU)&E)
In December 2015, 195 nations, includingMay and July of 2021, the U.S., signed the Paris Agreement on Climate, which establishes a comprehensive framework for the reductionDepartment of GHG emissions from both developed and developing nations. Although the agreement does not establish binding reduction requirements, it requires each nation to prepare, communicate, and maintain GHG reduction commitments. Reductions can be achieved in a variety of ways, including energy conservation, power plant efficiency improvements, reduced utilization of coal-fired generation or replacing coal-fired generation with natural gas or renewable generation. Based on the EPA's rules issued in 2015 imposing GHG emission standards for both new and existing power plants, the U.S. committed to an initial reduction target of 26% to 28% below 2005 levels by 2025. However, on June 1, 2017, President Trump announced a plan to withdraw from the Paris Agreement and undertake negotiations to reenter the current agreement or enter a new agreement on terms more favorable to the U.S. Under the terms of the Paris Agreement, any U.S. withdrawal would not be complete until November 2020.
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. SuchExamples of 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 securitiesobligations of PPL Capital Funding.
(All Registrants)
The table below details guarantees provided as of December 31, 2017.2023. "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee. The Registrants believe the probability of expected payment/performance under each of these guarantees is remote, except for "WPD guaranteethe guarantees and indemnifications related
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to the sale of unconsolidated entities" and "IndemnificationSafari Holdings, which PPL believes are reasonably possible but not probable of lease termination and other divestitures." The total recorded liability at December 31, 2017 was $17 million for PPL and $11 million for LKE. The $11 million recorded at LKE represents the settlement amount related to WKE's excess power matter. See footnote (e) for additional information. The total recorded liability at December 31, 2016 was $22 million for PPL and $17 million for LKE. occurring.For reporting purposes, on a consolidated basis, allthe guarantees of PPL Electric, LKE,include the guarantees of its subsidiary Registrants.
| Exposure at December 31, 2023 | Expiration Date | ||||||||||
| PPL | |||||||||||
| Indemnifications related to certain tax liabilities related to the sale of the U.K. utility business | £ | 50 | (a) | 2028 | |||||||
| PPL guarantee of Safari payment obligations under certain sale/leaseback financing transactions related to the sale of Safari Holdings | $ | 124 | (b) | 2028 | |||||||
| PPL guarantee of Safari payment obligations under certain PPAs related to the sale of Safari Holdings | 33 | (c) | |||||||||
| Indemnifications for losses suffered related to items not covered by Aspen Power's representation and warranty insurance associated with the sale of Safari Holdings | 140 | (d) | Various | ||||||||
| LG&E and KU | |||||||||||
| LG&E and KU obligation of shortfall related to OVEC | (e) | ||||||||||
(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)PPL guaranteed the payment obligations of Safari under certain sale/leaseback financing transactions executed by Safari. These guarantees will remain in place until Safari exercises its option to buy-out the projects under the sale/leaseback financings by the year 2028. Safari will indemnify PPL for any payments made by PPL or claims against PPL under the sale/leaseback transaction guarantees up to $25 million.
(c)PPL guaranteed the payment obligations of Safari under certain PPAs executed by Safari. PPL's guarantee was terminated on January 8, 2024.
(d)Aspen Power has obtained representation and warranty insurance, therefore, PPL generally has no liability for its representations and warranties under the agreement except for losses suffered related to items not covered. Expiration of these indemnifications range from 18 months to 6 years from the date of the closing of the transaction, and PPL’s aggregate liability for these claims will not exceed $140 million subject to certain adjustments plus the support obligations provided by PPL under sale-leaseback financings and PPAs that will be replaced by Aspen Power. PPL's support obligations related to the PPAs were replaced by Aspen Power and terminated on January 8, 2024.
(e)Pursuant to the OVEC power purchase contract, LG&E and KU also applyare obligated to PPL,pay for their share of OVEC's excess debt service, post-retirement and all guaranteesdecommissioning 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 $87 million at December 31, 2023, consisting of LG&E&E's share of $60 million and KU also apply to LKE.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" above for additional information on the OVEC power purchase contract.
| Exposure at December 31, 2017 | Expiration Date | ||||
| PPL | |||||
| Indemnifications related to the WPD Midlands acquisition | (a) | ||||
| WPD indemnifications for entities in liquidation and sales of assets | $ | 11 | (b) | 2020 | |
| WPD guarantee of pension and other obligations of unconsolidated entities | 95 | (c) | |||
| PPL Electric | |||||
| Guarantee of inventory value | 16 | (d) | 2018 | ||
| LKE | |||||
| Indemnification of lease termination and other divestitures | 201 | (e) | 2021-2023 | ||
| LG&E and KU | |||||
| LG&E and KU guarantee of shortfall related to OVEC | (f) | ||||
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 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.
14. Related Party Transactions
Wholesale Sales and Purchases(LG&E and KU)
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail customers. When LG&E has excess generation capacity after serving its own retail customers and its generation cost is lower than that of KU, KU purchases electricity from LG&E and vice versa. These transactions are reflected in the Statements of Income as "Electric revenue from affiliate" and "Energy purchases from affiliate" and are recorded at a price equal to the seller's fuel cost plus any split savings. Savings realized from such intercompany transactions are shared equally between both companies. The volume of energy each company has to sell to the other is dependent on its retail customers' needs and its available generation.
Support Costs(PPL Electric, LKE, LG&E and KU)
PPL Services, PPL EU Services and LKS provide and, prior to its merger into PPL Services on December 31, 2021, PPL Electric and LKE,EU Services provided the Registrants, their respective subsidiaries including LG&E and KU, and each other with administrative, management and support services. For all serviceservices companies, the costs of thesedirectly 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 and LKS use a three-factor methodology that includes the
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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.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, PPL EU Services and LKS charged the following amounts for the years ended December 31, 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.
| 2023 | 2022 | 2021 | |||||||||||||||
| PPL Electric from PPL Services | $ | 222 | $ | 241 | $ | 54 | |||||||||||
| PPL Electric from PPL EU Services | — | — | 222 | ||||||||||||||
| LG&E from LKS | 115 | 153 | 169 | ||||||||||||||
| LG&E from PPL Services | 42 | 13 | 3 | ||||||||||||||
| KU from LKS | 150 | 171 | 179 | ||||||||||||||
| KU from PPL Services | 48 | 14 | 3 | ||||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| PPL Electric from PPL Services | $ | 182 | $ | 132 | $ | 125 | |||||
| LKE from PPL Services | 20 | 18 | 16 | ||||||||
| PPL Electric from PPL EU Services | 64 | 69 | 60 | ||||||||
| LG&E from LKS | 169 | 178 | 155 | ||||||||
| KU from LKS | 190 | 194 | 185 | ||||||||
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 LKEPPL and LG&E and KU are reimbursed through LKS.
Intercompany Borrowings
(PPL Electric)
(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 $500 millionthe difference between LG&E's FERC borrowing limit and LG&E's commercial paper limit at an interest rate based on the lower of a market index of commercial paper issues. No balances were outstanding atissues and two additional rate options based on SOFR. At December 31, 2017 and 2016. Interest expense incurred on the2023, LG&E's money pool agreement withunused capacity was $750 million. At December 31, 2023 and 2022, LG&E's borrowings outstanding from KU wasand/or LKE were not significant for 2017 or 2016. There was no money pool activity with KU in 2015.significant.
KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to $500 millionthe difference between KU's FERC borrowing limit and KU's commercial paper limit at an interest rate based on the lower of a market index of commercial paper issues. No balances were outstanding atissues and two additional rate options based on SOFR. At December 31, 2017 and 2016. Interest income incurred on the2023, KU's money pool agreement withunused capacity was $557 million. At December 31, 2023 and 2022, KU's borrowings outstanding from LG&E wasand/or LKE were not significant for 2017 and 2016. There was no money pool activity with LG&E in 2015.significant.
See Note 1 for discussions regarding the intercompany tax sharing agreement (for PPL Electric, LKE, LG&E and KU) and intercompany allocations of stock-based compensation expense (for PPL Electric and LKE)Electric). For PPL Electric, LG&E and KU, see Note 11 for discussions regarding intercompany allocations associated with defined benefits.
15. Other Income (Expense) - net
(PPL)
The breakdowncomponents of "Other Income (Expense) - net" for the years ended December 31, was:
were:
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| 2023 | 2022 | 2021 | |||||||||||||||
| Defined benefit plans - non-service credits (Note 11) | $ | 40 | $ | 47 | $ | 21 | |||||||||||
| Interest income | 32 | 4 | 12 | ||||||||||||||
| AFUDC - equity component | 30 | 22 | 18 | ||||||||||||||
| Charitable contributions | (5) | (14) | (14) | ||||||||||||||
| Talen litigation (a) | (124) | 1 | (41) | ||||||||||||||
| Miscellaneous | (13) | (6) | 19 | ||||||||||||||
| Other Income (Expense) - net | $ | (40) | $ | 54 | $ | 15 | |||||||||||
(a)The costs for the year ended December 31, 2023 primarily relate to the settlement of the litigation. See "Legal Matters - Talen Litigation" in Note 13 for additional information.
| 2017 | 2016 | 2015 | |||||||||
| Other Income | |||||||||||
| Economic foreign currency exchange contracts (Note 17) | $ | (261 | ) | $ | 384 | $ | 122 | ||||
| Interest income | 2 | 3 | 4 | ||||||||
| AFUDC - equity component | 16 | 19 | 14 | ||||||||
| Miscellaneous | 17 | 6 | 6 | ||||||||
| Total Other Income | (226 | ) | 412 | 146 | |||||||
| Other Expense | |||||||||||
| Charitable contributions | 8 | 9 | 21 | ||||||||
| Miscellaneous | 21 | 13 | 17 | ||||||||
| Total Other Expense | 29 | 22 | 38 | ||||||||
| Other Income (Expense) - net | $ | (255 | ) | $ | 390 | $ | 108 | ||||
(PPL Electric)
The components of "Other Income (Expense) - net" for the years ended December 31, were:
| 2023 | 2022 | 2021 | |||||||||||||||
| Defined benefit plans - non-service credits (Note 11) | $ | 20 | $ | 15 | $ | 9 | |||||||||||
| Interest income | 8 | 3 | — | ||||||||||||||
| AFUDC - equity component | 16 | 16 | 18 | ||||||||||||||
| Charitable contributions | (3) | (3) | (3) | ||||||||||||||
| Miscellaneous | (2) | (1) | (3) | ||||||||||||||
| Other Income (Expense) - net | $ | 39 | $ | 30 | $ | 21 | |||||||||||
16. 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. Transfers between levels are recognized at end-of-reporting-period values. During 2017 and 2016, there were no transfers between Level 1 and Level 2. See Note 1 for information on the levels in the fair value hierarchy.
Recurring Fair Value Measurements
The assets and liabilities measured at fair value were:
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 485 | $ | 485 | $ | — | $ | — | $ | 341 | $ | 341 | $ | — | $ | — | |||||||||||||||
| Restricted cash and cash equivalents (a) | 26 | 26 | — | — | 26 | 26 | — | — | |||||||||||||||||||||||
| Price risk management assets (b): | |||||||||||||||||||||||||||||||
| Foreign currency contracts | 163 | — | 163 | — | 211 | — | 211 | — | |||||||||||||||||||||||
| Cross-currency swaps | 101 | — | 101 | — | 188 | — | 188 | — | |||||||||||||||||||||||
| Total price risk management assets | 264 | — | 264 | — | 399 | — | 399 | — | |||||||||||||||||||||||
| Total assets | $ | 775 | $ | 511 | $ | 264 | $ | — | $ | 766 | $ | 367 | $ | 399 | $ | — | |||||||||||||||
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 331 | $ | 331 | $ | — | $ | — | $ | 356 | $ | 356 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Restricted cash and cash equivalents (a) | 51 | 51 | — | — | 1 | 1 | — | — | |||||||||||||||||||||||||||||||||||||||
| Total Cash, Cash Equivalents and Restricted Cash (b) | 382 | 382 | — | — | 357 | 357 | — | — | |||||||||||||||||||||||||||||||||||||||
| Special use funds (a): | |||||||||||||||||||||||||||||||||||||||||||||||
| Money market fund | 1 | 1 | — | — | 1 | 1 | — | — | |||||||||||||||||||||||||||||||||||||||
| Commingled debt fund measured at NAV (c) | 9 | — | — | — | 13 | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Commingled equity fund measured at NAV (c) | 8 | — | — | — | 11 | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Total special use funds | 18 | 1 | — | — | 25 | 1 | — | — | |||||||||||||||||||||||||||||||||||||||
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| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||
| Price risk management assets (d): | |||||||||||||||||||||||||||||||||||||||||||||||
| Gas contracts | 1 | — | 1 | — | 25 | — | 25 | — | |||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 401 | $ | 383 | $ | 1 | $ | — | $ | 407 | $ | 358 | $ | 25 | $ | — | |||||||||||||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||
| Price risk management liabilities (d): | |||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | $ | 7 | $ | — | $ | 7 | $ | — | $ | 7 | $ | — | $ | 7 | $ | — | |||||||||||||||||||||||||||||||
| Gas contracts | 60 | — | 41 | 19 | 66 | — | 10 | 56 | |||||||||||||||||||||||||||||||||||||||
| Total price risk management liabilities | $ | 67 | $ | — | $ | 48 | $ | 19 | $ | 73 | $ | — | $ | 17 | $ | 56 | |||||||||||||||||||||||||||||||
| PPL Electric | |||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 51 | $ | 51 | $ | — | $ | — | $ | 25 | $ | 25 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Total assets | $ | 51 | $ | 51 | $ | — | $ | — | $ | 25 | $ | 25 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 18 | $ | 18 | $ | — | $ | — | $ | 93 | $ | 93 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Restricted cash and cash equivalents (a) | 26 | 26 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Total Cash, Cash Equivalents and Restricted Cash (b) | 44 | 44 | — | — | 93 | 93 | — | — | |||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 44 | $ | 44 | $ | — | $ | — | $ | 93 | $ | 93 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||
| Price risk management liabilities: | |||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | $ | 7 | $ | — | $ | 7 | $ | — | $ | 7 | $ | — | $ | 7 | $ | — | |||||||||||||||||||||||||||||||
| Total price risk management liabilities | $ | 7 | $ | — | $ | 7 | $ | — | $ | 7 | $ | — | $ | 7 | $ | — | |||||||||||||||||||||||||||||||
| KU | |||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 14 | $ | 14 | $ | — | $ | — | $ | 21 | $ | 21 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| Restricted cash and cash equivalents (a) | 24 | 24 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Total Cash, Cash Equivalents and Restricted Cash (b) | 38 | 38 | — | — | 21 | 21 | — | — | |||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 38 | $ | 38 | $ | — | $ | — | $ | 21 | $ | 21 | $ | — | $ | — | |||||||||||||||||||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||
| Price risk management liabilities (b): | |||||||||||||||||||||||||||||||
| Interest rate swaps | $ | 26 | $ | — | $ | 26 | $ | — | $ | 31 | $ | — | $ | 31 | $ | — | |||||||||||||||
| Foreign currency contracts | 148 | — | 148 | — | 27 | — | 27 | — | |||||||||||||||||||||||
| Total price risk management liabilities | $ | 174 | $ | — | $ | 174 | $ | — | $ | 58 | $ | — | $ | 58 | $ | — | |||||||||||||||
| PPL Electric | |||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 49 | $ | 49 | $ | — | $ | — | $ | 13 | $ | 13 | $ | — | $ | — | |||||||||||||||
| Restricted cash and cash equivalents (a) | 2 | 2 | — | — | 2 | 2 | — | — | |||||||||||||||||||||||
| Total assets | $ | 51 | $ | 51 | $ | — | $ | — | $ | 15 | $ | 15 | $ | — | $ | — | |||||||||||||||
| LKE | |||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 30 | $ | 30 | $ | — | $ | — | $ | 13 | $ | 13 | $ | — | $ | — | |||||||||||||||
| Cash collateral posted to counterparties (c) | — | — | — | — | 3 | 3 | — | — | |||||||||||||||||||||||
| Total assets | $ | 30 | $ | 30 | $ | — | $ | — | $ | 16 | $ | 16 | $ | — | $ | — | |||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||
| Price risk management liabilities: | |||||||||||||||||||||||||||||||
| Interest rate swaps | $ | 26 | $ | — | $ | 26 | $ | — | $ | 31 | $ | — | $ | 31 | $ | — | |||||||||||||||
| Total price risk management liabilities | $ | 26 | $ | — | $ | 26 | $ | — | $ | 31 | $ | — | $ | 31 | $ | — | |||||||||||||||
| LG&E | |||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 15 | $ | 15 | $ | — | $ | — | $ | 5 | $ | 5 | $ | — | $ | — | |||||||||||||||
| Cash collateral posted to counterparties (c) | — | — | — | — | 3 | 3 | — | — | |||||||||||||||||||||||
| Total assets | $ | 15 | $ | 15 | $ | — | $ | — | $ | 8 | $ | 8 | $ | — | $ | — | |||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||
| Price risk management liabilities: | |||||||||||||||||||||||||||||||
| Interest rate swaps | $ | 26 | $ | — | $ | 26 | $ | — | $ | 31 | $ | — | $ | 31 | $ | — | |||||||||||||||
| Total price risk management liabilities | $ | 26 | $ | — | $ | 26 | $ | — | $ | 31 | $ | — | $ | 31 | $ | — | |||||||||||||||
| KU | |||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 15 | $ | 15 | $ | — | $ | — | $ | 7 | $ | 7 | $ | — | $ | — | |||||||||||||||
| Total assets | $ | 15 | $ | 15 | $ | — | $ | — | $ | 7 | $ | 7 | $ | — | $ | — | |||||||||||||||
(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 statement of financial position.
