Company Quick10K Filing
Quick10K
PPL
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$31.32 721 $22,580
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-04-03 Regulation FD
8-K 2019-03-18 Other Events, Exhibits
8-K 2019-03-18 Regulation FD, Exhibits
8-K 2019-03-08 Off-BS Arrangement, Other Events, Exhibits
8-K 2019-02-14 Earnings, Regulation FD, Exhibits
8-K 2019-02-14 Earnings, Exhibits
8-K 2019-01-25 Officers
8-K 2019-01-25 Officers
8-K 2019-01-10 Regulation FD
8-K 2018-12-18 Regulation FD
8-K 2018-12-10 Regulation FD
8-K 2018-11-30 Regulation FD, Exhibits
8-K 2018-11-08 Regulation FD, Exhibits
8-K 2018-11-07 Officers, Exhibits
8-K 2018-11-01 Earnings, Regulation FD, Exhibits
8-K 2018-10-29 Other Events
8-K 2018-09-28 Regulation FD
8-K 2018-09-19 Regulation FD, Other Events, Exhibits
8-K 2018-09-17 Regulation FD
8-K 2018-08-07 Earnings, Regulation FD, Exhibits
8-K 2018-06-11 Off-BS Arrangement, Other Events, Exhibits
8-K 2018-06-07 Regulation FD
8-K 2018-06-04 Regulation FD
8-K 2018-05-18 Shareholder Vote
8-K 2018-05-08 Enter Agreement, Other Events, Exhibits
8-K 2018-04-30 Regulation FD, Exhibits
8-K 2018-03-26 Other Events
8-K 2018-03-20 Regulation FD
8-K 2018-02-23 Other Events, Exhibits
8-K 2018-01-29 Regulation FD, Exhibits
8-K 2018-01-18 Officers, Regulation FD, Exhibits
8-K 2018-01-11 Regulation FD
8-K 2018-01-10 Off-BS Arrangement, Regulation FD
8-K 2018-01-08 Officers, Regulation FD, Exhibits
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WPG Washington Prime Group 897
REX Rex American Resources 520
RDHL Redhill Biopharma 241
SDPI Superior Drilling Products 28
OWCP OWC Pharmaceutical Research 0
GLNS Golden Star Resource 0
PPL 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for The Registrant's Common Equity,
Item 6. Selected Financial and Operating Data
Item 6 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 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
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.
Item 11. Executive Compensation
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
Item 12 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 13. Certain Relationships and Related Transactions, and Director Independence
Item 13 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
Part IV
Item 15. Exhibits, Financial Statement Schedules
EX-4.A-4 ppl-12312018ex4ax4.htm
EX-4.A-3 ppl-12312018ex4ax3.htm
EX-4.D-6 ppl-12312018ex4dx6.htm
EX-10.B-5 ppl-12312018ex10bx5.htm
EX-10.KK-3 ppl-12312018ex10kkx3.htm
EX-10.KK-2 ppl-12312018ex10kkx2.htm
EX-10.KK-1 ppl-12312018ex10kkx1.htm
EX-10.U-8 ppl-12312018ex10xx8.htm
EX-21 ppl-12312018ex21.htm
EX-23.A ppl-12312018ex23a.htm
EX-23.B ppl-12312018ex23b.htm
EX-23.C ppl-12312018ex23c.htm
EX-23.D ppl-12312018ex23d.htm
EX-23.E ppl-12312018ex23e.htm
EX-24 ppl-12312018ex24.htm
EX-31.A ppl-12312018ex31a.htm
EX-31.B ppl-12312018ex31b.htm
EX-31.C ppl-12312018ex31c.htm
EX-31.D ppl-12312018ex31d.htm
EX-31.E ppl-12312018ex31e.htm
EX-31.F ppl-12312018ex31f.htm
EX-31.G ppl-12312018ex31g.htm
EX-31.H ppl-12312018ex31h.htm
EX-31.I ppl-12312018ex31i.htm
EX-31.J ppl-12312018ex31j.htm
EX-32.A ppl-12312018ex32a.htm
EX-32.B ppl-12312018ex32b.htm
EX-32.C ppl-12312018ex32c.htm
EX-32.D ppl-12312018ex32d.htm
EX-32.E ppl-12312018ex32e.htm
EX-99.A ppl-12312018ex99a.htm

PPL Earnings 2018-12-31

PPL 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 ppl-1231201810k.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2018
OR
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period from _________ to ___________
 
Commission File
Number
Registrant; State of Incorporation;
Address and Telephone Number
IRS Employer
Identification No.
 
 
 
1-11459
PPL Corporation
(Exact name of Registrant as specified in its charter)
(Pennsylvania)
Two North Ninth Street
Allentown, PA 18101-1179
(610) 774-5151
23-2758192
 
 
 
1-905
PPL Electric Utilities Corporation
(Exact name of Registrant as specified in its charter)
(Pennsylvania)
Two North Ninth Street
Allentown, PA 18101-1179
(610) 774-5151
23-0959590
 
 
 
333-173665
LG&E and KU Energy LLC
(Exact name of Registrant as specified in its charter)
(Kentucky)
220 West Main Street
Louisville, Kentucky 40202-1377
(502) 627-2000
20-0523163
 
 
 
1-2893
Louisville Gas and Electric Company
(Exact name of Registrant as specified in its charter)
(Kentucky)
220 West Main Street
Louisville, Kentucky 40202-1377
(502) 627-2000
61-0264150
 
 
 
1-3464
Kentucky Utilities Company
(Exact name of Registrant as specified in its charter)
(Kentucky and Virginia)
One Quality Street
Lexington, Kentucky 40507-1462
(502) 627-2000
61-0247570



Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
 
 
 
Common Stock of PPL Corporation
 
New York Stock Exchange
 
 
 
Junior Subordinated Notes of PPL Capital Funding, Inc.
 
 
2007 Series A due 2067
 
New York Stock Exchange
2013 Series B due 2073
 
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Common Stock of PPL Electric Utilities Corporation
 
Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act. 
PPL Corporation
Yes  X   
No        
PPL Electric Utilities Corporation
Yes        
No  X   
LG&E and KU Energy LLC
Yes        
No  X   
Louisville Gas and Electric Company
Yes        
No  X   
Kentucky Utilities Company
Yes        
No  X   
 
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 
PPL Corporation
Yes        
No  X   
PPL Electric Utilities Corporation
Yes        
No  X   
LG&E and KU Energy LLC
Yes        
No  X   
Louisville Gas and Electric Company
Yes        
No  X   
Kentucky Utilities Company
Yes        
No  X   
 
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
PPL Corporation
Yes  X   
No        
PPL Electric Utilities Corporation
Yes  X   
No        
LG&E and KU Energy LLC
Yes  X   
No        
Louisville Gas and Electric Company
Yes  X   
No        
Kentucky Utilities Company
Yes  X   
No        
 
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
PPL Corporation
Yes   X  
No        
PPL Electric Utilities Corporation
Yes   X  
No        
LG&E and KU Energy LLC
Yes   X  
No        
Louisville Gas and Electric Company
Yes   X  
No        
Kentucky Utilities Company
Yes   X  
No        




Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
PPL Corporation
[     ]
 
 
PPL Electric Utilities Corporation
[ X ]
 
 
LG&E and KU Energy LLC
[ X ]
 
 
Louisville Gas and Electric Company
[ X ]
 
 
Kentucky Utilities Company
[ X ]
 
 
 
Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, smaller reporting companies or emerging growth companies. See definition of "large accelerated filer," "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. 
 
Large accelerated
filer
Accelerated
filer
Non-accelerated
filer
Smaller reporting
company
Emerging growth company
PPL Corporation
[ X ]
[     ]
[     ]
[     ]
[     ]
PPL Electric Utilities Corporation
[     ]
[     ]
[ X ]
[     ]
[     ]
LG&E and KU Energy LLC
[     ]
[     ]
[ X ]
[     ]
[     ]
Louisville Gas and Electric Company
[     ]
[     ]
[ X ]
[     ]
[     ]
Kentucky Utilities Company
[     ]
[     ]
[ X ]
[     ]
[     ]
 
If emerging growth companies, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
PPL Corporation
[     ]
 
 
 
 
PPL Electric Utilities Corporation
[     ]
 
 
 
 
LG&E and KU Energy LLC
[     ]
 
 
 
 
Louisville Gas and Electric Company
[     ]
 
 
 
 
Kentucky Utilities Company
[     ]
 
 
 
 

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act). 
PPL Corporation
Yes        
No  X   
PPL Electric Utilities Corporation
Yes        
No  X   
LG&E and KU Energy LLC
Yes        
No  X   
Louisville Gas and Electric Company
Yes        
No  X   
Kentucky Utilities Company
Yes        
No  X   
 
As of June 29, 2018, PPL Corporation had 699,127,940 shares of its $0.01 par value Common Stock outstanding. The aggregate market value of these common shares (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $19,960,102,687. As of January 31, 2019, PPL Corporation had 720,936,897 shares of its $0.01 par value Common Stock outstanding.
 
As of January 31, 2019, PPL Corporation held all 66,368,056 outstanding common shares, no par value, of PPL Electric Utilities Corporation.
 
PPL Corporation directly holds all of the membership interests in LG&E and KU Energy LLC.
 
As of January 31, 2019, LG&E and KU Energy LLC held all 21,294,223 outstanding common shares, no par value, of Louisville Gas and Electric Company.
 
As of January 31, 2019, LG&E and KU Energy LLC held all 37,817,878 outstanding common shares, no par value, of Kentucky Utilities Company.
 



PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and are therefore filing this form with the reduced disclosure format.
 
Documents incorporated by reference:
 
PPL Corporation has incorporated herein by reference certain sections of PPL Corporation's 2019 Notice of Annual Meeting and Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 2018. Such Statements will provide the information required by Part III of this Report.




PPL CORPORATION
PPL ELECTRIC UTILITIES CORPORATION
LG&E AND KU ENERGY LLC
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, 2018
 
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.
 
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
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
LG&E and KU Energy LLC and Subsidiaries
 
 
 
 
 
 
 
 
 
 
 
 
 
Louisville Gas and Electric Company
 
 
 
 
 
 
 
 
 
 
 
Kentucky Utilities Company
 
 
 
 
 
 
 
 
 
 
 
 
 



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
 
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 LKE and its subsidiaries.
 
PPL - PPL Corporation, the parent holding company of PPL Electric, PPL Energy Funding, PPL Capital Funding, LKE 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 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 EU Services - PPL EU Services Corporation, a subsidiary of PPL that provides administrative, management and support services primarily to PPL Electric.
 
PPL Global - PPL Global, LLC, a subsidiary of PPL Energy Funding that, primarily through its subsidiaries, owns and operates WPD, PPL's regulated electricity distribution businesses in the U.K.
 
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 indirect U.K. subsidiary of PPL Global. Following a reorganization in October 2015 and October 2017, PPL WPD Limited is an indirect parent to WPD plc having previously been a sister company.

Safari Energy - Safari Energy, LLC, an indirect subsidiary of PPL, acquired in June 2018, that provides solar energy solutions for commercial customers in the U.S.
 
WPD - refers to PPL WPD Limited and its subsidiaries.
 
WPD (East Midlands) - Western Power Distribution (East Midlands) plc, a British regional electricity distribution utility company.
 
WPD plc - Western Power Distribution plc, an indirect U.K. 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 Midlands - refers to WPD (East Midlands) and WPD (West Midlands), collectively.
 
WPD (South Wales) - Western Power Distribution (South Wales) plc, a British regional electricity distribution utility company.
 
WPD (South West) - Western Power Distribution (South West) plc, a British regional electricity distribution utility company.
 

i


WPD (West Midlands) - Western Power Distribution (West Midlands) plc, a British regional electricity distribution utility company.
 
WKE - Western Kentucky Energy Corp., a subsidiary of LKE that leased certain non-regulated utility generating plants in western Kentucky until July 2009. 

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 PUC 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.

Adjusted Gross Margins - a non-GAAP financial measure of performance used in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A).

Advanced Metering System - meters and meter-reading systems that provide two-way communication capabilities, which communicate usage and other relevant data to LG&E and KU at regular intervals, and are also able to receive information from LG&E and KU, such as software upgrades and requests to provide meter readings in real time.

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.

AIP - annual iteration process.
 
AOCI - accumulated other comprehensive income or loss.
 
ARO - asset retirement obligation.
 
ATM Program - at-the-market stock offering program.

Cane Run Unit 7 - a natural gas combined-cycle 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.
 
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.

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.
 
COBRA - Consolidated Omnibus Budget Reconciliation Act, which provides individuals the option to temporarily continue employer group health insurance coverage after termination of employment.

ii


 
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 facility for furnishing of utility service to the public.
 
CPIH - Consumer Price Index including owner-occupiers' housing costs. An aggregate measure of changes in the cost of living in the U.K., including a measure of owner-occupiers' housing costs.

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.
 
Depreciation not normalized - the flow-through income tax impact related to the state regulatory treatment of depreciation-related timing differences.
 
DNO - Distribution Network Operator in the U.K.
 
DOJ - U.S. Department of Justice.
 
DPCR5 - Distribution Price Control Review 5, the U.K. five-year rate review period applicable to WPD that commenced April 1, 2010.
 
DRIP - PPL Amended and Restated Dividend Reinvestment and Direct Stock Purchase Plan.
 
DSIC - Distribution System Improvement Charge. Authorized under Act 11, which is an alternative ratemaking mechanism providing more-timely cost recovery of qualifying distribution system capital expenditures.
 
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.
 
DUoS - Distribution Use of System. The charge to licensed third party energy suppliers who are WPD's customers and use WPD's networks to deliver electricity to their customers, the end-users.
 
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-products from the production of energy from coal.
 
ELG(s) - Effluent Limitation Guidelines, regulations promulgated by the EPA.
 
EPA - Environmental Protection Agency, a U.S. government agency.
 
EPS - earnings per share.
 
Fast pot - Under RIIO-ED1, Totex costs that are recovered in the period they are incurred.

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.

iii


 
GBP - British pound sterling.
 
GHG(s) - greenhouse gas(es).
 
GLT - gas line tracker. The KPSC approved mechanism for LG&E's recovery of costs associated with gas transmission lines, gas service lines, gas risers, leak mitigation, and gas main replacements.
  
GWh - gigawatt-hour, one million kilowatt hours.

HB 487 - House Bill 487. Comprehensive Kentucky state tax legislation enacted on April 27, 2018.
 
IBEW - International Brotherhood of Electrical Workers.
 
ICP - The PPL Incentive Compensation Plan. This plan provides for incentive compensation to PPL's executive officers and certain other senior executives. New awards under the ICP were suspended in 2012 upon adoption of PPL's 2012 Stock Incentive Plan.
 
ICPKE - The PPL Incentive Compensation Plan for Key Employees. The ICPKE provides for incentive compensation to certain employees below the level of senior executive.
 
IRS - Internal Revenue Service, a U.S. government agency.

IT - Information Technology.
 
KPSC - Kentucky Public Service Commission, the state agency that has jurisdiction over the regulation of rates and service of utilities in Kentucky.
 
KU 2010 Mortgage Indenture - KU's Indenture, dated as of October 1, 2010, to The Bank of New York Mellon, as supplemented.
 
kV - kilovolt.
 
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.
 
LIBOR - London Interbank Offered Rate.

MATS - Mercury and Air Toxics Standards, regulations promulgated by the EPA.

Mcf - one thousand cubic feet, a unit of measure for natural gas.

MMBtu - one million British Thermal Units.
 
MOD - a mechanism applied in the U.K. to adjust allowed base revenue in future periods for differences in prior periods between actual values and those in the agreed business plan.
 
Moody's - Moody's Investors Service, Inc., a credit rating agency.

MPR- Mid-period review, a review of output requirements in RIIO-ED1 covering material changes to existing outputs that can be justified by clear changes in government policy or new outputs that may be needed to meet the needs of consumers and other network users. On April 30, 2018, Ofgem decided not to engage in a mid-period review of the RIIO-ED1 price-control period.

iv


 
MW - megawatt, one thousand kilowatts.
 
NAAQS - National Ambient Air Quality Standards periodically adopted pursuant to the Clean Air Act.
 
NERC - North American Electric Reliability Corporation.

New Source Review - a Clean Air Act program that requires industrial facilities to install updated pollution control equipment when they are built or when making a modification that increases emissions beyond certain allowable thresholds.

NGCC - natural gas-fired combined-cycle generating plant.
 
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.
 
NRC - Nuclear Regulatory Commission, the U.S. federal agency that regulates nuclear power facilities.
 
OCI - other comprehensive income or loss.
 
Ofgem - Office of Gas and Electricity Markets, the British agency that regulates transmission, distribution and wholesale sales of electricity and gas and related matters.
 
OVEC - Ohio Valley Electric Corporation, located in Piketon, Ohio, an entity in which LKE indirectly owns an 8.13% interest (consists of LG&E's 5.63% and KU's 2.50% interests), which is recorded at cost. OVEC owns and operates two coal-fired power plants, the Kyger Creek plant in Ohio and the Clifty Creek plant in Indiana, with combined capacities of 2,120 MW.
 
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 Exchange Utility 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.
 
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.
 
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 EnergyPlus - prior to the June 1, 2015 spinoff of PPL Energy Supply, LLC, 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 Energy Supply - prior to the June 1, 2015 spinoff, PPL Energy Supply, LLC, a subsidiary of PPL Energy Funding and the parent company of PPL EnergyPlus and other subsidiaries.

PPL Montana - Prior to the June 1, 2015 spinoff of PPL Energy Supply, PPL Montana, LLC, an indirect subsidiary of PPL Energy Supply that generated electricity for wholesale sales in Montana and the Pacific Northwest.
 
PUC - Pennsylvania Public Utility Commission, the state agency that regulates certain ratemaking, services, accounting and operations of Pennsylvania utilities.


v


RAV - regulatory asset value. This term, used within the U.K. regulatory environment, is also commonly known as RAB or regulatory asset base. RAV is based on historical investment costs at time of privatization, plus subsequent allowed additions less annual regulatory depreciation, and represents the value on which DNOs earn a return in accordance with the regulatory cost of capital. RAV is indexed to Retail Price Index (RPI) in order to allow for the effects of inflation. RAV additions have been based on a percentage of annual total expenditures that have a long-term benefit to WPD (similar to capital projects for the U.S. regulated businesses that are generally included in rate base).
 
RCRA - Resource Conservation and Recovery Act of 1976.
 
RECs - renewable energy credits.
 
Registrant(s) - refers to the Registrants named on the cover of this Report (each a "Registrant" and collectively, the "Registrants").
 
Regulation S-X - SEC regulation governing the form and content of and requirements for financial statements required to be filed pursuant to the federal securities laws.
 
RFC - ReliabilityFirst Corporation, one of eight regional entities with delegated authority from NERC that work to safeguard the reliability of the bulk power systems throughout North America.
 
RIIO - Ofgem's framework for setting U.K. regulated gas and electric utility price controls which stands for "Revenues = Incentive + Innovation + Outputs." RIIO-1 refers to the first generation of price controls under the RIIO framework. RIIO-ED1 refers to the RIIO regulatory price control applicable to the operators of U.K. electricity distribution networks, the duration of which is April 2015 through March 2023. RIIO-2 refers to the second generation of price controls under the RIIO framework. RIIO-ED2 refers to the second generation of the RIIO regulatory price control applicable to the operators of U.K. electricity distribution networks, which will begin in April 2023.
 
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.

RPI - retail price index, is a measure of inflation in the United Kingdom published monthly by the Office for National Statistics.
 
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.

SCRs - selective catalytic reduction, a pollution control process for the removal of nitrogen oxide from exhaust gas.

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.
 
SERC - SERC Reliability Corporation, one of eight regional entities with delegated authority from NERC that work to safeguard the reliability of the bulk power systems throughout North America.
 
SIP - PPL Corporation's Amended and Restated 2012 Stock Incentive Plan.
 
Slow pot - Under RIIO-ED1, Totex costs that are added (capitalized) to RAV and recovered through depreciation over a 20 to 45 year period.
 
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.

S&P - S&P Global Ratings, a credit rating agency.
 
Superfund - federal environmental statute that addresses remediation of contaminated sites; states also have similar statutes.

vi


 
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 new name of PPL EnergyPlus subsequent to the 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'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.
 
Totex (total expenditures) - Totex generally consists of all the expenditures relating to WPD's regulated activities with the exception of certain specified expenditure items (Ofgem fees, National Grid transmission charges, property and corporate income taxes, pension deficit funding and cost of capital). The annual net additions to RAV are calculated as a percentage of Totex. Totex can be viewed as the aggregate net network investment, net network operating costs and indirect costs, less any cash proceeds from the sale of assets and scrap.

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.

TRU - a mechanism applied in the U.K. to true-up inflation estimates used in determining base revenue.

U.K. Finance Act - refers to the U.K. Finance Act of 2016, enacted in September 2016, which reduced the U.K. statutory corporate income tax rate from 19% to 17%, effective April 1, 2020.
 
VEBA - Voluntary Employee Beneficiary Association. A tax-exempt trust under the Internal Revenue Code Section 501 (c)(9) used by employees to fund and 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.


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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:
 
the outcome of rate cases or other cost recovery or revenue proceedings;
changes in U.S. state or federal or U.K. tax laws or regulations, including the TCJA;
the direct or indirect effects on PPL or its subsidiaries or business systems of cyber-based intrusion or the threat of cyber attacks;
significant decreases in demand for electricity in the U.S.;
expansion of alternative and distributed sources of electricity generation and storage;
changes in foreign currency exchange rates for British pound sterling and the related impact on unrealized gains and losses on PPL's foreign currency economic hedges;
the effectiveness of our risk management programs, including foreign currency and interest rate hedging;
non-achievement by WPD of performance targets set by Ofgem;
the effect of changes in RPI on WPD's revenues and index linked debt;
developments related to ongoing negotiations regarding the U.K.'s intent to withdraw from European Union and any actions in response thereto;
the amount of WPD's pension deficit funding recovered in revenues after March 31, 2021, following the next triennial pension review to begin in March 2019;
defaults by counterparties or suppliers for energy, capacity, coal, natural gas or key commodities, goods or services;
capital market conditions, including the availability of capital or credit, changes in interest rates and certain economic indices, and decisions regarding capital structure;
a material decline in the market value of PPL's equity;
significant decreases in the fair value of debt and equity securities and its impact on the value of assets in defined benefit plans, and the potential cash funding requirements if fair value declines;
interest rates and their effect on pension and retiree medical liabilities, ARO liabilities and interest payable on certain debt securities;
volatility in or the impact of other changes in financial markets and economic conditions;
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;
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;
weather and other conditions affecting generation, transmission and distribution operations, operating costs and customer energy use;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events or other similar occurrences;
war, armed conflicts, terrorist attacks, or similar disruptive events;
changes in political, regulatory or economic conditions in states, regions or countries where the Registrants or their subsidiaries conduct business;
receipt of necessary governmental permits and approvals;
new 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 any business or industry restructuring;
development of new projects, markets and technologies;
performance of new ventures;
business dispositions or acquisitions and our ability to realize expected benefits from such business transactions;


1


collective labor bargaining negotiations; and
the outcome of litigation against the Registrants and their subsidiaries.

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.

 


2


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. PPL, through its regulated utility subsidiaries, delivers electricity to customers in the U.K., Pennsylvania, Kentucky and Virginia; delivers natural gas to customers in Kentucky; and generates electricity from power plants in Kentucky.
 
PPL's principal subsidiaries at December 31, 2018 are shown below (* denotes a Registrant).
 
 
 
 
 
 
 
 
PPL Corporation*
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PPL Capital Funding
 Provides financing for the operations of PPL and certain subsidiaries
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PPL Global
 Engages in the regulated distribution of electricity in the U.K.
 
 
LKE*
 
 
 
PPL Electric*
 Engages in the regulated transmission and distribution of electricity in Pennsylvania
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LG&E*
 Engages in the regulated generation, transmission, distribution and sale of electricity and the regulated distribution and sale of natural gas in Kentucky
 
 
KU*
 Engages in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.K.
Regulated Segment
 
 
Kentucky
Regulated Segment
 
 
Pennsylvania
Regulated Segment
 
 
PPL Global is not a registrant. Unaudited annual consolidated financial statements for the U.K. Regulated Segment are furnished contemporaneously with this report on a Form 8-K with the SEC.

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 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, 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.
 
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 engages in the distribution and sale of natural gas. LG&E and KU maintain separate corporate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name. LKE, formed in 2003, is the successor to a Kentucky entity incorporated in 1989.


3


 
Louisville Gas and Electric Company, headquartered in Louisville, Kentucky, is a wholly owned subsidiary of LKE and a regulated utility engaged in the generation, transmission, distribution and sale of electricity and distribution and sale of natural gas in Kentucky. LG&E is subject to regulation as a public utility by the KPSC, and certain of its transmission activities are subject to the jurisdiction of the FERC under the Federal Power Act. LG&E was incorporated in 1913.