(d)Current portion is included in "Other current liabilities" and noncurrent portion is included in "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
A reconciliation of net liabilities classified as Level 3 for the year ended December 31 is as follows:
| Gas Contracts | |||||
| Balance | $ | 56 | |||
| Purchases | 19 | ||||
| Settlements | |||||
| Balance | $ | 19 | |||
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
170
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/Foreign Currency Contracts/Cross-Currency Swaps(PPL, LKE, LG&E and KU)
To manage interest rate risk, PPL, LKE, LG&E and KU use interest rate contracts such as forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps. To manage foreign currency exchange risk, PPL uses foreign currency contracts such as forwards, options, and cross-currency swaps that contain characteristics of both interest rate and foreign currency contracts. An income approach is used to measure the fair value of these contracts, utilizing readily observable inputs, such as forward interest rates (e.g., LIBORSOFR and government security rates) and forward foreign currency exchange rates (e.g., GBP), 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)
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 classified as 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 classified as 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 classified as Level 2 and Level 3.
Financial Instruments Not Recorded at Fair Value(All Registrants)
The carrying amounts of long-term debt on the Balance Sheets and their estimated fair values are set forth below. The fair values were estimated using an income approach by discounting future cash flows at estimated current cost of funding rates, which incorporate the credit risk of the Registrants. Long-term debt is classified as Level 2. The effect of third-party credit enhancements is not included in the fair value measurement.
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||
| Carrying Amount (a) | Fair Value | Carrying Amount (a) | Fair Value | ||||||||||||||||||||
| PPL | $ | 14,612 | $ | 14,031 | $ | 13,243 | $ | 12,239 | |||||||||||||||
| PPL Electric | 4,567 | 4,475 | 4,486 | 4,259 | |||||||||||||||||||
| LG&E | 2,469 | 2,369 | 2,307 | 2,128 | |||||||||||||||||||
| KU | 3,064 | 2,861 | 2,920 | 2,616 | |||||||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
| Carrying Amount (a) | Fair Value | Carrying Amount (a) | Fair Value | ||||||||||||
| PPL | $ | 20,195 | $ | 23,783 | $ | 18,326 | $ | 21,355 | |||||||
| PPL Electric | 3,298 | 3,769 | 2,831 | 3,148 | |||||||||||
| LKE | 5,159 | 5,670 | 5,065 | 5,439 | |||||||||||
| LG&E | 1,709 | 1,865 | 1,617 | 1,710 | |||||||||||
| KU | 2,328 | 2,605 | 2,327 | 2,514 | |||||||||||
(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.
171
17. Derivative Instruments and Hedging Activities
Risk Management Objectives
(All Registrants)
PPL has a risk management policy approved by the Board of Directors to manage market risk associated with commodities, interest rates on debt issuances and foreign exchange (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 interest rates and foreign currency exchangeinterest 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 WPD hold over-the-counter cross currency swaps to limit exposure to market fluctuations on interest and principal payments from changes in foreign currency exchange rates and interest rates. PPL, LKE and LG&E utilize over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt. PPL, LKE, 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.issuance.
•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 and for certain plans at WPD due to the recovery methods in place.
Commodity Price Risk
PPL is exposed to commodity price risk through its domestic 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 PUC-approvedPAPUC-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.costs. These mechanisms generally provide for timely recovery of market price fluctuations associated with these expenses.
costs.•RIE utilizes derivative instruments pursuant to its RIPUC-approved plan to manage commodity price risk associated with its natural gas purchases. RIE's commodity price risk management strategy is to reduce fluctuations in firm gas sales prices to its customers. RIE's costs associated with derivatives instruments are recoverable through its RIPUC- approved cost recovery mechanisms. 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.below:
172
•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 at the regulated domestic utilities and for certain plans at WPD 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" interest rate and foreign currency derivativestransactions with financial institutions,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 contractual 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, LKE, 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 $20 million and $19 million obligation to returnno cash collateral posted under master netting arrangements at December 31, 20172023 and 2016.$4 million cash collateral posted at December 31, 2022.
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.
173
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 heldhad no such contracts at December 31, 2017.2023.
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 2023, 2022 and 2021, PPL had an insignificant amount ofno cash flow hedges reclassified into earnings associated with discontinued cash flow hedges in 2017 and 2016.hedges.
At December 31, 2017,2023, 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 LKE and LG&E)
LG&E enters into interest rate swap contracts that economically hedge interest payments on variable rate debt.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. In December 2016, a swap with a notional amount of $32 million was terminated. A cash settlement of $9 million was paid on the terminated swap. The settlement is included in noncurrent regulatory assets on the Balance Sheet and in "Cash Flows from Operating Activities" on the Statement of Cash Flows. At December 31, 2017,2023, LG&E held contracts with a notional amount of $147$64 million that rangemature in maturity through 2033.
Economic Activity
Accounting and Reporting
(All Registrants)
All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless the NPNS is elected. NPNS contracts for PPL and PPL Electric 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 that are recognized as regulatory assets or regulatory liabilities. See Note 67 for amounts recorded in regulatory assets and regulatory liabilities at December 31, 20172023 and 2016.2022.
See Note 1 for additional information on accounting policies related to derivative instruments.
(PPL)
The following table presents the fair value and location of derivative instruments recorded on the Balance Sheets. Sheets:
174
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | Derivatives not designated as hedging instruments | Derivatives designated as hedging instruments | Derivatives not designated as hedging instruments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives designated as hedging instruments | Derivatives designated as hedging instruments | Derivatives not designated as hedging instruments | Derivatives designated as hedging instruments | Derivatives not designated as hedging instruments | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | Assets | Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current: | Current: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Price Risk Management | Price Risk Management | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets/Liabilities (a): | Assets/Liabilities (a): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps (b) | $ | — | $ | — | $ | — | $ | 4 | $ | — | $ | — | $ | — | $ | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cross-currency swaps (b) | 4 | — | — | — | 32 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | — | 45 | 67 | — | — | 31 | 21 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gas contracts | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total current | 4 | — | 45 | 71 | 32 | — | 31 | 25 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent: | Noncurrent: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Price Risk Management | Price Risk Management | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets/Liabilities (a): | Assets/Liabilities (a): | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps (b) | — | — | — | 22 | — | — | — | 27 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cross-currency swaps (b) | 97 | — | — | — | 156 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | — | 118 | 81 | — | — | 180 | 6 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gas contracts | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent | 97 | — | 118 | 103 | 156 | — | 180 | 33 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total derivatives | $ | 101 | $ | — | $ | 163 | $ | 174 | $ | 188 | $ | — | $ | 211 | $ | 58 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)Current portion is included in "Other current assets" and "Other current liabilities" and noncurrent portion is included in "Other noncurrent assets" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
(b)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.liabilities:
| Derivative Relationships | Derivative Gain (Loss) Recognized in OCI | Location of Gain (Loss) Recognized in Income on Derivative | Gain (Loss) Reclassified from AOCI into Income | |||||||||||||||||
| 2023 | ||||||||||||||||||||
| Cash Flow Hedges: | ||||||||||||||||||||
| Interest rate swaps | $ | — | Interest Expense | $ | (3) | |||||||||||||||
| Total | $ | — | $ | (3) | ||||||||||||||||
| 2022 | ||||||||||||||||||||
| Cash Flow Hedges: | ||||||||||||||||||||
| Interest rate swaps | $ | — | Interest Expense | $ | (3) | |||||||||||||||
| Total | $ | — | $ | (3) | ||||||||||||||||
| Net Investment Hedges: | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Cash Flow Hedges: | ||||||||||||||||||||
| Interest rate swaps | $ | — | Interest Expense | $ | 11 | |||||||||||||||
| Income (Loss) from Discontinued operations (net of taxes) | (2) | |||||||||||||||||||
| Cross-currency swaps | (50) | Income (Loss) from Discontinued operations (net of taxes) | (39) | |||||||||||||||||
| Total | $ | (50) | $ | (30) | ||||||||||||||||
| 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 | 2023 | 2022 | 2021 | ||||||||||||||||||||||
| Foreign currency contracts | Income (Loss) from Discontinued Operations (net of taxes) | $ | — | $ | — | $ | (266) | |||||||||||||||||||
| Interest rate swaps | Interest Expense | — | (2) | (2) | ||||||||||||||||||||||
| Gas contracts | Energy Purchases | (19) | 41 | — | ||||||||||||||||||||||
| Other income (expense) - net | (1) | $ | — | $ | — | |||||||||||||||||||||
| Total | $ | (20) | $ | 39 | $ | (268) | ||||||||||||||||||||
Derivative Relationships | Derivative Gain (Loss) Recognized in OCI (Effective Portion) | Location of Gain (Loss) Recognized in Income on Derivative | Gain (Loss) Reclassified from AOCI into Income (Effective Portion) | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | ||||||||||
| 2017 | ||||||||||||||
| Cash Flow Hedges: | ||||||||||||||
| Interest rate swaps | $ | — | Interest Expense | $ | (9 | ) | $ | — | ||||||
| Cross-currency swaps | (98 | ) | Other Income (Expense) - net | (82 | ) | — | ||||||||
| Total | $ | (98 | ) | $ | (91 | ) | $ | — | ||||||
| Net Investment Hedges: | ||||||||||||||
| Foreign currency contracts | $ | 1 | ||||||||||||
| 2016 | ||||||||||||||
| Cash Flow Hedges: | ||||||||||||||
| Interest rate swaps | $ | (21 | ) | Interest Expense | $ | (7 | ) | $ | — | |||||
| Cross-currency swaps | 130 | Other Income (Expense) - net | 116 | — | ||||||||||
| Interest Expense | 3 | — | ||||||||||||
| Total | $ | 109 | $ | 112 | $ | — | ||||||||
| Net Investment Hedges: | ||||||||||||||
| Foreign currency contracts | $ | 2 | ||||||||||||
175
| Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized as Regulatory Liabilities/Assets | 2023 | 2022 | 2021 | ||||||||||||||||||||||
| Gas contracts | Regulatory assets - current | $ | 9 | $ | 39 | $ | — | |||||||||||||||||||
| Regulatory assets - noncurrent | (8) | — | — | |||||||||||||||||||||||
| Interest rate swaps | Regulatory assets - noncurrent | — | 11 | 5 | ||||||||||||||||||||||
| Total | $ | 1 | $ | 50 | $ | 5 | ||||||||||||||||||||
Derivative Relationships | Derivative Gain (Loss) Recognized in OCI (Effective Portion) | Location of Gain (Loss) Recognized in Income on Derivative | Gain (Loss) Reclassified from AOCI into Income (Effective Portion) | Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) | ||||||||||
| 2015 | ||||||||||||||
| Cash Flow Hedges: | ||||||||||||||
| Interest rate swaps | $ | (34 | ) | Interest Expense | $ | (11 | ) | $ | — | |||||
| Discontinued operations | — | (77 | ) | |||||||||||
| Cross-currency swaps | 60 | Other Income (Expense) - net | 49 | — | ||||||||||
| Interest Expense | 2 | — | ||||||||||||
| Commodity contracts | Discontinued operations | 13 | 7 | |||||||||||
| Total | $ | 26 | $ | 53 | $ | (70 | ) | |||||||
| Net Investment Hedges: | ||||||||||||||
| Foreign currency contracts | $ | 9 | ||||||||||||
Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized in Income on Derivative | 2017 | 2016 | 2015 | ||||||||||
| Foreign currency contracts | Other Income (Expense) - net | $ | (261 | ) | $ | 384 | $ | 122 | ||||||
| Interest rate swaps | Interest Expense | (6 | ) | (7 | ) | (8 | ) | |||||||
| Total | $ | (267 | ) | $ | 377 | $ | 114 | |||||||
Derivatives Designated as Hedging Instruments | Location of Gain (Loss) Recognized as Regulatory Liabilities/Assets | 2017 | 2016 | 2015 | ||||||||||
| Interest rate swaps | Regulatory assets - noncurrent | $ | — | $ | — | $ | (22 | ) | ||||||
Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized as Regulatory Liabilities/Assets | 2017 | 2016 | 2015 | ||||||||||
| Interest rate swaps | Regulatory assets - noncurrent | $ | 5 | $ | 7 | $ | 1 | |||||||
The following table presents the pre-tax effect of derivative instruments designated as cash flow hedges that are recognized in regulatory assets. All derivative instruments designated as cash flow hedges were terminated in 2015 and there is nohedge activity inon the current period.Statement of Income for the year ended December 31, 2023:
| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships | |||||||||||
| Interest Expense | |||||||||||
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 666 | |||||||||
| 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 | (3) | ||||||||||
| Cross-currency swaps: | |||||||||||
| Hedged items | — | ||||||||||
| Amount of gain (loss) reclassified from AOCI to income | — | ||||||||||
| Derivative Instruments | Location of Gain (Loss) | 2017 | 2016 | 2015 | ||||||||||
| Interest rate swaps | Regulatory assets - noncurrent | $ | — | $ | — | $ | (22 | ) | ||||||
The following table presents the pre-tax effect of derivative instruments designated as cash flow hedges that are recognized in regulatory assets. All derivative instruments designated as cash flow hedges were terminated in 2015 and there is nohedge activity inon the current period.Statement of Income for the year ended December 31, 2022:
| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships | |||||||||||
| Interest Expense | |||||||||||
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 513 | |||||||||
| 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 | (3) | ||||||||||
| Cross-currency swaps: | |||||||||||