Kentucky Utilities Company, headquartered in Lexington, Kentucky, is a wholly owned subsidiary of LKE and a regulated utility engaged in the generation, transmission, distribution and sale of electricity in Kentucky and Virginia. KU is subject to regulation as a public utility by the KPSC and the VSCC, and certain of its transmission and wholesale power activities are subject to the jurisdiction 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. 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' results primarily represent the results of its related subsidiary Registrants, except that the reportable segments are also allocated certain corporate level financing costs that are not included in the results of the applicable subsidiary Registrants. PPL also has corporate and other costs which primarily include financing costs incurred at the corporate level that have not been allocated or assigned to the segments, as well as certain other unallocated costs. The financial results of Safari Energy are also reported within Corporate and Other.

A comparison of PPL's three regulated segments is shown below.
 
 
 
Kentucky
 
Pennsylvania
 
U.K. Regulated
 
Regulated
 
Regulated
For the year ended December 31, 2018:
 
 
 
 
 
Operating Revenues (in billions)
$
2.3

 
$
3.2

 
$
2.3

Net Income (in millions)
$
1,114

 
$
411

 
$
431

Electricity delivered (GWh)
74,181

 
33,650

 
37,497

At December 31, 2018:
 
 
 

 
 

Regulatory Asset Base (in billions) (a)
$
9.7

 
$
9.8

 
$
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 RAV for U.K. Regulated, capitalization for Kentucky Regulated and rate base for Pennsylvania Regulated.
 
See Note 2 to the Financial Statements for additional financial information about the segments.
 
(PPL Electric, LKE, LG&E and KU)
 
PPL Electric has two operating segments that are aggregated into a single reportable segment. LKE, LG&E and KU are individually single operating and reportable segments.

U.K. Regulated Segment (PPL)

Consists of PPL Global, which primarily includes WPD's regulated electricity distribution operations, the results of hedging the translation of WPD's earnings from British pound sterling into U.S. dollars, and certain costs, such as U.S. income taxes, administrative costs and acquisition-related financing costs.

WPD operates four of the 14 Ofgem regulated DNOs providing electricity service in the U.K. through indirect wholly owned subsidiaries: WPD (South West), WPD (South Wales), WPD (East Midlands) and WPD (West Midlands). The number of network customers (end-users) served by WPD totals 7.9 million across 21,600 square miles in south Wales and southwest and central England.
 
Revenues, in millions, for the years ended December 31 are shown below. 


4


 
2018
 
2017
 
2016
Operating Revenues (a)
$
2,268

 
$
2,091

 
$
2,207

 
(a)
WPD’s Operating Revenues are translated from GBP to U.S. dollars using the average GBP to U.S. dollar exchange rates in effect each month. The annual weighted average of the monthly GBP to U.S. dollar exchange rates used for the years ended December 31, 2018, 2017 and 2016 were $1.34 per GBP, $1.28 per GBP and $1.37 per GBP.

Franchise and Licenses

WPD’s operations are regulated by Ofgem under the direction of the Gas and Electricity Markets Authority. Ofgem is a non-ministerial government department and an independent National Regulatory Authority that is responsible for protecting the interests of existing and future electricity and natural gas consumers. The Electricity Act 1989 provides the fundamental framework for electricity companies and established licenses that require each of the DNOs to develop, maintain and operate efficient distribution networks. WPD’s operations are regulated under these licenses which set the outputs WPD needs to deliver for their customers and associated revenues WPD is allowed to earn. WPD operates under a regulatory year that begins April 1 and ends March 31 of each year.

Ofgem has the formal power to propose modifications to each distribution license; however licensees can appeal such changes to the U.K.’s Competition and Markets Authority in the event of a disagreement with the regulator. Generally, any potential changes to these licenses are reviewed with stakeholders in a formal regulatory consultation process prior to a formal change proposal.

Competition

Although WPD operates in non-exclusive concession areas in the U.K., it currently faces little competition with respect to end-users connected to its network. WPD's four DNOs are, therefore, regulated monopolies, which operate under regulatory price controls.

Customers
 
WPD provides regulated electricity distribution services to licensed third party energy suppliers who use WPD's networks to transfer electricity to their customers, the end-users. WPD bills energy suppliers for this service and the supplier is responsible for billing its end-users. Ofgem requires that all licensed electricity distributors and suppliers become parties to the Distribution Connection and Use of System Agreement. This agreement specifies how creditworthiness will be determined and, as a result, whether the supplier needs to collateralize its payment obligations.

WPD’s costs make up approximately 17% of a U.K. end-user customer’s electricity bill.

U.K. Regulation and Rates

Overview

Ofgem has adopted a price control regulatory framework with a balanced objective of enhancing and developing electricity networks for the future, controlling costs to customers and allowing DNOs, such as WPD's DNOs, to earn a fair return on their investments. This regulatory structure is focused on outputs and performance in contrast to traditional U.S. utility ratemaking that operates under a cost recovery model. Price controls are established based on long-term business plans developed by each DNO with substantial input from its stakeholders. To measure the outputs and performance, each DNO business plan includes incentive targets that allow for increases and/or reductions in revenues based on operational performance, which are intended to align returns with quality of service, innovation and customer satisfaction.

For comparative purposes, amounts listed below are in British pounds sterling, nominal prices and in calendar years unless otherwise noted.

Key Ratemaking Mechanisms

PPL believes the U.K. electricity utility model is a premium jurisdiction in which to do business due to its significant stakeholder engagement, incentive-based structure and high-quality ratemaking mechanisms.


5



Current Price Control: RIIO-ED1

WPD is currently operating under an eight-year price control period called RIIO-ED1, which commenced for electricity distribution companies on April 1, 2015. The regulatory framework is based on an updated approach for sustainable network regulation known as the "RIIO" model where Revenue = Incentives + Innovation + Outputs.

The RIIO framework allowed for an MPR. On April 30, 2018, Ofgem announced its decision not to conduct an MPR of the RIIO-ED1 price control period.

In coordination with numerous stakeholders, WPD developed its business plans for RIIO-ED1 building off its historical track record and long-term strategy of delivering industry-leading levels of performance at an efficient level of cost. As a result, all four of WPD’s DNOs' business plans were accepted by Ofgem as "well justified" and were "fast-tracked" ahead of all of the other DNOs. WPD's DNOs were rewarded for being fast-tracked with preferential financial incentives, a higher return on equity and higher cost savings retention under their business plans as discussed further below. However, an unintended consequence of being fast-tracked resulted in WPD being disadvantaged from a cost of debt recovery standpoint as further discussed within “(2) Real Return on capital from RAV” below.

WPD's combined RIIO-ED1 business plans as accepted by Ofgem included funding for total expenditures of approximately £12.8 billion (nominal) over the eight-year period, broken down as follows:

Totex - £8.5 billion (£6.8 billion recovered as additions to RAV over time ("Slow pot"); £1.7 billion recovered in the year spent in the plan ("Fast pot"));
Pension deficit funding - £1.2 billion;
Cost of debt recovery - £1.0 billion;
Pass Through Charges - £1.6 billion (Property taxes, Ofgem fees and National Grid transmissions charges); and
Corporate income taxes recovery - £0.5 billion.

The chart below illustrates the building blocks of allowed revenue and GAAP net income for the U.K. Regulated Segment. The revenue components are shown in either 2012/13 prices or nominal prices, consistent with the formulas Ofgem established for RIIO-ED1. The reference numbers included in each block correspond with the descriptions that follow.
ukcharta02.jpg
(a)
Primarily pension deficit funding, pass through costs, profiling adjustments and legacy price control adjustments.
(b)
Primarily pass through true-ups and £5 per residential customer reduction completed in the regulatory year ended March 31, 2017.
(c)
Reference Form 8-K filed February 14, 2019 for U.K. Regulated Segment GAAP Statement of Income component values.
(d)
Includes the service cost component of GAAP pension costs/income. See “Defined Benefits, Net periodic defined benefit costs (credits)” in Note 11 to the Financial Statements.
(e)
Primarily property taxes.
(f)
Primarily includes the non-service cost (credit) components of GAAP pension costs/income and gains and losses on foreign currency hedges.
(g)
Includes WPD interest and $32 million of allocated interest expense to finance the acquisition of WPD Midlands.
(h)
GAAP income taxes represent an effective tax rate of 17% for 2018, 19% for 2017, 16% for 2016 and approximately 17% going forward.



6


(1) Base Revenue

The base revenue that a DNO can collect in each year of the current price control period is the sum of the following which are discussed further below:

a return on capital from RAV;
a return of capital from RAV (i.e., depreciation);
the Fast pot recovery, see discussion “(4) Expenditure efficiency mechanisms” below;
an allowance for cash taxes paid less a potential reduction for tax benefits from excess leverage if a DNO is levered more than 65% Debt/RAV;
pension deficit funding;
certain pass-through costs over which the DNO has no control;
profiling adjustments, see discussion “(6) Other revenue included in base revenue” below;
certain legacy price control adjustments from preceding price control periods, including the information quality incentive (also known as the rolling RAV incentive); and
fast-track incentive - because WPD's four DNOs were fast-tracked through the price control review process for RIIO-ED1, their base revenue also includes the fast-track incentive.

(2) Real Return on capital from RAV

Real-time returns on cost of regulated equity (real) - Ofgem establishes an allowed return on regulated equity that DNOs earn in their base business plan revenues as a consideration of the financial parameters for each RIIO-ED1 business plan. For WPD, the base cost of equity collected in revenues was set at 6.4% (real). Base equity returns exclude inflation adjustments, allowances for incentive rewards/penalties and over/under collections driven by cost efficiencies. WPD’s base equity returns are calculated using an equity ratio of 35% of RAV at the DNO. The equity ratio was reviewed and set during the RIIO-ED1 business plan process taking various stakeholder impacts into consideration such as costs to consumers, credit ratings and investor needs. The amounts of base real equity return for 2018, 2017 and 2016 were £160 million, £151 million and £144 million.

Indexed cost of debt recovery (real) - As part of WPD’s fast-track agreement with Ofgem for RIIO-ED1, WPD collects in revenues an assumed real cost of debt that is derived from a historical 10-year bond index (iBoxx) and adjusted annually for inflation. This calculated real cost of debt is then applied to 65% of RAV at the DNOs to determine the cost of debt revenue recovery. The cost of debt was set at 2.55% in the original "well justified" business plans. The recovery amounts are trued up annually as a component of the MOD true-up mechanism described within "(9) MOD and Inflation True-Up (TRU)" below.

As discussed above, WPD’s cost of debt revenue allowances are derived from using a rolling 10-year trailing average of
historical 10-year bond index (iBoxx); however, the cost of debt revenue allowances for all slow track companies are derived
using an extending trailing average of the index. Under this approach, the trailing average period used is progressively extended from 10 to 20 years and consequently short-term fluctuations in the interest rate have a less pronounced effect on the regulatory cost of debt applied. Therefore, WPD’s cost of debt recovery is significantly lower than it would have been had it been derived under the approach used for the slow-track companies.

Over the 8-year RIIO-ED1 period WPD is expected to under-recover its cost of debt at the four DNOs, based upon the latest inflation assumptions and projected 10-year iBoxx bond indices rates, by approximately £175 million primarily driven by the previously discussed differing cost of debt recovery calculations. Under the terms of the fast track process, fast tracked companies were not supposed to be disadvantaged financially to slow track companies. It is uncertain, however, at this time, if WPD will be able to recover any of this under-recovery in the next price control period, RIIO-ED2, beginning April 1, 2023.

Interest costs relating to long-term debt issued at WPD’s holding companies are not recovered in revenues and for 2018, 2017 and 2016 were approximately £46 million, £49 million and £54 million.

(3) Recovery of depreciation in revenues - Recovery of depreciation in regulatory revenues is one of the key mechanisms Ofgem uses to support financeable business plans that provide incentives to attract the continued substantial investment required in the U.K. Differences between GAAP and regulatory depreciation exist primarily due to differing assumptions on asset lives and because RAV is adjusted for inflation using RPI.

Compared to asset lives established for GAAP, asset lives established for ratemaking are set by Ofgem based on economic lives which results in improved near-term revenues and cash flows for DNOs during investment cycles. Under U.K. regulation prior to RIIO-ED1, electric distribution assets were depreciated on a 20-year asset life for the purpose of setting revenues. After


7


review and consultation, Ofgem decided to use 45-year asset lives for RAV additions after April 1, 2015, with transitional arrangements available for DNOs that fully demonstrated a need to ensure a financeable plan. WPD adopted a transition that has a linear increase in asset lives from 20 to 45 years for additions to RAV in each year of RIIO-ED1 (with additions averaging a life of approximately 35 years over this period), which adds support to its credit metrics. RAV additions prior to March 31, 2015 continue to be recovered in revenues over 20 years.

The asset lives used to determine depreciation expense for GAAP purposes are not the same as those used for the depreciation of the RAV in setting revenues and, as such, vary by asset type and are based on the expected useful lives of the assets. Effective January 1, 2015, after completing a review of the useful lives of its distribution network assets, WPD set the weighted average useful lives to 69 years for GAAP depreciation expense.

Because Ofgem uses a real cost of capital, the RAV and recovery of depreciation are adjusted for inflation using RPI. The inflation revenues collected in this line item help recover the cost of equity and debt returns on a "nominal" basis, compared to the "real" rates used to set the return component of base revenues.

This regulatory construct, in combination with the different assets lives used for ratemaking and GAAP, results in amounts collected by WPD as recovery of depreciation in revenues being significantly higher than the amounts WPD recorded for depreciation expense under GAAP. For 2018, 2017 and 2016, this difference was £444 million, £424 million and £415 million (pre-tax) and positively impacted net income. The difference is expected to continue in the £400 million to £450 million (pre-tax) range at least through 2022 (the last full calendar year of RIIO-ED1), assuming RPI of approximately 3.0% per year from 2019 through 2022 and based on expected RAV additions of approximately £800 million per year to prepare the distribution system for future U.K. energy objectives while maintaining premier levels of reliability and customer service.

(4) Expenditure efficiency mechanisms - Ofgem introduced the concept of Totex in RIIO to ensure all DNOs face equal incentives in choosing between operating and capital solutions. Totex is split between immediate recovery (called "Fast pot") and deferred recovery as an addition to the RAV (called "Slow pot"). The ratio of Slow pot to Fast pot was determined by each DNO in their business plan development. WPD established a Totex split of 80% Slow pot and 20% Fast pot for RIIO-ED1 to balance maximizing RAV growth with immediate cost recovery to support investment grade credit ratings. Comparatively, other DNOs on average used a ratio of approximately 70% Slow pot and 30% Fast pot for RIIO-ED1.

Ofgem also allows a Totex Incentive Mechanism that is intended to reward DNOs for cost efficiency. WPD's DNOs are able to retain 70% of any amounts not spent against its RIIO-ED1 plan and bear 70% of any over-spends. Any amounts to be returned to customers are trued up in the AIP discussed below.

Because Fast pot cost recovery represents 20% of Totex expenditures and certain other costs are recovered in other components of revenue, Fast pot will not equal operation and maintenance expenses recorded for GAAP purposes.

(5) Income Tax Allowance - For price control purposes, WPD collects income tax based on Ofgem’s notional tax charge, which will not equal the amount of income tax expense recorded for GAAP purposes. The following table shows the amount of taxes collected in revenues and recorded under GAAP.
 
 
2018
 
2017
 
2016
Taxes collected in revenues
 
£
58

 
£
57

 
£
53

Taxes recorded under GAAP
 
156

 
139

 
119


(6) Other revenue included in base revenue - Other revenue included in base revenue primarily consists of pension deficit funding, pass through costs, profiling adjustments and legacy price control adjustments.

Recovery of annual (normal) pension cost and pension deficit funding - Ofgem allows DNOs to recover annual (normal) pension costs through the Totex allocation, split between the previously described Fast pot (immediate recovery) and Slow pot recovery (as an addition to RAV). The amount of normal pension cost is computed by the pension trustees, using assumptions that differ from those used in calculating pension costs/income under GAAP. In addition, the timing of the revenue collection may not match the actual pension payment schedule, resulting in a timing difference of cash flows.

In addition, WPD recovers approximately 80% of pension deficit funding for certain of WPD's defined benefit pension plans in conjunction with actual costs similar to the Fast pot mechanism. The pension deficit is determined by the pension trustees on a triennial basis in accordance with their funding requirements. Pension deficit funding recovered in revenues was £147 million, £142 million and £139 million in 2018, 2017 and 2016. WPD expects similar amounts to be collected in revenues through


8


March 31, 2021, but cannot predict amounts that will be collected in revenues beyond then as the plans are approaching a fully funded status. The next triennial pension review will commence in March 2019 and is expected to conclude by the end of 2020.

See Note 11 to the Financial Statements for additional information on pension costs/income recognized under GAAP.

Recovery of pass through costs - WPD recovers certain pass-through costs over which the DNO has no control such as property taxes, National Grid transmission charges and Ofgem fees. Although these items are intended to be pass-through charges there could be timing differences, primarily related to property taxes, as to when amounts are collected in revenues and when amounts are expensed in the Statements of Income. WPD over-collected property taxes by £38 million, £19 million and £8 million in 2018, 2017 and 2016. WPD expects to continue to over-recover property taxes until the end of RIIO-ED1. Amounts under-or over-recovered in revenues in a regulatory year are trued up through revenues two regulatory years later.

Profiling adjustments - Ofgem permitted DNOs the flexibility to make profiling adjustments to their base revenues within their business plans. These adjustments do not affect the total base revenue in real terms over the eight-year price control period, but change the year in which the revenue is collected. In the first year of RIIO-ED1, WPD’s base revenue decreased by 11.8% compared to the final year of the prior price control period (DPCR5), primarily due to a change in profiling methodology and a lower weighted-average cost of capital. Base revenue then increases by approximately 2.5% per annum before inflation for regulatory years up to March 31, 2019 and by approximately 1% per annum before inflation for each regulatory year thereafter for the remainder of RIIO-ED1.

(7) Incentives for developing high-quality business plans (known as fast-tracking) - For RIIO-ED1, Ofgem incentivized DNOs with certain financial rewards to develop "well justified" business plans that drive value to customers. WPD was awarded the following incentives for being fast-tracked by Ofgem:

an annual fast-track revenue incentive worth 2.5% of Totex (approximately £25 million annually for WPD);
a real cost of equity rate of 6.4% compared to 6.0% for slow-tracked DNOs; and,
cost savings retention was established at 70% for WPD compared to approximately 55% for slow-tracked DNOs.

(8) Allowed Revenue - Allowed revenue is the amount that a DNO can collect from its customers in order to fund its investment requirements.

Base revenues are adjusted annually during RIIO-ED1 to arrive at allowed revenues. These adjustments are discussed in sections (9) through (13) below.

(9) MOD and Inflation True-Up (TRU)
 
MOD - RIIO-ED1 includes an AIP that allows future base revenues, agreed with the regulator as part of the price control review, to be updated during the price control period for financial adjustments including taxes, pensions, cost of debt, legacy price control adjustments from preceding price control periods and adjustments relating to actual and allowed total expenditure together with the Totex Incentive Mechanism (TIM). The AIP calculates an incremental change to base revenue, known as the "MOD" adjustment.

The MOD provided by Ofgem in November 2016 included the TIM for the 2015/16 regulatory year, as well as the cost of debt calculation based on the 10-year trailing average to October 2016. This MOD of £12 million reduced base revenue in calendar years 2017 and 2018 by £8 million and £4 million.
The MOD provided by Ofgem in November 2017 for the 2016/17 regulatory year is a £39 million reduction to revenue and reduced base revenue in calendar year 2018 by £26 million and will reduce base revenue in calendar year 2019 by £13 million.
The MOD provided by Ofgem in November 2018 for the 2017/18 regulatory year is a £42 million reduction to revenue and will reduce base revenue in calendar years 2019 and 2020 by £28 million and £14 million.
The projected MOD for the 2018/19 regulatory year is a £87 million reduction to revenue and is expected to reduce base revenue in calendar years 2020 and 2021 by £58 million and £29 million.

TRU - As discussed below in "(10) Inflation adjusted, multi-year rate cycle," the base revenue for the RIIO-ED1 period was set based on 2012/13 prices. Therefore an inflation factor as determined by forecasted RPI, provided by HM Treasury, is applied to base revenue. Forecasted RPI is trued up to actuals and affects future base revenue two regulatory years later. This revenue change is called the "TRU" adjustment.



9


The TRU for the 2015/16 regulatory year was a £31 million reduction to revenue and reduced base revenue in calendar years 2017 and 2018 by £21 million and £10 million.
The TRU for the 2016/17 regulatory year was a £6 million reduction to revenue and reduced base revenue in calendar year 2018 by £4 million and will reduce base revenue in calendar year 2019 by £2 million.
The TRU for the 2017/18 regulatory year was a £4 million increase to revenue and will increase base revenue in calendar years 2019 and 2020 by £3 million and £1 million.
The projected TRU for the 2018/19 regulatory year is a £3 million increase to revenue and is expected to increase base revenue in calendar years 2020 and 2021 by £2 million and £1 million.

As both MOD and TRU are changes to future base revenues as determined by Ofgem, these adjustments are recognized as a component of revenues in future years in which service is provided and revenues are collected or returned to customers. PPL's projected earnings per share growth rate through 2020 includes both the TRU and MOD for regulatory years 2015/16, 2016/17 and 2017/18 and the estimated TRU and MOD for 2018/19.

(10) Inflation adjusted, multi-year rate cycle - Ofgem built its price control framework to better coincide with the long-term nature of electricity distribution investments. The current price control for electricity distribution is for the eight-year period from April 1, 2015 through March 31, 2023. This both required and enabled WPD to design a base business plan with predictable revenues and expenses over the long-term to drive value for its customers through predetermined outputs and for its investors through preset base returns. A key aspect to the multi-year cycle is an annual inflation adjustment for revenue and cost components, which are inflated using RPI from the base 2012/13 prices used to establish the business plans. Consistent with Ofgem’s formulas, the inflation adjustment is applied to base revenue, MOD and TRU when determining allowed revenue. This inflation adjustment also has the effect of inflating RAV, and real returns are earned on the inflated RAV.

(11) Incentive revenues for strong operational performance and innovation - Ofgem has established incentives to provide opportunities for DNOs to enhance overall returns by improving network efficiency, reliability and customer service. These incentives can result in an increase or reduction in revenues based on incentives or penalties for actual performance against pre-established targets based on past performance. Some of the more significant incentives that may affect allowed revenue include the Interruptions Incentive Scheme (IIS), the broad measure of customer service (BMCS) and the time to connect (TTC) incentive:

The IIS has two major components: (1) Customer interruptions (CIs) and (2) Customer minutes lost (CMLs), and both are designed to incentivize the DNOs to invest in and operate their networks to manage and reduce both the frequency and duration of power outages.
The BMCS encompasses customer satisfaction in supply interruptions, connections and general inquiries, complaints, stakeholder engagement and delivery of social obligations.
The TTC incentive rewards DNOs for reducing connection times for minor connections against an Ofgem set target.

The annual incentives and penalties are reflected in customer rates on a two-year lag from the time they are earned and/or assessed. Based on applicable GAAP, incentive revenues and penalties are recorded in revenues when they are billed to customers. The following table shows the amount of incentive revenues (in total), primarily from IIS, BMCS and TTC that WPD has received and is projected to receive on a calendar year basis:
 
 
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
 
72

 
2019
2018 (a)
 
70-80

 
2020
2019 (a)
 
70-80

 
2021
 
(a)
Reflects projected incentive revenues.

(12) Correction Factor (K-factor) - During the price control period, WPD sets its tariffs to recover allowed revenue. However, in any fiscal period, WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the allowed revenue for a particular period. Conversely, WPD could over-recover revenue. Over- and under-recoveries are subtracted from or added to allowed revenue in future years, known as the "Correction Factor" or "K-factor." Over and under-recovered amounts during RIIO-ED1 will be refunded/recovered two regulatory years later.


10


The K-factor for the 2015/16 regulatory year was a £4 million under-recovery and increased allowed revenue in calendar years 2017 and 2018 by £3 million and £1 million.
The K-factor for the 2016/17 regulatory year was a £23 million over-recovery and reduced allowed revenue in calendar year 2018 by £15 million and will reduce allowed revenue in calendar year 2019 by £8 million.
The K-factor for the 2017/18 regulatory year was a £3 million over-recovery and will reduce allowed revenue in calendar years 2019 and 2020 by £2 million and £1 million.
The projected K-factor for the 2018/19 regulatory year is a £31 million over-recovery and is expected to reduce allowed revenue in calendar years 2020 and 2021 by £21 million and £10 million.