| Hedged items | — | ||||||||||
| Amount of gain (loss) reclassified from AOCI to income | — | ||||||||||
| Derivative Instruments | Location of Gain (Loss) | 2017 | 2016 | 2015 | ||||||||||
| Interest rate swaps | Regulatory asset - noncurrent | $ | — | $ | — | $ | (11 | ) | ||||||
The following table presents the pre-tax effect of derivative instruments designated as cash flow hedges that are recognized in regulatory assets. All derivative instruments designated as cash flow hedges were terminated in 2015 and there is nohedge activity inon the current period.Statement of Income for the year ended December 31, 2021:
| Derivative Instruments | Location of Gain (Loss) | 2017 | 2016 | 2015 | ||||||||||
| Interest rate swaps | Regulatory assets - noncurrent | $ | — | $ | — | $ | (11 | ) | ||||||
176
| Location and Amount of Gain (Loss) Recognized in Income on Hedging Relationships | |||||||||||
| Interest Expense | Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||
| Total income and expense line items presented in the income statement in which the effect of cash flow hedges are recorded | $ | 918 | $ | (1,498) | |||||||
| 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 | 11 | (2) | |||||||||
| Cross-currency swaps: | |||||||||||
| Hedged items | — | 39 | |||||||||
| Amount of gain (loss) reclassified from AOCI to income | — | (39) | |||||||||
(LG&E)
The following table presents the fair value and the location on the Balance Sheets of derivatives not designated as hedging instruments.instruments:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| 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 | — | 6 | — | 6 | ||||||||||||||||||||||
| Total noncurrent | — | 6 | — | 6 | ||||||||||||||||||||||
| Total derivatives | $ | — | $ | 7 | $ | — | $ | 7 | ||||||||||||||||||
| December 31, 2017 | December 31, 2016 | |||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||
| Current: | ||||||||||||||||
| Price Risk Management | ||||||||||||||||
| Assets/Liabilities: | ||||||||||||||||
| Interest rate swaps | $ | — | $ | 4 | $ | — | $ | 4 | ||||||||
| Total current | — | 4 | — | 4 | ||||||||||||
| Noncurrent: | ||||||||||||||||
| Price Risk Management | ||||||||||||||||
| Assets/Liabilities: | ||||||||||||||||
| Interest rate swaps | — | 22 | — | 27 | ||||||||||||
| Total noncurrent | — | 22 | — | 27 | ||||||||||||
| Total derivatives | $ | — | $ | 26 | $ | — | $ | 31 | ||||||||
The following tables present the pre-tax effect of derivatives not designated as cash flow hedges that are recognized in income or regulatory assets. assets:
| Derivative Instruments | Location of Gain (Loss) | 2023 | 2022 | 2021 | ||||||||||||||||||||||
| Interest rate swaps | Interest Expense | $ | — | $ | (2) | $ | (2) | |||||||||||||||||||
| Derivative Instruments | Location of Gain (Loss) | 2017 | 2016 | 2015 | Derivative Instruments | Location of Gain (Loss) | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||||||||||||
| Interest rate swaps | Interest Expense | $ | (6 | ) | $ | (7 | ) | $ | (8 | ) | ||||||||||||||||||||||||||||||||||||||||||
| Derivative Instruments | Location of Gain (Loss) | 2017 | 2016 | 2015 | ||||||||||
| Interest rate swaps | Regulatory assets - noncurrent | $ | 5 | $ | 7 | $ | 1 | |||||||
(PPL, LKE, LG&E and KU)
Offsetting Derivative Instruments
PPL, LKE, 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, LKE, 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 | |||||||||||||||||||||||||
| December 31, 2017 | ||||||||||||||||||||||||||||||||
| Treasury Derivatives | ||||||||||||||||||||||||||||||||
| PPL | $ | 264 | $ | 107 | $ | 20 | $ | 137 | $ | 174 | $ | 107 | $ | — | $ | 67 | ||||||||||||||||
| LKE | — | — | — | — | 26 | — | — | 26 | ||||||||||||||||||||||||
| LG&E | — | — | — | — | 26 | — | — | 26 | ||||||||||||||||||||||||
177
| Assets | Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||||
| Eligible for Offset | Eligible for Offset | |||||||||||||||||||||||||||||||||||||||||||||||||
| Gross | Derivative Instruments | Cash Collateral Received | Net | Gross | Derivative Instruments | Cash Collateral Pledged | Net | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL | $ | 1 | $ | — | $ | — | $ | 1 | $ | 67 | $ | — | $ | — | $ | 67 | ||||||||||||||||||||||||||||||||||
| LG&E | — | — | — | — | 7 | — | — | 7 | ||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives | ||||||||||||||||||||||||||||||||||||||||||||||||||
| PPL | $ | 25 | $ | 20 | $ | — | $ | 5 | $ | 73 | $ | 62 | $ | — | $ | 11 | ||||||||||||||||||||||||||||||||||
| LG&E | — | — | — | — | 7 | — | — | 7 | ||||||||||||||||||||||||||||||||||||||||||
| Assets | Liabilities | |||||||||||||||||||||||||||||||
| Eligible for Offset | Eligible for Offset | |||||||||||||||||||||||||||||||
| Gross | Derivative Instruments | Cash Collateral Received | Net | Gross | Derivative Instruments | Cash Collateral Pledged | Net | |||||||||||||||||||||||||
| December 31, 2016 | ||||||||||||||||||||||||||||||||
| Treasury Derivatives | ||||||||||||||||||||||||||||||||
| PPL | $ | 399 | $ | 27 | $ | 19 | $ | 353 | $ | 58 | $ | 27 | $ | 3 | $ | 28 | ||||||||||||||||
| LKE | — | — | — | — | 31 | — | 3 | 28 | ||||||||||||||||||||||||
| LG&E | — | — | — | — | 31 | — | 3 | 28 | ||||||||||||||||||||||||
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, LKE, 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, LKE'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 would represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" features.
At December 31, 2017,2023, derivative contracts in a net liability position that contain credit risk-related contingent features was $35 million. The aggregate fair value of additional collateral posted on those positions andrequirements in the related effectevent of a decrease in credit ratingsdowngrade below investment grade are summarized as follows:was $36 million.
| PPL | LKE | LG&E | ||||||||||
| Aggregate fair value of derivative instruments in a net liability position with credit risk-related contingent features | $ | 51 | $ | 10 | $ | 10 | ||||||
| Aggregate fair value of collateral posted on these derivative instruments | — | — | — | |||||||||
| Aggregate fair value of additional collateral requirements in the event of a credit downgrade below investment grade (a) | 51 | 10 | 10 | |||||||||
18. Goodwill and Other Intangible Assets
Goodwill
(PPL)
The changes in the carrying amount of goodwill by segment were:
| Kentucky Regulated | Rhode Island Regulated | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| Balance at beginning of period (a) | $ | 662 | $ | 662 | $ | 725 | $ | — | $ | 861 | $ | 53 | $ | 2,248 | $ | 715 | |||||||||||||||||||||||||||||||
| Goodwill recognized during the period (b) | — | — | — | 725 | (1) | 861 | (1) | 1,586 | |||||||||||||||||||||||||||||||||||||||
| Sale of Safari Holdings (c) | — | — | — | — | — | (53) | — | (53) | |||||||||||||||||||||||||||||||||||||||
| Total | $ | 662 | $ | 662 | $ | 725 | $ | 725 | $ | 860 | $ | 861 | $ | 2,247 | $ | 2,248 | |||||||||||||||||||||||||||||||
| U.K. Regulated | Kentucky Regulated | Total | |||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||
| Balance at beginning of period (a) | $ | 2,398 | $ | 2,888 | $ | 662 | $ | 662 | $ | 3,060 | $ | 3,550 | |||||||||||
| Effect of foreign currency exchange rates | 198 | (490 | ) | 198 | (490 | ) | |||||||||||||||||
| Balance at end of period (a) | $ | 2,596 | $ | 2,398 | $ | 662 | $ | 662 | $ | 3,258 | $ | 3,060 | |||||||||||
(a)There were no accumulated impairment losses related to goodwill.
(b)Recognized as a result of the acquisition of RIE. See Note 9 for additional information.
(c)See Note 9 for additional information.
178
Other Intangible Assets
(PPL)
The gross carrying amount and the accumulated amortization of other intangible assets were:
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||||||||||
| Subject to amortization: | |||||||||||||||||||||||
| Contracts (a) | $ | 125 | $ | 107 | $ | 125 | $ | 99 | |||||||||||||||
| Renewable Energy Credits | 15 | — | 14 | — | |||||||||||||||||||
| Land rights and easements | 411 | 143 | 407 | 138 | |||||||||||||||||||
| Licenses and other | 2 | — | 2 | 1 | |||||||||||||||||||
| Total subject to amortization | 553 | 250 | 548 | 238 | |||||||||||||||||||
| Not subject to amortization due to indefinite life: | |||||||||||||||||||||||
| Land rights and easements | 18 | — | 17 | — | |||||||||||||||||||
| Total not subject to amortization due to indefinite life | 18 | — | 17 | — | |||||||||||||||||||
| Total | $ | 571 | $ | 250 | $ | 565 | $ | 238 | |||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
| Subject to amortization: | |||||||||||||||
| Contracts (a) | $ | 138 | $ | 67 | $ | 405 | $ | 325 | |||||||
| Land and transmission rights | 382 | 120 | 362 | 115 | |||||||||||
| Emission allowances/RECs (b) | 1 | — | 2 | — | |||||||||||
| Licenses and other | 7 | 3 | 6 | 2 | |||||||||||
| Total subject to amortization | 528 | 190 | 775 | 442 | |||||||||||
| Not subject to amortization due to indefinite life: | |||||||||||||||
| Land and transmission rights | 12 | — | 19 | — | |||||||||||
| Easements | 347 | — | 348 | — | |||||||||||
| Total not subject to amortization due to indefinite life | 359 | — | 367 | — | |||||||||||
| Total | $ | 887 | $ | 190 | $ | 1,142 | $ | 442 | |||||||
(a)Gross carrying amount in 2023 and 2022 includes the fair value at the acquisition date of the OVEC power purchase contract with terms favorable to market recognized as a result of the 2010 acquisition of LKE by PPL.
Current intangible assets are included in "Other current assets" and long-term intangible assets are included in "Other intangibles" on the Balance Sheets.
| Amortization expense was as follows: | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Intangible assets with no regulatory offset | $ | 5 | $ | 5 | $ | 9 | |||||||||||
| Intangible assets with regulatory offset | 9 | 9 | 8 | ||||||||||||||
| Total | $ | 14 | $ | 14 | $ | 17 | |||||||||||
| Amortization Expense was as follows: | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Intangible assets with no regulatory offset | $ | 6 | $ | 6 | $ | 6 | |||||
| Intangible assets with regulatory offset | 9 | 24 | 51 | ||||||||
| Total | $ | 15 | $ | 30 | $ | 57 | |||||
Amortization expense for each of the next five years excluding insignificant amounts for consumption of emission allowances/RECs, is estimated to be:
| 2024 | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||
| Intangible assets with no regulatory offset | $ | 5 | $ | 5 | $ | 4 | $ | 4 | $ | 4 | |||||||||||||||||||
| Intangible assets with regulatory offset | 8 | 8 | 2 | — | — | ||||||||||||||||||||||||
| Total | $ | 13 | $ | 13 | $ | 6 | $ | 4 | $ | 4 | |||||||||||||||||||
| 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
| Intangible assets with no regulatory offset | $ | 6 | $ | 6 | $ | 6 | $ | 6 | $ | 6 | |||||||||
| Intangible assets with regulatory offset | 9 | 9 | 8 | 8 | 8 | ||||||||||||||
| Total | $ | 15 | $ | 15 | $ | 14 | $ | 14 | $ | 14 | |||||||||
(PPL Electric)
The gross carrying amount and the accumulated amortization of other intangible assets were:
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||||||||||
| Subject to amortization: | |||||||||||||||||||||||
| Land rights and easements | $ | 389 | $ | 138 | $ | 385 | $ | 134 | |||||||||||||||
| Licenses and other | 2 | 1 | 2 | 1 | |||||||||||||||||||
| Total subject to amortization | 391 | 139 | 387 | 135 | |||||||||||||||||||
| Not subject to amortization due to indefinite life: | |||||||||||||||||||||||
| Land rights and easements | 17 | — | 17 | — | |||||||||||||||||||
| Total | $ | 408 | $ | 139 | $ | 404 | $ | 135 | |||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
| Subject to amortization: | |||||||||||||||
| Land and transmission rights | $ | 361 | $ | 117 | $ | 341 | $ | 112 | |||||||
| Licenses and other | 3 | 1 | 3 | 1 | |||||||||||
| Total subject to amortization | 364 | 118 | 344 | 113 | |||||||||||
| Not subject to amortization due to indefinite life: | |||||||||||||||
| Land and transmission rights | 13 | — | 20 | — | |||||||||||
| Total | $ | 377 | $ | 118 | $ | 364 | $ | 113 | |||||||
Intangible assets are shown as "Intangibles" on the Balance Sheets.
179
Amortization expense was insignificant in 2017, 2016 and 2015 andas follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Intangible assets with no regulatory offset | $ | 4 | $ | 4 | $ | 4 | |||||||||||
Amortization expense for each of the next five years is expectedestimated to be insignificant in future years.be:
| 2024 | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||
| Intangible assets with no regulatory offset | $ | 4 | $ | 4 | $ | 4 | $ | 4 | $ | 4 | |||||||||||||||||||
(LG&E)
The gross carrying amount and the accumulated amortization of other intangible assets were:
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||||||||||
| Subject to amortization: | |||||||||||||||||||||||
| Land rights and easements | $ | 7 | $ | 2 | $ | 7 | $ | 1 | |||||||||||||||
| OVEC power purchase agreement (a) | 86 | 73 | 86 | 68 | |||||||||||||||||||
| Total subject to amortization | $ | 93 | $ | 75 | $ | 93 | $ | 69 | |||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
| Subject to amortization: | |||||||||||||||
| Coal contracts (a) | $ | — | $ | — | $ | 269 | $ | 269 | |||||||
| Land and transmission rights | 21 | 3 | 21 | 3 | |||||||||||
| OVEC power purchase agreement (b) | 126 | 58 | 126 | 49 | |||||||||||
| Total subject to amortization | $ | 147 | $ | 61 | $ | 416 | $ | 321 | |||||||
(a) Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 7 for additional information.
Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
Amortization expense was as follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Intangible assets with regulatory offset | $ | 6 | $ | 6 | $ | 5 | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Intangible assets with no regulatory offset | $ | — | $ | 1 | $ | — | |||||
| Intangible assets with regulatory offset | 9 | 24 | 51 | ||||||||
| Total | $ | 9 | $ | 25 | $ | 51 | |||||
Amortization expense for each of the next five years is estimated to be:
| 2024 | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||
| Intangible assets with regulatory offset | $ | 6 | $ | 6 | $ | 1 | $ | — | $ | — | |||||||||||||||||||
| 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
| Intangible assets with regulatory offset | $ | 9 | $ | 9 | $ | 8 | $ | 8 | $ | 8 | |||||||||
(KU)
The gross carrying amount and the accumulated amortization of other intangible assets were:
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||||||||||
| Subject to amortization: | |||||||||||||||||||||||
| Land rights and easements | $ | 17 | $ | 4 | $ | 16 | $ | 3 | |||||||||||||||
| OVEC power purchase agreement (a) | 39 | 33 | 39 | 31 | |||||||||||||||||||
| Total subject to amortization | $ | 56 | $ | 37 | $ | 55 | $ | 34 | |||||||||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
| Subject to amortization: | |||||||||||||||
| Coal contracts (a) | $ | — | $ | — | $ | 124 | $ | 124 | |||||||
| Land and transmission rights | 7 | 1 | 7 | 1 | |||||||||||
| OVEC power purchase agreement (b) | 87 | 40 | 87 | 34 | |||||||||||
| Total subject to amortization | $ | 94 | $ | 41 | $ | 218 | $ | 159 | |||||||
(a) Gross carrying amount represents the fair value at the acquisition date of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL. An offsetting regulatory liability was recorded related to this contract, which is being amortized over the same period as the intangible asset, eliminating any income statement impact. See Note 7 for additional information.
Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
180
Amortization expense was as follows:
| 2023 | 2022 | 2021 | |||||||||||||||
| Intangible assets with no regulatory offset | $ | — | $ | — | $ | 1 | |||||||||||
| Intangible assets with regulatory offset | 3 | 3 | 3 | ||||||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Intangible assets with regulatory offset | $ | 6 | $ | 13 | $ | 24 | |||||
Amortization expense for each of the next five years is estimated to be:
| 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
| Intangible assets with regulatory offset | $ | 6 | $ | 6 | $ | 6 | $ | 6 | $ | 6 | |||||||||
| December 31, 2017 | December 31, 2016 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
| Subject to amortization: | |||||||||||||||
| Coal contracts (a) | $ | — | $ | — | $ | 145 | $ | 145 | |||||||
| Land and transmission rights | 14 | 2 | 14 | 2 | |||||||||||
| OVEC power purchase agreement (b) | 39 | 18 | 39 | 15 | |||||||||||
| Total subject to amortization | $ | 53 | $ | 20 | $ | 198 | $ | 162 | |||||||
| 2017 | 2016 | 2015 | |||||||||
| Intangible assets with no regulatory offset | $ | — | $ | 1 | $ | — | |||||
| Intangible assets with regulatory offset | 3 | 11 | 27 | ||||||||
| Total | $ | 3 | $ | 12 | $ | 27 | |||||
| 2018 | 2019 | 2020 | 2021 | 2022 | |||||||||||||||
| Intangible assets with regulatory offset | $ | 3 | $ | 3 | $ | 2 | $ | 2 | $ | 2 | |||||||||
| 2024 | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||
| Intangible assets with regulatory offset | $ | 2 | $ | 2 | $ | 1 | $ | — | $ | — | |||||||||||||||||||
19. Asset Retirement Obligations
(PPL and PPL Electric)
PPL Electric has identified legal retirement obligations for the retirement of certain transmission assets that could not be reasonably estimated due to indeterminable settlement dates. These assets are located on rights-of-way that allow the grantor to require PPL Electric to relocate or remove the assets. Since this option is at the discretion of the grantor of the right-of-way, PPL Electric is unable to determine when these events may occur.
(PPL, LKE, LG&E and KU)
PPL's, LG&E's and KU's AROsARO liabilities are primarily related to CCR closure costs. See Note 13 for information on the final retirement of assets associated with generating units.CCR rule. LG&E and RIE also hashave 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. As described in Notes 1For LG&E, KU, and 6, for LKE, LG&E and KU,RIE , all ARO accretion and depreciation expenses are reclassified as a regulatory asset.asset or regulatory liability. ARO regulatory assets associated with certain CCR projects are amortized to expense in accordance with regulatory approvals. For other AROs, at the time of retirement, the related ARO regulatory assetdeferred accretion and depreciation expense is offset against the associatedrecovered through cost of removal regulatory liability, PP&E and ARO liability.removal.
The changes in the carrying amounts of AROs were as follows:
| PPL | LKE | LG&E | KU | ||||||||||||||||||||||||||||
| 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||
| ARO at beginning of period | $ | 488 | $ | 586 | $ | 433 | $ | 535 | $ | 145 | $ | 175 | $ | 288 | $ | 360 | |||||||||||||||
| Accretion | 21 | 24 | 20 | 22 | 7 | 7 | 13 | 15 | |||||||||||||||||||||||
| Changes in estimated timing or cost (a) | (73 | ) | (84 | ) | (54 | ) | (95 | ) | (8 | ) | (19 | ) | (46 | ) | (76 | ) | |||||||||||||||
| Effect of foreign currency exchange rates | 4 | (9 | ) | — | — | — | — | — | — | ||||||||||||||||||||||
| Obligations settled | (43 | ) | (29 | ) | (43 | ) | (29 | ) | (23 | ) | (18 | ) | (20 | ) | (11 | ) | |||||||||||||||
| ARO at end of period | $ | 397 | $ | 488 | $ | 356 | $ | 433 | $ | 121 | $ | 145 | $ | 235 | $ | 288 | |||||||||||||||
| PPL | LG&E | KU | |||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||||||
| ARO at beginning of period | $ | 177 | $ | 189 | $ | 86 | $ | 84 | $ | 82 | $ | 105 | |||||||||||||||||||||||
| Acquisition of RIE | — | 10 | — | — | — | — | |||||||||||||||||||||||||||||
| Accretion | 9 | 6 | 4 | 3 | 5 | 3 | |||||||||||||||||||||||||||||
| Obligations incurred | 2 | 2 | 1 | 2 | 1 | — | |||||||||||||||||||||||||||||
| Changes in estimated timing or cost | 15 | 15 | 11 | 12 | 6 | 4 | |||||||||||||||||||||||||||||
| Obligations settled | (39) | (45) | (11) | (15) | (28) | (30) | |||||||||||||||||||||||||||||
| Other | (6) | — | (6) | — | — | — | |||||||||||||||||||||||||||||
| ARO at end of period | $ | 158 | $ | 177 | $ | 85 | $ | 86 | $ | 66 | $ | 82 | |||||||||||||||||||||||
20. Accumulated Other Comprehensive Income (Loss)
The after-tax changes in AOCI by component for the years ended December 31 were as follows:
181
| Defined benefit plans | |||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation adjustments | Unrealized gains (losses) on qualifying derivatives | Equity investees' AOCI | Prior service costs | Actuarial gain (loss) | Total | ||||||||||||||||||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||||||||||||||||
| December 31, 2020 | $ | (1,158) | $ | — | $ | — | $ | (16) | $ | (3,046) | $ | (4,220) | |||||||||||||||||||||||||||||
| Amounts arising during the year | 372 | (39) | — | — | (1) | 332 | |||||||||||||||||||||||||||||||||||
| Reclassifications from AOCI | — | 25 | — | 2 | 126 | 153 | |||||||||||||||||||||||||||||||||||
| Reclassifications from AOCI due to the sale of the U.K. utility business (Note 9) | 786 | 15 | — | 8 | 2,769 | 3,578 | |||||||||||||||||||||||||||||||||||
| Net OCI during the year | 1,158 | 1 | — | 10 | 2,894 | 4,063 | |||||||||||||||||||||||||||||||||||
| December 31, 2021 | $ | — | $ | 1 | $ | — | $ | (6) | $ | (152) | $ | (157) | |||||||||||||||||||||||||||||
| Amounts arising during the year | — | — | 2 | (1) | 11 | 12 | |||||||||||||||||||||||||||||||||||
| Reclassifications from AOCI | — | 2 | — | 2 | 17 | 21 | |||||||||||||||||||||||||||||||||||
| Net OCI during the year | — | 2 | 2 | 1 | 28 | 33 | |||||||||||||||||||||||||||||||||||
| December 31, 2022 | $ | — | $ | 3 | $ | 2 | $ | (5) | $ | (124) | $ | (124) | |||||||||||||||||||||||||||||
| Amounts arising during the year | — | — | 1 | — | (41) | (40) | |||||||||||||||||||||||||||||||||||
| Reclassifications from AOCI | — | 3 | — | 1 | (3) | 1 | |||||||||||||||||||||||||||||||||||
| Net OCI during the year | — | 3 | 1 | 1 | (44) | (39) | |||||||||||||||||||||||||||||||||||
| December 31, 2023 | $ | — | $ | 6 | $ | 3 | $ | (4) | $ | (168) | $ | (163) | |||||||||||||||||||||||||||||
| Unrealized gains (losses) | Defined benefit plans | ||||||||||||||||||||||||||
Foreign currency translation adjustments | Available- for-sale securities | Qualifying derivatives | Equity investees' AOCI | Prior service costs | Actuarial gain (loss) | Total | |||||||||||||||||||||
| PPL | |||||||||||||||||||||||||||
| December 31, 2014 | $ | (286 | ) | $ | 201 | $ | 20 | $ | 1 | $ | 3 | $ | (2,213 | ) | $ | (2,274 | ) | ||||||||||
| Amounts arising during the year | (234 | ) | 8 | 26 | — | (9 | ) | (366 | ) | (575 | ) | ||||||||||||||||
| Reclassifications from AOCI | — | (2 | ) | 2 | (1 | ) | — | 146 | 145 | ||||||||||||||||||
| Net OCI during the year | (234 | ) | 6 | 28 | (1 | ) | (9 | ) | (220 | ) | (430 | ) | |||||||||||||||
| Distribution of PPL Energy Supply (See Note 8) | — | (207 | ) | (55 | ) | — | — | 238 | (24 | ) | |||||||||||||||||
| December 31, 2015 | $ | (520 | ) | $ | — | $ | (7 | ) | $ | — | $ | (6 | ) | $ | (2,195 | ) | $ | (2,728 | ) | ||||||||
| Amounts arising during the year | (1,107 | ) | — | 91 | — | (3 | ) | (61 | ) | (1,080 | ) | ||||||||||||||||
| Reclassifications from AOCI | — | — | (91 | ) | (1 | ) | 1 | 121 | 30 | ||||||||||||||||||
| Net OCI during the year | (1,107 | ) | — | — | (1 | ) | (2 | ) | 60 | (1,050 | ) | ||||||||||||||||
| December 31, 2016 | $ | (1,627 | ) | $ | — | $ | (7 | ) | $ | (1 | ) | $ | (8 | ) | $ | (2,135 | ) | $ | (3,778 | ) | |||||||
| Amounts arising during the year | 538 | — | (79 | ) | — | — | (308 | ) | 151 | ||||||||||||||||||
| Reclassifications from AOCI | — | — | 73 | 1 | 1 | 130 | 205 | ||||||||||||||||||||
| Net OCI during the year | 538 | — | (6 | ) | 1 | 1 | (178 | ) | 356 | ||||||||||||||||||
| December 31, 2017 | $ | (1,089 | ) | $ | — | $ | (13 | ) | $ | — | $ | (7 | ) | $ | (2,313 | ) | $ | (3,422 | ) | ||||||||
| LKE | |||||||||||||||||||||||||||
| December 31, 2014 | $ | — | $ | (8 | ) | $ | (37 | ) | $ | (45 | ) | ||||||||||||||||
| Amounts arising during the year | — | (3 | ) | (4 | ) | (7 | ) | ||||||||||||||||||||
| Reclassifications from AOCI | — | 1 | 5 | 6 | |||||||||||||||||||||||
| Net OCI during the year | — | (2 | ) | 1 | (1 | ) | |||||||||||||||||||||
| December 31, 2015 | $ | — | $ | (10 | ) | $ | (36 | ) | $ | (46 | ) | ||||||||||||||||
| Amounts arising during the year | — | — | (27 | ) | (27 | ) | |||||||||||||||||||||
| Reclassifications from AOCI | (1 | ) | 2 | 2 | 3 | ||||||||||||||||||||||
| Net OCI during the year | (1 | ) | 2 | (25 | ) | (24 | ) | ||||||||||||||||||||
| December 31, 2016 | $ | (1 | ) | $ | (8 | ) | $ | (61 | ) | $ | (70 | ) | |||||||||||||||
| Amounts arising during the year | — | (2 | ) | (23 | ) | (25 | ) | ||||||||||||||||||||
| Reclassifications from AOCI | 1 | 1 | 5 | 7 | |||||||||||||||||||||||
| Net OCI during the year | 1 | (1 | ) | (18 | ) | (18 | ) | ||||||||||||||||||||
| December 31, 2017 | $ | — | $ | (9 | ) | $ | (79 | ) | $ | (88 | ) | ||||||||||||||||
The following table presents PPL's gains (losses) and related income taxes for reclassifications from AOCI for the years ended December 31, 2017, 20162023, 2022 and 2015. LKE amounts are insignificant for the years ended December 31, 2017, 2016 and 2015.2021. The defined benefit plan components of AOCI are not reflected in their entirety in the statement of income; rather, they are included in the computation of net periodic defined benefit costs (credits) and subject to capitalization. See Note 11 for additional information.
| PPL | ||||||||||||||||||||||||||
| Details about AOCI | 2023 | 2022 | 2021 | Affected Line Item on the Statements of Income | ||||||||||||||||||||||
| Qualifying derivatives | ||||||||||||||||||||||||||
| Interest rate swaps | $ | (3) | $ | (3) | $ | 11 | Interest Expense | |||||||||||||||||||
| Cross-currency swaps | — | — | (2) | Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||||||||||||||
| — | — | (39) | Income (Loss) from Discontinued Operations (net of income taxes) | |||||||||||||||||||||||
| Total Pre-tax | (3) | (3) | (30) | |||||||||||||||||||||||
| Income Taxes | — | 1 | 5 | |||||||||||||||||||||||
| Total After-tax | (3) | (2) | (25) | |||||||||||||||||||||||
| Defined benefit plans | ||||||||||||||||||||||||||
| Prior service costs | (2) | (3) | (3) | |||||||||||||||||||||||
| Net actuarial loss | 3 | (24) | (159) | |||||||||||||||||||||||
| Total Pre-tax | 1 | (27) | (162) | |||||||||||||||||||||||
| Income Taxes | 1 | 8 | 34 | |||||||||||||||||||||||
| Total After-tax | 2 | (19) | (128) | |||||||||||||||||||||||
| Sale of the U.K. utility business (Note 9) | ||||||||||||||||||||||||||
| Foreign currency translation adjustments | — | — | (646) | Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||||||||||||||
| Qualifying derivatives | — | — | (15) | Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||||||||||||||
| Defined benefit plans | — | — | (3,577) | Income (Loss) from Discontinued Operations (net of income taxes) | ||||||||||||||||||||||
| Total Pre-tax | — | — | (4,238) | |||||||||||||||||||||||
| Income Taxes | — | — | 660 | |||||||||||||||||||||||
| Total After-tax | — | — | (3,578) | |||||||||||||||||||||||
| Total reclassifications during the year | $ | (1) | $ | (21) | $ | (3,731) | ||||||||||||||||||||
182
| PPL | ||||||||||||||
| Details about AOCI | 2017 | 2016 | 2015 | Affected Line Item on the Statements of Income | ||||||||||
| Available-for-sale securities | $ | — | $ | — | $ | 4 | Other Income (Expense) - net | |||||||
| Total Pre-tax | — | — | 4 | |||||||||||
| Income Taxes | — | — | (2 | ) | ||||||||||
| Total After-tax | — | — | 2 | |||||||||||
| PPL | ||||||||||||||
| Details about AOCI | 2017 | 2016 | 2015 | Affected Line Item on the Statements of Income | ||||||||||
| Qualifying derivatives | ||||||||||||||
| Interest rate swaps | (9 | ) | (7 | ) | (11 | ) | Interest Expense | |||||||
| — | — | (77 | ) | Discontinued operations | ||||||||||
| Cross-currency swaps | (82 | ) | 116 | 49 | Other Income (Expense) - net | |||||||||
| — | 3 | 2 | Interest Expense | |||||||||||
| Commodity contracts | — | — | 20 | Discontinued operations | ||||||||||
| Total Pre-tax | (91 | ) | 112 | (17 | ) | |||||||||
| Income Taxes | 18 | (21 | ) | 15 | ||||||||||
| Total After-tax | (73 | ) | 91 | (2 | ) | |||||||||
| Equity Investees' AOCI | (1 | ) | 1 | 1 | Other Income (Expense) - net | |||||||||
| Total Pre-tax | (1 | ) | 1 | 1 | ||||||||||
| Income Taxes | — | — | — | |||||||||||
| Total After-tax | (1 | ) | 1 | 1 | ||||||||||
| Defined benefit plans | ||||||||||||||
| Prior service costs | (2 | ) | (2 | ) | — | |||||||||
| Net actuarial loss | (167 | ) | (156 | ) | (192 | ) | ||||||||
| Total Pre-tax | (169 | ) | (158 | ) | (192 | ) | ||||||||
| Income Taxes | 38 | 36 | 46 | |||||||||||
| Total After-tax | (131 | ) | (122 | ) | (146 | ) | ||||||||
| Total reclassifications during the year | $ | (205 | ) | $ | (30 | ) | $ | (145 | ) | |||||
21. New Accounting Guidance Pending Adoption
(All Registrants)
In May 2014,November 2023, the Financial Accounting Standards Board (FASB)FASB issued accounting guidanceASU 2023-07 which improves reportable segment disclosure requirements, primarily through enhanced disclosures about segment expenses. The standard also requires public entities to disclose the title and position of the Chief Operating Decision Maker (CODM) and explain how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Disclosure of certain segment-related disclosures that establishes a comprehensive new model for the recognition of revenue from contracts with customers. This model is basedpreviously were required only on the core principlean annual basis will be required in interim periods. In addition, public entities that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
For public business entities, this guidance will be equivalentapplied retrospectively to the electricity and natural gas delivered and billedall prior periods presented in that period (including estimated billings), which is consistent with current practice.