Historically, tariffs have been set a minimum of three months prior to the beginning of the regulatory year (April 1). In February 2015, Ofgem determined that, beginning with the 2017/18 regulatory year, tariffs would be established a minimum of fifteen months in advance. Therefore, in December 2015, WPD was required to establish tariffs for the 2016/17 and 2017/18 regulatory years. This change will potentially increase volatility in future revenue forecasts due to the need to forecast components of allowed revenue including MOD, TRU, K-factor and incentive revenues.

(13) Other Allowed Revenue - Other Allowed Revenue primarily consists of pass through true-ups and £5 per residential customer reduction. For a discussion on property tax true-ups, see recovery of pass through costs in "(6) Other revenue included in base revenue" above.

In the 2016/17 regulatory year, WPD recovered a £5 per residential network customer reduction given through reduced tariffs in 2014/15. As a result, revenues were positively affected in calendar years 2017 and 2016 by £13 million and £25 million.

(14) GAAP Operating Revenue - Operating revenue under GAAP primarily consists of allowed revenue that has been collected in the calendar year converted to U.S. dollars. It also includes miscellaneous revenue primarily from engineering recharge work and ancillary activity revenue. Engineering recharge is work performed for a third party by WPD which is not for general network maintenance or to increase reliability. Examples are diversions and running new lines and equipment for a new housing complex. Ancillary activity revenue includes revenue primarily from WPD’s Telecoms and Property companies. For additional information on ancillary activity revenue, see footnote c in "Item 7. Combined Management’s Discussion and Analysis of Financial Conditions and Results of Operation - Reconciliation of Adjusted Gross Margins." The amounts of miscellaneous revenue for 2018, 2017 and 2016 were £115 million, £90 million and £84 million. The margin or profit on these activities; however, was not significant.

(15) Currency Hedging - Earnings generated by PPL's U.K. subsidiaries are subject to foreign currency translation risk. Due to the significant earnings contributed from WPD, PPL enters into foreign currency contracts to economically hedge the value of the GBP versus the U.S. dollar. These hedges do not receive hedge accounting treatment under GAAP. See "Overview- Financial and Operational Developments - U.K. Membership in European Union" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of U.K. earnings hedging activity.

GAAP Accounting implications:

As the regulatory model in the U.K. is incentive based rather than a cost recovery model, WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP. Therefore, the accounting treatment for the differences in the amounts collected in revenues and the amounts recorded for expenses related to depreciation, pensions, cost of debt and income taxes, and the adjustments to base revenue and/or allowed revenue are evaluated primarily based on revenue recognition guidance.

See "Revenue Recognition" in Note 1 to the Financial Statements for additional information.

See "Item 1A. Risk Factors - Risks related to our U.K. Regulated Segment" for additional information on the risks associated with the U.K. Regulated Segment.

RIIO-2 Framework

On March 7, 2018, Ofgem issued its consultation document on the RIIO-2 framework, which covers all U.K. gas and electricity transmission and distribution price controls. The current electricity distribution price control, RIIO-ED1, continues through March 31, 2023 and will not be impacted by this RIIO-2 consultation process. Ofgem consulted on a wide range of issues, including cost of debt and equity methodologies, the length of the price control period, indexation methodologies, innovation, stakeholder engagement in the business planning process and performance incentive mechanisms. The purpose of the RIIO-2 framework consultation was to build on lessons learned from the current price controls while supporting low costs to


11


consumers, improved customer service and reliability, and the U.K.'s continued shift to a low-carbon future. Comments on the RIIO-2 framework were due in May 2018. On July 30, 2018, Ofgem published its decision following its RIIO-2 framework consultation after consideration of comments received. Ofgem confirmed the following points in the decision document:

There will be a five-year default length for the price control period, compared to eight years in the current RIIO-ED1 price control.
There is intent to shift the inflation index used for calculating RAV and allowed returns from RPI to CPIH. Ofgem stated overall, consumers and investors as a whole will be neither better nor worse off in net present value terms as a result of the shift to CPIH and a transition period may be required.
There will be no change to the existing depreciation policy of using economic asset lives as the basis for depreciating RAV as part of base revenue calculations. WPD is currently transitioning to 45 year asset lives for new additions in RIIO-ED1 based on Ofgem’s extensive review of asset lives in RIIO-ED1.
Ofgem will retain the option for fast-tracking for electricity distribution companies only. Fast tracking will be further considered as part of the electricity distribution sector specific consultation.
A new enhanced engagement model will be introduced which will require distribution companies to set up a customer engagement group to provide Ofgem with a public report of their views on the companies’ business plans from the perspective of local stakeholders. Ofgem will also establish an independent RIIO-2 challenge group comprised of consumer experts to provide Ofgem with a public report on companies’ business plans.
Ofgem intends to expand the role of competition for projects that are new, separable and high value. WPD does not currently have any planned projects that would meet the high value threshold.
A focus of RIIO-2 will be on whole-system outcomes. Ofgem envisions network companies and system operators working together to ensure the energy system as a whole is efficient and delivers best value to consumers. Ofgem is undertaking further work to clarify the definition of whole-system and the appropriate roles of the network companies in supporting the energy transition.

Ofgem also indicated further work is needed on other price control principles, including but not limited to, cost of equity, cost of debt, financeability and incentives with decisions on these items expected to be made in the sector specific consultations or within the individual company business plan submissions.

In December 2018, the promulgation of sector specific price controls began with Ofgem publishing its consultation related to its RIIO-2 price controls for the gas distribution, gas transmission and electricity transmission operators that will be effective from April 2021 to March 2026. This current consultation does not apply directly to electricity distribution network operators although some decisions will be precedent setting. The electricity distribution price control work is scheduled to begin in 2020, at which time Ofgem plans to publish its RIIO-ED2 strategy consultation document.

Although the electricity distribution consultation does not commence until 2020, WPD is engaged in the RIIO-2 process and will be responding to the December 2018 consultation document. PPL cannot predict the outcome of this process or the long-term impact it or the final RIIO-ED2 regulations will have on its financial condition or results of operations.

Kentucky Regulated Segment (PPL)

Consists of the operations of LKE, which owns and operates regulated public utilities engaged in the generation, transmission, distribution and sale of electricity and distribution and sale of natural gas, representing primarily the activities of LG&E and KU. In addition, certain acquisition-related financing costs are allocated to the Kentucky Regulated segment.  

(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, also Virginia. LG&E also engages in the distribution and sale of natural gas in Kentucky. LG&E provides electric service to approximately 414,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in nine counties and provides natural gas service to approximately 328,000 customers in its electric service area and eight additional counties in Kentucky. KU provides electric service to approximately 527,000 customers in 77 counties in central, southeastern and western Kentucky and approximately 28,000 customers in five counties in southwestern Virginia, covering approximately 4,800 non-contiguous square miles. KU also sells wholesale electricity to 10 municipalities in Kentucky under load following contracts.
 


12


Details of operating revenues, in millions, by customer class for the years ended December 31 are shown below. 
 
2018
 
2017
 
2016
 
Revenue
 
% of
Revenue
 
Revenue
 
% of
Revenue
 
Revenue
 
% of
Revenue
LKE
 
 
 
 
 
 
 
 
 
 
 
Commercial
$
858

 
27

 
$
854

 
27

 
$
834

 
27

Industrial
566

 
18

 
603

 
19

 
601

 
19

Residential
1,313

 
41

 
1,259

 
40

 
1,261

 
40

Other (a)
293

 
9

 
280

 
9

 
288

 
9

Wholesale - municipal
105

 
3

 
112

 
4

 
116

 
4

Wholesale - other (b)
79

 
2

 
48

 
1

 
41

 
1

Total
$
3,214

 
100

 
$
3,156

 
100

 
$
3,141

 
100


(a)
Primarily includes revenues from street lighting and other public authorities.
(b)
Includes wholesale power and transmission revenues.
 
2018
 
2017
 
2016
 
Revenue
 
% of
Revenue
 
Revenue
 
% of
Revenue
 
Revenue
 
% of
Revenue
LG&E
 
 
 
 
 
 
 
 
 
 
 
Commercial
$
451

 
30

 
$
453

 
31

 
$
442

 
31

Industrial
178

 
12

 
187

 
13

 
185

 
13

Residential
661

 
44

 
637

 
44

 
627

 
44

Other (a)
133

 
9

 
123

 
8

 
135

 
9

Wholesale - other (b)
73

 
5

 
53

 
4

 
41

 
3

Total
$
1,496

 
100

 
$
1,453

 
100

 
$
1,430

 
100


(a)
Primarily includes revenues from street lighting and other public authorities.
(b)
Includes wholesale power and transmission revenues. Also includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.
 
2018
 
2017
 
2016
 
Revenue
 
% of
Revenue
 
Revenue
 
% of
Revenue
 
Revenue
 
% of
Revenue
KU
 
 
 
 
 
 
 
 
 
 
 
Commercial
$
407

 
23

 
$
401

 
23

 
$
392

 
22

Industrial
388

 
22

 
416

 
24

 
416

 
24

Residential
652

 
37

 
622

 
36

 
634

 
36

Other (a)
160

 
9

 
157

 
9

 
153

 
9

Wholesale - municipal
105

 
6

 
112

 
6

 
116

 
7

Wholesale - other (b)
48

 
3

 
36

 
2

 
38

 
2

Total
$
1,760

 
100

 
$
1,744

 
100

 
$
1,749

 
100

 
(a)
Primarily includes revenues from street lighting and other public authorities.
(b)
Includes wholesale power and transmission revenues. Also includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.

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. 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, which may be significant, cannot currently


13


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, 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, 2018, LKE owned, controlled or had a minority ownership interest in generating capacity of 8,017 MW, of which 2,920 MW related to LG&E and 5,097 MW related to KU, in Kentucky, Indiana, and Ohio. See "Item 2. Properties - Kentucky Regulated Segment" for a complete list of LKE's generating facilities.
 
The system capacity of LKE's owned or controlled generation is based upon a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changes in circumstances.
 
During 2018, LKE's power plants generated the following amounts of electricity.
 
GWh
Fuel Source
LKE
 
LG&E
 
KU
Coal (a)
28,742

 
12,446

 
16,296

Gas
6,301

 
1,584

 
4,717

Hydro
344

 
191

 
153

Solar
17

 
7

 
10

Total (b)
35,404

 
14,228

 
21,176


(a)
Includes 859 GWh of power generated by and purchased from OVEC for LKE, 594 GWh for LG&E and 265 GWh for KU.
(b)
This generation represents increases for LKE, LG&E and KU of 5.7%, 5% and 6.2% from 2017 output.

The majority of LG&E's and KU's generated electricity was used to supply their retail and KU's municipal customer base.
 
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.
 
As a result of environmental requirements and energy efficiency measures, KU anticipates retiring two older coal-fired units at the E.W. Brown plant in 2019 with a combined summer rating capacity of 272 MW.

In 2016, LG&E and KU completed construction activities and placed into commercial operation a 10 MW solar generating facility at the E.W. Brown generating site. Additionally, LG&E 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. The subscription for the first 500-kilowatt phase was completed in June 2018. Construction of the first section has begun and is expected to be operational in the summer of 2019. LG&E and KU continue to market the program and receive interest from customers for the second 500-kilowatt phase.

Fuel Supply
 
Coal and natural gas will continue to be the predominant fuel 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 are 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 of factors including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties.
 


14


LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2023 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 and southern Illinois. 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 with contracts of various durations from 2019 to 2024 on the interstate pipeline serving Cane Run Unit 7. This pipeline also serves the six simple cycle combustion turbine units located at the Trimble County site as well as four other simple cycle units at the Cane Run and Paddy's Run sites. 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 interconnected to two 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 through December 2020. The bulk of the natural gas fuel remains purchased on the spot market.

(PPL, LKE and LG&E)

Natural Gas Distribution Supply
 
Five underground natural gas storage fields, with a current working natural gas capacity of approximately 15 billion cubic feet (Bcf), are used in providing natural gas service to LG&E's firm sales customers. Natural gas is stored during the summer season for withdrawal during the following winter heating season. Without this storage capacity, LG&E would be required to purchase additional natural gas and pipeline transportation services during winter months when customer demand increases and the prices for natural gas supply and transportation services are expected to be higher. At December 31, 2018, LG&E had 12 Bcf of natural gas stored underground with a carrying value of $41 million.

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 contracts with one pipeline that are subject to termination by LG&E between 2020 and 2023. Total winter season capacity under these contracts is 184,900 MMBtu/day and summer season capacity is 60,000 MMBtu/day. With this same pipeline, LG&E also has another contract for pipeline capacity through 2026 in the amount of 60,000 MMBtu/day during both the winter and summer seasons. 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.
 
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.
 
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.



15


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 the levelized fuel factor and regulatory assets or liabilities recorded for 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 10 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, 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, certain municipalities submitted notices of termination, under the notice period provisions, to cease taking power under the wholesale requirements contracts. KU's service to eight municipalities will terminate effective May 1, 2019.

Rate Case Proceedings

(PPL, LKE, LG&E and KU)

On September 28, 2018, LG&E and KU filed requests with the KPSC for an increase in annual base electricity rates of approximately $112 million at KU and increases in annual base electricity and gas rates of approximately $35 million and $25 million at LG&E. The proposed base rate increases would result in an electricity rate increase of 6.9% at KU and electricity and gas rate increases of 3% and 7.5% at LG&E. As discussed in the "TCJA Impact on LG&E and KU Rates" section below, LG&E's and KU's applications seek to include applicable changes associated with the TCJA in the calculation of the proposed base rates and to terminate the TCJA bill credit mechanism when the new base rates go into effect.

New rates are expected to become effective on May 1, 2019. The applications are based on a forecasted test year of May 1, 2019 through April 30, 2020 with a requested return-on-equity of 10.42%. A number of parties have been granted intervention requests in the proceeding. Data discovery and the filing of written testimony will continue through February 2019 and a hearing is scheduled in March 2019. LG&E and KU cannot predict the outcome of these proceedings.

(LKE and KU)

In September 2017, KU filed a request seeking approval from the VSCC to increase annual Virginia base electricity revenue by $7 million, representing an increase of 10.4%. On March 22, 2018, KU reached a settlement agreement regarding the case, including the impact of the TCJA on rates, resulting in an increase in annual Virginia base electricity revenue of $2 million. This represents an increase of 2.8% with rates effective June 1, 2018. On May 8, 2018, the VSCC issued an Order approving the settlement agreement.

TCJA Impact on LG&E and KU Rates

(PPL, LKE, LG&E and KU)

On December 21, 2017, Kentucky Industrial Utility Customers, Inc. submitted a complaint with the KPSC against LG&E and KU, as well as other utility companies in Kentucky, alleging that their respective rates would no longer be fair, just and reasonable following the enactment of the TCJA, which reduced the federal corporate tax rate from 35% to 21%. The complaint requested the KPSC to issue an order requiring LG&E and KU to begin deferring, as of January 1, 2018, the revenue requirement effect of all income tax expense savings resulting from the federal corporate income tax reduction, including the amortization of excess deferred income taxes by recording those savings in a regulatory liability account and establishing a process by which the federal corporate income tax savings will be passed back to customers.

On January 29, 2018, LG&E, KU, Kentucky Industrial Utility Customers, Inc. and the Office of the Attorney General reached a settlement agreement to commence returning savings related to the TCJA to their customers through their ECR, DSM and LG&E's GLT rate mechanisms beginning in March 2018 and through a new bill credit mechanism from April 1, 2018 through April 30, 2019 and thereafter until tax-reform related savings are reflected in changes in base rates. The estimated impact of the rate reduction represents approximately $91 million in KU electricity revenues ($70 million through the new bill credit and $21 million through existing rate mechanisms), $69 million in LG&E electricity revenues ($49 million through the new bill credit and $20 million through existing rate mechanisms) and $17 million in LG&E gas revenues (substantially all through the new bill credit) for the period January 2018 through April 2019.



16


On March 20, 2018, the KPSC issued an Order approving, with certain modifications, the settlement agreement reached between LG&E, KU, Kentucky Industrial Utility Customers, Inc. and the Office of the Attorney General. The KPSC estimates that, pursuant to its modifications, electricity revenues would incorporate reductions of approximately $108 million for KU ($87 million through the new bill credit and $21 million through existing rate mechanisms) and $79 million for LG&E ($59 million through the new bill credit and $20 million through existing rate mechanisms). This represents $27 million ($17 million at KU and $10 million at LG&E) in additional reductions from the amounts proposed by the settlement. The KPSC's modifications to the settlement include certain changes in assumptions or inputs used in assessing tax reform or calculating LG&E's and KU's electricity rates. LG&E gas rate reductions were not modified significantly from the amount included in the settlement agreement.

On September 28, 2018, the KPSC issued an Order on reconsideration, pursuant to LG&E's and KU's petition, implementing rates reflecting electricity revenue reductions of $101 million for KU ($80 million through the new bill credit and $21 million through existing rate mechanisms), $74 million for LG&E electricity revenues ($54 million through the new bill credit and $20 million through existing rate mechanisms) and $16 million LG&E gas revenues (substantially all through the new bill credit) for the period January 2018 through April 2019. This represents lower revenue reduction amounts than the March 20, 2018 Order of approximately $13 million ($7 million at KU and $6 million at LG&E).

In January 2018, the VSCC ordered KU, as well as other utilities in Virginia, to accrue regulatory liabilities reflecting the Virginia jurisdictional revenue requirement impacts of the reduced federal corporate tax rate. In March 2018, KU reached a settlement agreement regarding its rate case in Virginia. New rates, inclusive of TCJA impacts, were effective June 1, 2018. The settlement also stipulates that actual tax savings for the five month period prior to new rates taking effect would be addressed through KU's annual information filing for calendar year 2018. In May 2018, the VSCC approved the settlement agreement. The TCJA and rate case are not expected to have a significant impact on KU's financial condition or results of operations related to Virginia.

On November 15, 2018, the FERC issued a Policy Statement which stated that the appropriate ratemaking treatment for changes in accumulated deferred income taxes as a result of the TCJA will be addressed in a Notice of Proposed Rulemaking. Also on November 15, 2018, the FERC issued the Notice of Proposed Rulemaking which proposes that public utility transmission providers include mechanisms in their formula rates to deduct excess accumulated deferred income taxes from, or add deficient accumulated deferred income taxes to, rate base and adjust their income tax allowances by amortized excess or deficient accumulated deferred income taxes. The Notice of Proposed Rulemaking did not prescribe the mechanism companies should use to adjust their formula rates. LG&E and KU are currently assessing the Notice of Proposed Rulemaking and are continuing to monitor guidance issued by the FERC. On February 5, 2019, in connection with a separate element of federal and Kentucky state tax reform effects, LG&E and KU filed a request with the FERC to amend their transmission formula rates, effective June 1, 2019, to incorporate reductions to corporate income tax rates as a result of the TCJA and HB 487. LG&E and KU do not anticipate the impact of the TCJA related to their FERC-jurisdictional rates to be significant.  

See Note 7 to the Financial Statements for additional information on rate mechanisms.

Pennsylvania Regulated Segment (PPL)

Consists of PPL Electric, a regulated public utility engaged in the distribution and transmission of electricity.
 
(PPL and PPL Electric)
 
PPL Electric delivers electricity to approximately 1.4 million customers in a 10,000-square mile territory in 29 counties of eastern and central Pennsylvania. PPL Electric also provides electricity to retail customers in this territory as a PLR under the Customer Choice Act.
 


17


Details of revenues, in millions, by customer class for the years ended December 31 are shown below. 
 
2018
 
2017
 
2016
 
Revenue
 
% of Revenue
 
Revenue
 
% of Revenue
 
Revenue
 
% of Revenue
Distribution
 
 
 
 
 
 
 
 
 
 
 
Residential
$
1,379

 
61

 
$
1,351

 
62

 
$
1,327

 
61

Industrial
54

 
2

 
44

 
2

 
42

 
2

Commercial
368

 
16

 
349

 
16

 
338

 
16

Other (a)
(73
)
 
(3
)
 
(36
)
 
(2
)
 
(4
)
 

Transmission
549

 
24

 
487

 
22

 
453

 
21

Total
$
2,277

 
100

 
$
2,195

 
100

 
$
2,156

 
100

 
(a)
Includes regulatory over- or under-recovery reconciliation mechanisms, pole attachment revenues and street lighting, offset by contra revenue associated with the network integration transmission service expense.

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, which it has succeeded and as a result of certification by the PUC. 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, 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 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 investments are subject to competitive processes outlined in the PJM tariff.

As a transmission owner, PPL Electric's transmission revenues are recovered through PJM and billed in accordance with a FERC-approved Open Access Transmission Tariff that allows recovery of incurred transmission costs, a return on transmission-related plant and an automatic annual update based on a formula-based rate recovery mechanism. Under this formula, rates are put into effect in June of each year based upon prior year actual expenditures and current year forecasted capital additions. Rates are then adjusted the following year to reflect actual annual expenses and capital additions, as reported in PPL Electric’s annual FERC Form 1, filed under the FERC’s Uniform System of Accounts. 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. Any change in the prior year PPL zonal peak load billing factor applied on January 1st of each year, will result in an increase or decrease in revenue until the next annual rate update goes into effect on June 1st of that same year.



18


As a PLR, PPL Electric also purchases transmission services from PJM. See "PLR" below.
 
See Note 7 to the Financial Statements for additional information on rate mechanisms.
 
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 are excluded from the return on rate base. Therefore, no return is earned on the related assets unless specifically provided for by the PUC. 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 electricity 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, 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 PUC 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 Note 7 to the Financial Statements for additional information regarding Act 129 and other legislative and regulatory impacts.
 
PLR
 
The Customer Choice Act requires Electric Distribution Companies (EDCs), including PPL Electric, or an alternative supplier approved by the PUC 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 PUC regulations. In 2018, the following average percentages of PPL Electric's customer load were provided by competitive suppliers: 47% of residential, 83% of small commercial and industrial and 98% of large commercial and industrial customers. The PUC continues to favor expanding the competitive market for electricity.
 
PPL Electric's cost of electricity generation is based on a competitive solicitation process. The PUC approved PPL Electric's default service plan for the period June 2015 through May 2017, which included four solicitations for electricity supply held semiannually in April and October. The PUC approved PPL Electric's default service plan for the period June 2017 through May 2021, which includes a total of eight solicitations for electricity supply held semiannually in April and October. 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 that service from PPL Electric. These solicitations include a mix of 6- and 12-month fixed-price load-following contracts for residential and small commercial and industrial customers, and 12-month real-time pricing contracts for large commercial and industrial customers to fulfill PPL Electric's obligation to provide customer electricity supply as a PLR.
 
Numerous alternative suppliers have offered to provide generation supply in PPL Electric's service territory. 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.

See Note 7 to the Financial Statements for additional information regarding Act 129 and other legislative and regulatory impacts.


19



TCJA Impact on PPL Electric Rates

On February 12, 2018, the PUC issued a Secretarial Letter requesting certain information from regulated utilities and inviting comment from interested parties on potential revision to customer rates as a result of enactment of the TCJA. PPL Electric submitted its response to the Secretarial Letter on March 9, 2018. On March 15, 2018, the PUC issued a Temporary Rates Order to allow time to determine the manner in which rates could be adjusted in response to the TCJA. The PUC issued another Temporary Rates Order on May 17, 2018 to address the impact of the TCJA and indicated that utilities without a currently pending general rate proceeding would receive a utility specific order. The PUC issued an Order specific to PPL Electric on May 17, 2018 that required PPL Electric to file a tariff or tariff supplement by June 15, 2018 to establish (a) temporary rates to be effective July 1, 2018, and (b) to record a deferred regulatory liability to reflect the tax savings associated with the TCJA for the period January 1 through June 30, 2018. On June 8, 2018, PPL Electric submitted a petition to the PUC to charge a negative surcharge of 7.05% to reflect the estimated 2018 tax savings associated with the TCJA. The PUC approved PPL Electric's petition on June 14, 2018 and PPL Electric filed a tariff on June 15, 2018 reflecting the increased negative surcharge. PPL Electric recorded a $41 million noncurrent regulatory liability and a corresponding reduction of revenue to be distributed to customers pursuant to a future rate adjustment related to the period January 1, 2018 through June 30, 2018.