The Registrants are currently assessing the impact of adopting this guidance. The Registrants will adopt this guidance effective January 1, 2019.
In June 2016,December 2023, the FASB issued accounting guidance thatASU 2023-09 which requires the use ofpublic business entities to provide additional income tax disclosures including a current expected credit loss (CECL) model for the measurement of credit lossesdisaggregated rate reconciliation as well as information on financial instruments within the scope of this guidance, which includes accounts receivable. The CECL model requires an entity to measure credit losses using historical information, current information and reasonable and supportable forecasts of future events, rather than the incurred loss impairment model required under current GAAP.income taxes paid.
For public business entities, this guidance will be applied usingon a modified retrospective approach andprospective basis. Retrospective application is permitted. This guidance will be effective for fiscal yearsannual periods beginning after December 15, 2019, and interim periods within those years. All entities may early adopt this guidance beginning after December 15, 2018, including interim periods within those years.2024. Early adoption is permitted for annual financial statements that have not yet been issued or made available for issuance.
The Registrants are currently assessing the impact of adopting this guidance and the period they will adopt it.
guidance.
183
| 2017 | 2016 | 2015 | |||||||||
| Operating Revenues | $ | — | $ | — | $ | — | |||||
| Operating Expenses | |||||||||||
| Other operation and maintenance | 2 | 2 | 9 | ||||||||
| Total Operating Expenses | 2 | 2 | 9 | ||||||||
| Operating Loss | (2 | ) | (2 | ) | (9 | ) | |||||
| Other Income (Expense) - net | |||||||||||
| Equity in earnings of subsidiaries | 1,175 | 1,915 | 711 | ||||||||
| Other income (expense) | (1 | ) | (1 | ) | (15 | ) | |||||
| Total | 1,174 | 1,914 | 696 | ||||||||
| Interest Expense | 8 | 8 | 9 | ||||||||
| Interest Expense with Affiliates | 16 | 10 | 10 | ||||||||
| Income Before Income Taxes | 1,148 | 1,894 | 668 | ||||||||
| Income Taxes | 20 | (8 | ) | (14 | ) | ||||||
| Net Income | $ | 1,128 | $ | 1,902 | $ | 682 | |||||
| Total other comprehensive income (loss) | 356 | (1,050 | ) | (430 | ) | ||||||
| Comprehensive Income Attributable to PPL Shareowners | $ | 1,484 | $ | 852 | $ | 252 | |||||
| Earnings Per Share of Common Stock: | |||||||||||
| Net Income Available to PPL Common Shareowners: | |||||||||||
| Basic | $ | 1.64 | $ | 2.80 | $ | 1.01 | |||||
| Diluted | $ | 1.64 | $ | 2.79 | $ | 1.01 | |||||
| Weighted-Average Shares of Common Stock Outstanding (in thousands) | |||||||||||
| Basic | 685,240 | 677,592 | 669,814 | ||||||||
| Diluted | 687,334 | 680,446 | 672,586 | ||||||||
| 2017 | 2016 | 2015 | |||||||||
| Cash Flows from Operating Activities | |||||||||||
| Net cash provided by (used in) operating activities | $ | 1,108 | $ | 1,563 | $ | 993 | |||||
| Cash Flows from Investing Activities | |||||||||||
| Capital contributions to affiliated subsidiaries | (585 | ) | (308 | ) | (491 | ) | |||||
| Return of capital from affiliated subsidiaries | — | — | 112 | ||||||||
| Net cash provided by (used in) investing activities | (585 | ) | (308 | ) | (379 | ) | |||||
| Cash Flows from Financing Activities | |||||||||||
| Issuance of equity, net of issuance costs | 453 | 144 | 203 | ||||||||
| Net increase (decrease) in short-term debt with affiliates | 113 | (341 | ) | 215 | |||||||
| Payment of common stock dividends | (1,072 | ) | (1,030 | ) | (1,004 | ) | |||||
| Other | (21 | ) | (24 | ) | (28 | ) | |||||
| Net cash provided by (used in) financing activities | (527 | ) | (1,251 | ) | (614 | ) | |||||
| Net Increase (Decrease) in Cash and Cash Equivalents | |||||||||||
| Cash and Cash Equivalents at Beginning of Period | 4 | — | — | ||||||||
| Cash and Cash Equivalents at End of Period | $ | — | $ | 4 | $ | — | |||||
| Supplemental Disclosures of Cash Flow Information: | |||||||||||
| Cash Dividends Received from Subsidiaries | $ | 1,253 | $ | 1,510 | $ | 1,198 | |||||
| 2017 | 2016 | ||||||
| Assets | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | — | $ | 4 | |||
| Accounts Receivable | |||||||
| Other | 7 | 7 | |||||
| Affiliates | 17 | 10 | |||||
| Price risk management assets | 196 | 63 | |||||
| Total Current Assets | 220 | 84 | |||||
| Investments | |||||||
| Affiliated companies at equity | 11,141 | 10,160 | |||||
| Other Noncurrent Assets | |||||||
| Deferred income taxes | 46 | 70 | |||||
| Price risk management assets | 186 | 284 | |||||
| Other noncurrent assets | 1 | 1 | |||||
| Total Other Noncurrent Assets | 233 | 355 | |||||
| Total Assets | $ | 11,594 | $ | 10,599 | |||
| Liabilities and Equity | |||||||
| Current Liabilities | |||||||
| Short-term debt with affiliates | $ | 157 | $ | 44 | |||
| Accounts payable with affiliates | 2 | 30 | |||||
| Dividends | 273 | 259 | |||||
| Price risk management liabilities | 233 | 237 | |||||
| Other current liabilities | 19 | 20 | |||||
| Total Current Liabilities | 684 | 590 | |||||
| Deferred Credits and Other Noncurrent Liabilities | 149 | 110 | |||||
| Equity | |||||||
| Common stock - $0.01 par value (a) | 7 | 7 | |||||
| Additional paid-in capital | 10,305 | 9,841 | |||||
| Earnings reinvested | 3,871 | 3,829 | |||||
| Accumulated other comprehensive loss | (3,422 | ) | (3,778 | ) | |||
| Total Equity | 10,761 | 9,899 | |||||
| Total Liabilities and Equity | $ | 11,594 | $ | 10,599 | |||
| 2017 | 2016 | 2015 | |||||||||
| Other Income (Expense) - net | |||||||||||
| Equity in Earnings of Subsidiaries | $ | 397 | $ | 452 | $ | 390 | |||||
| Interest Income with Affiliate | 14 | 9 | 4 | ||||||||
| Total | 411 | 461 | 394 | ||||||||
| Interest Expense | 30 | 29 | 39 | ||||||||
| Interest Expense with Affiliate | 20 | 18 | 5 | ||||||||
| Income Before Income Taxes | 361 | 414 | 350 | ||||||||
| Income Tax Expense (Benefit) | 45 | (15 | ) | (14 | ) | ||||||
| Net Income | $ | 316 | $ | 429 | $ | 364 | |||||
| Total other comprehensive loss | (18 | ) | (24 | ) | (1 | ) | |||||
| Comprehensive Income Attributable to Member | $ | 298 | $ | 405 | $ | 363 | |||||
| 2017 | 2016 | 2015 | |||||||||
| Cash Flows from Operating Activities | |||||||||||
| Net cash provided by (used in) operating activities | $ | 401 | $ | 285 | $ | 246 | |||||
| Cash Flows from Investing Activities | |||||||||||
| Capital contributions to affiliated subsidiaries | (30 | ) | (91 | ) | (140 | ) | |||||
| Net decrease (increase) in notes receivable from affiliates | (28 | ) | 47 | 73 | |||||||
| Net cash provided by (used in) investing activities | (58 | ) | (44 | ) | (67 | ) | |||||
| Cash Flows from Financing Activities | |||||||||||
| Net increase (decrease) in notes payable with affiliates | 58 | 90 | 315 | ||||||||
| Net increase (decrease) in short-term debt | — | (75 | ) | — | |||||||
| Retirement of long-term debt | — | — | (400 | ) | |||||||
| Contribution from member | — | 61 | 125 | ||||||||
| Distribution to member | (402 | ) | (316 | ) | (219 | ) | |||||
| Net cash provided by (used in) financing activities | (344 | ) | (240 | ) | (179 | ) | |||||
| Net Increase (Decrease) in Cash and Cash Equivalents | (1 | ) | 1 | — | |||||||
| Cash and Cash Equivalents at Beginning of Period | 1 | — | — | ||||||||
| Cash and Cash Equivalents at End of Period | $ | — | $ | 1 | $ | — | |||||
| Supplemental disclosures of cash flow information: | |||||||||||
| Cash Dividends Received from Subsidiaries | $ | 418 | $ | 376 | $ | 272 | |||||
| 2017 | 2016 | ||||||
| Assets | |||||||
| Current Assets | |||||||
| Cash and cash equivalents | $ | — | $ | 1 | |||
| Accounts receivable | 1 | — | |||||
| Accounts receivable from affiliates | 8 | 23 | |||||
| Income taxes receivable | 1 | 31 | |||||
| Notes receivable from affiliates | 1,035 | 1,007 | |||||
| Total Current Assets | 1,045 | 1,062 | |||||
| Investments | |||||||
| Affiliated companies at equity | 5,209 | 5,219 | |||||
| Other Noncurrent Assets | |||||||
| Deferred income taxes | 263 | 227 | |||||
| Total Assets | $ | 6,517 | $ | 6,508 | |||
| Liabilities and Equity | |||||||
| Current Liabilities | |||||||
| Notes payable to affiliates | $ | 241 | $ | 179 | |||
| Accounts payable to affiliates | 469 | 450 | |||||
| Taxes | 35 | — | |||||
| Other current liabilities | 5 | 6 | |||||
| Total Current Liabilities | 750 | 635 | |||||
| Long-term Debt | |||||||
| Long-term debt | 722 | 721 | |||||
| Notes payable to affiliates | 476 | 480 | |||||
| Total Long-term Debt | 1,198 | 1,201 | |||||
| Deferred Credits and Other Noncurrent Liabilities | 6 | 5 | |||||
| Equity | 4,563 | 4,667 | |||||
| Total Liabilities and Equity | $ | 6,517 | $ | 6,508 | |||
| For the Quarters Ended (a) | |||||||||||||||
| March 31 | June 30 | Sept. 30 | Dec. 31 | ||||||||||||
| 2017 | |||||||||||||||
| Operating revenues | $ | 1,951 | $ | 1,725 | $ | 1,845 | $ | 1,926 | |||||||
| Operating income | 796 | 702 | 777 | 793 | |||||||||||
| Net income | 403 | 292 | 355 | 78 | |||||||||||
| Net income available to PPL common shareowners: (b) | |||||||||||||||
| Basic EPS | 0.59 | 0.43 | 0.52 | 0.11 | |||||||||||
| Diluted EPS | 0.59 | 0.43 | 0.51 | 0.11 | |||||||||||
| Dividends declared per share of common stock (c) | 0.3950 | 0.3950 | 0.3950 | 0.3950 | |||||||||||
| Price per common share: | |||||||||||||||
| High | $ | 37.70 | $ | 40.06 | $ | 39.83 | $ | 38.37 | |||||||
| Low | 33.94 | 37.11 | 37.36 | 30.76 | |||||||||||
| 2016 | |||||||||||||||
| Operating revenues | $ | 2,011 | $ | 1,785 | $ | 1,889 | $ | 1,832 | |||||||
| Operating income | 823 | 725 | 786 | 714 | |||||||||||
| Net income | 481 | 483 | 473 | 465 | |||||||||||
| Net income available to PPL common shareowners: (b) | |||||||||||||||
| Basic EPS | 0.71 | 0.71 | 0.70 | 0.68 | |||||||||||
| Diluted EPS | 0.71 | 0.71 | 0.69 | 0.68 | |||||||||||
| Dividends declared per share of common stock (c) | 0.38 | 0.38 | 0.38 | 0.38 | |||||||||||
| Price per common share: | |||||||||||||||
| High | $ | 38.07 | $ | 39.68 | $ | 37.71 | $ | 34.74 | |||||||
| Low | 32.80 | 36.27 | 33.63 | 32.19 | |||||||||||
| For the Quarters Ended (a) | |||||||||||||||
| March 31 | June 30 | Sept. 30 | Dec. 31 | ||||||||||||
| 2017 | |||||||||||||||
| Operating revenues | $ | 573 | $ | 500 | $ | 547 | $ | 575 | |||||||
| Operating income | 159 | 156 | 189 | 197 | |||||||||||
| Net income | 79 | 77 | 95 | 111 | |||||||||||
| 2016 | |||||||||||||||
| Operating revenues | $ | 585 | $ | 495 | $ | 539 | $ | 537 | |||||||
| Operating income | 180 | 154 | 176 | 154 | |||||||||||
| Net income | 94 | 79 | 90 | 77 | |||||||||||
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a)Evaluation of disclosure controls and procedures.
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
The Registrants' principal executive officers and principal financial officers, based on their evaluation of the Registrants' disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of December 31, 2017,2023, the Registrants' disclosure controls and procedures are effective to ensure that material information relating to the Registrants and their consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, particularly during the period for which this annual report has been prepared. The aforementioned principal officers have concluded that the disclosure controls and procedures are also effective to ensure that information required to be disclosed in reports filed under the Exchange Act is accumulated and communicated to management, including the principal executive officers and principal financial officers, to allow for timely decisions regarding required disclosure.
(b)Changes in internal control over financial reporting.
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company, and Kentucky Utilities Company
The Registrants' principal executive officers and principal financial officers have concluded that there were no changes in the Registrants' internal control over financial reporting during the Registrants' fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Registrants' internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
PPL Corporation
PPL's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). PPL's internal control over financial reporting is a process designed to provide reasonable assurance to PPL's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in "Internal Control - Integrated Framework" (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017.2023. The effectiveness of our internal control over financial reporting has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report contained on page 95.firm.
PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Management of PPL's non-accelerated filer companies, PPL Electric, LKE, LG&E and KU, are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Each of the aforementioned companies' internal control over financial reporting is a process
designed to provide reasonable assurance to management and Board of Directors of these companies regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
184
accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including the principal executive officers and principal financial officers of the companies listed above, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in "Internal Control - Integrated Framework" (2013), management of these companies concluded that our internal control over financial reporting was effective as of December 31, 2017.2023. This annual report does not include an attestation report of Deloitte & Touche LLP, the companies' independent registered public accounting firm regarding internal control over financial reporting for these non-accelerated filer companies. The effectiveness of internal control over financial reporting for the aforementioned companies was not subject to attestation by the companies' registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit these companies to provide only management's report in this annual report.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareowners and the Board of Directors of PPL Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of PPL Corporation and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our report dated February 16, 2024, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Morristown, New Jersey
February 16, 2024
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ITEM 9B. OTHER INFORMATION
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
(a)None.
(b)Securities Trading Plans of Directors and Executive Officers
During the three months ended December 31, 2023, none of our directors or executive officers adopted, terminated or modified any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as such terms are defined in Item 408 of Regulation S-K.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
PPL Corporation, PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Not applicable.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PPL Corporation
Additional information forrequired by this itemItem is incorporated by reference to, and will be set forthcontained in, the sections entitled "Nominees for Directors," "Board Committees - Board Committee Membership" and "Section 16(a) Beneficial Ownership Reporting Compliance" in PPL's 2018 Notice of Annual Meeting and Proxy Statement,our definitive proxy statement, which will be filed with the SEC not later thanwithin 120 days after December 31, 2017, and which2023. Accordingly, we have omitted the information is incorporated herein by reference. There have been no changesfrom this Item pursuant to the procedures by which shareowners may recommend nominees to PPL's boardGeneral Instruction G(3) of directors since the filing with the SEC of PPL's 2017 Notice of Annual Meeting and Proxy Statement.Form 10-K.
PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 10 is omitted as PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K.
EXECUTIVE OFFICERS OF THE REGISTRANTS
Officers of the Registrants are elected annually by their Boards of Directors to serve at the pleasure of the respective Boards. There are no family relationships among any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.
Listed below are the executive officers at December 31, 2017.2023.
PPL Corporation
| Name | Age | |||||||||||||||||||||||
| Positions Held During the Past Five Years | Dates | |||||||||||||||||||||||
| 52 | ||||||||||||||||||||||||
| President and Chief Operating Officer | July 2019 - May 2020 | |||||||||||||||||||||||
| Senior Vice President and Chief Financial Officer | June 2014 - | |||||||||||||||||||||||
| Joseph P. Bergstein, Jr. | 53 | Executive Vice President and Chief Financial Officer | April 2021 - present | |||||||||||||||||||||
| Senior Vice President and Chief Financial Officer | July 2019 - April 2021 | |||||||||||||||||||||||
| Vice President-Investor Relations and Corporate Development & Planning | January 2018 - June 2019 | |||||||||||||||||||||||
| Vice President-Investor Relations and Treasurer | January 2016 - December | |||||||||||||||||||||||
| Angela K. Gosman | 55 | Executive Vice President and Chief Human Resources Officer | January 2023 - present | |||||||||||||||||||||
| Senior Vice President and Chief Human Resources Officer | ||||||||||||||||||||||||
| Vice President and Chief Human Resources Officer-PPL Services | ||||||||||||||||||||||||
| Vice President - Human Resources-PPL EU Services | May 2020 - July 2021 | |||||||||||||||||||||||
| Director - Human Resources-LKE | September 2016 - May 2020 | |||||||||||||||||||||||
| Wendy E. Stark | 51 | Executive Vice President, Chief Legal Officer and Corporate Secretary | January 2023 - present | |||||||||||||||||||||
| Senior Vice President, General Counsel, Corporate Secretary and Chief Legal Officer | January 2022 - December 2022 | |||||||||||||||||||||||
| Senior Vice President, General Counsel and Corporate Secretary | April 2021 - December 2021 | |||||||||||||||||||||||
| Francis X. Sullivan | 67 | Executive Vice President and Chief Operating Officer | January 2023 - present | |||||||||||||||||||||
| Vice President-Operations Performance-PPL Services | October 2021 - December 2022 | |||||||||||||||||||||||
| David J. Bonenberger (a) | 62 | President-RIE | May 2022 - present | |||||||||||||||||||||
| Vice President-Operations Integration-PPL Services | April 2021 - present | |||||||||||||||||||||||
| Vice President-Transmission and Substations-PPL Electric | January 2018 - April 2021 | |||||||||||||||||||||||
| Vice President-Distribution Operations-PPL Electric | July 2021 - December 2017 | |||||||||||||||||||||||
| John R. Crockett III (a) | 59 | President-LKE | October 2021 - present | |||||||||||||||||||||
| General Counsel, Chief Compliance Officer and Corporate Secretary - LKE | January 2018 - September 2021 | |||||||||||||||||||||||
| Christine M. Martin (a) | 51 | President-PPL Electric | September 2023 - present | |||||||||||||||||||||
| Senior Vice President-Public Affairs and Chief Sustainability Officer | January 2023 - August 2023 | |||||||||||||||||||||||
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| Name | Age | Positions Held During the Past Five Years | Dates | |||||||||||||||||||||
| Vice President-Public Affairs and Chief Sustainability Officer | April 2022 - January 2023 | |||||||||||||||||||||||
| Vice President-Public Affairs and Sustainability | August 2018 - April 2022 | |||||||||||||||||||||||
| Tadd J. Henninger | 48 | Senior Vice President-Finance and Treasurer | January 2023 - present | |||||||||||||||||||||
| Vice President-Finance and Treasurer | July 2019 - January 2023 | |||||||||||||||||||||||
| Vice President and Treasurer | January 2018 - July 2019 | |||||||||||||||||||||||
| Marlene C. Beers | 52 | Vice President and Controller | ||||||||||||||||||||||
| Vice President-Finance and Regulatory Affairs and Controller-PPL Electric | ||||||||||||||||||||||||
(a)Designated an executive officer of PPL by virtue of their respective positions at a PPL subsidiary.
ITEM 11. EXECUTIVE COMPENSATION
PPL Corporation
PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 11 is omitted as PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
PPL Corporation
Equity Compensation Plan Information
Number of securities to be issued upon exercise of outstanding options, warrants and rights (3) | Weighted-average exercise price of outstanding options, warrants and rights (3) | Number of securities remaining available for future issuance under equity compensation plans (4) | ||||||||
| Equity compensation | ||||||||||
| plans approved by | 495,422 | – ICP | $ | 39.88 | – ICP | 1,720,050 | – DDCP | |||
security holders (1) | 1,329,058 | – SIP | $ | 26.21 | – SIP | 10,506,026 | – SIP | |||
| 1,937,703 | – ICPKE | $ | 28.95 | – ICPKE | 1,598,811 | – ICPKE | ||||
| 3,762,183 | – Total | $ | 29.42 | – Combined | 13,824,887 | – Total | ||||
| Equity compensation | ||||||||||
| plans not approved by | ||||||||||
security holders (2) | ||||||||||
| Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans(3)(4) | ||||||||||||||||||
| Equity compensation | 1,185,379 | – DDCP | ||||||||||||||||||
| plans approved by | ||||||||||||||||||||
| 9,173,480 | – SIP | |||||||||||||||||||
security holders (1) | 353,965 | – ICPKE | ||||||||||||||||||
| 10,712,824 | – Total | |||||||||||||||||||
| Equity compensation | ||||||||||||||||||||
| plans | ||||||||||||||||||||
security holders (2) | ||||||||||||||||||||
(1)Includes (a) the ICPKE, under which restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based compensation awards may be awarded to non-executive key employees of PPL and its subsidiaries; (b) the SIP approved by shareowners in 2017 under which restricted stock, restricted stock units, performance units, dividend
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equivalents and other stock-based compensation awards may be awarded to executive officers of PPL and its subsidiaries; and (c) the DDCP, under which stock units may be awarded to directors of PPL.
(2)All of PPL's current compensation plans under which equity securities of PPL are authorized for issuance have been approved by PPL's shareowners.
(3)As of December 31, 2023, there were 3,592,916 stock awards outstanding under the plans. The following stock awards are outstanding under the SIP, ICPKE and DDCP: 690,050 restricted stock units, 599,855 TSR performance awards, 178,917 ROE performance awards, 246,276 EG performance awards and 246,276 ESG performance awards under the SIP; 624,409 restricted stock units 167,612 TSR performance awards, 84,454 ROE performance awards, 49,945 EG performance awards and 49,945 ESG performance awards under the ICPKE; and 655,177 stock units under the DDCP.
(4)Based upon the following aggregate award limitations under the SIP, ICPKE and DDCP: (a) under the SIP, 15,000,000 awards; (b) under the ICPKE, 16,573,608 awards (i.e., 5% of the total PPL common stock outstanding as of January 1, 2003) granted after April 25, 2003, reduced by outstanding awards for which common stock was not yet issued as of such date of 2,373,812 resulting in a limit of 14,199,796; and (c) under the DDCP, the number of stock units available for issuance was reduced to 2,000,000 stock units in March 2012. In addition, the ICPKE includes an annual award limitation of 2% of total PPL common stock outstanding as of January 1 of each year.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 12 is omitted as PPL Electric, LG&E and KU Energy LLC,meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
PPL Corporation
The information required by this Item is incorporated by reference to, and will be contained in, our definitive proxy statement, which will be filed within 120 days after December 31, 2023. Accordingly, we have omitted the information from this Item pursuant to General Instruction G(3) of Form 10-K.
PPL Electric Utilities Corporation, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 1213 is omitted as PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PPL Corporation
PPL Electric Utilities Corporation
For the fiscal yearyears ended 20172023 and 2016,2022, Deloitte & Touche LLP (Deloitte) served as PPL Electric's independent auditor. The following table presents an allocation of fees billed, including expenses, by the independent auditor to PPL Electric, for professional services rendered for the auditaudits of PPL Electric's annual financial statements and for fees billed for other services rendered by Deloitte.
| 2023 | 2022 | ||||||||||
(in thousands) | |||||||||||
| Audit fees (a) | $ | 1,390 | $ | 1,221 | |||||||
| Audit-related fees (b) | 17 | 17 | |||||||||
| 2017 | 2016 | ||||||
(in thousands) | |||||||
| Audit fees (a) | $ | 1,086 | $ | 1,104 | |||
| Audit-related fees (b) | 28 | — | |||||
| All other fees (c) | 253 | — | |||||
| (a)Includes estimated fees for audit of |
(b)Fees for agreed-upon procedures related to annual EPA filings.
| 2017 | 2016 | ||||||
(in thousands) | |||||||
| Audit fees (a) | $ | 1,717 | $ | 1,767 | |||
Louisville Gas and Electric Company
For the fiscal years ended 20172023 and 2016,2022, Deloitte served as LG&E's independent auditor. The following table presents an allocation of fees billed, including expenses, by the independent auditor to LG&E, for professional services rendered for the audits of LG&E's annual financial statements and for fees billed for other services rendered by Deloitte.
| 2023 | 2022 | ||||||||||
(in thousands) | |||||||||||
| Audit fees (a) | $ | 1,189 | $ | 831 | |||||||
| 2017 | 2016 | ||||||
(in thousands) | |||||||
| Audit fees (a) | $ | 826 | $ | 814 | |||
(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in LG&E's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
Kentucky Utilities Company
For the fiscal years ended 20172023 and 2016,2022, Deloitte served as KU's independent auditor. The following table presents an allocation of fees billed, including expenses, by the independent auditor to KU, for professional services rendered for the audits of KU's annual financial statements and for fees billed for other services rendered by Deloitte.
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| 2017 | 2016 | |||||||
(in thousands) | ||||||||
| Audit fees (a) | $ | 874 | $ | 936 | ||||
| 2023 | 2022 | |||||||||||||
(in thousands) | ||||||||||||||
| Audit fees (a) | $ | 1,175 | $ | 920 | ||||||||||
(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in KU's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Approval of Fees. The Audit Committee of PPL has procedures for pre-approving audit and non-audit services to be provided by the independent auditor. These procedures are designed to ensure the continued independence of the independent auditor. More specifically, the use of the independent auditor to perform either audit or non-audit services is prohibited unless specifically approved in advance by the Audit Committee of PPL. As a result of this approval process, the Audit Committee of PPL has pre-approved specific categories of services and authorization levels. All services outside of the specified categories and all amounts exceeding the authorization levels are approved by the Chair of the Audit Committee of PPL, who serves as the Committee designee to review and approve audit and non-audit related services during the year. A listing of the approved audit and non-audit services is reviewed with the full Audit Committee of PPL no later than its next meeting.
The Audit Committee of PPL approved 100% of the 20172023 and 20162022 services provided by Deloitte.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PPL Corporation, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
(a) The following documents are filed as part of this report:
1.Financial Statements - Refer to the "Table of Contents" for an index of the financial statements included in this report.
2.Supplementary Data and Supplemental Financial Statement Schedule I - PPL Corporation Condensed Unconsolidated Financial Statements.included in response to Item 8.
All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.
3.Exhibits
See Exhibit Index immediately following the signature pages."Shareowner and Investor Information."
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SHAREOWNER AND INVESTOR INFORMATION
Annual Meeting: The 20182024 annual meeting of shareowners of PPL will be held on Wednesday, May 16, 2018, at The PPL Center, 701 Hamilton Street, Allentown, Pennsylvania.15, 2024 in a virtual meeting format.
Proxy Statement Material: A proxy statement and notice of PPL's annual meeting will be provided to all shareowners who are holders of record as of February 28, 2018.2024. The latest proxy statement can be accessed at www.pplweb.com/PPLCorpProxy.
PPL Annual Report: The report will be published in the beginning of April and will be provided to all shareowners who are holders of record as of February 28, 2018.2024. The latest annual report can be accessed at www.pplweb.com/PPLCorpProxy.
Dividends: Subject to the declaration of dividends on PPL common stock by the PPL Board of Directors or its Executive Committee, dividends are paid on the first business day of April, July, October and January. The 20182024 record dates for dividends are expected to be March 9,8, June 8,10, September 10 and December 10.
PPL's Website(www.pplweb.com): Shareowners can access PPL publications such as annual and quarterly reports to the Securities and Exchange Commission (SEC Forms 10-K and 10-Q), other PPL filings, corporate governance materials, news releases, stock quotes and historical performance. Visitors to our website can subscribe to receive automated email alerts for SEC filings, earnings releases, daily stock prices or other financial news.
Financial reports which are available at www.pplweb.com will be mailed without charge upon request by writing to:request.
By mail:
PPL Treasury Dept.
Two North Ninth Street
Allentown, PA 18101
By email: invserv@pplweb.com
By telephone:
610-774-5151 or by calling:Toll-free at 1-800-345-3085
Online Account Access: Registered shareowners can activate their account for online access by visiting shareowneronline.com.
Direct Stock Purchase and Dividend Reinvestment Plans (Plan): PPL offers investors the opportunity to acquire shares of PPL common stock through its Plan. Through the Plan, participants are eligible to invest up to $25,000 per calendar month in PPL common stock. Shareowners may choose to have dividends on their PPL common stock fully or partially reinvested in PPL common stock or can receive full payment of cash dividends by check or electronic funds transfer. Participants in the Plan may choose to have their common stock certificates deposited into their Plan account.
Direct Registration System: PPL participates in the Direct Registration System (DRS). Shareowners may choose to have their common stock certificates converted to book entry form within the DRS by submitting their certificates to PPL's transfer agent.