On March 15, 2018, the FERC issued a Notice of Inquiry seeking information on whether and how it should address changes to FERC-jurisdictional rates relating to accumulated deferred income taxes and bonus depreciation resulting from passage of the TCJA. On March 16, 2018, PPL Electric filed a waiver request, pursuant to Rule 207(a)(5) of the Rules of Practice and Procedure of the FERC, to accelerate incorporation of the changes to the federal corporate income tax rate in its transmission formula rate commencing on June 1, 2018 rather than allowing the TCJA tax rate reduction to be initially incorporated in PPL Electric's June 1, 2019 transmission formula rate. The waiver was approved on April 23, 2018 and PPL Electric submitted its transmission formula rate, reflecting the TCJA rate reduction, on April 27, 2018. In addition, on May 21, 2018, PPL Electric, as part of a PJM Transmission Owners joint filing, submitted comments in response to the FERC's March 15, 2018 Notice of Inquiry. The filing requested guidance on how the reduction in accumulated deferred income taxes, resulting from the TCJA reduced federal corporate income tax rate, should be treated for ratemaking purposes. On November 15, 2018, the FERC issued a Policy Statement which stated that the appropriate ratemaking treatment for changes in accumulated deferred income taxes as a result of the TCJA will be addressed in a Notice of Proposed Rulemaking. Also on November 15, 2018, the FERC issued the Notice of Proposed Rulemaking which proposes that public utility transmission providers should include mechanisms in their formula rates to deduct excess accumulated deferred income taxes from, or add deficient accumulated deferred income taxes to, rate base and adjust their income tax allowances by amortized excess or deficient accumulated deferred income taxes. The Notice of Proposed Rulemaking did not prescribe the mechanism companies should use to adjust their formula rates. PPL Electric is currently assessing the Notice of Proposed Rulemaking and is continuing to monitor guidance issued by the FERC. The changes, related to accumulated deferred income taxes impacting the transmission formula rate revenues, have not been significant since the new rate went into effect on June 1, 2018.

(PPL)

Corporate and Other

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 utilize PPL Capital Funding as a source of capital in future financings, in addition to continued direct financing by the operating companies.
 
Unlike 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 in the financing for the acquisitions of LKE and WPD Midlands and certain associated financing costs were allocated to the Kentucky Regulated and U.K. Regulated segments. The associated financing costs, as well 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.


20



During the second quarter of 2018, PPL completed the acquisition of all the outstanding membership interests of Safari Energy, a privately held provider of solar energy solutions for commercial customers in the U.S. The acquisition is not material to PPL and the financial results of Safari Energy are reported within Corporate and Other.

(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 2019 through 2023. See Note 13 to the Financial Statements for additional information concerning the potential impact on capital expenditures from environmental matters.

ENVIRONMENTAL MATTERS
 
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. 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 2019 through 2023. Also, see "Environmental Matters" in Note 13 to the Financial Statements for additional information and Note 7 to the Financial Statements for information related to the recovery of environmental compliance costs.
 
EMPLOYEE RELATIONS
 
At December 31, 2018, PPL and its subsidiaries had the following full-time employees and employees represented by labor unions.
 
Total Full-Time
Employees
 
Number of Union
Employees
 
Percentage of Total
Workforce
PPL 
12,444

 
5,970

 
48
%
PPL Electric
1,674

 
1,014

 
61
%
LKE
3,504

 
781

 
22
%
LG&E
1,028

 
663

 
64
%
KU
904

 
118

 
13
%
 
PPL's domestic workforce has 1,924 employees, or 33%, that are members of labor unions.

WPD has 4,046 employees who are members of labor unions (or 61% of PPL's U.K. workforce). WPD recognizes four unions, the largest of which represents 41% of its union workforce. WPD's Electricity Business Agreement, which covers 3,989 union employees, may be amended by agreement between WPD and the unions and can be terminated with 12 months' notice by either side.



21


CYBERSECURITY MANAGEMENT

The Registrants and their subsidiaries are subject to risks from cyber-attacks that have the potential to cause significant interruptions to the operation of their businesses. The frequency of these attempted intrusions has increased in recent years and the sources, motivations and techniques of attack continue to evolve and change rapidly. PPL has undertaken a variety of actions to monitor and address cyber-related risks. Cybersecurity and the effectiveness of PPL’s cybersecurity strategy are regular topics of discussion at Board meetings. PPL's strategy for managing cyber-related risks is risk-based and, where appropriate, integrated within PPL's enterprise risk management processes. PPL’s Chief Information Security Officer (CISO), who reports directly to the Chief Executive Officer, leads a dedicated cybersecurity team and is responsible for the design, implementation, and execution of cyber-risk management strategy. Among other things, the CISO and the cybersecurity team actively monitor the Registrants' systems, regularly review policies, compliance, regulations and best practices, perform penetration testing, lead response exercises and internal campaigns, and provide training and communication across the organization to strengthen secure behavior. The cybersecurity team also routinely participates in industry-wide programs to further information sharing, intelligence gathering, and unity of effort in responding to potential or actual attacks. In addition, in 2018, PPL revised and formalized its internal policy and procedures for communicating cybersecurity incidents on an enterprise-wide basis.
In addition to these enterprise-wide initiatives, PPL’s Kentucky and Pennsylvania operations are subject to extensive and rigorous mandatory cybersecurity requirements that are developed and enforced by NERC and approved by FERC to protect grid security and reliability. Finally, PPL purchases insurance to protect against a wide range of costs that could be incurred in connection with cyber-related incidents. There can be no assurance, however, that these efforts will be effective to prevent interruption of services or other damage to the Registrants' businesses or operations or that PPL's insurance coverage will cover all costs incurred in connection with any cyber-related incident.
AVAILABLE INFORMATION
 
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. Additionally, the Registrants' filings are available at the SEC's website (www.sec.gov).



22


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 more information concerning the risks described below and for other risks, uncertainties and factors that could impact 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 LKE and its consolidated subsidiaries taken as a whole within the Kentucky Regulated segment discussion.
 
(PPL)
 
Risks related to our U.K. Segment
 
Our U.K. distribution business contributes a significant amount of PPL's earnings and exposes us to the following additional risks related to operating outside the U.S., including risks associated with changes in U.K. laws and regulations, taxes, economic conditions and political conditions and policies of the U.K. government 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 for payment of distributions or for other corporate purposes in the U.S.

changes in laws or regulations relating to U.K. operations, including rate regulations beginning in April 2023 under RIIO-ED2, operational performance and tax laws and regulations;
changes in government policies, personnel or approval requirements;
changes in general economic conditions affecting the U.K.;
regulatory reviews of tariffs for DNOs;
changes in labor relations;
limitations on foreign investment or ownership of projects and returns or distributions to foreign investors;
limitations on the ability of foreign companies to borrow money from foreign lenders and lack of local capital or loans;
changes in U.S. tax law applicable to taxation of foreign earnings;
compliance with U.S. foreign corrupt practices laws; and
prolonged periods of low inflation or deflation.

PPL's earnings may be adversely affected in the event the U.K. withdraws from the European Union.

In 2018, approximately 61% of PPL’s net income was generated from its U.K. businesses. Significant uncertainty continues to exist concerning the financial, economic and other consequences of a withdrawal by the U.K. from the European Union, including the outcome of negotiations between the U.K. and European Union as to the terms of the withdrawal. PPL cannot predict the impact, in either the short-term or long-term, on foreign exchange rates or PPL’s financial condition that may be experienced as a result of the actions taken by the U.K. government to withdraw from the European Union, although such impacts could be material.

We are subject to foreign currency exchange rate risks because a significant portion of our cash flows and reported earnings are currently generated by our U.K. business operations.
 
These risks relate primarily to changes in the relative value of the British pound sterling and the U.S. dollar between the time we initially invest U.S. dollars in our U.K. businesses, and our strategy to hedge against such changes, and the time that cash is repatriated to the U.S. from the U.K., including cash flows from our U.K. businesses that may be distributed to PPL or used for repayments of intercompany loans or other general corporate purposes. In addition, PPL's consolidated reported earnings on a GAAP basis may be subject to earnings translation risk, which is the result of the conversion of earnings as reported in our U.K. businesses on a British pound sterling basis to a U.S. dollar basis in accordance with GAAP requirements.
 
Our U.K. segment's earnings are subject to variability based on fluctuations in RPI, which is a measure of inflation.
 
In RIIO-ED1, WPD's base revenue was established by Ofgem based on 2012/13 prices. Base revenue is subsequently adjusted to reflect any increase or decrease in RPI for each year to determine the amount of revenue WPD can collect in tariffs. The RPI is forecasted annually by HM Treasury and subject to true-up in subsequent years. Consequently, the fluctuations between


23


forecasted and actual RPI can result in variances in base revenue. Although WPD also has debt that is indexed to RPI and certain components of operations and maintenance expense are affected by inflation, these may not offset changes in base revenue and timing of such offsets would likely not be correlated precisely with the calendar year in which the variance in demand revenue was initially incurred. Further, as RAV is indexed to RPI under U.K. rate regulations, a reduction in RPI could adversely affect a borrower's debt-to-RAV ratio, potentially limiting future borrowings at WPD's holding company.
 
Our U.K. delivery business is subject to revenue variability based on operational performance.
 
Our U.K. delivery businesses operate under an incentive-based regulatory framework. Managing operational risk and delivering agreed-upon performance are critical to the U.K. Regulated segment's financial performance. Disruption to these distribution networks could reduce profitability both directly by incurring costs for network restoration and also through the system of penalties and rewards that Ofgem administers relating to customer service levels.

Our ability to collect current levels of pension deficit funding for certain WPD pension plans after March 2021 is uncertain.

WPD recovers approximately 80% of pension deficit funding for certain of WPD's defined benefit pension plans in conjunction with actual costs under the RIIO-ED1 price control. The pension deficit is determined by the pension trustees on a triennial basis in accordance with their funding requirements. Pension deficit funding recovered in revenues was £147 million, £142 million and £139 million in 2018, 2017 and 2016. WPD expects similar amounts to be collected in revenues through March 31, 2021, but cannot predict amounts that will be collected in revenues beyond then as the plans are approaching a fully funded status. The next triennial pension review will commence in March 2019 and is expected to conclude by the end of 2020.
 
A failure by any of our U.K. regulated businesses to comply with the terms of a distribution license may lead to the issuance of an enforcement order by Ofgem that could have an adverse impact on PPL.
 
Ofgem has powers to levy fines of up to ten percent of revenue for any breach of a distribution license or, in certain circumstances, such as insolvency, the distribution license itself may be revoked. Ofgem also has formal powers to propose modifications to each distribution license and there can be no assurance that a restrictive modification will not be introduced in the future, which could have an adverse effect on the operations and financial condition of the U.K. regulated businesses and PPL.
 
Risks Related to All Segments
 
(All Registrants)
 
The operation of our businesses is subject to cyber-based security and integrity risks.

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. The operation of our transmission and distribution systems, as well as our generation plants, are all reliant on cyber-based technologies and, therefore, subject to the risk that these systems could be the target of disruptive actions by terrorists or criminals or otherwise be compromised by unintentional events. 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. In addition, under the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including PPL Electric, LG&E and KU, are subject to mandatory reliability standards promulgated by NERC and SERC and enforced by FERC. As an operator of natural gas distribution systems, LG&E is also subject to mandatory reliability standards of the U.S. Department of Transportation. Failure to comply with these standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of the standards.

We are subject to risks associated with federal and state tax laws and regulations.
 
Changes in tax law, including the December 2017 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 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 tax benefits and tax credits. Due to 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


24


cash flows. We have completed or made reasonable estimates of the effects of the TCJA reflected in our December 31, 2018 financial statements, and we continue to evaluate the application of various components of the law in the calculation of income tax expense.

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.
 
In the ordinary course of business, we are reliant upon adequate long-term and short-term financing to fund our significant capital expenditures, debt service and operating needs. As a capital-intensive business, we are sensitive to developments in interest rates, credit rating considerations, insurance, security or collateral requirements, market liquidity and credit availability and refinancing opportunities necessary or advisable to respond to credit market changes. Changes in these conditions could result in increased costs and decreased availability of credit. In addition, certain sources of debt and equity capital have expressed reservations about investing in companies that rely on fossil fuels. If sources of our capital are reduced, capital costs could increase materially.
 
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 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.
 
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.
 
Operating expenses could be affected by weather conditions, including storms, as well as by significant man-made or accidental disturbances, including terrorism or natural disasters.
 
Weather and these other factors can significantly affect our profitability or operations by causing outages, damaging infrastructure and requiring significant repair costs. Storm outages and damage often directly decrease revenues and increase expenses, due to reduced usage and restoration costs.
 
Our businesses are subject to physical, market and economic risks relating to potential effects 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. 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,


25


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.
 
We cannot predict the outcome of legal proceedings or investigations related to our businesses in which we are periodically involved. An unfavorable 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 state and federal investigations arising out of our business operations, the most significant of which are summarized in Note 7 to the Financial Statements and in "Legal Matters," "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 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.
 
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 the 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, no assurance can be given that such insurance coverage will be sufficient to compensate us in the event losses occur.


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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 the permit was sought unprofitable or otherwise unattractive. In addition, such permits or approvals may be subject to denial, revocation or modification under various 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. 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 additional capability following a terrorist incident.
 
We are subject to counterparty performance, credit or other risk in their 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-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 and new or more stringent environmental regulation, including greenhouse gases or other air emissions, 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.
 