Listed Securities:
New York Stock Exchange
PPL Corporation:
Common Stock (Code: PPL)
PPL Capital Funding, Inc.:
2007 Series A Junior Subordinated Notes due 2067 (Code: PPL/67)
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Fiscal Agents:
Transfer Agent and Registrar; Dividend Disbursing Agent; Plan Administrator
Equiniti Trust Company
Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Toll Free: 1-800-345-3085
Outside U.S.: 651-450-4064
Website: shareowneronline.com
Indenture Trustee
The Bank of New York Mellon
Corporate Trust Administration
500 Ross Street
Pittsburgh, PA 15262
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EXHIBIT INDEX
The following Exhibits indicated by an asterisk preceding the Exhibit number are filed herewith. The balance of the Exhibits has heretofore been filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein by reference. Exhibits indicated by a [_] are filed or listed pursuant to Item 601(b)(10)(iii) of Regulation S-K.
| - | Securities Purchase and Registration Rights Agreement, dated March 5, 2014, among PPL Capital Funding, Inc., PPL Corporation, and the several purchasers named in Schedule B thereto (Exhibit 1.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 10, 2014) | |||||||||||||
| - | ||||||||||||||
| - | ||||||||||||||
| Separation Agreement among PPL Corporation, Talen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Raven Power Holdings LLC, C/R Energy Jade, LLC and Sapphire Power Holdings LLC., dated as of June 9, 2014 (Exhibit 2.1 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated June 12, 2014) | ||||||||||||||
| - | Transaction Agreement among PPL Corporation, Talen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Talen Energy Merger Sub, Inc., C/R Energy Jade, LLC, Sapphire Power Holdings LLC. and Raven Power Holdings LLC, dated as of June 9, 2014 (Exhibit 2.2 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated June 12, 2014) | |||||||||||||
| - | Share Purchase Agreement, dated as of March 17, 2021, by and among PPL WPD Limited, National Grid Holdings One plc and National Grid plc. (Exhibit 2.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 18, 2021) | |||||||||||||
| - | Share Purchase Agreement, dated as of March 17, 2021, by and among PPL Energy Holdings, LLC, PPL Corporation (solely as guarantor), and National Grid USA (Exhibit 2.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 18, 2021) | |||||||||||||
| - | Assignment and Assumption Agreement, dated as of May 3, 2021, by and among PPL Energy Holdings, LLC, PPL Corporation, National Grid USA and PPL Rhode Island Holdings, LLC (Exhibit 2(b)-2 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2021) | |||||||||||||
| - | Tax Deed, dated as of June 9, 2021, by and among PPL WPD Limited, National Grid Holdings One plc (Exhibit 2.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 14, 2021) | |||||||||||||
| - | Amended and Restated Articles of Incorporation of PPL Corporation, effective as of May 25, 2016 (Exhibit 3(i) to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 26, 2016) | |||||||||||||
| - | Bylaws of PPL Corporation, effective as of December | |||||||||||||
| - | Amended and Restated Articles of Incorporation of PPL Electric Utilities Corporation, effective as of October 31, 2013 (Exhibit 3(a) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended September 30, 2013) | |||||||||||||
| - | Bylaws of PPL Electric Utilities Corporation, effective as of October 27, 2015 (Exhibit 3(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2015) | |||||||||||||
| - | Amended and Restated Articles of Incorporation of Louisville Gas and Electric Company, effective as of November 6, 1996 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173676)) | |||||||||||||
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| - | Articles of Amendment to Articles of Incorporation of Louisville Gas and Electric Company, effective as of April 6, 2004 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173676)) | |||||||||||||
| - | Bylaws of Louisville Gas and Electric Company, effective as of December 16, 2003 (Exhibit 3(c) to Registration Statement filed on Form S-4 (File No. 333-173676)) | |||||||||||||
| - | Amended and Restated Articles of Incorporation of Kentucky Utilities Company, effective as of December 14, 1993 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173675)) | |||||||||||||
| - | Articles of Amendment to Articles of Incorporation of Kentucky Utilities Company, effective as of April 8, 2004 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173675)) | |||||||||||||
| - | Bylaws of Kentucky Utilities Company, effective as of December 16, 2003 (Exhibit 3(c) to Registration Statement filed on Form S-4 (File No. 333-173675)) | |||||||||||||
| - | Amended and Restated Employee Stock Ownership Plan, dated December 1, 2016 (Exhibit 4(a) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2016) | |||||||||||||
| - | Amendment No. 1 to PPL Employee Stock Ownership Plan, dated October 2, 2017 (Exhibit 4(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2017) | |||||||||||||
| - | ||||||||||||||
| - | Amendment No. 3 to PPL Employee Stock Ownership Plan, dated January 1, 2019 (Exhibit 4(a)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2018) | |||||||||||||
| - | Indenture, dated as of November 1, 1997, among PPL Corporation, PPL Capital Funding, Inc. and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 12, 1997) | |||||||||||||
| - | Supplemental Indenture No. 8, dated as of June 14, 2012, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 14, 2012) | |||||||||||||
| - | Supplemental Indenture No. 9, dated as of October 15, 2012, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated October 15, 2012) | |||||||||||||
| - | Supplemental Indenture No. 10, dated as of May 24, 2013, to said Indenture (Exhibit 4.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 24, 2013) | |||||||||||||
| - | Supplemental Indenture No. 11, dated as of May 24, 2013, to said Indenture (Exhibit 4.3 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 24, 2013) | |||||||||||||
| - | Supplemental Indenture No. 12, dated as of May 24, 2013, to said Indenture (Exhibit 4.4 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 24, 2013) | |||||||||||||
| - | Supplemental Indenture No. 13, dated as of March 10, 2014, to said Indenture (Exhibit 4.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 10, 2014) | |||||||||||||
| - | Supplemental Indenture No. 14, dated as of March 10, 2014, to said Indenture (Exhibit 4.3 to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 10, 2014) | |||||||||||||
| - | Supplemental Indenture No. 15, dated as of May 17, 2016, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 17, 2016) | |||||||||||||
| - | Supplemental Indenture No. 16, dated as of September 8, 2017, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated September 6, 2017) | |||||||||||||
| - | Supplemental Indenture No. 17, dated as of | |||||||||||||
| - | ||||||||||||||
| Indenture, dated as of August 1, 2001, by PPL Electric Utilities Corporation and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 21, 2001) | ||||||||||||||
| - | Supplemental Indenture No. 6, dated as of December 1, 2005, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated December 22, 2005) | |||||||||||||
| - | Supplemental Indenture No. 7, dated as of August 1, 2007, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 14, 2007) | |||||||||||||
| - | Supplemental Indenture No. 9, dated as of October 1, 2008, to said Indenture (Exhibit 4(c) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 31, 2008) | |||||||||||||
| - | Supplemental Indenture No. 10, dated as of May 1, 2009, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated May 22, 2009) | |||||||||||||
| - | Supplemental Indenture No. 11, dated as of July 1, 2011, to said Indenture (Exhibit 4.1 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 13, 2011) | |||||||||||||
| - | Supplemental Indenture No. 12, dated as of July 1, 2011, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 18, 2011) | |||||||||||||
| - | Supplemental Indenture No. 13, dated as of August 1, 2011, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 23, 2011) | |||||||||||||
| - | Supplemental Indenture No. 14, dated as of August 1, 2012, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 24, 2012) | |||||||||||||
| - | Supplemental Indenture No. 15, dated as of July 1, 2013, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 11, 2013) | |||||||||||||
| - | Supplemental Indenture No. 16, dated as of June 1, 2014, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated June 5, 2014) | |||||||||||||
| - | Supplemental Indenture No. 17, dated as of October 1, 2015, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 1, 2015) | |||||||||||||
| - | Supplemental Indenture No. 18, dated as of March 1, 2016, to said Indenture (Exhibit 4(c) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 10, 2016) | |||||||||||||
| - | Supplemental Indenture No. 19, dated as of May 1, 2017, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated May 11, 2017) | |||||||||||||
199
| - | ||||||||||||||
| - | ||||||||||||||
| - | Supplemental Indenture No. 22, dated as of September 15, 2020, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated October 1, 2020) | |||||||||||||
| - | Supplemental Indenture No. 23, dated as of June 15, 2020, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 24, 2021) | |||||||||||||
| - | Supplemental Indenture No. 24, dated as of March 1, 2023, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 2, 2023) | |||||||||||||
| - | Supplemental Indenture No. 25, dated as of January 1, 2024, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated January 5, 2024) | |||||||||||||
| - | Pollution Control Facilities Loan Agreement, dated as of October 1, 2008, between Pennsylvania Economic Development Financing Authority and PPL Electric Utilities Corporation (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 31, 2008) | |||||||||||||
| - | Pollution Control Facilities Loan Agreement, dated as of March 1, 2016, between PPL Electric Utilities Corporation and the Lehigh County Industrial Development Authority (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 10, 2016) | |||||||||||||
| - | Pollution Control Facilities Loan Agreement, dated as of March 1, 2016, between PPL Electric Utilities Corporation and the Lehigh County Industrial Development Authority (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 10, 2016) | |||||||||||||
| - | ||||||||||||||
| Subordinated Indenture, dated as of March 1, 2007, between PPL Capital Funding, Inc., PPL Corporation and The Bank of New York, as Trustee (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2007) | ||||||||||||||
| - | Supplemental Indenture No. 1, dated as of March 1, 2007, to said Subordinated Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2007) | |||||||||||||
| - | Supplemental Indenture No. 4, dated as of March 15, 2013, to said Subordinated Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 15, 2013) | |||||||||||||
| - | ||||||||||||||
| Indenture, dated as of October 1, 2010, between Kentucky Utilities Company and The Bank of New York Mellon, as Trustee (Exhibit 4(q)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | ||||||||||||||
| - | Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(q)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Supplemental Indenture No. 3, dated as of November 1, 2013, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 13, 2013) | |||||||||||||
200
| - | Supplemental Indenture No. 4, dated as of September 1, 2015, to said Indenture (Exhibit 4(b) to Kentucky Utilities Company Form 8-K Report (File No. 1-3464) dated September 28, 2015) | |||||||||||||
| - | Supplemental Indenture No. 5, dated as of August 1, 2016, to said Indenture (Exhibit 4(b) to Kentucky Utilities Company Form 8-K Report (File No. 1-3464) dated August 26, 2016) | |||||||||||||
| - | Supplemental Indenture No. 6, dated as of August 1, 2018, to said Indenture (Exhibit 4(a) to PPL Corporation 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2018) | |||||||||||||
| - | Supplemental Indenture No. 7, dated as of March 1, 2019, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 1, 2019) | |||||||||||||
| - | Supplemental Indenture No. 8, dated as of May 15, 2020, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 3, 2020) | |||||||||||||
| - | Supplemental Indenture No. 9, dated as of March 1, 2023, to said Indenture (Exhibit 4(c) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2023) | |||||||||||||
| - | Supplemental Indenture No. 10, dated as of November 1, 2023, to said Indenture (Exhibit 4(e) to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2023) | |||||||||||||
| - | Indenture, dated as of October 1, 2010, between Louisville Gas and Electric Company and The Bank of New York Mellon, as Trustee (Exhibit 4(r)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(r)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(r)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Supplemental Indenture No. 3, dated as of November 1, 2013, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 13, 2013) | |||||||||||||
| - | Supplemental Indenture No. 4, dated as of September 1, 2015, to said Indenture (Exhibit 4(a) to Louisville Gas and Electric Company Form 8-K Report (File No. 1-2893) dated September 28, 2015) | |||||||||||||
| - | Supplemental Indenture No. 5, dated as of September 1, 2016, to said Indenture (Exhibit 4(b) to Louisville Gas and Electric Company Form 8-K (File No. 1-2893) dated September 15, 2016) | |||||||||||||
| - | Supplemental Indenture No. 6, dated as of May 15, 2017, to said Indenture (Exhibit 4(b) to Louisville Gas and Electric Company Form 8-K Report (File No. 1-2893) dated June 1, 2017) | |||||||||||||
| - | Supplemental Indenture No. 7, dated as of | |||||||||||||
| - | Supplemental Indenture No. 8, dated as of March 1, 2023, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2023) | |||||||||||||
| - | Supplemental Indenture No. 9, dated as of November 1, 2023, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2023) | |||||||||||||
201
| - | 2002 Series A Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated as of September 1, 2010 to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2002 Series B Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2004 Series A Carroll County Loan Agreement, dated October 1, 2004 and amended and restated as of September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2006 Series B Carroll County Loan Agreement, dated October 1, 2006 and amended and restated September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | ||||||||||||||
| 2008 Series A Carroll County Loan Agreement, dated August 1, 2008 by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | ||||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2016 Series A Carroll County Loan Agreement dated as of August 1, 2016 between Kentucky Utilities Company and the County of Carroll, Kentucky (Exhibit 4(a) to Kentucky Utilities Company Form 8-K Report (File No. 1-3464) dated August 26, 2016) | |||||||||||||
| - | ||||||||||||||
| 2002 Series A Mercer County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | ||||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2002 Series A Muhlenberg County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
202
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | ||||||||||||||
| - | 2023 Series A Trimble County Loan Agreement, dated | |||||||||||||
| - | ||||||||||||||
| 2001 Series A Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | ||||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2001 Series B Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2003 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated October 1, 2003, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2005 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated February 1, 2005 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2007 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated as of March 1, 2007 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
203
| - | 2007 Series B Louisville/Jefferson County Metro Government Amended and Restated Loan Agreement, dated November 1, 2010, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(oo) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2001 Series A Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(qq)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and | |||||||||||||
| - | 2017 Series A Trimble County Loan Agreement, dated as of June 1, 2017, by and between Louisville Gas and Electric Company and County of Trimble, Kentucky (Exhibit 4(a) to Louisville Gas and Electric Company Form 8-K Report (File No. 1-2893) dated June 1, 2017) | |||||||||||||
| - | 2001 Series B Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010) | |||||||||||||
| - | 2016 Series A Trimble County Loan Agreement dated as of September 1, 2016 by and between Louisville Gas and Electric Company and | |||||||||||||
| - | ||||||||||||||
| - | Description of PPL Corporation's common stock, par value $0.01 per share, as revised in February 2023 (Exhibit | |||||||||||||
| - | ||||||||||||||
| - | ||||||||||||||
| - | Indenture, dated as of March 22, 2010, by The Narragansett Electric Company and The Bank of New York Mellon as Trustee (Exhibit 4(a)-1 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | First Supplemental Indenture, dated as of March 22, 2010, to said Indenture (Exhibit 4(a)-2 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | Second Supplemental Indenture, dated as of March 22, 2010, to said Indenture (Exhibit 4(a)-3 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | Third Supplemental Indenture, dated as of December 10, 2012, to said Indenture (Exhibit 4(a)-4 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | ||||||||||||||
| - | Fifth Supplemental Indenture, dated as of April 9, 2020, to said Indenture (Exhibit 4(a)-6 to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | Indenture, dated as of February 24, 2023, by PPL Capital Funding, Inc., as | |||||||||||||
| - | ||||||||||||||
| Employee Matters Agreement, among PPL Corporation, Talen Energy Corporation, C/R Energy Jade, LLC, Sapphire Power Holdings LLC. and Raven Power Holdings LLC, dated as of June 9, 2014 (Exhibit 10.1 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated June 12, 2014) | ||||||||||||||
| - | ||||||||||||||
| - | ||||||||||||||
| - | ||||||||||||||
| - | Additional Confirmation of Forward Sale Transaction, dated May 8, 2018, between the Company and | |||||||||||||
| - | $1,250,000,000 Amended and Restated Revolving Credit Agreement dated as of December | |||||||||||||
| - | Amendment No. 1 to said Credit Agreement, dated as of March 30, 2023 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2023) | |||||||||||||
| - | $650,000,000 Amended and Restated Revolving Credit Agreement dated as of December 6, 2021 among PPL Electric Utilities Corporation, as Borrower, the Lenders party thereto and Wells Fargo, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2021) | |||||||||||||
| - | Amendment No. 1 to said Credit Agreement, dated as of March 30, 2023 (Exhibit 10(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2023) | |||||||||||||
| - | $500,000,000 Amended and Restated Revolving Credit Agreement dated as of December 6, 2021 among Louisville Gas and Electric Company, as Borrower, the Lenders party thereto and Wells Fargo, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.3 to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2021) | |||||||||||||
| - | Amendment No. 1 to said Credit Agreement, dated as of March 30, 2023 (Exhibit 10(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2023) | |||||||||||||
205
| - | $400,000,000 Amended and Restated Revolving Credit Agreement dated as of December 6, 2021 among Kentucky Utilities Company, as Borrower, the Lenders party thereto and Wells Fargo, National Association, as Administrative Agent, Issuing Lender and Swingline Lender (Exhibit 10.4 to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 6, 2021) | |||||||||||||
| - | Amendment No 1. to said Credit Agreement, dated as of March 30, 2023 (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended | |||||||||||||
| - | ||||||||||||||
| - | ||||||||||||||
| - | ||||||||||||||
| Amended and Restated Directors Deferred Compensation Plan, dated June 12, 2000 (Exhibit 10(h) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2000) | ||||||||||||||
| - | Amendment No. 1 to said Directors Deferred Compensation Plan, dated December 18, 2002 (Exhibit 10(m)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002) | |||||||||||||
| - | Amendment No. 2 to said Directors Deferred Compensation Plan, dated December 4, 2003 (Exhibit 10(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003) | |||||||||||||
| - | Amendment No. 3 to said Directors Deferred Compensation Plan, dated as of January 1, 2005 (Exhibit 10(cc)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2005) | |||||||||||||
| - | Amendment No. 4 to said Directors Deferred Compensation Plan, dated as of May 1, 2008 (Exhibit 10(x)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008) | |||||||||||||
| - | Amendment No. 5 to said Directors Deferred Compensation Plan, dated May 28, 2010 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2010) | |||||||||||||
| - | Amendment No. 6 to said Directors Deferred Compensation Plan, dated as of April 15, 2015 (Exhibit 10(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2015) | |||||||||||||
| - | PPL Corporation Directors Deferred Compensation Plan Trust Agreement, dated as of April 1, 2001, between PPL Corporation and Wachovia Bank, N.A. (as successor to First Union National Bank), as Trustee (Exhibit 10(hh)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012) | |||||||||||||
| - | PPL Officers Deferred Compensation Plan, PPL Supplemental Executive Retirement Plan and PPL Supplemental Compensation Pension Plan Trust Agreement, dated as of April 1, 2001, between PPL Corporation and Wachovia Bank, N.A. (as successor to First Union National Bank), as Trustee (Exhibit 10(hh)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012) | |||||||||||||
| - | PPL Revocable Employee Nonqualified Plans Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(c) to PPL Corporation Form 10-Q Report (File No. | |||||||||||||
206
| - | PPL Employee Change in Control Agreements Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007) | |||||||||||||
| - | PPL Revocable Director Nonqualified Plans Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(e) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007) | |||||||||||||
| - | Amended and Restated Officers Deferred Compensation Plan, dated December 8, 2003 (Exhibit 10(r) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003) | |||||||||||||
| - | Amendment No. 1 to said Officers Deferred Compensation Plan, dated as of January 1, 2005 (Exhibit 10(ee)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2005) | |||||||||||||
| - | Amendment No. 2 to said Officers Deferred Compensation Plan, dated as of January 22, 2007 (Exhibit 10(bb)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006) | |||||||||||||
| - | Amendment No. 3 to said Officers Deferred Compensation Plan, dated as of June 1, 2008 (Exhibit 10(z)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008) | |||||||||||||
| - | Amendment No. 4 to said Officers Deferred Compensation Plan, dated as of February 15, 2012 (Exhibit 10(ff)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2011) | |||||||||||||
| - | Amendment No. 5 to said Executive Deferred Compensation Plan, dated as of May 8, 2014 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2014) | |||||||||||||
| - | Amendment No. 6 to said Executive Deferred Compensation Plan, dated as of December 16, 2015 (Exhibit [_]10(q)-7 to PPL Corporation Form 10-K Report (File No. | |||||||||||||
| - | Amendment No. 7 to said Executive Deferred Compensation Plan, dated as of January 1, 2019 (Exhibit [_]10(x)-8 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2018) | |||||||||||||
| - | Amendment No. 8 to said Executive Deferred Compensation Plan, dated as of December 20, 2021 (Exhibit [_]10(n)-9 to PPL Corporation Form 10-K Report (File No. 11459) for the year ended December 31, 2021) | |||||||||||||
| - | Amendment No. 9 to said Executive Deferred Compensation Plan, dated as of December 28, 2022 (Exhibit [_]10(p)-10 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022) | |||||||||||||
| - | Amended and Restated Supplemental Executive Retirement Plan, dated December 8, 2003 (Exhibit 10(s) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003) | |||||||||||||
| - | Amendment No. 1 to said Supplemental Executive Retirement Plan, dated December 16, 2004 (Exhibit 99.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated December 17, 2004) | |||||||||||||
| - | Amendment No. 2 to said Supplemental Executive Retirement Plan, dated as of January 1, 2005 (Exhibit 10(ff)-3 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2005) | |||||||||||||
207
| - | Amendment No. 3 to said Supplemental Executive Retirement Plan, dated as of January 22, 2007 (Exhibit 10(cc)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006) | |||||||||||||
| - | Amendment No. 4 to said Supplemental Executive Retirement Plan, dated as of December 9, 2008 (Exhibit 10(aa)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008) | |||||||||||||
| - | Amendment No. 5 to said Supplemental Executive Retirement Plan, dated as of February 15, 2012 (Exhibit 10(gg)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2011) | |||||||||||||
| - | Amendment No. 6 to the Amended and Restated Supplemental Executive Retirement Plan, dated March 23, 2018 (Exhibit 10(g) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2018) | |||||||||||||
| - | Amended and Restated Incentive Compensation Plan, effective January 1, 2003 (Exhibit 10(p) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002) | |||||||||||||
| - | Amendment No. 1 to said Incentive Compensation Plan, dated as of January 1, 2005 (Exhibit 10(gg)-2 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2005) | |||||||||||||
| - | Amendment No. 2 to said Incentive Compensation Plan, dated as of January 26, 2007 (Exhibit 10(dd)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006) | |||||||||||||
| - | Amendment No. 3 to said Incentive Compensation Plan, dated as of March 21, 2007 (Exhibit 10(f) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007) | |||||||||||||
| - | Amendment No. 4 to said Incentive Compensation Plan, effective December 1, 2007 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2008) | |||||||||||||
| - | Amendment No. 5 to said Incentive Compensation Plan, dated as of December 16, 2008 (Exhibit 10(bb)-6 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2008) | |||||||||||||
| - | Form of Stock Option Agreement for stock option awards under the Incentive Compensation Plan (Exhibit 10(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated February 1, 2006) | |||||||||||||
| - | ||||||||||||||
| Form of Performance Unit Agreement for performance unit awards under the Incentive Compensation Plan (Exhibit 10(ss) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2007) | ||||||||||||||
| - | Amended and Restated Incentive Compensation Plan for Key Employees, effective | |||||||||||||
| - | Short-term Incentive Plan (Annex B to Proxy Statement of PPL Corporation, dated April 12, 2016) | |||||||||||||
| - | ||||||||||||||
| Form of Change in Control Severance Protection Agreement entered into between PPL Corporation and | ||||||||||||||
| - | PPL Corporation Amended and Restated 2012 Stock Incentive Plan, effective October 25, 2018 (Exhibit 10(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended | |||||||||||||
208
| - | ||||||||||||||
| Form of Performance Unit Agreement for performance unit awards under the Stock Incentive Plan (Exhibit 10(tt)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012) | ||||||||||||||
| - | Form of Performance Contingent Restricted Stock Unit Agreement for restricted stock unit awards under the Stock Incentive Plan (Exhibit 10(tt)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012) | |||||||||||||
| - | Form of Nonqualified Stock Option Agreement for stock option awards under the Stock Incentive Plan (Exhibit 10(tt)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2012) | |||||||||||||
| - | Form of Return on Equity Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan (Exhibit 10(dd)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2017) | |||||||||||||
| - | Form of Restricted Stock Unit Agreement under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022) | |||||||||||||
| - | Form of Total Shareholder Return Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-7 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022) | |||||||||||||
| - | Form of | |||||||||||||
| - | Form of Environmental, Social and Governance Performance Unit Agreement for performance units under the Amended and Restated 2012 Stock Incentive Plan, as approved on January 20, 2023 (Exhibit [_]10(v)-9 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2022) | |||||||||||||
| - | PPL Corporation Executive Severance Plan, effective as of July 26, 2012 (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2012) | |||||||||||||
| - | ||||||||||||||
| Form of Grant Letter dated May 29, 2015 (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 1, 2015) | ||||||||||||||
| - | Transition and Retirement Agreement dated August 12, 2021, by and among Paul W. Thompson, LG&E and KU Services Company, and PPL Corporation (Exhibit [_]10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2021) | |||||||||||||
| - | Offer Letter dated March 6, 2021, between PPL Corporation and | |||||||||||||
| - | Rhode Island Energy Retirement Plan, effective January 14, 2022 (Exhibit [_]10(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | Rhode Island Energy Executive Supplemental Retirement Plan, effective February 24, 2022 (Exhibit [_]10(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2022) | |||||||||||||
| - | Separation Agreement between Stephanie R. Raymond, PPL Electric Utilities Corporation, and | |||||||||||||
209
| - | Subsidiaries of PPL Corporation | |||||||||||||
| - | Consent of Deloitte & Touche LLP - PPL Corporation | |||||||||||||
| - | Consent of Deloitte & Touche LLP - PPL Electric Utilities Corporation | |||||||||||||
| - | ||||||||||||||
Consent of Deloitte & Touche LLP - Louisville Gas and Electric Company | ||||||||||||||
| - | Consent of Deloitte & Touche LLP - Kentucky Utilities Company | |||||||||||||
| - | Power of Attorney | |||||||||||||
| - | Certificate of PPL's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of PPL's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of PPL Electric's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of PPL Electric's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | ||||||||||||||
| Certificate of LG&E's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ||||||||||||||
| - | Certificate of LG&E's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of KU's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of KU's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of PPL's principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | Certificate of PPL Electric's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | ||||||||||||||
| Certificate of LG&E's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||||||||||||||
210
| - | Certificate of KU's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||||||||
| - | PPL Corporation Compensation Recoupment Policy, effective October 2, 2023 | |||||||||||||
| - | PPL Corporation and Subsidiaries Long-term Debt Schedule | |||||||||||||
| 101.INS | - | XBRL Instance Document for PPL Corporation, PPL | ||||||||||||
| 101.SCH | - | XBRL Taxonomy Extension Schema for PPL Corporation, PPL | ||||||||||||
| 101.CAL | - | XBRL Taxonomy Extension Calculation Linkbase for PPL Corporation, PPL | ||||||||||||
| 101.DEF | - | XBRL Taxonomy Extension Definition Linkbase for PPL Corporation, PPL | ||||||||||||
| 101.LAB | - | XBRL Taxonomy Extension Label Linkbase for PPL Corporation, PPL | ||||||||||||
| 101.PRE | - | XBRL Taxonomy Extension Presentation Linkbase for PPL Corporation, PPL | ||||||||||||
| 104 | The Cover Page Interactive Data File is formatted as Inline XBRL and contained in Exhibits 101. | |||||||||||||
211
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PPL Corporation
(Registrant)
| By /s/ Vincent Sorgi | |||||||||||||||||
| Vincent Sorgi - | |||||||||||||||||
| Chief Executive Officer | |||||||||||||||||
| Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. | |||||||||||||||||
| /s/ | |||||||||||||||||
| Chief Executive Officer | |||||||||||||||||
| and Director | |||||||||||||||||
| (Principal Executive Officer) | |||||||||||||||||
| /s/ | |||||||||||||||||
| Chief Financial Officer | |||||||||||||||||
| (Principal Financial Officer) | |||||||||||||||||
| /s/ | |||||||||||||||||
| Vice President and Controller | |||||||||||||||||
| (Principal Accounting Officer) | |||||||||||||||||
| Directors: | |||||||||||||||||
| Natica von Althann | |||||||||||||||||
| Keith H. Williamson | |||||||||||||||||
| Phoebe A. Wood | |||||||||||||||||
| Craig A. Rogerson | Armando Zagalo de Lima | ||||||||||||||||
| Linda G. Sullivan | |||||||||||||||||
| | |||||||||||||||||
| /s/ | |||||||||||||||||
212
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PPL Electric Utilities Corporation
(Registrant)
| By /s/ Christine M. Martin | ||||||||||||||||||
| Christine M. Martin - | ||||||||||||||||||
| Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. | ||||||||||||||||||
| President | ||||||||||||||||||
| (Principal Executive Officer) | ||||||||||||||||||
| /s/ Marlene C. Beers | ||||||||||||||||||
| Marlene C. Beers - | ||||||||||||||||||
Vice President and Controller (Principal Financial Officer and Principal Accounting Officer) | ||||||||||||||||||
| Directors: | ||||||||||||||||||
| /s/ | /s/ Wendy E. Stark | |||||||||||||||||
| Joseph P. Bergstein, Jr. | Wendy E. Stark | |||||||||||||||||
| /s/ Angela K. Gosman | /s/ Francis X. Sullivan | |||||||||||||||||
| Angela K. Gosman | Francis X. Sullivan | |||||||||||||||||
| /s/ Vincent Sorgi | ||||||||||||||||||
| Vincent Sorgi | ||||||||||||||||||
| Date: February | ||||||||||||||||||
213
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Louisville Gas and Electric Company
(Registrant)
| By /s/ John R. Crockett III | ||||||||||||||||||
| John R. Crockett III - | ||||||||||||||||||
| Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. | ||||||||||||||||||
| /s/ | ||||||||||||||||||
President | ||||||||||||||||||
| (Principal Executive Officer) | ||||||||||||||||||
| /s/ Christopher M. Garrett | ||||||||||||||||||
Vice President-Finance and Accounting (Principal Financial Officer and Principal Accounting Officer) | ||||||||||||||||||
| Directors: | ||||||||||||||||||
| /s/ | ||||||||||||||||||
/s/ Vincent Sorgi | ||||||||||||||||||
| Joseph P. Bergstein, Jr. | Vincent Sorgi | |||||||||||||||||
| /s/ John R. Crockett III | /s/ Wendy E. Stark | |||||||||||||||||
| Wendy E. Stark | ||||||||||||||||||
| /s/ Francis X. Sullivan | ||||||||||||||||||
| Angela K. Gosman | Francis X. Sullivan | |||||||||||||||||
| Date: February | ||||||||||||||||||
214
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Kentucky Utilities Company
(Registrant)
| By /s/ John R. Crockett III | ||||||||||||||||||
| John R. Crockett III - | ||||||||||||||||||
| Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. | ||||||||||||||||||
| /s/ | ||||||||||||||||||
President | ||||||||||||||||||
| (Principal Executive Officer) | ||||||||||||||||||
| /s/ Christopher M. Garrett | ||||||||||||||||||
Vice President-Finance and Accounting (Principal Financial Officer and Principal Accounting Officer) | ||||||||||||||||||
| Directors: | ||||||||||||||||||
| /s/ | ||||||||||||||||||
/s/ Vincent Sorgi | ||||||||||||||||||
| Joseph P. Bergstein, Jr. | Vincent Sorgi | |||||||||||||||||
| /s/ John R. Crockett III | /s/ Wendy E. Stark | |||||||||||||||||
| Wendy E. Stark | ||||||||||||||||||
| /s/ Francis X. Sullivan | ||||||||||||||||||
| Angela K. Gosman | Francis X. Sullivan | |||||||||||||||||
| Date: February | ||||||||||||||||||
215