We are experiencing an increase in 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.



27



(PPL and LKE)
 
Risk Related to Registrant Holding Companies
 
PPL and LKE are holding companies and their cash flows and ability to meet their obligations with respect to indebtedness and under guarantees, and PPL's ability to pay dividends, largely depends on the financial performance of their respective subsidiaries and, as a result, is effectively subordinated to all existing and future liabilities of those subsidiaries.
 
PPL and LKE are holding companies and conduct their operations primarily through subsidiaries. Substantially all of the consolidated assets of these Registrants are held by their subsidiaries. Accordingly, these Registrants' 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 distribution or other payment of such earnings in the form of dividends, distributions, loans, advances or repayment of loans and advances. The subsidiaries are separate legal entities and have no obligation to pay dividends or distributions to their parents or to make funds available for such a payment. The ability of the Registrants' subsidiaries to pay dividends or distributions in the future will depend on the subsidiaries' future earnings and cash flows and the needs of their businesses, and may be restricted by their obligations to holders of their outstanding debt and other creditors, as well as any contractual or legal restrictions in effect at such time, including the requirements of state corporate law applicable to payment of dividends and distributions, and regulatory requirements, including restrictions on the ability of PPL Electric, LG&E and KU to pay dividends under Section 305(a) of the Federal Power Act.
 
Because PPL and LKE are holding companies, their debt and guaranty obligations are effectively subordinated to all existing and future liabilities of their subsidiaries. Although certain agreements to which certain subsidiaries are parties limit their ability to incur additional indebtedness, PPL and LKE and their subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities. Therefore, PPL's and LKE's rights and the rights of their creditors, including rights of debt holders, to participate in the assets of any of their 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 Electric, LG&E and KU)
 
Risks Related to Domestic Regulated Utility Operations
 
Our domestic regulated utility businesses face many of the same risks, in addition to those risks that are unique to each of the Kentucky Regulated segment and the Pennsylvania Regulated segment. Set forth below are risk factors common to both domestic 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 investments. Regulators may not approve the rates we request and existing rates may be challenged.
 
The rates we charge our utility customers must be approved by one or more federal or state regulatory commissions, including the FERC, KPSC, VSCC and PUC. Although rate regulation is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that regulatory authorities will consider all of our costs to have been prudently incurred or that the regulatory process by which rates are determined will always result in rates that achieve full or timely recovery of our costs or an adequate return on our capital investments. Federal or state agencies, intervenors and other permitted parties may challenge our current or future rate requests, structures or mechanisms, and ultimately reduce, alter or limit the rates we receive. Although our rates are generally regulated based on an analysis of our costs incurred in a base year or on future projected costs, the rates we are allowed to charge may or may not match our costs at any given time. Our domestic regulated utility businesses are subject to substantial capital expenditure requirements over the next several years, which will likely require rate increase requests to the regulators. If our costs are not adequately recovered through rates, it could have an adverse effect on our business, results of operations, cash flows and financial condition.
 
Our domestic utility businesses are subject to significant and complex governmental regulation.
 
In addition to regulating the rates we charge, various federal and state regulatory authorities regulate many aspects of our domestic utility operations, including:
 
the terms and conditions of our service and operations;
financial and capital structure matters;


28


siting, construction and operation of facilities;
mandatory reliability and safety standards under the Energy Policy Act of 2005 and other standards of conduct;
accounting, depreciation and cost allocation methodologies;
tax matters;
affiliate transactions;
acquisition and disposal of utility assets and issuance of securities; 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 domestic regulated businesses undertake significant capital projects and these activities are subject to unforeseen costs, delays or failures, as well as risk of inadequate recovery of resulting costs.
 
The domestic 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;
skilled labor or equipment shortages;
construction problems or delays, including disputes with third-party intervenors;
increases in commodity prices or labor rates; 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 amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although they could be material.

Risks Specific to Kentucky Regulated Segment
 
(PPL, LKE, LG&E and KU)
 
The costs of compliance with, and liabilities under, environmental laws are significant and are subject to continuing changes.
 
Extensive federal, state and local environmental laws and regulations are applicable to LG&E's and KU's generation business, including its air emissions, water discharges and the management of hazardous and solid wastes, among other business-related activities, and the costs of compliance or alleged non-compliance cannot be predicted but could be material. In addition, our costs may increase significantly if the requirements or scope of environmental laws, 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 forfeitures, operational changes, permit limitations or other restrictions. At some of our older generating facilities it may be uneconomic for us to install necessary pollution control equipment, which could cause us to retire those units. Market prices for energy and capacity also affect this cost-effectiveness analysis. Many of these environmental law considerations are


29


also applicable to the operations of our key suppliers or customers, such as coal producers, power producers and industrial power users, and may impact the costs of their products and demand for our services.
 
Ongoing changes in environmental regulations or their implementation requirements and our related compliance strategies entail a number of uncertainties.
 
The environmental standards governing LG&E's and KU's businesses, particularly as applicable to coal-fired generation and related activities, continue to be subject to uncertainties due to rulemaking and other regulatory developments, legislative activities and litigation, administrative or permit challenges. Revisions to applicable standards, changes in compliance deadlines and invalidation of rules on appeal may require major changes in compliance strategies, operations or assets and adjustments to prior plans. Depending on the extent, frequency and timing of such changes, the companies may be subject to inconsistent requirements under multiple regulatory programs, compressed windows for decision-making and short compliance deadlines that may require new technologies or aggressive schedules for construction, permitting and other regulatory approvals. Under such circumstances, the companies may face higher risks of unsuccessful implementation of environmental-related business plans, noncompliance with applicable environmental rules, delayed or incomplete rate recovery or increased costs of implementation.
 
We are subject to operational, regulatory and other risks regarding certain significant developments in environmental regulation affecting coal-fired generation facilities.
 
Certain regulatory initiatives have been implemented or are under development which could represent significant developments or changes in environmental regulation and compliance costs or risk associated with the combustion of coal as occurs at LG&E's and KU's coal-fired generation facilities. In particular, such developments include the federal Coal Combustion Residuals regulations governing coal by-product storage activities and the federal Effluent Limitations Guidelines governing water discharge activities. Such initiatives have the potential to require significant changes in coal combustion byproduct handling and disposal or water treatment and release facilities and methods from those historically used or currently available. Consequently, such developments may involve increased risks relating to the uncertain cost, efficacy and reliability of new technologies, equipment or methods. Compliance with such regulations could result in significant changes to LG&E's and KU's operations or commercial practices and material additional capital or operating expenditures. Such circumstances could also involve higher risks of compliance violations or of variations in rate or regulatory treatment when compared to existing frameworks.

(PPL, LKE and LG&E)

We are subject to operational, regulatory and other risks regarding natural gas supply infrastructure.

A natural gas pipeline explosion or associated incident could have a significant impact on LG&E’s natural gas operations or result in significant damages and penalties that could have an adverse impact on LG&E’s financial position and results of operations. The Pipeline and Hazardous Materials Safety Administration has 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 LG&E. These regulations require, among other things, that pipeline operators engage in a pipeline integrity program. Depending on the results of these integrity tests and other integrity program 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 of compliance with pipeline integrity and safety regulations.

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 electric transmission planning activities. The PPL Electric transmission business, operating under a FERC-approved PJM Open Access Transmission Tariff, is subject to


30


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.
 
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.
 


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ITEM 2. PROPERTIES
 
U.K. Regulated Segment (PPL)
 
For a description of WPD's service territory, see "Item 1. Business - General - Segment Information - U.K. Regulated Segment." WPD has electric distribution lines in public streets and highways pursuant to legislation and rights-of-way secured from property owners. At December 31, 2018, WPD's distribution system in the U.K. includes 1,863 substations with a total capacity of 74 million kVA, 55,947 circuit miles of overhead lines and 84,032 underground cable miles.
 
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, 2018 was:
 
 
 
 
LKE
 
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
Coal
 
 
 
 
 
 
 
 
 
 
 
 
Ghent - Units 1- 4
 
1,919
 
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
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
 
 
7,410
 
5,157
 
 
 
2,059
 
 
 
3,098
Natural Gas/Oil
 
 
 
 
 
 
 
 
 
 
 
 
E.W. Brown Unit 5 (c)
 
130
 
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 8 - 11 (c)
 
484
 
484
 
 
 
 
 
100.00
 
484
Trimble County Units 5 - 6
 
318
 
318
 
29.00
 
92
 
71.00
 
226
Trimble County Units 7 - 10
 
636
 
636
 
37.00
 
235
 
63.00
 
401
Paddy's Run Units 11 - 12
 
35
 
35
 
100.00
 
35
 
 
 
 
Paddy's Run Unit 13
 
147
 
147
 
53.00
 
78
 
47.00
 
69
Haefling - Units 1 - 2
 
24
 
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 11
 
14
 
14
 
100.00
 
14
 
 
 
 
 
 
2,756
 
2,756
 
 
 
794
 
 
 
1,962
Hydro
 
 
 
 
 
 
 
 
 
 
 
 
Ohio Falls - Units 1-8 (d)
 
64
 
64
 
100.00
 
64
 
 
 
 
Dix Dam - Units 1-3
 
32
 
32
 
 
 
 
 
100.00
 
32
 
 
96
 
96
 
 
 
64
 
 
 
32
Solar
 
 
 
 
 
 
 
 
 
 
 
 
E.W. Brown Solar (e)
 
8
 
8
 
39.00
 
3
 
61.00
 
5
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
10,270
 
8,017
 
 
 
2,920
 
 
 
5,097
 
(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)
These units are owned by OVEC. LG&E and KU have a power purchase agreement that entitles LG&E and KU to their proportionate share of these units' total output and LG&E and KU fund their proportionate share of fuel and other operating costs, including debt service. Clifty Creek is located in Indiana and Kyger Creek is located in Ohio. See Note 13 to the Financial Statements for additional information.
(c)
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.


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(d)
In 2019, LKE completed upgrades to the Ohio Falls Hydroelectric Generating Station (Units 1-8), expanding the total generating capacity to 100 megawatts.
(e)
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, 2018, LG&E's transmission system included in the aggregate, 45 substations (31 of which are shared with the distribution system) with a total capacity of 8 million kVA and 669 pole miles of lines. LG&E's distribution system included 96 substations (31 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,887 circuit miles of overhead lines and 2,609 underground cable miles. KU's transmission system included 142 substations (61 of which are shared with the distribution system) with a total capacity of 14 million kVA and 4,067 pole miles of lines. KU's distribution system included 469 substations (61 of which are shared with the transmission system) with a total capacity of 8 million kVA, 14,017 circuit miles of overhead lines and 2,543 underground cable miles.

LG&E's natural gas transmission system includes 4,369 miles of gas distribution mains and 370 miles of gas transmission mains, consisting of 234 miles of gas transmission pipeline, 116 miles of gas transmission storage lines, 19 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.

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 8 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, LG&E 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. The subscription for the first 500-kilowatt phase was completed in June 2018. Construction of the first section has begun and is expected to be operational in the summer of 2019. LG&E and KU continue to market the program and receive interest from customers for the second 500-kilowatt phase.

Pennsylvania Regulated Segment (PPL and PPL Electric)

For a description of PPL Electric's service territory, 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, 2018, PPL Electric's transmission system includes 50 substations with a total capacity of 30 million kVA and 5,455 circuit miles in service. PPL Electric's distribution system includes 353 substations with a total capacity of 14 million kVA, 36,312 circuit miles of overhead lines and 8,428 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 8 to the Financial Statements for additional information.

ITEM 3. LEGAL PROCEEDINGS
 
See Notes 6, 7 and 13 to the Financial Statements for information regarding legal, tax litigation, regulatory and environmental proceedings and matters.
 
ITEM 4. MINE SAFETY DISCLOSURES
 
Not applicable.
 


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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 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, 2019, there were 53,571 common stock shareowners of record.

There were no purchases by PPL of its common stock during the fourth quarter of 2018.

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 $390 million in 2018 and $336 million in 2017.
 
LG&E and KU Energy LLC
 
There is no established public trading market for LKE's membership interests. PPL owns all of LKE's outstanding membership interests. Distributions on the membership interests are paid as determined by LKE's Board of Directors. LKE made cash distributions to PPL of $302 million in 2018 and $402 million in 2017.
 
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 $156 million in 2018 and $192 million in 2017.
 
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 $246 million in 2018 and $226 million in 2017.



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ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
PPL Corporation (a) (b)
 
2018
 
2017
 
2016
 
2015
 
2014
Income Items (in millions)
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
7,785

 
$
7,447